Geochemical Significance of Discovery in Cambrian Reservoirs at

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Geochemical significance of discovery in Cambrian reservoirs at well ZS1 of the Tarim Basin, NW China Guangyou Zhu, Haiping Huang, and Huitong Wang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/ef502345n • Publication Date (Web): 13 Feb 2015 Downloaded from http://pubs.acs.org on February 18, 2015

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Geochemical significance of discovery in Cambrian reservoirs at well ZS1 of the Tarim Basin, NW China

Guangyou Zhu,† Haiping Huang,*, ‡, § Huitong Wang

†

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

* Corresponding author. Tel.: +1-403-2208396; fax: +1-403-2840074; e-mail: [email protected] (H.P. Huang)

Abstract Gas condensate and natural gas samples from wells ZS1 and ZS1C in the Cambrian strata of the Tarim Basin, NW China are analyzed geochemically to assess thermal maturity, extent of oil cracking and secondary alteration. Hydrocarbons are derived from the Cambrian source rocks with gas condensate and solution gas reservoired in the Middle Cambrian Awatage Formation and dry gas in the Lower Cambrian Wusonggeer and Xiaoerbulake formations, where caverns from dolomitization and local fractures provide spaces for petroleum accumulation. Gas and gas condensate in the Middle Cambrian are mainly generated from kerogen thermal degradation at high maturity stage (condensate – wet gas window) rather than from in-reservoir thermal cracking of 1

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preexisted oils. Evaporative fractionation exerts certain impacts on gas condensates as evidenced by enrichment of light molecular weight alkanes, depletion of diamantanes in one condensate and low aromaticity. Condensate in well ZS1C is thermochemical sulfate reduction (TSR) alteration residual. The dry gas in the Lower Cambrian reservoirs is mainly derived from thermal degradation of kerogen with minor contribution from secondary cracking of preexisted oil. Variable H2S content in the Lower Cambrian reservoirs is primarily migrated from deep buried strata as in situ TSR alteration is on its initial stage. The Cambrian in the Tarim Basin is an unexplored zone. Condensate without extensive oil cracking in the Middle Cambrian and TSR altered condensate in the Lower Cambrian discovered at ZS1 structure suggest a likelihood of downdip oil. Geologic framework of the Tarim Basin also favors for the preservation of liquid hydrocarbons in ultra-deep strata as it reaches its maximum burial depth in last 5 Ma. Short heating time requires much higher temperature than current reservoir temperature for completion of oil thermal cracking. Keywords: Gas Condensate; Thermal Cracking; Evaporative Fractionation; Deep Exploration Potential; Tarim Basin

1. Introduction There are two pathways to form thermogenic gas in sedimentary basins. Primary thermogenic gas is derived from thermal cracking of sedimentary organic matter during progressive catagenesis of kerogen and bitumen, while secondary thermogenic gas is from thermal cracking of oil at high reservoir temperatures. Similarly, gas condensate in a reservoir can result either from high maturity source rock or thermal cracking of previous generated oil with increasing temperature.1-4 Molecular and isotopic compositions of gas and gas condensate have widely been used to differentiate their genetic origins.5-10 However, original compositions of natural gas and gas condensate can be 2


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destroyed by various post-accumulation alteration processes. The main effects include biodegradation, oil thermal cracking, evaporative fractionation, phase separation, gas washing, multiple charges and mixing, and thermochemical sulfate reduction (TSR). Thermal cracking, the breakdown of heavy hydrocarbons to form gas, condensate and a residual pyrobitumen takes place within reservoirs at temperatures > 150 °C, 2, 11-12 whereas the TSR process oxidizes the hydrocarbons with sulfate, producing H2S, CO2 and a residual pyrobitumen at the same temperature range as thermal cracking but mainly in carbonate reservoirs associated with evaporite-bearing successions.13-16 Evaporative fractionation is hydrocarbon fractionation caused by a single gas charge into an oil accumulation followed by chemical equilibration with the oil and subsequent migration and condensation of the vapor phase, leaving behind residual oil.17-18 Gas washing refers a similar process as evaporative fractionation where gas influx into an oil field, stripping its soluble components and condensing liquid in a shallower trap.19-20 Phase separation or segregation can induce the separation of a single-phase system due to reduction in pressure and temperature caused by uplift, seal failure or faulting.21 Biodegradation is mainly occurs at shallow reservoir where temperature is below 80 °C. Multiple charges and mixing are common in sedimentary basin when source rocks are experienced complicated uplift and subsidence cycles or several source rock horizons are available. 9, 22-23 In the case of the Paleozoic petroleum systems in cratonic region of the Tarim Basin, all above processes are operative in varying degree at different locations.16, 24-35 Recognizing genetic origin and secondary alteration processes operative in the field is important because they impact oil quality, remaining potential assessment in deep strata, and near-field exploration.36 However, the task can be difficult because these processes and their effects are interrelated. Recently, well ZS1 located at 3


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Tazhong Uplift has successfully been drilled in the Cambrian dolomite reservoirs at depth about 7,000 m. It is the first commercial production well from the Cambrian strata in the Tarim Basin. Gas and gas condensate are most likely derived from Cambrian source rock as the dolomite reservoir is beneath thick anhydrite and salt succession. Whether the formation of ZS1 gas and gas condensate is purely the result of secondary thermal cracking of oil as generally expected, or primary cracking of kerogen, even retrograde condensation (through evaporative fractionation and/or phase separation) deserves thorough assessment because this may have implications for the existence of a deeper oil leg. The present paper uses carbon isotopic and chemical compositions of gas components and comprehensive two-dimensional gas chromatography-time of flight mass spectrometry (GC × GC-TOFMS) and two-dimensional gas chromatography-flame ionization detector (GC × GC-FID) of liquid hydrocarbons to investigate gas and gas condensate origins, maturity, degree of thermal cracking and other secondary alterations in well ZS1. The objective of the study is to improve prediction of and reduce uncertainty for further exploration in deep strata of the Tarim Basin.

