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Organic facies in Cretaceous and Jurassic hydrocarbon source rocks, Southern Indus basin, Pakistan
International Journal of Coal Geology 39 Ž1999. 205–225
Organic facies in Cretaceous and Jurassic hydrocarbon source rocks, Southern Indus basin, Pakistan C.R. Robison ) , M.A. Smith 1, R.A. Royle
2
Texaco Exploration and Production Technology Department, 3901 Briar Park Dr., Houston, TX 77042, USA
Abstract A detailed organic petrographic study of the geologic section penetrated by the Sann a1 well in the Southern Indus basin ŽKirthar Trough. of Pakistan permits definition of organic facies and oil-generation potential of Cretaceous and Jurassic source rocks. The well encountered Eocene through Jurassic rocks; however, only closely spaced samples of fine-grained rocks from the Cretaceous Goru, Sembar, and the Jurassic Chiltan formations in the well were studied in detail. Kerogen from the samples was examined in blue light epifluorescence and transmitted white light. The petrographic data are compared with total organic carbon and Rock-Eval w pyrolysis data from an earlier study. The results of the present study demonstrate that three distinct organic facies are present within the Sann a1 section. Organic facies A is oil-prone and consists of fluorescent amorphinite with trace to minor amounts of alginite and other liptinites. This facies quite possibly represents deposition in reasonably deep water. In shallower water conditions, a mixture of non-fluorescent and fluorescent amorphinite with some liptinites and vitrinite was deposited. This mixture of kerogen maceral types characterizes organic facies B, which contains both oil- and gas-prone organic material. Organic facies C was deposited under the most oxidizing shallow-water conditions of the three facies. It is largely gas-prone and contains mostly non-fluorescent amorphinite and minor amounts of vitrinitic material. A cyclical variation in kerogen types is characteristic of the studied well section. Such cyclic variation was produced by repeated periods of transgression and regression. If these variations, which produced the different organic facies, are confined to the trailing edge of the Cretaceous Indian subcontinent, then local controls such as the velocity of the subcontinent’s northward movement instead of global change in sea level may
)
Corresponding author. Fax: q1-713-954-6911; E-mail: [email protected] Present address: 1123 Shillington Dr. Katy, TX 77450, USA. 2 Present address: 5523 Rutherglen, Houston, TX 77096, USA. 1
0166-5162r99r$ - see front matter q 1999 Elsevier Science B.V. All rights reserved. PII: S 0 1 6 6 - 5 1 6 2 Ž 9 8 . 0 0 0 4 6 - 9
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have determined the extent of water depth along the margin of the subcontinent. q 1999 Elsevier Science B.V. All rights reserved. Keywords: organic facies; petroleum source rocks; organic petrology; organic geochemistry; Southern Indus basin; Kirthar Trough; Southern Pakistan
1. Introduction A suite of cuttings and some cores from the Sann a1 well, located along the west-central edge of Kirthar Trough, Southern Indus basin, Sindh Province, Pakistan ŽFig. 1., were evaluated using organic petrographic and geochemical methods. The purpose of this study was to try to define the hydrocarbon potential of petroleum source rocks in the area of the Sann a1 well. The geochemical data given here support the existence of high quality oil and gas source rocks in the area where the well was drilled and also permit the recognition of three distinct organic facies within these source rocks as originally defined by Smith et al. Ž1992.. Excellent agreement among the organic carbon, pyrolysis, and organic petrologic data allows earlier ambiguities to be resolved and permits novel interpretation techniques to define organic facies and individual transgressive cycles.
2. Geologic setting The Indus basin ŽFig. 1. is a large Late Paleozoic through Paleogene downwarp that occurs along the northwestern edge of the Indian subcontinent ŽDolan, 1990.. It covers the eastern two-thirds of Pakistan, with its axis generally coinciding with the course of the Indus River ŽKingston, 1986.. The Indian Shield to the east and an axial fold belt to the west–northwest ŽQuadri and Shuaib, 1986. confine the Southern Indus basin. Quadri and Shuaib also point out that the Murray Ridge–Owen fracture plate boundary limits the south–southwest offshore extension of the basin. To the north, the Jacobabad Arch separates the Southern from the Central Indus basin ŽFig. 1.. The Indian subcontinent drifted north during the late Mesozoic from a paleolatitude of near 308S to about the equator ŽFig. 2.. Marine marls, turbidites, and shales, along with shelf carbonates and clastics, were deposited in the Southern Indus basin ŽShuaib, 1982; Quadri and Shuaib, 1986, 1987.. Fig. 3 presents the general stratigraphy of the Southern Indus basin and Kirthar Trough as interpreted by Dolan Ž1990.. The Miocene through Pliocene Siwalik Group sediments ŽShah, 1978; Dolan, 1990; Quadri and Quadri, 1996. are thickest in areas closer to the Himalayas, but subsidence and deposition had stopped by the Oligocene throughout most of the lower Southern Indus basin and widespread erosional unconformities developed at that time ŽDolan, 1990; Smith et al., 1992; Bender, 1995., limiting the thickness of the younger deposits in this area. As revealed in the west to east cross section shown in Fig. 4, Tertiary ŽPaleogene and early Neogene. rocks are also relatively thin in the Southern Indus basin. Pab Formation sandstones and Moro
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
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Fig. 1. Southern Indus basin and Sann a1 well location map Žafter Quadri and Shuaib, 1986..
Formation carbonates represent the latest Cretaceous. Fort Munro, Mughal Kot, and Parh formation limestones, shales, and sandstones ŽFig. 3. underlie these formations. The earliest Cretaceous rocks in the basin belong to the Goru Formation. According to Dolan Ž1990., in the Southern Indus basin the Goru Formation is generally split into a lower
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C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Fig. 2. Late Cretaceous paleogeography. The Indian subcontinent was moving north through the tropical Tethyan realm at a relatively high velocity. Sea level was higher in relation to most land areas than it had been during the Early Cretaceous Žafter Stanley, 1989..
unit of sandstones and shales and an upper unit consisting mostly of shales and marls. Underlying the Goru Formation are the shales of the Cretaceous Sembar Formation, and beneath the Sembar are the carbonates of the Jurassic Chiltan Formation ŽFig. 3.. Table 1 lists the thickness, age, and general lithology of the different formations encountered by the Sann a1 well. The Late Cretaceous Moro and Fort Monro formations were not encountered by the Sann a1 well; however, the lateral equivalent of the Moro Formation ŽPab Formation sandstones. and of the Fort Munro Formation ŽMughal Kot Formation shales. were encountered ŽTable 1; Fig. 3.. Transgressive–regressive facies of a regional nature are particularly well developed in marls and shales of the upper Goru Formation ŽShuaib, 1982; Quadri and Shuaib, 1986, 1987; Brink and Logan, 1997.. Local variations in the type and particle size of organic matter are seen in the underlying lower Goru and Sembar formations, which most likely accumulated in marginal to occasionally deep marine settings. Jurassic and
Fig. 3. General stratigraphy of the Southern Indus subbasin Žafter Dolan, 1990. Žexplanation: CG s conglomerate; FMs formation; GRPsGroup; LST s limestone; JUR.s Jurassic..
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
209
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C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Fig. 4. West to east cross-section through the center of the southern Indus basin; line of section shown on Fig. 1 Žadapted from Quadri and Shuaib, 1986..
Cretaceous lithofacies show a southwest to northeast change from deep to shallow water ŽDolan, 1990.. Marine Cretaceous petroleum source rocks in Southern Indus are part of an independent petroleum system, and they are not particularly overmature for oil generation ŽSmith et al., 1992.. Shales of the Lower Cretaceous oil- and gas-prone Sembar Formation ŽTable 1; Figs. 3 and 4. are considered to be the major source unit in the basin ŽQuadri and Quadri, 1996; Brink and Logan, 1997.. The sandstones of the Cretaceous lower Goru Formation form the main reservoir unit ŽQuadri and Shuaib, 1986; Kingston, 1986; Dolan, 1990; Smith et al., 1992.. Production from the Khaskeli field ŽFigs. 1 and 3. and discoveries in surrounding blocks suggest that source rocks in the region could produce petroleum yields in the range of 65–155 million barrelsrkm2 ŽQuadri and Quadri, 1996..
3. Samples and methods Owing to the poorly consolidated nature of the clay-rich silt and sand samples, most geochemical analyses had to be made on unwashed cuttings samples Ž n s 76. to prevent loss of fine-grained material. The only available core samples Ž n s 3. came from a very limited depth interval within the Chiltan Formation at 3677–3686 m. Total organic carbon ŽTOC. and Rock-Eval w pyrolysis were used to evaluate organic richness and hydrocarbon generation potential, respectively ŽSmith et al., 1992.. Detailed microscopy
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211
Table 1 Stratigraphy in the Sann a1 well, Southern Indus basin, Pakistan Žadapted from Shah, 1978; Dolan, 1990. Depth to Formationa top Žm.
Stratigraphic unit
Age
Lithology
Laki Formation Ranikot Group ŽLakhra Formation. Ranikot Group ŽBara Formation. Ranikot Group ŽKhadro Formation. Pab Sandstone
Eocene Paleocene
Limestone Sandstone, Gray Shale Sandstone, Gray Shale, Basalt
Mughal Kot Formation Parh Limestone
Late Cretaceous
Albian–Late Cretaceous Aptian?–Albian
3455
Goru Formation Župper. Goru Formation Žlower. Sember Formation
3604
Chiltan Formation
Jurassic
3769
Total Depth
Jurassic
5 95 888 888 1035 1082 1090 1258 2578
a
Paleocene Paleocene Late Cretaceous
Late Cretaceous
Aptian?
