ORGANIC GEOCHEMISTRY OF POTENTIAL SOURCE ROCKS IN THE TERTIARY DINGQINGHU FORMATION, NIMA BASIN, CENTRAL TIBET

Transcription

1 Journal of Petroleum Geology, Vol. 34(1), January 2011, pp ORGANIC GEOCHEMISTRY OF POTENTIAL SOURCE ROCKS IN THE TERTIARY DINGQINGHU FORMATION, NIMA BASIN, CENTRAL TIBET Licheng Wang 1,2, Chengshan Wang *1,2, Yalin Li 1,2, Lidong Zhu 3 and Yushuai Wei 1,2 INTRODUCTION The Tertiary Nima Basin in central Tibet covers an area of some 3000 km 2 and is closely similar to the nearby Lunpola Basin from which commercial volumes of oil have been produced. In this paper, we report on the source rock potential of the Oligocene Dingqinghu Formation from measured outcrop sections on the southern and northern margins of the Nima Basin. In the south of the Nima Basin, potential source rocks in the Dingqinghu Formation comprise dark-coloured marls with total organic carbon (TOC) contents of up to 4.3 wt % and Hydrogen Index values (HI) up to 849 mg HC/g TOC. The organic matter is mainly composed of amorphous sapropelinite corresponding to Type I kerogen. Rock-Eval T max ( o C) and vitrinite reflectance (R r ) (average R r = 0.50%) show that the organic matter is marginally mature. The potential yield (up to mg HC/g rock) and a plot of S2 versus TOC suggest that the marls have moderate to good source rock potential. They are interpreted to have been deposited in a stratified palaeolake with occasionally anoxic and hypersaline conditions, and the source of the organic matter was dominated by algae as indicated by biomarker analyses. Potential source rocks from the north of the basin comprise dark shales and marls with a TOC content averaging 9.7 wt % and HI values up to 389 mg HC/g TOC. Organic matter consists mainly of amorphous sapropelinite and vitrinite with minor sporinite, corresponding to Type II III kerogen. This is consistent with the kerogen type suggested by cross-plots of HI versus T max and H/C versus O/C. The T max and R r results indicate that the samples are immature to marginally mature. These source rocks, interpreted to have been deposited under oxic conditions with a dominant input of terrigenous organic matter, have moderate petroleum potential. The Dingqinghu Formation in the Nima Basin therefore has some promise in terms of future exploration potential. The Tibetan Plateau is located in the eastern part of the Tethyan realm within which over two-thirds of global petroleum reserves are concentrated (Klemme 1 School of Earth Science and Resources, China University of Geosciences, Beijing , China. 2 State Key Laboratory of Geological Process and Mineral Resources, China University of Geosciences, Beijing , China. 3 Institute of Sedimentary Geology, Chengdu University of Technology, Chengdu , China. * Corresponding author, chshwang@cugb.edu.cn and Ulmishek, 1991). Over the past two decades, the Plateau has become a frontier for oil exploration, and hydrocarbon discoveries have recently been made in the Tertiary Lunpola Basin where production tests were successful at two wells in 1999 (Gu et al., 1999). Exploration wells and geophysical surveys have to-date mostly been concentrated in the Lunpola Basin. Other basins have been received little consideration and only a few papers in international Key words: source rock potential, organic matter, thermal maturity, biomarkers, Nima Basin, Dingqinghu Formation, Tibet The Authors. Journal of Petroleum Geology 2010 Scientific Press Ltd

