Geochemistry and origins of natural gases in the Yinggehai and Qiongdongnan basins, offshore South China Sea

Organic Geochemistry 34 (2003) 1009–1025 www.elsevier.com/locate/orggeochem

Geochemistry and origins of natural gases in the Yinggehai and Qiongdongnan basins, offshore South China Sea Baojia Huanga,b,*, Xianming Xiaoa, Xuxuan Lib a

State Key Laboratory of Organic Geochemistry, Guangzhou Institute of Geochemistry, Chinese Academy of Sciences, Guangzhou 510640, Guangdong, China b CNOOC Nanhai West Research Institute, Zhanjiang 524057, Guangdong, China

Abstract Four gas fields and a number of gas-bearing structures have been discovered in the Yinggehai and Qiongdongnan basins offshore South China Sea. Chemical and isotopic data indicate the presence of at least three genetic groups of gases in these basins: biogenic gas, thermogenic gas, and gases with mixed origin. Thermogenic gases produced from the Yacheng field are characterized by relatively high contents of benzene and toluene, relatively low d13C values of toluene, and high abundance of bicadinanes and oleanane in the associated condensates, showing good correlation with the coal-bearing sequence of the Yacheng Formation in the Qiongdongnan Basin. In contrast, the gases from the DF1-1 and LD gas fields contain high amounts of N2 and CO2, low to moderate amounts of benzene and toluene, with relatively high d13C values of toluene. These characteristics correlate well with the Miocene neritic shales in the Yinggehai Basin. Analyses on potential source rock samples indicate excellent gas source potential for both the coal-bearing sequence in the Yacheng Formation and the Miocene neritic shales containing type III II2 kerogens. As the result of recent rapid subsidence and sedimentation, high temperature and overpressure systems are well developed in the Yinggehai and Qiongdongnan basins. The rapid heating resulted in advanced maturation of organic matter deposited in normally pressured and overpressured strata, whereas the strongly overpressured systems led to retarded organic matter maturation, postponing the time when the source rocks reached peak gas generation. Results of 1-D modeling indicate that the coal-bearing Yacheng Formation in the Yacheng Sag reached peak gas generation during mid Miocene-Pliocene time, after the deposition of upper Oligocene to lower Miocene reservoir rocks. The lower-mid Miocene marine shales reached their peak gas generation stage during the Pliocene-Quaternary in the central Yinggehai basin, supplying abundant gases to charge the Pliocene reservoirs. More importantly, focused-episodic gas migration significantly increased the hydrocarbon expulsion efficiencies of source rocks, and thus provided favorable conditions for the accumulation of large amounts of gases in the diapiric structures in a very short geological time. The gas–source relationship for the Yacheng field suggests dominantly short–distance gas migration and thus strong source facies controls on the geographic distribution of gas fields within the Qiongdongnan Basin. # 2003 Elsevier Science Ltd. All rights reserved.

1. Introduction The Yinggehai and Qiongdongnan basins (also called ‘‘Ying-Qiong basins’’ for short) in the north continental shelf of the South China Sea are two separate Cenozoic basins with close geographic proximity and genetic linkage (Fig. 1 a). Great attention has been paid to these basins in recent years because of their large sedimentary * Corresponding author. Tel.: +86-759-3900573. E-mail address: [email protected] (B. Huang).

volumes and gas potentials. Four gas fields and many gas-bearing structures have been discovered since 1983 (Fig. 1b). These include the Yacheng gas field (YC13-1), and YC13-4 and YC13-6 commercial gas discoveries in the Qiongdongnan Basin. Major gas discoveries in the Yinggehai Basin include the DF1-1 gas field and the Ledong gas field group. The latter is composed of LD22-1, LD15-1 gas fields and several other gas-bearing structures (Fig. 1b). Several geochemical studies have been conducted in these basins, with the focus on the general characteristics

0146-6380/03/$ - see front matter # 2003 Elsevier Science Ltd. All rights reserved. doi:10.1016/S0146-6380(03)00036-6

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Fig. 1. Maps showing the location (a) and structural divisions (b) of the Yinggehai and Qiondongnan basins: (1) Yabei Sag; (2) Songxi Sag; (3) Songdong B Sag; (4) Yacheng Sag; (5) Ledong Sag; (6) Lingshui Sag; (7) Songnan Sag; (8) Baodao Sag; (9) Central Yinggehai Depression (Diapir Belt).

of the natural gases and their possible source rocks (Chen, 1987; Zhang and Zhang, 1989; Zhang and Huang, 1991; Zhang and Hu, 1992; Hao et al., 1996, 1998). The origin of these gases has been a subject of heated debate, but no general consensus has been reached. For example, the marine shales in the Meishan Formation in the Yinggehai Basin were suggested to be the major source rocks for the Yacheng gas field (Zhang and Zhang, 1989; Zhang and Hu, 1992; Zhang et al., 1994), whereas others believe that the source for these gases was the coal-bearing Yacheng Formation in the Qingdongnan Basin (Lin et al., 1985; Chen, 1987; Zhang and Huang, 1991; Zhou and Sheng, 1995; Chen et al., 1998; Dong and Huang, 2001). Therefore, the objectives of this paper are to provide an overview of the geochemical characteristics of these gases and potential source rocks, classify gas families and identify their sources, constrain the thermal evolution of major gas source rocks, and assess the hydrocarbon potential of the source rocks. This would help to better define petroleum systems and reduce the risk associated with the future exploration efforts in this area.

Fig. 2. Generalized stratigraphic column of the Yinggehai and Qiongdongnan basins.

