Revised models for hydrocarbon generation, migration and accumulation in Jurassic coal measures of the Turpan basin, NW China

Organic Geochemistry 32 (2001) 1127–1151 www.elsevier.com/locate/orggeochem

Revised models for hydrocarbon generation, migration and accumulation in Jurassic coal measures of the Turpan basin, NW China Maowen Lia,*, Jianping Baob, Renzi Linc, Lavern D. Stasiuka, Mingsheng Yuand a

Geological Survey of Canada, 3303-33 St. NW Calgary, Alberta, Canada T2L 2A7 b Jianghan Petroleum University, Hubei 434102, China c Petroleum University (Beijing), Changping 102200, China d PetroChina Tu-Ha Oilfield Company, Xingjiang 839001, China Received 18 April 2001; accepted 15 June 2001

Abstract Whether or not the Lower-Middle Jurassic coal measures in the Turpan basin of NW China have generated commercial quantities of liquid petroleums is a problem of considerable importance that remains contentious as it has not yet been resolved unequivocally. This study provides evidence against the Jurassic humic coals as the only major source for the oils discovered in the Taibei depression of this basin and suggests additional significant contributions from the Upper Permian and Middle–Lower Jurassic lacustrine source rocks. The Carboniferous–Permian marine source rocks may have been important also in limited locations along the major basement faults. Molecular and petrographic data indicate that the majority of the Middle Jurassic strata are currently immature or marginally mature with respect to hydrocarbon generation. Within the major depocenters, the Middle–Lower Jurassic coal-bearing strata of the Baodaowan and Xishanyao formations has reached the conventional oil window (i.e. with vitrinite reflectance >0.7% Ro). Pre-Jurassic (Upper Permian in particular) derived hydrocarbons appear to be widespread in extracts of fractured Jurassic coal and finegrained rocks. Large differences have been observed in the absolute concentrations of biomarker compounds in rock extracts of various source intervals. Thus, ‘‘coaly’’ biomarker signatures of the oils most likely resulted from mixing and migration contamination when hydrocarbons derived from mature source rocks migrated up through highly fractured coal seams along deep-seated faults. In addition to conventional exploration targets, revised petroleum generation and accumulation models predict that the focus in the Turpan basin should also include deep structures within the Carboniferous–Permian strata and subtle, low magnitude anticlines and stratigraphic traps within the Triassic– Jurassic sections. Crown copyright # 2001 Published by Elsevier Science Ltd. All rights reserved. Keywords: Jursassic coal measures; Turpan basin; Coal-derived oils; Chinese oils; Lacustrine source rocks

1. Introduction Terrestrial organic matter, coals and coaly shales, can be a source for liquid hydrocarbons (e.g. Hedberg, 1968;

* Corresponding author. Tel.: +1-403-2927042; fax: 1-4032927159. E-mail address: [email protected] (M. Li).

Snowdon and Powell, 1982; Durand and Paratte, 1983; Khavari Khorasani and Murchison, 1988; Powell et al., 1991). The importance of this potential source of hydrocarbons has been highlighted by the discovery of a number of oil-gas fields from the Mesozoic–Cenozoic coal measures or related strata around the world. Welldocumented examples include the Gippsland (Thomas, 1982; Shanmugam, 1985) and Cooper/Eromanga basins in Australia (Vincent et al., 1985); the Beaufort-Mackenzie

0146-6380/01/$ - see front matter Crown copyright # 2001 Published by Elsevier Science Ltd. All rights reserved. PII: S0146-6380(01)00070-5

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Delta in Canada (Snowdon and Powell, 1982); the Mahakam Delta in Indonesia (e.g. Robinson, 1987; Peters et al., 1999) and the Niger Delta in Nigeria (e.g. Ekweozor et al., 1979). The Jurassic in China was an era of extensive coal formation, and oils and gases are commonly found in Jurassic reservoirs in northwest China. After encountering commercial oils in 1989 from the Lower–Middle Jurassic coal measures of the Turpan Basin, several large oil fields (e.g. Shanshan, Qiuling, Wenjisang, Shanle) with a combined total in-place reserve of over one billion barrels were soon confirmed (Cheng and Zhao, 1998). Since 1990, many oil–gas fields with significant reserves have been found from the coal measures of similar stratigraphic horizons in the adjacent basins, including the Tarim, Junggar, Yanqi and Santanghu basins, all within the Xinjiang Uygur Autonomous Region (Dai and Sun, 1996; Dai et al., 1999). Most oils produced from the Taibei depression of the Turpan basin have been considered by previous workers as coal-derived hydrocarbons (Huang et al., 1991, 1995; Cheng, 1994). These oils are somewhat similar to other oils derived from terrestrial organic matter (Tissot and Welte, 1984; Shanmugam, 1985; Philp and Gilbert, 1986; Tegelaar et al., 1989), with low sulfur content, high pristane/phytane ratio, high C29 regular steranes and the presence of terpane biomarkers indicative of terrigenous origin (e.g. Cheng, 1994). It was suggested that the presence of hydrogen-rich macerals (suberite and resinite) in coals is favorable for the early generation of liquid hydrocarbons (Cheng and Zhao, 1998). According to these authors, generation of liquid hydrocarbons from these hydrogen-rich macerals in coals starts at vitrinite reflectance (Ro) as early as
0.35%, reaches peak stage at
0.6%, and terminates at
0.7–0.8%. Because the most favorable stage for coal-derived liquid hydrocarbon expulsion was considered to occur prior to 0.7% Ro (Cheng and Zhao, 1998), primary exploration targets for liquid hydrocarbons in the Mesozoic–Cenozoic intermontane basins of northwestern China have been focused on traps at shallow horizons, particularly on Jurassic sand bodies with the coal seams at their tops and bottoms. There is no doubt that terrestrial organic matter in the Jurassic coal measures has made contributions to oil and gas discovered in the Turpan basin. On a quantitative basis, however, oil is produced predominantly from the Lower–Middle Jurassic strata. This is in sharp contrast with many coal-bearing sequences in other parts of the world where vitrinite-rich, humic coals usually produce far more gas than oil (e.g. review by Hunt, 1991; Snowdon, 1991). This exceptional circumstance was interpreted as being due to the relatively high liptinite (e.g. suberinite, resinite) contents of the coals (e.g. Cheng, 1994; Cheng and Zhao, 1998). Several pre-Jurassic strata have been observed from outcrops surrounding the Turpan

basin (e.g. Greene et al., 1997), but their spatial distributions and petroleum source potentials have not been properly constrained, due to their deep burial in the basin area, limited well control and the poor quality of seismic reflection data. Consequently, whether or not these strata have generated and contributed liquid hydrocarbons to the Jurassic coal measures has not been seriously considered prior to this study. The purpose of the present study is to characterize the potential sources (organic input and depositional environment), thermal maturity relationships of the light oils and gas-condensates, and to understand the mechanisms controlling their accumulation in the Turpan basin. The answer to these questions has fundamental implications for models of oil expulsion, migration and accumulation in the Mesozoic–Cenozoic coal-bearing strata in the Turpan basin. This in turn can be of significant importance for further oil exploration in northern China, as many sedimentary basins have tectono-stratigraphic settings similar to the Turpan basin.

2. Geological setting and petroleum occurrence The Turpan basin is located about 150 km (or 100 miles) east of Urumuqi, the capital city of the Xinjiang Uygur autonomous region of northwestern China. It is an intermontane basin in the eastern part of the Tianshan Mountains fold belt, with an area of 35,000 km2 (13,500 sq. miles). The Turpan basin was a semi-closed depression created by collision of the surrounding plates during the Late Carboniferous–Early Permian (Hou, 1995). The first-order tectonic units of the Turpan basin (Fig. 1) include (A) Taibei depression, (B) Central uplift and (C) Tainan depressioon. Fig. 2 shows the generalized stratigraphic column of the basin. There were marine incursions during the basin’s early history, thus the Carboniferous–Lower Permian strata (marine carbonates, volcaniclasts and silicic rocks) are the oldest sedimentary rocks that are currently nonmetamorphosed. A paralic lake developed during the Late Permian, and then progressively evolved into an inland intermontane basin in the early Mesozoic. The Turpan basin is asymmetrical, with the deepest and thickest sediments in the north, and shallowest and thinnest in the south. The thickness of Mesozoic and Cenozoic sediments in the main depocenters is over 7000 m. The Lower–Middle Jurassic section contains fluvial coalbearing strata about 2500 m thick. The total thickness of the coal seams is more than 100 m, occurring mainly in the lower part of the section, i.e. in the Badaowan Fm. (J1b) and to a lesser extent in the Xishanyao Fm. (J2x). The upper part of the Middle Jurassic Qiketai Fm. (J2q) is composed of about 50–100 m of black lacustrine mudstones, whereas the Upper Jurassic Qigu Fm. (J3q) contains over 600 m of red clastic sediments.

M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

Fig. 1. (A) Location map showing the major tectonic units of the Turpan-Hami basins; A, Taibei depression: B, Central uplift (including h, Lukexun Arch) and C. Tainan depression (including i, Tuokexun sag). (B) Enlarged map of Taibei Depression of the Turpan basin: a, Shengbei Sag; b, Shanshan Arch; c, Quidong Sag; d, Bogeda foothills; e, Hongtai Structural Zones; f, Xiaocaohu Sag; and g, Flamong Mountain-Qiketai Structural Zone. Oil and gas field locations: 1. Shanshan (oil); 2. Qiuling (oil); 3. Baka (oil); 4. Wenxi (oil/gas); 5. Wenjisang (oil/gas); 6. Mideng (gas); 7. Qiudong (gas); 8. Shanle (oil); 9. Qiketai (oil); 10. Hongtai (gas-condensates); 11. Hongnan (oil); 12. Shengjinkou (oil); 13. Tuyuke (heavy oil); 14. Yilahu (oil).

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Fig. 2. Stratigraphy and likely petroleum systems of the Turpan basin. Petroleum systems I–IV represent four possible source rockreservoir-cap rock combinations. Modified from Huang et al. (1995), based on data prior to this study.

Several potential source beds are present in the Taibei depression (Fig. 2). The first two potential source beds have been observed mainly at outcrops near the basin margins and from wells in the Central uplift. These include the Carboniferous–Lower Permian marine carbonates and clastics, and the paralic lacustrine sediments of the Upper Permian Taodonggou Group (Taerlang and Daheyuan formations, P2t-d). The Taerlang Fm. in the Turpan basin is equivalent to the Lucaogou Fm. in the Junggar basin (Carroll et al., 1992), and it consists of

dark mudstones, shales, argillaceous limestones and oil shales, with a total thickness of 200–600 m. No wells have been drilled deep enough to penetrate these sections near the Mesozoic depocenters, except the Shanke1 well drilled near the Shanshan oilfield (location 1 in Fig. 1) in late 1999. This well penetrated into the Permian strata and encountered over 80 m of oil column in the Triassic section. The other potential source beds occur in the Lower–Middle Jurassic coal-bearing strata (mainly in the Badaowan and Xishanyao formations),

M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

and the Middle Jurassic Qiketai Fm. (J2q) containing black mudstones formed in semi-deepwater lakes. Regional flow barriers and hydrocarbon seals in the Taibei Depression include the shales in the Middle Jurassic Qiketai Fm. –Upper Jurassic Qigu Fm., and the upper part of the Middle Jurassic Xishanyao Fm. In places where the local seals were well developed, favorable conditions may have also existed for oil accumulations in the Permian–Triassic traps.

3. Samples and methods Samples used in this study include 47 cores with detailed sedimentological description, 44 drill stem test oils, and 83 gas samples collected at separator. Chemical compositions, stable carbon, hydrogen and helium isotope data for all the gas samples were made available to this study by the PetroChina Tuha Oilfield Company, together with the stable carbon isotope data for some of the DST oils and rock extracts. All of the oil samples were initially screened by gasoline range hydrocarbon analysis using the analytical techniques reported in Osadetz et al. (1994). Most core samples used in this study were characterized previously (Huang et al., 1991; Cheng, 1994). The total organic carbon contents (TOC) and petroleum potentials of the cores were initially determined using a Rock-Eval 6 instrument. Whole rock samples were prepared for petrographic analysis, reflectance measurement and incident fluorescent light microscopy, as described in Stasiuk and Snowdon (1997). The cores were then extracted using a Soxhlet apparatus with a distilled chloroform/methanol azeotrope (87:13, v/v, 72 h). After the addition of synthetic standard compound, d4-24-ethylcholestane, and asphaltene precipitation, pre-weighed rock extracts or oils were fractionated by silica/alumina column chromatography into saturate, aromatic hydrocarbons and a polar resin fraction. The saturate and aromatic hydrocarbon fractions were analyzed by gas chromatography (GC), gas chromatography–mass spectrometry (GC/MS). Selected saturate fractions were also analyzed by gas chromatography-mass spectrometry-mass spectrometry (GC/MS/ MS). The instrumentations, analytical conditions and quantification methods were described in Li et al. (1999).

