Formation mechanisms of secondary hydrocarbon pools in the Triassic reservoirs in the northern Tarim Basin

Marine and Petroleum Geology 46 (2013) 51e66

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Formation mechanisms of secondary hydrocarbon pools in the Triassic reservoirs in the northern Tarim Basin Guangyou Zhu a, *, Jin Su a, Haijun Yang b, Yu Wang a, Anguo Fei a, Keyu Liu a, Yongfeng Zhu b, Jianfeng Hu b, Baoshou Zhang b a b

PetroChina Research Institute of Petroleum Exploration and Development, Beijing 100083, China Research Institute of Petroleum Exploration and Development, Tarim Oilfield Company, PetroChina, Korla 841000, China

a r t i c l e i n f o

a b s t r a c t

Article history: Received 25 August 2011 Received in revised form 8 June 2013 Accepted 8 June 2013 Available online 18 June 2013

The northern Tarim Basin (Tabei) is a rich composite hydrocarbon accumulation region with multi-layers of oil and gas reservoirs in the Ordovician, Carboniferous and Triassic strata. In the Triassic, the Tabei region was dominated by non-marine sedimentation that developed deltaic sandstone reservoirs with favourable petrophysical properties for hydrocarbon accumulations. Hydrocarbons in the Triassic hydrocarbon pools are dominated by oil and condensate gas. Analysis of the hydrocarbons, in combination with well testing and drilling data, reveals that oils in the Triassic hydrocarbon pools are commonly biodegraded and originated mainly from the middle-upper Ordovician source rocks. The predominant dry gases in the reservoirs are cracked from oils derived from the Cambrian source rocks. The origin of hydrocarbons in the Triassic pools is similar to those in the underlying reservoirs. Fluid inclusions and KeAr dating confirm that the hydrocarbons were accumulated during the Himalayan orogenic movement. Because the middleeupper Ordovician source rocks already experienced peak hydrocarbon generation in the late Hercynian orogeny (late Permian), the Triassic hydrocarbon pools are from secondary adjustment of earlier oil and gas pools from the underlying Ordovician and Carboniferous reservoirs. Due to the rapid subsidence of the Kuqa foreland basin to the north of the Tabei region since the beginning of the Himalayan orogenic movement, the Triassic reservoir strata was changed from south-dipping to north-dipping, resulting in the formation of plunging anticlines and hydrocarbon migration toward the south. At the same time, fault reactivation occurred in the area, causing the hydrocarbons from the deeper reservoirs to migrate into the Triassic structural traps through faults and unconformities, and thus formed the widespread secondary hydrocarbon pools. The structure inversion during the Triassic and the formation of nose structures since the Himalayan orogeny (250 w 290 Ma, Permian) controlled the secondary accumulation in the Triassic reservoirs. The reformation process of the hydrocarbon pools continued until the late Himalayan orogeny when the gas was charged and developed condensate pools in the eastern area. Ó 2013 Elsevier Ltd. All rights reserved.

Keywords: Triassic Non-marine reservoir Secondary hydrocarbon pool Tabei area Tarim Basin

1. Introduction Hydrocarbon pooling is primarily controlled by tectonic and structural evolution of a basin (England et al., 1987; Luo et al., 2008; Tissot and Welte, 1984; Hooper, 1991). As a result, re-migration and re-distribution of oil and gas occur frequently in superimposed basins (Zhang et al., 2011). In general, hydrocarbon pools formed by a consecutive process of oil and gas generationemigratione accumulation are known as primary hydrocarbon pools (Ping and Chen, 2009; Zhao et al., 2010). Secondary hydrocarbon pools are

* Corresponding author. Tel.: þ86 10 8359 2318. E-mail address: [email protected] (G. Zhu). 0264-8172/$ e see front matter Ó 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.marpetgeo.2013.06.006

reservoirs accumulated by re-migration and re-distribution of hydrocarbons from primary hydrocarbon pools, or ‘discrete-migration’ of secondary migration (Silverman, 1965). Secondary oil and gas pools are therefore defined as hydrocarbons re-migrated from existing primary reservoirs as a result of tectonic and structural destruction, leading to accumulations in new traps. Secondary oil and gas pools are widespread in superimposed basins in western China (Jia et al., 1995; Zhang et al., 2007a; Zhu and Zhang, 2009; Zhu et al., 2010). The Triassic stratigraphic interval in the Tarim Basin, which consists of terrestrial deposits, is rich in hydrocarbons derived from the Cambrian and Ordovician marine source rocks (Zhang et al., 2000, 2002a; Wang and Xiao, 2004). Since the late Hercynian orogeny (250 w 290 Ma, Permian), oil and gas pools have been redistributed in the Tarim platform-depression

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transitional belt, i.e. hydrocarbons from the Ordovician primary reservoirs migrated upward through faults and/or unconformities forming multiple hydrocarbon pools with diverse geochemical signatures. The secondary hydrocarbon pools are mostly developed in subtle stratigraphic and/or lithological reservoirs and are extremely difficult targets for exploration. Therefore, reconstruction of the oil and gas accumulation process in the Triassic pools has a theoretical and practical significance in the study area. 2. Geological setting The Tabei area is located in the uplifted region of the northern Tarim Basin. The Tabei Uplift is a first order tectonic unit and is rich in petroleum (Wang, 2004; Lü et al., 2008a). Geographically the uplift is located south of the Kuqa Depression and north of the Manjiaer Sag, and has an area of about 36.6  103 km2. It comprises the Nanka-Yingmaili Low Uplift, the Halahatang Depression, the Lunnan Low Uplift, the Caohu Depression, and other secondary structures from west to east (Fig. 1). The Tabei Uplift had evolved through a number of stages including the formation of (1) the PreSinian basement, the SinianeOrdovician rift (during the Caledonian period), (2) the SilurianePermian uplift and evolution during the Hercynian orogeny (250 w 290 Ma, Permian), (3) the Triassice Jurassic foreland basin (forebulge) during the Indo-China orogeny, (4) the CretaceouseNeogene extensional stage during the Yanshan orogeny, (5) the late NeogeneeQuaternary rapid subsidence (foreland basin) during the Himalayan orogeny. The Tabei area was uplifted during the early Caledonian orogeny with the entire Upper Ordovician strata being eroded in most areas. During the early Silurian, the northwestern part was uplifted and exposed, while the middle-eastern part was subsided. During the middle-late Silurian, the entire Tabei area was uplifted and exposed, forming a palaeo-morphological high in the east and morphological low in the west. During the early Hercynian orogeny (about 400 Ma ago), the crust subsided and sedimentation started since the Carboniferous, forming regional angular unconformities between the Carboniferous and underlying SilurianeDevonian strata in the Manjiaer and the Tabei area (Lü et al., 2008b; Zhu et al., 2011a). The basin entered into a regression stage since the late Hercynian orogeny and became an interior basin. Fluvialelacustrine facies were then deposited, including arenaceous pelitic, gypsum and clastic sediments. Since the Indo-China orogenic movement (from the Triassic to the Quaternary) the Tabei area (Fig. 1) has been dominated by terrestrial deposition (Jia et al., 1995). During the Hercynian orogeny, mediumesmall scale thrust faults were well developed within the Tarim Basin, mostly with eastewest strike and parallel to the Luntai Fault. They are distributed in the top of the anticline structure of the buried hills and obliquely crossing the buried hills. The Tabei area experienced a NEeSW shear stress during the Indo-Chinese orogenic epoch and formed a series of normal faults trending NNE, which led to the reactivation of thrust faults during the Hercynian orogeny. During the Yanshan-Himalayan orogenies (approximately 140 Ma to now), extensional, small and short extended faults were developed. Sustained activities and multi-phase superposition of the faults formed the present-day faults system (Fig. 1). The shallowest zone that faults can reach is the top pay, so faulting is one of the key factors that controlled the formation of oil and gas pools in the Tabei area. The complex faults system caused multi-stage hydrocarbon accumulations and a complex distribution patterns, and thus presented an enormous challenge in hydrocarbon exploration in the region. The Lunnan region comprises multi-layered oil and gas pays including the Ordovician, Carboniferous, Triassic and Jurassic