2. Geologic setting The Ying-Qiong basins are located in the area southwest and south of Hainan Island respectively (Fig. 1a). These basins were separated by the No. 1 fault in Paleogene and had different structural trends. In Neogene, this fault was no longer in control of the sedimentation, and the two basins merged, with rapid subsidence. The deposition of thick Neogene and Quaternary sediments in a united Ying-Qiong basins resulted in a large oxbow-like seaward-dipping wedge. The structural evolution of the Ying-Qiong basins can be divided into two stages: an Eocene-Oligocene rift and a post-rift thermal subsidence (Gong and Li, 1997). During the Eocene-Oligocene rift stage, sediments well developed in the Qingdongnan Basin and the adjacent Beibuwan Basin (Fig. 1a). These sediments are composed mainly of fluvial, lacustrine and coastal plain facies (Fig. 2). About 5000–7000 m of Paleogene sediments occurs in the Central Depression of the Yinggehai Basin, but have not been revealed by drilling due to deep burial. The post-rift Neogene-Quaternary marine sediments in the central Yinggehai Basin are near 7000–9000 m in thickness and are dominated by shales. These sediments have not been structurally disrupted except where shale diapirs developed. The post-rift sediments in the

B. Huang et al. / Organic Geochemistry 34 (2003) 1009–1025

Qiongdongnan Basin are much thinner (about 3000– 5000 m). The Yinggehai–Qiongdongnan basins are characterized by high subsidence/sedimentation rates (with the maximum sedimentation rate up to 1.2 mm/year) and high geothermal gradient (39–45  C/km) (Zhang and Huang, 1991; Dong and Huang, 1999, 2000; Hao et al., 2000). As a result of the rapid sediment loading and associated under-compaction, overpressure developed throughout much of the basins. The maximum measured pressure coefficient (fluid pressure/hydrostatic pressure ratio) is up to 2.3 (Hao et al., 1998; Dong and Huang, 1999). Available geological and geochemical data indicate that potential source rocks in the Yinggehai and Qiongdongnan Basins include the Yacheng, Sanya and Meishan Formations (Zhang and Huang, 1991; Huang, 1998, 1999), and the gases accumulate mainly in the Upper Oligocene (Lingshui Fm.), Miocene (Sanya and Huangliu formations), Pliocene (Yinggehai Fm.) and Quaternary strata.

3. Samples and experimental conditions A total of 90 gas samples and 25 condensate oil samples collected during drill stem tests and modular formation tests were used in this study. About 350 rock samples (including cores and cuttings from 26 wells) were also included for total organic carbon (TOC) and source potential determination using a Rock-Eval II instrument. Vitrinite reflectance measurements were preformed on randomly oriented grains using conventional microphotometric methods described by Stach et al. (1982). The gas samples were analyzed using a Hewlett Packard 5890 II gas chromatograph, equipped with a thermal conductivity detector. Methane, C2+ gaseous hydrocarbons and CO2 were prepared for stable carbon isotopic analysis using the methods similar to those reported by Schoell (1983), as described in Wen and Shen (1991). The d13C values are reported in d notation in per mil (%) based on the PDB standard, with an analytical precision of 0.02%. The 3He/4He measurements were carried out using a VG-5400 static-vacuum noble gas mass spectrometer, with the sensitivity remaining stable at 10 4A˚/cm3 STP (standard temperature and pressure). Visual examination and homogenization temperature measurement of the fluid inclusions in sandstone reservoir rocks were conducted using a Leica microscope equipped with a heating-and-freezing stage. For data consistency, only those inclusions occurring in overgrowth edges of quartz grains in sandstones were investigated. The error margins for measured homogenization temperatures are generally with  2  C. Selected rock samples with reasonable hydrocarbon source potentials ( >0.8%TOC) were extracted with dichloromethane in a Soxhlet apparatus (72 h). The

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rock extracts and condensate oils were fractionated using column chromatography after asphaltene precipitation. Saturate fractions obtained were then analyzed by gas chromatography (GC) and gas chromatography/mass spectrometry (GC/MS), under the same conditions described in Huang et al. (this volume). A portion of condensate oils was analyzed directly using gas chromatography for gasoline range hydrocarbon parameters. On-line anhydrous pyrolysis experiments were conducted using a SGE high temperature pyrolysis oven, interfaced with an HP5890II GC. Crushed rock samples (20–60 mesh) were loaded into stainless steel tubes and placed in the pyrolysis furnace. In three separate experiments, the furnace was heated to 400, 500, and 600 (  2.5) C respectively, and maintained at these temperatures isothermally for 1 h. Benzene and toluene were trapped by the GC analyzer from gas products and then combusted into CO2. dCbenzene. and dCtoluene were determined using a Finnigan-MAT 251 mass spectrometer. The BASINMSR (Basin Modeling System), developed by PetroChina RIPED-Beijing, was used to reconstruct the burial history of the Yinggehai and Qiongdongnan basins. The sedimentary sequences used were based on both seismic interpretations and well data. We used the sequence boundaries determined by Gong and Li (1997), paleogeothermal gradients reported by Chen et al. (1998), and a heat flow of 76–84.1 mW/m2 (Gong and Li, 1997). The modeling results were calibrated using measured vitrinite reflectance data.

4. Classification of natural gases in the Ying-Qiong basins Known natural gas reserves in the Qingdongnan Basin occur mainly in the YC13-1 gas field, and the YC13-4 and YC 13-6 gas-bearing structures, northwest of the Yacheng Sag (Fig. 1b). The YC13-1 gas field, located near the No.1 fault, produces gases from marine sandstones in the Upper Oligocene Lingshui and the Lower Miocene Sanya formations. The reservoirs rocks overlay the coal-bearing strata of the Yacheng Formation. The gases are composed prominently of CH4 (85–90%), with relatively low CO2 and N2 contents (Table 1). The ratios of C1/C1-5 in the gases range from 0.93 to 0.99, with relatively high d13C1 ( 34.75 to 39.88%) and dDCH4 values ( 122 to 143%). Proven gas reserves in the Yinggehai Basin occur mainly in mudstone diapiric structures. These include the DF1-1 gas field and Ledong gas field group located within in the central diapir belt (Fig. 1b). The production horizons are the Pliocene–Quaternary marine sandstones, with reservoir depth ranging from 392 to 2000 m. The gases contain variable amounts of CH4 relative to CO2 and N2 (Table 1), with relatively high C1/C1 5 ratios (0.92–0.99). The d13C1 values of these

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Table 1 Chemical and stable carbon isotopic compositions of natural gases produced from the Ying-Qiong basinsa Well

Reservoir age

Depth (m)

d13C(%)

