origin and mechanism of the formation of the low-oil-saturation moxizhuang field, junggar basin,...
TRANSCRIPT
AUTHORS
Fang Hao � State Key Laboratory of Petro-leum Resources and Prospecting, China Uni-versity of Petroleum, Fuxue Road No. 18,Changping, Beijing 102249, China;[email protected]
Fang Hao received his Ph.D. from the ChinaUniversity of Geosciences in 1995. He is nowdirector of the State Key Laboratory of PetroleumResources and Prospecting and chairperson ofthe Academic Committee of China University ofPetroleum. He has conducted petroleum geologyand geochemistry studies in several Chinesebasins. His interests include petroleum accumu-
Origin and mechanismof the formation of thelow-oil-saturation Moxizhuangfield, Junggar Basin, China:Implication for petroleumexploration in basins havingcomplex histories
lation and postaccumulation processes in thesedimentary basins.
Fang Hao, Zhihuan Zhang, Huayao Zou,Yuanchun Zhang, and Yuanyuan Yang
Zhihuan Zhang � State Key Laboratory ofPetroleum Resources and Prospecting, ChinaUniversity of Petroleum, Fuxue Road No. 18,Changping, Beijing 102249, China;[email protected]Zhihuan Zhang has a Ph.D. in geochemistry fromthe China University of Petroleum. He is now aprofessor of geochemistry and director of theDepartment of Geochemistry and EnvironmentalScience at China University of Petroleum. Hisrecent interest is reservoir geochemistry.
Huayao Zou � State Key Laboratory of Pe-troleum Resources and Prospecting, ChinaUniversity of Petroleum, Fuxue Road No. 18,Changping, Beijing 102249, China;[email protected]
Huayao Zou received his Ph.D. from the ChinaUniversity of Geosciences and is now a professorof geology at the China University of Petroleum.He spent 2 yr as a postdoctorate research fel-low studying petroleum generation and accu-mulation in the Bohai Bay Basin before hejoined the university. His recent interest is inthe study of filling history of oil and/or gasfields in Paleozoic basins in western China.
Yuanchun Zhang � State Key Laboratory ofPetroleum Resources and Prospecting, China
ABSTRACT
TheMoxizhuang field is a small oil field in the central JunggarBasin containing several low-saturation, low-resistivity oil res-ervoirs, which display a complex correlation between oil sat-uration and porosity and permeability that is atypical of boththe filled and drained reservoirs. Biomarker associations ofcrude oil and grains containing oil inclusions (GOIs) of boththe present-day water-bearing zones (water zones) and the oil-and water-bearing zones (low-oil-saturation pay zones) wereanalyzed to investigate the mechanisms for the formation ofthe low-saturation, low-resistivity oil accumulations. The bio-marker assemblage and hierarchical cluster analysis indicatethat oil in the Moxizhuang field was mostly generated fromPermian source rock deposited in brackish to hypersaline anoxicenvironments. The pay zones and several water zones displayGOI values asmuch as 38%, greater than the generally acceptedthreshold GOI value for an oil column (5%). These GOI valuesare similar to those for high-saturation oil reservoirs in the BohaiBay Basin and oil zone samples from Australian basins, suggest-ing that both pay zones and water zones were high-saturationoil reservoirs in the geologic past.Geologic history analysis showsthat the Moxizhuang field was located on the north wing of a
University of Petroleum, Fuxue Road No. 18,Changping, Beijing 102249, China;[email protected]
Yuanchun Zhang graduated in 2007 with anM.S. degree in geophysics and is now a Ph.D.student at the China University of Petroleum.
Copyright ©2011. The American Association of Petroleum Geologists. All rights reserved.
Manuscript received July 7, 2010; provisional acceptance September 16, 2010; revised manuscriptreceived September 30, 2010; final acceptance November 19, 2010.DOI:10.1306/11191010114
AAPG Bulletin, v. 95, no. 6 (June 2011), pp. 983– 1008 983
Her interest is in the study of mechanism forthe formation of low-resistivity oil accumula-tions in Paleozoic basins in western China.
Yuanyuan Yang � State Key Laboratory ofPetroleum Resources and Prospecting, ChinaUniversity of Petroleum, Fuxue Road No. 18,Changping, Beijing 102249, China;[email protected]
Yuanyuan Yang graduated in 2007 with a degreein geochemistry from the Yangtze Universityand is now a Ph.D. student at the China Univer-sity of Petroleum. Her interest is in the studyof biomarker compositions of lacustrine sourcerocks and crude oils.
ACKNOWLEDGEMENTS
This research was supported by the NationalNatural Science Foundation of China (90914006),973 Project (2005CB422105), and Program forChangjiang Scholars and Innovative ResearchTeam in the University (IRT0658). We thankPilong Li, Jianhui Feng, and Zehui Mu from theExploration Company of SINOPEC and JianhuiZeng, Jiafu Qi, Nansheng Qiu, and Fusheng Yuat the China University of Petroleum for collab-oration and enthusiastic support. We thank theExploration Company of SINOPEC for kindlyproviding part of the data in this study. Barry J.Katz, Kenneth E. Peters, and Norelis D. Rodriguezare gratefully acknowledged for their construc-tive reviews. We thank Stephen E. Laubach(AAPG Editor) for his constructive commentsand instructions, which helped improve themanuscript. Finally, we thank Frances PlantsWhitehurst for her careful checking of thismanuscript.The AAPG Editor thanks the following reviewersfor their work on this paper: Barry J. Katz,Kenneth E. Peters, and Norelis D. Rodriguez.
EDITOR ’S NOTE
Color versions of Figures 2, 5, 7, 8, 10, and 11 maybe seen in the online version of this article.
984 Formation of the Low-Oil-Saturation Moxizh
paleoanticline during oil charge in the Late Cretaceous to Paleo-gene. This anticline has gradually evolved into a south-dippingmonocline since theNeogene, causing northward remigration ofaccumulated oil. Differential lateral leakage of accumulated oilin different sandstone layers during the remigration phase ledto the formation of the water zones with high GOI values(completely drained reservoirs) and the low-saturation, low-resistivity pay zones (partially preserved reservoirs) and causedthe complex correlation between oil saturation and porosity andpermeability. Compared with other postaccumulation phys-icochemical alteration processes, lateral leakage has rarely beenrecognized. Recognizing differential lateral leakage of accu-mulatedpetroleumwith the existence of high-quality unfaultedcap rocks has important implication for petroleum explorationin sedimentary basins having complex evolution histories.