2. Geological Background Tarim Basin is the largest petroliferous basin in China with Tazhong and Tabei uplifts as main production units in the cratonic region. Well ZS1 (and ZS1C, a deviation well due to poor wellbore quality of well ZS1) is located at east section of the Tazhong Uplift, which is a long developed inherited structural high (Fig. 1). Tazhong Uplift, with an area of approximately 30,000 km2, is bordered by Manjiaer Depression to the north, Tangguzibasi Depression to the south, Bachu uplift to the west, and Tadong low uplift to the east. The Cambrian section in the Tarim Basin is composed of tidal platforms, platform-marginal marls, 4


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mudstones, carbonates and evaporite rocks.37-38 Well ZS1 penetrates Cambrian strata at depth from 5257.5 – 6810.5 m with a thickness of 1553.0 m and well ZS1C reaches Precambrian strata with completion depth at 6944 m. The Cambrian strata can be divided into Lower Cambrian Xiaoerbulake Formation (Є1x) and Wusonggeer Formation (Є1w), Middle Cambrian Shayilike Formation (Є2s) and Awatage Formation (Є2a), and Upper Cambrian Qiulitage Formation (Є3q) (Fig. 2). The overlying Ordovician section is primarily composed of platform dolomite and marginal slope-shelf carbonate sediments. The upper Paleozoic marine and continental transitional sediments are accumulated after deposition of the Silurian and Devonian fine-grained red beds and sandstones. Well ZS1 is the first commercial oil/gas production well from the Lower and Middle Cambrian although numerous studies have acknowledged that Cambrian strata are one of the most important source rocks in the Tarim Basin.25, 29, 39-41 Two tests have been performed in the Middle Cambrian Awatage Formation (Є2a). The first one at interval 6425 – 6496 m recovers 3.67 m3 condensate and 2,611 m3gas and the second one at depth 6439 – 6458 m after fracturing recovers 6.24 m3 condensate and 2,718 m3 gas within 12 h testing. Testing in Lower Cambrian Wusonggeer and Xiaoerbulake formations (Є1x) performed at depth 6598 – 6785 m obtains daily gas production of 30,322 m3 without condensate (Fig. 2). Well ZS1C has daily production of 158,545 m3 gas from the Lower Cambrian Xiaoerbulake Formation at depth 6861 – 6944 m. Small amount of condensate have been recovered during the testing but no commercial condensate has been encountered during production. Interbedded dolomites are well developed in the Middle and Lower Cambrian which can serve as reservoir while salt and anhydrite developed in the Middle Cambrian can serve as regional cap rocks. 5


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The Middle Cambrian reservoirs are dominated by dissolution pores and vugs with average porosity of 4.5% and permeability less than 0.1 md, while the Lower Cambrian reservoirs contain more fractures with porosities in the range of 1.7 - 12.6% and permeability greater than 1.0 md. Two reservoirs are well separated by thick salt and anhydrite and no source rocks have been encountered in this well.

3. Experimental Methods Gas condensates were directly analyzed by comprehensive GC × GC - TOFMS and GC × GC-FID without any pre-treatment. The GC × GC–TOFMS system was a Pegasus IV model made by the LECO Corporation. The GC × GC system was composed of an Agilent 7890 GC coupled to a hydrogen flame ionization detector (FID) and a liquid-nitrogen-cooled pulse jet modulator. The first column on GC × GC was 50 m × 0.2 mm × 0.5 µm (from Petro) and the second column was 3 m × 0.1 mm × 0.1 µm (DB-17HT). The temperature program used for the first column was: 0.2 min at 35 °C; increased to 210 °C at a rate of 1.5 °C/min and held for 0.2 min; then increased to 300 °C at the rate of 2 °C/min and held for 20 min. The temperature program used for the second column was the same as that used for the first one but the temperature was 5 °C higher. The modulator temperature was 45 °C higher than for the first column. The inlet temperature was set at 300 °C, the inlet mode was split injection with split ratio of 700:1 and sample volume of 0.5 µL. Helium was the carrier gas with a flow rate of 1.5 ml/min. The modulation cycle was 10 s. The TOFMS was performed under the following conditions: ionizing voltage ∼70 eV, monitoring voltage 1600 V, rate of data acquisition 100 spectra/s, mass scanning range 40 - 520 µm, and dwell time 9 min. The temperatures of the transfer line and the ion source were 300 °C and 240 °C, respectively. The flow rates of the carrier gas, hydrogen and air for FID were 50, 40, and 450 mL/min, respectively. The 6


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detector temperature was 320 °C with the acquisition rate of 200 spectra/s. All the data were processed with the ChromaTOF software. Normalized peak area was used for quantification of compound groups and D16-adamantane was used as an internal standard for quantification of diamondoid hydrocarbons. The chemical composition of gas samples was determined using an Agilent 6890N gas chromatograph (GC) equipped with a flame ionization detector and a thermal conductivity detector. Individual hydrocarbon gas components from methane to pentanes (C1–C5) were separated using a capillary column (PLOT Al2O3 50 m × 0.53 mm). The GC oven temperature was initially set at 30 °C for 10 min, and then ramped to the maximum temperature of 180 °C at a rate of 10°C /min where it was held for 20 min. Stable carbon isotope (δ13C) ratios were determined on a Finnigan Mat Delta S mass spectrometer interfaced with a HP 5890II gas chromatograph. Gas components were separated on the gas chromatograph in a stream of helium, converted into CO2 in a combustion interface and then introduced into the mass spectrometer. Individual hydrocarbon gas components (C1–C5) were initially separated using a fused silica capillary column (PLOT Q 30 m × 0.32 mm). The GC oven temperature was ramped from 35° to 80 °C at 8°C /min, then to 260 °C at 5°C /min, and the oven was maintained its final temperature for 10 min. Gas samples were analyzed in triplicate. Stable carbon isotopic values were reported in the customary δ notation in per mil (‰) relative to PDB. Measurement precision was estimated to be ± 0.3‰ for δ13C.