reservoirs with proven reserves of more than 7.3 billion BOE (barrels of oil equivalent) (Yang and Han, 2008). Hydrocarbons discovered within the Triassic reservoirs are mainly distributed in the eastern part of the Tabei area, the Lunnan Low Uplift region (referred as the Lunnan region) (Fig. 1). In this paper we primarily focus on the Lunnan region to elaborate the formation mechanism and the distribution of the Triassic oil and gas pools in the northern Tarim Basin. The Triassic stratigraphic interval comprises alluvial fan-braided river delta-lacustrine depositional systems (Fig. 2), with a thickness of 380 m. Being influenced by the Triassic Luntai fault in the Lunnan area, the differential elevations on both sides of the fault are large enough to cause the alluvial fan entering directly into the lacustrine basin developing fan-deltas (Gu and He, 1994). The fan deltas can be divided into three sub-facies including fan delta plain, fan delta front and pro-fan delta. The distributary channel sands in the fan delta front are the major oil and gas reservoirs. There are many trap types in the Triassic sequence, including low amplitude structural traps, lithologic traps and composite traps (Fig. 2). The structural traps generally have low amplitude and a small areal closure (Table 1). The lithologic traps are mainly controlled by facies change and sand bodies pinch-out, with the sand body thickness being mostly thinner than 20 m. The original reservoir (formation) pressure is between 45 and 60 MPa with average pressure coefficients of 1.1. Reservoir temperatures range from 100 to 140  C. The average geothermal gradient is 2.24  C/ 100 m. Figure 1 it appears that the Triassic pools are dominated by oil pools. The occurrence of gas condensates is restricted to the southeastern area around Jilake. 3. Characteristics and distribution of the Triassic oil and gas pools 3.1. Sedimentary setting and reservoir distribution In the Lunnan region, the Triassic stratigraphic interval was characterized by a sedimentary system of lacustrine transgression, forming retrograding fan delta sequences, which are dominated by fining-upward sequence, thinning sand thickness and decreasing sand-shale ratio. In the southern part sandstones become thinner (Pang and Zhen, 2008). The Triassic sequence is composed of 4 sets of mudstone units interbedded with 3 sets of sandstone (conglomerate) units. According to the oilfield development plan, the three sets of sandstone (conglomerate) units are divided into three oil-bearing formations: TI, TII, TIII (from top to bottom). These three oil formations were composed of several fining-upward cycles (Fig. 2). The TIII oil formation is characterized by thick sand bodies, widespread distribution and good lateral continuity. The sandstones of TII oil formation is characterized by thin, confined and isolated sand bodies with poor lateral continuity. The TI oil formation sand has a stable distribution and a rapid lateral variation. The TI and TIII oil formations are important oil production horizons (Table 1), with thickness of 16e60 m and 100e150 m, respectively. 3.2. Sedimentary and reservoir characteristics The Triassic reservoir sand bodies consist of distributary channel fillings and distributary channel month bar deposits. The reservoir rocks are mainly gray fine, medium-coarse argillaceous sandstone with low mineralogical and textural maturity. Quartz content ranges from 40% to 60%, feldspar is less than 20%, and clay is dominated by illite and chlorite. Storage space in the sandstones is dominated by secondary dissolution pores, including intergranular and intragranular dissolved pores, followed by primary pores. From

G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

Figure 1. Tectonic and structural units and the occurrence of Triassic oil and gas pools in the Tabei Uplift.

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Figure 2. Generalized strata column and cross-section of typical Triassic hydrocarbon pools in the Tabei area showing the petroleum system elements and reservoir properties.

north to south the reservoir qualities become progressively better, with the best reservoir being located at the southern slope of the Lunnan region, followed by the Sangtamu Fault Zone. The reservoir qualities generally become poor upward. The three oil pays are all deeply (>4500 m) buried reservoirs with high-porosity (15e28%) and high-permeability (10e4000  103 mm2) (Fig. 3). The well preserved deeply buried (>4500 m) high quality reservoirs are

related to a low geothermal gradient and long-term uplift setting in the region (Gu and He, 1994). From the late Triassic to the early Tertiary, the Triassic reservoirs were buried in the depth range of less than 1500 m with a temperature less than 50  C. The Triassic reservoirs were not deeply buried until the Pliocene, when the area experienced a rapid burial leading to a high geo-temperature diagenetic environment. Diagenesis occurred quite late and not

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Table 1 Characteristics of the structural traps in Tabei area. Reservoir name

Structural form

Layer

Strike

Closed area (km2)

Closed height (m)

The average thickness of oil layer (m)

Reservoir area (km2)

Major oil and gas wells

Jilake condensate gas field

Faulted anticline Faulted anticline Minor axis anticline

TII TII TI TII TIII TI

NWW w SEE NWW w SEE NS

55.00 37.00 10.50 10.00 9.90 1.45 1.38 1.00 3.07 3.02 1.29 3.46 2.47 3.51 5.72 4.02 1.01 7.87 3.74 2.96 26.13 20.20 21.69

30.0 20.0 20.0 35.0 20.0 20.0 25.0 15.0 20.0 25.0 10.0 30.0 35.0 20.0 35.0 30.0 12.5 20.0 35.0 25.0 63.0 38.0 35.5

22.0 5.1 6.0 18.3 4.3 5.0 23.0 9.0 11.0 2.9 1.0 26.5 27.5 16.0 31.0 28.0 9.5 4.1 6.0 20.0 10.2 6.8 7.8

41.5 11.0 6.0 8.0 3.0 1.4 1.2 0.7 2.2 13.5 7.0 3.2 2.4 3.0 5.3 3.8 0.9 5.0 3.7 2.3 24.9 15.3 16.1

JL109, LN57 etc. JN4, JN401 etc. LN55, JF100 etc. JF100, JF132 JF100, JF132 LN14, LN48 etc. LN22, JF127 etc. LN23 etc. JF121, JF126 etc. N39, JF123 etc. LN44 etc. LN14 LN22 LN23 JF121 LN39 LN44 LN1, LN101 etc. LN10, LN25 etc. LN26 etc. LN2, LN3, LN5 etc. LN3, LN5 etc. LN3, LN204 etc.