Sandstone, Brown Shale Argillaceous Limestone Limestone, Marl Gray Shale, Marl Gray Shale, Sandstone Gray Shale, Calcareous Sanstone Gray Limestone, Gray–Black Shale
The Late Cretaceous Moro and Fort Monro formations are not present in the Sann a1 well.
using transmitted white light and epifluorescence Žblue light. was conducted on all 79 samples to add further definition to the earlier conceived organic facies ŽSmith et al., 1992. and to determine organic maturation levels. The samples examined were split into two subsets; one for organic richness and source potential determinations, the other for kerogen microscopy. For the organic richness and source potential assessments, each sample in the subset was ground to a 200 mesh powder mechanically and then a portion of each powdered sample was treated with hydrochloric acid to dissolve carbonate minerals. The samples were dried and then combusted in a LECO CarbonrSulfur Analyzer for total organic carbon and total sulfur contents. Some of the remaining portions of the powdered samples was subjected to whole rock pyrolysis using a Rock-Eval w pyrolyzer after the method of Espitalie´ et al. Ž1977.. Each sample in the subset for kerogen microscopy was demineralized first with dilute hydrochloric acid Ždissolution of carbonate minerals., washed, and then treated with concentrated hydrofluoric acid Ždissolution of silicate minerals. following standard kerogen isolation procedures ŽCombaz, 1980.. Kerogen macerals were separated from residual mineral matter by heavy liquid separation using zinc bromide Žspecific gravity 1.85–1.90.. Kerogen slides were prepared from concentrated kerogen. The mounting medium used was a non-fluorescent synthetic resin. Kerogen microscopy was performed in both transmitted white light and in blue light epifluorescence with a Nikon Mi-
TOC Ž%.
S Ž%.
1318 1333 1348 1373 1393 1418 1435 1458 1468 1488 1513 1538 1563 1578 1593 1608 1628 1663 1683 1718 1753 1778 1808 1818 1878 1948 1963 1988 2013 2043 2098
5.85 5.51 2.26 1.10 2.81 1.91 2.41 1.66 1.71 1.56 8.75 4.32 2.10 2.09 3.81 3.23 3.38 1.46 1.25 4.21 5.64 11.54 4.33 1.71 2.13 2.96 5.64 2.71 2.11 1.37 1.37
0.77 0.17 0.15 0.11 0.18 0.25 0.41 0.49 0.60 0.43 0.74 0.67 0.58 0.68 0.70 0.77 0.63 0.71 0.69 0.91 1.16 1.33 1.06 0.92 1.13 1.74 1.72 1.99 1.36 1.31 1.34
S1 Žmgrg. 2.08 2.94 1.78 0.15 0.29 0.06 0.35 0.06 0.24 0.11 4.46 1.65 0.41 0.30 0.22 0.59 0.95 0.16 0.15 0.55 1.66 1.94 0.93 0.24 0.28 0.58 1.58 0.15 0.09 0.15 0.16
S2 Žmgrg.
S1 q S2 Žmgrg.
S3 Žmgrg.
HI Ž S2 rTOC.
OI Ž S3 rTOC.
KTR Ž S1 rS1 q S2 .
Tmax Ž8C.
Formation
Organic Facies
38.56 39.95 20.63 3.32 14.11 5.48 12.30 5.77 7.66 5.35 55.15 27.78 10.30 8.66 13.59 19.04 21.97 5.52 4.06 22.31 28.34 75.13 27.63 6.49 7.50 14.01 36.82 10.13 4.46 2.38 1.36
40.64 42.89 22.41 3.47 14.40 5.54 12.64 5.83 7.90 5.46 59.61 29.43 10.71 8.96 13.81 19.63 22.92 5.68 4.21 22.86 30.00 77.07 28.56 6.73 7.78 14.59 38.40 10.28 4.55 2.53 1.52
4.00 2.13 3.72 3.59 4.09 3.41 3.61 3.46 3.67 2.43 2.83 3.82 4.04 3.37 4.65 3.83 2.67 4.25 3.69 3.23 1.95 3.95 1.66 4.22 3.36 3.57 2.33 2.80 4.44 2.54 3.46
659 725 913 302 502 287 510 348 448 343 630 643 490 414 357 589 650 378 325 530 502 651 638 380 352 473 653 374 211 174 99
68 39 165 326 146 179 150 208 215 156 32 88 192 161 122 119 79 291 295 77 35 34 38 247 158 121 41 103 210 185 253
0.05 0.07 0.08 0.04 0.03 0.01 0.03 0.01 0.03 0.03 0.08 0.06 0.04 0.03 0.02 0.03 0.04 0.03 0.03 0.20 0.05 0.03 0.03 0.04 0.04 0.04 0.04 0.01 0.02 0.06 0.11
428 427 425 428 432 429 430 433 427 429 430 428 433 432 434 427 431 431 431 431 431 432 431 430 434 427 429 434 434 434 440
upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru
A A A C B C B B B B A A B B B A A B B A A A A B B B A B C C C
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Depth Žm.
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Table 2 Total organic carbon and pyrolysis data for the Sann a1 well
1.34 1.82 1.28 1.56 1.38 1.32 1.22 1.24 1.18 1.10 1.22 0.93 1.65 1.18 1.08 1.14 1.13 2.74 1.51 2.13 1.52 1.62 1.31 1.38 1.09 1.35 1.35 1.45 2.25 2.15 2.26 1.26 1.94 2.22 0.96
0.19 0.26 0.16 0.50 0.52 1.10 0.76 0.74 0.69 0.73 0.64 1.22 1.12 1.24 0.57 0.69 0.43 1.36 1.02 1.73 1.65 0.91 0.94 1.47 2.48 2.34 0.96 1.55 5.64 3.32 5.03 2.85 10.16 6.57 2.37
1.73 4.28 1.70 1.60 1.34 6.16 1.99 1.62 1.14 1.03 1.26 2.94 2.37 4.41 1.02 1.26 1.07 2.33 2.95 2.96 5.15 2.13 2.66 3.09 6.14 8.83 2.05 1.76 17.37 6.07 16.83 7.37 29.75 33.91 4.96
1.92 4.54 1.86 2.10 1.86 7.26 2.75 2.36 1.83 1.76 1.90 4.16 3.49 5.65 1.59 1.95 1.50 3.69 3.97 4.69 6.80 3.04 3.60 4.56 8.62 11.17 3.01 3.31 23.01 9.39 21.86 10.22 39.91 40.48 7.33
3.20 2.38 2.87 2.47 4.13 3.16 3.29 3.56 4.05 4.65 2.70 3.22 4.25 3.28 2.09 4.18 4.55 5.31 5.37 4.97 4.78 6.12 3.22 3.90 3.94 3.36 4.04 4.34 5.38 5.48 3.84 4.21 3.68 1.93 3.90
170 236 148 148 108 323 160 140 96 83 118 212 150 249 96 75 67 135 138 148 204 108 127 131 201 273 98 65 333 177 336 281 505 358 235
314 131 250 229 333 165 265 307 340 375 252 232 269 185 197 247 284 309 251 249 189 309 153 165 129 104 192 160 103 160 77 161 62 20 185
0.10 0.06 0.09 0.24 0.28 0.15 0.28 0.31 0.38 0.41 0.34 0.29 0.32 0.22 0.36 0.35 0.29 0.37 0.26 0.37 0.24 0.30 0.26 0.32 0.29 0.21 0.32 0.47 0.25 0.35 0.23 0.28 0.25 0.16 0.32
433 435 437 432 438 426 431 425 431 429 428 428 421 425 422 438 438 424 428 426 416 429 429 426 426 428 428 416 425 428 427 426 422 431 425
upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru Sembar Sembar Sembar Sembar Sembar
C C C C C B C C C C C C C C C C C C C C C C C C C C C C B C B B A B C
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1.02 1.81 1.15 1.08 1.24 1.91 1.24 1.16 1.19 1.24 1.07 1.39 1.58 1.77 1.06 1.69 1.60 1.72 2.14 2.00 2.53 1.98 2.10 2.36 3.05 3.24 2.10 2.71 5.22 3.43 5.01 2.62 5.89 9.48 2.11
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
2143 2188 2208 2303 2363 2408 2438 2498 2503 2518 2548 2573 2603 2618 2638 2653 2668 2738 2758 2798 2868 2898 2918 2958 2983 2990 3377 3399 3419 3452 3482 3509 3518 3520 3531
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Depth Žm.
TOC Ž%.
S Ž%.
S1 Žmgrg.
S2 Žmgrg.
S1 q S2 Žmgrg.
S3 Žmgrg.
HI Ž S2 rTOC.
OI Ž S3 rTOC.
KTR Ž S1 rS1 q S2 .
Tmax Ž8C.
Formation
Organic Facies
3559 3598 3611 3631 3658 3660 3680 3685 3689 3709 3721 3722 3731
2.09 1.86 0.81 1.55 1.06 0.74 5.43 1.53 1.46 1.84 2.31 2.87 1.29
1.21 1.19 0.64 0.64 0.50 0.19 1.00 1.75 0.64 0.72 0.71 0.39 0.89
1.66 1.79 0.23 1.68 0.88 0.20 8.95 0.09 2.30 2.15 3.24 2.00 1.22
4.72 2.88 2.14 3.41 1.77 0.91 30.04 0.12 7.29 6.87 10.43 11.49 2.89
6.38 4.67 2.37 5.09 2.65 1.11 38.99 0.21 9.59 9.02 13.67 13.49 4.11
4.88 4.19 1.73 4.26 3.18 1.20 4.36 0.50 3.13 3.36 3.51 1.45 3.58
226 155 264 220 167 123 553 8 499 373 452 400 224
233 225 214 275 300 162 80 33 214 183 152 51 278
0.26 0.38 0.10 0.33 0.33 0.18 0.23 0.43 0.24 0.24 0.24 0.15 0.30
423 424 431 422 428 421 423 413 421 426 423 433 415
Sembar Sembar Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan
C C C C C C A C B B B B C
S1 sdistillable hydrocarbons present in the rock Žmgrg rock.. S2 s hydrocarbons generated from the pyrolysis of kerogen Žmgrg rock.. S1 q S2 s total hydrocarbon generation potential of the rock Žmgrg rock.. S3 sCO 2 generated from kerogen pyrolysis Žmgrg rock.. HI s hydrogen index Žmg generated HCrg of organic carbon.. OI s oxygen index Žmg CO 2 rg of organic carbon.. KTR s kerogen transformation ratio-proportion of distillable hydrocarbons to total hydrocarbon generation potential S1 rŽ S1 q S2 .. Used as a maturation index when samples are contamination-free. Tma x s pyrolysis temperature at which a maximum yield of generated hydrocarbons occurs ŽTmax increases with increasing maturation..
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Table 2 Žcontinued.
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crophot-FXA microscope. Some of the concentrated kerogen for each sample was also embedded in resin and polished for examination in reflected white light and for measurement of vitrinite reflectance using a Zeiss Universal microscope and photometer. Mean random reflectance was measured. Six main maceral classes were used: fluorescent amorphous material, alginite, exinite Žexcluding alginite., non-fluorescent amorphous material, vitrinite, and inertinite.