2 68 Potential source rocks, Tertiary Nima Basin, Central Tibet journals have considered their petroleum geology and exploration potential (e.g. Taner and Meyerhoff, 1990a, b; Wang et al., 1997). A number of Tertiary continental basins are located on the approximately east-west surface trace of the Bangong suture in central Tibet, including the Lunpola Basin, the Nima Basin, the Dongco Basin and the Avengco Basin (Fig. 1). The Nima Basin is located close to, and to the west of, the Lunpola Basin (Fig. 1) and covers an area of about 3000 km 2. It is bound to north and south by the Qiangtang and Lhasa terranes respectively. The Nima and Lunpola Basins are closely similar in terms of age, sedimentary fill and developmental history. Major source rocks in the Lunpola Basin are the Niubao and Dingqinghu Formations (Taner and Meyerhoff, 1990b; Gu et al., 1999), and these units also have source rock potential in the Nima Basin. Although oil saturated sandstones and disseminated asphaltic material have recently been found in the Nima Basin (Fig. 2), most previous studies have focused on the basin s tectonic history, regional geology and sedimentology (e.g. Kapp et al., 2007; DeCelles et al., 2007a, b). No organic geochemical studies of potential source rocks have yet been published. The purpose of the present paper is to characterize potential source rocks in the Tertiary Dingqinghu Formation in the Nima Basin. The results will assist with future exploration both in the Nima Basin and in other Tertiary continental basins located nearby. Geological Setting and Stratigraphy The depression filled by Tertiary deposits in the Nima area is referred to in this paper as the Nima Basin, but its description here is a little different from that published by DeCelles et al. (2007a). The Nima Basin is an east-west trending rift basin whose fill rests on a Jurassic-Cretaceous marine succession containing deformed flysch and mélange. The southern boundary of the basin is marked by the regionally extensive, southward-dipping Gaize Siling Co and Nima thrusts, with the northernmost exposures of the Aptian Albian Langshan Formation in its hanging wall (Kapp et al., 2005) (Fig. 1b). The northern boundary of the Nima Basin is formed by the northward-dipping Muggar thrust (DeCelles et al., 2007a). Although there are no exploration wells in the Nima Basin, similar depositional fills in the Nima and Lunpola Basins have been investigated based on studies at a number of outcrop sections. The sedimentary succession in the Nima Basin is about 4000 m thick according to magnetotelluric soundings (unpublished data). The sedimentary succession is dominated by the Niubao Formation (Paleocene-Eocene) and the overlying Dingqinghu Formation (Oligocene) (Xia and Liu, 1997) (Fig. 3), which have thicknesses of about m and m, respectively. Depositional systems in the southern and northern Nima Basin developed independently (DeCelles et al., 2007a). Two stratigraphic sections (NMN and NMS), located near the 2MK and 1DC sections of DeCelles et al. (2007a), were measured in the northern and southern parts of the basin (Fig. 1b). The NMS section comprises two upward-coarsening successions with marls, shales and claystones in the lower part and sandstones and conglomerates in the upper part (Fig. 3a). The successions are interpreted to represent alluvial fans that prograded into large-scale open lakes. Biotite Ar/Ar dating gave ages of Ma (Late Oligocene) (DeCelles et al., 2007a). The NMN section exhibits an overall upward-fining trend from conglomerates in the lower part to shales (Fig. 3a). Organic-rich siltstones and shales in the section yield Eocene Oligocene palynomorphs, and lithofacies are interpreted to suggest deposition in shallow lakes and fluvial systems on a lacustrine coastal plain (DeCelles et al., 2007a). In contrast to the large-scale Tertiary palaeolakes documented for the southern Nima Basin, palaeolakes in the northern part of the basin were relatively shallow (DeCelles et al., 2007a). MATERIALS AND METHODS The study areas are located on the southern and northern margins of the Nima Basin (Fig. 1b). A total of 68 outcrop samples of the Tertiary Dingqinghu Formation were collected from two measured sections and from two other localities in the Nima Basin (Fig. 1b). To minimize the effects of surface weathering, surface material was removed before sampling. Fortytwo samples were selected by colour for total organic carbon (TOC), Rock-Eval pyrolysis, organic petrology, and extractable organic matter (EOM) and stable carbon isotope analyses. Extracts from eleven of these samples were selected for analysis by gas chromatography (GC) and gas chromatography mass spectrometry (GC MS). Details of sample locations are shown in Figs. 1b and 3. TOC and total sulphur values were determined using a Leco CS-200 carbon sulphur analyser. Crushed samples (about 100 mg and 120 mesh) were heated to 1200 C in an induction furnace after removing carbonate using hydrochloric acid (HCl). Pyrolysis data was collected using a Rock-Eval II instrument. A 100 mg crushed sample was analyzed following guidelines established by Peters (1986). Analyzed powdered samples were extracted with chloroform for 72 h in a Soxhlet apparatus. The EOM was separated by column chromatography into saturated hydrocarbons, aromatic hydrocarbons and NSO compounds using a silica gel alumina column,

3 Licheng Wang et al. 69 Fig.1. A. Tectonic elements of the Tibetan Plateau (after DeCelles et al., 2007a). B. Geological map of the Nima Basin (after Kapp et al., 2007). ATF: Altyn Tagh fault; BSZ: Banggong suture zone; JSZ: Jingsha Suture zone; ISZ: Indus-Yarlung suture zone. The locations of the two measured cross-sections (NMS and NMN) in the south and north of the basin, respectively, are indicated by red stars. Sampling localities (NMD1 and NMD2) are also indicated (black triangles).

4 70 Potential source rocks, Tertiary Nima Basin, Central Tibet Fig.2. (A) Oil-saturated limestones in the Dingqinghu Formation exposed at the NMS section in the south of the Nima Basin. (B) Dark disseminated asphaltic material. (C) Grey to brownish lacustrine marls of the Dingqinghu Formation; 12 cm pencil for scale. (D) Marls interbedded with shales as potential source rocks in the Dingqinghu Formation exposed in the NMS section (indicated by the red line). (E) Grey-dark grey shales of the Dingqinghu Formation; 25cm hammer for scale. (F) Outcropping shales interbedded with pebble conglomerates in the NMN section, northern Nima Basin. See Fig. 1b for section locations. after precipitation of asphaltenes (Petersen et al., 2005). Gas chromatography of the saturated hydrocarbon fraction was performed on a Hewlett Packard 5890 II GC apparatus with a DB-1 fused silica column (15 m 0.22 mm ID 0.2 μm film thickness). The oven temperature was initially set to rise from 80 C to 320 C at a rate of 10 C/min then held at 320 C for 20 min (c.f. Fildani et al., 2005). The injector was set at 325 C in splitless mode, with hydrogen as the carrier gas at a head pressure of 20 psi (Fildani et al., 2005). The GC MS of saturated hydrocarbon fractions was performed on a Finnigan SSQ-7000 instrument fitted with a DB5-MS fused silica capillary column (30 m 0.32 mm ID 0.25 μm film thickness) using helium as the carrier gas. The oven was isothermally held for 1 min at 35 C, heated C at 10 C/min, then C at 3 C/min, with a final holding time of 30 min (Fu et al., 2009). The selected ion monitoring capabilities of the data acquisition system permitted specific ions to be monitored, such as tricyclic terpanes and hopanes (m/z 191) and steranes (m/z 217) (c.f. Alsharhan and Abd El-Gawad, 2008). To prepare the kerogens, fragments of rock were leached in 6N HCl for 12 h to remove carbonates, and then washed several times with distilled water and treated with hydrofluoric acid (HF) for 12 h to remove silicates (Vandenbroucke and Largeau, 2007). Samples were again washed with distilled water and again treated with 6N HCl (Vandenbroucke and Largeau, 2007). Vitrinite reflectance (R r ) measurements were performed under a Leica MPV Compact II reflected light microscope fitted with an oil-immersion photomicrometer. Visual estimation of the relative abundance of maceral content was determined using a Zeiss incident-light microscope and a Swift point counter (Petersen, 2005). Elemental analyses were performed on a FLASH EA-1112 Series elemental analyzer with a precision generally better than 0.3% for carbon and 0.5% for nitrogen. The δ13c kerogen isotopic measurements were determined on an EA-Finnigan Delta plus XL mass spectrometer. Results of carbon isotopes are reported in the usual δ-notation relative to the PDB standard;