4. Results and discussion 4.1. Characteristics of potential petroleum source beds Detailed source rock isopach maps can be found in Cheng (1994), Huang et al. (1995) and Zhang et al. (1997). Vitrinite reflectance isopach maps for individual stratigraphic sections were reported previously by Wang et al. (1996). According to these studies, the deepest

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portions of the Lower Jurassic Badaowan Fm. in the Tainan depression (Tuokexun Sag; location i, Fig. 1) have vitrinite reflectance values (Ro) < 0.6%. As the Triassic strata are marginally mature, the only viable, significant petroleum source rocks in this depression are most likely to be the Carboniferous–Permian section. No sediments in other parts of the Tainan depression have reached the main oil window, thus no significant hydrocarbon generation would be expected to have occurred there. Organic petrology, Rock-Eval, bulk chemical and GC/MS data from the cores used in this study are presented in Tables 1–4. The following discussion focuses on geochemical and petrographic characteristics of the source rocks that are the most critical for resolving the question of effective petroleum source intervals in the Taibei depression. The Middle Jurassic Qiketai formation (J2q, Fig. 2) consists of around 50–100 m of dark shales and mudstones, and occurs mainly within the Shengbei and Qiudong sags (Fig. 1). These Types I–III source rocks contain on average 2% TOC and exhibit the highest hydrocarbon generating potential among all the source beds in the basin, with Rock-Eval hydrogen index values (HI) up to 765 mg/gTOC (Table 1). As exemplified by the J2q shale sample from the Taican-2 well at 3888 m, the maceral assemblage in these samples is enriched in oil-prone liptinites dominated by dinoflagellates, acritarchs and very small, thin-walled unicellular prasinophyte alginites. Inertinite macerals are also common, together with minor amounts of vitrinite, terrestrial sporinites and Botryococcus alginite. The presence of Botryococcus and small thin-walled prasinophytes indicates a brackish to fresh water environment commonly attributed to ’inner platform’, paralic to restricted lacustrine settings (e.g. Brugman et al., 1994). The depositional environment suggested for the J2q source rocks is consistent with the biomarker distributions in their solvent extracts. These extracts are characterized by low pristane/phytane ratios ( <2), C19 3, the presence of gammacerane, and the relatively high abundance of C27 regular steranes (Fig. 3, Table 3). The most diagnostic character of the Qiketai Fm. source rocks, revealed by their GC/ MS/MS data, is the high abundance of C30 4-methylsteranes and dinosteranes (4a,23,24-trimethylcholestane) relative to the 3-and 2-methylsteranes (Fig. 4). These compounds are thought to be derived from dinoflagellates, which first occurred in the Triassic (Summons et al., 1992). These compounds are either absent or only in trace amount in Jurassic coals, coaly shales and pre-Jurassic rock samples we have examined in the Turpan basin. The vitrinite reflectance values estimated for most J2q source rocks in the Taibei depression are < 0.6% Ro

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Table 1 Origin and Rock-Eval pyrolysis data for the core samples used in this study Lab No. Well

Strata Depth (m) Lithologya

TMAX S1

S2

S3

PI

8857 8858 8859 8876 8877 8878 8879 8892 8883 8888 8861 8862 8886 8884 8863 8860 8864 8880 8881 8882 8884 8885 8887 8889 8890 8891 8865 8866 8867 8869 8870 8871 8872 8853 8854 8893 8894 8895 8896 8897 8868 8873 8874 8875 8855 8856

J2q J2q J2q J2q J2q J2q J2q J2q J2s J2s J2x J2x J2x J2x J2x J2x J2x J2x J2x J2x J2x J2x J2x J2x J2x J2x J3h-s J3h-s J3h-s P2t-d P2t-d P2t-d P2t-d P2t-d P2t-d P2t-d P2t-d P2t-d P2t-d P2t-d T3 C C C C C

447 349 384 322 445 439 441 436 348 406 437 435 437 424 385 461 446

0.04 0.03 0.09 0.01 15.01 0.68 0.99 1.79 0.34 0.02 150.98 235.47 269.23 190.09 0.06 0.21 5.31 0.00 0.00 0.71 0.84 1.52 7.81 0.01 0.08 1.90 21.48 43.10 12.26 0.03 0.00 61.36 0.52 0.16 0.24 40.36 9.46 7.59 0.14 0.75 0.53 0.01 0.08 0.03 0.12 0.31

0.00 0.16 0.06 0.03 0.36 0.00 0.00 0.09 0.00 0.23 3.03 5.75 3.07 5.04 0.14 0.03 0.14 0.00 0.00 0.00 0.88 0.00 0.17 0.00 0.00 0.03 0.67 0.49 0.51 0.24 0.76 1.05 0.32 0.45 0.51 0.31 0.41 0.37 0.21 0.19 0.53 0.05 0.00 0.06 0.12 0.03

0.00 0.00 0.18 0.20 1.50 0.33 0.05 41.69 0.12 0.07 0.02 19.88 0.85 0.50 0.08 0.06 49.82 0.07 40.95 0.01 87.69 0.02 37.71 0.17 0.42 0.09 7.00 0.01 37.92

a b

SHEN-102 SHENGBEI-3 SHENGBEI-3 TAICAN-2 TAICAN-2 TAICAN-2 TAICAN-2 LIAN-1 HONGTAI-1 LE-1 LINGSHEN-1 LINGSHEN-1 HONGTAI-5 HONGTAI-5 LINGSHEN-1 LINGSHEN-1 LINGSHEN-1 TAICAN-2 TAICAN-2 TAICAN-2 HONGTAI-5 HONGTAI-5 HONGTAI-5 LE-1 LE-1 LE-1 AICAN-1 AICAN-1 AICAN-1 AICAN-1 AICAN-1 AICAN-1 AICAN-1 LUNAN-1 LUNAN-1 MA-1 MA-1 MA-1 MA-1 MA-1 AICAN-1 AICAN-1 AICAN-1 AICAN-1 LUNAN-1 LUNAN-1

2395.0 2294.0 2405.0 3863.0 3888.0 3997.0 4004.0 3082.0 1395.0 1700.0 3846.0 3941.0 2390.9 2389.5 4046.5 3670.0 4080.0 4607.5 4769.0 5003.0 2389.5 2390.0 2496.0 2267.0 2520.0 2611.0 2165.0 2175.0 2182.0 3165.0 3166.0 3298.0 3385.0 2077.5 2124.9 2065.3 2131.0 2157.8 2234.0 2397.5 2198.0 3916.0 3979.0 4220.0 2867.0 3446.5

Oil sand Oil stain Shale Shale Shale Shale Shale Shale Oil sand Shale Coal Coal Coal C. shale C. shale C. shale C. shale Shale Shale C. shale Shale Shale C. shale Shale Shale Shale Oil sand Oil sand Oil sand Shale Shale Oil shale Shale C. shale Shale Oil sand Oil sand Oil sand Sandstone Sandstone Silty shale Shale Shale Shale Shale Bio.limestone

451 437 439 436 373 446 431 429 431 426 319 438 439 432 433 431 415 414 433 445 517 445 442 387 437 445

0.00 0.00 0.02 0.00 0.79 0.09 0.07 0.03 1.93 0.02 10.29 17.07 3.46 3.68 0.01 0.02 0.03 0.00 0.00 0.22 0.11 0.11 0.31 0.03 0.03 0.40 13.02 23.15 8.52 0.00 0.00 0.57 0.00 0.00 0.00 26.99 7.71 6.21 0.01 0.00 0.03 0.00 0.00 0.00 0.00 0.00

S2/S3

PC

0.00 0.00 0.00 0.00 1.31 0.06 0.08 0.15 0.18 0.00 13.43 21.04 22.72 16.14 0.00 0.01 0.44 0.00 0.00 0.24 0.07 0.12 0.95 0.07 0.07 0.13 0.04 45.94 0.67 0.75 0.00 0.30 0.00 0.17 63.33 0.19 0.38 32.05 2.87 0.35 87.95 5.52 0.41 24.03 1.73 0.00 0.12 0.00 0.00 0.00 0.01 58.43 5.16 0.00 1.62 0.04 0.00 0.35 0.01 0.00 0.47 0.02 0.40 130.19 5.61 0.45 23.07 1.43 0.45 20.51 1.15 0.07 0.66 0.01 0.00 3.94 0.06 0.05 1.00 0.04 0.20 0.00 0.00 0.00 0.00 0.50 0.00 0.00 1.00 0.01 0.00 10.33 0.02

TOC H I O I HIb 0.00 0.04 0.12 0.06 1.96 0.82 0.79 1.02 0.21 0.12 70.25 81.90 72.17 81.61 0.28 0.50 1.36 0.09 0.13 2.11 1.51 2.29 6.12 0.29 0.36 2.41 3.56 6.60 2.29 1.57 0.62 11.85 1.50 1.00 0.71 6.60 1.87 1.55 0.75 1.92 0.80 0.03 0.27 0.19 0.61 1.14

75 75 16 765 82 125 175 161 16 214 287 373 232 21 42 390 0 0 33 55 66 127 3 22 78 603 653 535 1 0 517 34 16 33 611 505 489 18 39 66 33 29 15 19 27

400 50 50 18 0 0 8 0 191 4 7 4 6 50 6 10 0 0 0 58 0 2 0 0 1 18 7 22 15 122 8 21 45 71 4 21 23 28 9 66 166 0 31 19 2

717

133 175

345

181 138

450

50 100 160

C. Shale=Coaly shale. Numbers obtained after solvent extraction.

(Cheng, 1994; Wang et al., 1996). Slightly more mature J2q source rocks are found only in a small area within the depocenter of the Shengbei sag, with a maximum vitrinite reflectance of only 0.7% Ro. The J2q source rocks have only reached approximately 0.55 and 0.5% Ro in the Qiudong and Xiaocaohu sags respectively. Therefore, because of low maturity levels, the J2q is

unlikely to be a significant source bed for oils found in the Jurassic strata. Volumetrically, the Lower–Middle Jurassic strata in the Badaowan (J1b), Xishanyao (J2x) and Sanjianfang formations (J2s) represent the most obvious candidates for potential hydrocarbon source beds in the Taibei depression. The combined total thickness of these formations is

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Fig. 3. M/z 191 and 217 mass fragmentograms for various source rock extracts in the Turpan basin. T19–T25: C19–C25 tricyclic terpanes; TT24: C24 tetracyclic terpane; Ts and Tm: 18a(H)- and 17a(H)-trisnorhopanes; H29–H35: C29–C35 17a(H),21b(H)-hopanes; Dia27 and Dia29: C27 and C29 diasteranes; C27, C28 and C29: C27, C28 and C29 5a(H),14a(H),17a(H)-20R steranes.