INTRODUCTION
Sedimentary basins having complex histories represent one ofthe frontier areas for petroleum exploration. As petroleum ex-ploration and development in Mesozoic and Cenozoic rift ba-sins in eastern China mature, finding more oil and gas reservesin complex Paleozoic basins in western China has become animportant strategy for the country (Ma et al., 2004; Zhao et al.,2007; Hao et al., 2008). Sedimentary basins with complexmultistage evolution histories are called superimposed basinsin China (He et al., 2004). In these superimposed basins, initialpetroleumaccumulation occurred several hundredmillion yearsago, followed by several major tectonic movements. Petroleumreservoirs preserved in these superimposed basins may haveexperienced complex physicochemical processes, such as al-teration, leakage, remigration, and reaccumulation (Hao et al.,2008; Ohm et al., 2008). The complex postaccumulation pro-cesses make petroleum exploration in these superimposed ba-sins a great challenge. Understanding the geochemical originsand physicochemical processes associated with the accumu-lation and preservation of petroleum during these complexhistories has become a prerequisite for successful petroleumexploration in superimposed basins.
The Junggar Basin, located in northwest China (Figure 1),is one of themost petroliferous Paleozoic basins in China (Caoet al., 2006;Qiu et al., 2008; Li et al., 2010).More than 20majoroil fields have been found so far, and more than 2 × 108 tons(1.31 × 109 bbl) of oil were produced from this basin by theend of 2005 (Qiu et al., 2008). The Moxizhuang field is asmall oil field in the central Junggar Basin. The initial aim of
uang Field, Junggar Basin, China
petroleum exploration in this area was to find lith-ologic reservoirs, one type of the so-called subtlereservoirs. The pay zones in the Moxizhuang fieldwere confirmed to have low oil saturations (bothwater and oil were produced). Uncertainty aboutcause of the low oil saturation is one of the majorfactors impeding further petroleum exploration inthe central Junggar Basin. The Junggar Basin hasexperienced fundamental geologic changes sincetheNeogene (Figure 2) because of rapid subsidenceand sedimentation in the southern Junggar Basin asa result of uplift and northward obduction of thenorthern Tian Shan (Li et al., 2010). Therefore,theMoxizhuang field provides a natural laboratoryto investigate postaccumulation processes causedby these geologic changes. The purpose of this ar-ticle is to investigate the geochemical origin andfilling and alteration histories of the Moxizhuang
field and reveal the mechanisms for the formationof low-saturation, low-resistivity oil reservoirs inthe Junggar Basin by integrating geologic and geo-chemical data.
GEOLOGIC AND GEOCHEMICAL SETTING
The Junggar Basin has a triangular geometry and anarea of about 130,000 km2 (50,193mi2) (Figure 1).This basin is surrounded by foldedmountain rangessuch as the Tian Shan and the Altai and Kelameilimountains (Figure 1). The Junggar Basin is an upperPaleozoic, Mesozoic, and Cenozoic superimposedbasin at the junction of the Kazakhstan, Siberia,and Tarim blocks (Cao et al., 2006). The basindeveloped on the Junggar terrane and is underlainby oceanic crust of the early and middle Paleozoic
Figure 1. Structural units of the Junggar Basin (modified from Qiu et al., 2008), showing location of the Moxizhuang field and wellsfrom which samples were taken. The inset shows the structure map at the top of the Jurassic Sangonghe Formation, the reservoir rock inthe Moxizhuang field (contour interval at 20 m [66 ft]). I = Wulungu depression; II = Luliang uplift; III = Western uplift; IV = Centraldepression; V = Southern depression; VI = Eastern uplift; MXZ = Moxizhuang.
Hao et al. 985
trapped during the late Paleozoic amalgamation ofcentral Asia (Carroll et al., 1990). The Junggar Basincan be divided into six second-order structural units:the Wulungu depression, Luliang uplift, Westernuplift, Central depression, Southern depression,and Eastern uplift (Qiu et al., 2008) (Figure 1),each of which has a different structural configura-tion and tectonic history.
The Junggar Basin had a complex tectonic andsedimentary history. The evolutionary stages, espe-cially changes in the nature of the basin throughgeologic time, are still in dispute. Li et al. (2010)recently divided the geohistory of the Junggar Ba-
986 Formation of the Low-Oil-Saturation Moxizhuang Field, Jun
sin into four stages: the rift basin stage (middle–Late Permian), compressional flexural basin stage(Triassic–Jurassic), balanced flexural basin stage(Cretaceous–Paleogene), and contractional basinstage (Neogene–Quaternary). The uplift and north-ward obduction of the northern Tian Shan sincethe Neogene caused rapid subsidence and sedi-mentation in the southern Junggar Basin, whichfundamentally changed the structural framework ofthe basin (Figure 2).
The Junggar Basin has as much as 16 km ofsediments (Figure 1). Carboniferous sediments weredeposited in alternating marine and continental en-vironments, whereas Permian to Tertiary sedimentsare dominated by lacustrine-alluvial conglomerates,sandstones, and shales. Although the Permian, Ju-rassic, Triassic, and Paleogene in the Junggar Basinhave candidate source rocks (Clayton et al., 1997;Chen et al., 2003; Cao et al., 2005;Qiu et al., 2008),organic-rich lacustrine shales in the Permian are themost important oil source rocks (Carroll et al., 1997;Carroll, 1998; Cao et al., 2006; Zou et al., 2008a).The Permian source rocks are dominated by sapro-pelic organic matter, as indicated by high Rock-Evalpyrolysis hydrogen indices (as much as 1000 mg/g
Figure 2. Cross sections showing change in the structural frame-work in the central Junggar Basin since the Neogene (provided bythe Exploration Company of SINOPEC, see Figure 1 for section lo-cation). J1b = Lower Jurassic Badaowan Formation; J1s = LowerJurassic Sangonghe Formation; J2x = Middle Jurassic XishanyaoFormation.
Figure 3. Van Krevelen diagram for kerogens from the JunggarBasin.
ggar Basin, China
total organic carbon), high concentrations of fluo-rescent amorphous organic matter, and high atomichydrogen/carbon (H/C) ratios of kerogen (Figure 3)(Zou et al., 2008a; Li et al., 2010). Other intervals,especially the coal-bearing Jurassic, are dominatedby higher plant organic matter (Figure 3) and aretherefore more gas prone (Li et al., 2010).