4. Results 4.1. Physical properties of gas condensates Two gas condensate samples obtained at depth of 6425 - 6496 m and 6439 - 6458 m in well ZS1 7


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show very similar physical properties (Table 1). The average API gravities are 47.2° and 45.5° at 20 °C and viscosities are 1.7 – 1.8 mPa.s at 50 °C. Gas condensate ratios (GCR) are 435 and 711 m3/m3, respectively. The condensates have low pour point (< -20 °C), low sulfur content (< 0.2%), low resin and asphaltene contents (< 2.0%) and moderately low wax content (4.5–8.5%). ZS1C condensate is very different from that in well ZS1 with API gravity of 20.7° at 20 °C and GCR as high as 25,195 m3/m3.

4.2. Molecular and isotopic compositions of condensates Molecular compositions of condensates are quantitatively analyzed by GC × GC-TOFMS and GC × GC-FID. On GC × GC, the x-axis represents retention time on the first dimension column where components are primarily separated based on the volatility with molecular weight increasing from left to right. The y-axis represents retention time on the second dimension column where separation is based on polarity. Most non-polar components are situated on the bottom of the chromatographic plane and most polar ones are situated on the top. Compounds from bottom to top on the y-axis are n-alkanes, branched alkanes, single- and multi-ring cycloalkanes, and one-, two- and three-ring aromatic hydrocarbons, and heterocyclic non-hydrocarbons. Homologue components are collected in specific retention time area of the contour plot based on 2D separations (Fig. 3). Using ChromaTOF software and quantitative analysis described by Wang et al., 42 a total of 4341 compounds in 6425 - 6496 m condensate and 3720 compounds in the 6439 - 6458 m sample have similarity above 900 with the National Institute of Standards and Technology software library. These compounds are classified into ten groups and the proportion of each group is quantified (Fig. 4). Very similar hydrocarbon distributions are observed from two condensates. Saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbons are 91.30%, 8.63%, 0.06%, and 8


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91.65%, 7.62%, 0.43%, respectively. Traditional chromatographic separation derives similar but less accurate results with saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbons in the range of 92.3–95.1%, 2.6–5.6% and 0–2.3%, respectively. 43 n-Alkanes are one of the most abundant compound class, accounting for about 30% of the condensate (Fig. 4). The GC × GC chromatograms show carbon distribution ranging from n-C3 to n-C33 with the major peak at n-C9. Its lower carbon number homologues (< n-C19) obviously predominate over the whole n-alkane series, and the concentration of higher homologues decreases rapidly with increasing carbon numbers. There is no odd-over-even carbon number predominance (Fig. 5a). Such kind of n-alkane profile indicates very high maturity, corresponding to condensate or wet gas zone. Branched alkanes comprise the highest abundant compound group, which accounts for roughly 35% of the condensate (Fig. 4). There are numerous compounds in this class with only a few of them having known geochemical meaning. Isoprenoid alkanes especially pristane and phytane are the most common branched alkanes, which are derived from chlorophylls of phototrophs, from archaebacteria, from methanogens, or from tocopherols.44 The ratios of pristane to n-C17 and phytane to n-C18 in the studied condensates are below 0.3. Relatively low isoprenoids in the ZS1 condensates indicates either limited contribution from above mentioned sources or very high maturity. The pristane/phytane (Pr/Ph) ratio has been applied widely as a paleoenvironmental redox, salinity, and terrigenous input indicator. 45 The Pr/Ph ratios for two condensates are 1.22 and 1.23, respectively, slightly higher than these in the Ordovician reservoir oils. 43 According to Didyk et al. 45 low Pr/Ph ratios (< 1.0) would indicate a source rock deposited under highly reducing conditions. Pr/Ph ratios in ZS1 condensates suggest a normal marine depositional environment. For all branched alkanes, the summed isomers of each carbon number show very similar distribution 9


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pattern and the relative intensity which mirrors that of n-alkanes (Fig. 5b). In cyclic alkane class, monocyclic alkanes are the richest one, which is about 25% of condensate (Fig. 4). Carbon numbers of substitution in the alkylated cyclohexane and cyclopentane chains are up to C26. Methylcyclohexane (C7) is the dominant component in cyclic alkane series (Fig. 5c). A striking feature of the alkylcyclohexane distributions is how closely they resemble that of the n-alkanes in the same sample. This similarity possibly suggests that alkylcyclohexanes probably have the same biogenic precursors as the n-alkanes, possibly from the cyclisation of straight chain algal fatty acids, by mechanisms that involve decarboxylation. The summed polycyclic alkanes are less than 5% of condensate (Fig. 4) and the samples show maxima at C10 and C11 (Fig. 5d). In aromatic hydrocarbon classes, monoaromatic hydrocarbons are the most abundant compound class which accounts for 6-7% of condensate (Fig. 4) with xylenes (C8) as dominated compounds (Fig. 5e). The second richest aromatic compound class is 1,2,3,4-tetrahydronaphthalene (tetralin) series which is about 1% of condensate (Fig. 4). Up to C6 substitutes occur in this compound series with methyl-tetralin (C11) as the most abundant component (Fig. 5f). Diaromatic (two rings) hydrocarbons are less than 1% of condensate (Fig. 4), which are dominated by naphthalene series (Fig. 5g). Triaromatic hydrocarbons (phenanthrene series), 1,2,3,4-tetrahydro-phenanthrene series and others occur in trace amount (Figs. 4, 5h-j). Diamondoids identification by GC × GC/TOFMS has described in our previous study.46 Alkyladamantanes are examined using m/z 135, 136, 149, 163, and 177 ions and alkyldiamantanes are examined using m/z 187, 188, and 201 ions (Fig. 6). The quantitative results of diamondoid compounds in the two samples are obtained by using GC × GC-FID (Table 2). Condensate obtained from 6425-6496 m contains higher diamondoids than that from 6439-6458 m. Such difference is 10