Eastern Jiefangqu oilfield

Sangtamu oilfield

Central Platform oilfield Lunnan oilfield

Anticline þ Lithology Fault nose þ Lithology Fault nose Anticline Fault nose þ Lithology Half-anticline Dome-shaped anticline Minor axis fault anticline Fault nose Minor axis fault anticline Fault nose Fault block Dome-shaped anticline Dome-shaped anticline Fault nose Minor axis anticline Minor axis anticline Minor axis anticline

TIII

TIII TI TI TI TII TIII

NEE NEE NWW NWW NWW EW EW EW EW EW EW EW EW EW EW EW EW EW

intensive. The reason why high porosity and permeability has been preserved might also relate to the timing of oil charging, since the presence of oil may inhibit mineral dissolution/precipitation (diagenesis) (Stuart Hazeldine reference). 4. Samples and experimental methods Sixteen crude oil samples and 13 samples of oil-bearing reservoir rocks from the Lunnan region were collected for a range of geochemical analyses including bitumen compositions, biomarkers, gas compositions and carbon isotope compositions. Fluid inclusions analyses were carried out on 6 samples; and KeAr dating of authigenic illite was conducted on 5 bituminous sandstone samples. In addition, we also collected physical properties of crude

oils, natural gas component and formation water composition data of 120 wells in the Tarim Oilfield, as well as some natural gas carbon isotope data, in addition to drilling and well testing data of these wells. The analytical conditions were as follows: GC analysis was performed on the oil and condensate samples using a HP7890A instrument equipped with a HPDB-5 silica gel column (J & W 122-532, length 30 m, diameter 0.25 mm, film thickness 0.25 mm). The oven temperature was programmed initially at 40  C and kept for 2 min, then increased to 310  C by 6  C/min and the temperature was held at the final temperature (310  C) for 40 min. Gas carbon isotope ratios were analyzed by the Thermo Delta V Advantage instrument. A Trace GC Ultra was used to fractionate the components, and the temperature was initially held at 33  C, programmed to 80  C at the rate of 8  C/min and finally programmed to 250  C at the rate of 5  C/min and held isothermally for 20 min. GC Combustion III was the transfer interface and the temperature of the oxidizing oven was kept at 980  C and that of the reducing oven was 640  C. A Delta V Advantage IRMS was used to acquire mass spectral data from the GC by using 3.07 kV electron impact ionization. Detailed accounts of the conventional KeAr dating technique have been given by Faure (1986), and Dickin (1995). In this research, KeAr isotope age determinations were performed on a MM 5400 static vacuum mass spectrometry instrument. 5. Geochemical characteristics of hydrocarbons and their origin 5.1. Crude oils

Figure 3. Porosity variation with permeability in Triassic reservoir of the Lunnan region.

5.1.1. Physical properties Crude oils from the Triassic pools have wide range of physical properties. The oil densities range from 0.745 to 0.945 g/cm3 (average: 0.85 g/cm3). Oils from the Jilake structure are the lightest and are mainly condensate or light oils. Crude oils from the Sangtamu Fault Zone and some sites on the Central Platform are mostly heavy crude oils with densities up to 0.94 g/cm3 (Table 2). The

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G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

Table 2 Physical and chemical properties of selected Triassic crude oils in the Tabei area. Block

Well

Well depth (m)

Well depth (m)

Layer

Density (g/cm3)

Kinematic viscosity of 50  C (mPa s)

Jilake

JN1 JN4 JL105 JL102 JL101 JL110 LN57 JL109 JL106 LN58 JL103 JL103 LN53 LN53 Average LN55 LN55 JF135 JF100 JF131 JF131 JF100 JF100 JF134 JF135 JF131 JF132 JF100 JF100 JF138 Average LN14 LN48 LN22 JF121 JF123 LN39 LN44 JF127 LN14 JF127 LN51 LG13 LN23 LN22 JF128 LN39 LN54 JF124 LN44 Average LG31 LN18 LG8 LN1 LN101 LG31 LN101 LN18 LG202 LG801 LG8 LN1 Average LN24 LN10 LN10 LN4 LN31 LN30 LN2 LN3 LN3

4131.0 4315.0 4334.0 4336.0 4346.0 4333.0 4338.5 4334.0 4321.5 4335.5 4315.0 4341.5 4343.0 4315.0

4139.0 4320.5 4341.0 4342.0 4348.0 4336.0 4341.5 4343.5 4327.0 4349.0 4345.0 4345.0 4346.0 4355.0

TI TII TII TII TII TII TII TII TII TII TII TII TIII TIII

4264.1 4290.0 4262.0 4250.5 4250.5 4278.0 4406.0 4417.0 4409.5 4419.0 4418.0 4419.5 4473.0 4430.0 4556.0

4278.8 4296.0 4267.5 4256.5 4255.0 4287.0 4412.0 4425.0 4419.0 4422.0 4424.0 4422.0 4475.5 4433.0 4563.0

TⅠ TⅠ TⅠ TⅠ TⅠ TⅠ TⅡ TⅡ TⅡ TⅡ TⅡ TⅡ TⅢ TⅢ TⅢ

4430.0 4446.0 4446.5 4501.0 4549.0 4546.5 4602.0 4548.0 4609.8 4607.0 4619.0 4765.8 4633.5 4620.5 4692.0 4699.0 4715.0 4735.0 4763.0

4436.9 4452.0 4456.0 4505.0 4557.0 4559.0 4617.0 4552.0 4625.8 4613.0 4624.0 4787.4 4651.0 4628.0 4697.0 4711.0 4719.0 4744.0 4769.0

TⅠ TⅠ TⅠ TⅠ TⅠ TⅠ TⅠ TⅡ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ

0.8902 0.7634 0.7618 0.7616 0.7535 0.7578 0.7620 0.7605 0.7454 0.7609 0.7615 0.7548 0.8499 0.8740 0.8146 0.8813 0.8506 0.8567 0.8873 0.8847 0.8392 0.7470 0.7904 0.8713 0.8743 0.8755 0.8641 0.8953 0.8847 0.8485 0.8567 0.8833 0.8832 0.8567 0.8796 0.8772 0.8716 0.8555 0.7727 0.8460 0.8567 0.9176 0.8517 0.8980 0.9294 0.9284 0.9437 0.9290 0.9283 0.8335 0.8812 0.8837 0.8576 0.8836 0.8859 0.9144 0.8634 0.9453 0.8689 0.8731 0.9311 0.8945 0.8027 0.8837 0.8494 0.8510 0.8528 0.8464 0.8837 0.8603 0.8737 0.8855 0.8392

19.3400 0.9963 1.0330 1.0170 1.2730 0.9696 1.5950 1.3110 0.8331 1.0950 1.0360 0.9400 4.3600 11.0000 3.34 17.2300 6.2400 7.6710 21.5400 18.6600 4.2600 0.8800 1.9500 10.9700 12.0500 12.4400 9.7920 23.8800 15.7300 6.0820 11.29 17.3500 16.3700 7.9800 15.8800 14.0400 10.8500 8.3000 1.1340 4.4800 5.4310 44.7200 5.5850 53.7200 100.1100 94.8100 173.2100 326.8600 82.6100 2.6200 51.90 16.9800 7.7700 16.8600 14.2500 73.6900 8.0200 150.3300 9.2900 11.6800 0.9137 25.7600

Jiefangqu

Sangtamu fault-horst zone

Central platform

Lunnan fault-horst zone

4741.0 4710.0 4743.5 4751.0 4753.0 4894.0 4910.0 4836.0 4858.0 4869.5 4890.0 4913.0

4746.5 4714.0 4745.5 4771.0 4758.0 4910.5 4915.0 4845.0 4863.0 4876.0 4896.0 4926.0

TⅠ TⅠ TⅠ TⅠ TⅠ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ

4740.0 4722.0 4722.0 4786.5 4741.0 4728.0 4740.0 4732.5 4796.5

4745.0 4754.0 4734.0 4792.5 4746.5 4732.0 4759.0 4784.5 4809.0

TⅠ TⅠ TⅠ TⅠ TⅠ TⅠ TⅠ TⅠ TⅠ

30.50 5.0900 6.4530 6.5960 4.6400 16.9800 7.3100 10.4200 17.0300 3.8600

Wax content (%) 9.10 8.04 0.30 2.80 3.12 5.40 5.30 5.00 2.12 4.50 4.40 1.90 3.30 2.44 4.12 6.32 4.07