Petroleum has been found in different reser-voir rocks from the Carboniferous to the Paleogene,and at least seven sets of reservoir–cap rock combi-nations have been identified (Cao et al., 2006). Thereservoir rocks in the Moxizhuang field are deltaicsandstones of the Jurassic Sangonghe Formation. Atpresent, the Sangonghe Formation in the centralJunggar Basin is a south-dipping monocline with-out structural closure (inset in Figure 1). Sandstonesin the Sangonghe Formation in the central JunggarBasin are thin (mostly <30 m [<98 ft] thick) anddisplay rapid lateral facies changes, which makecorrelation of sandstone layers difficult. The reser-voir sandstones in the Moxizhuang oil field displayporosity ranging from 1.7 to 18.3%, and perme-ability from less than 0.01 to 642 md (Figure 4).
SAMPLES AND METHODS
Thirty-seven oil samples or sandstone extracts fromthe Moxizhuang field were selected for analysis ofbiomarker compositions. Four oil samples from theC1 discovery and six oil samples from the D1 dis-
covery in the central Junggar Basin were also ana-lyzed for comparison. Oils and sandstone extractswere separated into saturated hydrocarbons, aro-matic hydrocarbons, and polars. Gas chromato-graphic (GC) analyses of the saturated hydrocar-bon fractions were achieved using an HP6890chromatograph equipped with a PONA fused sil-ica column (60 m × 0.20 mm inner diameter; filmthickness, 0.5 mm). The oven temperature was ini-tially held at 35°C for 5 min, programmed to 80°Cat 2°C/min and to 300°C at 4°C/min, and heldat 300°C for 30 min. Helium was used as carriergas. The GC–mass spectrometry (GC-MS) analysesof the saturate fractions were performed using anHP6890GC/5973MSD instrument equipped withan HP-5MS fused silica column (30 m × 0.25 mminner diameter; film thickness, 0.25 mm). The GCoven temperature for analysis of the saturate frac-tions was initially held at 50°C for 2 min, pro-grammed to 100°C at 20°C/min and to 310°C at 3°C/min, and held at 310°C for 16.5 min. Biomarkerratios were calculated from peak areas of individualcompounds.
Hierarchical cluster analysis (HCA) was usedto separate the analyzed samples into different oilgroups. Ten biomarker parameters confirmed to re-flect organic matter input and/or depositional con-ditions in the Junggar Basin (marked parameters inTable 1) were used in HCA. The HCA was com-pleted using the Statistical Package for the SocialSciences (SPSS, Inc.). In HCA, the Euclidean mea-sure interval and Ward’s cluster method were used,and values for each parameter were automaticallyscaled to the range of 0 to 1. Where samples lackedreliable data for certain parameters, the missing pa-rameter was replaced with the mean value for thatparameter determined from the remaining samplesin the same well.
Porosity and permeability of reservoir rocksand measured oil saturations were collected fromthe North West Petroleum Exploration Coopera-tion, SINOPEC. They were measured using stan-dard methods. Oil and water saturations were cal-culated from well logs. The grains containing oilinclusions (GOIs) were determined using the tech-nique described by Lisk et al. (2002) and Brincatet al. (2006).
Figure 4. Measured permeability versus porosity for reservoirsandstones in the Moxizhuang field, Junggar Basin.
Hao et al. 987
Table 1. Biomarker Parameters for Oils and Sandstone Extracts from the Moxizhuang Field and Discoveries in the Central Junggar Basin*
WellDepth(m) ID C31 S/S + R C32 S/S + R C29 S/S + R
C29 bb/(bb + aa) Pr/Ph† b/H† G/H†
C19+20TT/S TT† C24/C24 + C26
† S TT/H† ETR† C27/C29† C28/C29
† S/H†OilClass