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most likely caused by reservoir heterogeneity and varying degree of late charge and mixing. Carbon isotopic value in an oil is dependent upon the value of the kerogen in the source rock from which it is derived. The value of kerogen depends, in turn, on the types of organisms preserved and the values of its substrate. Therefore, carbon isotopic value is widely used as oil-source correlation parameter. In the case of the Palaeozoic oils in the Tarim Basin, majority oils have their δ13C values of in the range of -31.0‰ to -33.0‰ with a few exceptions. Bulk isotopic compositions of the studied samples and a few representative samples from literature are plotted in Fig. 7. The δ13C of whole condensate of ZS1 is -32.8‰, while that of ZS1C is -30.0‰. Bulk isotopic compositions of saturated hydrocarbons, aromatic hydrocarbons, resins and asphaltenes in ZS1 condensate are -33.4‰, -30.9‰, -32.3‰ and -29.5‰, respectively, whereas bulk isotopic compositions of saturated hydrocarbons, aromatic hydrocarbons and resins in ZS1C condensate are -30.9‰, -30.5 and -29.4‰, respectively. Oil from well TD2 oil has the heaviest δ13C value, which is reservoired in the Cambrian strata. It has been regarded as standardized end member for the Cambrian sourced oil in all previous studies. The most 13C depleted oil is automatically selected as the O2-3 sourced end member. 29, 30, 43, 47 ZS1 condensate from the Middle Cambrian is isotopically light, which is very similar to majority oils discovered from the Tabei and Tazhong uplifts in the Ordovician and younger reservoirs, whereas ZS1C condensate from the Lower Cambrian is isotopically heavy and close to oils in wells of TD2 and TZ62(S). Li et al. 43 noted more dramatic differences from isotopic values of individual n-alkanes and suggested that condensate in well ZS1 is derived from the O2-3 source rocks, while condensate in well ZS1C is derived from the Є-O1 source rocks.

4.3. Gas chemical and isotopic compositions Methane is the dominant component in recovered gas samples from wells ZS1 and ZS1C, however, 11


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their wet gas (C2+) contents differ significantly. The Middle Cambrian sample is a wet gas with dryness coefficient (C1/C1+) of 0.75–0.78, while the Lower Cambrian samples are dry gas with dryness coefficients of 0.99 (Table 3). The non-hydrocarbon gas contents are different as well, especially the carbon dioxide and hydrogen sulfide. The deep sample is sour gas with hydrogen sulfide of 3.3–4.0% at well ZS1 and 8.3% at well ZS1C, while the shallow sample is almost hydrogen sulfide free (Table 3). Higher nitrogen and carbon dioxide contents also occur in the Lower Cambrian gases (Table 3). Gases within the Lower Cambrian are not homogenized even though they have the same dryness. ZS1C gas contains much less hydrocarbon components than that in ZS1 gas. Relative density of ZS1 gas is 0.807 kg/m3 while that in well ZS1C gas is 0.865 kg/m3. Paralleling the gas compositional data, the stable carbon isotope ratios (δ13C) of the gas components differs from each other as well. Gas isotopic compositions of the studied samples and a few representative samples from literature are plotted in Fig. 8. According to Chung et al.’s 5 proposal, if isotope values plot in a straight line, the gas sample is pristine, but if isotope values do not lie on a straight line, the gas contains mixed composition or surfers from secondary alteration. The Middle Cambrian gas from well ZS1 has isotopically depleted methane but its methane isotopic value is much heavier than typical oil associated gas in well ZG13. ZS1 gas is also characterized by slightly isotopically depleted propane and isotopically enriched butane. The isotope values do not fit a straight line on natural gas plot, suggesting mixed compositions or generation pathways. The Lower Cambrian gases from ZS1 and ZS1C have their isotopic composition close to a straight line, suggesting a pristine gas mainly derived from kerogen thermal degradation without significant secondary alteration. Gas from well TZ83 has suffered extensive TSR alteration and its 12


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hydrocarbon components show systematically enriched isotopic values. 30, 40, 43

5. Discussion 5.1. Oil-source correlation Biomarkers indicative of the source rocks for oils in the Tarim Basin have been comprehensively investigated. 29, 30, 40, 43, 48 Detailed oil-source correlation for well ZS1 has been performed by Li et al. 43 based on biomarker and carbon isotopic compositions. The Middle Cambrian condensate from well ZS1 (6426-6497 m) contains no Є-O1 diagnostic biomarkers and a relatively low content of C28 regular sterane. This condensate is also characterized by depleted 13C in individual n-alkanes and is primarily sourced from the O2-3 source rocks. Although no reliable biomarkers can be detected from ZS1C condensate, the enriched 13C in individual n-alkanes indicate close affinity to the Є-O1 source rocks. 43 We doubt this conclusion simply due to the previous selected end member for the Є-O1 sourced oils cannot represent genuine Є-O1 source rock systems. The most diagnostic biomarkers are detected from TD2 oil within the Cambrian strata. This oil is most likely derived from the Cambrian source rocks, but by no mean can represent the Cambrian end member. Only a few tens litres of oil has been recovered from this well during testing. It is an ultra-heavy oil with API gravity of 7°. This oil has experienced abnormally high temperature influence from hydrothermal fluid as evidenced by the presence of abundant pyrobitumen with bitumen reflectance ranging from 2.7 to 5.0% and coeval aqueous brine inclusions homogenization temperature of 160 – 220 °C.49 These so-called diagnostic biomarkers and unusually heavy carbon isotopic value most likely reflect abnormal thermal alteration effect rather than Є-O1 sourced signatures. Similarly, TZ62 oil in the Silurian sandstone at depth 4052.88-4073.88 m has suffered moderate to severe biodegradation influence 13