Sulfur (%)

Resin þ asphaltene (%)

Total acid number (mg KOH/g)

Free-zing point ( C)

Initial boiling point ( C)

1.31 0.07 0.59 0.03 0.01 0.06 0.05 0.08 0.10 0.04 0.01 0.10 0.36 0.23 0.22 0.59 0.32 0.57

15.40 0.14

0.41

18.0 14.0 20.0 18.0 14.0 18.0 26.0 18.0 20.0 <-30 18.0 26.0 0.5 10.5 15.4 4.5 8.0 2.0

78.0 66.0 61.0 61.0 81.0 51.0 58.0 61.0 52.0 71.0 54.0 50.0 92.0 82.0 65.6 72.0 85.5 91.0 90.0 113.0 70.0 50.0 50.0 75.0 78.0 140.0 88.0 115.0 92.0 104.0 87.57 74.0 70.0 72.0 117.0 95.0 125.0 105.0 71.0 103.0 89.0

0.04 0.02

0.70 0.12 1.40

14.80 18.96 7.36 21.48 13.75

0.03 0.06 0.07 0.23 0.04 0.02

0.10

0.42

3.03

0.19 0.13

11.10

6.96

0.66 0.60 0.14 0.06

9.15

3.99 5.90 5.05 6.20 4.64 7.30

0.24 0.59 0.37 0.89 0.14 0.45

20.66 6.30 13.74 12.60 21.49 6.70

4.06 5.56 1.60 4.55 3.80 6.00 9.57 4.61 4.33 5.42

0.21 0.35

10.33 11.99 0.00 8.57 10.60 18.90 6.02 31.47 27.72 21.45

0.28 0.35 0.36 0.86 0.43

4.44 1.70 4.92 4.23 3.30 12.84 6.76 3.77 4.88 3.72 6.60 6.70 9.74 3.72 6.02 3.21 8.20 1.25 4.23 5.97 4.52 2.00 6.71

0.28 0.92 1.36 0.54 1.31 1.38 0.95

1.51 0.60 0.78 0.41 0.26 1.69 0.24 0.32 0.43 0.48 1.37 0.75 0.66 0.36 0.40 0.24 0.26 0.39 0.65 0.57 0.34

15.57 13.49 14.46 22.30 13.43 6.51 19.63 18.92 32.19 11.95 6.10 19.60 9.66 16.03 8.34 5.90 11.07 22.30 14.79 17.44 13.20 8.72

0.07 0.14 0.83

15.0 6.0 16.5 17.5 4.0 2.0 13.5 12.0 9.5 10.5 6.0 5.07 8.0 20.0 2.0 5.0 18.0 15.0 4.5 30.0 7.5 <-30 24.0 10.5 11.0 20.0

0.45

20.0 12.25

83.5 113.0

78.0 91.96

6.0

127.0

32.0

73.0

1.04

18.0 6.0 4.0 24.5 11.75

103.0 119.0 98.0 82.0 100.33

1.68 0.65

0.0 2.0

94.0 84.0

0.44

1.5 28.0

78.0 88.0

1.32 0.75

G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

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Table 2 (continued ) Block

Well

Well depth (m)

Well depth (m)

Layer

Density (g/cm3)

LN3 LN5 LN33 LN26 LN201 LN5 LN203 LN204 LN206 LN206 LN204 LN208 LN209 LN209 LN203 LN5 LN3 LN30 LN31 Average

4881.0 4741.0 4781.0 4831.4 4800.5 4796.5 4841.0 4782.0 4819.0 4819.0 4867.0 4848.0 4866.5 4866.5 4883.5 4873.0 4881.0 4860.0 4894.0

4888.5 4743.4 4796.8 4856.7 4802.0 4801.5 4844.5 4788.5 4838.0 4838.0 4871.0 4859.0 4873.5 4870.0 4886.5 4879.0 4884.0 4873.0 4910.5

TⅠ TⅠ TⅠ TⅠ TⅡ TⅡ TⅡ TⅡ TⅡ TⅡ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ TⅢ

0.8404 0.8795 0.8540 0.8493 0.8586 0.8418 0.8613 0.8623 0.8495 0.8476 0.8574 0.8434 0.8497 0.8476 0.8785 0.8450 0.8863 0.8453 0.8634 0.8572

Kinematic viscosity of 50  C (mPa s) 4.0000 12.3800 5.3900 5.7600 4.0000 0.5090 7.5040 6.2340 4.9700 7.1250 5.1750 5.9440 6.1280 14.5000 5.6590 18.2900 5.4550 8.0200 7.61

content of resin and asphaltene varies greatly, ranging from 0 to 32.9%, with high values distributed in the Sangtamu Fault Zone (Fig. 4). In general, the properties of the Triassic oils are characterized by low content of wax, low sulfur, low freezing point,

Wax content (%) 6.91 9.08 4.04 4.52 4.90 4.06 5.90 6.10 5.44 4.80 10.29 15.20 16.10 4.57 12.20 4.10 8.90 3.77 6.42

Sulfur (%)

Resin þ asphaltene (%)

0.20 0.49 0.34 0.52 0.35 0.25 0.44 0.45 0.26 0.33

7.74 9.70 7.40 10.73 6.16 3.00 6.81 6.50 5.70 6.60 5.10 5.57 5.20 4.30 7.40 7.00 13.70 4.50 18.92 9.03

0.37 0.89 0.46 0.48 0.26 0.61 0.48 0.42

Total acid number (mg KOH/g)

Free-zing point ( C)

Initial boiling point ( C)

2.0

84.5

0.01 0.05

6.0 0.0 8.0 12.0

88.0 85.0 72.0 100.0

0.28 0.40 0.66

12.0 20.0 10.0

80.0 95.0 94.0

0.50

1.46

86.88

0.31

medium density, medium viscosity and intermediate content of resin and asphaltene. With increasing depth, the oil density and viscosity decrease and the content of resin and asphaltene were also reduced (Fig. 4).

Figure 4. Plots showing physical properties of selected Triassic crude oils in the Lunnan region.

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G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

5.1.2. Biomarker characteristics and oil sources Crude oils from the Triassic pools comprise normal crude oil, heavy crude oil and condensate oil. The study area is dominated by normal oil. Heavy oils are mainly distributed in the western part of the Central Platform and in a single well nearby the Sangtamu Fault. Condensate is only distributed in the Jilake area. Comparison of the spectrums of the normal crude oil and the condensate shows that even the condensates have 25-norhopane peaks (identified by the guidance of Bennett et al., 2006). 25norhopane commonly exists in the Triassic crude oil (Fig. 5). Most of the crude oil was biodegraded, resulting in crude oil with high density, high viscosity, high sulfur, and high resin and asphaltene contents. Marine sourced hydrocarbons in the Tabei area were known to be derived from the CambrianeLower Ordovician and MiddleeUpper Ordovician source rocks (Zhang et al., 2000, 2005). Because the two sets of source rocks were developed in different depositional environments, there are significant differences in their biomarker compositions. The CambrianeLower Ordovician source rocks are characterized by a high content of C28 steranes, gammacerane, dinosterane and TAS, 4-methyl steranes, C26norcholestane, tricyclic terpanes, with a low content of diasteranes and a heavy d13C values of individual n-alkanes for oils. The MiddleeUpper Ordovician source rocks have the opposite characteristics (Zhang et al., 2000, 2002a; 2002b, 2004a). Oil