Fig. 4. M/z 414!231 transitions obtained for various source rock extracts in the Turpan basin. Peak 1–4: 3methyl-24-ethylcholestanes; 5–8: 4-methyl-24-ethylcholestanes; 9–11: 4, 23,24-trimethylcholestanes.

over 2500 m. Mudstones deposited in the more distal, lacustrine facies in these formations generally show sterane and hopane distributions similar to those found in the Middle Jurassic Qiketai Formation (Chen et al., 1998). The coal seams typically contain humic coals dominated by vitrinite (Huang et al., 1995), particularly collotelinite which hosts minor but persistent orangefluorescing resinite to exsudatinite, with variable amounts, and in some places high concentrations of cutinite and sporinite. Botryococcus alginite is also present in the coals but only in trace amounts. Hydrogen indices for the coals are typically below 250 mg HC/gTOC when they are immature (Table 1). As observed also by others (Sun et al., 2000), no clear differentiation could be made at the molecular level by terpane and sterane distributions between the humic coals and type III organic matter within associated coaly shales. These sediments, deposited in relatively acidic and suboxic fluvial-swamp environment, are characterized by very high pristane/phytane ratios (>3), C19>C20>>C21 for tricyclic terpanes, C24 tetracyclic terpane/C26 tricyclic terpane>10, and the near absence of gammacerane (Fig. 3, Table 3). The dominance of C29 over C27 and C28 isomers for regular and rearranged steranes was considered as one of the most diagnostic features of the coaly sediments and was indeed observed from many Jurassic coals and coaly shales in the Turpan basin (e.g. Fig. 3b). GC/MS/MS analyses (Fig. 4) indicate that dominantly 3- and 2-methylsteranes are present in the extracts of coals and coaly shales. Thus, the

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absence or low abundance of C30 4-methylsteranes (including dinosteranes) indicative of organic matter derived from dinoflagellates could be used as evidence against a solely coaly organic matter source if they are present in an oil (e.g. Clayton, 1993). The spatial distribution of the Xishanyao Fm. source rocks in the Taibei Depression is similar to that of the Qiketai Fm, except that the maturity level of this formation is slightly higher (Cheng, 1994; Zhang et al., 1997). A detailed vitrinite reflectance isopach map for the Xishanyao Fm. source rocks can be found in Wang et al. (1996). The vitrinite reflectance values of the Xishanyao Fm. source rocks are <0.7% Ro in the Qiudong and Xiaocaohu sags, and slightly higher (0.7– 0.8% Ro) in the Hongnan–Lianmuqing region. Only in a small area at the depocenter of the Shengbei sag is the Xishanyao Fm. currently mature enough to generate liquid hydrocarbons (0.8–0.9% Ro). The most important Jurassic source rocks lie in the Badaowan Fm. of the Shengbei sag. The Badaowan Fm. is currently at the peak stage of liquid hydrocarbon generation within the depocenter of the Shengbei sag, whereas it is only marginally mature in the Qiudong and Xiaocaohu sags (with 0.7–0.8% Ro). The extent of Carboniferous–Permian strata has not been properly constrained in the Taibei depression, particularly in regions away from the current production. Subsidence profiles reconstructed mostly from seismic data (Ren, 1998) show that onset of significant oil generation in the Carboniferous–Permian source rock intervals varies from the Early Jurassic in the major depocenters to very recent at the basin margin. Most Carboniferous–Permian strata in the Taibei depression are currently mature to overmature with respective to hydrocarbon generation, and thus should not be excluded as one of the most important potential petroleum source beds in the basin. The maximum vitrinite reflectance values for these strata have reached approximately 1.20 and 1.00%Ro in the Shengbei and Qiudong–Xiaocaohu sags respectively (Ren, 1998). Outcrop samples from several localities along the basin margin and cores from the Aican-1 well (location 13, Fig. 1) reveal that the Upper Permian Taodonggou group consists of dark mudstones, shales, argillaceous limestones and oil shales, with TOC ranges from 0.5 to 11.7%. As reported by Greene et al. (1997), these strata are the most likely source for the heavy oils discovered in the Tuyuke field (location 13, Fig. 1). Its stratigraphic equivalent, the Lucaogou Fm., has been shown to be the major source rocks in the adjacent Jungeer and Santanghu basins (Carroll et al., 1992). The organic matter in these rocks is enriched in yellow to white-yellow fluorescing, chlorophyte-derived Prasinophyte alginites. Most of the prasinophytes alginites appear to be related to Tasmanites, although other types may also be present (e.g. Cymatiosphera and Pterospermaella). Other mac-

erals include fusinites, inertodetrinite, as well as minor amount of sporinites. Biomarker signatures characteristic of the Upper Permian lacustrine sediments include low pristane/phytane ratios (< 1.5), C19 < C20 < C21 for tricyclic terpanes, C24 tetracyclic terpane/C26 tricyclic terpane < 3, and variable but often abundant b-carotanes and gammacerane (Fig. 3, Table 3). The Carboniferous–Lower Permian marine and regressive marine/non-marine strata contain several important, but not yet fully constrained type II petroleum source beds in the Turpan basin. Data from a limited sample collection indicate that the organic richness of these rocks ranges from 0.6 to 1.5%TOC (Su Chuanguo, unpublished data). Similar marine carbonates with good hydrocarbon source potentials have been found previously in the Kalasayi Formation from the Bacu region of the Tarim basin (Li et al., 1999). Hydrocarbons derived from these rocks can be readily differentiated from the Upper Permian lacustrine rocks by their low abundances of b-carotanes and gammacerane, and the presence of abundant C30 4-desmethylsteranes (24-n-propylcholestanes; Fig. 5). In fact, among all the potential source rocks in the Turpan basin, the desmethylsteranes were detected only from the Carboniferous–Lower Permian source rocks deposited in settings with strong marine influence. These compounds are believed to derive diagenetically from 24-n-propylcholesterols present mainly in marine algae Sarcinochrysidales (Raederstorff and Rohmer, 1984). To the best of our knowledge, desmethylsteranes have been reported previously only from marine source rocks and related oils, but not from lacustrine or fluvialswamp source rocks and related oils that are lack of marine influence (e.g. Moldowan et al., 1985). Therefore, the presence of these compounds should be considered as one of the most powerful parameters for identifying oils derived from the Carboniferous–Lower Permian marine source rocks in the Turpan basin. 4.2. Evidence for vertical migration of Carboniferous– Permian derived oil stains in the Jurassic cores Almost all the major oil and gas accumulations discovered so far in Jurassic reservoirs appear related to vertical fault systems. As reported by Huang et al. (1995), individual well production data indicate that wells close to the fault zones normally have high productivity, whereas wells away from the faults are mostly dry. The permeability enhancement near faults does not prove whether the hydrocarbon migration in the Turpan basin was vertical or lateral. as discussed below, however, the geochemical analysis of the core extracts in the major production areas provides substantial evidence for vertical hydrocarbon migration of Carboniferous– Permian derived hydrocarbons into Jurassic strata. Some of the Jurassic core samples we have analyzed have very low TOC contents but with relatively high

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these core extracts are generally correlatable with either the Carboniferous or the Upper Permian source rocks encountered in the Aican-1 well, except that the maturity levels of the core extracts in these wells are significantly higher. The core extracts that are interpreted to have

extract/TOC ratios (Table 2). Based on GC/MS data (Table 3), cores with over 1000 mg extract/gTOC generally contain clearly visible oil stains that are almost entirely allochthonous hydrocarbons derived from preJurassic strata. The terpane and sterane distributions of

Table 2 Bulk geochemical parameters of the core samples used in this study Lab No. Well

Depth

Strata Type

Cores containing no or 8877 Taican-2 8878 Taican-2 8879 Taican-2 8892 Lian-1 8862 Lingshen-1 8864 Lingshen-1 8882 Taican-2 8886 Hongtai-5 8891 Le-1 8869 Aican-1 8870 Aican-1 8871 Aican-1 8872 Aican-1 8855 Lunan-1 Lunan-1

less obvious migrated hydrocarbons 3888 J2q Shale 3997 J2q Shale 4002-4004 J2q Shale 3076-3082 J2q Shale 3941 J2x Coal 4078-4080 J2x Coaly shale 5003 J2x Coaly shale 2390.9 J2x Coal 2606-2611 J2x Shale 3165 P2td Shale 3166 P2td Shale 3296-3298 P2td Shale 3384-3385 P2td Shale 2687 C Shale 3446.5 C Bioclast. limestone

Cores containing obvious migrated hydrocarbons 8857 Sen-102 2390-2395 J2q Oilsand 8858 Shengbei-3 2292-2294 J2q Shale 8859 Shengbei-3 2394-2405 J2q Shale 8876 Taican-2 3861-3863 J2q Shale 8883 Hongtai-1 1394.7-1395 J2s Oilsand 8888 Le-1 1699-1700 J2s Shale 8860 Lingshen-1 3665-3670 J2x Coaly shale 8861 Lingshen-1 3846 J2x Coal 8863 Lingshen-1 4042-4046.5 J2x Shale 8880 Taican-2 4607.5 J2x Shale 8881 Taican-2 4768-4769 J2x Coaly shale 8884 Hongtai-5 2389.5 J2x Shale 8885 Hongtai-5 2390 J2x Shale 8887 Hongtai-5 2496 J2x Coaly shale 8889 Le-1 2264-2267 J2x Shale 8890 Ne-1 2514-2520 J2x Shale 8865 Aican-1 2165 J3hs Oilsand 8866 Aican-1 2175 J3hs Oilsand 8867 Aican-1 2182 J3hs Oilsand 8868 Aican-1 2198 T3 Silty shale 8853 Lunan-1 2077.5 P2td Carb. shale 8854 Lunan-1 2124.9 P2td Shale 8893 Ma-1 2065.3 P2td Oilsand 8894 Ma-1 2131 P2td Oilsand 8895 Ma-1 2157.8 P2td Oilsand 8896 Ma-1 2234 P2td Shale 8897 Ma-1 2397.5 P2td Shale 8873 Aican-1 3916 C Shale 8874 Aican-1 3979 C Shale 8875 Aican-1 4220 C Shale

TOC Ext/Rock Ext/TOC % (%) (mg/g) Sat

% % % SAT/ARO Aro Resin Asph

1.95 0.82 0.79 1.02 82 1.39 2.11 70 2.41 1.54 0.61 11.7 1.52 0.61 1.2

2.7 1 0.9 0.8 80.5 0.6 1.2 15.3 2.2 0.4 0.5 7.6 0.9 0.5 0.5

136.9 125.2 116 81.1 98.2 42.2 57.9 21.9 91.9 28.9 83.6 65.2 60.1 80.0 43.4

23.8 7.8 18.9 9.5 3.3 12.9 5.7 7.5 8.6 8.8 8.1 30.3 6.0 7.0 3.0

12.2 5.2 8.5 6.0 11.3 11.0 5.3 12.7 10.6 6.6 7.0 9.5 7.0 5.0 6.1

49.0 45.1 58.5 57.8 5.3 56.1 43.5 20.4 35.1 84.9 87.6 33.4 56.9 68.0 67.9

5.0 35.8 27.8 17.2 78.1 12.9 42.9 52.5 41.5 6.3 5.4 24.1 40.1 20.0 14.9

1.95 1.5 2.23 1.6 0.29 1.18 1.08 0.59 0.82 1.33 1.14 3.2 0.86 1.4 0.5

0.05 0.04 0.12 0.06 0.22 0.12 0.51 70 0.28 0.09 0.13 1.52 2.28 6.13 0.29 0.36 3.57 6.6 2.3 0.8 1 0.72 6.67 1.88 1.53 0.75 1.92 0.03 0.27 0.2

0.4 0.3 0.5 0.4 3.2 0.5 0.6 49.3 0.4 0.3 0.4 1.2 1.3 3.4 0.7 0.8 43.0 78.2 26.8 0.7 0.5 0.8 69.8 21.3 17.7 0.6 0.7 0.6 0.4 0.6

723.6 749.7 452.8 674 1460.2 414.5 112.6 70.5 158.9 356.8 321.4 78.8 58.8 55.0 224.8 212.2 1204.9 1184.6 1163.7 85.7 53.4 113.9 1045.9 1134.1 1157.4 86.2 38.1 2111.2 135.6 286.1

9.3 11.1 7.9 8.5 63.3 15.1 9.8 6.6 6.1 5.3 8.6 8.2 9.5 5.4 17.2 6.8 34.6 36.2 35.5 6.8 6.7 5.2 25.1 19.6 20.6 12.1 7.9 10.1 3.8 4.8

5.3 2.8 2.6 7.5 11.4 4.3 7.2 10.2 10.5 2.7 3.8 6.3 8.6 10.9 2.5 3.4 17.4 19.4 18.6 8.8 1.9 4.2 15.4 13.5 12.4 3.0 4.6 2.5 2.9 5.7

76.0 77.8 46.2 87.3 21.0 79.6 49.0 7.3 69.3 88.0 75.5 46.5 44.2 29.4 72.2 74.8 34.2 34.0 51.7 58.5 63.0 64.4 40.6 34.0 32.1 70.6 45.9 68.2 76.7 73.5

14.7 0 27.6 4.2 0.6 0 32.0 74.6 28.9 1.3 15.0 33.6 35.4 49.6 3.1 10.8 15.2 15.3 1.8 17.0 26.5 21.0 2.9 12.7 23.2 13.2 37.7 4.9 6.0 13.1

1.75 4 3 1.14 5.53 3.5 1.36 0.65 0.58 2.00 2.25 1.31 1.11 0.49 7.00 2.00 1.99 1.87 1.91 0.77 3.50 1.25 1.63 1.45 1.66 4.00 1.71 4.00 1.33 0.83

