The occurrence of ultra-deep heavy oils in the Tabei Uplift of the Tarim Basin, NW China

Organic Geochemistry 52 (2012) 88–102

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The occurrence of ultra-deep heavy oils in the Tabei Uplift of the Tarim Basin, NW China Guangyou Zhu a, Shuichang Zhang a, Jin Su a, Haiping Huang b,c,⇑, Haijun Yang d, Lijing Gu a, Bin Zhang a, Yongfeng Zhu d a

Research Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083, China School of Energy Resource, China University of Geosciences, Beijing 100083, China Department of Geoscience, University of Calgary, 2500 University Drive NW, Calgary, AB, Canada T2N 1N4 d Research institute of Petroleum Exploration and Development, Tarim Oilfield Company, PetroChina, Korla 841000, China b c

a r t i c l e

i n f o

Article history: Received 13 December 2011 Received in revised form 7 August 2012 Accepted 23 August 2012 Available online 4 September 2012

a b s t r a c t Deeply buried heavy oils from the Tabei Uplift of the Tarim Basin have been investigated for their source origin, charge and accumulation time, biodegradation, mixing and thermal cracking using biomarkers, carbon isotopic compositions of individual alkanes, fluid inclusion homogenization temperatures and authigenic illite K–Ar radiometric ages. Oil-source correlation suggests that these oils mainly originated from Middle–Upper Ordovician source rocks. Burial history, coupled with fluid inclusion temperatures and K–Ar radiometric ages, suggests that these oils were generated and accumulated in the Late Permian. Biodegradation is the main control on the formation of these heavy oils when they were elevated to shallow depths during the late Hercynian orogeny. A pronounced unresolved complex mixture (UCM) in the gas chromatograms together with the presence of both 25-norhopanes and demethylated tricyclic terpanes in the oils are obvious evidence of biodegradation. The mixing of biodegraded oil with non-biodegraded oil components was indicated by the coexistence of n-alkanes with demethylated terpanes. Such mixing is most likely from the same phase of generation, but with accumulation at slightly different burial depths, as evidenced by overall similar oil maturities regardless of biodegradation level and/or amount of n-alkanes. Although these Ordovician carbonate reservoirs are currently buried to over 6000 m with reservoir temperatures above 160 °C, no significant secondary hydrocarbon generation from source rocks or thermal cracking of reservoired heavy oil occur in the study area. This is because the deep burial occurred only within the last 5 Ma of the Neogene, and there has not been enough heating time for additional reactions within the Middle–Upper Ordovician source rocks and reservoired heavy oils. Ó 2012 Elsevier Ltd. All rights reserved.

1. Introduction The composition of reservoired oil integrates all the processes occurring during petroleum generation, migration, accumulation and secondary alteration. Although source and maturity are commonly the main control on the present oil composition, in some cases secondary alteration is more important. Two important alteration processes are thermal cracking after expulsion and biodegradation. Thermal cracking, a consequence of increasing burial depth and higher temperature, will form increasingly high API gravity oils until extreme temperatures result in cracking of all oil to methane (Horsfield et al., 1992; Dahl et al., 1999; Vandenbroucke et al., 1999). In contrast, biodegradation by subsurface microbial communities at shallow depths leads to low API gravity heavy oils (Connan, 1984; Volkman et al., 1984; Peters and Moldowan, 1993). ⇑ Corresponding author at: Department of Geoscience, University of Calgary, 2500 University Drive NW, Calgary, AB, Canada T2N 1N4. Tel.: +1 403 2208396. E-mail address: [email protected] (H. Huang). 0146-6380/$ - see front matter Ó 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.orggeochem.2012.08.012

Moreover, oil reservoirs can be charged by multiple phases, continuously or periodically, resulting in complex distributions of fluid quality (Leythaeuser and Rückheim, 1989; Koopmans et al., 2002). Similar to kerogen thermal cracking to form oil and gas, heavier fractions of the crude oil are broken down to form light oil, condensate, and finally gas once the reservoir temperature is high enough. However, the issue of oil stability is highly controversial. Early work suggested oil was only stable to 150 °C (Hayes, 1991). It is generally agreed that around 200 °C, oil will be transformed into a mixture of mostly methane, with some C2–C5 alkanes and traces of C6–C14 products (Behar et al., 1991; Kuo and Michael, 1994). Fieldwork, laboratory pyrolysis and theoretical calculations suggest that liquid components may be preserved at higher temperatures than previously thought (Horsfield et al., 1992; Pepper and Dodd, 1995; Sajgó, 2000; Waples, 2000). Pepper and Dodd (1995) observe no evidence of significant in-reservoir cracking of oil in a deep petroleum pool in the North Sea, where temperatures had been in the range 174–195 °C. McNeil and BeMent (1996) studied the composition of a Cameroon oil and a Texas oil that had been

G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102

subjected to temperatures of 175–200 °C for tens of millions of years. They concluded that hydrocarbons are far more stable in nature than generally recognized. Waples (2000) performed a kinetic calculation and concluded that the maximum temperature where oil is preserved varies from 170 °C at geologically slow heating rates to over 200 °C at geologically fast heating rates. Dominé et al. (1998) also concluded that hydrocarbons in reservoirs should be stable to at least 180 °C. Once oils are reservoired at shallow depth, they are commonly found to be biodegraded to some degree. For biodegradation to occur, reservoir temperatures should usually be less than 80 °C, and nutrients and a suitable microbial population must be present (Connan, 1984; Peters and Moldowan, 1993; Wenger et al., 2002; Head et al., 2003; Huang et al., 2004). Larter et al. (2003) suggested that an 80 °C cut-off biodegradation temperature is the pasteurization temperature and the upper limit for hydrocarbon degraders in basins. Biodegradation of oil in reservoirs results in a decrease in hydrocarbon content and an increase in oil density, sulfur content, acidity, viscosity and metal content (Connan, 1984; Volkman et al., 1984; Peters and Moldowan, 1993; Head et al., 2003). This generally causes a decline in oil quality and serious problems for oil production, transportation and refining. While geochemists have made advances in identifying the geochemical sequence of subsurface oil degradation, in many cases it is geological factors such as oil mixing (Barnard and Bastow, 1991; Horstad and Larter, 1997; Koopmans et al., 2002; Larter et al., 2003) that dominate the final oil composition and physical properties. When two oils become mixed in the reservoir, the various molecular maturity indicators may differ widely between the end member values. A more complicated charge situation occurs when the first oil charge is subjected to biodegradation and is subsequently mixed with later charges to the reservoir, resulting in non-biodegraded and biodegraded oils within the same reservoir interval. Since reservoir charging is a dynamic process, Larter et al. (2003) proposed that fresh charge mixing concurrent with biodegradation is the key to understanding oil biodegradation. The Tarim Basin in NW China is a superimposed basin which contains huge volumes of heavy oil resources (about 3  109 t) in deeply buried Ordovician carbonate reservoirs at 6000–7000 m depth with temperatures of 150–170 °C in the northern uplift of the Tarim Basin (referred to as the Tabei Uplift). The initial oil charges underwent severe biodegradation during the Hercynian orogeny in the Late Permian. Spatial heterogeneities of compositions have repeatedly been recognized and interpreted to result from compositional changes of multiple sources and/or varying degree of biodegradation. The mixing of biodegraded and non-biodegraded oils is commonly indicated by the presence of a pronounced unresolved complex mixture (UCM) in the fingerprint pattern from gas chromatographic (GC) analysis of the oil together with the presence of both 25-norhopanes and n-alkanes. However, whether this fresh charge is from more matured source rocks or simply remigrated from the same phase of generation without biodegradation influence has not been thoroughly investigated in the study area. The purpose of the paper is to investigate the origin and subsequent evolution of the heavy oils through a systematic molecular and isotopic characterization integrated with geological study of the Tabei Uplift. This information may contribute to a better understanding of oil and gas accumulation mechanisms in the Tarim Basin and provide a better model for further petroleum exploration.