5 Licheng Wang et al. 71 Fig. 3. Stratigraphic columns for the NMS section (A) and NMN section (B) in the south and north of the Nima Basin respectively. Sample depths are indicated on the columns. The sections are located in Fig. 1b. the analytical precision by this method was better than ± 0.2 (Chen et al., 2005). All analyses were performed in the Organic Geochemistry Laboratory, Research Institute of Exploration and Development, Huabei Oilfield Branch Co. of PetroChina. RESULTS AND DISCUSSION TOC and Rock-Eval data Rock-Eval and TOC data are summarized in Table 1. The TOC contents of the samples from the NMS section range from 0.04 to 4.31 wt %, variations being related to lithology. Argillaceous rocks (grey shales and grey claystones) have TOC contents ranging from about 0.06 to 0.18 wt %. Marl samples have comparatively higher TOC contents, up to 4.31 wt % (n = 17). This assessment is consistent with the S2 values which are much higher in marls than in shales and claystones. Most S2 values in marl samples are range from 0.50 to mg HC/g rock, compared to mg HC/g rock for the argillaceous samples. The hydrogen index (HI) is consistently higher in marl samples (HI up to 849 mg HC/g TOC). T max

6 72 Potential source rocks, Tertiary Nima Basin, Central Tibet Table 1. TOC and Rock-Eval data. Sample No. lithology TOC,%wt o Tmax C S1, mghc/g S2, mghc/g PY (S1+S2) HI PI NMS-1 marls NMS-2 marls NMS-3 marls NMS-4 marls NMS-5 marls NMS-6 claystones NMS-7 marls NMS-8 shales NMS-9 marls NMS-10 shales NMS-11 marls NMS-12 shales NMS-13 shales NMS-14 marls NMS-15 claystones NMS-16 marls NMS-17 marls NMS-18 shales NMS-19 marls NMS-20 marls NMS-21 marls NMS-22 marls NMS-23 shales NMS-24 marls NMS-25 marls NMN-1 shales NMN-2 shales NMN-3 shales NMN-4 shales NMN-5 shales NMN-6 shales NMN-7 shales NMN-8 shales NMN-9 shales NMN-10 shales NMN-11 shales NMN-12 shales NMD1-1 marls NMD1-2 shales NMD1-3 shales NMD2-1 marls NMD2-2 marls values of all the samples mostly range from 430 to 451 C, with some exceptional samples which have low S2 values (< 0.2 mg HC/g rock) that were rejected (Peters, 1986). These results indicate that the samples of the Dingqinghu Formation from the NMS section are marginally mature at the onset of hydrocarbon generation. Most samples have production indices (PI) (PI = S1/[S1+S2]) ranging from 0.01 to 0.36, which is not consistent with the maturity suggested by the T max values. Weathering is known to affect the amount and quality of OM in outcropping source rocks (Clayton and King, 1987), and Rock-Eval pyrolysis data such as HI and OI are very sensitive to weathering (Lo and Cardott, 1995). Therefore, the inconsistency between PI and T max values may be due to weathering. Uncertainties regarding OI values, which can be affected by the presence of carbonates, low TOC values, weathering or oxidation in outcrop sections, are avoided if pyrolysis data is plotted on a plot of HI versus T max (c.f. Tyson, 1995), as in Fig. 4. Based on this diagram, the OM in the shales and claystones can be classified as Type III kerogen (gas-prone). The diagram indicates that the OM in the marls is dominated by Type I II oil-prone kerogen. S2 in the samples is plotted versus TOC in Fig. 5; this plot can be used to determine the true average

7 Licheng Wang et al. 73 Fig. 4. Cross-plot of hydrogen index versus T max for samples from the Dingqinghu Formation showing organic type of potential source rocks (based on data in Table 1). Fig. 5. Cross-plot of Rock-Eval S2 yields plotted against TOC content for the samples analysed. The insets in the two figures are enlarged from the boxes in the lower left-hand corner. A. The true Hydrogen Index is 760 mg HC/g TOC. The regression line (R 2 = 0.97) cuts the x-axis at 0.16 wt %, indicating that 0.16 wt % TOC is required before liquid hydrocarbons can be expelled by pyrolysis (c.f. Langford and Blanc-Valleron, 1990). B. The true Hydrogen Index is 159 mg HC/g TOC. A TOC content less than 1.10 wt % does not have sufficient organic matter to overcome the effect of adsorption (Langford and Blanc-Valleron, 1990).