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Table 3 Molecular geochemical parameters of the core samples used in this studya Lab No. Pr/Ph H29/H30 TT24/T26 Gam/C31 D30/H30 T19/T21 Ts/(Ts+Tm) 20S abb D/R-29 C27/C29 C28/C29 27/29dia ST/Hop Cores containing no or less obvious migrated hydrocarbons 8877 1.25 0.62 3.53 0.46 0.15 8878 1.65 0.81 2.83 0.14 0.08 8879 1.45 0.86 – 0.31 0.08 8892 1.39 0.60 3.25 0.16 0.08 8862 4.80 0.85 11.49 0.18 0.20 8864 1.20 0.70 35.25 0.51 0.24 8882 1.28 0.56 1.66 0.40 0.17 8886 7.63 0.87 11.25 0.00 0.09 8891 2.98 0.61 2.96 0.11 0.06 8869 1.21 0.59 0.90 1.34 0.05 8870 1.36 0.37 – 0.14 0.03 8871 1.42 0.38 2.43 0.14 0.03 8872 1.56 0.43 0.89 0.31 0.05 8855 1.11 0.46 1.05 0.23 0.09 8856 1.39 0.65 1.30 0.14 0.07

0.28 0.54 8.82 0.42 4.66 3.08 0.30 6.52 1.32 0.19 0.34 0.00 0.26 0.39 0.25

0.47 0.08 0.19 0.06 0.21 0.39 0.30 0.06 0.10 0.26 0.29 0.30 0.13 0.25 0.16

0.35 0.42 0.44 0.12 0.47 0.45 0.43 0.26 0.14 0.40 0.12 0.11 0.16 0.24 0.33

0.31 0.31 0.33 0.24 0.30 0.42 0.49 0.20 0.26 0.40 0.26 0.23 0.28 0.40 0.43

0.20 0.35 0.31 0.26 0.24 0.72 0.50 0.20 0.17 0.15 0.11 0.08 0.25 0.23 0.28

0.69 0.20 0.22 0.78 0.10 0.55 0.69 0.11 0.08 0.37 0.66 0.59 0.25 0.50 0.63

0.47 0.26 0.34 0.39 0.22 0.51 0.49 0.17 0.17 0.61 0.67 0.54 0.28 0.32 0.41

0.78 0.20 0.27 0.86 0.21 0.31 0.66 0.16 0.19 0.37 0.28 0.69 0.27 0.72 0.99

0.36 0.25 0.06 0.40 0.41 0.09 0.30 0.49 0.67 0.66 0.43 0.56 0.57 0.48 0.38

Cores containing obvious migrated hydrocarbons 8857 0.94 0.52 0.95 0.18 0.11 8858 2.18 0.49 1.02 0.19 0.10 8859 2.21 0.69 1.10 0.43 0.08 8876 0.70 0.52 0.92 0.81 0.08 8883 4.12 0.70 – 0.00 0.10 8888 1.40 0.54 0.81 0.31 0.10 8860 0.63 0.58 0.52 0.51 0.05 8861 0.82 0.85 2.22 0.13 0.06 8863 1.20 0.78 5.22 0.10 0.06 8880 1.06 0.68 0.82 0.41 0.08 8881 0.96 0.79 1.06 0.25 0.11 8884 2.10 0.73 1.83 0.12 0.05 8885 2.28 0.69 1.99 0.10 0.04 8887 3.50 1.03 3.25 0.06 0.05 8889 2.32 0.68 1.23 0.32 0.10 8890 1.15 0.61 0.91 1.23 0.06 8865 – 0.69 0.63 1.42 0.14 8866 – 0.71 0.76 1.49 0.06 8867 – 0.70 0.75 1.45 0.08 8868 1.25 0.58 0.72 1.41 0.06 8853 0.69 0.11 0.57 1.31 0.02 8854 1.07 0.52 0.86 0.33 0.11 8893 – – – – – 8894 1.13 – – – – 8895 0.82 – – – – 8896 1.28 0.28 0.68 0.63 0.07 8897 1.69 0.53 0.69 0.44 0.10 8873 1.02 0.51 0.75 0.42 0.08 8874 1.44 0.57 1.01 0.28 0.08 8875 1.48 0.46 1.04 0.19 0.08

0.11 0.37 0.46 0.19 – 0.26 0.12 0.70 0.54 0.25 0.29 0.45 0.35 0.47 0.45 0.27 0.24 0.11 0.17 0.13 0.25 0.25 – – – 0.30 0.22 0.23 0.21 0.16

0.49 0.51 0.30 0.32 0.15 0.37 0.16 0.06 0.15 0.43 0.25 0.05 0.05 0.02 0.24 0.24 0.29 0.20 0.23 0.22 0.21 0.40 – – – 0.33

0.39 0.38 0.36 0.43 0.44 0.39 0.44 0.42 0.43 0.37 0.44 0.32 0.32 0.31 0.43 0.35 0.46 0.38 0.40 0.37 0.04 0.21 0.63 0.63 0.62 0.13 0.24 0.38 0.36 0.36

0.48 0.50 0.43 0.49 0.47 0.45 0.46 0.32 0.38 0.44 0.47 0.40 0.34 0.23 0.47 0.38 0.39 0.37 0.38 0.38 0.23 0.37 0.43 0.44 0.45 0.33 0.38 0.46 0.43 0.44

0.29 0.27 0.30 0.19 0.38 0.24 0.22 0.16 0.22 0.38 0.32 0.25 0.21 0.18 0.34 0.24 0.14 0.14 0.16 0.15 0.02 0.20 0.95 1.12 0.97 0.12 0.26 0.22 0.18 0.27

0.63 0.62 0.51 0.58 0.18 0.53 0.53 0.17 0.22 0.99 0.73 0.23 0.24 0.13 0.40 0.66 0.51 0.39 0.43 0.34 0.26 0.49 1.73 2.25 1.97 0.50 0.35 0.60 0.52 0.54

0.51 0.48 0.52 0.61 0.23 0.49 0.55 0.28 0.31 0.58 0.52 0.29 0.30 0.19 0.39 0.49 0.85 0.69 0.75 0.59 0.25 0.30 0.74 0.81 0.73 0.31 0.32 0.50 0.42 0.45

0.90 0.88 0.71 0.45 0.18 0.64 0.25 0.17 0.37 1.06 0.54 0.32 0.28 0.26 0.37 0.77 0.55 0.24 0.30 0.29 0.68 0.86 0.42 0.36 0.33 0.57 0.47 0.56 0.58 0.71

0.52 0.44 0.46 0.60 0.45 0.50 0.74 0.48 0.18 0.39 0.33 0.24 0.23 0.33 0.49 0.40 1.54 1.03 1.08 0.74 0.80 0.67 – – – 0.80 0.76 0.50 0.50 0.44

0.39 0.21 0.39

a Pr/Ph: pristane/phytane ratio; H29/H30: norhopane/hopane ratio; TT24/T26: C24-tetracyclic/C26-tricyclic terpane ratio; Gam/C31: gammacerane/22S-homohopane ratio; D30/H30: diahopane/hopane ratio; T19/T21: C19/C21-tricyclic terpane ratio; Ts/(Ts+Tm): 18a(H)-/ (18a(H)+17a(H)-trisnorhopane ratio; 20S and bb: 20S/(20S+20R)- aaa and abb/(abb+aaa) ratios for C29 steranes; D/R-29: C29 diasterane/ regular sterane ratios; C27, C28 and C29: percentage within C27+C28+C29 regular steranes; 27/29-dia: C27/C29 diasterane ratio; ST/Hop: C29 aaa-steranes/ C30-ab-hopane ratio.

M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

originated from an Upper Permian Taodonggou group source generally show abundant b-carotane and gammacerane, C19 < C20 < C21 for tricyclic terpanes, and C24 tetracyclic terpane/C26 tricyclic terpane ratios around 1.0, whereas those with a dominant Carboniferous– Lower Permian marine source contain abundant C30 4-desmethylsteranes by GC/MS/MS analyses (Fig. 5). Results obtained from intra-laboratory checks starting with original core samples, suggest that the characteristic pre-Jurassic biomarker signatures in the Jurassic cores are real, thus eliminating the possibility of contamination during sample work-up. It is our experience that Jurassic cores with TOC < 1.0% and over 100 mg extract/gTOC in the Taibei depression generally contain allochthonous hydrocarbons. Although our sampling strategies targeted mainly potential petroleum source rocks, fractures are common to extensive in many hand specimens of the mudstones and siltstone samples. Samples that contain allochthonous hydrocarbons include those from Wells Fang-1 (J2x, 2053–2058 m) and

Fig. 5. GC/MS/MS evidence for possible marine oil stains in the Jurassic samples. Peaks 1–4 are the four regular 24-ethylcholestane isomers; peaks 5–8 are the four isomers of 24-npropylcholestanes.

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Hongtai-5 (J2x, 2389–2390 m, 2496 m) in the Xiaocaohu sag; Le-1 (J2s, 1699–1700 m; J2x, 2264–2267 m, 2514– 2520 m) and Le-2 (J2s, 2010–2020 m, 2265–2275 m) in the Qiudong sag; Lian-1 (J2x, 3669–3672 m) and Shengbei-3 (J2q, 2292–2294 m) in the central part of the Shengbei Sag; and Shen-1 (J2x, 2709–2710 m) and Shen-102 (J2q, 2390–2395 m) in the western part of the Shengbei sag. While most of the allochthonous hydrocarbons have been identified for the first time in this study, pre-Jurassic sourced hydrocarbons were also suspected previously in several locations by Tuha in-house studies (Su Chuanguo, unpublished results). As discussed later, examination of cores microscopically indicates that the allochthonous hydrocarbons are distributed mainly along the micro-fractures, not in the rock matrix of the low permeability shales and siltstones. Pre-Jurassic sourced hydrocarbons appear to be common in the Shengbei and Qiudong-Xiaocaohu sags, sometimes in fractured Jurassic coals. For example, the coal sample from the Lingshen-1 well (J2x, 3846 m) is dominated by vitrinite, specifically collotelinite that hosts persistent orange fluorescing resinite to exsudatinite, together with minor amounts of cutinite and sporinite. Throughout the sample, the collotelinite vitrinite has been highly fractured and the fractures or cleats in-filled with calcite. In many places the fracture-fill calcites host blue fluorescing hydrocarbon fluid and oil inclusions. Blue oil globules commonly exude directly from the calcites in microfractures as well as from fractured vitrinite. The presence of the hydrocarbon fluid and oil inclusions in coals and high API gravity for the produced oils have been previously taken as evidence for early hydrocarbon generation from the hydrogen-rich macerals in the coal (e.g. Cheng, 1994). While this is case in the fluorescing rock matrix, the saturate gas chromatograms of the extracts obtained from hand-picked fracturefill calcites after HCl treatment indicate in-migrated hydrocarbons. The extracts show a pristane/phytane ratio of 0.63, with relatively abundant b-carotane. Their terpane and sterane distributions also show characteristics similar to those observed for the Upper Permian source rocks in the Aican-1 well, suggesting a dominant Upper Permian source. The relative enrichment of bcarotane and gammacerane in these Upper Permian derived hydrocarbons may have been partially caused by biodegradation, as in the case of Karamay field in the Jungaar basin (Carroll et al., 1992). The hydrogen index of the J2x coal of the Lingshen-1 well (3846 m) was 213 mgHC/gTOC, and after solvent extraction it decreased to 137 mgHC/gTOC (Table 1). Similar results were also obtained from a number of other J2x coals. Some of the coals have an initial hydrogen index of up to 450 mgHC/gTOC, but generally show a 30–65% decrease to less than 200 mgHC/gTOC after solvent extraction. The hydrogen index values measured after solvent extraction are typical of humic coals which are