Z1 4331.4 1A 0.61 0.60 0.54 0.53 1.71 2.20 0.22 0.21 0.34 2.20 0.66 0.39 0.81 0.42 2Z1 4332.0 1B 0.60 0.60 0.54 0.53 1.56 2.52 0.23 0.20 0.36 3.29 0.70 0.21 0.89 0.54 1Z1 4332.5 1C 0.61 0.61 0.53 0.52 1.67 2.48 0.26 0.19 0.36 2.39 0.70 0.48 0.87 0.46 1Z1 4333.3 1D 0.63 0.63 0.54 0.53 1.57 1.49 0.22 0.23 0.38 3.35 0.67 0.12 0.74 0.47 2Z1 4336.6 1E 0.61 0.63 0.56 0.53 1.47 2.01 0.33 0.19 0.33 5.33 0.77 0.15 1.05 0.60 1Z1 4364.3 1F 0.62 0.60 0.58 0.51 1.31 2.66 0.37 0.17 0.36 3.96 0.75 0.19 0.96 0.56 1Z1 4372.1 1G 0.62 0.61 0.57 0.51 1.24 2.74 0.27 0.16 0.33 3.85 0.75 0.18 0.98 0.58 1Z1 4372.8 1H 0.62 0.61 0.57 0.51 1.36 3.04 0.30 0.17 0.35 3.82 0.75 0.19 0.99 0.57 1Z1 4373.2 1J 0.62 0.59 0.57 0.53 1.70 1.66 0.14 0.23 0.43 2.56 0.61 0.09 0.76 0.40 2Z1 4373.5 1K 0.63 0.59 0.58 0.51 1.33 2.17 0.26 0.18 0.34 5.67 0.76 0.21 0.98 0.60 1Z1 4378.2 1L 0.61 0.61 0.55 0.52 1.33 2.46 0.35 0.17 0.34 4.37 0.73 0.14 0.99 0.55 1Z1 4379.0 1M 0.61 0.61 0.55 0.53 1.56 2.63 0.35 0.18 0.36 4.19 0.75 0.19 1.00 0.56 1Z1 4379.7 1N 0.62 0.62 0.55 0.52 1.41 2.54 0.34 0.19 0.33 5.02 0.76 0.20 0.96 0.57 1Z1 4380.7 1P 0.60 0.61 0.56 0.54 2.17 3.93 0.08 0.27 0.49 1.67 0.50 0.09 0.64 0.29 4Z2 4305.7 2A 0.61 0.62 0.57 0.51 1.38 3.04 0.32 0.15 0.36 3.05 0.73 0.19 0.97 0.53 1Z2 4309.5 2B 0.62 0.61 0.55 0.51 1.26 2.81 0.43 0.15 0.35 3.14 0.74 0.20 0.98 0.49 1Z2 4334.1 2C 0.62 0.61 0.58 0.51 1.28 2.49 0.38 0.17 0.35 4.96 0.76 0.19 0.96 0.55 1Z2 4335.2 2D 0.62 0.60 0.55 0.52 1.17 2.96 0.33 0.15 0.33 3.94 0.76 0.19 0.85 0.51 1Z2 4340.1 2E 0.62 0.61 0.58 0.51 1.24 3.07 0.41 0.16 0.35 3.79 0.77 0.18 0.98 0.54 1Z2 4342.3 2F 0.62 0.61 0.58 0.50 1.22 2.97 0.40 0.15 0.34 3.85 0.77 0.19 0.97 0.58 1Z2 4344.2 2G 0.61 0.61 0.58 0.51 1.34 2.73 0.28 0.18 0.34 4.17 0.77 0.15 1.02 0.60 1Z2 4344.7 2H 0.69 0.68 0.59 0.57 1.78 0.94 0.19 0.24 0.36 12.04 0.77 0.34 1.02 0.52 2Z3 4272.7 3A 0.62 0.63 0.55 0.53 1.46 2.33 0.24 0.19 0.33 2.79 0.69 0.19 0.84 0.48 1Z3 4275.2 3B 0.61 0.61 0.55 0.52 1.44 1.80 0.41 0.05 0.36 2.70 0.75 0.37 0.82 0.43 1Z3 4295.8 3C 0.55 0.51 0.35 0.38 1.57 0.23 0.08 0.37 0.47 4.34 0.70 0.37 0.44 0.18 4Z3 4304.3 3D 0.62 0.60 0.57 0.51 1.36 3.24 0.34 0.17 0.34 3.48 0.75 0.17 0.96 0.53 1Z3 4305.2 3E 0.62 0.60 0.55 0.53 1.32 3.25 0.24 0.18 0.33 3.75 0.76 0.17 0.93 0.53 1Z4 4131.4 4A 0.64 0.58 0.58 0.50 1.26 2.67 0.34 0.18 0.36 5.37 0.68 0.61 0.75 0.55 1Z4 4339.2 4B 0.62 0.62 0.56 0.52 1.65 2.12 0.33 0.16 0.33 3.97 0.76 0.23 0.95 0.46 1Z4 4361.1 4C 0.63 0.63 0.57 0.52 1.41 2.15 0.30 0.17 0.34 7.18 0.79 0.20 1.06 0.63 1Z4 4368.2 4D 0.62 0.60 0.57 0.52 1.35 3.09 0.26 0.18 0.35 3.48 0.75 0.18 0.94 0.52 1Z4 4373.3 4E 0.62 0.62 0.53 0.51 1.36 1.82 0.23 0.06 0.34 4.91 0.81 0.07 0.76 0.53 1Z4 4381.5 4F 0.61 0.61 0.57 0.52 1.28 3.26 0.26 0.18 0.33 4.03 0.77 0.21 0.96 0.54 1Z4 4389.2 4G 0.62 0.61 0.54 0.52 1.41 2.32 0.29 0.04 0.34 2.84 0.75 0.34 0.83 0.47 1
988Form
ationofthe
Low-Oil-Saturation
Moxizhuang
Field,JunggarBasin,China
RES
The
The
base(W
a199eta(22C32
Z5 4611.9 5A 0.64 0.65 0.51 0.57 0.71 0.33 0.84 0.61 2Z5 4658.7 5B 0.61 0.59 0.46 0.55 0.67 0.12 0.62 0.37 2Z5 4667.0 5C 0.64 0.57 0.56 0.58 0.79 0.26 0.85 0.59 2C1 5036.1 C1 0.59 0.60 0.51 0.52 0.54 0.14 0.11 0.25 3C1 5036.5 C2 0.60 0.59 0.52 0.54 0.61 0.16 0.17 0.25 3C1 5037.9 C3 0.59 0.59 0.48 0.51 0.68 0.10 0.21 0.25 3C1 5325.9 C4 0.60 0.59 0.50 0.53 0.66 0.15 0.17 0.25 3D1 4582.0 D1 0.62 0.61 0.58 0.50 0.52 0.27 0.23 0.28 4D1 4586.4 D2 0.63 0.61 0.59 0.51 0.54 0.24 0.44 0.21 4D1 4837.2 D3 0.60 0.60 0.49 0.49 0.63 0.28 0.24 0.28 4D1 4871.0 D4 0.59 0.59 0.49 0.47 0.43 0.07 0.27 0.13 3D1† 5226.5 D5 0.58 0.58 0.47 0.34 0.62 0.34 0.23 0.22 4D1 5298.4 D6 0.58 0.68 0.47 0.54 0.50 0.12 0.10 0.31 3
*ID = sample identifications in Figure 8; C31 S/S + R = C31 22S/(22S + 22R) homohopane; C32 0R); C29 bb/(bb + aa) = 5a-C29 sterane bb/(bb + aa);Pr/Ph = pristane/phytane; b/H = b-carotane/ab C30 hopane; G/H = gammacerane/ab C C24/C24 + C26 = C24 tetracyclic terpane/(C24 tetracyclicterpane + C26 tricyclic terpane); STT/H = SC19-C29 tricyclic terpanes/ab C30 hopane; E steranes; S/H = SC27-C29 steranes/SC27-C35 hopanes.
†Parameters used in the hierarchical cluster analysis.
Figure5.C
29 20S/(20S+20R)versusC
29 bb/(bb+aa)sterane
ratiosfor
oilsfrom
theMoxizhuang
fieldand
C1and
D1dis-
coveriesin
thecentralJunggar
Basin.Vitrinitereflectance
(Ro )
estimatesw
erefrom
correlationsinPetersand
Moldow
an(1993)
andJustw
anetal.(2006).
Haoetal.