2. Geological background The Tarim Basin is the largest oil and gas bearing basin in China, with an area of about 56  104 km2. It is a Paleozoic cratonic basin, overlain in the south and north by the Mesozoic–Cenozoic foreland

89

depressions (Li et al., 1996). The outer part of the basin has been intensively deformed by superimposed Mesozoic–Cenozoic foreland tectonic events. Fluctuating crustal activity has resulted in multiple unconformities (Jia and Wei, 2002), allowing the basin to form several tectono-stratigraphic units (Fig. 1). The Tazhong and Tabei uplifts, separated by the Munjar Depression, constitute the main part of the cratonic region. All sedimentary strata (Neoproterozoic to Quaternary) are preserved in the cratonic region, with up to 14 km of sedimentary rocks accumulated in the Munjar Depression (Huang et al., 1999). The stratigraphy (Fig. 2) of the Tarim Basin consists of several marine, continental and transitional sequences. The Paleozoic strata sections were deposited almost entirely in marine settings. The 3 km of the Cambrian–Lower Ordovician strata comprise shallow marine to lagoonal carbonates, while the Middle–Upper Ordovician strata formed during a marine transgression that deposited bioclastic grainstone, packstone and mudstone. Following deposition of the Silurian and Devonian fine grained brown or reddish mudstones and tidal sandstones, about 1 km of the Upper Paleozoic marine clastics and continental transitional sediments accumulated. After a major Late Permian hiatus, renewed subsidence led to the accumulation of up to 6 km of the Mesozoic–Cenozoic fluvio-lacustrine sandstone and mudstone in the depocenter. The Tabei uplift located in northern part of the Tarim Basin is an inherited structural high formed on the pre-Sinian metamorphic basement. It initially formed as a large NE trending structural nose in the middle–late Caledonian period and reformed in the early Hercynian orogeny under regional compressive stress. During long term uplift and exposure, the Silurian–Devonian and Middle– Upper Ordovician strata were largely eroded over most of the uplift and the Lower Ordovician strata was partially denuded. The Hercynian orogeny in the late Permian caused further erosion of all of the Permian and part of the Carboniferous formations. Since the Indosinian tectonic movement, the Tabei Uplift experienced continuous subsidence and deep burial. In the last 5 Ma, the Tabei Uplift was rapidly buried with the present Ordovician reservoirs reaching depths of 5500–9000 m. A series of second order structural units are developed on Tabei Uplift, including the Yingmaili Sub-uplift, Halahatang Sag, Lunnan Sub-uplift and Caohu Sag from west to east (Fig. 1). The Munjar Depression located south of the Tabei Uplift generated a large quantity of oil and gas from marine source rock, while the Kuqa Depression (foreland basin) in the north was a source of gas from terrestrial source rocks of the Cenozoic age. The Tabei Uplift has the largest proven oil/gas reserves of the basin with over 3 billion tonnes oil-equivalent discovered in the Ordovician carbonates at 6000–7000 m depth, including the giant Tahe, Lunnan and Yingmaili oilfields (Pang et al., 2010). Heavy oils are mainly distributed in the Halahatang Sag and surrounding area within reservoirs of the Yijianfang and Yingshan formations (Fig. 2). These formations were deposited in an open platform facies and consist of brown-grey arenite, bioclastic limestone and algal limestone intercalated with oolitic limestone and micrite limestone. These carbonates have well developed karstification creating fairly high quality reservoirs. Karst reservoirs developed about 90 m below the Ordovician unconformity and are overlapped by the Lower Carboniferous and Triassic strata. Reservoir distributions are nearly parallel to the unconformity, which were formed by the combination of karstification, faulting and tectonic fracturing. The actual depth of the oil reservoirs varies over 1500 m without a uniform oil/water contact (Fig. 1d). Fractures connect secondary pores and vugs to a limited extent, but most of the reservoirs are highly heterogeneous with matrix porosity generally <8%. Due to low matrix porosity and permeability of the Ordovician carbonates, secondary solution pores and vugs serve as the main reservoir volume. The oils were primarily derived from the Middle–Upper Ordovician age source rocks in

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G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102

Fig. 1. Tectonic settings and oil/gas distribution in the Ordovician reservoir in the Tabei Uplift. (a) Location of the Tarim Basin; (b) structural unit division of the Tarim Basin; (c) structural unit division and main wells in the Tabei area; (d) EW cross section of reservoir in the Tabei area. Well names are along top of graph. Red lines are faults; red blobs are oil reservoirs. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

the western part of the Tabei Uplift (Hanson et al., 2000; Zhang et al., 2000; Zhang and Huang, 2005).

3. Methods and experimental procedures Oil and gas samples were collected from over 20 wells from the Halahatang Sag and its surrounding area in the Tabei Uplift. GC– FID of whole oil samples was performed on a HP 7890A instrument, equipped with a DB-5 fused silica capillary column (Model J&W 122-5-32, 30 m  0.25 mm  0.25 lm). Helium was used as the carrier gas. The GC oven was initially set at 40 °C for 2 min, and then programmed to 310 °C at 6 °C/min with a final holding time of 40 min. Saturated hydrocarbon fractions were analyzed using a ULTRA/ DSQ II mass spectrometer linked to a TRACE gas chromatograph (GC). The GC was equipped with a 60 m  0.25 mm (i.d.) J&W Scientific HP-5 fused silica capillary column with a 0.25 lm film

thickness. The oven temperature was initially set at 100 °C for 5 min, programmed to 220 °C at 4 °C/min and then to 320 °C at 2 °C/min, with a final hold time of 20 min. Helium was used as the carrier gas. Compound specific carbon isotopic determinations were performed on a Thermo Delta V Advantage IRMS instrument interfaced to a HP6890 GC via a combustion interface. Saturated hydrocarbons were purified by urea adduction before measurement to obtain n-alkane fractions. GC analysis of n-alkanes was performed on a 30 m HP5 column (0.32 mm i.d., 0.25 lm film thickness). The initial temperature was 60 °C for 2 min, then increased at 4 °C/min to 290 °C with a final hold time of 20 min. Gold tube pyrolysis experiments were carried out in stainless steel autoclaves with a sealed gold tube (60 mm length, 5 mm inner diameter and 0.25 mm wall thickness). An aliquot of oil from Well HD-11 (5125–5128.5 m, API = 19° at 20 °C, viscosity = 118.4 mPa s at 50 °C) was loaded into each of the duplicate gold tubes in a glove box containing an argon atmosphere. The tubes

G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102

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Fig. 2. Log interpretation of reservoir quality, lithology variation and oil saturation of the Middle–Upper Ordovician reservoir at well Ha 6C.