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and severe evaporative fractionation.50 It is probably derived from the Є-O1 source rocks but not a proper end member. Meanwhile, some diagnostic biomarkers for the Є-O1 source origins have been detected in the Upper Ordovician source rocks with very high concentrations at Keping outcrop, indicating that they are not age-specific. Biomarkers extracted from the O2-3 source rocks are most likely similar to those of the Є-O1 source rocks.51 The discovery of well ZS1 condensate in the Middle Cambrian reservoirs provides a very good end member of the Cambrian sourced oil. In cratonic region of the Tarim Basin the most 13C enriched oil has been selected as an end member for Є-O1 source rocks because TD2 oil is the isotopically heaviest, while the isotopically most depleted oil is automatically selected to represent the end-member of the O2-3 source rocks. 29, 30, 43 This is the source of so many years’ confusion. Firstly, the current knowledge of isotopic compositions in the Tarim oils is completely conflict to global carbon isotopic compositional variation. The Cambrian sourced oils have an average δ13C value of -34.8‰, while oil derived from the Ordovician is averaged at -29.2‰.52 The overall trend of enrichment in 13C with decreasing age appears to be independent of source rock facies type especially from the Cambrian to the Ordovician. The Steptoean positive carbon isotope excursion marks a global oceanographic event.53-54 Secondly, although some kerogens from the Є-O1 are isotopically enriched (possibly caused by unusually high thermal stress), isotopically depleted kerogens from O2-3 source rocks have never been recorded to support such kind of correlation. However, isotopically depleted kerogens with δ13C values around -35.0‰ have been documented from the Cambrian source rocks at the Keping Uplift.43 Thirdly, isotopic values of oils show a depletion trend with increasing burial depth. Most oils with burial depth greater than 6,000 m have relatively low δ13C values of n-alkanes,43 implying that Cambrian sourced oils are isotopically lighter than the Ordovician ones. Most importantly, the widely 14


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recognized rule that thermal maturity do not substantially alter carbon isotope values of oil through maturation with 13C-enrichment in the order of 2-3‰55 may be true for large oil pools but not for small quantity of isolated non-commercial oil accumulation. Assuming that the same amount of 12

C-rich carbon are removed during thermal maturation, the change in δ13C of residual oil in isolated

oil pad may be significantly larger than that in large oil pool. TD2 oil and ZS1C condensate are typical residual accumulation after severe secondary alteration processes. Both samples are largely depleted in n-alkanes either due to thermal cracking or TSR alteration. Unusually heavy carbon isotopic compositions in TD2 oil and ZS1C condensate reflect secondary alteration processes rather than source input signatures. Although no detailed oil-source correlation can be performed at the present study due to limited sample availability, deleted δ13C value in ZS1 condensate is a defined characteristic of the Cambrian source origin and can serve as an adequate oil-source correlation parameter. Majority oils discovered in the Tazhong and Tabei uplifts have similar isotopic compositions as ZS1 condensates suggesting that most oils in the cratonic region of the Tarim Basin are actually derived from the Є-O1 source rocks.

5.2. Thermal maturity and degree of cracking of oil in condensate Only trace amount of biomarkers can be detected from ZS1 condensates, which do not permit robust maturity evaluation by routine biomarker parameters. Diamondoids are thought to form by the alteration of some polycyclic hydrocarbons under thermal stress with strong Lewis acids acting as catalysts. 56 Variations in the thermal stability of methyl-substituted diamondoids have led to the use of certain isomer ratios as maturity parameters for crude oils and source rocks, especially at high and overmature stages of hydrocarbon generation.57 Since 1-methyladamantane (1-MA) is 15


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thermally more stable than 2-MA, methyladamantane index (MAI) is defined as ratio of 1-MA to the sum of 1-MA + 2-MA. Similarly, the methyldiamantane index (MDI) defined as ratio of 4-MD to the sum of 1-MD + 3-MD + 4-MD (where 4-MD is thermally more stable than 1- and 3-MDs). The MAI for 6425 - 6496 m condensate is 0.72, which is very similar to most normal oils in the Tazhong and Tabei Uplift.48 The MAI for 6439 - 6458 m condensate has much higher MAI value of 0.81, which is close to typical condensates like TZ45 and YN2.48 Since no diamantanes can be detected from 6439 - 6458 m condensate, MDI for 6425 - 6496 m condensate is 0.55, which is close to TZ6 and LN10 condensates.48 Slightly higher MDI value in 6425 - 6496 m condensate than majority oils in the Tazhong and Tabei uplifts may result from lower diamondoids concentration in this condensate. Using empirical correlation established by Chen et al. 57 in the Tarim Basin, the estimated thermal maturity corresponding to vitrinite reflectance is around 1.5%, implying that condensates in well ZS1 are formed at high maturity stage (condensate–wet-gas window). Another well-established maturity proxy is the methylphenanthrene index [MPI1 = 1.5 × (2MP + 3-MP)/(P + 1MP + 9MP)] as β-isomers (2MP and 3MP) are thermodynamically more stable than α-isomers (1MP and 9MP), which allows calculation of equivalent vitrinite reflectance.58 Two Є2a condensates form well ZS1 have their MPI1 values of 1.61 and 1.63, respectively, while majority other oils in the Tazhong Uplift have their MPI1 values less than 1.0, 48 suggesting that ZS1 condensates are derived from very high maturity stage. The relative abundance of diamondoids can also be used to identify the occurrence and estimate the extent of oil destruction and the oil deadline in a particular basin. The commonly used method derives from the relationship between 4- and 3-MD and C29 ααα20R sterane concentrations.11 Diamondoids display a nearly constant concentration in oil throughout the entire oil window 16