989
0.68endsterganoilmtionC29
hav(T
a
1.33 2.92 0.09 0.27 0.27 4.151.35 1.57 0.06 0.26 0.31 2.031.24 3.08 0.08 0.27 0.28 4.204.06 0.00 0.03 0.70 1.00 0.154.02 0.00 0.04 0.62 1.00 0.214.04 0.00 0.04 0.56 1.00 0.174.04 0.00 0.02 0.55 0.96 0.151.73 0.00 0.11 0.25 0.44 1.921.61 0.00 0.22 0.30 0.50 3.431.90 0.00 0.09 0.45 0.54 2.283.03 0.00 0.02 0.64 0.90 0.221.56 0.00 0.09 0.48 0.46 3.042.65 0.00 0.04 0.71 1.00 0.89
S/S + R = C32 22S/(22S + 22R) homohopane; C29 S/S + R = C29 sterane 20S/(20S + 230 hopane; C19+20 TT/STT = C19 + C20 tricyclic terpanes/SC19-C29 tricyclic terpanes;TR = (C28 + C29)/(C28 + C29 + Ts); C27/C29 = C27/C29 steranes; C28/C29 = C28/C29
ULTS
AND
DISC
USSIO
N
rmalM
aturityof
CrudeOil
thermalm
aturityofcrude
oilcanbe
evaluateddon
theanalysis
ofthe
saturatebiom
arkersplesand
Machihara,1990;Petersand
Moldow
an,3;K
atzetal.,2000;Petersetal.,2005;Justw
anl.,2006).T
heanalyzed
samplesdisplay
C3122S/
S+22R
)homohopane
ratiosof0.55to
0.69and
22S/(22S+22R
)homohopane
ratiosof0.51to
(Table
pointvane
ratiicmatte
aturityof
two
bb/(bbenot
reble
1;F
1).Mostofthese
ratiosare
closeto
thealues
(0.57–0.62).T
heC29bb/(bb
+aa)
ois
believedto
beindependent
ofor-
rinput
andisan
effectiveparam
eterof
(Peterset
al.,2005).With
theexcep-
samples,
theanalyzed
samples
display+aa)sterane
ratiosgreaterthan0.45
butached
theendpoint
values(0.67
–0.71)igure
5).Allbut
oneanalyzed
sample
have C29 20S/(20S + 20R) sterane ratios rangingbetween 0.46 and 0.59 (Table 1; Figure 5). Thepositive correlation between C29 bb/(bb + aa) andC29 20S/(20S + 20R) sterane ratios, which is com-monly observed in many basins such as the SouthCaspian Basin (Katz et al., 2000), was not observed(Figure 5). In addition, of the 47 samples analyzed,22 samples (two samples from the D1 discovery,20 samples from the Moxizhuang field) have 20S/(20S + 20R) sterane ratios higher than the end-
990 Formation of the Low-Oil-Saturation Moxizhuang Field, Jun
point values (0.52–0.55). Such abnormally highC29 20S/(20S + 20R) sterane ratios were also ob-served in oils in the south Viking Graben (Justwanet al., 2006) and in the Penglai 19-3 and QHD 32-6oil fields in the Bohai Bay Basin (Hao et al., 2009a,b). The causes of these abnormal phenomena areyet unclear, but may be probably caused by the ef-fect of mixing of oils of different origins (Wilhelmsand Larter, 2004) and/or in-reservoir alteration(Hao et al., 2009a, b). According to the correlation
Figure 6. Representative mass chromatograms of terpanes (mass to change ratio [m/z] = 191) and steranes (m/z = 217) for theanalyzed samples. Peaks marked by solid dots are tricyclic terpanes (C19-C29); C24 Tet = C24 tetracyclic terpane; ab C30 H = ab C30hopane; Gam = gammacerane; C27, C28, and C29 represent C27 sterane 20R, C28 sterane 20R, and C29 sterane 20R, respectively.
ggar Basin, China
between vitrinite reflectance (Ro) and the C29 20S/(20S + 20R) sterane ratio ofWaples andMachihara(1990), Peters andMoldowan (1993), and Justwanet al. (2006), these C29 20S/(20S + 20R) steraneratios indicate that most oils were generated at ma-turity close to peak oil generation (Figure 5).
Biomarker Compositions and GeochemicalOrigin of Crude Oil
Two intervals (Permian and Jurassic) may be thesource rocks for reservoir oils in the central JunggarBasin (Figure 3). Therefore, understanding theorigin of the crude oil is of great significance both
for optimizing petroleum exploration in the centralJunggar Basin and for revealing the mechanisms forthe formation of the low-saturation oil reservoirs inthe Moxizhuang field.
Biomarker analysis is the most powerful tech-nique for oil-source correlation and oil origin classi-fication (Tissot andWelte, 1984; Peters et al., 1994,2008a, b; Hunt, 1996; Curiale, 2008). Represen-tative mass chromatograms of terpanes (mass tochange ratio [m/z] = 191) and steranes (m/z = 217)for the analyzed samples are shown in Figure 6. Inthe Junggar Basin, the Permian source rock wasdeposited in saline lakes dominated by sapropelicorganic matter, whereas the Jurassic source rockwas deposited in freshwater conditions dominated
Figure 7. Correlations between various biomarker parameters reflecting organic matter input and/or depositional environment,showing the differences in biomarker compositions between oil from the Moxizhuang (MXZ) field and oil from the C1 and D1 discoveriesin the central Junggar Basin. Tet = tetracyclic terpane; TT = tricyclic terpane; STT = SC19-C29 tricyclic terpanes; sterane/hopane = SC27-C29 steranes/SC27-C35 hopanes; Gam = gammacerane; ab C30 H = ab C30 hopane; ETR = (C28 + C29)/( C28 + C29 + Ts).
Hao et al. 991
byhigher plant organicmatter (Figure 3) (Zou et al.,2008a; Li et al., 2010). Therefore, parameters re-flecting organic matter input and/or depositionalconditions can be used to distinguish oils havingdifferent origins (Hunt, 1996; Peters et al., 2005,2008a; Curiale, 2008). Ten parameterswere used toinvestigate the origins of oils in the central JunggarBasin (Table 1). The geochemical significance ofthese parameters will be briefly discussed here.