were flushed with argon in the box for 5 min to ensure the complete removal of air, then sealed by welding under an argon atmosphere. The sealed gold tubes were placed in pressurized autoclaves and kept at a constant pressure of 50 MPa during the course of the experiment. The samples were heated using two different non-isothermal heating programs of 20 °C/h and 2 °C/h from ambient temperature to 650 °C for 4 h, 8 h and 16 h. The gold tube was pierced by a steel needle in a vacuum after cooling. The generated gases were collected into a calibrated volume by using a Toepler pump and then introduced directly into the GC instruments for composition analysis. Polished thin sections were prepared for microscopic examination of fluid inclusions and reservoir bitumen. The petrological examination of fluid inclusions were performed on a ZEISS AXIOSKOP multi-function optical microscope. Measurements of fluid

inclusion homogenization temperatures were made with a Linkham Model TMS 94 heating–cooling stage. Four samples for fluid inclusion homogenization temperature measurement were collected from the Ordovician grainstone from well Ha 601-4 at depth 6654 m. The cements are mainly calcsparite with blue-white fluorescence showing a single phase charged hydrocarbon inclusion. The K–Ar measurements were conducted mainly on the fine size fractions which contain authigenic illite. Detailed methods of the K–Ar dating technique have been reported by Zhang et al. (2011c, and references therein). Freeze–thaw disaggregation was applied for sample preparation. Potassium content was determined in duplicate by atomic adsorption (PE AA100). The Ar isotope ratios were measured with an online high sensitivity MM5400 mass spectrometer. The K–Ar ages were calculated using 40K abundance and decay constants. The K–Ar age errors are within 1-sigma

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uncertainty. Six pieces of bituminous sandstone samples from the Silurian strata were analyzed for potassium–argon (K–Ar) age in the present study. Oil physical property analysis data were collected from unpublished reports of the Tarim Oil and Gas Company. 4. Results 4.1. Physical properties of oils and chemical composition of associated gases A wide range of petroleum types, including normal gravity oils, biodegraded heavy oils, waxy oils and condensates have been discovered in the Tabei Uplift. Condensate and natural gas are mainly distributed in the east of the Lunnan Uplift where thermal cracking, migration fractionation and gas invasion are the main controls on oil physical properties. Some waxy oils discovered in this area are migration fractionated residual oils, rather than having terrigenous origin. The heavy oils and oilsands are concentrated in the west of the Lunnan Uplift where biodegradation and mixing are prevalent (Zhang et al., 2005, 2011a,b; Lu et al., 2008; Wang and Zhang, 2010; Wu et al., 2010). Oils in the present study are mainly from the Halahatang, Aiding and Tuoputai oilfields in the west part of the Lunnan Uplift. API gravities for the oils range from 8° to 43° and the kinematic viscosity values vary from 2 to 4068 mm2/s at 20 °C (Table 1). Oil qualities become better from north to south. In the south part of the Halahatang Sag, API gravities generally range between 25° and 35°, while some low API gravity oils (<20°) are mainly in the northeast in shallower reservoirs. API gravity is mainly controlled by residual thickness of overburden on the reservoir before the deposition of the Triassic (Fig. 3). Low API gravity oils (higher degree of biodegradation and/or less late charge) are distributed in the late Permian structural high where the overburden thickness was <1800 m, while high API gravity oils are mainly distributed in the slope of the palaeo-high where the reservoir overburden thickness was >2000 m. Oil accumulations in reservoirs deeper than 2000 m before deposition of the Triassic have suffered slight or no biodegradation influence, so this is where conventional oils may be preserved. The sulfur contents vary from 0.34–2.7% (Table 1). Regional variations of the sulfur content of the oils mirror that of API gravities and viscosities. Well testing data show that the original gas to oil ratio (GOR) is around 50 m3/m3 or less in the heavy oil production region, showing a typical unsaturated nature (Table 1). Gases from the Halahatang region are dominated by methane but rich in high molecular gaseous components with C1/C2+ ratios <10. They are typical oil associated wet gases (Hartmann and Beaumont, 1999). The concentration of CO2 in natural gases from the Tabei area is generally high, especially associated with heavy oils, even though a wide range of variation is observed (Table 1). 4.2. Molecular composition of oils Except for a few oil samples reported in the literature from the structural high around the Halahatang Sag, such as LG 9 (5549.5 m, Zhang and Huang, 2005) and YW2 (5211.2 m, Jia et al., 2010), most oil samples in the Tabei Uplift either from the present study or reported in the literature (Zhang et al., 2005, 2011a; Jia et al., 2010; Li et al., 2010a,b) are characterized by a regular pattern of normal alkanes and isoprenoid alkanes superimposed on the UCM, corresponding to typical mixtures of non-biodegraded oil added to biodegraded oil (Fig. 4). Absolute concentrations of summed n-alkanes (n-C11–n-C35) from the saturated hydrocarbon fraction in the studied sample suite vary from 42–351 mg/g oil. There is a negative

correlation between the size of the UCM hump and the concentrations of n-alkanes with lower mg/g n-alkanes in the bigger UCM. Biomarker information about source rock identification and thermal maturity assessment in the Tarim Basin have been documented by numerous studies (Hanson et al., 2000; Zhang et al., 2000, 2002; Zhang and Huang, 2005; Jia et al., 2010; Li et al., 2010a,b; Yu et al., 2011). Very similar biomarker fingerprints were observed by GC–MS analysis of the studied samples, regardless of their physical properties, suggesting that these oils were most likely derived from the same source rock system. A series of 25norhopanes and 17-nortricylic terpanes were detected in the m/z 191 and m/z 177 mass chromatograms for the studied samples (Fig. 5). The ratios of C28 17a,21b 25-norhopanes to C29 17a,21b hopane (28NH/29H) and C29 17a,21b 25-norhopane to C30 17a,21b hopane (29NH/30H) are in the range from 0.09 to 3.16 and from 0.37 to 2.31, respectively (Table 2). Demethylated hopanes (25-norhopanes) are often present in severely biodegraded oils and are generally considered to be the product of hopane degradation which occurs during severe biodegradation (Moldowan and McCaffrey, 1995). As a class, the tricyclic terpanes are quite recalcitrant to the effects of biodegradation. Their degradation typically occurs well after hopane removal, generally at the same time as the pregnanes (Alberdi et al., 2001). A homologous series of 17-nortricyclic terpanes detected in most samples from the Tabei Uplift indicate oils are biodegraded to at least level 8 on the Peters and Moldowan (1993) scale. Several thermal maturity related compound ratios are given in Table 2. Some maturity parameters show a wide range of variation such as the values of Ts/(Ts + Tm) which ranges from 0.34 to 0.70, suggesting apparent maturity variation. However, the oils with high Ts/(Ts + Tm) values usually have very high 29NH/30H ratios. The Ts/(Ts + Tm) ratio appears to be sensitive to biodegradation, with Tm being preferentially removed at an advanced stage (Peters and Moldowan, 1993). Biodegradation influence is also indicated by high sulfur and low API values for these oils (Table 1). Therefore, the Ts/(Ts + Tm) ratio should be used with caution as a thermal maturity indicator when oils have been severely biodegraded. Isomerization at C-20 in the C29 5a,14a,17a(H) steranes causes 20S/(20S + 20R) to rise from 0 to 0.6 (equilibrium) with increasing thermal maturity. Isomerization at C-14 and C-17 in the C29 20S and 20R regular steranes causes an increase in the ratio of bb/(bb + aa) from near zero to values close to 0.65 (equilibrium) with increasing maturity. The ratios of 20S/(S + R) and abb/ (aaa + abb) for the C29 steranes in the studied oils are primarily in the range of 0.5–0.55 and 0.5–0.6 (Table 2), respectively. The ratios are approaching the equilibrium point, but remain as valid maturity indictors. The sterane isomerization degree suggests that oils in the Halahatang area were generated at the mature stage, before the peak oil generation window. The C27–29 diasterane/C27–29 sterane (Dia St/St) ratio is also commonly used to indicate the thermal maturity of crude oils although depositional facies and/or lithology have inevitably impact on the abundance of diasteranes. Relatively low diasteranes over regular steranes is generally related to a carbonate environment or lack of clay catalysis (Peters and Moldowan, 1993). This parameter seems not to reflect maturity very well, probably because all the oils are derived from a carbonate source rock and suffered severe biodegradation influence. Gammacerane is a depositional environment sensitive biomarker which originates from tetrahymanol. High relative abundance of gammacerane indicates an anoxic marine hypersaline source depositional environment, often associated with stratified water columns (Peters et al., 2005). The relative abundance of gammacerane is commonly used to differentiate the Middle–Upper Ordovician from the Cambrian–Lower Ordovician source rock systems in the Tarim Basin. The Cambrian–Lower Ordovician derived