Compositions (%) C1

C2+

CO2

N2

C1

Yinggeahi Basin L2812-5 Q L2213-4 Q L2214-4 Q DF118-3 YGH DF118-2 YGH DF9-4 YGH L2211-5 Q DF112-4 YGH DF112-3 YGH DF112-2 YGH DF113-3 YGH DF113-2 YGH DF113-1 YGH DF114-4 YGH DF114-3 YGH DF114-2 YGH DF115-3 YGH DF115-2 YGH DF117-3 YGH DF117-2 YGH L1511-3 YGH L1514-4 YGH L1514-1 YGH L2012-3 Q L2012-1 YGH L2111-D YGH L2211-4 Q L2211-1 Q L2212-6 Q L2212-2 Q L1411-2 YGH L2811-1 YGH D2911-1 YGH L811-1 YGH

560–562 395–410 575–595 1342–1358 1369–1405 1318–1325 851–858 1284–1296 1331–1361 1414–1452 1260–1268 1287–1307 1333–1372 1225–1240 1277–1293 1320–1340 1322–1326 1386–1410 1358–1386 1403–1415 1417–1557 1428–1445 1855–1873 1056–1065 1703–1720 1553–1566 972–985 1486–1510 392–400 963–985 1013–1058 1655–1690 1832–1842 1910–1923

96.02 87.09 87.01 79.64 82.44 73.54 83.48 76.39 30.82 25.80 81.98 37.05 23.62 79.50 70.40 70.69 71.27 67.32 35.90 40.40 65.46 28.14 9.54 42.09 34.60 8.71 81.70 13.44 81.10 79.20 68.37 7.10 24.79 15.61

0.00 0.31 3.35 1.38 2.14 1.96 0.85 3.03 1.93 1.27 2.06 0.86 0.63 1.67 1.38 1.68 1.41 1.26 1.90 2.00 2.86 1.16 0.37 1.47 1.90 0.51 1.88 0.57 0.20 1.80 0.65 0.80 0.82 0.71

0.01 0.73 0.06 0.35 0.37 0.21 0.17 1.01 57.32 66.66 0.65 55.06 71.00 0.65 0.12 0.22 0.17 0.21 57.00 51.60 16.73 63.90 85.06 52.16 57.60 83.97 0.10 80.42 0.10 0.10 1.34 88.10 70.35 79.69

3.63 11.48 9.30 18.63 15.04 24.04 15.23 19.57 9.06 6.27 15.31 7.03 4.75 17.30 27.70 27.16 27.15 31.21 5.20 6.00 14.73 6.52 4.27 4.09 5.50 6.63 16.04 5.29 18.20 18.50 29.14 3.50 3.94 3.40

65.57 63.14 55.72 54.09 50.32 51.04 54.11 35.77 32.61 33.19 nd nd nd 38.7 38.0 35.5 35.6 34.6 31.8 31.7 37.28 34.82 33.12 32.8 33.01 36.08 38.29 26.9 40.8 34.14 43.1 32.1 32.1 31.39

Qionndongnan Basin YC1311-3 LS YC1312-5 LS YC1312-4 LS YC1313-5 LS YC1314-5 SY YC1314-2 LS YC1316-3 LS YC1341-t SY YC1361-t SY

3573.8–3586.3 3708.8–3725.6 3771.6–3849.6 3788.7–3817.3 3738.7–3743.6 3943.5–3961.8 3774.9–3817.6 2772 3012.5

85.03 88.95 88.52 83.22 86.32 84.10 85.50 87.43 86.52

3.74 2.92 0.98 6.98 6.62 4.21 8.34 6.04 5.39

9.60 8.00 10.10 8.54 6.53 9.17 4.99 5.21 6.14

0.72 nd 0.30 1.04 0.25 1.11 0.93 0.57 0.87

35.80 35.02 34.75 39.36 nd 36.89 39.88 37.3 36.5

C2

C3

CO2

– –

– – –

– – –

22.29 26.86 25.90 26.3 23.48 25.42 25.68 24.81 nd nd nd 26.6 25.4 24.7 25.0 25.4 23.7 23.6 27.74 19.40 17.88 23.9 23.56 22.68 23.08 21.97 28.4 23.3 24.11 23.4 24.1 22.95 25.20 24.37 24.57 26.47 nd 26.29 26.82 27.40 26.80

26.92 25.76 27.70 27.84 25.57 24.73 nd nd nd 26.0 23.7 24.0 24.5 24.3 23.3 23.2 29.37 18.36 16.91 22.4 20.99 nd 21.43 nd nd 21.32 23.77 21.6 22.8 21.20 24.20 22.94 nd 25.01 nd 25.16 25.39 25.80 24.80

18.35 14.59 10.94 15.48 3.19 2.89 nd nd nd 16.2 19.9 20.7 16.9 12.52 3.4 2.8 6.96 5.76 4.78 3.9 3.25 4.18 12.73 2.2 12.4 nd 10.59 +7.9 2.0 3.26 4.90 5.10 nd 7.68 nd 6.09 10.29

Mercury (ng/m3)

Genetic type

nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd nd 5463 5463 14 219 1193 3388 3766 nd nd 2653 nd

I I I II II II II III III III III III III III III III III III III III III III III III III III III III III III III III III III

43 000 45 000 nd nd nd nd nd nd nd

III III III III III III III III III

a YGH, Yinggehai Formation; LS, Lingshui Formation; SY, Sanya Formation; Q, Quaternary; nd, not determined; Genetic type: I. Biogenic; II. Mixed; III. Thermogenic.

gases vary from 27 to 65%, but typically from 30 and 40%, indicating a variable origin of these gases. Like the gases in the Qiongdongnan Basin, gases in the Yinggehai Basin are also enriched in Deuterium, as their dDCH4 values range from 119 to 180%.

Based on the stable carbon isotope of methane, C1/C1 5 ratio and non-hydrocarbon gas concentration, natural gases in the Ying-Qiong Basin can be divided into three genetic groups (Table 1; Figs. 3 and 4).