8 74 Potential source rocks, Tertiary Nima Basin, Central Tibet Fig. 6. S2 versus TOC diagram showing the genetic petroleum potential of source rocks. Key to symbols as in Fig. 4. HI, measure the adsorption of hydrocarbon by the rock matrix and indicate the kerogen type (Langford and Blanc-Valleron, 1990). The NMS samples plot in the Type I II kerogen field for most of the marls, and in the Type III kerogen field for the argillaceous rocks. The slope of the regression line suggests that the true HI is 760 mg HC/g TOC (Fig. 5A). This value is higher than the average HI for the NMS samples (325 mg HC/g TOC), indicating mineral matrix effects and the adsorption of generated hydrocarbons. The x-intercept in Fig. 5A is 0.16% which indicates the amount of organic material required for liquid hydrocarbons to be expelled by pyrolysis (c.f. Petersen et al., 2005). The shale samples from the NMN section have TOC contents ranging from 0.7 to 40.0 wt % (Table 1), averaging 11.8 wt %. S1 and S2 are and mg HC/g rock, respectively. T max values vary from 422 to 438 C (average 430 C), indicating an immature to marginally mature stage. The samples have PI ranging from 0.01 to 0.13 with only one sample > 0.1 which suggests that most samples are immature, tending to contradict the T max values. Based on the HI vs T max diagram (Fig. 4), the OM in the shales can be classified as Type II III kerogen. The S2 vs TOC plot (Fig. 5B) shows that the true HI value is 159 mg HC/g TOC, which is higher than the average HI value for the NMN samples (108 mg HC/g TOC). The NMN samples plot in the Type II III kerogen area, suggesting that the OM in the samples would generate oil and gas. The marl samples from the NMD1 location in the north of the Nima Basin (Fig. 1b) contain 0.49 wt % TOC, and have S1 and S2 values of 0.04 mg HC/g rock and 0.45 mg HC/g rock, respectively. Two shale samples from NMD1 contain much higher TOC, S1 and S2 values, averaging 5.6 wt %, 0.18 mg HC/g rock, and 12.2 mg HC/g rock, respectively. The OM in two of the marl samples from the NMD2 location have high TOC values (9.3 wt % and 1.9 wt %), S1 (0.36 mg HC/g rock and 0.08 mg HC/g rock) and S2 (14.22 mg HC/g rock and 1.35 mg HC/g rock). The high T max value (482 C) in one marl sample (S2 < 0.2) is not comparable with values from other samples and has been ignored. T max in two shale and marl samples are C and C, respectively, which indicates that the OM is marginally mature. The HI versus T max diagram (Fig. 4) shows that all the NMD1 and NMD2 samples contained Type II III kerogen. The NMD1 and NMD2 samples plot in the Type II-III kerogen field on the S2 versus TOC diagram (Fig. 5B), consistent with the HI versus T max cross-plot. The potential yield (PY), defined as the sum of Rock-Eval S1 and S2 values, is an evaluation of the genetic potential of a source rock (Tissot and Welte, 1984). Potential yield values of samples from the Dingqinghu Formation are closely correlated to TOC values (Table 1), and samples with high TOC contents have high PY values. Potential yield values of samples from the NMS section, the NMN section, NMD1 and NMD2 range from 0.09 to kg/t, 0.31 to kg/t, 0.49 to kg/t, and 1.35 to kg/t, respectively. Samples NMS-1, NMS-5, NMS-11, NMS-14, NMS-16, NMS-19, NMS-22, NMN-3, NMN-7-11, NMD1-2, NMD1-3 and NMD2-1 have high potential yield values corresponding to good source rock potential; other samples (NMS-2, NMS- 7 and NMN-12) have moderate values corresponding to more moderate source rock potential (c.f. Tissot and Welte, 1984). An S2 versus TOC diagram, which classifies source rocks into poor, fair, good and excellent, shows a good correlation with the potential yield values (Fig. 6). Elemental Analyses Kerogen samples used for elemental analyses are listed in Table 2. Elemental analysis is considered reliable if the sum of these elements > 90 wt % (Vandenbroucke and Largeau, 2007). The sum of C, H, O, N and S

9 Licheng Wang et al. 75 Table 2. Organic composition of kerogen from samples of the Dingqinghu Formation. Sample No. C,% H,% O,% N,% S,% H/C O/C S/C N/C δ13c, NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMN NMN NMN NMN NMN NMN NMN NMN NMN NMN NMN NMN NMD NMD NMD NMD NMD contents ranges from 19% to 99% in the kerogens analyzed from the Nima Basin. Six shale samples from the NMN section, two shale samples from NMD1, and one marl from the NMD2 locality have sum > 90%, with other samples varying from 19% to 89%. These incomplete mass balance analyses suggest that the isolated kerogen contains a significant amount of residual minerals (e.g. Montero-Serrano et al., 2010). Kerogens from the NMS section have H/C ratios between 0.82 and 1.6 and O/C ratios between 0.07 and 0.3. Based on the H/C versus O/C cross-plot (Fig. 7), the OM in most of the marl samples can be classified as Type I II kerogen, whereas the OM in argillaceous rocks can be classified as Type II III kerogen. H/C ratios of and O/C ratios of from kerogens of the NMN shales plot in the field of Type II III kerogen (see Fig. 7). Kerogens from the NMD1 locality have H/C ratios ranging from 0.83 to 0.9 and O/C ratios ranging from 0.2 to 0.3, whereas the kerogens from NMD2 have H/C ratios