Table 1 Oil physical properties, sulfur content and associated gas compositions from the Tabei Uplift. Block

Depth (m)

API gravity (° @20 °C)

Ha6C

6731.41– 6830.00 6598.23– 6677.00 6631.08– 6645.24 6598.11– 6710.00 6608–6666 6658.00– 6748.00 6615.5–6736 6668.58–6800 6597.6–6715 6597.56–6745 6643–6828.6 6512.61–6688 6548.38–6705 6613–6779.78 6625–6755 6542.3–6703.35 6540.21–6726.5

21.56

6557.89–6618 6594.06–6660 6562.7–6680 6637–6649 7050.1–7069.56 6400.00– 6437.18 6689.00– 6750.00 6140.00– 6330.00 6224.92– 6239.12

Ha601 Ha7 Ha9 Ha9-1 Ha11

Halahatang oil field

Tuoputai oilfield

Ha12 Ha13 Ha12-1 Ha12-2 Ha13-1C Ha15 Ha601-3 Ha602 Ha603 Ha6-1 Ha6017PT1 Ha701 Ha702 Ha7-6 Ha802 Ha901H TP7-3 TP8

Aiding oilfield

AD5 AD13CH

Viscosity (mm2/s) 20 °C

Sulfur content (%)

GOR (m3/m3)

Gas components (%) CH4

C2H6

C3H8

iC4H10

nC4H10

iC5H12

nC5H12

N2

CO2

0.59

82.8

8.43

2.23

0.24

0.38

0.07

0.06

4.82

0.90

26.46

6.175

0.61

65.8

16.1

6.45

0.75

1.55

0.30

0.34

7.72

0.71

3.30

18.73

238.70

1.21

58.37

16.30

7.30

0.97

2.33

0.58

0.68

7.52

5.47

15.60

21.92

28.55

0.62

58.50

16.30

4.35

0.37

0.83

0.10

0.10

3.79

15.60

42.20

29.00 37.66

8.01 3.23

0.75 0.55

69.70 65.50

11.60 10.60

6.94 8.98

1.29 2.27

2.56 3.64

0.66 1.09

0.65 0.97

3.08 3.46

2.07 2.74

61.80

38.74 42.76 27.36 26.97 42.89 25.95 25.97 43.30 28.93 33.05 27.94

2.96 2.25 2.85 18.57 2.26 40.00 3.76 2.18 7.75 5.24 10.15

0.79 0.39 0.34 – 0.45 0.87 – – 0.74 –

66.00 44.00 73.00 59.60 64.10 52.10 71.40 77.60 36.60 66.70 76.60

12.80 6.63 11.90 16.00 11.30 13.90 8.89 6.76 7.33 14.90 12.00

6.68 4.19 5.12 8.02 8.49 7.02 4.79 3.82 4.19 6.85 3.97

1.54 1.18 1.06 1.28 2.13 1.36 1.15 0.95 0.89 1.21 0.56

2.40 2.16 1.60 2.66 3.65 2.83 2.10 1.49 1.87 2.17 0.99

0.73 0.92 0.45 0.80 1.16 1.23 0.81 0.41 0.61 0.55 0.19

0.64 0.95 0.41 0.81 1.07 1.11 0.86 0.40 0.67 0.55 0.20

5.38 3.13 3.31 3.90 4.11 7.59 3.80 2.83 2.01 4.73 4.00

3.36 35.70 2.89 6.21 2.81 10.10 5.39 5.41 45.30 1.82 1.33

25.37 21.27 21.47 35.44 22.82 19.63

14.70 31.08 34.04 3.86 22.96 18.92

1.13 1.42 – 0.56 – 0.84

53.70 55.70 48.70 66.70 62.40 67.99

20.50 17.30 5.83 11.50 14.70 14.54

12.50 11.50 2.34 5.40 7.93 8.36

1.54 2.08 0.34 1.08 1.23 1.40

3.46 4.07 1.10 1.80 2.95 2.45

0.67 0.95 0.34 0.56 0.72 0.50

0.79 0.91 0.41 0.62 0.85 0.54

5.84 2.64 3.69 3.72 2.96 3.99

0.44 3.05 30.10 7.89 3.74 0.00

18.36

303.88

1.59

74.49

13.49

4.57

0.45

0.91

0.10

0.11

4.00

1.88

8.07

4068.07

2.70

11.04

4.92

2.69

0.23

0.77

0.13

0.20

0.56

79.41

19.05

375.78

1.63

42.69

8.30

3.06

0.29

0.59

0.09

0.10

2.46

42.39

49.20

G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102

Well

93

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G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102

Fig. 3. Oil API gravity variation in the Halahatang area (Paleo-structure contour map showing the top of the Middle Ordovician in the late Hercynian period before deposition of the Triassic).