B. Huang et al. / Organic Geochemistry 34 (2003) 1009–1025

4.1. Group I. Biogenic gas Biogenic gases were produced from the QuaternaryPliocene reservoirs in the LD22-1 and LD28-1 gas fields of the Yinggehai Basin, with a daily production rate of around 4 million cubic feet. These gases contain 87– 92% of methane, with only trace amounts of heavy hydrocarbon gases (Fig. 3). These gases are characterized by low d13C1 values ( 55.72– 65.57%), similar to those biogenic gases in the Caidam Basin in northwestern China (Gu and Zhou, 1993) and Po Basin in Italy (Mattavelli, 1983). Other geochemical features of these gases include their high N2 contents relative to those of CO2. 4.2. Group II. Mixed biogenic-thermogenic gases Up to now, gases belonging to this group have been found only in the DF1-1 and LD22-1 gas fields in the daipiric belt of the Yinngehai Basin. These gases contain 75–84.5% of hydrocarbons, with methane accounting for 73.54–83.48%. The non-hydrocarbon gases are mainly N2, with little CO2. The intermediate d13C1 values of these gases ( 49.3 to 54.3%) suggest the mixing of dominantly biogenic gas with small amounts

Fig. 3. Cross plot of d13C1 values vs. C1/C1 from Tissot and Welte (1984).

5

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of thermogenic gas, likely as the result of diapiric activity that brought deep thermogenic gas into the shallow biogenic gas reservoirs. 4.3. Group III. Thermogenic gas Thermogenic gas accounts for the overwhelming bulk of the proven gas reserves in the Ying-Qiong basins. On the d13C1 vs. C1/C1 5 plot, gases in this group fall into mature to highly mature categories (Fig. 3). Regardless of their contents of non-hydrocarbon components, these gases display high C1/C1 5 ratios (0.92–0.99), characteristic of thermogenic hydrocarbon gases generated from source rocks ranging in maturity from wet-gas to dry-gas zones. Isotopically, the d13C1 values of these gases range from 27 to 40%, about 5–20% more positive than the under-saturated, oil associated gases in the adjacent Beibuwan Basin (Zhang and Huang, 1991). Because the d13C2 values of the thermogenic gases in the Ying-Qiong basins ( 19.13 to 27.04%, Table 1) fall within the empirical range generally observed in the coal-derived gases in the Chinese basins (Xu, 1996; Fig. 4), we suggest that the source rocks for these gases contain dominantly humic organic matter deposited in a deltaic setting. This suggestion is supported by the

for the gas samples collected from the Ying-Qiong basins. The boundary lines are taken

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B. Huang et al. / Organic Geochemistry 34 (2003) 1009–1025

Fig. 4. Cross plot of d13C1 vs. d13C2 values for the gas samples collected from the Ying-Qiong basins. The boundary lines between different genetic groups are taken from Xu (1996).

relatively high benzene and toluene contents (15–50% of the C6 7 hydrocarbons) and high pristane/phytane ratios (Table 2) in the associated condensate oils (Fig. 5). High pristane/phytane ratios have been previously reported for oils derived from terrestrial source rocks in the Tarim (Li et al., 1999; Hanson et al., 2000) and Turpan basins in NW China (Li et al., 2001), and Gippsland Basin in Australia (Philp and Gilbert, 1986). Although the relative enrichment in benzene and toluene can be also caused by phase related compositional fractionation (Thompson, 1987), higher plant material is known to produce more aromatic components than oil-prone organic matter (Leythaeuser et al., 1979).

Qiongdongnan Basin and probably in northwestern Yinggehai Basin. Drilling results indicate that the Yacheng Formation consists of 40–70% of mudstones, ranging in thickness from 482.6 m to 910 m. These coalbearing sequence was formed on coastal plains, with thickness reaching up to 2500 m in central Yacheng Sag. The mudstones, carbonaceous mudstones and coals contain variable amounts of TOC, with Rock-Eval S1+S2 values ranging from 14 to 143 mg HC/g TOC (Fig. 6). Microscopic examination indicates that the kerogens contain 40 to 80% of vitrinite and inertinite with 10–30% amorphous organic matter, and thus are classified mainly into gas-prone type III and II2 kerogens (Zhang and Huang, 1991; Fu, 1995; Hao et al., 1995; Huang, 1998,1999). The d13C values of the kerogens range from 29.50 to 27.16%.

5. Geochemistry of possible gas source rocks 5.2. Miocene Meishan and Sanya formations As indicated by the results of regional geological and geochemical studies (Zhang and Huang, 1991; Fu, 1995; Hao et al., 1996, 1998; Huang, 1998, 1999), the likely candidates for effective petroleum source rocks in the Ying-Qiong Basins are distributed within the Oligocene Yacheng Formation and Miocene ShanyaMeishan formations. 5.1. Yacheng formation The Oligocene Yacheng and Lingshui formations developed mainly in the Paleogene half grabens in the

The Miocene includes Sanya and Meishan formations, as well as the lower part of the Huangliu Formation. The Miocene source rocks occur mainly in the Central Yinggehai Depression (CYD) (Fig. 1) and are composed of deltaic to neritic deposits. As no deep-wells have been drilled in the CYD, wells that encountered the Miocene rocks have been located mostly at the basin margins. The TOC contents in the Miocene shales from the basin margins are only 0.4–0.65%, but increase toward the CYD region. For example, samples of the Huangliu and Meisahn formations collected from the

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B. Huang et al. / Organic Geochemistry 34 (2003) 1009–1025 Table 2 Physical properties and selected molecular parameters for condensate oils produced from Ying-Qiong basinsa Well

Depth (m)

Yinggehai Basin DF113-3 1260–1268 DF114-1 1360–1375 DF115-3 1322–1326 DF115-2 1386–1410 DF118-4 1342–1405 DF118-3 1342–1358 DF119-3 1395–1410 L1512-2 1243–1258 L1513-2 1449–1455 L2012-1 1703–1720 L2111-D 1553–1566 L2211-3 1044–1052 L2211-2 1352–1385 L2213-1 1486–1496 L2216-2 1468–1482 L812-3 1194–1205 L812-1 1335–1352

Pr/Ph C27% C28% C29% C304 W+ OL/ S/ Fm. Gravity Sulphur Wax Viscosity 2,4-/2,3- T (%) 50  C mm2/s (g/cm3) (%) MS/C29S T/H30 H30 (S+R) DMP ( C) YGH YGH YGH YGH YGH YGH YGH YGH YGH YGH YGH Q Q YGH YGH Q YGH