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enriched in vitrinite (Boreham and Powell, 1993). Because these coals often occur near the top or bottom of the oil-bearing sandstones and were also highly fractured during the geological history, it is unlikely that the hydrogen indices obtained by Rock-Eval pyrolysis of preextracted coals would represent their true hydrocarbongenerating potential. We hypothesize that hydrocarbon fluid and oil inclusions in the fracture-fill calcite which are incapable of thermal volatilization at low temperature (
300  C) contribute partially to the yields of pyrolyzable hydrocarbons at temperature ramped up to 600  C, resulting in deceptively high hydrogen indices. 4.3. Oil geochemistry and possible origins Tables 4–6 list the bulk chemical compositions, gasoline range and C15+ saturate compositions of the crude oils produced from the Turpan basin. The only oil discovery in the Tuokexun sag thus far was made in the Triassic of the Tuocan-1 well. The Tuocan-1 oil is a light oil (
40oAPI), with a relatively low heptane value (Table 5). The carbon isotopic composition of this oil (13C, 31.80%) is within the same range of that observed for the Upper Permian source rock extracts (Liang et al., unpublished data). Its biomarker distribution has many characteristics in common with oils derived from the Upper Permian sources in the Jungaar basin, i.e. the presence of b-carotane, low pristane/phytane (1.22) and C24 tetracyclic/C26 tricyclic terpane ratios (0.65), high C28/C29 regular sterane ratio (0.62), and C19 < C20 < C21 for tricyclic terpanes. The source rocks for this oil most likely occur in the Upper Permian section of the Tuokexun sag. Although a contribution from a Triassic source was also proposed previously (Cheng, 1994), this is less likely due to the relatively low maturity level of this strata. Crude oils produced from the Lukexun Arch between the Taibei and Tainan depressions are dominated by low API gravity oils (15–25 ), with varying degrees of biodegradation. The gasoline range parameters of these oils vary significantly, from oils containing no gasolinerange and C15+ n-alkanes to oils showing no signs of biodegradation (Table 5), consistent with a later phase of light oil injection into parts of the pre-existing biodegraded oil fields. The Tuyuke field oils are generally enriched in C28 regular steranes, with relatively low ratios of saturate/aromatic hydrocarbons (< 2), pristane/phytane ( < 2) and C24 tetracyclic/C26 tricyclic terpane. These distributions generally correlate well with the Upper Permian source rocks encountered in Well Aican-1 (Greene et al., 1997). b-Carotane and gammacerane are also relatively enriched in these oils, likely as a result of biodegradation. Because the maturity levels of all potential source rocks in the Tainan depression are currently too low for liquid hydrocarbon generation, the Tuyuke oils were most likely derived laterally from

the Upper Permian Taodonggou group source rocks within the Taibei depression. Acyclic isoprenoid alkanes and regular steranes in heavy oils produced from the Machang structure east of the Tuyuke field were affected more severely by biodegradation, but their similar tricyclic and tetracyclic terpane distributions appear to indicate a common origin. Most commercial oil production in the Turpan basin comes from the Taibei depression. These are generally light oils (37–45oAPI), with low viscosity, sulfur and gas to oil ratios (GOR 100-500 scf/bbl). These oils often have high saturate/aromatic hydrocarbon ratios (4–10, Table 5), and those with extremely high ratios (>30) are actually condensates. Some oils in the Baka Field have been affected by biodegradation (e.g. n-alkanes are completely absent in oils produced from Well Ke-7), but their gravities in the range of 34–40 API indicate originally lighter oils. The carbon isotopic compositions of the bulk oils of the Taibei oils generally range from 27 to 25% 13C. The 13C values are in the same range as for the Jurassic coal extracts (27 to 21%, mostly 25 to 23%) observed in the Taibei depression. These have been taken as one of the key evidences for the origin of these oils from coal (e.g. Huang et al., 1991). Although the bulk properties of the oils in the Taibei Depression are very similar, biomarker distributions in these oils vary significantly (Figs. 6 and 7; Table 6). On one hand, oils and condensates from a number of wells (e.g. Wenxi-3, Wen-1, Wen-8, Pubei-1, Pubei-101, Guo-1, Ge-1) show biomarker distributions typically found in humic coals, including the relative enrichment of C24 tetracyclic terpane and C29 regular steranes (C29 >>C27
C28), high pristane/phytane ratios (>3.50) and the dominance of C19 and C20 over other tricyclic terpanes. On the other hand, oils from the Shengjinkou, Shanle, Shenqian, Lianmuqin, Pubei-102, Shengnan and Taican-2 J2q pools and condensates from the Hongtai-2 pool show relatively low abundances of C24 tetracyclic terpane, low pristane/phytane ratios ( < 3.50), with no obvious carbon number predominance for the tricyclic terpanes and regular steranes. While it is easy to identify these ‘‘end member’’ oils, it is important to note that a compositional continuum exists between the end members. Thus, it is virtually impossible to classify most oils in the Taibei depression into distinct family groupings if multiple compositional criteria are used. Nevertheless, largely based on biomarker distributions and more recently on 13C values of n-alkanes, crude oils in the Taibei depression have been classified and correlated to two different Jurassic petroleum source beds (Huang et al., 1991; Cheng, 1994). Oils with apparent ‘‘coaly’’ biomarkers were thought to have been derived from type III kerogen of typical swampy facies in the Badaowan Fm. (J1b), whereas the other end members of oils (e.g. from the Shengjinkou field) were attributed to

M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

freshwater-brackish lacustrine source beds in the Middle Jurassic Qiketai Fm. (J2q). In the light of the detection of pre-Jurassic derived hydrocarbons in the fractured Jurassic rocks, it is difficult to explain why almost all of the oils discovered so far in the Taibei depression appear to show a Jurassic source only. To reconcile this paradoxical relationship, we propose below an alternative to the autochthonous hypothesis. 4.4. Possible mixing of Jurassic and pre-Jurassic derived oils It is possible that source rocks in the pre-Jurassic (particularly the Upper Permian) source rocks in the deepest parts of the Taibei depression were also generative during the Mesozoic and formed oil accumulations that were subsequently breached or even mixed with Jurassic oils during Cenozoic deformation. The possible mixing of Jurassic and pre-Jurassic derived oils in the Taibei depression appears to be supported by the wide variability in the biomarker compositions of the produced oils and a good match of a number of parameters among the oils and Carboniferous–Permian source rock extracts. Figs. 7 and 8 demonstrate that although the Taibei oils correlate better with Jurassic source rocks than with Carboniferous-Permian sources using C19/C21-tricyclic terpane ratio, the same is not true using the relative distribution of C27–C28–C29 regular steranes. As shown in Fig. 9, all

1139

of the oils in the Taibei depression fall outside the expected range for Jurassic coals and coaly shales which contain no detectable allochthonous hydrocarbons. Relatively high sterane/hopane ratios as observed in the Carboniferous–Permian source rock extracts would not be expected if the oils were indeed derived from the fluvial-swampy source facies (see the review by Clayton, 1993). Molecular evidence supporting mixing can be also found by comparing the internal consistency or discrepancy in different sterane maturity parameters of the Jurassic core extracts that, based on geological-geochemical observations, should contain pre-Jurassic hydrocarbons. As shown in Fig. 5, the presence of C30desmethylsteranes in the Jurassic non-marine strata (J2x and J2q) indicates pre-Jurassic hydrocarbons. The Shengbei-3 core (J2q, 2292–2294m), for example, is low in TOC (0.04%) but high in extract/TOC ratios (
745 mg/g), indicating mostly allochthonous hydrocarbons. The C29 regular steranes and C30 desmethylsteranes in this sample show similar 20S/(20S+20R) and abb/ (aaa+abb) ratios (Fig. 5b), which indicates that both compound classes were derived from the same source rocks and also have experienced similar geothermal histories. In contrast, the Hongtai-5 core (J2x, 2496m) has a TOC content of 6.13% and around 55.0 mg extract/gTOC, indicative of substantial amount of indigenous organic matter in the sample. In this case, the presence of more mature, allochthonous marine-sourced hydrocarbons is

Fig. 6. M/z 191 and 217 mass fragmentograms for some of the oil samples in the Turpan basin. See Fig. 3 legend for abbreviations of peak identifications.

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M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

Fig. 7. Plots of C30-diahopane/hopane versus T19/T21-tricyclic terpane ratios for produced oils and core extracts in the Turpan basin. Data for Carboniferous–Permian outcrop rock extracts and Triassic reservoired oil from Shanke-1 well [Sk-1(T)] was taken from Li et al. (2001).

clearly demonstrated by the higher 20S/(20S+20R) and abb/(aaa+abb) ratios observed for the C30 desmethylsteranes than those for the C29 regular steranes (Fig. 5c). An attempt has been made to estimate the relative contributions of the pre-Jurassic versus Jurassic derived hydrocarbons for most of the known oil pools by comparing the absolute concentrations of biomarker compounds in the oils with those in the source rock extracts. Given the wide variability in the biomarker concentration data that are highly dependent on the source, thermal maturity level and expulsion efficiency in both source rocks and oils, mixing experiments were done on only a few end member samples. The end members listed in Table 7 were selected on the basis of quantitative biomarker data obtained from core extracts and oils. The pre-Jurassic sourced oils are represented by an oil stain sample encountered in Shengbei-3 well, whilst the Jurassic source rocks are represented by a coal from Lingshen-1well (with 0.76% Ro) and a lacustrine shale from Taican-2 well (with 0.83% Ro).

As shown in Table 7, the absolute concentrations of terpanes and steranes in pre-Jurassic sourced hydrocarbons are several orders of magnitude lower than those in the less mature Jurassic coals, coaly shales and lacustrine shales. Calculations using a simple binary mixing model (Fig. 10) suggest that even small quantities of the Jurassic extracts (coals, coaly shales or lacustrine shales) mixed with over ten-fold of the preJurassic oils gives a GC/MS fingerprint with distinct biomarker distributions similar to those of the Jurassic coals or shale extracts. The sterane and terpane ratios actually observed for the Taibei Depression oils extend beyond the ‘‘100% pre-Jurassic source’’ ranges predicted from the mixing models (Fig. 10). This indicates that the end member oils selected to represent the preJurassic sources themselves may have already been contaminated by indigenous hydrocarbons. Alternatively, there may have been contributions from even higher maturity pre-Jurassic sources than the end member samples arbitrarily selected in the model calculations.

M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

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Fig. 8. Plots of C27/C29 versus C28/C29-sterane ratios for produced oils and core extracts in the Turpan basin.

Geological considerations suggest that both alternatives are possible. The distribution of acyclic isoprenoid hydrocarbons, particularly the relatively high pristane/ phytane ratios can be explained using similar conceptual mixing models, but this has not been done experimentally in this study. Results of the model calculations (Fig. 10) raise concerns about the oil-source correlations using ‘‘biomarker fingerprint’’ techniques. The current work suggests that bulk geochemical parameters should always be considered when the interpretation of data, obtained from more sophisticated techniques but on quantitatively less abundant compounds, is attempted. For example, the presence of the C30 3- and 2-, but not 4-, methylsteranes (including dinosteranes) in a number of oils (e.g. J2x in Taican-2, Wenxi-3, WX-5, Sha-1, Guo-1, Ke-7, Pubei-101, etc.) can be opportunistically (or may well be correctly) interpreted as due to the lack of contribution from Jurassic lacustrine source rocks in the Qiketai Fm. However, the presence of 4-methylsteranes (including dinosteranes) in various abundances detected in other oils (e.g. J2q, Taican-2; K1tg, Lian-2; J2x, Pubei-102,

Sennan-1, Hongtai-2) certainly cannot be taken as evidence for a dominant Jurassic lacustrine hydrocarbon source for the oils. To demonstrate this point, both oils and potential source rocks of the Qiketai Fm. (J2q) sampled from the Taican-2 well have been compared. The m/z 191 and 217 mass fragmentograms and the C30 methylsterane distributions of the J2q oils (3610–3630 m) match almost perfectly with those of the J2q lacustrine shales (3888 m) (e.g. Fig. 6c versus Fig. 3a). As discussed earlier, this shale is currently immature and thus cannot be the source for an oil with a gas to oil ratio around 2350 scf/bbl. Consequently, the perfect match in biomarker distribution is considered as the best indication of migration contamination rather than a proven oil-source relationship. Similarly, the presence of C30 4-desmethylsteranes is considered as an important parameter for marine sourced oils (Moldowan et al., 1985, 1990; Mello et al., 1988). These compounds occur widely in Jurassic cores containing pre-Jurassic sourced hydrocarbons, but they were either not detected or present in extremely low concentrations in the oils produced from the Taibei

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M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

Fig. 9. Plots of sterane/hopane versus Ts/(Ts+Tm) ratios for produced oils and core extracts in the Turpan basin. *Oilsands in the Lukexun arch containing Carboniferous–Permian sourced hydrocarbons; **Jurassic oilstains in the Taibei Depression containing Carboniferous–Permian sourced hydrocarbons; *** Lower–Middle Jurassic source rocks containing no microscopically visible allochthonous hydrocarbons.