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maturity range. When oil cracking occurs, steranes almost disappear while diamondoid concentrations become increasingly elevated with the extent of oil cracking.11 The diamondoid baseline (summed concentration of 4- and 3-MDs) in the Paleozoic strata of the Tarim Basin is around 20 µg/g.20 The highest concentration of 4- and 3-MDs in the Tabei condensates is 213 µg/g.20 For a typical thermal cracked condensate in the Tazhong Uplift, taking TZ83 as an example, concentration of 3- + 4-MDs reaches 181 µg/g in condensate.46 Another oil cracked condensate in well YN2 at Tadong area has the concentration of 3- and 4-MDs about 250 µg/g.27 Condensate in 6425 - 6496 m has concentration of 4- and 3-MDs < 10 µg/g and condensate in 6439 - 6458 m has no detectable 4- and 3-MDs, indicating condensates in well ZS1 mainly derived from kerogen cracking at high maturity stage without significant contribution from preexisted oil cracking.

5.3. Gas origins Preliminary screening of the hydrocarbon composition of the studied gases using gas dryness coefficient allows the identification of two gas groups. Thermal maturity is the primary control over gas chemistry, where the Middle Cambrian gas is less mature than the Lower Cambrian one. The wet gas from the Middle Cambrian is associated with oil while the dry gas can be derived from either primary or secondary cracking. The Є1x gases form ZS1 and ZS1C plotted on Chung et al.5 natural gas plot show a straight line, suggesting pristine gas from kerogen thermal degradation without significant secondary alteration (Fig. 8). Previous studies illustrated that gases from oil cracking usually have larger differences between ethane and propane carbon isotopes, but smaller ratios of ethane to propane by volume than gases from kerogen cracking at similar maturity levels.8, 10, 59 Although no systematic data are available in the present study, small carbon isotopic difference between ethane and propane and high ratio of 17


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ethane to propane by volume do not support secondary cracking as dominant source of gas in the Lower Cambrian reservoirs. However, to differentiate primary cracking of kerogen from secondary cracking of oil is always a challenge as the processes are inevitably overlapped. If isotopic value of the source and resulted gas components are taken into account, thermal cracking of oil has occurred in the Lower Cambrian reservoir. Estimation of δ13C values of original kerogen for the gaseous hydrocarbons is out the scope of present study. Based on average isotopic value of oils from the cratonic region of the Tarim Basin, kerogen of the Lower Cambrian has carbon isotopic value around -33‰. A plot of “δ13C methane-δ13C source” against C1/ΣC1–5 shows varying degrees of thermal cracking. The Middle Cambrian sample is plotted in oil associated gas region, representing gases that are cogenerated with oil at relatively lower maturity. The Lower Cambrian samples are plotted in moderate to extensive cracking region, indicating secondary cracking of previously formed oil has initiated (Fig. 9). Unusually high dryness is presumably followed by some secondary alterations.

5.4. Secondary alteration In addition to thermal generation, gas condensates can be the result of evaporative fractionation. The mechanism of such process may be ascertained by inspecting the paraffinicity (F: n-heptane/methylcyclohexane) and aromaticity (B: toluene/n-heptane) of both oils and gas condensates.17-18 The evaporatively fractionated condensate would show increased paraffinicity and decreased aromaticity compared to the resulting residual oil that is depleted in light n-alkanes. However, Thompson's17-18 B-F diagram is more properly to differentiate evaporatively fractionated residual oil from pristine oil but less powerful to recognize evaporatively derived condensate. Our studied condensates from well ZS1 have their toluene/n-heptane (B) < 0.5, and 18


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n-heptane/methylcyclohexane (F) < 1.0, which is plotted in the pristine oil region on Thompson's17-18 B-F diagram. Very low toluene/n-heptane ratios may conform to fractionation effect. The dominance of low molecular weighted n-alkanes, branched alkanes and cyclic alkanes in ZS1 condensates suggests they could be the migrated portion of down-dip oil via evaporative migration processes. The lack of diamantanes in one condensate provides another clue of fractionation effect of light ends with respect to the less volatile, heavier ends. Although well ZS1 may not contain a typical retrograde condensate formed by phase separation, evaporative fractionation effects cannot be precluded, which renders deeper oil prospects likely. If so, this could have significant implications from the petroleum exploration in the Tarim Basin. In contrast to the Є2a condensates from well ZS1, the Є1x condensate from well ZS1C has completely different bulk and molecular compositions. The saturated hydrocarbons only account 57.3% of ZS1C condensate and total ion chromatogram (TIC) of the saturated hydrocarbon fraction shows an obvious hump of unresolved complex mixture.43 The unusually high Pr/Ph ratio of 3.79 documented by Li et al.43 is inconsistent with the Cambrian origin. Li et al.43 interpret this as result of extensive thermal cracking of crude oil. However, such phenomena only occur in cracked residual rather than in derived condensate. Coupled with high H2S content in associated gas, this condensate can be regarded as TSR alteration residual. Unusually high content of dibenzothiophenes (DBTs) in ZS1C condensate further proves TSR alteration. DBTs are dominated on the TIC of the aromatic hydrocarbon fraction, accounting for 87.5% of total quantified aromatic compounds. 43 However, in non-TSR altered ZS1 condensates, DBTs contents are less than 20% of total quantified aromatic compounds. TSR is one of major risks in deep carbonate reservoir exploration, which can destroy oil reservoir 19