Qiongdongnan Basin Y1311-3 3573–3586 LS Y1311-2 3658–3702 LS Y1312-5 3708–3725 LS Y1312-3 3888–3907 LS Y1314-5 3738–3743 SY Y1314-3 3898–3921 LS Y1313-5 3788–3817 LS Y1316-2 3901–3938 LS

0.7815 0.7763 0.7830 0.7884 0.7815 0.7845 0.7833 0.7954 0.8181 0.8095 0.8388 0.7484 0.7515 0.7891 0.7797 0.7861 0.7756

0.03 0.03 0.03 0.03 0.08 0.10 0.03 0.05 0.07 0.04 0.11 0.04 0.04 0.03 0.05 0.04 0.04

0.00 0.02 0.37 0.71 0.00 0.00 0.04 0.15 0.15 0.04 2.34 0.00 0.00 0.25 0.01 0.00 0.00

0.83 0.92 1.05 1.30 0.90 0.93 0.93 0.97 1.11 1.01 2.22 0.74 0.78 0.99 1.11 0.83 0.74

3.43 4.09 nd nd nd 4.98 nd 4.14 3.28 3.32 2.91 3.08 3.17 6.38? 2.98 3.20 3.05

0.8585 0.8530 0.8492 0.8460 0.8402 0.8508 0.7966 0.7989

0.06 0.05 0.04 0.05 0.01 0.01 0.01 0.02

10.68 12.88 6.98 21.07 5.68 4.73 3.01 3.15

2.01 2.64 1.61 3.54 1.76 1.83 0. 94 1.00

6.68 7.00 6.77 7.11 8.34 8.59 7.10 6.73

37.5 37.8 39.8 42.3 39.3 45.4 37.3 29.3 43.9 38.3 40.3 42.9 43.4 35.1 39.2 27.5 31.8

31.3 25.5 19.6 21.9 30.9 34.3 32.5 24.0 29.9 31.8 30.9 19.2 19.4 19.1 21.5 27.5 25.0

31.2 tr 36.7 0.16 40.6 1.18 35.8 1.21 29.8 0.39 20.4 tr 30.2 0.21 46.7 0.76 26.3 0.19 29.9 0.05 28.8 0.05 37.9 0.26 37.2 0.27 45.8 0.34 39.3 0.27 44.8 nd 43.2 0.21

tr tr tr tr tr tr 0.06 tr tr tr tr 0.03 0.05 tr tr tr tr

0.34 0.10 0.04 0.03 0.05 0.11 0.13 0.16 0.12 0.26 0.10 0.28 0.33 0.13 0.19 0.08 0.08

0.27 0.36 0.42 0.40 0.30 0.13 0.38 0.47 0.21 0.23 0.21 0.34 0.36 0.48 0.40 0.28 0.49

0.73 0.68 0.64 0.37 – – 0.63 0.54 0.63 0.57 0.44 0.52 0.54 0.53 0.61 0.59 0.69

135 134 133 125 – – 133 131 133 132 128 130 131 130 133 132 134

nd nd nd nd nd nd nd nd

nd nd nd nd nd nd nd nd

nd nd nd nd nd nd nd nd

4.70 5.10 3.46 3.96 1.27 4.92 2.98 4.21

2.30 2.40 1.86 1.84 0.41 2.00 1.12 0.87

nd nd nd nd nd nd nd 0.50

– 0.68 0.25 0.21 0.39 0.41 0.23 0.48

– 134 119 117 126 127 118 129

nd nd nd nd nd nd nd nd

a

Pr/Ph, pristane/phytane ratio; C27%, C28% C29%, relative percentage of C27, C28, and C29 steranes; C30MS/C29S, C30 4-methylsterane/C29 regular sterane ratio; W+T/H30, bicadinanes (W+T)/C30 hopane ratio; OL/H30, oleanane/C30 hopane ratio; S/(S+R), 20S/(20S+20R) ratio for C29 steranes; these ratios were calculated using peak areas in appropriate m/z 217 and 191 mass fragmentograms. 2,4/2,3-DMP and T( C), 2,4-/2,3-dimethylpentane ratio and hydrocarbon generation temperature calculated from this ratio using the method described by Bement et al. (1994). See Table 1 legend for formation abbreviations.

LD3011A and LD2217 wells contain 0.4–2.97% TOC (Zhang and Huang, 1991; Hao et al., 1995, Huang et al., 2002). The Miocene source rocks also contain type II2-III kerogens, similar to those in the Yacheng Formation. However, these Miocene source rocks contain more amorphous materials (30–80%), likely derived from degradation of phytoplankton and higher plant material (Venkatachala, 1981; Fu, 1995). The d13C values of the kerogens in the Miocene source rocks range from 24.41 to 22.30%.

6. Gas–source correlation for thermogenic gases in the Ying-Qiong basins Based on the following chemical and isotopic characteristics, we suggest that thermogenic gases in the Ying-Qiong basins were derived from two geographically separate petroleum systems. The gases in the

Yinggehai Basin were likely sourced from the Miocene marine shales within this basin, whereas those in the Qiongdongnan Basin came from the coal-bearing source rocks in the Yacheng Formation. 6.1. Aromatic contents and d13C values of toluene The relative concentrations of mononuclear aromatic hydrocarbons (benzene and toluene) in the gases of the Yacheng field are much higher than those in the Yinggehai Basin (Fig. 5), suggesting difference in the source facies for these gases. As organic matter in the Yacheng Formation coal-bearing strata was derived mainly from higher plants with abundant lignin and cellulose (Zhang and Huang, 1991; Huang, 1999), thermal maturation of these source rocks would be expected to produce higher proportions of aromatic components than the Miocene marine shales in the Yinggehai Basin.

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Fig. 5. Chemical compositions of C6-7 light hydrocarbons associated with the gas samples collected from the Ying-Qiong basins.

Fig. 6. Cross plot of TOC vs. Rock-Eval S1+S2 values for potential source rocks in the Oligocene Yacheng and Lingshui formations.

