at SciVerse ScienceDirect

Marine and Petroleum Geology 43 (2013) 478e488

Contents lists available

Marine and Petroleum Geology

journal homepage: www.elsevier .com/locate/marpetgeo

A well-preserved 250 million-year-old oil accumulation in the TarimBasin, western China: Implications for hydrocarbon exploration in oldand deep basins

Guangyou Zhu a,*, Shuichang Zhang a, Keyu Liu a,b, Haijun Yang c, Bin Zhang a, Jin Su a,Yaguang Zhang c

aResearch Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083, ChinabCSIRO Division of Earth Science and Resource Engineering, P.O. Box 1130, Bentley, WA 6102, Australiac Tarim Oilfield Research Institute of Exploration and Development, PetroChina, Xinjiang, Korla 841000, China

a r t i c l e i n f o

Article history:Received 28 March 2012Received in revised form27 November 2012Accepted 6 December 2012Available online 16 December 2012

Keywords:Old oil accumulationBiomarkersFluid inclusionKeAr datingPVTx modelingTarim Basin

* Corresponding author. Tel.: þ86 10 8359 2318.E-mail address: zhuguangyou@petrochina.com.cn

0264-8172/$ e see front matter � 2012 Elsevier Ltd.http://dx.doi.org/10.1016/j.marpetgeo.2012.12.001

a b s t r a c t

A giant oilfield (YM-2) with an estimated reserve of close to one billion bbl was recently discovered in anOrdovician carbonate reservoir at a burial depth of 5800e6200 m in the northern Tarim Basin, westernChina. Biomarker and isotope geochemistry of the hydrocarbons indicate that the oil was derived fromOrdovician marine source rocks at early to peak oil generation. Authigenic illite (KeAr) dating, fluidinclusion analysis, fluid inclusion PVTx and thermal history modeling indicate that the accumulation is ofprimary in origin, and the original charge occurred in the Permian during the Late Hercynian OrogenicStage, approximately 290e250 million years ago. The physiochemical compositions of the hydrocarbonsand formation water remained largely unchanged since the initial accumulation. The excellent preser-vation of such an old accumulation at such a great depth is due to continuous burial of the YM-2structure since the Triassic, a thick effective seal, and a relatively low geothermal gradient witha current reservoir temperature of 127e130 �C. This finding suggests that under suitable conditions oldpetroleum accumulations can be well-preserved, and some old and deep basins may be prospectivefrontiers for future exploration.

� 2012 Elsevier Ltd. All rights reserved.

1. Introduction

Destruction or alteration of a hydrocarbon accumulation is quitecommon, especially for old reservoirs (Miller, 1992; Liu et al., 2006).How long can a hydrocarbon accumulation be preserved is not onlyan important scientific question, but also a practical issue for oil andgas exploration and resource assessment. Despite the fact that oil isknown to be present on earth and has been preserved in mineralsas inclusions for close to 3 billion years (e.g. Dutkiewicz et al., 1998),there is surprisingly few old hydrocarbon accumulations foundworld-wide. According to Miller (1992) the median age for oilaccumulations is only about 29 Ma, and over 75% of accumulationswere charged within the last 75 million years, including 90% of thelight oil accumulations. MacGregor (1996) studied the original oil inplace (OOIP) and age distribution of 350 large oil fields and foundthat over half were formed after the Oligocene, with a median ageof 35 Ma, and only one-sixth of the world’s known hydrocarbon

(G. Zhu).

All rights reserved.

accumulations were formed before the Mesozoic. Thus that mosthydrocarbon accumulations formed in the Paleozoic have beeneither altered or destroyed with very few being preserved (Li et al.,2006). Such ancient hydrocarbon accumulations can only bepreserved under two situations: (1) in a stable structural setting,such as cratonic basins without large-scale uplift or faulting; and(2) associated with excellent sealing, such as ultra-thick evaporitesto prevent hydrocarbon dispersion and formationwater movement(MacGregor, 1996). As for the old marine basins in China, Paleozoicmarine strata generally have experienced superimposition ofmultiple tectonic systems and structural styles (Jin, 2005), andoriginal hydrocarbon accumulations have been altered severely.

This paper was reported on a well-preserved Paleozoic oilaccumulation (ca 250 Ma), the Yingmaili-2 (YM-2) Oilfield in thenorthern Tarim Basin area. The discussions and conclusionswere based on the detailed biomarker and isotope geochemicalanalysis, fluid inclusion PVTx and geohistory modeling, KeArdating of authigenic illite and regional geological reconstruction.This discovery has great significance and implications on the re-evaluation of the exploration potential in the Paleozoic deep

G. Zhu et al. / Marine and Petroleum Geology 43 (2013) 478e488 479

marine strata in the Tarim Basin and may provide new insight forhydrocarbon exploration in the old and deep basins elsewhere.

2. Geology of the study area

Tarim Basin is a typical superimposed basin (Li et al., 1996) inwestern China covering a total area of about 560 � 103 km2 (Fig. 1).The northern area of the basin contains the largest proven reserves,highest hydrocarbon abundance and hydrocarbon-bearing forma-tionswithin the Tarim Basinwith 3P (Provenþ Probableþ Possible)reserves of over 20 � 109 bbl (Yang and Han, 2008). The NorthernTarim Uplift (NTU) or Tabei Uplift is located between the ManjarDepression to the south and the Kuqa Depression to the north(Fig. 1). The YM-2 (Yingmaili-1) Oilfield investigated in this study isin the western part of the NTU area.