Ha9, 6626.1 m, O2y, Oil

Ha11, 6658.0-6748.0 m, O1-2y1, Oil

Fig. 4. Representative gas chromatograms of saturated hydrocarbon fractions in oils from the Tabei Uplift. 13–21: Carbon number of n-alkane; Pr: pristane; Ph: phytane.

oils were enriched with gammacerane and gammacerane/C30 17a,21b hopane ratios (Gam/30H, gammacerane index) fall in the range of 0.18–0.26, while the relatively low ratios of Gam/30H is associated with Middle–Upper Ordovician source rocks (Li et al., 2010a; Yu et al., 2011). Ratios of Gam/30H vary from 0.05 to 0.97 in the studied sample suite. Since gammacerane is more resistant to biodegradation than regular hopanes (Peters and Moldowan, 1993), the unusually high gammacerane index in some samples may indicate a biodegradation influence rather than being depositional environment related. 4.3. Stable carbon isotopic compositions of individual n-alkanes Stable carbon isotopic compositions of n-alkanes can also be used for source characterization of oils. Distinct isotopic signatures have been observed in two suites of source rocks and derived oils in the Tarim Basin. Oils from the Cambrian source rocks and associated oils have individual n-alkanes in the range n-C14 to n-C31 that are isotopically enriched (d13C 29.6‰ to 29.1‰), while the Middle–Upper Ordovician source rocks and derived oils have individual n-alkane that are isotopically depleted (d13C 34‰ to

35.6‰) (Jia et al., 2010; Li et al., 2010a,b). Oil in the Ordovician reservoir from well LN 63 in the east of the Lunnan Uplift is widely accepted as the end member of the Cambrian-sourced oil whose n-alkanes are enriched in 13C. In contrast, well YM1 is a typical Middle–Upper Ordovician origin oil whose n-alkanes are depleted in 13C (Jia et al., 2010; Li et al., 2010a; Zhang et al., 2011a). Carbon isotopic values of individual C14–C33 n-alkanes for oils from the Halahatang area are generally within the range from 32.0‰ to 34.0‰ (Fig. 6), close to the Mid-Upper Ordovician origin signature. However, Li et al. (2010b) regarded such compound specific isotope values of n-alkanes in the Lunnan area as an indicator of mixed contribution from both Ordovician and Cambrian source rock systems. 4.4. Authigenic illite dating The timing of hydrocarbon charge into reservoirs can be inferred from authigenic illite K–Ar radiometric measurement, because authigenic illite stops growing after initial oil/gas entrapment (Darby et al., 1997). The differences in the accumulation timing between various oil pools in different parts of the Tarim Basin have been

G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102

95

Fig. 5. Representative mass chromatograms of terpanes and demethylated terpanes (m/z 191 and 177) in oils from the Tabei Uplift. 23–35: Carbon number; TT: tricyclic terpanes; H: hopanes; DT: demethylated tricyclic terpanes; D: demethylated hopanes.

illustrated by Zhang et al. (2011c). They reported a wide range of authigenic illite age variations in the Tabei uplift. Seven Silurian sandstones from wells YM11, YM34, YM35 and YM35-1 were collected for K–Ar dating. The ages range from 255 to 293 Ma (Table 3), corresponding to a Late Permian (late Hercynian) initial liquid and gaseous hydrocarbon migration timing. 4.5. Fluid inclusions Petroleum fluid inclusions may hold important clues to the palaeo-migration of oils at the time of authigenic mineral formation. The homogenization temperatures (Th) of fluid inclusions provide information about the temperature of the strata in which the hydrocarbon inclusions were trapped (Thiery et al., 2000). Several studies have reported the petroleum charge history of the Tabei Uplift by comparing the geochemical characteristics of fluid inclusion oils and homogenization temperatures from the Ordovician reservoirs (Gong et al., 2007; Wang et al., 2008; Yu et al., 2011). Fluid inclusions sampled from well Ha 601-4 at a depth of 6654 m in the Ordovician carbonate reservoir have a size of 5– 8 lm with irregular shape, no colour or light brown colour, and light yellow or yellow fluorescence. Most inclusions are aqueous coeval with liquid oil. Frequency of oil inclusions (FOIs) is 4%. FOI is a petrographic method that records the numerical measure of

the abundance of oil inclusions in carbonate reservoirs. Similar to the grains with oil inclusions (GOIs) technique (George et al., 2004), FOI measures the areas with inclusions versus the number of areas which have potential oil inclusion trapping sites. Areas that are unlikely to have been exposed to oil are excluded from the analysis. No three phase fluid inclusions containing gas, oil and water in the same inclusion have been observed. Based on microthermometry, the homogenization temperatures of the associated aqueous inclusions are in the range from 83.4 to 89.0 °C (Table 4). A uniform population of fluid inclusion Th values suggests a single phase of oil charge. 4.6. Kinetic parameters Laboratory closed system pyrolysis can potentially provide useful information about gaseous hydrocarbon generation from oil cracking within the reservoir. The yields of hydrocarbon gases and geochemical evidence of thermal cracking of oil in the Tarim Basin have been documented by a few case studies (Zhao et al., 2005; Wang et al., 2006; Zhang et al., 2011a). In the present study, a gold tube pyrolysis experiment was performed on oil from well HD11 oil (refer to Jia et al., 2010 for geochemical characteristics of the oil). The KINETICS™ package was used to derive kinetic parameters including the activation energy and frequency factor

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Table 2 Molecular compositions of oil from the Halahatang area of the Tabei Uplift. Well

Depth (m)

n-Arkanes (mg/g)

28NH/29H

29NH/30H

Ts/(Tm + Ts)

20S/20(S + R)

bb/(aa + bb)

Dia St/St

C28/C27-C29

Gam/30H

Ha6-1 Ha6C Ha7 Ha8 Ha9 Ha9-1 Hall Hal2 Hal2-1 Ha 12–2 Hal3 Hal3-lC Hal5 Ha601 Ha601–3 Ha601–7PTl Ha602 Ha603 Ha701 Ha702 Ha802 Ha901H

6542.3–6703.35 6731.41–6830.00 6631.08–6645.24

240.2 140.9 59.6 237.2 83.6 42.5 239.1 231.2 195.2 223.4 351.2 344.1 121.5 123.9 180.3 120.2 236.5 67.3 70.3 91 56.4 98.7

0.25 0.55 1.78 0.31 1.73 1.79 0.63 0.36 0.45 0.31 0.09 0.29 1.95 0.40 0.43 1.35 0.32 2.80 3.16 1.49 1.64 1.99

0.89 1.90 2.31 0.85 2 22 1.56 0.95 0.71 0.64 0.55 0.38 0.52 2.03 0.99 0.88 1.39 0.66 1.52 2.16 2.04 1.74 1.64

0.46 0.46 0.41 0.37 0.38 0.42 0.35 0.34 0.66 0.63 0.37 0.43 0.42 0.34 0.46 0.43 0.48 0.50 0.47 0.70 0.44 0.42

0.45 0.49 0.50 0.56 0.55 0.53 0.54 0.57 0.53 0.52 0.60 0.56 0.49 0.59 0.54 0.57 0.58 0.56 0.52 0.52 0.56 0.52

0.48 0.54 0.54 0.55 0.58 0.54 0.53 0.54 0.54 0.58 0.57 0.57 0.56 0.52 0.56 0.54 0.55 0.55 0.54 0.57 0.56 0.53

0.46 0.40 0.47 0.41 0.45 0.41 0.39 0.36 0.38 0.49 0.42 0.42 0.27 0.40 0.38 0.36 0.42 0.39 0.35 0.37 0.36 0.45

0.29 0.17 0.10 0.20 0.19 0.24 0.27 0.25 0.22 0.13 0.27 0.23 0.19 0.27 0.20 0.25 0.35 0.24 0.20 0.08 0.26 0.22

0.14 0.16 0.16 0.22 0.16 0.10 0.12 0.22 0.75 0.18 0.10 0.05 0.24 0.21 0.38 0.05 0.12 0.12 0.97 0.34 0.20 0.07

6598.11–6710.00 6608–6666 6658.00–6748.00 6615.5–6736 6597.6–6715 6597.56–6745 6668.58–6800 6643–6828.6 6512.61–6688 6598.23–6677.00 6548.38–6705 6540.21–6726.5 6613–6779.78 6625–6755 6557.89–6618 6594.06–6660 6637–6649 7050.1–7069.56

n-alkanes: C11–35 n-alkanes; 28NH/29H: C28 25-norhopanes to C29 hopane; 29NH/30H: C29 25-norhopane to C30 hopane; Tm: 17a(H)-trisnorhopane; Ts: 18a(H)trisnorhopane; 20S/(20S + 20R): C29 5a,14a,17a(H) steranes 20S/(20S + 20R); bb/(bb + aa): C29 20S and 20R steranes bb/(bb + aa); Dia St: C27–29 diasteranes; St: C27–29 regular steranes; C28: sum of C28 regular steranes; C27–C29: sum of C27–C29 regular steranes; Gam: gammacerane.