The C19-C20 tricyclic terpanes originate mainlyfrom diterpenoids (Peters et al., 2005), which areproduced by vascular plants (Barnes and Barnes,1983). Therefore, high C19 + C20 tricyclic terpanes/tricyclic terpanes (C19+20 TT/STT) ratios indicateimportant contributions from terrigenous organicmatter (Hanson et al., 2000; Preston and Edwards,2000; George et al., 2004; Volk et al., 2005; Haoet al., 2009a). In the Junggar Basin, C24 tetracyclicterpane/(C24 tetracyclic terpane + C26 tricyclic ter-pane) (C24 Tet/[C24 Tet + C26 TT]) ratios increaseas pristane/phytane (Pr/Ph) and C19 + 20 TT/STTratios increase (Figure 7A, B), confirming that highC24 Tet/(C24 Tet + C26 TT) ratios are diagnostic ofterrigenous organic matter input in lacustrine sourcerocks and oils (Philip and Gilbert, 1986; Bohacset al., 2000;Hanson et al., 2000; George et al., 2004;Duan et al., 2008; Hao et al., 2009a, b). In general,high sterane/hopane (SC27-C29 steranes/SC27-C35
hopanes) ratios typify organic matter having majorcontributions from planktonic and/or benthic al-gae (Moldowan et al., 1985; Peters et al., 2005).Conversely, low sterane/hopane ratios are more in-dicative of terrigenous and/or microbially reworkedorganic matter (Peters et al., 2005). Grantham andWakefield (1988) observed a general increase in therelative content of C28 steranes and a decrease inC29 steranes in marine petroleum through geologictime. However, the C28/C29 sterane ratios in la-custrine oils and source rocks are closely related toorganic matter input, especially the contributionfrom diatoms. For example, C28/C29 sterane ratiosdecrease as Pr/Ph and C19 tricyclic terpane/C23
tricyclic terpane increase, and increase as sterane/hopane and gammacerane/ab C30 hopane increasefor the Eocene and Oligocene lacustrine sourcerocks in the Bohai Bay Basin. In the Junggar Basin,C28/C29 sterane ratios increase as sterane/hopane
992 Formation of the Low-Oil-Saturation Moxizhuang Field, Jun
ratios increase (Figure 7C), suggesting that highC28/C29 sterane ratios indicate algal organic matterwith little or no contribution from higher plant or-ganic matter.
The b-carotane is believed to originate fromcyanobacteria and algae (Peters et al., 2005, and ref-erences therein), and high b-carotane/abC30 hopaneratios are believed to reflect source rock depositionin hypersaline environments, commonly in arid cli-mates (Peters et al., 2005). The b-carotane wasdetected in all samples from theMoxizhuang field,with b-carotane/ab C30 hopane ratios ranging be-tween 0.23 and 3.93, but was not detected in allsamples from the C1 and D1 discoveries (Table 1).Gammacerane is believed to form by a reduction oftetrahymanol (ten Haven et al., 1989; Venkatesan,1989). The principal source of tetrahymanol ap-pears to be bacterivorous ciliates, which occur atthe interface between oxic and anoxic zones instratified water columns (Sinninghe Damsté et al.,1995). Therefore, abundant gammacerane is com-monly believed to indicate the presence of a strati-fied water column (Sinninghe Damsté et al., 1995;Peters et al., 2005; Zhu et al., 2005; Sepúlveda et al.,2009). Although stratified water columns can re-sult from both hypersalinity at depth and tem-perature gradients (Peters et al., 2005), the highabundance of gammacerane typifies evaporite orhigh-salinity environments (Fu et al., 1990; Chenet al., 1996; Ritts et al., 1999; Hanson et al., 2000,2001; Holba et al., 2003; Gürgey et al., 2007; Haoet al., 2007a; Manzi et al., 2007; Summons et al.,2008). In the Junggar Basin, gammacerane/abC30
hopane decreases as Pr/Ph increases (Figure 7D),as was observed in lacustrine oils and source rocksfrom Angola (Peters et al., 2005). Oils from theC1 and D1 discoveries have low gammacerane/abC30 hopane (commonly <0.1) but high Pr/Ph(>1.5; Figure 7D), which is consistent with thefact that no b-carotane was detected.
Holba et al. (2001) used the extended tricyclicterpane ratio (ETR = [C28 + C29]/[C28 + C29 + Ts])to differentiate crude oils generated from Triassic,Lower Jurassic, andMiddle–Upper Jurassic marinesource rocks. They observed a sharp drop in ETRat the end of the Triassic that corresponds to amajor mass extinction and implied that the mass
ggar Basin, China
extinctionmayhave had an impact on the principalbiological sources of tricyclic terpanes. However,the effectiveness of ETR as an age-related param-eter was questioned by Ohm et al. (2008). In theJunggar Basin, ETR decreases as Pr/Ph and C19 + 20
TT/STT increase (Figure 7E, F) and increases asgammacerane/ab C30 hopane, sterane/hopane,and C28/C29 sterane ratios increase (Figure 7G–I).Similar trends were also observed in the CenozoicBohai Bay Basin, where ETR increases with in-creasing gammacerane/abC30 hopane and C35 22S/C34 22S hopane ratios (Hao et al., 2009a). Ourobservations in the Junggar and Bohai Bay basinsare consistent with those of Kruge et al. (1990a, b)and De Grande et al. (1993), who concluded thatfossil lipids of prokaryotes in anoxic, saline, alka-line lakes are rich in precursors of extended tricyclicterpanes. The close correlations of ETRwith Pr/Ph,sterane/hopane, and gammacerane/ab C30 hopaneratios indicate that in lacustrine environments, ETRis an effective indicator of the salinity and alkalinityduring or immediately after deposition of sourcesediments (Hao et al., 2009a).
The best way to distinguish crude oils gener-ated from different source rocks using multipleparameters is multivariate statistics (Peters et al.,1986, 2007, 2008a;Zumberge, 1987;Hanson et al.,2000; Hostettler et al., 2004; Justwan et al., 2006;Hao et al., 2009a, b). Hierarchical cluster analysis isa commonly used statistical technique in whichcluster distance between samples is calculated inmultidimension or n space (where n represents thenumber of parameters used). The HCA was ap-plied to the biomarker data for the analyzed sam-ples to sort out the differences in the biomarkerratios, to test for correlations of oils within theMoxizhuang field or between the Moxizhuangfield and the two discoveries, and to relate thetrapped oil to specific source rock intervals. Figure 8shows the dendrogram using the 10 selected pa-rameters listed in Table 1. The HCA separates theanalyzed samples into two supergroups or clans(Peters et al., 2007). Note that all but two samplesfrom theMoxizhuang field are classified into clan A,whereas all samples from the C1 andD1 discoveriesare classified as belonging to clan B (Figure 8). Basedon biomarker compositions of the analyzed sam-
ples (Table 1; Figures 6, 7) and the result of HCA(Figure 8), four oil classes can be identified.