The NTU area is a palaeo-uplift that developed over the pre-Sinian Proterozoic metamorphic basement, upon which Sinian-Devonian marine, Carboniferous-Permian marine and non-marine, and Triassic-Quaternary terrestrial strata were developed.

The Yingmaili (YM) structure is located on a low uplift in thewestern part of the NTU. The structure developed its initial config-uration in the early Paleozoic. The NTUwas elevated as a whole and

Figure 1. The Yingmaili (YM-2) Oilfield in the Tarim Basin showing (a) the geographic locatioil distribution within the Ordovician reservoir formation capped by the Ordovician and Si

formed a south dipping structure during the Late Caledonian(Hendrix et al., 1992; Carroll et al., 1995). Prior to the Silurian depo-sition, the Ordovician sequencewas partially eroded in the northernarea where it was elevated, resulting in an angular unconformity(Fig. 1b). The shape of the YM-2 trap was formed during the LateHercynian orogenic movement and the final configuration of theYM-2 structure was developed during the Permian.

The YM-2 structure is an inherited large-scale NE trending domestructure with mainly Paleozoic formations (Fig. 1a). Its longstructural axis is about 16.6 km and the short axis is 12.9 km. Thestructure’s relief is about 664 m and the trap area is approximately153 km2. The present burial depth of the main structure is about5800e6200 m.

The YM-2 reservoir is an anticlinal trap with a reserve of over0.7 � 109 bbl. The oil with an API gravity range of 25e30� anda relatively low GOR of less than 280 scf/bbl, mainly accumulatedwithin the lower to middle Ordovician (O1e2y) carbonatesequence (Table 1; Fig. 1b). The reservoir lithology comprisesmainly sparite, granular limestone, granular micrite and micritewith an average reservoir thickness of about 25 m. The corederived porosity and permeability are relatively low with averagevalues of 1.16% and 0.56 mD, respectively. However, the presence

on, structural map of the YM-2 reservoir and (b) cross section of the YM-2 trap and thelurian caprocks. Red dots denote oil wells.

Table 1Individual-well production test data in the YM-2 Oilfield.

Well no. Perforation interval (m) Thickness (m) Daily production GOR (scf/bbl) Crude oil density(g/cm3)

Testing result

Oil (bbl) Gas (Mscf) Water (bbl)

YM-2 5940.00e5953.00 13.00 1661 345 208 0.9112 OilYM-201 5805.16e5884.60 79.44 79 0.8955 OilYM-201 6041.00e6052.00 11.00 103 8.90 0.9206 OilewaterYM-202 5879.00e5897.00 18.00 36 13.95 OilewaterYM-204 5850.61e5920.50 69.89 639 282 441 0.8779 OilYM-206 5801.64e5850.00 48.36 221 0.8737 OilYM-206 5864.48e5950.00 85.52 215 OilYM-206 5801.64e5950.00 148.36 234 OilYM-2-H1 5918.50e6203.00 284.50 980 258 3.15 263 0.8964 OilYM-2-2 5810.00e5880.00 70.00 358 Minor 0.875 OilYM-2-3 5828.59e5970.00 141.41 1030 121 117 0.9097 OilYM-2-4 5806.96e5890.00 83.04 942 258 274 0.9002 OilegasYM-2-8 5773.41e5900.00 126.59 513 33 65 0.8957 OilYM-2-12 5785.00e5885.00 100.00 692 157 227 0.9104 OilegasYM-2-14 5775.50e5915.00 139.50 843 197 234 0.8659 OilegasYG-2 6009.86e6070.00 60.14 1057 59 56 0.8945 OilYG-2-1C 5940.70e6094.26 153.56 1019 70 69 0.9121 Oil

G. Zhu et al. / Marine and Petroleum Geology 43 (2013) 478e488480

of well-developed fractures and vuggy pores in the reservoirhas enhanced the effective permeability and effective storagecapacity.

The major caprock of the YM-2 reservoir is the SangtamuFormation (O3s) shale, calcareous shale and tight limestone witha total thickness of 400e500 m (Fig. 1b), which are distributedextensively in the region. The rocks are extremely tight and areexcellent regional caprocks. In addition, there is a set of thick-bedded shale at the base of the Silurian sequence (200 m). TheTriassic shale in the area is also quite thick, approximately 200 m.The Cenozoic sequence in the area contains a set of 600-m thickshale, gypsum-bearing shale and gypsum shale, which are widelydistributed in the region, collectively forming an additionalimportant set of indirect caprocks for the YM-2 reservoir.

At present, 17 wells have been drilled on the YM-2 structure(Table 1) and themajority ofwells have encountered commercial oilflow with daily oil production, typically around 350e1000 bbl andonlyminor gas production due to a lowGORof less than 450 scf/bbl.

3. Analytical methods

3.1. Sampling

A number of water, oil, gas and core samples from the YM-2reservoir were analyzed using a suite of techniques includingfluid property measurements, wet chemistry, biomarker andisotopic geochemistry, KeAr dating, and fluid inclusion petrog-raphy, microthermometry and PVTx modeling (Tables 2e8).

Table 2Summary of the physical properties of the Ordovician oil in the YM-2 Oilfield.

Well name Upperdepth (m)

Lowerdepth (m)

Density @ 20 C(g/cm3)

Viscositya

@ 50 C(mm2/s)

YM-2 5940 5953 0.9112 36.43YM-201 5948 5960 0.8956 21.14YM-204 5845.1 5920.5 0.8779 15.32YM-206 5801.6 5950 0.8737 11.89YM-2-1H 6000.3 6233.4 0.8814 13.57YM-2-1H 5159.6 5970.9 0.8756 9.856YM-2-3 5828.6 5970 0.9127YM-2-4 5806.9 5890 0.8852 16.18YM-2-8 5773.4 5900 0.8808 12.3YG-2 6009.8 6070 0.8909 23.42YG-2-1 6008.8 6120 0.9193 54.2YG-2-1C 5940.7 6094.3 0.9121 38.85

a Kinetic viscosity.