Fig. 6. Distribution of carbon isotopic values of individual n-alkanes in the Tabei crude oils.

Table 3 Authigenic illite K–Ar radiometric age of the Silurian bitumen sandstone from the Yingmaili area of the Tabei Uplift. Well

Depth (m)

Fm.

Grain size (lm)

Mineral (%) I/S

Potassium content

Age (Ma)

Tectonic episode

YM 11

S1k

YM 35-1 YM 35

5562 5574 5631 5588.7

S1k S1k

YM 34

5386.9 5388.7

S1k

0.3–0.15 0.3–0.15 0.3–0.15 0.3–0.15 0.3–0.15 <0.15 0.3–0.15

53 97 100 100 78 76 75

3.71 6.07 6.71 6.38 3 3.41 3.43

277 287 288 293 255 281 280

Late Late Late Late Late Late Late

for hydrocarbon gas from oil cracking. The activation energy defines the minimum energy required to initiate a specific chemical reaction, while the frequency factor is the pre-exponential constant in the Arrhenius equation. Our thermal simulation experiment derived kinetic parameters with a mean activation energy of 59.8 kcal/mol and a frequency factor of 2.13  1013 s 1 for oil cracking and gas generation. These activation energy and frequency values are similar to an average of values quoted in the literature for secondary cracking (Dieckmann et al., 1998; Vandenbroucke et al., 1999).

Hercynian Hercynian Hercynian Hercynian Hercynian Hercynian Hercynian

5. Discussion 5.1. Oil source correlation There are two major sets of Palaeozoic marine source rocks in the Tarim Basin, the Cambrian shale and the Middle–Upper Ordovician marl. Previous studies have shown that the biomarker assemblage can be used to distinguish the Cambrian source rocks from the Middle–Upper Ordovician marls (Hanson et al., 2000; Zhang et al., 2002, 2011b; Zhang and Huang, 2005; Lu et al.,

G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102 Table 4 Fluid inclusion homogenization temperatures of the Ordovician reservoir from well Ha601-4 at a depth of 6654 m. Type

Size (um)

Colour

Fluorescence

GLR (%)

FOI (%)

Th (°C)

OLG + OL

6

Yellow

15

4

86.2

OLG + OL

8

Yellow

10

4

83.4

OLG + OL OLG + OL

8 5

Light brown Light brown None None

Yellow Yellow

10 15

4 4

85.3 89.0

OLG: liquid and gaseous hydrocarbons; OL: liquid hydrocarbons; GLR: Gaseous to liquid hydrocarbons ratio; FOI: frequency of oil inclusions; Th: homogenization temperature.

2008; Li et al., 2010a). Oils derived from the Cambrian source rocks have high contents of C28 regular sterane, gammacerane, dinosterane and triaromatic dinosteranes, 4-methyl steranes, C26 4-norcholesterane, tricyclic terpanes, low contents of diasteranes, and enriched carbon isotopic values for n-alkanes. In contrast, oils from the Middle–Upper Ordovician source rocks show the opposite features (Hanson et al., 2000; Zhang et al., 2000, 2002, 2005; Li et al., 2010a). Oils in the present study have very similar triaromatic sterane (m/z 231) and methyl triaromatic sterane (m/z 245) distributions, as shown for oil Ha11 in Fig. 7, indicating the same source origin. This distribution pattern differs from typical Cambrian sourced oil, as represented by LN 63 in Fig. 7 (Zhang et al., 2011a). Sterane distribution can also be applied for oil-source correlation. The Cambrian source rock and oil have linear or reverse-L shaped C27, C28 and C29 sterane distribution patterns, whereas most of the Middle–Upper Ordovician source rock and oil display ‘‘V’’ shaped sterane distribution (Zhang et al., 2000; Li et al., 2010a,b). All oils in the studied sample suite show ‘‘V’’ shaped sterane distribution, suggesting predominance of the Middle–Upper Ordovician source origin (Fig. 8). Some oils with unusually low C28/C27–29 ratios (Table 2) are probably altered by biodegradation.

97

5.2. Charge time and accumulation history The analysis of hydrocarbon charge history is normally based on the burial history of source rocks coupled with petroleum fluid inclusion measurement. The homogenization temperatures, especially those of aqueous inclusions coeval with petroleum inclusions are commonly used to predict the time of fluid entrapment by integration with thermal history. However, the charge history interpretation depends on the accuracy of burial history reconstruction. Different burial history reconstructions will derive different interpretations of hydrocarbon generation and accumulation histories (see Gong et al., 2007; Lu et al., 2008; Wang et al., 2008; Zhu et al., 2012 for more details). Therefore, the accuracy of the burial history curve remains critical for such interpretation. A typical burial history of the Tabei Uplift is illustrated in Fig. 9, as represented by well Ha 601-4. In summary, early Paleozoic subsidence (at the time of source rock deposition) was followed by tectonic activity and burial during the late Paleozoic (the Hercynian Orogeny), followed by gradual subsidence during the Mesozoic and rapid deposition during the Cenozoic. The geothermal history in the present study was reconstructed using an equivalent vitrinite reflectance (Ro) forward modeling method. The fluid inclusion homogenization temperatures from 83–89 °C correspond to the late Permian period on the thermal history curve. The 1-D basin modeling results show that the main oil generation time of the Middle–Upper Ordovician source rocks in the depression area south of the Tabei Uplift was 280–250 Ma (Fig. 10, Zhu and Zhang, 2009). Our K–Ar dating ages from 255 to 293 Ma show that early hydrocarbon charge most likely occurred during the Late Permian, which is consistent with the fluid inclusion results. Hydrocarbon generation, accumulation and alteration histories in the Halahatang area can be illustrated by a cross section evolution profile (Fig. 11). Before the late Hercynian orogeny, the Middle–Upper Ordovician marine source rocks had reached the peak oil generation stage. The presence of well defined structural and stratigraphic fairways, combined with rapid, tectonically

Fig. 7. Representative triaromatic steroid hydrocarbon (m/z 231) and methyl triaromatic steroid hydrocarbon (m/z 245) distributions in oils from different source rocks in the Tarim Basin. 1: C26 20S triaromatic sterane; 2: C26 20R + C27 20S triaromatic sterane; 3: C29 20S triaromatic sterane; 4: C27 20S triaromatic sterane; 5: C27 20S triaromatic sterane; 7: 4,23,24-trimethyl triaromatic sterane (C29 triaromatic dinosterane); 8: 4-methyl-24-ethyl triaromatic sterane (C29); 9: 3-methyl-24-ethyl triaromatic sterane (C29); 11: 4-methyl triaromatic sterane (C27); 12: 3-methyl triaromatic sterane (C27); 13: 3, 24-dimethyl triaromatic sterane (C29); : Unidentified compound.