10 76 Potential source rocks, Tertiary Nima Basin, Central Tibet Fig. 7. Plot of H/C versus O/C for kerogen in samples of the Dingqinghu Formation showing type of organic matter. Key to symbols as in Fig. 4. from 0.88 to 0.91 and O/C ratios from 0.37 to The H/C versus O/C plot shows Type II III kerogens in NMD1 samples and Type III kerogens in the NMD2 samples (Fig. 7). The S/C ratio ranges from to 0.178, which indicates that pyrite is present in a few samples. The N/C atomic ratio ranges from to 0.036, and these low ratios are characteristic of immature OM derived from vascular land plants (Hetényi et al., 2004). However, the low values may also suggest that the preserved OM underwent selective degradation during early diagenesis and microbial reworking that could have modified the original N/C ratios (Meyers, 1997; Hetenyi et al., 2004; Vandenbroucke and Largeau, 2007). Composition and δ 13 C of kerogen The kerogen composition of the samples is listed in Table 3. Petrographic examination of selected organicrich samples (TOC > 0.5 wt %) from the Dingqinghu Formation showed some variation in kerogen composition (see Fig.8). In the NMS samples examined, amorphous sapropelinite comprised 90 99% of the kerogen assemblages, along with minor vitrinite (0 3%) and inertinite (0-8%). The maceral composition implies Type I kerogen (Peterson et al., 2005). The samples from the NMN section were also dominated by amorphous sapropelinite (50 76%), but were much richer in vitrinite (16 35%) and inertinite (6 12%) than the NMS samples. The sporinite content was up to 10% in some samples. The samples from the NMD1 location have similar maceral compositions in terms of amorphous sapropelinite (55 60%), vitrinite (32 35%), sporinite (1 2%) and inertinite (7 8%). Amorphous sapropelinite ranged from 75% to 78% and vitrinite ranged from 19% to 20% in two samples from NMD2. The presence of more terrigenous organic matter (mainly vitrinite + inertinite > 30%) (Tissot and Welte, 1984) in the northern samples than in the southern samples (vitrinite + inertinite < 11%) suggests that the OM in the outhern samples is more oil-prone than that in the northern samples. Isotopic composition of isolated kerogens shows negative values (c.f. Katz, 1995). The δ 13 C values of NMS kerogens range from -29 to PDB, with most values within a range of -25 to -29 (Table 2). The carbon isotope composition of NMN kerogens has δ 13 C values from to -25.4, with most values around The kerogens from the NMD1 and NMD2 locations have δ 13 C values ranging between -25 and -26. Organic matter produced from atmospheric CO 2 by land plants using the C3 pathway show isotopic values ranging from - 34 to -24, averaging -27 (Meyers, 1994, 1997). Meyers (1997, 2003) reported that the δ 13 Corg values of typical lacustrine algae ranges from -30 to -25. Therefore, lake-derived algal OM is usually isotopically indistinguishable from OM produced by C3 plants in the surrounding watershed (Meyers, 2003). However, according to maceral compositions, the OM of the NMS samples is interpreted to be dominated by algae consistent with the oil-prone potential, and the OM of the northern samples is derived from algal and land plant material and it therefore less oil prone. Therefore, the kerogen type indicated by the δ 13 C values of the kerogens agrees with the results suggested by the HI versus T max and H/C versus O/C cross-plots. Vitrinite Reflectance Vitrinite reflectance (R r ) values were measured on 26 selected organic-rich samples (TOC > 0.5 wt %) from the Dingqinghu Formation in the Nima Basin (Table 3). Samples from the NMS section show that R r values range between 0.4 and 0.89, but two samples contain only one measured particle. Reliable values (with more particles measured) (average R r = 0.50) indicate that the OM in the NMS section is marginally

11 Licheng Wang et al. 77 Table 3. Organic petrography and vitrinite reflectance data. Sample No. Amorphous Sapropelinite Sporinite Vitrinite Inertinite Rr,% number of particles Standard Deviation NMS NMS NMS NMS NMS NMS NMS NMS NMS NMN NMN NMN NMN NMN NMN NMN NMN NMN NMN NMN NMN NMD NMD NMD NMD mature (Tissot and Welte, 1984), consistent with the T max values. The R r values of NMN shales range between 0.48 and 0.67 (averaging 0.56), which indicates that most of the shale is marginally mature, with two samples being immature. The samples from the NMD1 and NMD2 sections have R r values of 0.50 to 0.65 (also averaging 0.56), suggesting marginal maturity. Bitumen composition and organic geochemistry Data regarding bitumen composition is listed in Table 4. The total abundance of EOM of the samples from the NMS section ranges from 25 ppm to 1297 ppm. The bitumens consist of 10 44% saturates, 4 24% aromatics, 37 72% NSO and 8 23% asphaltenes. Values from samples from the NMN section vary widely, from 70 ppm to 3328 ppm. The bitumens comprise saturates (2 22%), aromatics (1 12%), NSO (63 90%) and asphaltenes (4 13%). The EOM extracted from the NMD1 and NMD2 samples ranges between 84ppm and 1064 ppm, averaging 15% saturates, 17% aromatics, 62% NSO and 6% asphaltenes. All samples from the Dingqinghu Formation show the non-hydrocarbon fraction to be dominant (Fig. 9) and have a bitumen/toc ratio ranging from 0.01 to Samples from the northern Nima Basin have lower bitumen/toc ratios than samples from the south, which is consistent with the HC yields (up to mg HC/g TOC, averaging 31.6 mg HC/g TOC for the NMS samples, but up to 8.35 mg HC/g TOC, averaging 2.36 mg HC/g TOC for the NMN, NMD1 and NMD2 samples). Differences in samples from the northern and southern Nima Basin are related to OM type; the OM in the northern samples is more terrigenous. The lower maturity of the OM in the northern samples may also contribute to the difference. C 15+ gas chromatograms of saturated hydrocarbons from the NMS section (Fig. 10a) show a bimodal distribution with a dominance of long-chain n-alkanes (> n-c 23 ) and a slight odd/even predominance (CPI of ). The n-alkanes maxima mainly appear at n-c 23 indicating a contribution from aquatic macrophytes or non-marine algae (Ficken et al., 2000; Sachsenhofer et al., 2006; Riboulleau et al., 2007). In the present case, phytoplankton such as algae are a dominant component in the OM according to the maceral composition. In contrast, the extracts from the NMN section (Fig. 10b) show a unimodal distribution with a dominance of long-chain n-alkanes (> n-c 27 ) and have a marked odd/even predominance