3.2. Methods

In addition to the routine geochemical analyses of the water, oiland gas using IC, GCeMS and GC-IRMS, KeAr isotope age deter-minations were performed on an MM 5400 static vacuum massspectrometry instrument. The analytical procedure used for thefluid inclusion analysis is based on a combination of non-destructive techniques applied to individual inclusions includingfluid inclusion petrography and microthermometry on both oiland aqueous inclusions. Dissolved methane and salt content inthe aqueous inclusions were quantified using Raman micro-spectroscopy. CH4 and CO2 contents of hydrocarbon inclusions areapproximated using Fourier transform infrared (FT-IR) spectrom-etry. The volume of hydrocarbon inclusions was reconstructedusing Confocal Scanning Laser Microscopy (CSLM). Thermody-namic modeling was also performed to determine the tempera-ture and pressure conditions and compositions of the hydrocarbonfluids trapped.

4. Hydrocarbon compositions

4.1. Physical properties

The Ordovician crude oil in the Yingmaili Oilfield is charac-terized by high density, high viscosity, high colloid andasphaltene contents, medium sulfur content and low waxcontent (Tables 1 and 2). Oil densities range from 0.87 to 0.92 g/cm3; the average wax content is 4.84% and the average sulfur

Condensationtemperature (�C)

Waxcontent (%)

Colloidcontent (%)

Asphaltene(%)

Sulfur(%)

�8 13.1 4.26 7.24 0.53�30 2.3 5.4 6.7 0.6<-30 10.7 7.95 4.49 0.22�22 6.4 8 4.6 0.66<-30 5.4 3.75 6.46�14 7.75 6.61 4.26 0.8�20�16 8.98 8.18 2.95 0.99<�30 4.8 12.3 4.6 0.74�8 10.0 4.04 4.99 0.56<�30 4.9 10.0 9.61 1.5<�30 4.1 7.66 8.86 0.95

Table 3Bulk group compositions of the Ordovician oils in the YM-2 Oilfield.

Well No. Depth (m) Fm. Saturatedhydrocarbon

Aromatichydrocarbon

Resins Asphaltene Total

YM-2 5926.81e6050 O1e2y 30.26 32.03 9.56 28.14 100YM-206 5801.64e5950 O1þ2 37.3 39.17 8.98 14.55 100YM-1 5350.16e5410 O1þ2 25.58 29.83 24.75 19.83 100

Table 4Carbon isotopes of the Ordovician oils in the YM-2 Oilfield.

Well No. Depth (m) Fm. Oil (&) Saturatedhydrocarbon (&)

Aromatichydrocarbon (&)

Non-hydrocarbon (&) Asphaltene (&)

YM-2 5926.81e6050 O1e2y �33.3 �33.3 �32.9 �32.9 �33.3YM-206 5801.64e5950 O1þ2 �33.4 �33.1 �33.1 �32.8 �33.4YM-1 5350.16e5410 O1þ2 �31.9 �32.5 �32.0 �32.3 �32.5

Table 5Ordovician gas compositions in the YM-2 Oilfield.

Well No. Depth (m) C1 C2 C3 iC4 nC4 iC5 nC5 C6þ N2 CO2 C1/C1þ

Upper Lower

YM-2 5940 5953 46.2 11.5 11.1 2.58 3.71 0.871 0.57 0.192 17.8 5.4 0.60YM-201 5948 5960 43.66 11.73 13.32 3.54 6.02 1.58 1.52 1.46 14.53 2.64 0.53YM-204 5866 5884 45.4 12.1 11.4 2.27 3.49 0.768 0.603 0.319 16.2 7.45 0.59YM-206 5801.64 5850 51.84 10.4 9.13 2.18 3.97 1.15 1.23 1.22 16.95 1.94 0.64YM-2-1H 6000.32 6233.38 54.1 12.3 8.75 1.52 2.18 0.469 0.346 0.204 15.7 4.43 0.68YM-2-2 5810 5880 49.3 13.2 10.2 1.74 2.62 0.508 0.4 0.203 15.4 6.33 0.63YM-2-3 5828.59 5940 47.5 13.9 11.4 2.52 4.03 0.99 0.796 0.449 13.5 4.94 0.58YM-2-4 5858 5889 47.5 13.9 11.4 2.08 3.17 0.66 0.522 0.284 14.5 6.02 0.60YM-2-8 5773.41 5900 52.8 12.8 9.15 1.57 2.25 0.472 0.357 0.205 14.7 5.74 0.66YG-2 6009.86 6070 57 12.2 8.97 1.63 2.09 0.433 0.301 0.163 13.4 3.8 0.69YG-2-1C 5940.7 6094.26 56.5 11.5 9.04 1.75 2.41 0.468 0.324 0.147 16.6 1.32 0.69

G. Zhu et al. / Marine and Petroleum Geology 43 (2013) 478e488 481

content is 0.72%, representing typical marine oil in the TarimBasin (Zhang et al., 2000, 2002). The oil density and viscosityshow positive correlation with the contents of colloid, asphalteneand sulfur content. This indicates that oil degradation anddensification were the major reasons that had caused theelevated oil density, viscosity, sulfur content, colloid content andasphaltene content.