Class 1 OilClass 1 oil belongs to clan A and is found in theMoxizhuang field (Figure 8). Class 1 oil has thelowest C19 + 20 TT/STT (0.04–0.20) and C24 Tet/(C24 Tet + C26 TT) (0.33–0.36) but the higheststerane/hopane (0.43–0.63) and C28/C29 sterane(0.75–1.06) ratios (Table 1; Figure 7) withabundant tricyclic terpanes (Figure 6A), suggest-ing that source rock for class 1 oil has minor or noterrestrial organic matter input. Class 1 oil has thelowest Pr/Ph ratios (1.17–1.67) but the highestgammacerane/ab C30 hopane (0.23–0.43) and b-carotane/ab C30 hopane (1.80–3.26) ratios and
Figure 8. Result of hierarchical cluster analysis (HCA), showingcrude oil classes in the central Junggar Basin. ID = sampleidentifications in Table 1.
Hao et al. 993
ETR (0.68–0.81) (Table 1; Figure 7), suggestingsource rock deposition in hypersaline anoxic envi-ronments. In the Junggar Basin, all potential sourcerock intervals except Permian have significant con-tribution from, or even are dominated by, higherplant organic matter (cf. Figure 3), and source rockdeposited in hypersaline environments (with abun-dant gammacerane and b-carotane) with minor orno terrestrial organic matter input was only found inthe Permian (Li et al., 2010). Therefore, class 1 oil isinterpreted to originate from Permian source rock.
Class 2 OilClass 2 oil belongs to clan A and is also found inthe Moxizhuang field (Figure 8). Compared withclass 1 oil, class 2 oil displays relatively higher Pr/Ph (1.24–1.78) and C19+20 TT/STT (0.21–0.27)ratios but lower gammacerane/ab C30 hopane(0.06–0.22), b-carotane/ab C30 hopane (0.94–3.08), sterane/hopane (0.37–0.61), and C28/C29
sterane (0.62–1.02) ratios and ETR (0.61–0.79)(Table 1; Figure 7). In addition, whereas class 1 oilhas C20/C23 tricyclic terpane (C20/C23 TT) lowerthan 1.0, class 2 oil displays C20/C23 TT higherthan 1.0 (Figure 6A, B). The systematic differ-ences between class 1 oil and class 2 oil suggestthat source rock for class 2 oil has increased con-tribution from higher plant organic matter and wasdeposited under less saline, less anoxic conditions.Class 2 oil is interpreted to have been derived fromthe Permian source rock that was deposited inbrackish lakes.
Class 3 OilClass 3 oil belongs to clan B and is found in the C1and D1 discoveries (Figure 8). Class 3 oil is dis-tinctly different from class 1 oil and class 2 oil(Table 1; Figures 6, 7). Class 3 oil has very lowabundances of tricyclic terpanes (Figure 6C), withSC19-C29 tricyclic terpanes/ab C30 hopane ratiosless than 0.9 (Table 1). Class 3 oil has the highestPr/Ph (2.65–4.06), C19+20 TT/STT (0.55–0.71),and C24 Tet/(C24 Tet + C26 TT) (0.9–1.0) ratiosbut displays the lowest gammacerane/ab C30
hopane (0.02–0.04), C28/C29 sterane (0.10–0.27),sterane/hopane (0.13–0.31) ratios and ETR (0.43–0.68) in the analyzed samples (Table 1; Figures 6,
994 Formation of the Low-Oil-Saturation Moxizhuang Field, Jun
7). In addition, no b-carotane was detected inclass 3 oil. The absence of b-carotane and the verylow gammacerane abundance suggest that sourcerock for class 3 oil was deposited in freshwater en-vironments without well-developed stratified watercolumns (Sinninghe Damsté et al., 1995; Peterset al., 2005). The high Pr/Ph, C19+20 TT/STT, andC24 Tet/(C24 Tet + C26 TT) ratios, combined withthe low C28/C29 sterane and sterane/hopane ratiosand ETR, indicate that class 3 oil was derived fromsource rock dominated by higher plant organicmatter. This means that class 3 oil must not haveoriginated from the Permian source rock becausethe Permian source rock in the Junggar Basin wasdominated by algal organic matter deposited inbrackish to hypersaline anoxic lakes. Class 3 oil isinterpreted to have been generated from the Ju-rassic source rock.
Class 4 OilClass 4 oil also belongs to clan B and is found in theD1 discovery and theMoxizhuang field (Figure 8).Class 4 oil has biomarker compositions in-betweenclass 1 oil and class 3 oil (Figures 6, 7). Taking intoconsideration that Permian and Jurassic are thetwo potential source rock intervals in the studyarea (Figure 3) and that class 1 oil and class 3 oiloriginated from Permian and Jurassic source rocks,respectively, class 4 oil is interpreted to originatemainly from the Jurassic source rock, with somecontributions from the Permian source rock.
Present-Day Oil Saturations andPaleo-Oil Saturations
The measured oil saturations for the Moxizhuangfield range from 0.4 to 40%, with most sampleshaving measured oil saturations less than 20%(Figure 9A, B). Mobile oil saturations were calcu-lated for two wells from well-log data (Figures 10,11). The calculated mobile oil saturations rangefrom near zero to 46%, which are in reasonableagreementwithmeasured oil saturations (Figures 10,11). In addition, all tested intervals produced ei-ther both oil and water or water only, and mea-surements on core samples and calculations from
ggar Basin, China
well logs both indicate that all reservoirs containsignificant amounts of mobile water (Figures 10,11). The above evidence indicates that, current-ly, the Moxizhuang field is a low-oil-saturationfield.
As previously discussed, oil in theMoxizhuangfield was generated mainly from Permian sourcerock. Peak oil generation from the Permian sourcerock in the central Junggar Basin occurred duringthe Late Cretaceous to the Paleogene (Qiu et al.,2008; Zou et al., 2008a). This implies that theMoxizhuang field may have been affected byNeogene tectonicmovements, which significantlychanged the structural framework of the basin(Figure 2). Given the complex evolution of the
field, two possibilities exist for the formation of thepresent-day low-saturation oil reservoirs: (1) ini-tially inefficient oil charge or (2) oil loss from high-saturation paleo-oil reservoirs. Therefore, estimat-ing paleo-oil saturations is a key to understandingthe formation mechanism of the low-saturationMoxizhuang field.