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through oxidation of hydrocarbons and reduction of sulfate to form H2S and CO2. The effects of TSR in the Tarim Basin have been thoroughly investigated by previous studies. 25, 30, 40, 60-61 The reaction is generally assumed occurring in the Cambrian strata since evaporite sequence consist mainly of salt and anhydrite, together with dolomite and mudstone interbeds formed in lagoonal and subtidal environments is well developed in the Middle Cambrian and the temperature is high enough for TSR at depth greater than 7,000 m.25, 40, 62 The sour gas is probably typical of discoveries that can be expected in this geochemical environment. Unusually high dryness of gas from the Lower Cambrian can be partially result from TSR process as wet gaseous hydrocarbons are more vulnerable to TSR attack than methane.13-15 However, TSR seems does not affect hydrocarbon gas compositions significantly in the studied gas samples if isotopic composition is considered. In general, when TSR is proceeded, gases become progressively enriched in 13C as TSR kinetically favors the removal of the 12C.13-16, 63 Low concentration of the wet gaseous components in the Lower Cambrian gas can be result of TSR and high thermal maturity. However, pristine gas carbon isotopic compositions in the Lower Cambrian gases (Table 3) suggest that TSR reaction is insignificant in the current reservoir and H2S is mainly migrated from deeper strata. If bulk isotopic compositions of gas condensates are considered, obvious 13C enrichment in whole condensate and individual fractions in ZS1C condensate as compared to these from well ZS1 reflects possible TSR involvement in liquid hydrocarbons. Low TSR effect in current reservoirs is supported by isotopic value of carbon dioxide. CO2 in geological environment has various origins but each origin has distinctive carbon isotopic signatures. If the CO2 is derived from thermal decomposition of carbonates, the isotope values of CO2 are in the range 0 ± 4‰, that from mantle varies ∼-4 to -5‰. If the CO2 is derived from organic 20


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matter, the isotope values of CO2 are generally heavier than ethane by about 15‰.64 If the CO2 from a direct oxidation of the hydrocarbons by TSR, the isotope values of CO2 are generally less than -20‰.25 Very depleted 13C value in CO2 relative to the oxidized hydrocarbons in the Lower Cambrian reservoirs suggests a mixture of organic originated CO2 with CO2 formed at initial stage of TSR, which is 13C depleted and leaked out from reaction site. High CO2 content in the studied gases suggests CO2 augmentation without significant water-rock-gas equilibration.

5.5. Implication in deep exploration potential The Є-O1 source rocks occur throughout most of the cratonic region of the Tarim Basin with TOC in the range of 1.2–2.3% and they are currently over matured (> 2.0% Ro). The O2-3 source rocks have relatively low TOC (averaged below 0.5%) and limited thickness, and they are matured with respect to oil generation (Ro 0.8–1.5%). Previous studies regarded O2-3 source rocks as main contributor for oil accumulation in the cratonic region is mainly due to maturity consideration as the Є-O1 source rocks may be exhausted during the late Hercynian Orogeny (late Permian). However, the discovery of well ZS1 in the Cambrian reservoirs recalls reexamining exploration potential in deep strata. An assessment of hydrocarbon origins is critical, which can minimize risk associated with downdip potential and drilling additional wells as different geological-geochemical processes result in different vertical and lateral hydrocarbon distributions. Our results suggest thermal cracking of preexisted oil is not as extensive as imagined. The Middle Cambrian condensates are mainly derived from thermal degradation of kerogen, which have experienced certain influence from evaporative fractionation. H2S in current Cambrian reservoir is largely migrated from deeper strata where TSR mainly alters liquid hydrocarbons as evidenced by the occurrence of pristine gas and TSR altered residual condensate. This implies liquid hydrocarbons may emerge in the deeper 21


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Cambrian strata. Oil preserved for over 250 million years has been illustrated in our previous studies.33-35, 65 Possible preservation of liquid hydrocarbons in ultra-deep strata is derived from two aspect of considerations. Generally, crude oils are thermally more stable than traditionally thought where oils are destroyed at temperatures of 150 - 175°C.1,3 Numerous studies have illustrated that thermal cracking is gone to completion at far higher temperatures.12, 66-70 In the Tabei Uplift, heavy oils are well preserved (without cracking) at depth about 7,000 m with reservoir temperature about 160 °C.65 Particularly in the Tarim Basin, low geothermal gradient and short heating time favors for liquid oil preservation in deep strata. The measured reservoir temperature in well ZS1 is 163 °C at depth 6902 m, which derives the geothermal gradient about 22.5 °C/1000 m. The burial history illustrates that it has reached its maximum burial depth within the last 5 Myr (Fig. 10). Recent rapid burial requires a high temperature for crude oil cracking due to time-temperature compensation effect. Kinetic calculation based on thermal simulation experiments suggested that crude oil cracking to methane with conversion rate of 50% at 180 °C takes 52.8 Myr.65 Extensive crude oil cracking may occur currently at 9,000 - 9,500 m deep where temperature is about 210 - 220 °C. In addition to gas perspective, liquid hydrocarbons may be preserved above the dead line depth down to 9,000 m. Reservoir quality can be one risk in ultra-deep strata, however, dolomites are well developed in the Cambrian succession mainly in the Middle Cambrian Awatage Formation and Lower Cambrian Wusonggeer and Xiaoerbulake formations. Dissolution in the Middle Cambrian and fractures in the Lower Cambrian can provide reservoir spaces. Affected by faulting, hydrothermal karst processes, dolomitization and early oil accumulation, carbonate rocks have good reservoir properties even at depth of 8,000 m.71 22