Depression. In the light of the conflicting reports on the absence (Bailey et al., 1990) or presence (Peters et al., 1989) of these compounds in the marine-sourced Beatrice oils from the North Sea, we are cautious that this data alone necessarily precludes the contribution of a marine source to these oils. The concentrations of the regular steranes in the mature Carboniferous oils are almost two order of magnitude lower than those in the less mature Jurassic coal and shales extracts (Table 7), and C30 desmethylsteranes are normally several orders of magnitude lower than the regular steranes. Thus, routine GC/MS/MS analyses that were geared towards the most abundant steranes and terpanes may not be sensitive enough to detect these trace molecules. As the D values of the n-alkanes in the Taibei depression oils (210 to 160%) are consistently lighter than those of marine oils (Li et al., 2001), a more plausible explanation is that significant marine source contributions may be possible only in limited locations of the Taibei depression. Although the oils can be classified using the hydrogen isotopic data into a freshwater and a more brackish water lacustrine facies, most of these oils are virtually indistinguishable from the Upper Permian derived oils in the Tuokexun sag and the Shanke-1 well. Thus, the contribution of Upper Permian lacustrine oils

to the Jurassic reservoirs in the Taibei depression may be far more significant than previously recognized. Other key evidence previously cited to dismiss a preJurassic source for the Taibei oils was the presence of dominantly Lower–Middle Jurassic spores and pollens in the filtrates of these oils (Hou, 1995). Considering the physical sizes of spores and pollens, it would be difficult to imagine that they could be expelled out of a shaly petroleum source rock as readily as hydrocarbons. As we argued previously for the Tarim basin oils (Li et al., 1999), these spores and pollens were most likely introduced into the oils during secondary migration in the more porous and fractured carrier / reservoir system and thus should not be used as a decisive tool for oilsource correlation. 4.5. Resinite and suberinite in Turpan coals as major sources for early oil generation? Early oil generation from immature humic coals and coaly shales has been proposed earlier, with resinite and suberinite being suggested as possible sources (Cheng, 1994; Huang et al., 1995; Cheng and Zhao, 1998). Several lines of evidence exist against resinite as a major source for the oils in the Taibei depression.

M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

Fig. 10. Comparison of biomarker ratios observed from the oils in the Taibei Depression with those from the model predictions.

Firstly, resinite is extremely rare in immature coals of this basin, often less than 1% by volume in coals with <0.35% Ro. Secondly, resin derived biomarkers (bi-, tri- and tetracyclic diterpanes) are present only as minor components in the oils and condensates. Finally, the hydrocarbon fluids are largely paraffinic rather than naphthenic. Cheng et al. (1998) propose that the oils in the Taibei depression were most likely derived exclusively from the hydrogen-rich macerals in coal. The primary evidence was that the Jurassic coals and oils in the Taibei Depression appeared to contain phyllocladane in relatively low abundance, whereas this compound is relatively enriched in the pre-Jurassic source rocks and related oils. Results obtained from a detailed study on a much larger sample set suggest an alternative interpretation. The extracts of both Jurassic coals and the Upper Permian source rocks contain significant amounts of retene, but this compound is also present in various concentrations in all of the oils and condensates examined by these authors. Since retene is an aromatization product of conifer-derived diterpenoids, abietic acid (Laflamme and Hites, 1978) and phyllocladane (Alexander et al., 1987), the relative abundance of phyllocladane in the oils would be highly dependent upon thermal maturity of the samples, in addition to source and diagenetic

1143

controls. Because the pre-Jurassic source rocks and oils used by previous researchers are significantly less mature than the Jurassic samples, the general trend reported earlier was not confirmed when a larger sample set covering wider maturity range was included in the study. It appears likely from the preceding discussion that liquid hydrocarbons from pre-Jurassic (e.g. Upper Permian) source rocks could have made significant contributions to the Jurassic reservoirs. This suggestion does not imply that suberinite and subereous organic matter of amorphous nature in the Jurassic coals could not have been effective generators of liquid hydrocarbons as proposed previously (Cheng, 1994; Huang et al., 1995; Cheng and Zhao, 1998). These macerals were thought to account for up to 6% by volume of the immature coals from the Baodaowan Fm., but were nearly absent in samples with >0.7% Ro (Cheng, 1994). However, more recent investigations put the subereous macerals in the immature Turpan coals generally below 1% (Chen Jianping, personal communications). If the original report was correct, these could add substantial liquid hydrocarbons to the bitumen of coaly material at low level of thermal stress to overcome the threshold for liquid hydrocarbon expulsion. The problem with the model of early oil generation from dominantly subereous material is that the oils discovered in the Taibei depression do not show nalkane distributions characteristic of low maturity (e.g. clear odd-over-even carbon preference for n-alkanes). The maturity levels determined for the oils (mostly >0.8% Ro) are generally much higher than that expected from suberinite (Table 4). The 20S/(20S+20R) and abb/(aaa+abb) ratios of the steranes in the oils (Table 5) are also consistent with oils expelled within conventional oil window. The effective lag between generation and expulsion in coals that produce more polar bitumen may have been responsible for the reservoired oils with more mature signatures because of the delayed expulsion. Alternatively, mixing of the early hydrocarbons generated from suberinite with more mature oils derived from other liptinites in the Jurassic coals and pre-Jurassic source rocks may be an even more plausible explanation. 4.6. Gas geochemistry and possible origins The Turpan basin produces dominantly oil, with only very minor quantities of gas. The hydrocarbon gases are mainly associated gases from under-saturated oil pools with gas/oil ratios generally below 250 scf/bbl. Small quantities of gas are also produced from the gas cap of six gas-condensate pools, including the Qiudong, Wenjisang, Wenxi, Mideng and Ling-4 pools surrounding the Qiudong sag and the Hongtai-2 pool in the Xiaocaohu sag. The associated hydrocarbon gases produced from the oil pools could not be differentiated either chemically or isotopically from those from the gas-condensate pools (Table 8). Although we have not taken

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M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

Table 4 Bulk geochemical parameters for the Turpan Basin oils and condensate samplesa Lab No.

Well

Depth

Strata

Tuokexun depression oil 2934 Tuocan-1

2428–2438

T2k

Lukexun Arch oils 2672 Yudong-1 2677 Yudong-1 2673 Yudong-2 2681 Yudong-2 2685 Yu-1

2700–2721 2732–2752 2791–2816 2826–2846 3358–3378

T2k T2k J1b T2k T2k

Taibei depression oils 2686 Ge-2 2696 Guo-1 2692 Hongtai-2 2684 Ke-7 2671 Lian-1 2675 Lian-2 2667 Le-1 2687 Le-3 2670 Le-4 2688 Pubei-1 2695 Pubei-101 2697 Pubei-102 2682 Shan-6-17 2680 Sa-1 2683 Sen-1 2693 Sen-1 2666 Sen-102 2694 Sen-102 2679 Shengnan-1 2676 Shengnan-3 2678 Taican-2 2689 Taican-2 2669 Taican-2 2691 Wen-1 2674 Wen-8 2668 Wenxi-3 2690 Wenxi-5

911–917 3576–3585 2228 1841.5–1848.3 3372–3379 1525–1540 2677–2687 3537–3540 2692–2737 3467.5–3473.5 3833.9 3345.6–3351.2 2952.5–3062.8 3087–3090 2514–2525 2489–2493 2050–2062 2366.5–2770.9 2320–2330.4 2458–2464 3610–3630 4202.2–4247.0 4746–4774 2764–2819 2350 2314–2323 2882.2–2888

J2s J2s J2s J2x J2x K1tg J2x J1b J2x J2s J2x J2q J2s J2x J2s J2s K1tg J2q J2s J2s J2q J2s J2x J2s J2s J2s J2x

GOR

0 0 0 0 0 0 301–651 22674 99 0 35.7 131.6 1103 240 2.2 233

125 288 246 147 251 0.3 2353 4800 1279 5981 326 134 4578

%Sat

%Aro

%Resin

SAT/ARO

60.0

16.9

33.1

3.55

46.4 47.9 45.7 45.5 49.2

24.1 28.0 29.2 27.3 25.4

29.5 24.1 25.1 27.3 25.5

1.92 1.71 1.57 1.67 1.94

87.4 80.5 98.0 79.8 82.5 81.8 86.6 82.9 87.9 74.1 77.3 78.2 76.3 83.4 82.5 81.2 76.5 80.9 76.4 77.5 73.3 85.6 82.3 98.0 77.4 71.9 96.8

9.7 15.7 1.6 16.6 14.1 14.4 9.9 13.0 9.4 21.1 16.8 18.2 17.8 12.2 13.4 15.4 16.5 16.0 17.8 18.0 17.9 11.9 14.7 1.6 17.4 17.6 2.7

2.9 3.7 0.4 3.6 3.4 3.8 3.5 4.0 2.8 4.8 5.9 3.6 5.9 4.4 4.0 3.4 7.0 3.2 5.8 4.5 8.7 2.5 3.0 0.4 5.3 10.6 0.6

8.97 5.12 61.32 4.79 5.87 5.69 8.76 6.35 9.39 3.52 4.59 4.30 4.28 6.83 6.14 5.27 4.64 5.07 4.30 4.32 4.09 7.18 5.58 61.10 4.46 4.09 36.47

a GOR: gas/oil ratio (scf/bbl); %Sat, %Aro and %Resin: relative percentages for saturate, aromatic hydrocarbons and NSO fractions; SAT/ARO: saturate/aromatic hydrocarboin ratio.

additional gas samples for further geochemical analyses in the present study, examination of the published gas data requires a critical evaluation of the existing hypotheses on the origin of these hydrocarbon gases. Three general groups of gases have been recognized from the Turpan basin (Fig. 11; Cheng, 1994; Huang et al., 1995). The first group consists only of wet hydrocarbon gases associated with the oil, produced from the Triassic reservoir of the Tuocan-1 well in the Tuokexun sag. These gases have a C1/C15 ratio around 0.63 and d13C1 value around 40.00% (Cheng, 1994). As they were under-saturated gases separated from the oils that were derived from a lacustrine source, there is no reason to suggest a different source for these gases.

The second group accounts for more than 95% of the hydrocarbon gases discovered in the basin, including gases from Qiudong, Mideng, Wenjisang and Wenxi gascondensate fields, and Shanshan, Shanne and Qiuling oilfields. These are generally wet gases, with C1/C1-5 values ranging from 0.77 to 0.83, d13C1 values from44.8 to 38.6% (mostly between 42.0 to 41.0%) and Dmethane values from 280 to 220%. These gases were previously considered as transitional biogenicthermogenic gases generated from coals at low thermal maturity level (
0.3–0.6% Ro) (Cheng, 1994; Huang et al., 1995). We do not concur with this interpretation, as the plot of 13C1 versus Dmethane (Schoell, 1980) or C1/ C2+3 (Whiticar et al., 1985) of these gases (Table 8)

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M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151 Table 5 Gasoline range hydrocarbon parameters of the Turpan basin oils and condensatesa Lab No.

PI-1

PI-2

Q

R

S

T

U

V

W

B

24/23

T C

Rm

Tuokexun depression oil 2934 17.35 0.93

2.10

0.34

9.18

65.93

64.36

0.77

0.27

0.05

0.29

122

0.84

Lukexun Arch oils 2672 n.d. 2677 28.91 2673 20.15 2681 23.00 2685 15.04

2.70 1.33 1.54 1.08

2.43 1.50 1.52 0.98

0.66 0.67 0.56 0.23

4.18

1.28

6.02

– 2.96

5.71 9.89

– 29.03

1.29 1.56 1.95 1.32

0.46 0.67 0.67 0.36

1.19 0 0.31 0.44

0.27 0.32 0.25 0.13

120 123 119 110

0.82 0.85 0.81 0.72

Taibei depression oils 2686 18.41 2696 22.98 2692 29.99 2684 2.75 2671 28.82 2675 21.19 2667 25.90 2687 23.30 2670 22.14 2688 23.33 2695 31.29 2697 21.84 2682 24.62 2680 17.84 2683 20.73 2693 20.59 2666 18.04 2694 21.93 2679 18.40 2676 19.85 2678 19.76 2689 19.67 2669 20.93 2691 26.14 2674 22.63 2668 21.41 2690 26.74

1.67 1.98 2.11 0.75 2.07 1.56 1.94 1.69 1.53 2.06 2.23 1.57 1.77 1.80 1.95 1.66 1.89 1.94 1.36 1.64 1.06 1.94 1.55 2.15 1.50 1.49 2.14

2.11 3.15 2.31 0.36 3.43 3.07 2.75 2.62 2.40 3.16 3.75 2.76 2.71 2.61 3.18 3.11 2.52 3.18 22.30 2.77 1.65 2.69 2.41 3.21 2.57 2.83 3.40

0.34 0.49 0.59 0.04 0.64 0.45 0.59 0.48 0.55 0.47 0.87 0.43 0.53 0.41 0.41 0.42 0.34 0.44 0.34 0.41 0.44 0.35 0.39 0.69 0.51 0.49 0.72