12 78 Potential source rocks, Tertiary Nima Basin, Central Tibet Table 4. Bulk composition of extractable organic matter from the Dingqinghu Formation. Sample No. EOM, ppm Fractionation of EOM,% Sat/Aro HC, ppm Bitumen/TOC HC yield, Sat Aro NSO Asp mg HC/ g TOC NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMS NMN NMN NMN NMN NMN NMN NMN NMN NMN NMN NMN NMN NMD NMD NMD NMD NMD (CPI of ) with n-alkanes maxima at n-c 29 or n-c 31, suggesting higher terrestrial plant input (Cranwell, 1984; Meyers, 1997). The pristane/phytane (Pr/Ph) ratio is a commonlyused parameter for the study of oxic/anoxic conditions (e.g. Montero-Serrano et al., 2010). However, differences in thermal maturity (Koopmans et al., 1999) and variable source input (ten Haven et al., 1987) must be taken into account when Pr/Ph ratios are considered. Peters et al. (2005) recommended that Pr/Ph <0.6 indicates anoxic, commonly hypersaline or carbonate environments, while Pr/Ph >3.0 typify terrigenous OM input under oxic conditions for rocks within the oil-generative window. The Pr/ Ph ratios (Table 5) are lower for the NMS samples (between 0.17 and 0.81) than for the NMN samples

13 Licheng Wang et al. 79 Fig.8. Photomicrographs of macerals from the Dingqinghu Formation in the Nima Basin, fluorescent light (Aμm. (A-B) Abundant amorphous material, samples B) and transmitted light (C-D). Horizontal scale = 400μ NMS-5 and NMS-11. (C-D) Amorphous material and minor vitrinite, samples NMN-4 and NMN2-1. Fig. 9. Ternary diagram showing the composition of extracted bitumens. Key to symbols as in Fig. 4.

14 80 Potential source rocks, Tertiary Nima Basin, Central Tibet Table 5. Selected biomarker data of the extractable organic matter from the Dingqinghu Formation. %C 29 sterane %C 28 sterane %C ββ-c 29 / C sterane 20S/(20S+20R)C gammacerane /(C 31 (22S+22R)/2 29 CPI Pr/Ph Pr/nC 17 Ph/nC 18 Tm/Ts Ts /Ts+Tm 22S/22S+22R Homohopane Sample No. ) NMS NMS NMS NMS NMS NMS NMS NMS NMN NMN NMN (between 3.44 and 6.77). This indicates that the OM of several NMS samples (NMS-6, NMS-12, and NMS-25) were deposited under anoxic and hypersaline conditions, while the OM of the NMN samples were deposited under oxic conditions with terrigenous organic matter input. The variation of the Pr/Ph ratios in the NMS section suggests variations in depositional environment from the lower part to the upper part of the section. The distribution of terpane (m/z 191) and sterane (m/z 217) biomarkers shows more variation between samples from the southern and northern Nima Basin. Representative mass fragmentograms are shown in Fig. 11, with selected biomarker ratios summarized in Table 5. The m/z 191 mass fragmentograms (Fig. 11) show low abundance of tricyclic hydrocarbons; 17α(H), 21β (H)-hopane is the highest peak in most of the samples. The extracts from the NMS and NMN samples display a predominance of 17α (H)-22,29,30- trisnorhopane (Tm) over 18α(H)-22,29,30- trisnorhopane (Ts), especially in the NMS section (Tm/ Ts ratios range from to ). Tm is less stable than Ts during catagenesis (Seifert and Moldowan, 1978) and the Ts/(Ts+Tm) ratio or Ts/ Tm ratio depends on both source and maturity (Moldowan et al., 1986). Ratios for the NMS and NMN samples range from 0.09 to 0.27 and from to 0.012, respectively. The NMS samples have higher Ts/(Ts+Tm) ratios. It indicates that the ratios are dependent on the depositional environment of the source rocks. The NMS samples have higher concentrations of gammacerane than homohopane (gammacerane / (C 31 (22S+22R)/2) compared with samples from the NMN section (Table 5). Gammacerane is often present in samples from hypersaline marine and non-marine depositional environments (Moldowan et al., 1985; Fu et al., 1986). High gammacerane contents are often recorded in freshwater lacustrine sediments, and indicate water column stratification (Sinninghe Damsté et al., 1995). Since the water column in hypersaline depositional environments is usually stratified, the compound is abundant in saline lacustrine deposits (Zhu et al., 2005). The higher gammacerane indices for NMS samples indicate an overall stratified palaeolake with occasionally in high salinity. This interpretation is in agreement with the Pr/Ph ratios. Commonly, very low Pr/Ph ratios of <0.5 have been associated with hypersaline conditions (ten Haven et al., 1987). The local abundance of gypsum (DeCelles et al., 2007b) also supports the interpretation. The 22S/(22S+22R) ratios for homohopanes increase from 0 to 0.60 during maturation (Seifert and Moldowan, 1980). The ratios for the C 31 17α-hopane vary between 0.49 and 0.62, averaging 0.57 for the NMS samples, and range from

15 Licheng Wang et al. 81 Fig. 10. Gas chromatograms of the saturated fractions of samples from the Dingqinghu Formation. (a) sample NMS-27, southern Nima Basin; (b) sample NMN-9, northern Nima Basin. See text for discussion to 0.44, averaging 0.41 for the NMN samples, which is consistent with their R r and T max values. The distribution of the regular steranes in the m/z 217 mass fragmentograms (Fig. 11) shows variable peaks in the extracts from both the NMS and NMN sections. The samples from the NMS section show a high proportion of C 27 sterane compared to C 28 and C 29, and the NMN samples are dominated by C 29 sterane. C 27 sterols mainly derive from zooplankton, C 28 sterols from phytoplankton, and C 29 sterols dominate in land plants (Huang and Meinschein, 1979). Although more recent research has demonstrated that C 29 sterols are also present in numerous microalgae such as diatoms and freshwater eustigmatophytes, the sterane ternary plot is still useful in reflecting the source of OM in sediments and of the petroleum (Riboulleau et al., 2007). The distribution pattern of regular steranes in the NMN samples plots in the higher-plants field in Fig. 12, confirming the high concentrations of terrestrial OM input. NMS samples plot in the lacustrine and estuarine regions of the diagram, indicating that the OM is mainly derived from lacustrine zooplankton and phytoplankton in agreement with the C 27 sterol dominance. The S/(S+R) and ββ/(αα+ββ) ratios for the C 29 steranes increase with increasing thermal maturity and reach equilibrium values at and , respectively (Seifert and Moldowan, 1986). The ratios of NMS and NMN samples (Table 5) are lower than the equilibrium values and indicate thermally immaturity, although the previous results indicate that the rocks are at the onset of the oil window. This discrepancy may be due to the insufficient time for complete sterane isomerization in Tertiary rocks (Peters et al., 2005).