4. Results and discussion 4.1. Source rock quality and generation potential Source rock richness is based on total organic carbon content ŽTable 2.. Total hydrocarbon generation potential ŽTHGP. is derived from Rock-Eval w pyrolysis S1 q S2 values ŽTable 2; S1 values represent the amount of bitumen in a rock distilled off at pyrolysis temperatures below 3008C; S2 values represent the bitumen generated from thermally cracking kerogen and high molecular weight bitumen in the rock at pyrolysis temperatures between 3008 and 5008C.. TOC and THGP data are cross-plotted in Fig. 5. Above-average Ž) 1.0 wt.%. levels of TOC are found throughout the Goru and Sembar formations, and in isolated depth intervals of the Jurassic Chiltan Formation Ž3630–3659 m; 3678–3679 m., and at depths from 3680 m to total depth in the Sann a1 well ŽTable 2.. Average TOC values for the Cretaceous formations are 2.70% in the upper Goru Ž n s 43., 2.35% in the lower Goru Ž n s 18., and 4.15% in the Sembar Ž n s 7.. Cuttings samples from the Chiltan Formation Ž n s 8. contain an average of 1.56% TOC. The three core samples that were analyzed from the Chiltan Formation from 3680, 3685, and 3689 m were found to contain an average TOC content of 2.81%. The extremely low S1 q S2 Rock-Eval w pyrolysis yield for the core sample from 3685 m ŽTable 2., which had ) 1.5% TOC, suggests contamination from either drilling mud additives or migrant bitumen. Rock-Eval w pyrolysis data ŽTable 2. show good to excellent total hydrocarbon yields throughout the well section studied. Total hydrocarbon generation potentials average 14.31 mg HCrg rock for the upper Goru Formation between 1318 and 2573 m, 5.72 mg HCrg rock for the lower Goru, 18.69 mg HCrg rock for the Sembar, and 9.12 mg HCrg rock for cuttings from the Chiltan Formation. Hydrocarbons that were introduced into the stratigraphic section by either drilling-fluid contamination or migration would be included in the Rock-Eval w S1 peak, but the kerogen transformation ratios ŽKTR. show that only 4% of the hydrocarbon generation potential for rocks above 2300 m and 29% for the thermally mature units below this depth are contributed by S1 distillable hydrocarbons in the rocks. Therefore, it appears from the pyrolysis data that the Sann a1 well has excellent source-rock potential below 1318 m. On Fig. 5, the hydrocarbon yield for most samples is seen to be high relative to their TOC; i.e., they plot above the best-fit line. This indicates that these source rocks are oil-prone and contain little coal or other gas-prone organic matter. The measured level of organic enrichment and the measured distillable hydrocarbon yields Ž S1 values. may be affected by contributions from drilling additives. Because
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C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Fig. 5. Plot of total hydrocarbon generation potential Žpyrolysis S1 q S2 . vs. weight percentage total organic carbon content for Sann a1 samples.
TOC and Rock-Eval w S1 and S2 measurements were substantially lower in core samples from the Jurassic Chiltan Formation between 3677 and 3686 m compared to cuttings samples, selected cuttings samples from near the bottom of the well were thoroughly washed with water to remove as much drilling fluid as possible. TOC and pyrolysis analyses were carried out on these washed samples to determine the extent of possible drilling-fluid contamination. In all cases the quantity of free hydrocarbons Ž S1 s. was lowered, but the overall organic enrichment was not changed significantly. Thus, it appears that contamination by drilling-mud additives is not a serious problem affecting the geochemical analyses conducted on samples from the Sann a1 well. 4.2. Thermal maturation Thermal Alteration Indices ŽTAIs. from visual kerogen assessment indicate the degree of thermal maturation of samples from the Sann a1 well ŽTable 3.. Vitrinite was
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
217
a secondary component of the kerogen in most samples, compared to the amount of amorphous organic matter. The distribution of the few reflectance measurements that were obtained is tabulated in Table 3. These mean reflectance values, although possibly based on reworked material, are consistent with maturation levels suggested by the thermal alteration indices ŽTAIs. as reported in Table 3. The upper Goru Formation between 1318 and 2573 m is within the initial phase of the thermal generation of wet gas and condensate. The deeper samples in this interval, from 1985–2573 m, appear from their Tmax values in Table 2 to be slightly more mature, but their level of maturation is still consistent with the initial phase of hydrocarbon generation. The transition from the initial phase of the thermal generation of hydrocarbons to the main phase of generation and expulsion also occurs within the upper Goru Formation between 2300 and 2400 m based vitrinite reflectance measurements ŽTable 3.. TAI values at about this depth indicate a slightly lower maturation level ŽTable 3.. A mean vitrinite reflectance measurement of 1.09% for a sample from the Sembar Formation at 3530 m places the base of the main phase of hydrocarbon generation and expulsion Žthe ‘oil-window’. near this depth. The lack of vitrinite in deeper samples, including the cored intervals, precluded any additional reflectance measurements. 4.3. Organic facies Although thermally immature to marginally mature, upper Goru samples above 2013 m contain mostly fluorescent amorphous kerogen, indicating that this stratigraphic interval is largely oil-prone ŽTable 3.. Non-fluorescent amorphous kerogen, which is regarded as gas-prone if not thermally overmature, is the most dominant organic matter type in the lower Goru Formation ŽTable 3.. In the Sembar and Chiltan formations, the organic facies alternate between thick units of shallow-water facies C and slightly deeper water facies B to occasional thin units of deep water facies A ŽTable 3.. It is possible that much of this material was originally oil-prone and that thermally mature source rocks in this area may already have generated liquid hydrocarbons. At some point in their history, however, the kerogen in the deeper units in this well appear to have been oxidized, and degraded to become more gas-prone. A further indication of oil proneness can be seen in Fig. 6. Fig. 6 is a modified van Krevelen diagram that plots Rock-Eval w hydrogen and oxygen indices ŽHI—in mg S2rg TOC; OI—in mg CO 2rg TOC. values to distinguish among Types I, II, and III kerogen. Most OI values are quite high, with an average of 186 for the Goru units, 157 for the Sembar Formation, and 215 for the Chiltan samples. For cleaned Sembar and Chiltan samples, the OIs were reduced by about a factor of 3 while the HIs were affected only slightly, suggesting that the high OIs are related to a possible contaminant in the drilling mud rather than to bitumen in the rocks. The most oil-prone samples in the well, as indicated by HIs above 600, all occur within the upper Goru Formation above 2013 m. Looking at the distribution of HI and OI ratios on Fig. 6, it is apparent that they should be separated into three separate organic facies. Samples from Organic Facies A are oil-prone with predominantly Type I and lesser amounts of Type II kerogen. Facies B and C contain a mixture of Type II and
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Table 3 Organic petrologic data for the Sann a1 well Fluorescent amorphous Ž%.
Alginite Ž%.
Exinite Ž%.
Oil-prone Ž%.
Nonfluorescent amorphous Ž%.
Vitrinite Ž%.
Inertinite Ž%.
Gas-prone Ž%.
TAI ŽThermal Alteration Index.
Vitrinite reflectance Žmean %; min–max; n.
Formation
Organic Facies
1318 1333 1348 1373 1393 1418 1435 1458 1468 1468 1513 1538 1563 1578 1593 1608 1628 1663 1683 1718 1753 1778 1808 1818 1878 1948 1963 1968
65 70 90 55 65 45 65 35 45 50 60 70 50 40 55 65 90 45 45 60 60 85 85 45 45 50 85 40
5 10 5 0 5 0 5 0 0 5 5 10 0 0 5 5 0 0 0 5 5 5 0 0 0 0 0 0
15 15 5 5 10 10 5 15 10 10 15 5 10 5 15 15 0 20 25 20 15 5 10 10 15 15 5 0
85 95 100 60 80 55 75 50 55 65 80 85 60 45 75 85 90 65 70 85 80 95 95 55 60 65 90 40
0 0 0 30 0 25 25 25 30 30 10 10 20 30 10 0 0 20 20 10 10 0 0 25 25 25 0 30
15 5 0 10 5 10 0 10 10 5 5 5 15 20 10 10 10 10 10 5 5 5 5 15 10 10 10 20
0 0 0 0 15 10 0 15 5 0 5 0 5 5 5 5 0 5 0 0 5 0 0 5 5 0 0 10
15 5 0 40 5 35 25 35 40 35 15 15 35 50 20 10 10 30 30 15 15 5 5 40 35 35 10 50
2.3 2.3 2.3 2.3 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.5 2.5
– – – – – – – – – – – – – – – – – – – – – – – – – – – –
upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru
A A A C B C B B B B A A B B B A A B B A A A A B B B A B
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Depth Žm.
0 0 0 0 0
5 5 0 0 5
25 15 0 5 45
50 70 90 80 40
20 15 10 15 10
5 0 0 0 5
70 85 100 95 50
2.5 2.5 2.5 2.5 2.5
upper Goru upper Goru upper Goru upper Goru upper Goru
C C C C C
upper Goru upper Goru upper Goru
C C C
2.5 2.5 2.6 2.6 2.6 2.6 2.6
– – – – 0.65 Ž0.49–0.83; ns18. – – 0.72 Ž0.54–0.89; ns 40. – – – – – – –
2208 2303 2363
0 0 0
0 0 0
0 0 0
0 0 0
90 90 95
10 10 5
0 0 0
100 100 100
2.5 2.5 2.5
2408 2438 2498 2503 2518 2548 2573
40 0 0 0 0 0 25
0 0 0 0 0 0 0
10 0 0 0 0 0 10
50 0 0 0 0 0 35
30 80 85 95 95 90 45
20 20 10 5 5 5 15
0 0 5 0 0 5 5
50 100 95 100 100 100 60
upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru
B C C C C C C
2603 2618 2638 2653 2668 2738 2758 2796 2868 2898 2918 2958 2963 2990 3377
0 40 0 0 0 10 10 10 15 0 0 0 20 15 0
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
0 15 0 0 0 5 0 0 5 0 5 5 0 0 0
0 55 0 0 0 5 10 10 20 0 5 5 20 15 0
90 25 95 100 100 80 80 85 70 90 85 85 75 80 95
10 20 5 0 0 15 10 5 10 5 5 5 5 5 5
0 0 0 0 0 0 0 0 0 5 5 5 0 0 0
100 45 100 100 100 95 90 90 80 95 90 90 85 85 100
2.6 2.6 2.6 2.6 2.6 2.6 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7
– – – – – – – – – – – – – – –
lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru
C C C C C C C C C C C C C C C
219
20 10 0 5 40
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
2013 2043 2098 2143 2188
220
Table 3 Žcontinued. Fluorescent amorphous Ž%.