As demonstrated previously from laboratory simulation experiments (Li et al., 1998; Dong and Huang, 2001), the d13C values of toluene in natural gases and gas-condensates change with organic source facies and do not appear to vary with increasing thermal maturation and migrational fractionation. Fig. 7a shows that the d13C values of toluene generated from coal and shale samples of the Yacheng Formation during pyrolysis at

400 and 600  C are within 1%. The lack of fractionation in the stable carbon isotopic values of toluene under different thermal conditions is consistent with the high thermal stability of this molecule, thus providing a firm foundation for the use of this parameter in direct gas–source correlation. As shown in Fig. 7b, the d13C values of toluene in the thermogenic gases from the Yinggehai Basin correlate well with the shale pyrolytic

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Fig. 7. Application of the d13C values of toluene as a gassource correlation parameter: (a) the d13C values of toluene in the pyrolytic gases generated from a given source rock do not appear to change with pyrolysis temperature; (b) correlation of reservoir gases with those produced from laboratory pyrolysis of possible source rocks in the Ying-Qing basins.

gas of the Meishan Formation, supporting a possible genetic relationship. In contrast, the d13C values of toluene in the gases produced from the Yacheng field are significantly lower, and their close affinities with the pyrolytic gas from the coastal plain swamp source facies of the Yacheng Formation indicate that these gases could not have been derived from the marine shales in the Meishan Formation in the Yinggehai Basin. 6.2. Biomarkers and carbon isotopes of associated condensates The condensates associated with the gases in the Yacheng field are high in wax (7–21%) and density (0.85–0.86 g/cm3) (Table 2). These condensates are characterized by abundant terrigenous biomarkers such as oleanane, bicadinane (W and T—van Aarssen et al., 1992) and lupane (Fig. 8; Table 2), as well as cadinane and homocadinane in the sesquiterpane range. These diagnostic molecular markers for terrigenous angiosperm plants occur commonly in the coastal plain source facies in the Yacheng Formation (Fig. 8). In contrast, the condensates associated with the gases in the Yiggehai Basin have lower density (0.75–0.84 g/cm3) and wax content (mostly less than 0.5%). These condensates display a wide range in the 20S/20S+20R ratio for C29 steranes (0.13–0.47, Table 2), seemingly suggesting

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immature to mature sources. However, this suggestion contradicts the calculated C7 Mango parameters (Table 2; Mango, 1990). The hydrocarbon generation temperatures of 120–140  C (Table 2), estimated using the 2,3-/2,4-dimethylpentane ratios (Bement et al., 1994), suggest that the Yinggehai condensates and light oils were expelled from the source rocks at the mid to late oil window. It is interesting to note that the 20S/(20S+20R) ratio for steranes correlates inversely with the CO2 concentration in the gas (Fig. 9). This data suggests that biomarkers in the ‘‘immature’’ condensates are not indigenous, and were probably derived from the CO2 extraction of immature rocks en route or immediately underneath or above the gas reservoirs. If this suggestion was correct, the biomarkers present in those more mature condensates may be more representative of the mature source from which they were generated. The presence of moderate amounts of oleanane, sesquiterpanes and bicadinanes in these condensates indicates that they could not have been derived from the same source as the condensates in the Yacheng field (Fig. 8). The detection of C30 4-methyl steranes including dinosteranes of marine algal sources shows that these condensates correlate better with the Miocene neritic-delta source facies in the Yinggehai Basin, particularly in the Huangliu Formation (Fig. 8). This correlation is supported by the reasonable match in the d13C values of individual alkanes in these condensates and the kerogens in the Miocene marine shales (Fig. 10). The large discrepancy in thermal maturity observed from sterane ratios of the condensates (immature to marginally mature, Fig. 9) and co-producing gases (overmature, Fig. 3) is consistent with the mixing of deep gases derived from the Meshan-Sanya formations with less mature hydrocarbons generated from shallower sources in the Huangliu Formation. 6.3. N2 and CO2 contents The nitrogen contents in the natural gases from the Yinggehai Basin vary significantly and show inverse correlation with the d13C1 values. In the DF1-1 gas field, for example, the nitrogen contents in the gases drop from the 15–35% range to less than 10% when the d13C1 values of the gases changes from lower than 34% to higher than 33% (Fig. 11). This indicates that nitrogen generation from mudstones occurs mainly in relatively early thermal evolution stages, thus the amount of nitrogen generated from humic organic matter in mudstones decreases with increasing thermal maturity. As shown in Fig. 11, natural gases in the Yacheng field generally have much lower nitrogen contents, regardless of their d13C1 values. One possible explanation is that coal usually contains fewer amino compounds and trends to generate ammonia at low

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Fig. 8. Representative m/z 191 and 217 mass fragmentograms showing the correlation of gas condensates with potential source rocks. W and T: bicadinanes; O: oleanane.

thermal evolution stage and then convert it into nitrogen under oxidative conditions. As most of the earlygenerated nitrogen can be easily absorbed by coal, little free nitrogen is available for expulsion. The nitrogenous heterocycles in coal can generate some nitrogen only through cracking at post maturation stage (Littke et al., 1995). In northern Germany, for example, nitrogen-rich gas reservoirs containing more than 50% of nitrogen usually occur in high evolution zones (with >3.0%Ro) in the Carboniferous coal-bearing strata. Therefore, lower nitrogen content is normally expected from coalderived gases than from humic-rich mudstone derived

gases when the source rocks have not reached around 3.0%Ro. Most of the gases in the Yinggehai Basin contain more CO2 than those in the Yacheng field (Table 1). For natural gases with 51–71% of CO2 in the Yinggehai Basin, the d13CCO2 values range from 2.8 to 3.4%. The helium contents in these gases are only 5 to 45 ppm, with 3He/4He ratio ranging from 6.9910 7 to 9.810 8 (Dong and Huang, 1999; Huang et al., 2002), lower than the standard value for air (1.3910 6, Dai et al., 1996). These characteristics indicate that the abundant carbon dioxide in the Yinggehai Basin was mainly

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Fig. 9. Correlation of CO2 content in the gas with increasing 20S/(20S+20R) ratio for C29 steranes in the associated condensates in the Yinggehai Basin (data provided by Chevron Oil Company).

Fig. 10. Correlation of condensates with potential source rocks using the d13C values of individual n-alkanes.

of inorganic origin, probably derived from thermal decomposition of carbonate minerals in sediments, reaction of clay and carbonate minerals, or thermal decomposition of pre-Cenozoic carbonates (Dong and Huang, 1999).