16 82 Potential source rocks, Tertiary Nima Basin, Central Tibet Fig.11. m/z 191 and m/z 217 fragmentograms showing the distribution of terpanes and steranes for selected samples from the Dingqinghu Formation.

17 Licheng Wang et al. 83 Fig.12. Ternary diagram showing the relative contributions of C 27, C 28 and C 29 regular steranes. Key to symbols as in Fig. 4. CONCLUSIONS Forty-two samples of lacustrine shales, claystones and marls from the Tertiary Dingqinghu Formation in the Nima Basin have been studied with regard to their organic geochemical characteristics and source rock potential. The following conclusions can be drawn. There are significant differences in the lithology, organic richness, organic type, and maturity of the potential source rocks in the Dingqinghu Formation from the southern and northern Nima Basin, although both have moderate-to-good source potential. Southern samples are mainly composed of dark marls with an average TOC value of 1.23 wt %, and northern samples are dark shales and marls with higher TOC values (averaging 9.71 wt %). As indicated by Rock- Eval data and kerogen composition, the OM in the southern samples contains Type I II kerogen; the northern samples contain less oil-prone Type II III kerogen. Rock-Eval T max and vitrinite reflectance data show that the OM in the southern samples is marginally mature, and that the northern OM is immature to marginally mature. Based on GC and GC MS analysis, the southern samples are interpreted to have been deposited in an overall stratified palaeolake with occasionally anoxic and hypersaline conditions, and the source of the OM is dominated by algae, while the northern samples were deposited under oxic conditions with a mainly terrigenous organic matter input. ACKNOWLEDGEMENTS The research project was financially supported by the Fundamental Research Funds for the Central Universities, the National Natural Science Foundation of China (no ), and the National Petroleum Resources Special Project: Strategic Investigation and Geological Survey on Oil and Gas Resources in Tibet Plateau (XQ ). Analytical work by Dr. Shunping Ma is gratefully acknowledged. David Cushley (International Science Editing) is thanked for improving the English in the manuscript. We acknowledge helpful comments on the manuscript by Luba Jansa (Geological Survey of Canada Atlantic), and are grateful to JPG editorial staff and referee Mike Pearson for their constructive and valuable reviews. REFERENCES ALSHARHAN, A. and ABD EL-GAWAD, E., Geochemical characterization of potential Jurassic/Cretaceous source rocks in the Shushan Basin, Northern Western Desert, Egypt. Journ. Petrol. Geol., 31, CHEN, L., YI, H.S., HU, R.Z., ZHONG, H. and ZOU, Y.R., Organic geochemistry of the Early Jurassic oil shale from the Shuanghu area in Northern Tibet and the Early Toarcian oceanic anoxic event. Acta Geol. Sinica, 79, CLAYTON, J. and KING, J., Effects of weathering on biological marker and aromatic hydrocarbon composition of organic matter in Phosphoria shale outcrop. Geochim. Cosmochim. Acta, 51, CRANWELL, P., Lipid geochemistry of sediments from