Alginite Ž%.
Exinite Ž%.
Oil-prone Ž%.
Nonfluorescent amorphous Ž%.
Vitrinite Ž%.
3399 3419 3452 3482 3509 3518 3520 3531
0 55 15 55 40 65 45 25
0 5 0 0 0 5 0 0
0 15 0 15 10 15 5 0
0 75 15 70 50 85 50 25
100 15 80 20 40 10 40 50
0 5 5 5 5 5 10 25
3559 3596 3611 3631 3658 3660 3680 3685 3689 3709 3721 3722 3731
25 10 35 25 0 0 70 0 65 45 60 60 25
0 0 0 0 0 0 5 0 0 0 0 0 0
0 0 0 0 0 0 15 0 15 20 15 20 0
25 10 35 25 0 0 90 0 80 65 75 80 25
75 85 45 65 95 90 5 90 5 15 10 10 70
0 5 5 0 5 5 5 10 5 10 10 5 5
Inertinite Ž%.
Gas-prone Ž%.
TAI ŽThermal Alteration Index.
Vitrinite reflectance Žmean %; min–max; n.
Formation
Organic Facies
0 5 0 5 5 0 0 0
100 20 85 25 45 15 50 75
2.9 2.9 2.9 2.8 2.8 2.9 2.9 2.9
lower Goru lower Goru lower Goru Sembar Sembar Sembar Sembar Sembar
C B C B B A B C
0 0 15 10 0 5 0 0 10 10 5 5 0
75 90 50 65 100 95 10 100 10 25 20 15 75
2.9 2.9 2.9 2.9 2.9 2.9 3.0 3.1 3.1 3.1 3.1 3.1 3.0
– – – – – – – 1.09 Ž0.88–1.28; ns18. – – – – – – – – – – – – –
Sembar Sembar Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan
C C C C C C A C B B B B C
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Depth Žm.
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
221
Fig. 6. Plot of Kerogen Type and Organic Facies as defined by Rock-Eval w HI and OI indices. Three Organic Facies are delineated, with oil-prone type-I kerogen found only in Facies A and oxidized, gas-prone type-III kerogen characterizing Facies C. Possible thermal degradation pathways for samples from individual sequences are also shown on the diagram Žafter Smith et al., 1992..
III kerogen and are more gas-prone. Facies C is distinguished by OIs greater than 150 and somewhat lower HI values than Facies B and it includes almost all upper Goru samples below 2013 m. Stratification of water depth in sequences up to several hundred meters thick are contained in individual formations. For example, source facies in the upper Goru Formation display upwardly asymmetrical cycles of regressive–transgressive sequences from shallow-water, gas-prone Facies C through less oxidized Facies B to the deep-water, oil-prone Facies A ŽTables 2 and 3; Fig. 7.. This manner of source rock deposition explains why both oil and gas source rocks were identified in the upper Goru by Katz Ž1989.. Organic Facies C dominates the lower Goru Formation ŽTables 2 and 3.. The
222
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Fig. 7. Asymmetric changes in organic facies within the Cretaceous upper Goru Formation as defined by marked variations in oil-prone kerogen concentrations and in Rock-Eval w HI values of kerogen.
Sembar Formation grades from Facies C at around 3598 m to Facies B at 3520 m, Facies A at 3518 m, and then back to Facies B between 3518 and 3482 m ŽTables 2 and 3.. The Chiltan Formation grades upward from Facies A to B starting at 3731 m to Facies C between 3660 and 3611 m ŽTables 2 and 3.. The van Krevelen diagram in Fig. 6 also indicates the relative level of thermal maturation of the organic matter as the HI and OI values decrease along fixed pathways relating to burial and time–temperature alteration. Interpretation of kerogen-type data plotted on Fig. 6 is complicated further because OI values may be elevated from drilling-mud contamination. HIs for the lower Goru, Sembar, and Chiltan formations, all of which fall within the ‘oil-window’, reflect S2 values that have been lowered as hydrocarbons were released from effective source-rock intervals.
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
223
5. Summary and conclusions The Indus basin is a large Late Paleozoic–Paleogene downwarp that developed on the northwestern margin of the Indian Platform. It covers the eastern two-thirds of Pakistan ŽKingston, 1986., and the basin axis generally coincides with the course of the Indus River. Although the Miocene Siwalik Group can reach great thickness farther to the north near the Himalayas, subsidence and deposition had ceased by late Palogene throughout most of the Indus basin and widespread erosional unconformities developed at that time ŽDolan, 1990; Smith et al., 1992; Bender, 1995.. Recoverable gas reserves from 14 fields total about 22 tcf, but more than 90% of Pakistan’s gas production and 57% of the gas reserves are from the giant Sui and Mari fields ŽFig. 1., both of which were discovered in the 1950s and produce from Eocene carbonate reservoirs in the central basin ŽQuadri and Quadri, 1996.. Oil was discovered in the Cretaceous upper and lower Goru Formation at Khaskeli in 1981, and several small fields with estimated reserves of about 50 million barrels of oil were developed in the next few years. More recently, additional discoveries have increased gas production from other areas of the basin ŽSoulsby and Kemal, 1988a,b; Quadri and Quadri, 1996.. Oil fields southeast of the location of the Sann a1 well produce from the upper Goru Formation in a stratigraphic setting similar to that of the Sann a1. In the area southwest of the Sann a1 well, the Tertiary section is only about 1000 m thick and the underlying Cretaceous rocks are probably not overmature for oil generation. The Sann a1 was an exploratory wildcat well drilled during a 6-month period in 1984–1985 by the Oil and Gas Development Corporation of Pakistan. Early work on the well ŽDungworth and Abernethy, 1988. provided a thermal maturation profile and identified important possible oil and gas source sequences within the upper Goru and lower GorurSembar Formations. These workers also reported oil source quality for the Chiltan Formation. Although their work involved samples that may have been contaminated or stained, the new geochemical data presented here supports the concept of high quality petroleum source rocks throughout the Cretaceous and Upper Jurassic section in the Sann a1 well. Thermal maturity determinations for the Sann a1 section from mean vitrinite reflectance and TAI data are in general agreement. Based on this data, the top of the ‘oil window’ Ž R o of ; 0.60%. occurs at a depth of 2000 m and the base of the ‘oil window’ Ž R o of ; 1.30%. occurs at an extrapolated depth of about 4000 m. The Rock-Eval w pyrolysis data for the upper Goru Formation support the organic petrographic observations on thermal alteration, source quality and type, and organic facies. There is a pronounced increase in the kerogen transformation ratios ŽKTR; S1rS1 q S2 . of the upper Goru at a depth of 2300 m from an average of 0.04 to 0.30. This jump in KTR values corresponds to the start of peak oil and gas generation, and it appears to represent the onset of indigenous hydrocarbon generation. Additionally, the Tmax for the upper Goru also increases slightly between 1963 and 2013 m ŽTable 2., corresponding to entry into the ‘oil window’ at this point. Tmax values in the deeper stratigraphic units have been suppressed, probably by some inevitable drilling-fluid contamination, and are no longer a reliable indicator of thermal maturation.
224
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
The richest hydrocarbon source rocks in the well are found in the thermally immature upper Goru section above 2013 m. Fluorescent amorphous kerogen is prevalent, suggesting a largely oil-prone unit. The Goru Formation is the reservoir unit of oil fields to the southeast of the Sann a1 well, many of the samples come from intervals that are defined here as belonging to deep-water, oil-prone Organic Facies A. Individual transgressive sequences that shallow upward into Facies C are from 40 to 165 m thick, and are capable of generating both oil and gas following additional burial and thermal alteration. Kerogen types are also quite distinct for the deeper units. The Sembar and the few Chitlan samples examined are more oil-prone than samples from the lower Goru. However, the kerogen in the Chitlan appears to be more heavily oxidized than that in the Sembar Formation and lower Goru Formation. The most prospective mature source-rock interval occurs between 3270 and 3585 m. The lower Goru and Sembar formations at this depth are within the zone of peak oil generation and contain mostly non-fluorescent amorphous kerogen. Rock-Eval w data suggest that although liquid hydrocarbons may have already been expelled from these units, this section retains considerable gas generation potential.
Acknowledgements We thank Ewa Szymczyk and L.M. Darnell of the Houston Advanced Research Center ŽHARC. for their analytical support, M.A. Weismiller of Texaco EPTD for drafting support, and Texaco for allowing us to publish this work. We are grateful also to Drs. James C. Hower and Peter Warwick for their constructive reviews of the manuscript.
References Bender, F.K., 1995. Palaeographic and geodynamic evolution. in: Bender, F.K., Raza, H.A. ŽEds.., Geology of Pakistan ŽChap. 6.. Gebruder ¨ Brontraeger, Berlin, pp. 162–181. Brink, G.I., Logan, A.M., 1997. Sequence stratigraphic approach to the Goru Petroleum system in the middle Indus basin. Pakistan Bull., Am. Assoc. Pet. Geol. 81 Ž8., 1365, Abstract. Combaz, A., 1980. Les kerogenes ´ ` vus au microscope, in: Durand, B. ŽEd.., Kerogen: Insoluble Organic Matter from Sedimentary Rocks. Editions Technip, Paris, pp. 55–112. Dolan, P., 1990. Pakistan: a history of petroleum exploration and future potential. in: Brooks, J. ŽEd.., Classic Petroleum Provinces. Geol. Soc. ŽLondon. Special Publication No. 53, pp. 503–524. Dungworth, G., Abernethy, I., 1988. Well Sann-1, a petroleum geochemical report. Unpublished Paleoservices Report. Espitalie, ´ J., Laporte, J.L., Madec, M., Marquis, F., Leplat, P., Poulet, J., Boutefeu, A., 1977. Methode rapide de characterisation des roches meres de leur potential petrolier et de leur degre d’evolution. Rev. Inst. Fr. Pet. 32, 23–42. Katz, B.K., 1989. Geochemical review: Sann a1 well and coastal Makran Region, Pakistan. Unpublished Texaco EPTD internal report 89-0920. Kingston, J., 1986. Undiscovered petroleum resources of south Asia. USGS Open-File Report 86-80. Quadri, V.-N., Quadri, S.M.G.J., 1996. Anatomy of success in oil and gas exploration in Pakistan, 1915–1994. Oil and Gas J. 94 Ž20., 92–97.