generated from the two sets of source rocks can be qualitatively identified using these indicators. Especially, the dinosteranes and TAS biomarkers originated from dinoflagellate are the best indicators which can well distinguish oils of the Cambriane lower Ordovician source from the upper Ordovician source. Triaromatic methyl sterane (m/z 245) and triaromatic sterane (m/z 231) are abundant in the oil from the Cambrianelower Ordovician source rocks (Zhang and Huang, 2005; Li et al., 2010). Based on the analytical results of the dinosteranes and TAS biomarkers, the Triassic crude oils in the Lunnan region originated only from the Ordovician source rocks. The biomarker mass spectrogram shows that the oils from Triassic pools has significantly lower C28 steranes (C29 > C28  C27) (Fig. 6). The distribution of triaromatic steroid and methyl triaromatic steroid exhibit the characteristics of the middleeupper Ordovician crude oil. And, the oils from Triassic pools have complex and diverse properties and commonly contain 25-norhopane, which are certainly not the original hydrocarbons charged directly from the middleeupper Ordovician source rocks. Because it has been demonstrated that 25-norhopanes absent in source rocks of middleeupper Ordovician (Zhu et al., 2012), Triassic hydrocarbons may result from the re-accumulation of the early biodegraded crude oils. The similar examples have been reported that use of 25-norhopanes to indicate mixed petroleum accumulations (Bennett et al., 2006).

Figure 5. Biomarker characteristics of Triassic crude oils and reservoir rock extracts in the Lunnan region. Notes: 28N ¼ C28 25-norhopane, 29N ¼ C29 25-norhopane, 29H ¼ C29 hopane.

G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

59

Figure 6. Biomarker characteristics of crude oils from the Triassic reservoirs in the Lunnan region. Notes: On m/z 231, peak 1 is C2620S Triaromatic Steranes; peak 2 is C2620R Triaromatic Steranes þ C2720S Triaromatic Steranes; peak 3 is C2820S Triaromatic Steranes; peak 4 is C2720R Triaromatic Steranes; peak 5 is C2820R Triaromatic Steranes. On m/z 245, peak 7 is 4, 23, 24-Trimethyl Triaromatic Steranes (C29 triaromatic dinosteranes); peak 8 is 4-methyl-24 Ethyl Triaromatic Steranes (C29); peak 9 is 3-Methyl-24 Ethyl Triaromatic Steranes (C29); peak 11 is 4-Methyl Triaromatic Steranes (C27); peak 12 is 3-Methyl-Triaromatic Steranes; peak 13 is 3-Methyl-24 Methyl Triaromatic Steranes.

5.2. Geochemical characteristics and origin of gas 5.2.1. compositions of gases and their distribution Wells drilled in the Lunnan region are mainly of oil wells with single well daily production of crude oil ranging from 50 to 350 m3. The single well daily production of gas in most wells in the study area is less than 50,000 m3. High-yielding wells are mainly located in the Jilake area, where single well daily gas production reaches 200,000 m3. GOR (gas oil ratio) in the Jilake gas condensate reservoir is the highest, ranging from 1000 to 3000 m3/m3. The gas composition data (Table 3) shows the methane contents are 73 vol% to 91 vol%. The ethane content is less than 6.7%, and the dryness coefficient (C1/C1þ) ranges from 0.87 to 0.999 (average 0.93), which is between the wet and dry gas values. There is a higher level of non-hydrocarbon gases, mainly N2, with an average

of 6.7%. There is no significant difference of gas compositions among different wells (Fig. 7). 5.2.2. Origin of the gases The methane carbon isotope compositions are distributed over a wide range (Fig. 8), from 35& to 39&, while the isotopic composition of ethane ranges from 38.5& to 30&, typical of oiltype gases (Dai et al., 2005; Zhu et al., 2004, 2005a; 2007a; Xiang et al., 2010). The carbon isotopes of associated gases in the marine reservoirs in the Tarim Basin are significantly lower than terrestrial reservoirs in the Lunnan region. The methane carbon isotope compositions of gases in the Lunnan area is significantly lighter than 38& (38& to 52&), and ethane carbon isotope from 36& to 48& (Zhao et al., 2009). Therefore, gases in the Triassic pools are possibly originated from thermally cracked gases except for some oil-soluble gas, which is similar to the gases

60

G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

Table 3 Gas compositions in the Triassic reservoirs in the Tabei area. Block

Well

Well depth 1

Well depth 2

Layer

C1

C2

C3

C4

C5

C6þ

N2

CO2

Relative density

C1/C1þ

Jilake

LN57 LN58 JL101 JL102 JL105 JL106 JL109 JL110 LN53 Average LN55 JF131 JF132 JF100 JF100 JF100 Average LN44 JF121 LN51 LN48 JF124 LN39 JF121 LN22 LN23 LN51 LN14 LG13 LG13 Average LN101 LN6 LN101 LN34 LG8 LN18 LG31 Average LN26 LN10 LN2 LN5 LN41 LN30 LN31 Average

4341.8 4335.5 4346.0 4355.0 4337.0 4331.0 4338.5 4333.0 4353.5

4344.0 4337.5 4348.0 4357.0 4341.0 4334.0 4343.5 4336.0 4355.5

TII TII TII TII TII TII TII TII TIII

4268.0 4255.0 4426.0 4256.5 4425.0 4434.0

TI TI TII TI TII TII TI TI TI TI TIII TIII TIII TIII TIII TIII TIII TIII þ TI TI

9.30 7.55

0.45 0.62

19.78 8.77 2.25 2.45 2.88 2.03 3.34 3.39 7.19 0.26 4.76 5.39

0.70 0.69 0.62 0.62 0.61 0.60 0.61 0.62 0.58 0.63 0.60 0.63

4770 4749 4915 4920 4894.53 4845 4754.12

TI TI TIII TIII TIII TIII TIII

1.10 0.20 0.81 0.24 0.32 0.92 0.11 0.61 0.63 0.55 0.66 1.17 0.53 0.17 0.16 1.21 0.65 0.22 0.68 0.28 0.63 0.32 0.42 0.22 0.28 0.29 0.36 0.01 0.31 0.12 0.32 0.25

0.5863 0.6343 0.6806 0.6346 0.6540 0.7155 0.6268 0.6811 0.6333 0.65 0.6514 0.7196 0.6965 0.6425 0.6046 0.6795 0.67 0.5700

4765 4745.5 4910 4909.5 4888.84 4836 4742

5.61

0.54

4827.5 4722.0 4740.0 4805.0 4898.0 4868.0 4894.0

4845.0 4754.0 4759.0 4815.0 4914.0 4873.0 4910.5

TI TI TI TIII TIII TIII TIII

1.16 1.11 1.94 0.88 1.06 1.45 0.53 1.72 0.80 1.18 1.38 2.50 1.58 0.37 0.55 2.46 1.47 0.26 1.75 0.92 1.34 0.90 0.94 0.66 0.56 0.66 0.91 0.01 0.64 0.32 0.76 0.85 Tace 0.90 0.50 0.32 1.74 0.25 0.76 1.07 0.57 0.68 0.06 0.38 1.72 0.50 0.71

0.16 0.19 0.42 0.45 0.21 4.15 0.22 0.26 0.08 0.68 0.70

4617 4509 4432 4452 4744 4711 4673 4628 4651 4621 4625.8 4787.37 4787.98

1.69 1.60 2.75 2.09 2.15 2.08 1.62 2.94 0.88 1.98 1.76 3.40 2.50 0.90 1.01 3.39 2.16 0.86 2.00 1.83 2.55 1.78 1.45 0.98 1.16 1.03 1.57 0.02 0.94 0.64 1.29 2.75 0.34 1.57 0.65 0.47 2.30 0.20 1.18 1.04 1.94 1.58 0.13 0.52 2.15 0.78 1.16