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6. Conclusion The hydrocarbons discovered in well ZS1 of the Tarim Basin are derived from the Cambrian source rocks and reservoired in the Cambrian dolomites. Gas condensate and solution gas from the Middle Cambrian are derived from kerogen thermal degradation at high maturity stage rather than the result of in-reservoir thermal cracking of preexisted oils, while gas condensate from the Lower Cambrian is TSR alteration residual of oil. Dry gas from the Lower Cambrian is pristine gas mainly originated from thermal cracking of kerogen with minor contribution from secondary cracking of preexisted oils. The complexity of hydrocarbon compositions is a result of multiple charges and mixing together with evaporative fractionation and TSR alteration. The presence of primary thermogenic condensate in the Middle Cambrian, pristine gas and TSR altered condensate in the Lower Cambrian suggests the potential for downdip oil/condensate accumulations remains high. New oil opportunities may emerge in ultra-deep Cambrian reservoir (> 7,000 m) is supported by basin geological framework. Recent rapid burial in the Tarim Basin requires a high temperature for crude oil cracking due to time-temperature compensation effect.

Acknowledgements We acknowledge the PetroChina Tarim Oilfield Company for data contribution and sample collection. This work is financially supported by PetroChina Science and technology research project-Study on New Fields, New Theories and New Approaches for Oil and Gas Exploration (2008A-0609), the CNPC International cooperation project (Grant No: 2011A-0203-01) and China National Natural Science Foundation (Grant Number: 41273062). Dr. Ryuzo Tanaka and two anonymous reviewers are gratefully acknowledged for their constructive comments that substantially improved the quality of this manuscript. 23


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Figure Caption Fig. 1. (a) Structural map of the top Cambrian in the Tazhong area showing the location of well ZS1. (b) Cross section of the Tazhong Uplift showing oil and gas accumulation at well ZS1 area. Fig. 2. Integrated stratigraphic column of the Cambrian strata at well ZS1 showing hydrocarbon distributions. Fig. 3. GC×GC-FID chromatograms of the studied condensates from well ZS1. Fig. 4. Quantitative results of chemical compositions in the studied condensates. Fig. 5. Quantitative distributions of different compound groups with carbon numbers. (a) n-alkanes; (b) branched alkanes (C3 branched alkanes represent summed branched alkanes eluted between n-C3 and n-C4, and same definition for other carbon numbers); (c) monocyclic alkanes; (d) polycyclic alkanes; (e) monoaromatic hydrocarbons; (f) tetralin series; (g) diaromatic hydrocarbons; (h) 1,2,3,4-tetrahydro-phenanthrene series; (i) triaromatic hydrocarbons; (j) others. Fig. 6. Diamondoids distributions in the studied gas condensates. (a) chromatogram with selected ions of m/z 136, 135, 149, 163, and 177 showing distribution of alkyladamantanes; (b) chromatogram with selective ions of m/z 187, 188, 201, and 215 showing distribution of alkyldimantanes. Compound identification refers Table 2. Fig. 7. Natural gas plot of the studied gases from wells ZS1 and ZS1C. Data with * are from Li et al.43 Fig. 8. Bulk isotopic compositions of ZS1 and ZS1C condensates. Data with * are from Wang et al.47 Fig. 9. Cross plot of ∆13C (Methane – Source) vs. C1/ΣC1-5 for ZS1 and ZS1C gases. Plot interpretation after Clayton.5


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Fig. 10. Burial and thermal history of well ZS1.


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(a)

(b)

Fig. 1


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Fig. 2


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Monocyclic alkane 8.46

8.46

2nd Dimension Time / s


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6.46

6.46

4.46

4.46

2.46 10.7

94 1st Dimension Time / min

177.3

2.46 10.7

Fig. 3


94 1st Dimension Time / min

177.3

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Fig. 4


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Fig. 5


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(a) 2nd Dimension Time / s

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4.81

4.81

4.31

3.81 88.1

4.31

91.4

98.1 94.7 1st Dimension Time / min

101.4

3.81 88.1

91.4

(b)

Fig. 6


94.7 101.4 98.1 1st Dimension Time / min

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Fig. 7


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CH4

C2H6 ZS1 6439-6458 m C3H8 C4H10 -

ZS1 6598-6785 m ZS1C 6861-6944 m *TZ83 5666.1-5684.7 m *ZG13 6458–6550.36 m

-55

-50

-45

-40

-35

-30

δ13C (‰)

Fig. 8


-25

-20

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0 -5

∆13C Methane - Source

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TZ83 ZS1 Є1x

Moderate

-10

ZS1C

ZS1 Є2a

-15 Extraction of Gas From Oil

-20 -25

ZG13

Labile Kerogen Gas

-30 0.4 0.45 0.5 0.55 0.6 0.65 0.7 0.75 0.8 0.85 0.9 0.95 C1/ΣC1-5

Fig. 9


1

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Fig. 10


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Table 1 Physical properties of gas condensates from wells ZS1 and ZS1C

Well

Depth (m)/ Age 6439-6458 / Є2a

ZS1 6425-6496 / Є2a ZS1C

6861-6944 / Є1x

API gravity (°) 20 °C 50 °C 46.4 51.6 48.4 53.8 46.9 52.1 47.8 54.5 46.3 51.5 48.3 53.6 20.7

23.9

Viscosity (mPa·s) 20 °C 50 °C 1.9 1.5 1.6 1.2 1.8 1.4 1.6 1.2 1.8 1.4 1.6 1.2 2.4

2.2

Wax (%) 8.5 4.6 5.4 6.4 5.3 4.5

Sulfur (%) 0.18 0.06 0.12 0.16

Resin (%) 0.57 0.68 0.52 0.39 1.24 1.04

2.8

2.06

0.29


Asphaltene (%) 0.46 0.33 0.2 0.6 0.42 0.49 0.18

Pour point (°C) -4

Geochemical Significance of Discovery in Cambrian Reservoirs at

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