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Quadri, V.N., Shuaib, S.M., 1986. Hydrocarbon prospects of southern Indus basin. Pakistan. Bull., Am. Assoc. Pet. Geol. 70 Ž6., 730–747. Quadri, V.-N., Shuaib, S.M., 1987. Geology and hydrocarbon prospects of Pakistan’s offshore Indus basin. Oil and Gas J. 85 Ž35., 65–67. Shah, S.M.L., 1978. Stratigraphy of Pakistan. Geol. Surv. Pakistan, Memoir. 12, 138. Shuaib, S.M., 1982. Geology and hydrocarbon potential of offshore Indus basin. Bull., Am. Assoc. Pet. Geol. 66 Ž7., 940–946. Smith, M.A., Schwab, K.W., Bissada, K.K., 1992. Organic facies analysis of Cretaceous petroleum source rocks, southern Indus basin. Pakistan Bull., Am. Assoc. Pet. Geol. 76 Ž7., 1126–1127, Abstract. Soulsby, A., Kemal, A., 1988a. A review of exploration activity in Pakistan. Oil and Gas J. 86 Ž47., 56–58. Soulsby, A., Kemal, A., 1988b. A review of exploration activity in Pakistan. Oil and Gas J. 86 Ž48., 81–83. Stanley, S.M., 1989. Earth and Life Through Time, 2nd edn. Freeman, New York, 689 pp.
Organic facies in Cretaceous and Jurassic hydrocarbon source rocks, Southern Indus basin, Pakistan C.R. Robison ) , M.A. Smith 1, R.A. Royle
2
Texaco Exploration and Production Technology Department, 3901 Briar Park Dr., Houston, TX 77042, USA
Abstract A detailed organic petrographic study of the geologic section penetrated by the Sann a1 well in the Southern Indus basin ŽKirthar Trough. of Pakistan permits definition of organic facies and oil-generation potential of Cretaceous and Jurassic source rocks. The well encountered Eocene through Jurassic rocks; however, only closely spaced samples of fine-grained rocks from the Cretaceous Goru, Sembar, and the Jurassic Chiltan formations in the well were studied in detail. Kerogen from the samples was examined in blue light epifluorescence and transmitted white light. The petrographic data are compared with total organic carbon and Rock-Eval w pyrolysis data from an earlier study. The results of the present study demonstrate that three distinct organic facies are present within the Sann a1 section. Organic facies A is oil-prone and consists of fluorescent amorphinite with trace to minor amounts of alginite and other liptinites. This facies quite possibly represents deposition in reasonably deep water. In shallower water conditions, a mixture of non-fluorescent and fluorescent amorphinite with some liptinites and vitrinite was deposited. This mixture of kerogen maceral types characterizes organic facies B, which contains both oil- and gas-prone organic material. Organic facies C was deposited under the most oxidizing shallow-water conditions of the three facies. It is largely gas-prone and contains mostly non-fluorescent amorphinite and minor amounts of vitrinitic material. A cyclical variation in kerogen types is characteristic of the studied well section. Such cyclic variation was produced by repeated periods of transgression and regression. If these variations, which produced the different organic facies, are confined to the trailing edge of the Cretaceous Indian subcontinent, then local controls such as the velocity of the subcontinent’s northward movement instead of global change in sea level may
)
Corresponding author. Fax: q1-713-954-6911; E-mail: [email protected] Present address: 1123 Shillington Dr. Katy, TX 77450, USA. 2 Present address: 5523 Rutherglen, Houston, TX 77096, USA. 1
0166-5162r99r$ - see front matter q 1999 Elsevier Science B.V. All rights reserved. PII: S 0 1 6 6 - 5 1 6 2 Ž 9 8 . 0 0 0 4 6 - 9
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C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
have determined the extent of water depth along the margin of the subcontinent. q 1999 Elsevier Science B.V. All rights reserved. Keywords: organic facies; petroleum source rocks; organic petrology; organic geochemistry; Southern Indus basin; Kirthar Trough; Southern Pakistan
1. Introduction A suite of cuttings and some cores from the Sann a1 well, located along the west-central edge of Kirthar Trough, Southern Indus basin, Sindh Province, Pakistan ŽFig. 1., were evaluated using organic petrographic and geochemical methods. The purpose of this study was to try to define the hydrocarbon potential of petroleum source rocks in the area of the Sann a1 well. The geochemical data given here support the existence of high quality oil and gas source rocks in the area where the well was drilled and also permit the recognition of three distinct organic facies within these source rocks as originally defined by Smith et al. Ž1992.. Excellent agreement among the organic carbon, pyrolysis, and organic petrologic data allows earlier ambiguities to be resolved and permits novel interpretation techniques to define organic facies and individual transgressive cycles.
2. Geologic setting The Indus basin ŽFig. 1. is a large Late Paleozoic through Paleogene downwarp that occurs along the northwestern edge of the Indian subcontinent ŽDolan, 1990.. It covers the eastern two-thirds of Pakistan, with its axis generally coinciding with the course of the Indus River ŽKingston, 1986.. The Indian Shield to the east and an axial fold belt to the west–northwest ŽQuadri and Shuaib, 1986. confine the Southern Indus basin. Quadri and Shuaib also point out that the Murray Ridge–Owen fracture plate boundary limits the south–southwest offshore extension of the basin. To the north, the Jacobabad Arch separates the Southern from the Central Indus basin ŽFig. 1.. The Indian subcontinent drifted north during the late Mesozoic from a paleolatitude of near 308S to about the equator ŽFig. 2.. Marine marls, turbidites, and shales, along with shelf carbonates and clastics, were deposited in the Southern Indus basin ŽShuaib, 1982; Quadri and Shuaib, 1986, 1987.. Fig. 3 presents the general stratigraphy of the Southern Indus basin and Kirthar Trough as interpreted by Dolan Ž1990.. The Miocene through Pliocene Siwalik Group sediments ŽShah, 1978; Dolan, 1990; Quadri and Quadri, 1996. are thickest in areas closer to the Himalayas, but subsidence and deposition had stopped by the Oligocene throughout most of the lower Southern Indus basin and widespread erosional unconformities developed at that time ŽDolan, 1990; Smith et al., 1992; Bender, 1995., limiting the thickness of the younger deposits in this area. As revealed in the west to east cross section shown in Fig. 4, Tertiary ŽPaleogene and early Neogene. rocks are also relatively thin in the Southern Indus basin. Pab Formation sandstones and Moro
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
207
Fig. 1. Southern Indus basin and Sann a1 well location map Žafter Quadri and Shuaib, 1986..
Formation carbonates represent the latest Cretaceous. Fort Munro, Mughal Kot, and Parh formation limestones, shales, and sandstones ŽFig. 3. underlie these formations. The earliest Cretaceous rocks in the basin belong to the Goru Formation. According to Dolan Ž1990., in the Southern Indus basin the Goru Formation is generally split into a lower
208
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Fig. 2. Late Cretaceous paleogeography. The Indian subcontinent was moving north through the tropical Tethyan realm at a relatively high velocity. Sea level was higher in relation to most land areas than it had been during the Early Cretaceous Žafter Stanley, 1989..
unit of sandstones and shales and an upper unit consisting mostly of shales and marls. Underlying the Goru Formation are the shales of the Cretaceous Sembar Formation, and beneath the Sembar are the carbonates of the Jurassic Chiltan Formation ŽFig. 3.. Table 1 lists the thickness, age, and general lithology of the different formations encountered by the Sann a1 well. The Late Cretaceous Moro and Fort Monro formations were not encountered by the Sann a1 well; however, the lateral equivalent of the Moro Formation ŽPab Formation sandstones. and of the Fort Munro Formation ŽMughal Kot Formation shales. were encountered ŽTable 1; Fig. 3.. Transgressive–regressive facies of a regional nature are particularly well developed in marls and shales of the upper Goru Formation ŽShuaib, 1982; Quadri and Shuaib, 1986, 1987; Brink and Logan, 1997.. Local variations in the type and particle size of organic matter are seen in the underlying lower Goru and Sembar formations, which most likely accumulated in marginal to occasionally deep marine settings. Jurassic and
Fig. 3. General stratigraphy of the Southern Indus subbasin Žafter Dolan, 1990. Žexplanation: CG s conglomerate; FMs formation; GRPsGroup; LST s limestone; JUR.s Jurassic..
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
209
210
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Fig. 4. West to east cross-section through the center of the southern Indus basin; line of section shown on Fig. 1 Žadapted from Quadri and Shuaib, 1986..
Cretaceous lithofacies show a southwest to northeast change from deep to shallow water ŽDolan, 1990.. Marine Cretaceous petroleum source rocks in Southern Indus are part of an independent petroleum system, and they are not particularly overmature for oil generation ŽSmith et al., 1992.. Shales of the Lower Cretaceous oil- and gas-prone Sembar Formation ŽTable 1; Figs. 3 and 4. are considered to be the major source unit in the basin ŽQuadri and Quadri, 1996; Brink and Logan, 1997.. The sandstones of the Cretaceous lower Goru Formation form the main reservoir unit ŽQuadri and Shuaib, 1986; Kingston, 1986; Dolan, 1990; Smith et al., 1992.. Production from the Khaskeli field ŽFigs. 1 and 3. and discoveries in surrounding blocks suggest that source rocks in the region could produce petroleum yields in the range of 65–155 million barrelsrkm2 ŽQuadri and Quadri, 1996..
3. Samples and methods Owing to the poorly consolidated nature of the clay-rich silt and sand samples, most geochemical analyses had to be made on unwashed cuttings samples Ž n s 76. to prevent loss of fine-grained material. The only available core samples Ž n s 3. came from a very limited depth interval within the Chiltan Formation at 3677–3686 m. Total organic carbon ŽTOC. and Rock-Eval w pyrolysis were used to evaluate organic richness and hydrocarbon generation potential, respectively ŽSmith et al., 1992.. Detailed microscopy
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
211
Table 1 Stratigraphy in the Sann a1 well, Southern Indus basin, Pakistan Žadapted from Shah, 1978; Dolan, 1990. Depth to Formationa top Žm.