18 84 Potential source rocks, Tertiary Nima Basin, Central Tibet Upton Broad, a small productive lake. Org. Geochem., 7, DeCELLES, P., KAPP, P., DING, L. and GEHRELS, G., 2007a. Late Cretaceous to middle Tertiary basin evolution in the central Tibetan Plateau: Changing environments in response to tectonic partitioning, aridification, and regional elevation gain. GSA Bull., 119, DeCELLES, P., QUADE, J., KAPP, P., FAN, M., DETTMAN, D. and DING, L., 2007b. High and dry in central Tibet during the Late Oligocene. Earth Planet. Sci. Lett., 253, FICKEN, K., LI, B., SWAIN, D. and EGLINTON, G., An n- alkane proxy for the sedimentary input of submerged/ floating freshwater aquatic macrophytes. Org. Geochem., 31, FILDANI, A., HANSON, A., CHEN, Z., MOLDOWAN, J., GRAHAM, S. and ARRIOLA, P., Geochemical characteristics of oil and source rocks and implications for petroleum systems, Talara basin, northwest Peru. AAPG Bull., 89, FU, J., SHENG, G., PENG, P., BRASSELL, S., EGLINTON, G. and JIANG, J., Peculiarities of salt lake sediments as potential source rocks in China. Org. Geochem., 10, FU, X., WANG, J., ZENG, Y., LI, Z. and WANG, Z., Geochemical and palynological investigation of the Shengli River marine oil shale (China): implications for paleoenvironment and paleoclimate. Int. Journ. Coal Geol., 78, GU, Y., SHAO, Z.B., YE, D.L., ZHANG, X.Y. and LU, Y.P., Characteristics of source rocks and resource prospect in the Lunpola Basin, Tibet. Petrol. Geol. & Exper., 21, (in Chinese with English abstract). HETÉNYI, M., SAJGÓ, C., VETÖ, I., BRUKNER-WEIN, A. and SZÁNTÓ, Z., Organic matter in a low productivity anoxic intraplatform basin in the Triassic Tethys. Org. Geochem., 35, HUANG, W. and MEINSCHEIN, W., Sterols as ecological indicators. Geochim. Cosmochim. Acta, 43, KAPP, P., DeCELLES, P., GEHRELS, G., HEIZLER, M. and DING, L., Geological records of the Lhasa-Qiangtang and Indo-Asian collisions in the Nima area of central Tibet. GSA Bull., 119, KAPP, P., YIN, A., HARRISON, T. and DING, L., Cretaceous-Tertiary shortening, basin development, and volcanism in central Tibet. GSA Bull., 117, KATZ, B., The Green River Shale: an Eocene Carbonate Lacustrine Source Rock. In: KATZ, B. (Ed), Petroleum source rocks. Springer-Verlag, Berlin Heidelberg, KLEMME, H. and ULMISHEK, G., Effective petroleum source rocks of the world stratigraphic distribution and controlling depositional factors. AAPG Bull., 75, KOOPMANS, M.P., RIJPSTRA, W.I.C., KLAPWIJK, M.M., DE LEEUW, J.W., LEWAN, M.D. and DAMSTE, J.S.S., A thermal and chemical degradation approach to decipher pristane and phytane precursors in sedimentary organic matter. Org. Geochem., 30, LANGFORD, F. and BLANC-VALLERON, M., Interpreting Rock-Eval pyrolysis data using graphs of pyrolizable hydrocarbons vs. total organic carbon. AAPG Bull., 74, LO, H. and CARDOTT, B., Detection of natural weathering of Upper McAlester coal and Woodford Shale, Oklahoma, USA. Org. Geochem., 22, MEYERS, P. A., Preservation of elemental and isotopic source identification of sedimentary organic-matter. Chem. Geol., 114, MEYERS, P. A., Organic geochemical proxies of paleoceanographic, paleolimnologic, and paleoclimatic processes. Org. Geochem., 27, MEYERS, P. A., Applications of organic geochemistry to paleolimnological reconstructions: a summary of examples from the Laurentian Great Lakes. Org. Geochem., 34, MOLDOWAN, J., SEIFERT, W. and GALLEGOS, E., Relationship between petroleum composition and depositional environment of petroleum source rocks. AAPG Bull., 69, MOLDOWAN, J., SUNDARARAMAN, P. and SCHOELL, M., Sensitivity of biomarker properties to depositional environment and/or source input in the Lower Toarcian of SW-Germany. Org. Geochem., 10, MONTERO-SERRANO, J., MARTINEZ, M., RIBOULLEAU, A., TRIBOVILLARD, N., MARQUEZ, G. and GUTIERREZ- MART, N, J., Assessment of the oil source-rock potential of the Pedregoso Formation (Early Miocene) in the Falcón Basin of northwestern Venezuela. Mar. Petrol. Geol., doi: /j.marpetgeo PETERS, K., WALTERS, C. and MOLDOWAN, J., The biomarker guide, Volume 2. Cambridge University Press, PETERS, K.E., Guidelines for evaluating petroleum source rock using programmed pyrolysis. AAPG Bull., 70, PETERSEN, H., TRU, V., NIELSEN, L., DUC, N. and NYTOFT, H., Source rock properties of lacustrine mudstones and coals (Oligocene Dong Ho Formation), onshore Song Hong Basin, northern Vietnam. Journ. Petrol. Geol., 28, RIBOULLEAU, A., SCHNYDER, J., RIQUIER, L., LEFEBVRE, V., BAUDIN, F. and DECONINCK, J., Environmental change during the Early Cretaceous in the Purbeck-type Durlston Bay section (Dorset, Southern England): A biomarker approach. Org. Geochem., 38, SACHSENHOFER, R., BECHTEL, A., KUFFNER, T., RAINER, T.,GRATZER, R., SAUER, R. and SPERL, H., Depositional environment and source potential of Jurassic coal-bearing sediments (Gresten Formation, Hoflein gas/ condensate field, Austria). Petrol. Geosci., 12, SEIFERT, W. and MOLDOWAN, J., Applications of steranes, terpanes and monoaromatics to the maturation, migration and source of crude oils. Geochim.Cosmochim. Acta, 42, SEIFERT, W. and MOLDOWAN, J., Effect of thermal stress on source-rock quality as measured by hopane stereochemistry. Phys. Chem. Earth, 22, SEIFERT, W. and MOLDOWAN, J., Use of biological markers in petroleum exploration. Methods in Geochemistry and Geophysics, 24, SINNINGHE DAMSTE, J., KENIG, F., KOOPMANS, M., KOSTER, J., SCHOUTEN, S., HAYES, J. and DE LEEUW, J., Evidence for gammacerane as an indicator of water column stratification. Geochim.Cosmochim. Acta, 59, TANER, I. and MEYERHOFF, A., 1990a. Petroleum at the roof of the world: The geological evolution of the Tibet (Qinghai-Xizang) Plateau Part I. Journ. Petrol. Geol., 13, TANER, I. and MEYERHOFF, A., 1990b. Petroleum at the roof of the world: The geological evolution of the Tibet (Qinghai-Xizang) Plateau Part II. Journ. Petrol. Geol., 13, ten HAVEN, H.L., DE LEEUW, J.W., RULLKOTTER, J. and SINNINGHE DAMSTE, J.S., Restricted utility of the pristane/phytane ratio as paleeoenvironmental indicator. Nature, 330, TISSOT, B. and WELTE, D., Petroleum occurrence and formation. Springer-Verlag, Berlin, Heidelberg, New York, Tokyo,