4.2. Bulk group compositions

The bulk oil composition in the Yingmaili area is dominated bysaturated hydrocarbons and aromatic hydrocarbons, which accountfor over 50% of total hydrocarbons (Table 3). Asphaltene content isrelatively high varying from 15% to 29%. The content of resins isapproximately 10% on average but may be up to 25% such as in YM-1 well. Comparatively speaking the oils from the Yingmaili areacontains high asphaltene and resins.

4.3. Carbon isotope compositions

The carbon isotope ratios of crude oils can reflect the origin ofthe oils. The carbon isotope of marine-sourced oil in the Tarim Basin

Table 6Carbon isotopes of gases in the YM-2 Oilfield and surrounding Ordovicianaccumulations.

Well No. Depth (m) d13C1 (&) d13C2 (&) d13C3 (&) d3C4 (&)

YM-2 5795.6e6050.0 �42.39 �38.16 �34.30YM-201 6041.0e6052.0 �48.38 �40.59 �34.74 �32.40DH-1 5575.6e5621.5 �41.57 �38.16 �34.30 �31.75DH-11 5790.0e5800.0 �42.75 �33.62 �32.43X-3 6117.0e6127.0 �49.30 �37.40 �35.20 �32.80

is distinctively lighter than that of the terrestrial- sourced oil (Daiet al., 2004). As for the Ordovician oil in the Yingmaili Oilfield,the bulk oil carbon isotope (d13C) is lighter than �31.9& (Table 4).The d13C values of the saturated hydrocarbons are between�32.5&and �33.3&, and that of the aromatic hydrocarbons are from�32.0& to �33.1&. In contrast, the terrestrial oil in the Tarim Basinhas a bulk oil d13C of over �31&, between �27.9& and �30.1&(Zhang et al., 2000). The d13C values of the saturated hydrocarbonsare between �28.1& and �30.8& with an average value of�30.0&, and that of the aromatic hydrocarbons are from�27.9& to�30.1& with an average value of �29.3&. Therefore the oil fromthe Yingmaili Oilfield is typically of marine facies origin.

4.4. Dissolved gas compositions

Natural gas production from the Ordovician reservoirs in thestudy area is extremely low, primarily derived from soluble gas.Hydrocarbon gas is the dominant component of the natural gas.CH4 content is low overall, with a maximum value of 57% (Table 5).In contrast, the content of the heavier hydrocarbon gases is high,generally greater than 25%. The natural gas dehydration coefficientC1/C1

þ ratio is less than 0.7, generally ranging from 0.5 to 0.7,characteristic of wet gas. Among the non-hydrocarbon gases, theaverage CO2 content is about 5%; the N2 content is relatively high,ranging from 13% to 17%.

4.5. Dissolved gas isotope compositions

The carbon isotope composition of the hydrocarbon gas is aneffective geochemical index for differentiating natural gas types, forgasegas correlation and for gas origin recognition (Galimov, 1988;Dai et al., 2004). Carbon isotope compositions of the natural gas in

Table 7KeAr ages of authigenic illite from the Silurian bituminous sandstone in the Yingmaili area (Zhang and Luo, 2011).

Well No. Depth (m) Formation Grain size (mm) Clay minerals (%) S% Potassic feldspar Potassiumcontent

Age (Ma) Tectonicmovement

I/S I K C

YM-11 5562 S1k 0.3e0.15 53 47 5 Not detected 3.71 277 HercynianYM-35-1 5574 S1k 0.3e0.15 97 3 5 Not detected 6.07 287 Hercynian

5631 0.3e0.15 100 5 Not detected 6.71 288 HercynianYM-35 5588.7 S1k 0.3e0.15 100 5 Not detected 6.38 293 HercynianYM-34 5386.9 S1k 0.3e0.15 78 14 8 5 Not detected 3 255 Hercynian

<0.15 76 12 12 5 Not detected 3.41 281 Hercynian5388.7 0.3e0.15 75 17 8 5 Microscale 3.43 280 Hercynian

G. Zhu et al. / Marine and Petroleum Geology 43 (2013) 478e488482

the YM-2 Oilfield and its surrounding Ordovician accumulations(Table 6) have a distinctive d13C1 < d13C2 < d13C3 < d13C4 pattern.The major distribution range of d13C1 is from �42& to �49&, andthat of d13C2 is between �34& and �41&, indicating a typical oil-type origin. Using the Sapropel type natural gas maturity calcula-tion equation (d13C1 ¼ 15.8*log Roe42.2) established by Dai et al.(2004) and Lu et al. (2008) and based on the d13C1 values, thecalculated natural gas maturity for the Ordovician accumulation inthe YM-2 Oilfield is approximately 0.92%e1.25% of Ro equivalent.The gas was therefore probably produced during the peak ofhydrocarbon generation, as suggested by its low dehydra-tion coefficient. Combined with the source rock distributioncharacteristics and the thermal evolution characteristics of thecarbonate platform-basin area in the Tarim Basin, it is believedthat natural gas was mainly originated from Middle and UpperOrdovician marine source rock during peak oil generation (Zhanget al., 2000) and therefore can be classified as associated gas.

5. Hydrocarbon origin and source

The bulk chemical properties of the YM-2 oil, and the biomarkerand isotopic geochemistry data (Figs. 2e4) indicate that hydrocar-bons in the YM-2 Oilfield are (1) characteristic of marine source; (2)generated at an early to peak oil generation window; (3) derivedfrom the Mid-Upper Ordovician marine source kitchen (Zhanget al., 2000).