Stratigraphic unit
Age
Lithology
Laki Formation Ranikot Group ŽLakhra Formation. Ranikot Group ŽBara Formation. Ranikot Group ŽKhadro Formation. Pab Sandstone
Eocene Paleocene
Limestone Sandstone, Gray Shale Sandstone, Gray Shale, Basalt
Mughal Kot Formation Parh Limestone
Late Cretaceous
Albian–Late Cretaceous Aptian?–Albian
3455
Goru Formation Župper. Goru Formation Žlower. Sember Formation
3604
Chiltan Formation
Jurassic
3769
Total Depth
Jurassic
5 95 888 888 1035 1082 1090 1258 2578
a
Paleocene Paleocene Late Cretaceous
Late Cretaceous
Aptian?
Sandstone, Brown Shale Argillaceous Limestone Limestone, Marl Gray Shale, Marl Gray Shale, Sandstone Gray Shale, Calcareous Sanstone Gray Limestone, Gray–Black Shale
The Late Cretaceous Moro and Fort Monro formations are not present in the Sann a1 well.
using transmitted white light and epifluorescence Žblue light. was conducted on all 79 samples to add further definition to the earlier conceived organic facies ŽSmith et al., 1992. and to determine organic maturation levels. The samples examined were split into two subsets; one for organic richness and source potential determinations, the other for kerogen microscopy. For the organic richness and source potential assessments, each sample in the subset was ground to a 200 mesh powder mechanically and then a portion of each powdered sample was treated with hydrochloric acid to dissolve carbonate minerals. The samples were dried and then combusted in a LECO CarbonrSulfur Analyzer for total organic carbon and total sulfur contents. Some of the remaining portions of the powdered samples was subjected to whole rock pyrolysis using a Rock-Eval w pyrolyzer after the method of Espitalie´ et al. Ž1977.. Each sample in the subset for kerogen microscopy was demineralized first with dilute hydrochloric acid Ždissolution of carbonate minerals., washed, and then treated with concentrated hydrofluoric acid Ždissolution of silicate minerals. following standard kerogen isolation procedures ŽCombaz, 1980.. Kerogen macerals were separated from residual mineral matter by heavy liquid separation using zinc bromide Žspecific gravity 1.85–1.90.. Kerogen slides were prepared from concentrated kerogen. The mounting medium used was a non-fluorescent synthetic resin. Kerogen microscopy was performed in both transmitted white light and in blue light epifluorescence with a Nikon Mi-
TOC Ž%.
S Ž%.
1318 1333 1348 1373 1393 1418 1435 1458 1468 1488 1513 1538 1563 1578 1593 1608 1628 1663 1683 1718 1753 1778 1808 1818 1878 1948 1963 1988 2013 2043 2098
5.85 5.51 2.26 1.10 2.81 1.91 2.41 1.66 1.71 1.56 8.75 4.32 2.10 2.09 3.81 3.23 3.38 1.46 1.25 4.21 5.64 11.54 4.33 1.71 2.13 2.96 5.64 2.71 2.11 1.37 1.37
0.77 0.17 0.15 0.11 0.18 0.25 0.41 0.49 0.60 0.43 0.74 0.67 0.58 0.68 0.70 0.77 0.63 0.71 0.69 0.91 1.16 1.33 1.06 0.92 1.13 1.74 1.72 1.99 1.36 1.31 1.34
S1 Žmgrg. 2.08 2.94 1.78 0.15 0.29 0.06 0.35 0.06 0.24 0.11 4.46 1.65 0.41 0.30 0.22 0.59 0.95 0.16 0.15 0.55 1.66 1.94 0.93 0.24 0.28 0.58 1.58 0.15 0.09 0.15 0.16
S2 Žmgrg.
S1 q S2 Žmgrg.
S3 Žmgrg.
HI Ž S2 rTOC.
OI Ž S3 rTOC.
KTR Ž S1 rS1 q S2 .
Tmax Ž8C.
Formation
Organic Facies
38.56 39.95 20.63 3.32 14.11 5.48 12.30 5.77 7.66 5.35 55.15 27.78 10.30 8.66 13.59 19.04 21.97 5.52 4.06 22.31 28.34 75.13 27.63 6.49 7.50 14.01 36.82 10.13 4.46 2.38 1.36
40.64 42.89 22.41 3.47 14.40 5.54 12.64 5.83 7.90 5.46 59.61 29.43 10.71 8.96 13.81 19.63 22.92 5.68 4.21 22.86 30.00 77.07 28.56 6.73 7.78 14.59 38.40 10.28 4.55 2.53 1.52
4.00 2.13 3.72 3.59 4.09 3.41 3.61 3.46 3.67 2.43 2.83 3.82 4.04 3.37 4.65 3.83 2.67 4.25 3.69 3.23 1.95 3.95 1.66 4.22 3.36 3.57 2.33 2.80 4.44 2.54 3.46
659 725 913 302 502 287 510 348 448 343 630 643 490 414 357 589 650 378 325 530 502 651 638 380 352 473 653 374 211 174 99
68 39 165 326 146 179 150 208 215 156 32 88 192 161 122 119 79 291 295 77 35 34 38 247 158 121 41 103 210 185 253
0.05 0.07 0.08 0.04 0.03 0.01 0.03 0.01 0.03 0.03 0.08 0.06 0.04 0.03 0.02 0.03 0.04 0.03 0.03 0.20 0.05 0.03 0.03 0.04 0.04 0.04 0.04 0.01 0.02 0.06 0.11
428 427 425 428 432 429 430 433 427 429 430 428 433 432 434 427 431 431 431 431 431 432 431 430 434 427 429 434 434 434 440
upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru
A A A C B C B B B B A A B B B A A B B A A A A B B B A B C C C
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Depth Žm.
212
Table 2 Total organic carbon and pyrolysis data for the Sann a1 well
1.34 1.82 1.28 1.56 1.38 1.32 1.22 1.24 1.18 1.10 1.22 0.93 1.65 1.18 1.08 1.14 1.13 2.74 1.51 2.13 1.52 1.62 1.31 1.38 1.09 1.35 1.35 1.45 2.25 2.15 2.26 1.26 1.94 2.22 0.96
0.19 0.26 0.16 0.50 0.52 1.10 0.76 0.74 0.69 0.73 0.64 1.22 1.12 1.24 0.57 0.69 0.43 1.36 1.02 1.73 1.65 0.91 0.94 1.47 2.48 2.34 0.96 1.55 5.64 3.32 5.03 2.85 10.16 6.57 2.37
1.73 4.28 1.70 1.60 1.34 6.16 1.99 1.62 1.14 1.03 1.26 2.94 2.37 4.41 1.02 1.26 1.07 2.33 2.95 2.96 5.15 2.13 2.66 3.09 6.14 8.83 2.05 1.76 17.37 6.07 16.83 7.37 29.75 33.91 4.96
1.92 4.54 1.86 2.10 1.86 7.26 2.75 2.36 1.83 1.76 1.90 4.16 3.49 5.65 1.59 1.95 1.50 3.69 3.97 4.69 6.80 3.04 3.60 4.56 8.62 11.17 3.01 3.31 23.01 9.39 21.86 10.22 39.91 40.48 7.33
3.20 2.38 2.87 2.47 4.13 3.16 3.29 3.56 4.05 4.65 2.70 3.22 4.25 3.28 2.09 4.18 4.55 5.31 5.37 4.97 4.78 6.12 3.22 3.90 3.94 3.36 4.04 4.34 5.38 5.48 3.84 4.21 3.68 1.93 3.90
170 236 148 148 108 323 160 140 96 83 118 212 150 249 96 75 67 135 138 148 204 108 127 131 201 273 98 65 333 177 336 281 505 358 235
314 131 250 229 333 165 265 307 340 375 252 232 269 185 197 247 284 309 251 249 189 309 153 165 129 104 192 160 103 160 77 161 62 20 185
0.10 0.06 0.09 0.24 0.28 0.15 0.28 0.31 0.38 0.41 0.34 0.29 0.32 0.22 0.36 0.35 0.29 0.37 0.26 0.37 0.24 0.30 0.26 0.32 0.29 0.21 0.32 0.47 0.25 0.35 0.23 0.28 0.25 0.16 0.32
433 435 437 432 438 426 431 425 431 429 428 428 421 425 422 438 438 424 428 426 416 429 429 426 426 428 428 416 425 428 427 426 422 431 425
upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru Sembar Sembar Sembar Sembar Sembar
C C C C C B C C C C C C C C C C C C C C C C C C C C C C B C B B A B C
213
1.02 1.81 1.15 1.08 1.24 1.91 1.24 1.16 1.19 1.24 1.07 1.39 1.58 1.77 1.06 1.69 1.60 1.72 2.14 2.00 2.53 1.98 2.10 2.36 3.05 3.24 2.10 2.71 5.22 3.43 5.01 2.62 5.89 9.48 2.11
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
2143 2188 2208 2303 2363 2408 2438 2498 2503 2518 2548 2573 2603 2618 2638 2653 2668 2738 2758 2798 2868 2898 2918 2958 2983 2990 3377 3399 3419 3452 3482 3509 3518 3520 3531
214
Depth Žm.
TOC Ž%.
S Ž%.
S1 Žmgrg.
S2 Žmgrg.
S1 q S2 Žmgrg.
S3 Žmgrg.
HI Ž S2 rTOC.
OI Ž S3 rTOC.
KTR Ž S1 rS1 q S2 .
Tmax Ž8C.