2.47 6.60 7.31 4.42 7.41 7.44 6.81 7.69 6.93 6.34 5.78 10.48 12.85 12.71 4.66

4602 4501 4426 4446 4735 4699 4671 4620.5 4633.5 4616 4609.8 4765.81 4784.22

3.11 3.06 4.46 4.21 5.17 3.49 3.53 5.66 1.75 3.83 2.46 4.11 3.88 2.74 1.97 4.73 3.32 2.68 4.49 2.91 5.73 4.15 2.67 2.54 2.28 2.12 2.55 0.03 2.20 1.99 2.80 6.71 1.52 3.29 1.11 1.71 3.65 0.81 2.69 2.90 6.02 4.05 0.33 0.90 3.11 1.66 2.71

4.73

4264.0 4250.0 4422.0 4250.5 4417.0 4430.0

85.58 87.15 82.32 87.70 83.68 79.86 87.19 81.12 88.51 84.79 87.06 77.89 77.30 85.55 91.58 87.80 84.53 87.85 83.87 73.24 79.75 90.11 91.48 92.37 93.54 92.23 91.17 92.74 88.49 91.69 88.35 83.23 91.98 89.78 95.27 94.48 89.68 83.79 89.74 85.14 78.44 80.86 86.31 91.05 86.20 86.13 84.88

1.89 2.47 1.26 14.74 5.19 7.16 8.00 12.00 13.08 6.89 2.99 10.19 8.62

0.36 0.24 0.19 0.20 0.31 1.86 1.28 0.82 0.07 0.04 2.15 0.11 0.90

0.878915 0.935889 0.892068 0.921993 0.905824 0.903291 0.937729 0.881260 0.952335 0.91 0.930924 0.870279 0.901037 0.953416 0.961268 0.877824 0.92 0.956243 0.896718 0.924981 0.886111 0.926486 0.943482 0.954531 0.956246 0.957438 0.944180 0.999300 0.952735 0.967092 0.94 0.887408 0.980179 0.936867 0.974529 0.971117 0.912031 0.985185 0.95 0.935810 0.890049 0.927613 0.993782 0.978296 0.912169 0.960415 0.94

Jiefangqu

Sangtamu fault-horst zone

Central platform

lunnan fault-horst zone

0.29 0.23 0.18 0.72 0.33 0.62 1.16 0.02 0.22 1.06 0.20 0.55

0.61

0.37 1.90 0.20 0.43

0.43 0.35

0.56 0.09

0.74

0.30 0.05 0.36

0.13 0.24 0.19 0.21

0.26 0.41 0.29

1.0500 1.2600 0.4900 0.5800 0.3700 0.1500 0.3300 0.0500 0.0040 6.8600 0.4200 1.01 0.6599 0.5931 0.6215 0.5887 0.5900 0.6514 0.6553 0.62 0.6584 0.7310 0.6579 0.6129 0.6020 0.6835 0.6344 0.65

originated in the Sichuan Basin (Zhu et al., 2005b, 2007b; 2009, 2011b; Pan et al., 2010; Long et al., 2011). The Jilake and Jiefangqu pools have high gas productions, while the Carboniferous and Ordovician in the lower part are all gas condensate reservoirs. All wells in the area are of high yields. GOR is mostly about 10,000 m3/m3. Gas dryness coefficient is higher than those in the Triassic reservoirs. The isotopic compositions of gases indicate that the gases from the Carboniferous and Ordovician reservoirs are significantly heavier than those from the Triassic reservoirs. The diversities in the geochemical characteristics of the natural gas reflect the complexity of the oil and gas migration and accumulation process. The origin of the natural gases is a mixture of thermally cracked gas and oil-soluble gas.

et al., 2002a, 2005). The CambrianeLower Ordovician source rocks entered into hydrocarbon generation peak in the late Caledonian and went into a thermally cracked dry gas stage since the late Himalayan orogeny (290 w 250 Ma, Permian). The MiddleeUpper Ordovician source rocks entered into the hydrocarbon generation and expulsion peak in the late Hercynian orogeny (290 w 250 Ma, Permian, Zhang et al., 2007b). Because crude oils in the Triassic hydrocarbon pools were mainly sourced from the MiddleeUpper Ordovician source rocks (Fig. 6), which did not generate hydrocarbons until the Neogene, so the Triassic hydrocarbon pools must have been formed during a later stage of adjustment (Fig. 9).

6. Timing of Hydrocarbon accumulation

The homogenization temperatures of the aqueous inclusions coeval with the petroleum inclusions in the oil/gas-bearing sandstones in the Triassic pools range from 110 to 120  C. Combined with the burial history modeling (Fig. 10), it is believed that hydrocarbon charge mainly occurred in the late Himalayan orogeny (e.g. 290 w 250 Ma, Permian).

6.1. Hydrocarbon generation and expulsion history The CambrianeLower Ordovician and MiddleeUpper Ordovician source rocks are the major source rocks in the Tarim Basin (Zhang

6.2. Analysis of fluid inclusions

G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

61

Figure 7. Distribution of dryness coefficients vs. depth of the gases from different blocks in the Lunnan region.

6.3. Accumulation timing The timing of the cessation of authigenic illite in a reservoir often represents the timing of the initial emplacement of hydrocarbons into a reservoir (Hamilton and Nicholas, 1989; Zhang et al., 2004b). Authigenic illite KeAr dating data (Table 4) indicates that hydrocarbon charged into the Triassic reservoirs in the late Himalayan orogeny (e.g. 290 w 250 Ma, Permian). 7. Formation of the Triassic secondary hydrocarbon pools 7.1. Formation and evolution of the Triassic traps Hydrocarbon accumulations in the Tabei area are by multi-layered reservoirs and multi-stage charge lations. The geochemistry of oils and gases from the also reflects the complexity of the accumulating

characterized and accumuTriassic pools process. The

Figure 8. Relationship of carbon isotope compositions between methane and ethane in the gases.

Figure 9. Comparison of gas geochemical data at different stratigraphic intervals in the Lunnan region.

Triassic crude oil originated from the MiddleeUpper Ordovician source rocks, the generation and expulsion peak of which happened in the late Hercynian orogeny (before the Triassic). Thus, the formation of Triassic traps was later than the timing of the hydrocarbon generation in the MiddleeUpper Ordovician source rocks. The Triassic oils commonly show characteristics of biodegradation (Fig. 5). However the biodegradation does not seem to indicate that it was after the accumulation in the Triassic pools. Because the depth of Triassic pools had exceeded 4500 m, and the palaeo temperature was above 100  C at the stage of accumulation. Therefore, the crude oil likely came from other reservoirs where oil had been previously biodegraded. In addition, the results of the formation water analysis show that the formation water is of CaCl2type with a chlorine (Cl1) content ranging from 63,930 to 146,300 mg/l and a total mineralization from 108,100 to 248,500 mg/l (Table 5), which indicate that the pools are well preserved since its formation without any infiltration of surface water. In other words, the Triassic hydrocarbons were not altered by formation water after the charge. The formation of the plunging anticline in the Triassic strata is later than the Neogene. The top structural map of the Triassic reservoirs and NeS direction shows that the Triassic strata dipped south before the Jurassic deposition with the hydrocarbons being migrated from south to north. Hydrocarbons could not be preserved if there were no traps present. In fact, the Triassic traps are dominated by nose structures developed after the Jurassic deposition (Fig. 11).