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Ha11 6658.0-6748.0m O1-2y1 Oil

LN63 5957-6071m O3 Oil

Fig. 8. Representative sterane (m/z 217) distributions in oils from different source rocks in the Tarim Basin.

Fig. 9. Burial history of the Tabei Uplift represented by Well Ha 601-4. The right figure shows the enlarged curve for the Neogene and the arrow points to the corresponding homogenization temperature.

Fig. 10. Thermal evolution and hydrocarbon generation history of the Middle–Upper Ordovician source rock at well Acan 1 area, the Tabei Uplift.

driven burial, created the opportunity for unusually efficient migration and trapping of hydrocarbons expelled during the Late Permian, and resulting in the large accumulations in the Ordovician and Silurian reservoirs observed on the Tabei Uplift (Fig. 11). The late Hercynian orogeny during the late Paleozoic–Triassic period caused uplifted and erosion, and was the defining event for the petroleum geology of the Tabei Uplift. About 1000 m of the Paleozoic strata has been removed during the Hercynian tectonic movement, which not only interrupted the thermal maturation processes of the Lower Paleozoic source rocks, but also caused poor reservoir preservation conditions. In the Halahatang area, most

reservoirs were buried at depths of about 600–2000 m before deposition of the Triassic strata (Fig. 11). Based on a paleogeothermal gradient of 30 °C/km and a surface temperature of 15 °C (Feng et al., 2009), the Ordovician reservoirs had a temperature in the range from 33–75 °C in the late Hercynian period. This temperature is suitable for microbial activity (Head et al., 2003; Larter et al., 2003; Huang et al., 2004), which leads to the extensive biodegradation and heavy oil formation in the Tabei Uplift. Since deposition of the Triassic strata, drape-like sediments were deposited on top of the Paleozoic strata during the Mesozoic. The continuous sediment loading, particularly in the Pliocene and younger

G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102

99

Fig. 11. Cross section of burial history evolution, illustrating hydrocarbon accumulation history in the Ordovician carbonate reservoir at the Tabei Uplift (see Fig. 1 for location). r Before deposition of the Upper Ordovician, weathering and erosion caused the formation of Karst reservoirs due to the Caledonian Orogeny. s In the early phase of the Hercynian Orogeny, the Silurian formation was denuded and Ordovician karst reservoirs were further developed. t In the late phase of Hercynian Orogeny (late Permian), oil derived from the Middle–Upper Ordovician source rocks migrated laterally from south to north to charge the Ordovician karst reservoirs extensively. u Before deposition of the Triassic, regional structures were uplifted and heavy oils were formed due to severe biodegradation. v Since deposition of the Mesozoic, the Ordovician reservoirs have been continuously buried and heavy oils are effectively preserved.

rapid burial phase of 2000–3000 m, resulted in a significant increase in thermal maturity of the Cambrian and Ordovician source rocks and reservoired oils and led to thermal cracking in the east Tarim Basin (Zhao et al., 2005; Wang et al., 2006; Zhang et al., 2011a). During the last 5 Ma the burial rate increased to about 400 m/Ma. The Ordovician reservoirs are currently deeply buried up to 7000 m, which corresponds to a reservoir temperature of 160 °C. However, since the late Hercynian orogeny, the source rocks in the study area have not surpassed the previous thermal maturity for a long period of time, due to the decreasing geothermal regime. Faster heating during the last few million years has not caused significant thermal cracking yet.

5.3. Mixing of biodegraded and non-degraded oil Reservoirs can be charged by multiple phases (or through continuous charge) and this will complicate fluid-quality distribution. Petroleum fluid mixing in the carrier and reservoir system is common in sedimentary basins that contain multiple petroleum source sequences with a long, complex tectonic history, such as in the Tarim Basin. In-reservoir mixing has been discussed by several studies (Lu et al., 2008; Li et al., 2010a,b; Wang and Zhang, 2010; Yu et al., 2011). However, the charge event interpretation and source of the late charge remain controversial. In some cases, mixing in the reservoir has resulted in a geochemical composite that precludes

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G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102

description of each individual charge. Our results show that late oil charge is mainly from re-migration of previously accumulated oil pools formed at the same time as the biodegraded oils. Changes in petroleum compositions can be interpreted in terms of gradual mixing of earlier biodegraded oil with later migrated non-biodegraded oil. The co-existence of intact n-alkanes and 25-norhopanes in most of the Tabei oils suggest that the oil pools have experienced complicated charge histories, but clearly have one biodegraded phase and one non-biodegraded phase. The n-alkanes detected in the reservoirs are derived from late oil charges without biodegradation, while 25-norhopanes represent the initial phase of charge suffering severe biodegradation influence. An inverse correlation between absolute concentrations of n-alkanes and the 29NH/30H ratio may form a semi-quantitative estimation of the relative intensities of the fresh oil charges (Fig. 12). Obviously, the relative intensities of fresh oil charges as indicated by concentrations of nalkanes exhibit large variations (more detailed quantification will be published later). Since late charge and mixing is the norm in the Tabei Uplift, the unaltered second pulse of oil commingling with the initial biodegraded charge gives the wide range of oil physical property variations. Where no fresh charge was received, as indicated by very low n-alkane concentrations, the biodegraded oil residuals changed little in their physical properties, whereas the intensive fresh charge could dissolve the biodegraded oil residuals to form conventional oil. Therefore, relative abundances of the n-alkanes and 25-norhopanes present in crude oils provide an excellent tool for resolving crude oils that result from in-reservoir mixing of two charges, if both components are available. Whether this fresh charge is from more matured source rocks, or re-migrated from the same phase of generation without biodegradation influence, requires more thorough investigation. One process which will affect the distributions is the in-reservoir mixing of crude oils with different maturities, since most reservoirs receive progressively more thermally mature fluids over time (Leythaeuser and Rückheim, 1989; Waples, 2000). When two oils mixed in the reservoir their thermal maturity indicators show a wide range of variation in the different components. However, limited sample analysis in the present study shows uniform thermal maturity levels, regardless of different physical properties (API gravity and viscosity) and n-alkane content (Table 2). Since regular steranes are only moderately resistant to microbial attack and their distributions can be affected at more advanced stages of biodegradation, current sterane maturity reflect the late pulse of charge. Nonequilibrium sterane isomerization indicates thermal maturities lower than the peak oil generation window, implying that these oils were generated before the late Hercynian, the same time as the biodegraded oils. A slightly high thermal maturity appearance in some heavy oils, as indicated by high Ts/(Ts + Tm) ratios, may be