Formation
Organic Facies
3559 3598 3611 3631 3658 3660 3680 3685 3689 3709 3721 3722 3731
2.09 1.86 0.81 1.55 1.06 0.74 5.43 1.53 1.46 1.84 2.31 2.87 1.29
1.21 1.19 0.64 0.64 0.50 0.19 1.00 1.75 0.64 0.72 0.71 0.39 0.89
1.66 1.79 0.23 1.68 0.88 0.20 8.95 0.09 2.30 2.15 3.24 2.00 1.22
4.72 2.88 2.14 3.41 1.77 0.91 30.04 0.12 7.29 6.87 10.43 11.49 2.89
6.38 4.67 2.37 5.09 2.65 1.11 38.99 0.21 9.59 9.02 13.67 13.49 4.11
4.88 4.19 1.73 4.26 3.18 1.20 4.36 0.50 3.13 3.36 3.51 1.45 3.58
226 155 264 220 167 123 553 8 499 373 452 400 224
233 225 214 275 300 162 80 33 214 183 152 51 278
0.26 0.38 0.10 0.33 0.33 0.18 0.23 0.43 0.24 0.24 0.24 0.15 0.30
423 424 431 422 428 421 423 413 421 426 423 433 415
Sembar Sembar Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan
C C C C C C A C B B B B C
S1 sdistillable hydrocarbons present in the rock Žmgrg rock.. S2 s hydrocarbons generated from the pyrolysis of kerogen Žmgrg rock.. S1 q S2 s total hydrocarbon generation potential of the rock Žmgrg rock.. S3 sCO 2 generated from kerogen pyrolysis Žmgrg rock.. HI s hydrogen index Žmg generated HCrg of organic carbon.. OI s oxygen index Žmg CO 2 rg of organic carbon.. KTR s kerogen transformation ratio-proportion of distillable hydrocarbons to total hydrocarbon generation potential S1 rŽ S1 q S2 .. Used as a maturation index when samples are contamination-free. Tma x s pyrolysis temperature at which a maximum yield of generated hydrocarbons occurs ŽTmax increases with increasing maturation..
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Table 2 Žcontinued.
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
215
crophot-FXA microscope. Some of the concentrated kerogen for each sample was also embedded in resin and polished for examination in reflected white light and for measurement of vitrinite reflectance using a Zeiss Universal microscope and photometer. Mean random reflectance was measured. Six main maceral classes were used: fluorescent amorphous material, alginite, exinite Žexcluding alginite., non-fluorescent amorphous material, vitrinite, and inertinite.
4. Results and discussion 4.1. Source rock quality and generation potential Source rock richness is based on total organic carbon content ŽTable 2.. Total hydrocarbon generation potential ŽTHGP. is derived from Rock-Eval w pyrolysis S1 q S2 values ŽTable 2; S1 values represent the amount of bitumen in a rock distilled off at pyrolysis temperatures below 3008C; S2 values represent the bitumen generated from thermally cracking kerogen and high molecular weight bitumen in the rock at pyrolysis temperatures between 3008 and 5008C.. TOC and THGP data are cross-plotted in Fig. 5. Above-average Ž) 1.0 wt.%. levels of TOC are found throughout the Goru and Sembar formations, and in isolated depth intervals of the Jurassic Chiltan Formation Ž3630–3659 m; 3678–3679 m., and at depths from 3680 m to total depth in the Sann a1 well ŽTable 2.. Average TOC values for the Cretaceous formations are 2.70% in the upper Goru Ž n s 43., 2.35% in the lower Goru Ž n s 18., and 4.15% in the Sembar Ž n s 7.. Cuttings samples from the Chiltan Formation Ž n s 8. contain an average of 1.56% TOC. The three core samples that were analyzed from the Chiltan Formation from 3680, 3685, and 3689 m were found to contain an average TOC content of 2.81%. The extremely low S1 q S2 Rock-Eval w pyrolysis yield for the core sample from 3685 m ŽTable 2., which had ) 1.5% TOC, suggests contamination from either drilling mud additives or migrant bitumen. Rock-Eval w pyrolysis data ŽTable 2. show good to excellent total hydrocarbon yields throughout the well section studied. Total hydrocarbon generation potentials average 14.31 mg HCrg rock for the upper Goru Formation between 1318 and 2573 m, 5.72 mg HCrg rock for the lower Goru, 18.69 mg HCrg rock for the Sembar, and 9.12 mg HCrg rock for cuttings from the Chiltan Formation. Hydrocarbons that were introduced into the stratigraphic section by either drilling-fluid contamination or migration would be included in the Rock-Eval w S1 peak, but the kerogen transformation ratios ŽKTR. show that only 4% of the hydrocarbon generation potential for rocks above 2300 m and 29% for the thermally mature units below this depth are contributed by S1 distillable hydrocarbons in the rocks. Therefore, it appears from the pyrolysis data that the Sann a1 well has excellent source-rock potential below 1318 m. On Fig. 5, the hydrocarbon yield for most samples is seen to be high relative to their TOC; i.e., they plot above the best-fit line. This indicates that these source rocks are oil-prone and contain little coal or other gas-prone organic matter. The measured level of organic enrichment and the measured distillable hydrocarbon yields Ž S1 values. may be affected by contributions from drilling additives. Because
216
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Fig. 5. Plot of total hydrocarbon generation potential Žpyrolysis S1 q S2 . vs. weight percentage total organic carbon content for Sann a1 samples.
TOC and Rock-Eval w S1 and S2 measurements were substantially lower in core samples from the Jurassic Chiltan Formation between 3677 and 3686 m compared to cuttings samples, selected cuttings samples from near the bottom of the well were thoroughly washed with water to remove as much drilling fluid as possible. TOC and pyrolysis analyses were carried out on these washed samples to determine the extent of possible drilling-fluid contamination. In all cases the quantity of free hydrocarbons Ž S1 s. was lowered, but the overall organic enrichment was not changed significantly. Thus, it appears that contamination by drilling-mud additives is not a serious problem affecting the geochemical analyses conducted on samples from the Sann a1 well. 4.2. Thermal maturation Thermal Alteration Indices ŽTAIs. from visual kerogen assessment indicate the degree of thermal maturation of samples from the Sann a1 well ŽTable 3.. Vitrinite was
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
217
a secondary component of the kerogen in most samples, compared to the amount of amorphous organic matter. The distribution of the few reflectance measurements that were obtained is tabulated in Table 3. These mean reflectance values, although possibly based on reworked material, are consistent with maturation levels suggested by the thermal alteration indices ŽTAIs. as reported in Table 3. The upper Goru Formation between 1318 and 2573 m is within the initial phase of the thermal generation of wet gas and condensate. The deeper samples in this interval, from 1985–2573 m, appear from their Tmax values in Table 2 to be slightly more mature, but their level of maturation is still consistent with the initial phase of hydrocarbon generation. The transition from the initial phase of the thermal generation of hydrocarbons to the main phase of generation and expulsion also occurs within the upper Goru Formation between 2300 and 2400 m based vitrinite reflectance measurements ŽTable 3.. TAI values at about this depth indicate a slightly lower maturation level ŽTable 3.. A mean vitrinite reflectance measurement of 1.09% for a sample from the Sembar Formation at 3530 m places the base of the main phase of hydrocarbon generation and expulsion Žthe ‘oil-window’. near this depth. The lack of vitrinite in deeper samples, including the cored intervals, precluded any additional reflectance measurements. 4.3. Organic facies Although thermally immature to marginally mature, upper Goru samples above 2013 m contain mostly fluorescent amorphous kerogen, indicating that this stratigraphic interval is largely oil-prone ŽTable 3.. Non-fluorescent amorphous kerogen, which is regarded as gas-prone if not thermally overmature, is the most dominant organic matter type in the lower Goru Formation ŽTable 3.. In the Sembar and Chiltan formations, the organic facies alternate between thick units of shallow-water facies C and slightly deeper water facies B to occasional thin units of deep water facies A ŽTable 3.. It is possible that much of this material was originally oil-prone and that thermally mature source rocks in this area may already have generated liquid hydrocarbons. At some point in their history, however, the kerogen in the deeper units in this well appear to have been oxidized, and degraded to become more gas-prone. A further indication of oil proneness can be seen in Fig. 6. Fig. 6 is a modified van Krevelen diagram that plots Rock-Eval w hydrogen and oxygen indices ŽHI—in mg S2rg TOC; OI—in mg CO 2rg TOC. values to distinguish among Types I, II, and III kerogen. Most OI values are quite high, with an average of 186 for the Goru units, 157 for the Sembar Formation, and 215 for the Chiltan samples. For cleaned Sembar and Chiltan samples, the OIs were reduced by about a factor of 3 while the HIs were affected only slightly, suggesting that the high OIs are related to a possible contaminant in the drilling mud rather than to bitumen in the rocks. The most oil-prone samples in the well, as indicated by HIs above 600, all occur within the upper Goru Formation above 2013 m. Looking at the distribution of HI and OI ratios on Fig. 6, it is apparent that they should be separated into three separate organic facies. Samples from Organic Facies A are oil-prone with predominantly Type I and lesser amounts of Type II kerogen. Facies B and C contain a mixture of Type II and
218
Table 3 Organic petrologic data for the Sann a1 well Fluorescent amorphous Ž%.
Alginite Ž%.
Exinite Ž%.
Oil-prone Ž%.
Nonfluorescent amorphous Ž%.
Vitrinite Ž%.
Inertinite Ž%.
Gas-prone Ž%.
TAI ŽThermal Alteration Index.
Vitrinite reflectance Žmean %; min–max; n.
Formation
Organic Facies
1318 1333 1348 1373 1393 1418 1435 1458 1468 1468 1513 1538 1563 1578 1593 1608 1628 1663 1683 1718 1753 1778 1808 1818 1878 1948 1963 1968
65 70 90 55 65 45 65 35 45 50 60 70 50 40 55 65 90 45 45 60 60 85 85 45 45 50 85 40
5 10 5 0 5 0 5 0 0 5 5 10 0 0 5 5 0 0 0 5 5 5 0 0 0 0 0 0
15 15 5 5 10 10 5 15 10 10 15 5 10 5 15 15 0 20 25 20 15 5 10 10 15 15 5 0
85 95 100 60 80 55 75 50 55 65 80 85 60 45 75 85 90 65 70 85 80 95 95 55 60 65 90 40
0 0 0 30 0 25 25 25 30 30 10 10 20 30 10 0 0 20 20 10 10 0 0 25 25 25 0 30
15 5 0 10 5 10 0 10 10 5 5 5 15 20 10 10 10 10 10 5 5 5 5 15 10 10 10 20
0 0 0 0 15 10 0 15 5 0 5 0 5 5 5 5 0 5 0 0 5 0 0 5 5 0 0 10
15 5 0 40 5 35 25 35 40 35 15 15 35 50 20 10 10 30 30 15 15 5 5 40 35 35 10 50
2.3 2.3 2.3 2.3 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.5 2.5
– – – – – – – – – – – – – – – – – – – – – – – – – – – –
upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru
A A A C B C B B B B A A B B B A A B B A A A A B B B A B
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Depth Žm.