– 2.01 3.46 0.77 3.30 8.79 3.21 1.51 7.55 0.94 16.83 1.28 2.42 71.24 1.83 1.36 1.44 1.69 1.26 2.49 0.53 1.14 0.51 4.92 3.53 5.07 15.80

28.83 5.38 9.11 20.89 9.41 12.33 2.44 3.59 7.38 3.01 47.52 4.55 5.94 32.64 5.92 5.08 48.85 4.91 2.48 4.93 4.76 4.27 1.81 8.23 5.81 5.63 13.44

– 6.26 30.14 18.83 12.29 27.35 7.50 6.03 13.05 3.63 25.12 7.23 7.87 87.00 7.30 5.71 6.72 6.97 7.28 8.73 2.49 6.71 3.67 9.49 9.82 11.57 29.77

0.00 0.60 – 1.71 0.72 0.79 0.82 0.63 1.06 0.69 0.96 0.57 0.92 1.53 0.58 0.61 0.54 0.74 1.16 0.79 0.70 0.61 0.57 0.71 1.23 0.70 0.71

0.31 0.25 0.18 0.61 0.21 0.28 0.28 0.25 0.34 0.24 0.29 0.22 0.30 0.48 0.26 0.25 0.29 0.25 0.03 0.30 0.28 0.24 0.22 0.29 0.33 0.36 0.29

0.10 0.38 0.18 1.12 0.16 0.18 0.70 0.58 0.25 0.70 0.02 0.52 0.32 0.08 0.41 0.47 0.06 0.47 1.18 0.49 0.48 0.66 1.41 0.18 0.34 0.36 0.10

0.32 0.32 0.18 0.52 0.29 0.33 0.37 0.33 0.45 0.31 0.38 0.29 0.27 0.41 0.36 0.35 0.32 0.34 0.19 0.36 0.27 0.33 0.32 0.41 0.32 0.34 0.38

123 123 114 130 122 123 125 123 128 123 125 121 120 127 125 124 123 124 115 125 121 123 123 127 123 124 125

0.85 0.85 0.76 0.93 0.84 0.85 0.87 0.85 0.90 0.85 0.87 0.83 0.82 0.89 0.87 0.86 0.85 0.86 0.77 0.87 0.83 0.85 0.85 0.89 0.85 0.86 0.87

a PI-1: paraffin index -1 (isoheptane value); PI-2: paraffin index-2 (heptane value, %)—Thompson (1987); Q: n-cyclohexane/methylcyclopentane; R: n-heptane/methylcyclohexane; S: 3-methylpentane/benzene; T: methylcyclohexane/toluene; U: cyclohexane/benzene; V: isopentane/n-pentane; W: 3-methylpentane/n-hexane; B: toluene/n-heptane; 24/23: 2,4-/2,3-dimethylpentane ratio; T( C): hydrocarbon generation temperature determined from the 2,4-/2,3-dimethylpentane ratio using the calibration reported by BeMent et al. (1995); Rm: equivalent % vitrinite reflectance value estimated from T ( C) using the relationship described by Barker and Pawlewicz (1994).

clearly indicate a thermogenic origin. The C1/C1-5 values of the Taibei gases are within the range proposed for the transitional biogenic-thermogenic gases, but the 13C1 values are too heavy to be considered as being derived from this source. According to Xu et al. (1990), 13C1 values for transitional biogenic-thermogenic gases typically range from 60 to 46% (Type III organic matter) and 55 to 48% (Type I organic matter). Although many hydrogen-rich coals in other parts of the world do produce oil and wet gas, on a quantitative basis more gas than oil is often produced from the coals.

This is in sharp contrast with the Jurassic coal-bearing strata, thus these gases could have been generated within the conventional oil window from the same sources as the oils, not solely from the coals at the suggested low maturity levels. The third gas group includes only very minor quantities of associated gases from some J2q and J2x reservoirs in the Baka oilfield and the northwestern part of the Qiuling oilfield. These gases are differentiated from others by their high methane contents (>95%), high iC4/n-C4 ratio (up to 10), abnormal 3He/4He values

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M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

Table 6 Molecular geochemical parameters of the oil samples used in this studya Lab No.

H29/ H30

TT24/ T26

Tuokexun depression oil 2934 1.22 0.40 0.32

0.40

Lukexun Arch oils 2672 1.04 – 2677 2.16 0.65 2673 1.54 – 2681 1.29 – 2685 3.15 0.83

– 0.27 – – 0.24

Taibei depression oils 2686 5.86 0.85 2696 3.23 0.38 2692 8.51 1.23 2684 5.31 – 2671 4.25 0.45 2675 3.74 0.60 2667 4.67 0.68 2687 2.69 0.28 2670 4.55 0.61 2688 2.95 0.37 2695 2.71 0.37 2697 2.65 0.40 2682 3.74 0.49 2680 5.22 1.41 2683 2.88 0.39 2693 2.90 0.38 2666 3.25 0.34 2694 2.99 0.38 2679 3.02 0.38 2676 3.21 0.36 2678 1.56 0.57 2689 3.46 0.36 2669 2.39 0.23 2691 6.04 0.70 2674 3.89 0.59 2668 4.28 0.53 2690 4.39 0.45

0.15 0.10 0.18 – 0.09 0.14 0.13 0.09 0.12 0.10 0.12 0.14 0.12 0.21 0.13 0.13 0.10 0.12 0.12 0.11 0.34 0.10 0.09 0.12 0.14 0.13 0.11

a

Pr/ Ph

Pr/ 17

Ph/ 18

Gam/ C31

D30/ H30

0.65

0.15

0.10

0.64 0.60 0.65 0.64 0.66

0.79 0.67 0.73 0.75 0.80

1.48 1.48 1.56 1.52 1.37

0.65 0.52 0.48 0.77 0.59 0.52 0.68 0.68 0.69 0.52 0.53 0.48 0.56 0.68 0.44 0.47 0.60 0.48 0.58 0.50 0.55 0.52 0.52 0.70 0.65 0.59 0.62

37.90 4.28 0.99 4.75 4.74 3.69 1.93 1.39 1.86 4.85 2.22 7.11 3.71 5.89 4.64 4.54 3.00 3.81 2.10 4.33 3.30 2.45 2.13 1.76 9.22 4.02 1.84

0.13 0.07 0.55 0.10 0.13 0.24 0.12 0.23 0.13 0.12 0.23 0.28 0.14 0.08 0.25 0.24 0.24 0.22 0.24 0.20 0.33 0.28 0.32 0.10 0.18 0.18 0.14

T19/ T21

Ts/ (Ts+Tm)

20S

abb

D/R-29

27/ 29

28/ 29

27/ 29-dia

ST/ Hop

0.80

0.51

0.39

0.49

0.77

0.48

0.53

0.82

0.41

0.04 0.13 0.07 0.06 0.07

0.15 0.35 0.15 0.11 0.16

0.18 0.28 0.21 0.20 0.21

0.38 0.46 0.37 0.39 0.39

0.36 0.40 0.37 0.38 0.37

0.14 0.14 0.14 0.14 0.15

0.31 0.47 0.32 0.34 0.35

0.65 0.84 0.68 0.74 0.73

0.23 0.49 0.23 0.19 0.21

0.82 1.27 0.93 0.95 0.93

0.11 0.13 0.07 0.13 0.08 0.10 0.13 0.22 0.15 0.17 0.14 0.13 0.12 0.07 0.10 0.10 0.20 0.11 0.18 0.14 0.12 0.30 0.37 0.10 0.17 0.16 0.13

8.89 2.87 2.25 4.68 4.64 2.92 3.70 3.31 5.89 5.51 2.31 6.36 4.34 3.14 3.37 3.14 7.66 4.33 3.15 5.87 0.18 3.07 4.99 3.49 20.63 – 3.06

0.19 0.23 0.36 0.17 0.19 0.35 0.19 0.31 0.20 0.29 0.32 0.46 0.23 0.10 0.45 0.46 0.32 0.44 0.33 0.37 0.51 0.43 0.39 0.23 0.27 0.28 0.31

0.40 0.47 0.42 0.45 0.44 0.31 0.42 0.46 0.41 0.46 0.41 0.39 0.44 0.47 0.40 0.38 0.41 0.39 0.43 0.43 0.38 0.48 0.47 0.45 0.42 0.42 0.46

0.47 0.52 0.46 0.47 0.44 0.34 0.48 0.52 0.46 0.53 0.51 0.43 0.49 0.52 0.42 0.42 0.47 0.44 0.47 0.48 0.32 0.58 0.55 0.42 0.48 0.49 0.49

0.40 0.36 0.29 0.35 0.52 0.28 0.38 0.34 0.35 0.38 0.43 0.30 0.41 0.17 0.31 0.31 0.33 0.34 0.30 0.33 0.24 0.37 0.32 0.75 0.37 0.41 0.58

0.26 0.21 1.31 0.12 0.21 0.64 0.14 0.29 0.14 0.24 0.20 0.64 0.17 0.15 0.79 0.75 0.37 0.61 0.45 0.42 0.71 0.31 0.33 0.42 0.16 0.21 0.42

0.28 0.31 0.73 0.20 0.31 0.38 0.24 0.36 0.25 0.29 0.27 0.40 0.27 0.19 0.44 0.44 0.34 0.41 0.41 0.32 0.46 0.34 0.40 0.34 0.28 0.30 0.39

0.17 0.15 0.45 0.15 0.12 0.49 0.16 0.26 0.17 0.19 0.20 0.58 0.16 0.20 0.65 0.64 0.29 0.51 0.36 0.32 0.83 0.27 0.26 0.23 0.20 0.20 0.28

0.51 0.49 0.30 0.47 0.33 0.28 0.55 0.57 0.73 0.48 0.32 0.28 0.35 0.43 0.23 0.22 0.64 0.30 0.51 0.34 0.27 0.88 1.17 0.45 0.45 0.47 0.47

Pr/17 and Ph/18: pristane/n-C17 and phytane/n-C18 alkane ratios; see Table 3 for other abbreviations.

(7.01107) and extremely heavy 13C2 (20.1%) and 13C3 (21.3%) values. Because mantle-sourced gases usually show heavy 3He/4He values (
3105, Craig and Lupton, 1978) the abnormal 3He/4He values of the Baka field gases were taken as evidence for significant contributions from a mantle source (Huang et al., 1995). We believe that these gases may have nothing to do with a mantle source, but are most likely derived from biodegradation of the accumulated oils. As pointed out previously (James and Burns, 1984, James, 1990), aerobic bacteria are capable of preferentially attacking the wet gas components (C2+) resulting in the destruction of most of the wet gases. As a result of this alteration, the gases become much drier, and the 13C values of the

residual ethane, propane and other wet gases are much heavier than expected. On the other hand, many of the features of classical subsurface petroleum degradation can be obtained by anaerobic degradation using sulphate, Fe, Mn and carbon dioxide as co-oxidants (Bennett et al., 1993; Hunkeler et al., 1998; Larter et al., 1999). Biodegradation in the Baka field and adjacent area is clearly indicated by the absence of n-alkanes in the saturate gas chromatogram of the associated oils, e.g. from Ke-7 well. Atmospheric gases normally display heavy 3He/4He values (
1.4106, Craig and Lupton, 1978) compared to the 3.7– 5.3108 range observed for other Taibei depression gases. Hence, we suggest that the abnormal 3He/4He value of the Baka field gases

M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151 Table 7 Absolute concentrations of terpanes and steranes (mg/g saturate) in the solvent extracts of end member source rocks extracts selected for the calculations of simple binary mixing models Lab No.