As mentioned previously the produced gas is typical of dissolvedwet gas with a gas dehydration coefficient (C1/C1þ) less than 70% anda calculated equivalent Ro of 0.92%e1.25%, corresponding to theliquid hydrocarbon generation peak based on the isotopes of d13C1.The oil is characterized by high density, high viscosity, high colloidand asphaltene content, with moderate sulfur and low wax. Thesaturate fraction reservoirs displays complete n-alkane distributionprofiles with predominantly low molecular components with C9 as

Table 8Modeled petroleum inclusion compositions using Petroleum Inclusion Thermody-namic (PITx) modelling.

Component 5A-If24a

(mole %)6B-If54(mole %)

6B-If56(mole %)

6B-If57(mole %)

6B-If62(mole %)

C1 22.42 8.78 17.57 9.31 10.83C2 4.35 1.12 3.09 1.21 1.57C3 5.24 1.93 4.16 2.04 2.54iC4 1.32 0.55 1.09 0.57 0.71nC4 2.96 1.23 2.44 1.28 1.60iC5 2.16 0.97 1.83 1.01 1.25nC5 3.47 1.56 2.94 1.63 2.01nC6 4.59 3.27 4.56 3.32 3.83nC7 5.27 3.52 4.91 3.58 4.13nC8 4.94 2.51 4.70 3.56 4.07nC9 4.63 3.50 4.51 3.54 4.02nC10 4.34 3.49 4.33 3.52 3.96Cn1# 25.06 28.04 28.32 28.09 29.90Cn2# 8.93 35.50 15.55 37.34 29.52

a Individual inclusions modeled; #Cn1: C11e25; Cn2: C26þ.

the dominant n-alkane peak (Fig. 2) and declining graduallytoward the heavier components, typical of mature oil. The n-alkaneprofiles do not show any apparent “bumping” phenomenon (Figs. 2and 3), suggesting that the oil had not experienced any obviousbiodegradation. The Ts/(Ts þ Tm), dibenzothiophene maturityparameters (Fig. 4) suggest that the Ordovician marine oil in theYM-2 and surrounding areas was derived from a source rock with anequivalent Ro values of 0.86e1.02 (Hanson et al., 2000; Zhang et al.,2002).

6. Reservoir accumulation timing

6.1. Hydrocarbon generation history

The oil in the YM-2 Oilfield was originated from the Mid-UpperOrdovician source rock, which is distributed widely in the ManjarDepression to the south of the YM-2 structure, with a knownthickness of 50e150 m, TOC of 0.6e2.5 % and an equivalent Ro of1.3e1.5% (Hanson et al., 2000). Hydrocarbon generation modelingshows that the source rock generated a large quantity of oil in thePermian when the Ro reached 0.8e1.0% (Fig. 5). Since the Neogene,the maturity of the source rock increased rapidly from a Ro value of1.0%e1.5%, causing the generation of high-maturity oil andcondensate. The maturity of the oil recovered from the YM-2 Oil-field is typical of those generated in the late Permian.

6.2. Authigenic illite KeAr dating

The Silurian strata above the O3s seal of the YM reservoirs hadalso received hydrocarbon charge during the Permian, but withoutany major accumulation preserved due to the lack of effectivecaprocks and subsequent erosion (Yang and Han, 2008). As a resultbituminous sandstone is widespread in the surrounding region dueto biodegradation. The Silurian bituminous sandstone wasencountered by seven wells (YM-2, YM-3, YM-11, YM-34, YM-35,YM-39 and YM-35-1; Fig. 1) with reservoir thickness of 1e5 m. Oilcorrelation indicates that the Silurian bitumen share similar originas the Ordovician oil in the YM-2wells andwas charged at the sametime (Yang and Han, 2008).

The cessation of authigenic illite in a reservoir often representsthe timing of the initial emplacement of hydrocarbons (Hamiltonet al., 1989; Zhang et al., 2011). The authigenic illite ages obtainedfrom the YM-34, YM-35, YM-35-1 and YM-11wells yielded five setsof high confidence results with pure authigenic illite (I/S) obtainedin the YM-35 and YM-35-1 wells (Table 7). The initial hydrocarboncharging event in the Silurian reservoir in the YM area has beendated to have occurred around 255e293 Ma.

6.3. Fluid inclusion and PVTx modeling

A sample from the current YM-2 reservoir at 5909e5917 mwasanalyzed in great detail to understand the charge history of the

Figure 2. Typical chromatograms of oils from the YM-2 Oilfield with C9 as the dominant peak in both samples: (a) Oil sample from YM-2-15 at 5159.6e5970.9 m; (b) Oil samplefrom YM-204 at 5845.1e5920.5 m.

G. Zhu et al. / Marine and Petroleum Geology 43 (2013) 478e488 483

YM-2 reservoir. The sample is a limestone and is composed mostlyof micrite and calcite cements with stylolitization features and latecalcite veins. Fluid inclusions have been studied in both calcitecements and calcite veins.

Hydrocarbon and aqueous inclusions are mostly distributed inlocalized concentrations occurring as groups outlining healed

Figure 3. Mass chromatograms of saturated hydrocarbo

microfractures both in calcite cements and in calcite veins (Fig. 6).Some inclusions were observed to be contemporaneous with sty-lolitization. Others are also present in micrite, but they could not bemeasured due to their small sizes. The hydrocarbon inclusions aremostly two-phase liquid and vapor inclusions, with predominantblue and green fluorescence. They are mostly colorless under

ns in the YM-2 well (Left: m/z 191; Right: m/z 217).