62

G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

Figure 10. Burial history and the Triassic fluid inclusion homogenization temperatures in the Lunnan region.

Since the Himalayan orogeny (400 Ma ago), the Triassic structures have become flattened and inversed slightly with the development of the Kuqa foreland basin. After the rapid deposition of KuqaeKangcun Formation, the middleeupper part (above the Carboniferous) in the Tabei area started to be inverted significantly (Fig. 11) with the structural highs shifting toward the south and culminating south of the Lunnan region. As a result, the Triassic strata were dipped to the north. The structures reversal resulted in the development of a number of sets of low amplitude traps and the provision of the essential condition for secondary hydrocarbon accumulations. Therefore, the tectonic inversion since the Himalayan orogeny controlled the accumulation of the Triassic hydrocarbon pools. 7.2. Accumulation process and model for the Triassic secondary hydrocarbon pools Although hydrocarbons experienced multi-stage accumulation in the Tabei area, the early hydrocarbon generation and expulsion process was not directly related to the formation of Triassic hydrocarbon pools. Since the Triassic traps were formed during the Himalayan orogeny, only one episode of natural gas charge occurred in the area which greatly influenced the hydrocarbon distribution in the eastern region of the Tabei area. The intensity of

gas charge decreased from the Ordovician to the Triassic hydrocarbon pools, which changed both the Ordovician and the Triassic pools in the Jilake area to gas condensate accumulations. From the early Hercynian to the early Himalayan orogenies, the Ordovician strata in the Tabei area had been tilted south dipping, and thus the traps located in the south of the Tabei Uplift were in the advantageous migration direction for a long period. The Cambrian source rocks started to generate dry gas since the late Himalayan orogeny. Because of the rapid subsidence of the northern Tabei area, the strata was then reversed and dipped toward north. This caused gases in the Carboniferous traps to migrate south into the Carboniferous reservoirs located in the Jilake region. The gases then migrated upward into Triassic pools through faults, displacing the previously trapped normal oil to the Triassic pools, and formed gas condensate reservoirs. The Carboniferous and Triassic strata were reversed since the Himalayan orogeny, changing from south-dipping to northdipping, and formed low amplitude structural, lithologic or composite traps. Sinistral strike-slip faults were developed in the Triassic and Jurassic strata due to the influence of NEeSW shear stress which also reactivated the EeW faults. Hydrocarbon migrated into the Triassic pools from the lower Ordovician and Carboniferous pools through faults and/or unconformities. Oil properties have the characteristics of oils from the Ordovician with

Table 4 Summary results of KeAr dating of authigenic illites from the Triassic pools. Block

Well

Depth (m)

Layer

Lithology

Dating data (Ma)

Lunnan fault-horst zone Central platform Sangtamu fault-horst zone

LN21 LN19 LN14 JF100 LN56 JL105 JL105 JL105 JL105 JL105 JL105

4503.5 4390.6 4421.3 4189.8 4206.5 4336.8 4336.8 4337.8 4351.6 4353.5 4353.5

TII TII TII TII TII TII TⅡ TII TII TII TII

Water layer sandstone Water layer sandstone Water layer sandstone Oil layer sandstone Oil layer sandstone Oil layer sandstone Oil layer sandstone oil layer sandstone Water layer sandstone Water layer sandstone Water layer sandstone

44 46 49 53 44 47 49 59 40 46 42

Jiefangqu Jilake

     

4.8 7.0 3.6 4.2 5.0 5

Dating mineral

Prediction method

Accumulation period

Data sources

Authigenic illite Authigenic illite Authigenic illite Authigenic illite Authigenic illite Authigenic illite authigenic illite Authigenic illite Authigenic illite Authigenic illite Authigenic illite

KeAr KeAr KeAr KeAr KeAr KeAr KeAr KeAr KeAr KeAr KeAr

Himalayan Himalayan Himalayan Himalayan Himalayan Himalayan Himalayan Himalayan Himalayan Himalayan Himalayan

This study

Wang et al., 1997

G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

63

Table 5 Formation water data in Triassic pools from the Tabei area. Block

Jilake

Jiefangqu

Sangtamu fault-horst zone

Central Platform

Lunnan fault-horst zone

Well

JL102 JN1-1 JN4 JN4-2H JL101 JL102 JL103 JL105 JL106 JL109 LN53 LN57 LN57-H3 LN58 LN58-H1 JF132 JF134 JF135 JF138 LN14 ST2-1 ST6-2 ST6-H2 JF126-3 LN39-1 LN22 JF128 ST1-5 ST5-H1 ST6-1 ST6-2 LG100-6 LN1-H1 LG1-5 LG2-2 LG8 LN1-H1 LN10-2 LN2-22-5 LN26-2 LN3-H12 LN3-H7 LN2-2-J1 LN2-3-14 LN3-H6T LN208 LN209 LN2-34-4 LN26-2

Layer

TI TI TII TII TII TII TII TII TII TII TII TII TII TII TII TII TII TII TII TI TI TI TI TII TII TIII TIII TIII TIII TIII TIII TIII TI TIII TIII TIII TIII TI TI TI TI TI TII TII TII TIII TIII TIII TIII

Color

Light yellow Light yellow Yellow Light brown Brick red Light yellow Light yellow Colorless Yellow Brick red Light brown Yellow Light yellow Yellow Brick red Light yellow Brick red Colorless Brown Yellow Reddish brown Reddish brown Colorless Black Light yellow Reddish brown Yellow Black Yellow Brick red Colorless Colorless Brown Reddish brown Yellow Brick red Light brown Light yellow Light brown Black Black Light brown Light yellow Black Light yellow Dark green Colorless Brick red Light brown

pH

6.30 5.82 5.82 5.48 5.15 6.13 6.46 6.39 6.11 5.14 6.10 6.35 5.69 6.62 6.34 6.77 6.02 6.72 6.52 6.44 5.45 6.17 6.52 6.73 6.44 6.22 6.32 6.30 6.47 6.63 7.23 6.54 4.73 7.01 5.78 6.03 6.05 6.12 6.18 8.54 6.66 5.29 6.24 4.89 6.38 7.60 6.21 5.74 5.54

Cation (mg/L)

Anion (mg/L)

Ca2þ

Mg2þ

B2þ

Total

Cl-

SO4 2 -

HCO3 

Total

10680.0 6080.0 12540.0 4457.0 8632.0 6510.0 10730.0 15200.0 10750.0 4850.0 6410.0 10790.0 10940.0 10650.0 11350.0 10830.0 9382.0 9732.0 12070.0 9793.0 9794.0 8200.0 9259.0 5212.0 15090.0 11850.0 11610.0 9034.0 11280.0 11500.0 11460.0 12010.0 3044.0 5080.0 12280.0 10180.0 4816.0 9940.0 7947.0 3645.0 16380.0 9190.0 4861.0 11210.0 11900.0 7040.0 7680.0 11830.0 10610.0

936.2 571.0 895.8 893.3 762.2 736.0 960.1 711.2 1125.0 760.0 958.8 845.1 815.3 829.7 1022.0 783.8 909.0 1174.0 863.2 1140.0 1069.0 874.7 1104.0 549.7 1939.0 988.0 1056.0 440.4 1220.0 1250.0 916.5 1131.0 723.8 510.0 892.7 846.0 1306.0 1450.0 654.6 521.1 2188.0 1157.0 742.5 1031.0 1108.0 618.7 1155.0 976.7 1180.0