0 0 0 0 0
5 5 0 0 5
25 15 0 5 45
50 70 90 80 40
20 15 10 15 10
5 0 0 0 5
70 85 100 95 50
2.5 2.5 2.5 2.5 2.5
upper Goru upper Goru upper Goru upper Goru upper Goru
C C C C C
upper Goru upper Goru upper Goru
C C C
2.5 2.5 2.6 2.6 2.6 2.6 2.6
– – – – 0.65 Ž0.49–0.83; ns18. – – 0.72 Ž0.54–0.89; ns 40. – – – – – – –
2208 2303 2363
0 0 0
0 0 0
0 0 0
0 0 0
90 90 95
10 10 5
0 0 0
100 100 100
2.5 2.5 2.5
2408 2438 2498 2503 2518 2548 2573
40 0 0 0 0 0 25
0 0 0 0 0 0 0
10 0 0 0 0 0 10
50 0 0 0 0 0 35
30 80 85 95 95 90 45
20 20 10 5 5 5 15
0 0 5 0 0 5 5
50 100 95 100 100 100 60
upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru upper Goru
B C C C C C C
2603 2618 2638 2653 2668 2738 2758 2796 2868 2898 2918 2958 2963 2990 3377
0 40 0 0 0 10 10 10 15 0 0 0 20 15 0
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
0 15 0 0 0 5 0 0 5 0 5 5 0 0 0
0 55 0 0 0 5 10 10 20 0 5 5 20 15 0
90 25 95 100 100 80 80 85 70 90 85 85 75 80 95
10 20 5 0 0 15 10 5 10 5 5 5 5 5 5
0 0 0 0 0 0 0 0 0 5 5 5 0 0 0
100 45 100 100 100 95 90 90 80 95 90 90 85 85 100
2.6 2.6 2.6 2.6 2.6 2.6 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7
– – – – – – – – – – – – – – –
lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru lower Goru
C C C C C C C C C C C C C C C
219
20 10 0 5 40
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
2013 2043 2098 2143 2188
220
Table 3 Žcontinued. Fluorescent amorphous Ž%.
Alginite Ž%.
Exinite Ž%.
Oil-prone Ž%.
Nonfluorescent amorphous Ž%.
Vitrinite Ž%.
3399 3419 3452 3482 3509 3518 3520 3531
0 55 15 55 40 65 45 25
0 5 0 0 0 5 0 0
0 15 0 15 10 15 5 0
0 75 15 70 50 85 50 25
100 15 80 20 40 10 40 50
0 5 5 5 5 5 10 25
3559 3596 3611 3631 3658 3660 3680 3685 3689 3709 3721 3722 3731
25 10 35 25 0 0 70 0 65 45 60 60 25
0 0 0 0 0 0 5 0 0 0 0 0 0
0 0 0 0 0 0 15 0 15 20 15 20 0
25 10 35 25 0 0 90 0 80 65 75 80 25
75 85 45 65 95 90 5 90 5 15 10 10 70
0 5 5 0 5 5 5 10 5 10 10 5 5
Inertinite Ž%.
Gas-prone Ž%.
TAI ŽThermal Alteration Index.
Vitrinite reflectance Žmean %; min–max; n.
Formation
Organic Facies
0 5 0 5 5 0 0 0
100 20 85 25 45 15 50 75
2.9 2.9 2.9 2.8 2.8 2.9 2.9 2.9
lower Goru lower Goru lower Goru Sembar Sembar Sembar Sembar Sembar
C B C B B A B C
0 0 15 10 0 5 0 0 10 10 5 5 0
75 90 50 65 100 95 10 100 10 25 20 15 75
2.9 2.9 2.9 2.9 2.9 2.9 3.0 3.1 3.1 3.1 3.1 3.1 3.0
– – – – – – – 1.09 Ž0.88–1.28; ns18. – – – – – – – – – – – – –
Sembar Sembar Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan Chiltan
C C C C C C A C B B B B C
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Depth Žm.
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
221
Fig. 6. Plot of Kerogen Type and Organic Facies as defined by Rock-Eval w HI and OI indices. Three Organic Facies are delineated, with oil-prone type-I kerogen found only in Facies A and oxidized, gas-prone type-III kerogen characterizing Facies C. Possible thermal degradation pathways for samples from individual sequences are also shown on the diagram Žafter Smith et al., 1992..
III kerogen and are more gas-prone. Facies C is distinguished by OIs greater than 150 and somewhat lower HI values than Facies B and it includes almost all upper Goru samples below 2013 m. Stratification of water depth in sequences up to several hundred meters thick are contained in individual formations. For example, source facies in the upper Goru Formation display upwardly asymmetrical cycles of regressive–transgressive sequences from shallow-water, gas-prone Facies C through less oxidized Facies B to the deep-water, oil-prone Facies A ŽTables 2 and 3; Fig. 7.. This manner of source rock deposition explains why both oil and gas source rocks were identified in the upper Goru by Katz Ž1989.. Organic Facies C dominates the lower Goru Formation ŽTables 2 and 3.. The
222
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
Fig. 7. Asymmetric changes in organic facies within the Cretaceous upper Goru Formation as defined by marked variations in oil-prone kerogen concentrations and in Rock-Eval w HI values of kerogen.
Sembar Formation grades from Facies C at around 3598 m to Facies B at 3520 m, Facies A at 3518 m, and then back to Facies B between 3518 and 3482 m ŽTables 2 and 3.. The Chiltan Formation grades upward from Facies A to B starting at 3731 m to Facies C between 3660 and 3611 m ŽTables 2 and 3.. The van Krevelen diagram in Fig. 6 also indicates the relative level of thermal maturation of the organic matter as the HI and OI values decrease along fixed pathways relating to burial and time–temperature alteration. Interpretation of kerogen-type data plotted on Fig. 6 is complicated further because OI values may be elevated from drilling-mud contamination. HIs for the lower Goru, Sembar, and Chiltan formations, all of which fall within the ‘oil-window’, reflect S2 values that have been lowered as hydrocarbons were released from effective source-rock intervals.
C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
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5. Summary and conclusions The Indus basin is a large Late Paleozoic–Paleogene downwarp that developed on the northwestern margin of the Indian Platform. It covers the eastern two-thirds of Pakistan ŽKingston, 1986., and the basin axis generally coincides with the course of the Indus River. Although the Miocene Siwalik Group can reach great thickness farther to the north near the Himalayas, subsidence and deposition had ceased by late Palogene throughout most of the Indus basin and widespread erosional unconformities developed at that time ŽDolan, 1990; Smith et al., 1992; Bender, 1995.. Recoverable gas reserves from 14 fields total about 22 tcf, but more than 90% of Pakistan’s gas production and 57% of the gas reserves are from the giant Sui and Mari fields ŽFig. 1., both of which were discovered in the 1950s and produce from Eocene carbonate reservoirs in the central basin ŽQuadri and Quadri, 1996.. Oil was discovered in the Cretaceous upper and lower Goru Formation at Khaskeli in 1981, and several small fields with estimated reserves of about 50 million barrels of oil were developed in the next few years. More recently, additional discoveries have increased gas production from other areas of the basin ŽSoulsby and Kemal, 1988a,b; Quadri and Quadri, 1996.. Oil fields southeast of the location of the Sann a1 well produce from the upper Goru Formation in a stratigraphic setting similar to that of the Sann a1. In the area southwest of the Sann a1 well, the Tertiary section is only about 1000 m thick and the underlying Cretaceous rocks are probably not overmature for oil generation. The Sann a1 was an exploratory wildcat well drilled during a 6-month period in 1984–1985 by the Oil and Gas Development Corporation of Pakistan. Early work on the well ŽDungworth and Abernethy, 1988. provided a thermal maturation profile and identified important possible oil and gas source sequences within the upper Goru and lower GorurSembar Formations. These workers also reported oil source quality for the Chiltan Formation. Although their work involved samples that may have been contaminated or stained, the new geochemical data presented here supports the concept of high quality petroleum source rocks throughout the Cretaceous and Upper Jurassic section in the Sann a1 well. Thermal maturity determinations for the Sann a1 section from mean vitrinite reflectance and TAI data are in general agreement. Based on this data, the top of the ‘oil window’ Ž R o of ; 0.60%. occurs at a depth of 2000 m and the base of the ‘oil window’ Ž R o of ; 1.30%. occurs at an extrapolated depth of about 4000 m. The Rock-Eval w pyrolysis data for the upper Goru Formation support the organic petrographic observations on thermal alteration, source quality and type, and organic facies. There is a pronounced increase in the kerogen transformation ratios ŽKTR; S1rS1 q S2 . of the upper Goru at a depth of 2300 m from an average of 0.04 to 0.30. This jump in KTR values corresponds to the start of peak oil and gas generation, and it appears to represent the onset of indigenous hydrocarbon generation. Additionally, the Tmax for the upper Goru also increases slightly between 1963 and 2013 m ŽTable 2., corresponding to entry into the ‘oil window’ at this point. Tmax values in the deeper stratigraphic units have been suppressed, probably by some inevitable drilling-fluid contamination, and are no longer a reliable indicator of thermal maturation.
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C.R. Robison et al.r International Journal of Coal Geology 39 (1999) 205–225
The richest hydrocarbon source rocks in the well are found in the thermally immature upper Goru section above 2013 m. Fluorescent amorphous kerogen is prevalent, suggesting a largely oil-prone unit. The Goru Formation is the reservoir unit of oil fields to the southeast of the Sann a1 well, many of the samples come from intervals that are defined here as belonging to deep-water, oil-prone Organic Facies A. Individual transgressive sequences that shallow upward into Facies C are from 40 to 165 m thick, and are capable of generating both oil and gas following additional burial and thermal alteration. Kerogen types are also quite distinct for the deeper units. The Sembar and the few Chitlan samples examined are more oil-prone than samples from the lower Goru. However, the kerogen in the Chitlan appears to be more heavily oxidized than that in the Sembar Formation and lower Goru Formation. The most prospective mature source-rock interval occurs between 3270 and 3585 m. The lower Goru and Sembar formations at this depth are within the zone of peak oil generation and contain mostly non-fluorescent amorphous kerogen. Rock-Eval w data suggest that although liquid hydrocarbons may have already been expelled from these units, this section retains considerable gas generation potential.
Acknowledgements We thank Ewa Szymczyk and L.M. Darnell of the Houston Advanced Research Center ŽHARC. for their analytical support, M.A. Weismiller of Texaco EPTD for drafting support, and Texaco for allowing us to publish this work. We are grateful also to Drs. James C. Hower and Peter Warwick for their constructive reviews of the manuscript.
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