Figure 4. Methyl triaromatic steranes (m/z 245, left) and triaromatic steranes (m/z 231, right), characteristic of crude oils from the YM-2 well area. Left: 1, 4, 23, 24-trimethylTriaromatic Steranes (C29 triaromatic dinosteranes); 2, 4-Methyl-24 Ethyl Triaromatic Steranes; 3, 3-Methyl-24 Ethyl Triaromatic Steranes; 4, 4-Methyl Triaromatic Steranes; 5,3-Methyl Triaromatic Steranes; 6, 3-Methyl-24 Methyl Triaromatic Steranes; *, unrecognized material. Right: 1, C2820R Triaromatic Steranes; 2, C2620R TriaromaticSteranes þ C2720S Triaromatic Steranes; 3, C2820S Triaromatic Steranes; 4, C2720R Triaromatic Steranes; 5, Triaromatic Steranes.

Figure 5. Petroleum generation modeling of the inferred source rock in the Tarim Basin showing peak oil generation occurred in the Permian period (Zhu et al., 2012). AfterSweeney and Burnham (1990) using Easy%Ro in PetroMod.

G. Zhu et al. / Marine and Petroleum Geology 43 (2013) 478e488484

Figure 6. Fluid inclusions analyzed for microthermometric analysis and PVTx modeling. The sample is from YM-206 at 5908e5916.6 m. (a) and (b) Inclusions from calcite veinsanalyzed; (c), (e) and (f) 3D volume construction of the fluid inclusions (both oil and gas) using Laser Scanning Confocal Microscopic imaging and (d) a typical hydrocarbon inclusionmeasured for homogenization temperature (Th).

Figure 7. Gas percentage (Fv) vs homogenization temperature (Th) plot for themodeled fluid inclusions from YM-206 showing that the trapped oil contains little gas,much lower than that of the North American black oil.

G. Zhu et al. / Marine and Petroleum Geology 43 (2013) 478e488 485

transmitted light, but are occasionally light brown in calcite veins.Most inclusions measured are relatively small in sizes from a few toabout 10 mm. Watereoilevapor 3-phase inclusions are present butno solid phases inside hydrocarbon inclusions are observed.

Aqueous inclusions are mostly two-phase liquid and vaporinclusions, with sizes ranging up to 10 mm. Some single phase liquidaqueous inclusions are also present. Aqueous inclusions cogeneticwith hydrocarbon inclusions were distinguished by detailedpetrographic characterization. Quite often the cogenetic aqueousand hydrocarbon inclusions are located in the same microfracturewithin calcite veins.

The homogenization temperature (Th) of hydrocarbon inclu-sions is found to be independent of their color under transmittedlight, their fluorescence or locations. The Th distribution is unim-odal with an average value of 62.1 �C. The aqueous inclusionhomogenization is in the range of 78e144 �C (Fig. 7). Aqueousinclusions cogenetic with hydrocarbon inclusions have Th in therange of 78.5e105 �C and a lower mean Th (88.6 �C) than otheraqueous inclusions (109.4 �C).

Due to the fragility of the host mineral, the samples have notbeen frozen to obtain the ice melting temperature (Tm) in order toprevent stretching and/or leaking of fluid inclusions (Bourdet andPironon, 2008). Salinities were obtained using the laser Ramanmethod of Dubessy et al. (2002) and are expressed in wt. % NaCl eq.The Raman salinities are variable but are predominantly of 12e

16 wt.% NaCl eq. A single measured inclusion cogenetic withhydrocarbon inclusions yields a salinity of 12 wt.% NaCl eq.

Confocal Laser Scanning Microscopic (CLSM) study was per-formed on five hydrocarbon inclusions in calcite veins with Th

G. Zhu et al. / Marine and Petroleum Geology 43 (2013) 478e488486

values ranging from 58.5 to 66.2 �C, which are considered to berepresentative of the reservoir system at the time of hydrocarboncharge. The difference between the hydrocarbon and cogeneticaqueous inclusions is around 20e40 �C, indicating a low tomoderate overpressured reservoir system at the time of hydro-carbon charging (Pironon and Bourdet, 2008).

PVTx modeling (Fig. 8) shows that hydrocarbons trapped in theinclusions contain low to very low CH4 concentrations of 8.8e22.4 mol% (Table 8). The fluid inclusion oils contain abnormallyhigh amount of C26þ up to 37%. The C11e25 components range from25 to 30%. Overall, the modeled gas percentages (Fv) at 20 �C of the

Figure 8. Hydrocarbon generation and burial history modeling of the YM-2 reservoirshowing the timing of the initial hydrocarbon generation and charge from KeAr datingof the authigenic illite and fluid inclusion PVTx modeling. (a) 1D basin modeling withK/Ar age; (b) PIT modeling of the trapping pressure and temperature; (c) Histogram ofhomogenization temperatures of both petroleum and aqueous inclusions.

fluid inclusion oils are well below that of the North American blackoil reference (Fig. 7; Bourdet and Pironon, 2008; Bourdet et al.,2010), which is consistent with the extremely low GOR andmoderate API gravity of the current reservoir oil in the YM-2 oilfield(Tables 1 and 2).