11.0 9.4 6.6 5.0 7.4 7.0 23.2 6.8 11.0 8.3 5.5 6.5 5.3 42.2 7.7 5.8 16.4 14.0 22.4 24.0 25.7 23.0 12.0 8.8 16.9 31.6 204.0 21.0 34.3 11.7 42.3 125.0 11.8 53.0 87.2 26.0 25.7 10.0 25.2 6.7 16.3 33.7 66.2 35.8 102.0 36.0 110.0 88.0 119.0

86,590 94,370 82,260 82,710 81,150 95,510 80,100 87,320 83,610 95,890 101,900 83,590 80,890 77,070 85,820 83,880 83,010 84,660 83,550 86,220 84,020 75,660 86,230 71,950 90,310 79,380 81,010 88,700 83,670 82,110 84,160 72,030 42,750 41,470 70,500 79,770 77,350 84,880 64,280 75,990 87,080 79,750 51,000 74,380 79,680 55,530 82,210 78,330 76,710

136900.0 138600.0 130800.0 129600.0 126500.0 133100.0 127000.0 138900.0 132700.0 128300.0 146300.0 132200.0 128100.0 122200.0 135800.0 132700.0 131100.0 134100.0 132600.0 136500.0 133100.0 119500.0 136400.0 112400.0 145000.0 126300.0 128800.0 127600.0 133100.0 130800.0 133400.0 115300.0 64740.0 63930.0 110000.0 125200.0 121900.0 134900.0 101400.0 118200.0 140600.0 126500.0 80500.0 118500.0 126900.0 87590.0 115100.0 119900.0 122100.0

360.5 316.9 146.5 207.0 721.1 235.4 222.2 243.6 154.8 228.8 293.0 377.0 222.2 214.0 665.1 151.5 272.5 185.2 144.0 107.0 113.6 113.6 113.6 537.0 459.3 197.6 220.6 283.2 194.3 192.6 227.2 70.8 170.0 2224.0 256.8 543.3 254.0 72.4 343.2 553.0 454.4 87.3 165.0 154.8 98.8 403.3 75.7 39.5 95.0

77.2 117.0 91.9 32.0 69.9 79.9 145.0 145.0 139.0 39.0 86.9 134.0 89.3 133.0 88.8 92.0 155.0 208.0 64.1 184.0 102.0 240.0 206.0 194.0 41.0 61.8 66.0 162.0 56.8 39.0 107.0 79.3 25.0 439.0 4323.0 185.0 98.4 315.0 252.0 146.0 118.0 161.0 229.0 32.0 94.2 346.0 178.0 46.0 211.0

137,300 139,000 131,000 129,800 127,300 133,400 127,400 139,300 133,000 128,600 146,700 132,700 128,400 122,500 136,600 132,900 131,500 134,500 132,800 136,800 133,300 119,900 136,700 113,100 145,500 126,600 129,100 128,000 133,400 131,000 133,700 115,500 67,670 66,590 114,600 125,900 122,300 135,300 102,000 118,900 141,200 126,700 80,890 118,700 127,100 88,340 115,400 120,000 122,400

widespread biodegradation. The adjustment and formation process of the secondary hydrocarbon pools lasted till the late Himalayan orogeny (Fig. 12). In the late Himalayan orogeny, gas charge occurred only in the eastern part of the Tabei area. The gas charged along the Ordovician karst reservoirs from east to west, and formed the Lungudong gas condensate reservoirs. Fault systems in the area were also activated in the Jilake and Lungudong regions, with en echelon arrangement and displacements of 30e60 m, cutting through the Ordovician strata. These faults provided good transport conduits for hydrocarbons to migrate from the Ordovician reservoirs into the Triassic traps. The oil reservoirs in the area were rarely influenced by the gas charge and were preserved, resulted in two types of secondary hydrocarbon pools in the Triassic reservoirs. The Triassic structural high had progressively migrated southward and its location and morphology had continually changed and been adjusted. This had a great impact on the oil water contacts.

Total salinity (mg/L)

Water type

223,900 233,400 213,300 212,500 208,400 228,900 207,500 226,600 216,600 224,500 248,500 216,300 209,300 199,600 222,400 216,800 214,500 219,200 216,400 223,000 217,300 195,500 222,900 185,100 235,800 205,900 210,100 216,700 217,000 213,100 217,900 187,500 110,400 108,100 185,100 205,700 199,600 220,200 166,300 194,900 228,300 206,500 131,900 193,100 206,800 143,900 197,600 198,300 199,100

CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2

Under the regional monocline background, reservoirs of the low amplitude anticlines, fault-anticlines, fault noses, fault-lithologic and lithologic pinchouts, commonly formed small individual pools. The sizes of the pools are dependent on the southward migration of the structure and the temporalespatial distribution of terrestrial sand in the Triassic low stand system tracts. However, those hydrocarbon pools often occurred or distributed in groups and zones, so fine exploration would be useful to further expand the reserves. (1) Before the deposition of the Kangcun Formation, oils already began to migrate toward the Carboniferous and Triassic reservoirs along faults. But the oils might not accumulate in the Carboniferous and Triassic reservoirs because the reservoirs then were shallowly buried and poorly sealed. (2) Before the deposition of the Kuqa Formation, upward-migrating oil could be accumulated in the Carboniferous and Triassic reservoirs because the thick sedimentation of the Jidike and Kangcun Formation became effective seals.

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Figure 11. Palaeo-structure maps of the base of the Triassic strata in the Lunnan region. (a) Palaeo-structural map showing the Triassic base features after the deposition of the Kuqa Formation. (b) Palaeo-structural map showing the Triassic base features after the deposition of the Kangcun Formation. (c) Palaeo-structural map showing the Triassic base features before the Jurassic deposition.

(3) Due to the thick sediment of the Kuqa Formation, the cap rocks over the Carboniferous and Triassic reservoirs became well developed, and both oil and gas can be sealed by then. At the same time, the Triassic structures were inversed and oil began to migrate

southwards along sand bodies. In addition, oil in the Cambrian paleo-reservoirs reached thermal cracking point and generated large quantities of dry gas, which charged from the southeast to the northwest.

G. Zhu et al. / Marine and Petroleum Geology 46 (2013) 51e66

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Figure 12. A structure evolution cross section along NeW direction for the Triassic reservoirs in the Tabei area. (a) Dry gas charged into the oil pools during the late Himalayan. (b) Oil pools formed during the Kangcun period. (c) None trapping due to poor capping conditions before the deposition of the Jidike Formation.

8. Conclusions

Acknowledgements

The Triassic oil and gas pools in the northern Tarim Basin are characteristic of secondary hydrocarbon accumulations. The hydrocarbons were migrated from older and deeper primary hydrocarbon pools. The oils were sourced from the MiddleeUpper Ordovician, and the secondary accumulation occurred mainly during the Himalayan orogeny. Biomarker characteristics of crude oils, fluid inclusion homogenization temperatures and authigenic illite KeAr dating collectively suggested that the Triassic oil and gas pools are of secondary in nature. The formation of the secondary pools was mainly controlled by the tectonic and structure inversion and the development of the “nose structure” traps during the Himalayan orogeny. The hydrocarbon phase difference in the secondary pools from the eastern to the western parts in the Tabei area resulted from the gas charge and the accumulation of gas condensate pools in the eastern part during the late Himalayan orogeny.

We thank the Exploration and Development Research Institute of the Tarim Oilfield Company, PetroChina for providing well testing and analytical data. Thanks also go to Yang Debing, Cui Jie, Meng Shucui and Chen Ling for their contributions. This study is funded by the National Petroleum Key Projects (Grant No: 2008ZX05004-003)

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