8858

8877

8862

Well Depth (m) Strata Sample type C27baS C27baR C27aaaS C27abbR C27abbS C27aaaR C28aaaS C28abbR C28abbS C28aaaR C29baS C29baS C29aaaS C29abbR C29abbS C29aaaR C19 tricyclic C20 tricyclic C21 tricyclic C23 tricyclic C24 tricyclic C24 tetracyclic Ts Tm 30-Norhopane Diahopane 30-Normoretane Hopane Moretane C31-abS C31-abR Gammacerane C32-abS C32-abR C33-abS C33-abR C34-abS C34-abR C35-abS C35-abR

Shengbei-3 2292–2294 J2q C-P oilstain 3.5 2.4 3.6 3.0 3.5 3.8 4.8 3.2 4.3 4.1 2.3 3.8 4.9 6.9 5.6 7.8 5.8 15.8 15.7 11.1 5.6 3.4 6.2 5.9 28.0 5.5 5.3 57.3 9.9 26.9 20.6 5.0 20.7 15.2 18.1 12.0 12.3 8.6 11.8 9.1

Taican-2 3888.0 J2q Shale 454.1 329.1 908.4 528.5 583.3 410.5 1605.1 424.0 695.3 405.9 361.6 1082.4 1227.1 970.0 610.8 2327.4 120.9 268.3 424.2 349.4 112.7 703.5 3637.3 4074.6 8845.9 2115.6 3370.0 14295.3 5475.0 6710.8 5694.6 3115.9 3872.8 3033.6 2659.2 2028.0 1238.8 888.7 505.4 367.4

Lingshen-1 3941.0 J2x Coal 20.8 37.9 38.6 0.0 161.0 31.1 41.1 115.8 111.6 62.4 105.2 95.9 380.6 199.4 143.5 427.4 375.0 277.5 80.5 67.0 53.1 514.9 484.0 1803.5 2402.5 553.0 915.5 2811.7 1679.9 1811.6 1508.4 325.8 1288.7 939.7 689.6 464.2 323.3 199.8 80.5 61.2

resulted from the introduction of atmospheric gases dissolved in meteoric waters into reservoirs originally containing light oils. This suggestion is consistent with formation water data (Su and Li, 1994) which show a drastic reduction in the total dissolved solid concentrations from the Shanshan field (10,000–30,000 mg/l) to the Baka field (< 2000 mg/l).

1147

4.7. Revised model for hydrocarbon generation, migration and accumulation in the Turpan Basin In the light of the above new observations, a revised model for hydrocarbon generation, migration and accumulation in the Taibei depression of Turpan basin is proposed here. (1) The Middle Jurassic Qiketai Fm. lacustrine shales can be excluded as a major, effective petroleum source bed due to their low levels of thermal maturity throughout most of the basin, even though they show excellent hydrocarbon potential. Certain hydrogen-rich organic macerals in the Lower-Middle Jurassic coals and coaly shales in the Baodaowan and Xishanyao formations were capable of generating hydrocarbons when thermally mature. Due to the dominance and very nature of the humic coals, however, they would normally generate and expel significantly more gas than liquid hydrocarbons. (2) Lacustrine source rocks within the Baodaowan and Xishanyao formations and Upper Permian strata in the Taibei depression were also capable of generating large quantities of hydrocarbons. The Carboniferous–Permian marine source rocks are also potentially present in certain parts of the basin. In the Central uplift and Tainan depression, these strata are currently immature. Within the major Jurassic depocenters of the Taibei depression, the Paleozoic source intervals were generative during the Mesozoic and formed oil accumulations that were subsequently breached and redistributed during Cenozoic deformation. The maturity levels of the lacustrine source facies in the Baodaowan and Xishanyao formations are currently mature in large parts of the Taibei depression, thus representing another important source of liquid hydrocarbons. (3) Successive tectonic movements reactivated many deep-seated basement faults (Hou, 1995). These faults and associated fracture zones acted as conduits connecting both pre-Jurassic and Jurassic hydrocarbon source rocks to the Jurassic and overlying reservoirs. In places where Jurassic source rocks are immature, the hydrocarbons display excellent biomarker signatures for a pre-Jurassic source. In places where the Jurassic coal measures were mature during the Cenozoic deformation, mixing of oils generated from different sources occurred. In highly fractured regions along the major basement faults, the addition of allochthonous hydrocarbons may have helped the coals and coaly shales reaching the hydrocarbon saturation points that were needed for effective hydrocarbon expulsion. In the latter case, the resultant oils show a characteristic ‘‘coaly’’ biomarker signature even though they had significant contributions from other sources. Such a hydrocarbon generation, migration and accumulation scenario can be used more reasonably to explain many of the paradoxical relationships observed

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M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

Table 8 Chemical and isotopic compositions of the gases in the Turpan basin Field

Well name Strata

Depth (m) Sample d13C1 type

DC1

d13C2

d13C3

d13C4

% C1 % C2 % C3 C1/ C2+3 iC4/nC4

Shanshan Taican-1 J2q–J2x 2808–3247 Shan-13-15 J2s 3086–3100

Oil Oil

44.80 242 29.10 22.10 23.60 72.24 9.83 5.42 41.50 220 27.80 25.70 26.10 51.97 25.47 13.43

Qiuling

Ling-3 Ling-2 Ling-3

J2s+J2x 2300–2994 J2s 2748–2758 J2s 2405–2420

Oil Oil Oil

43.10 229 26.60 23.60 – 67.54 13.72 45.20 280 30.20 25.70 25.20 97.37 1.32 41.50 227 – – – 68.00 14.00

9.23 2.94 0.74 47.27 9.00 2.96

– – –

Wenxi

Wenxi-1 Wenxi-1

J2s J2x

2314–2627 Oil 2843–2860 Gas

43.00 265 28.70 24.70 23.50 76.43 14.81 43.40 271 28.80 24.70 24.20 84.40 7.80

4.90 3.89

3.88 7.22

0.84 0.62

Wenjisang Wen-1 Wen-5

J2s+J2x 2341–2819 Gas J2s 2488–2500 Oil

38.60 240 26.80 25.20 25.00 84.54 9.49 41.60 – 26.50 24.50 24.70 71.11 18.56

3.61 6.21

6.45 2.87

1.32 0.88

Qiudong

QD-7 QD-3

J2s J2x

2640–2658 Gas 3105–3434 Gas

39.90 244 26.90 26.10 24.60 41.20 24-7 – 26.10 25.00

– –

– –

– –

Miden

Mi-1

J2s

2667–2675 Gas

41.29

– 25.89 24.92 24.06 61.73 13.27 10.25

2.62

1.17

Hongtai

Hongtai-2

J2s

2570–2586 Gas

40.45

– 24.72 24.59 24.30 84.19

6.76

3.43

8.26

1.05

Shanle

Le-1

J2x

2677–2687

Oil

43.70

– 28.20 26.10 25.90 76.95 13.43

6.31

3.90

1.65

Baka

Ke-7

J2x

1841–1848

Oil

41.70 229 20.10 21.30

–

97.73

2.27

Yulahu

Tuocan-1

T3k

2428–2435

Oil

40.00 252 35.80 27.90

–

62.60

7.94 10.12

in the Turpan basin. These include (1) the large liquid hydrocarbon reserves with low gas/oil ratios in such a small humic-coal dominated basin, (2) the close association of major oil accumulations with fault systems, and (3) the regional distributions of Jurassic ‘‘coal-derived oils’’ and confirmed Upper Permian-derived oils. In the southern part of the basin (Tainan depression and Lukexun Arch) where the Jurassic source rocks are either absent or too immature, dominantly Permian sourced hydrocarbons are recognized in traps within the Permian and overlying strata. In the relatively shallow parts of Taibei depression (particularly along the exterior edges) where the Jurassic source rocks are immature, the underlying Permian and older source rocks generated hydrocarbons and later migrated up into certain relatively permeable Jurassic sections. Some of them have been recognized

Fig. 11. Methane and ethane carbon isotopes for gases in the Turpan basin.

– –

– –

4.74 1.34

0.00 43.05 3.47

– 0.73

– –

clearly as pre-Jurassic derived oil stains. In the bulk parts of the Taibei depression where large parts of the Jurassic are mature but the Carboniferous–Permian section are highly mature to overmature, only light ‘‘coal-derived oils’’ can be observed. 4.8. Implications for petroleum exploration A number of studies have indicated that the peak hydrocarbon generation and expulsion from the Paleozoic and Lower–Middle Jurassic source rocks occurred during the Middle–Late Jurassic and Late JurassicEarly Cretaceous time respectively (Huang et al., 1995; Cheng and Zhao, 1998). Thus, large petroleum accumulations in the Turpan basin are most likely found in traps formed prior to Middle–Late Jurassic time. Statistical data (Huang et al., 1995) indicate that oils in structures developed during the Yuanshan (or Kimmerian) period (e.g. Shanshan, Qiuling, Wenjisang, Mideng and Qiudong fields, Fig. 1) are generally filled to their spill points. In contrast, many of the Cenozoic structures that developed during the Himalayan period contain either no producible hydrocarbons or only small oil columns spilled from early-formed oil accumulations. Our results are consistent with this interpretation in that the oils and condensates were derived, by dominantly vertical migration, from the deep-buried Upper Permian and Middle–Lower Jurassic source beds during the Late Yuanshan (or Kimmerian) orogeny. The Carboniferous–Permian marine source rocks may be also important in limited localities.

M. Li et al. / Organic Geochemistry 32 (2001) 1127–1151

The oil and gas distribution in the Qiudong–Wenjisang structural zone shows a clear trend, from dominantly gas (Qiudong field; location 7, Fig. 1) in the north to the dominantly oil (Wenjisang field; location 5, Fig. 1) in the south. This could have resulted from selective leakage of gaseous components in the south from the more or less comparable hydrocarbons derived from the Qiudong depression. If this was indeed the case, lateral hydrocarbon migration must have been the dominant mechanism for the secondary migration in the basin. In addition, slightly heavier methane carbon isotope values would also be expected for residual gas caps in the southern oil accumulation zone. Because such a trend was not observed from existing analytical data, we propose an alternative explanation here. As all the oil and gas traps in the study area are cut by deep-seated faults, the faults may have provided them with access to deep hydrocarbon sources during the history of the basin evolution. The recent discovery of Upper Permian derived oils in the Triassic reservoirs from the Shanke-1 well (location 1, Fig. 1) indicates that a significant volume of conventional oil must have been generated within the Paleozoic sections from the deep part of the depression. These oils may have become entrapped within the pre-Jurassic strata in the vicinity of the major Jurassic depocenters, probably as early as Jurassic period, because of regional thermal maturity considerations. These oils subsequently remigrated upward via the deep-seated faults to shallower Jurassic and younger reservoirs. The basin geometry is such that significant variation in thermal maturity exists over a very short lateral distance for any given source bed sections. Thus, the vertical hydrocarbon migration via different deep-seated fault systems with access to different maturity source sections provides a viable explanation for the lateral hydrocarbon distribution within the Qiudong–Wenjisang structural zones. Jurassic targets in the Turpan basin have been pursued extensively with a high degree of success, but obviously for rather different reasons. These consist of anticlinal or stratigraphic traps that were all interconnected with the Upper Paleozoic strata sometime during geological time through deep-seated faults although the fault planes are currently impermeable. These traps were thought to contain Jurassic ‘‘coalderived oils’’, although the results of the present study show that this is not the whole story. The revised models for petroleum generation, migration and accumulation suggest that, in addition to Jurassic anticlines, faulted anticlines and other structure related to the basement faults, two types of new exploration targets exist in the Turpan basin. These include (1) deep structures within the Carboniferous-Permian strata for indigenous petroleum accumulations and (2) secondary petroleum accumulations in subtle structures (low magnitude anticlines and stratigraphic traps) within the Triassic–Jurassic sections cut by deep faults where regional Jurassic seals

1149

are well developed. As the Lower–Middle Jurassic coal measures in major depocenters of the Taibei depression are thermally mature, exploration for more Jurassic gas resources is also worth pursuing.

5. Conclusions The Lower–Middle Jurassic coal measures in the Turpan basin of NW China have been cited as a typical example of liquid hydrocarbon generation from humic coals. This study provides evidence against the Jurassic humic coals as the only major source for the oils discovered in this basin and suggests additional, significant contributions from lacustrine source rocks in the Upper Permian and Middle–Lower Jurassic strata. The occurrence and relative importance of Carboniferous–Permian marine source rocks cannot be properly evaluated on the basis of available data. Revised models for hydrocarbon generation, migration and accumulation predict that, in addition to conventional targets pursued over the past two decades, further petroleum exploration in the Turpan basin should include deep structures within the Carboniferous–Permian strata and subtle structures within the Triassic–Jurassic sections away from the current production areas.

Acknowledgements We thank PetroChina Tu-Ha Oilfield Company, Geological Survey of Canada and Jianghan Petroleum University for jointly funding this work and for permission to publish this paper; Sneh Achal, Laura Mulder and Huanxin Yao for excellent laboratory technical assistance; Drs. Tao Wu, Liechan Yuan, Yikui Yuan, Chuanguo Su, Zhiyong Wang and Suhua Li for providing samples and background data; and many GSCC colleagues for useful discussions. The authors benefited greatly from the helpful comments made by Drs. Lloyd Snowdon, Andrew Scott and Allan Carroll on an earlier version of this manuscript. This is a Geological Survey of Canada Contribution No. 1999233.

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