A cogenetic aqueous inclusionwith Th of 84.8 �C was selected tomodel the trapping PeT conditions. The intersection of the iso-chores of the hydrocarbon and the cogenetic aqueous inclusionsgives PeT conditions for the hydrocarbons in the range of 90e98 �Cand 18e30 MPa (Fig. 8b). The intersections of the hydrocarbonisochores with virtual aqueous inclusion isochores (with similarsalinity and methane content) the Th of the cogenetic aqueousinclusions is translated to 78.5e105.0 �C. Therefore the minimumtrapping conditions (considering cogenetic aqueous inclusion withminimum Th) are around 83e90 �C and 15e25 MPa, while themaximum trapping conditions (considering cogenetic aqueousinclusions with maximum Th) are around 125e133 �C and 38e55 MPa.

7. Trap evolution and accumulation reconstruction

The YM-2 trap was initially developed in the Permian (Fig. 9a).Hydrocarbon generated from the Mid-Upper Ordovician sourcerock south of the NTU area during the Permianmigrated northwardand charged into the Ordovician and Silurian traps to form large-scale hydrocarbon accumulations (Fig. 9b). The initial trapping PeT conditions based on fluid inclusion modeling are around 83e90 �C and 15e25 MPa, respectively, corresponding to a depth ofapproximately 2000 m. The charge was probably associated witha regional tectonic event as most inclusions measured are fromcalcite veins and some hydrocarbon inclusions are contempora-neous with stylolitization. Due to the tectonic movements prior tothe Triassic deposition, some hydrocarbon reservoirs had experi-enced extensive degradation or destruction (Fig. 9c). On thestructural highs, the Silurian reservoirs were damaged and some oilwas partially biodegraded due to the shallow depth and extensiveerosion of the caprocks, but hydrocarbons at the periclinal struc-tures were preserved, such as the YM-2 Ordovician reservoir and itssouthern extension. Since the deposition of the Triassic sequence,the Ordovician reservoirs have been under constant subsidencewith a thick caprock sequence having developed (Fig. 9def). Theconfiguration of the original trap remains largely unchanged andthe hydrocarbons in the YM-2 reservoir have thus been well-preserved.

The current reservoir formation water from the YM-2 area is ofCaCl2 type, representing a preservation setting with an excellentsealing capability. The salinity of the formation water is high withthe total salinity over 100,000 mg/L, similar to the salinity ob-tained from the aqueous inclusions (12%) coeval with the petro-leum inclusions. This suggests that the reservoir formation waterhas not been altered much since the hydrocarbon emplacementand that the YM-2 trap has been a closed system after the initialcharge.

Currently, the burial depth of the Ordovician reservoir formationis 5800e6200 m. The borehole temperature is 127e130 �C, lowerthan the oil cracking temperature. The maximum PeT conditionrecorded by the fluid inclusions (133 �C and 55 MPa) is comparablewith the current reservoir PeT ranges measured as 51e62 MPa,suggesting the pressure regime in the YM-2 trap have been wellmaintained. Because of the high heterogeneity of the Ordovicianreservoir in the YM-2 area, the presence of a direct 600-m thick sealof the Upper Ordovician tight shale (O3s) and the presence ofseveral kilometers of indirect sealing rocks (Triassic to Neogene)above, enabled the original YM-2 accumulation formed around250 Ma ago to have been well-preserved.

Figure 9. Trap evolution and hydrocarbon accumulation process of the Yingmaili (YM-2) reservoirs (a) At the end of Silurian deposition, no oil/gas accumulated in the Ordovicianreservoirs; (b) At the Late Hercynian Stage, oil originated fromMiddle and Upper Ordovician source rock migrated through Ordovician karst layers, faults and unconformity surfacesfrom the south to the north and entered into the Ordovician and Silurian traps to form large-scale accumulations; (c) The Late Hercynian movement before Triassic depositioncaused regional uplift. The Ordovician oil/gas experienced biodegradation and densification and reservoirs at structure highs were damaged. Silurian erosion was even more severe;oil/gas was completely dispersed and with only asphaltene left. (d) Since Triassic deposition, the Yingmaili area continuously subsided at moderate rates; (e) since the deposition ofthe Kangcun Formation (8e5 Ma ago), the Yingmaili area has undergone rapid subsidence due to the development of the Kuqa foreland basin to the north but it had little influenceon the traps; (f) present day reservoirs.

G. Zhu et al. / Marine and Petroleum Geology 43 (2013) 478e488488

8. Conclusions

The hydrocarbon accumulation in the Ordovician reservoir inthe YM-2 area originated from the Mid-Upper Ordovician sourcerock. Hydrocarbon charge occurred in the Permian. From the earlyTriassic period, the YM-2 reservoir has undergone continuoussubsidence, providing an excellent environment for hydrocarbonpreservation. The integrated investigation of the hydrocarbongeneration history, authigenic illite KeAr dating, fluid inclusion andPVTx modeling, and regional trap evolution indicate that the YM-2Ordovician reservoir is a primary accumulation originally formedaround 250 Ma ago. The discovery of such a well-preserved trulyancient old primary oil accumulation at a depth of over 6000 msuggests that under suitable tectonic, depositional and geothermalconditions, hydrocarbon reservoirs can be preserved over a signifi-cant long period, possibly up to several hundreds of millions ofyears. This may provide new insight for exploration of old and deepfrontier basins that previously may be regarded as non-prosperousdue to their age and depth constraints.

Acknowledgments

We thank Prof. Zhang Youyu of RIPED, PetroChina for authigenicillite dating; Dr Emmanuel Laverret of CV Associés Engineering,France for fluid inclusion analysis and PVTx modeling. The TarimOilfield Company is thanked for providing the backgroundgeological information.

References

Bourdet, J., Pironon, J., 2008. Strain response and re-equilibration of CH4-richsynthetic aqueous fluid inclusions in calcite during pressure drops. Geo-chimica et Cosmochimica Acta 72, 2946e2959.