6.4. Mercury contents Mercury contents in the gases from the Yacheng field range from 43 000 to 45 000 ng/m3, but only 1193 to 14219 ng/m3 in the gases from the Yinggehai Basin

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Fig. 11. Cross plot of d13C1 values vs. N 2 content (%) showing two distinct gas families in the study area.

(Dong and Huang, 2001; Table 1). As coals are known to contain higher mercury than mudstones and shales (Tu and Wu, 1986), these results provide further evidence for a more coaly source of the gases in the Yacheng field compared with the Yinggehai Basin.

7. Focused and episodic gas migration and accumulation in the Yinggehai Basin The YC13-1 gas field is the largest offshore gas field discovered in South China Sea. The source and migration on the gases of the field have been discussed extensively. Li (1994) thought that gases from the Yacheng Formation in the Yacheng Sag charged the YC13-1 field, whereas Zhang and Zhang (1989, 1991) believed that the gases were derived from the deep, hot, and over-pressured Miocene source rocks in the Yinggehai Basin. The latter authors also speculated that hydrocarbons dissolved in formation water charged the YC13-1 gas field along the No.1 fault and caused the abnormally high concentration of aromatic hydrocarbons (Zhang and Zhang, 1989, 1991). More recent work by Chen et al. (1998) indicated multiple sources for the YC13-1 gas field, with the first gas charge from the Yacheng Sag at approximately 5.5 Ma b.p. and the second charge from the Yinggehai Basin at about 2.0 Ma b.p. This explanation appears to be supported by the work of Hao et al. (1998). However, the generally low CO2 concentrations in the YC13-1 field gases and the recent discoveries of commercial gas-bearing structures (YC13-4 and YC13-6) in the Yanan Uplift (Fig. 1b) indicate that the majority of the gases in the YC13-1 field

were likely derived within the Qiongdongnan Basin, with only small amounts of contribution from the Yinggehai Basin (Dong and Huang, 2001). The DF1-1 gas field is the largest gas accumulation in the Yinggehai Basin, and the reservoirs are the Pliocene fine-grained sandstones and siltstones. The gas column, ranging from 1200 to 2000 m in depth, can be divided into five reservoir units (Fig. 12). As different reservoir units could trap gases from different source rocks or from the same set of source rocks with different maturity, the compositional heterogeneities preserved in the accumulated gases may reflect the migration and filling history of reservoirs (Schoell, 1993). On the basis of chemical and isotopic compositions of the produced gases and fluid inclusion data (Figs. 12 and 13; Table 1), the formation of the DF1-1 gas field most likely involved four different phases:  Phase I: Injection of biogenic gas. Biogenic gases derived from immature mudstones adjacent to the reservoir migrated into reservoir units # I and/or II, as observed from the DF118 well (Fig. 12). These gases are characterized by high CH4 contents (73.5–82.4%), and the lowest d13C1 values ( 54.1%). The distribution of biogenic gases is rather limited.  Phase II: Injection of early thermogenic gases. These gases are accumulated in the reservoir unit # I of the DF113 and DF114 wells. They are dominated by methane (about 75%), with 3 5% of C2+ hydrocarbons, 15–35% of N2 and minor amounts of CO2 (0.1 3%). The d13C1 values of these gases range from 40.45 to

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Fig. 12. Cross sections through the DF1-1 gas field, showing the inter-reservoir gas compositional heterogeneities. The locations of the sections are shown in Fig. 1.

Fig. 13. Correlation of d13C1 values with CO2 content in the gases studied (a) and the histogram of homogenization temperatures of fluid inclusions from the DF1-1 gas reservoirs (b).

38%, and correspond to a source maturity of 0.8–1.4%Ro (Dong and Huang, 1999). As the measured maturity of the reservoir rocks is currently only 0.3–0.45%Ro, these gases migrated into the shallow reservoirs from deeper source rocks.  Phase III: Injection of late thermogenic gases generated from peak gas window. Compared with the early thermogenic gases, these gases originated from deeper source rocks with higher maturity, and are characterized by higher d13C1 values ( 36.5 to 34.6%) and higher dry coefficient (C1/C1-5=0.95  0.97).  Phase IV: Injection of CO2-rich gases. These gases were generated from much deeper source rocks, consisting of 55 to 70% of CO2, 4.7 to 7% of N2, and 23 to 37% of gaseous alkanes. The reservoirs were typically connected with diapiric faults (e.g. reservoir unit # III in the DF112 well

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and unit # II in the DF117 well). The gases have the d13CCO2 value in the range of 3.4 to 2.8% and 3He/4He ratio of 0.5410 7 to 13.4710 7, and the d13C1 values of 33.9 to 31.7% (Fig. 13a). The CO2 was likely derived from inorganic minerals and the hydrocarbon gases from high to post-mature source rocks.

Fluid inclusion data have been widely used to study reservoir filling-processes (Karlsen et al., 1993; Roberts and Nunn, 1995; Dong and Huang, 1999). The compositions and homogenization temperatures of fluid inclusions from the reservoirs in the DF1-1 gas field support these four phases of gas migration and accumulation (Fig. 13b). According to Dong and Huang (1999), the phase A inclusions were formed when biogenic gases migrated in situ into the reservoirs. The phases B and C inclusions trapped gases derived from the early gas zone and peak gas window, respectively. In contrast, the phase D inclusions with homogenization temperatures above 200  C are believed to have been associated with the formation and migration of CO2-rich gases from the deep source rocks. Because the CO2-rich gases migrated into the reservoirs later than hydrocarbon-rich gases, exploring the early-formed traps and sand reservoirs separated from the shale diapirs may significantly reduce the risk of encountering CO2-rich gas. Recent work (Huang, 1998; Dong and Huang, 1999; Hao et al., 2000) indicates that the focused and episodic migration was largely responsible for the large gas accumulation in diapric structures of the Yinggehai Basin within very short time spans (1–3 Ma).