caused by a biodegradation influence, since Tm is slightly more susceptible than Ts (Peters et al., 2005). No clear thermal maturity difference or obvious highly matured fresh charge among different oils suggests the mixes of biodegraded and non-biodegraded oil might have been derived from the same source and were probably generated at the same time. Such physical mixing may develop either during a continuous process due to seal breach of deeply buried accumulations during late evolution, or as episodic events. 5.4. Secondary thermal cracking and stability of oil under high temperature The possibility of oil cracking in the study area has been investigated through the kinetic simulation of marine oil from the Halahatang region. Thermodynamic conditions for the secondary cracking of oil under geological circumstances can be evaluated using kinetic parameters derived from laboratory experiments. The geological time required for conversion efficiency of 51% (the threshold value when the independent oil phase in the reservoir disappears, with a corresponding GOR of 3200 scf/bbl; Waples, 2000) from oil under constant heating temperatures and different geological heating rates were calculated on the basis of the laboratory kinetic results in well HD 11 and the geothermal history (Table 5). If oil was heated at a constant temperature of 180 °C, our kinetic model predicts 52.8 million years is required for the oil to reach a conversion rate of 51% (destruction of the original oil). If oil was heated at a constant temperature of 200 °C, only 3.2 million years is required for the oil to reach the same conversion rate. For studying the thermal stability of the Paleozoic oil under geological conditions, a series of heating rates including 1, 2, 3, 5 and 10 °C/ million years were used to derive the extrapolations for the required geological time of oil cracking. The conversion rate of cracked gas from oil under geological temperatures and heating rates are shown in Fig. 13. The arc lines representing the duration time for complete cracking of the oil clearly demonstrate the evolution trend as the geological heating rates change. It is well known from chemical kinetics that the heating rate is an important factor for controlling oil cracking. The faster the geological heating rate, the shorter is the required geological time for oil cracking (Pepper and Dodd, 1995; Waples, 2000; Zhang et al., 2007). It will require about 100.8 million years to transform 51% of oil to gas if the oil was heated at 2 °C/million years, whereas it only needs 21 million years to reach the same cracking degree if the heating rate is as high as 10 °C/million years. This type of study is particularly important for investigations of in-reservoir oil cracking where the presence and distribution of the palaeo-oil reservoir is not clear. Based on the geothermal history, burial history and kinetic calculation in the Halahatang area, the onset depth for oil cracking is 7500 m, and large scale cracking will

2.5 Table 5 Minimum time for 51% of oil conversion to gas under geologically constant heating temperature and varying heating rate conditions.

29NH/30H

2.0 1.5

Geological conditions

Temperature or heating rate

Time (MY for 51% conversion)

1.0

Constant temperature (°C)

100 150 180 190 200

8.09  107 5.86  103 52.8 12.6 3.18

0.5 0.0

0

50

100

150

200

250

300

350

400

Total n-alkanes concentration (mg/g oil) Fig. 12. Plot of absolute concentrations of total n-alkanes (C11–C35) versus 29NH/ 30H ratios illustrating intensity of biodegradation and late charge.

Geothermal heating (°C/MY)

1 2 3 5 10

196.4 100.8 68.2 41.3 21

G. Zhu et al. / Organic Geochemistry 52 (2012) 88–102

Conversion efficiency (%)

100

101

6. Conclusions

90 80 70 60 50

1 ºC/MY

40

2 ºC/MY 3 ºC/MY

30

5 ºC/MY 10 ºC/MY

20 10 0

0

50

100

150

200

250

Time (MY) Fig. 13. The conversion rate of cracked gas from the Paleozoic oil in the Tarim Basin at geological temperatures and geological heating rates (lines from right to left corresponding to 1, 2, 3, 5, 10 °C/Ma).

occur at 8800–9500 m (Fig. 14). At a depth of >9500 m, liquid oil will disappear when the reservoir temperature reaches >210 °C. This implies that the Paleozoic oil in the Tabei Uplift remained stable within the temperature window from 120 °C to over 160 °C in the last million years. Oil cracking is currently initiated, however, the duration time of oil-cracking has not been sufficient for significant oil cracking. Therefore, the heavy oils are largely preserved in the deep and hot reservoirs. GORs of oils in the Tarim Basin have a good correlation to the degree of thermal cracking (Zhang et al., 2011a). Low gas daily production (generally <10,000 m3/day) and low GORs (<150 m3/m3) are supplementary evidence for the low degree of thermal cracking. These heavy oil reservoirs are unsaturated with gas and these gases are wet (Table 1). A low degree of thermal cracking also agrees with empirical data from diamondoid compounds estimation. Using cracking resistant diamondoid concentrations as a measure of loss of oil due to cracking, Dahl et al. (1999) demonstrated that the relative abundance of diamondoid hydrocarbons can be used to identify the occurrence and estimate the extent of oil destruction and the oil deadline in a particular basin. A typical thermally cracked oil, as represented by the YN2 oil, has 3- and 4-methyl diamondoids concentrations of 250 lg/g oil (Zhao et al., 2005). Heavy oils in the present study have much lower diamondoid hydrocarbon content with 3- and 4-methyl diamondoids of about 25 lg/g oil. The high GOR of 14,670 m3/m3 and high diamondoid hydrocarbon concentrations in YN2 oil are reliable indicators for thermal cracking (Zhao et al., 2005; Zhang et al., 2011a), while low GOR and low concentrations of diamondoid hydrocarbons are consistent with a low degree of thermal cracking.

Ultra-deep heavy oils are widely distributed in the northern Tarim Basin. These oils have been biodegraded to level 8 on the Peters and Moldowan (1993) scale, but were diluted with non-biodegraded fresh charge to varying degrees. Their mixed nature can be illustrated by the coexistence of intact n-alkanes, 25-norhopanes and 17-nortricyclic terpanes and obvious baseline ‘‘humps’’ in the saturated hydrocarbon fractions. Biomarkers and d13C values of n-alkanes suggest that these heavy oils originated from Middle–Upper Ordovician source rocks. The late charge was mainly derived from the same phase of generation, but without biodegradation influence, rather than from secondary generation and/or heavy oil thermal cracking. The hydrocarbon generation history, coupled with fluid inclusion analysis and K–Ar age measurement, indicate that heavy oils were formed in the late Permian. Oil charge and subsequent biodegradation occurred during the Late Hercynian orogenic event, which makes up the principle element in the evolution of the Ordovician petroleum system. Although the reservoir has been buried to >7000 m with temperatures >160 °C since the Pliocene, the heavy oils have not been cracked to any significant degree, due to the low geothermal gradient and the short duration time for oil cracking. No in-reservoir thermal cracking was supported by the similarities between the composition of the C15+ hydrocarbons in different reservoirs, low GORs and low concentrations of diamondoid hydrocarbons. Acknowledgements This research was supported by the China National Oil and Gas Project (Grant: 2008ZX05004-003). We would like to acknowledge the Tarim Oilfield Company Ltd for valuable assistance in sampling and data collection. Dr Kun He and Dr Youyu Zhang from the Research Institute of Petroleum Exploration and Development, PetroChina are acknowledged for the Gold tube pyrolysis experiments and the K–Ar age measurements. H.H. gratefully acknowledges the Program for Changjiang Scholars and Innovative Research Team in University (IRT0864) and the China National Natural Science Foundation (40973034) for partially supporting this work. Prof. Simon George, Dr. Bob Burruss and an anonymous reviewer are gratefully acknowledged for their constructive comments and English improvement that substantially improved the quality of this manuscript. Associate Editor – Simon George References

Conversion efficiency (%)

100 90 80 70 60 50 40 30 20 10 0 7000

7500

8000

8500

9000

9500

10000

Depth (m) Fig. 14. Curve of conversion rate for crude oil thermal cracking as a function of buried depth in the Tabei Uplift.

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