Bourdet, J., Pironon, J., Levresse, G., Tritlla, J., 2010. Petroleum accumulation andleakage in a deeply buried carbonate reservoir, Nispero field (Mexico). Marineand Petroleum Geology 27 (1), 126e142.

Carroll, A.R., Graham, S.A., Hendrix, M.S., Ying, D., Zhou, D., 1995. Late Paleozoictectonic amalgamation of northwest China: sedimentary record of the northernTarim, northwestern Turpan, and southern Junggar basins. Geological Society ofAmerica Bulletin 107, 571e594.

Dai, J.X., Xia, X.Y., Qin, S.F., et al., 2004. Origins of partially reversed alkane d13Cvalues for biogenic gases in China. Organic Geochemistry 35 (3), 405e411.

Dubessy, J., Lhomme, T., Boiron, M.C., Rull, F., 2002. Determination of chlorinityin aqueous fluids using Raman microspectroscopy of the stretching band ofwater at room temperature: application to fluid inclusions. Applied Micro-spectroscopy 56, 99e106.

Dutkiewicz, A., Rasmussen, B., Buick, R., 1998. Oil preserved in fluid inclusions inArchaean sandstones. Nature 395, 885e888.

Galimov, E., 1988. Source mechanisms of the formation of gaseous hydrocarbon insedimentary rocks. Chemical Geology 71, 77e95.

Hamilton, P.J., Kelley, S., Fallick, A.E., 1989. KeAr dating of illite in hydrocarbonreservoirs. Clay Mineral 24, 215e231.

Hanson, A.D., Zhang, S.C., Moldowan, J.M., Liang, D.G., Zhang, B.M., 2000. Molecularorganic geochemistry of the Tarim Basin, Northwest China. AAPG Bulletin 84,1109e1128.

Hendrix, M.S., Graham, S.A., Carroll, A.R., Sobel, E.R., McKnight, C.L., Schulein, B.J.,Wang, Z., 1992. Sedimentary record and climatic implications of recurrentdeformation in the Tian Shan: evidence from Mesozoic strata of the northTarim, south Junggar, and Turpan basins, northwest China. Geological Society ofAmerica Bulletin 104, 53e79.

Jin, Z.J., 2005. Particularity of petroleum exploration on marine carbonate strata inChinese sedimentary basins. Earth Science Frontiers 12 (3), 15e22.

Li, D., Liang, D., Jia, C., Wang, G., Wu, Q., He, D., 1996. Hydrocarbon accumulations inthe Tarim Basin, China. AAPG Bulletin 80, 1587e1603.

Li, M., Ma, C., Hu, G., San, X., 2006. Age of oil accumulations. Petroleum Explorationand Development 33, 653e656.

Liu, W., Guo, Z., Li, B., Rao, M., Wen, Z., Yang, R., 2006. Destruction types andmechanism of hydrocarbon reservoirs in the western Qaidam Basin. Journal ofChina University of Geosciences 12, 131e141.

Lu, Y.H., Xiao, Z.Y., Gu, Q.Y., Zhang, Q., 2008. Geochemical characteristics andaccumulation of marine oil and gas around Halahatang depression, Tarim basin,China. Science in China (Series D) 51 (Suppl.), 195e206.

MacGregor, D.S., 1996. Factors controlling the destruction of preservation of giantlight oilfields. Petroleum Geoscience 2, 197e217.

Miller, R.G., 1992. The Global Oil System: the relationship between oilgeneration, loss, half-life, and the world crude oil resource. AAPG Bulletin76, 489e500.

Pironon, J., Bourdet, J., 2008. Petroleum and aqueous inclusions from deeply buriedreservoirs: experimental simulations and consequences for overpressure esti-mates. Geochimica et Cosmochimica Acta 72 (20), 4916e4928.

Sweeney, J.J., Burnham, A.K., 1990. Evaluation of a simple model of vitrinitereflectance based on chemical kinetics. AAPG Bulletin 74, 1559e1570.

Yang, H., Han, J., 2008. Reservoir formation characteristics and main controllingfactors of complex oil and gas accumulation area of Tarim Basin. Science inChina, Series D 51 (Supp. 1), 65e76.

Zhang, S., Hanson, A.D., Moldowan, J.M., Graham, S.A., Liang, D., Chang, E., Fago, F.,2000. Paleozoic oil-source rock correlations in the Tarim Basin, NW China.Organic Geochemistry 31, 273e286.

Zhang, S.C., Moldowan, J.M., Li, M.W., Bian, L.Z., 2002. The abnormal distribution ofthe molecular fossils in the pre-Cambrian and Cambrian: its biological signifi-cance. Science in China 45 (3), 193e200.

Zhang, Y., Zwingmann, H., Liu, K., Todd, A., Luo, X., 2011. Hydrocarbon charge historyof the Silurian bituminous sandstone reservoirs in the Tazhong uplift, TarimBasin, China. AAPG Bulletin 95, 395e412.

Zhang, Y.Y., Luo, X.Q., 2011. KeAr dating of authigenic illites and the hydrocarbonaccumulation history of the Silurian bituminous sandstone reservoirs in theYingmaili area, Tarim Basin. Petroleum Exploration and Development 38 (2),203e210.

Zhu, G.Y., Zhang, S.C., Su, J., Huang, H.P., Yang, H.J., Gu, L.J., Zhang, B., Zhu, Y.F., 2012.The occurrence of ultra-deep heavy oils in the Tabei Uplift of the Tarim Basin,NW China. Organic Geochemistry 52, 88e102.