8. Thermal maturation and hydrocarbon generation models The rapid subsidence during the Neogene to Quaternary times brought the Yacheng Formation to its present depth of 4000–7000 m in sags in the Qiongdongnan Basin. Influenced by post-rift rapid thermal subsidence, strong overpressure and high geothermal gradients (3.9–4.0  C/100 m) developed in the Yacheng, Songnan, Baodao, Lingshui and Ledong sags. Results of 1-D basin modeling indicate that the Yacheng Formation in the Yacheng Sag reached the peak gas generation window during the mid Miocene-Pliocene time (Fig. 14 a) after the deposition of Upper Oligocene to Lower Miocene sandstone reservoirs in the Qiongdongnan Basin (Gong and Li, 1977). In the Central Yinggehai Depression, the geothermal gradient is up to 4.2  C/100 m. Thermal history modeling for the LD8-1-M well indicates that the lower part of the Huangliu Formation to the upper part of the Sanya Formation are currently mature to highly

Fig. 14. Burial history curves for source rocks at the depocenters of the Yacheng Sag (a) and Central Yinggehai Depression (b).

mature, whereas the lower part of the Sanya Formation is overmature (Fig. 14b). The main source rocks, Meishan and Sanya formations, reached their peak gas generation window during the Pliocene-Quaternary time in the center of the Yinggehai Basin, thus providing abundant gas supplies to charge the Pliocene reservoirs in recently formed shallow diapiric structures. The Meishan and Huangliu formation in the large part of the Central Yinggehai Depression and Yacheng Sag are over-pressured, with the top of the over-pressured zone at the depth of about 3000 m (Gong and Li, 1997, Dong and Huang, 2000). In a normal pressure zone away from mud diapiric structures (e.g. LD30-11A and YC35-1-1 wells), thermal maturity reaches 0.6%Ro or 135  C at the depth of 3000 m (Zhang and Huang, 1991; Hao et al., 1995). This temperature is 30

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to 50  C higher than those at equivalent depth in other sedimentary basins in eastern China. In areas intensely affected by the migration of deep-sourced hot fluids, such a temperature was reached even at shallower depth, e.g. about 2650 m in the DF111 well (Hao et al., 1995). Strongly over-pressured system often leads to the retardation of thermal maturation and hydrocarbon generation. This has been observed clearly from several wells drilled in the Ying-Qiong basins (Hao et. al, 1995; Huang et al., 2002). For example, retarded thermal maturation in the LD30-1-1A well was observed to occur below 3900 m, whereas the equivalent depth in the YC35-1-1 well is 4200 m (Huang et al., 1998). The strongly over-pressured zones have pressure coefficients of 1.4 to 1.6, consistent with the results reported from the modeling experiments (Hill et al., 1994; Price and Wenger, 1992). In the Ying-Qiong basins, overpressure can be early authigenic and late allogenic. The early authigenic overpressure, caused by rapid sediment loading, developed in mud-dominated stratigraphic intervals when organic matter was immature and marginally mature. The late allogenic overpressure developed in interbeded sands and mudstones and did not obviously restrain thermal evolution of organic matter. This is why in some basins characterized by overpressure, thermal evolution of organic matter was normal (Hao et al., 1998). Geochemically, pressure’s restraint on thermal evolution of organic matter and hydrocarbon generation is to decrease thermal maturation rate of organic matter in overpressured zone. Therefore, in a strongly over-pressured system, the organic matter would remain in pseudo-metamorphic stage within the ‘‘gas window’’ for a prolonged time, thus enhancing gas potential. On the other hand, in sealed high pressure and high temperature formations, the abnormal pressure would continuously increase. When the pressure reaches a critical value, the top or lateral seal of over-pressured zone would be broken, resulting in the expulsion of overpressured fluids. Obviously, when pressure accumulated, the natural gas in the compartment also started to accumulate (Dong and Huang, 1999, 2001). Such focused and episodic migration of hydrocarbon significantly improved hydrocarbon expulsion efficiency (Huang et al., 1998; Dong and Huang, 1999; Hao et al., 2000). The Ying-Qiong basins contain abundant natural gas resources. It is estimated that the gas potential indices (GPI) in various sags of the Qingdongnan Basin and in the Central Yinggehai Depression were in the order of 3.62109 8.35109 and 8.22109 m3/km2, respectively. As all of the large to medium gas fields discovered in China occur in the region with GPI > 20108 m3/km2 (Dai et al., 1997), there is high potential for discovering more giant gas fields in the Ying-Qiong basins.

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9. Conclusions This study demonstrated that three types of natural gases occur in the Yinggehai and Qiongdongnan basins offshore South China Sea, among which thermogenic gases are dominant. The thermogenic gases in the Yacheng field of the Qiongdongnan Basin can be differentiated both chemically and isotopically from those in the Yinggehai Basin, suggesting that they were derived from two different source systems. Gas-source correlation results indicate that the gases in the Yinggehai Basin most likely originated from humic organic matter in the Miocene neritic mudstones within the basin, and subsequently accumulated through vertical migration and episodic charging. In contrast, the gases in the Yacheng field are related mainly to the coal-bearing strata of the Yacheng Formation in the Qiongdongnan Basin, through short distance lateral migration. While source rocks in normal pressure systems underwent rapid thermal maturation, there are clear indications for a significant delay of thermal evolution and hydrocarbon generation in strongly over-pressured source systems. The Yinggehai-Qiongdongnan basins show high gas potential indices (3.62109 to 8.35109 m3/ km2). The peak gas generation in the Miocene source rocks in the Yinggehai Basin occurred during Pliocene to Quaternary. For the Yacheng Formation in the Qiongdongnan Basin, this occurred from Middle Miocene to Pliocene. The very late peak gas generation, coupling with the good matches in the timing of the trap formation, provided favorable conditions for the accumulation of large natural gas reserves.

Acknowledgements We are extremely grateful to Dr. Maowen Li of Geological Survey of Canada who helped to polish the English writing. Drs. Maowen Li, Fang Hao, and Mark Obermajer are thanked for providing constructive comments on an early version of this manuscript We also extend our thanks to Mr. Yiwen Huang and Li Li for providing valuable assistance on this paper. This study was undertaken as part of the Chinese state project 973 (contract No. G1999043308). It was also supported by the Chinese Academy of Sciences (Project No.: KZCX12-110).

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