The GOI technique is a quantitative method toestimate paleo-oil saturations in sandstone reser-voirs (Lisk et al., 2002; George et al., 2004; Brincatet al., 2006). Fluid inclusions are small (commonly<10 mm in diameter) samples of reservoir fluidsealed from the formation during the crystalliza-tion of framework minerals, such as quartz, feld-spar, and carbonates, and represent samples of the
Figure 9. Variation of measured oil saturation with porosity (A) and permeability (B) for reservoirs in the Moxizhuang field, JunggarBasin, compared with oil saturation variation in the Pearl River Mouth Basin (C) and on the Norwegian Continental Shelf (D). Dashedlines in panels A and B show the approximate limit of data point distributions. The solid and dashed lines in panel D are the best fits forthe Frøy field and Rind discovery, respectively. Data for the Frøy field and Rind discovery are from Bhullar et al. (1999b) (published withpermission from Elsevier). Note the complex relationship between oil saturation and porosity and permeability for the Moxizhuang field,which is atypical of both the filled reservoirs (C) and drained reservoirs (D).
Hao et al. 995
formation fluid contained in the adjacent porespace at the time of their formation (George et al.,2007). Oil-bearing fluid inclusions can be seen ashidden oil shows that form when oil is presentwithin the pore network (Brincat et al., 2006;George et al., 2007). Therefore, the number offramework minerals containing oil inclusions re-flects the filling of available pore space and is anapproximate measure of fluid saturation. Based onGOI measurements for a series of oil fields fromAustralian basins, Lisk et al. (2002) and Brincatet al. (2006) proposed that GOI values greaterthan 5% indicate high oil saturation (oil accumu-
996 Formation of the Low-Oil-Saturation Moxizhuang Field, Jun
lation), whereas GOI values less than 1% reflect oilmigration without accumulation.
To estimate the paleo-oil saturations, GOI anal-yseswere performed on19 samples from thewater-bearing zones (water zones) and 20 samples fromthe oil- and water-bearing zones (low–oil satura-tion pay zones). FromFigures 10–12, the followingobservations can be made:
1. The 39 analyzed samples display GOI valuesbetween 0.9 and 38%, with an average of 16%.Only eight samples (five samples from waterzones and three from pay zones, Figure 12A)
Figure 10. Results of logging interpretation, drill-stem test (DST), and grains-containing-oil-inclusions (GOI) analysis for well Z1, JunggarBasin. GR = natural gamma-ray log (API or mR/hr); SP = spontaneous potential logging (mV); RT = formation true resistivity (W·m); RXO =resistivity of flushed zone (W·m); ROS = residual oil saturation; MOS = mobile oil saturation; MWS = mobile water saturation; IWS =irreducible water saturation; C-MOS = mobile oil saturation calculated from well logs; M-MOS = mobile oil saturation measured on coresample; NHC = nonhydrocarbon; Asp = asphaltene; PZ = low-oil-saturation pay zone; WZ = water zone. See inset in Figure 1 for welllocation.
ggar Basin, China
have GOI values less than 5%. In contrast,79.5% of the analyzed samples, regardless ofwhether from the water zones or pay zones,have GOI values greater than 5%.
2. The highest GOI values occur in the water zonein well Z2 (Figure 11). The high GOI values areconsistent with the abundant bitumen observedin the present-day water zones (J. Z. Liu, 2009,personal communication). Both the water andpay zones between 4331 and 4386 m (14,209–14,390 ft) in well Z1 and between 4303 and4365 m (14,117–14,321 ft) in well Z2 displayGOI values greater than 5%, the generally ac-cepted threshold GOI value for an oil column(Lisk et al., 2002; Brincat et al., 2006). In ad-
dition, these GOI values are comparable to thosefor high-saturation oil reservoirs from the BohaiBayBasin (Figure 12B) and oil zone samples fromAustralian basins (Lisk et al., 2002; Brincat et al.,2006). Therefore, it may be concluded that allsandstone intervals between 4331 and 4386 m(14,209–14,390 ft) in well Z1 (Figure 10) andbetween 4303 and 4365 m (14,117–14,321 ft) inwell Z2 (Figure 11), whether water or pay zonesat present, were once high-saturation oil reservoirs.
3. All samples below 4365 m (14,321 ft) in wellZ2 have GOI values between 1.0 and 5.0%(Figure 11). Brincat et al. (2006) believed thatGOI values between 1 and 5% are rare and sug-gested that they characterize low-permeability
Figure 11. Results of logging interpretation, drill-stem test, and grains-containing-oil-inclusions (GOI) analysis for well Z2, JunggarBasin. Abbreviations are explained in Figure 10. See inset in Figure 1 for well location.
Hao et al. 997
reservoirs, or cutting samples from the oil zonediluted by low-oil-saturationmaterial from belowthe oil-water contact. In our study, all GOI valueswere measured on core samples, which rules outthe possibility of the dilution of oil zone materialby low-oil-saturation material. Therefore, theGOI values between 1 and 5% below 4365 m(14,321 ft) in well Z2 probably represent a low-oil-saturation zone resulting from insufficientoil charge.
The chemical compositions of crude oils andsandstone extracts provide additional evidence forhigh paleo-oil saturations in the Moxizhuang field.Some of the analyzed samples have abnormallyhigh nonhydrocarbon and asphaltene contents (asmuch as 90%; Figures 10, 11). Petroleum expelledfrom source rock commonly has lower nonhydro-carbon and asphaltene contents compared withresidues in the source rock (Tissot andWelte, 1984;
998 Formation of the Low-Oil-Saturation Moxizhuang Field, Jun
Hunt, 1996). Petroleum along migration routes(no accumulation) may have abnormally high non-hydrocarbon and asphaltene contents (Miles, 1990;Bhullar et al., 2000); however, sandstones alongmigration routes commonly display GOI values lessthan 1% (Lisk et al., 2002; Brincat et al., 2006).Therefore, the abnormally high nonhydrocarbonand asphaltene contents can only be explained as aresult of preferential loss of large amounts of lowermolecular weight hydrocarbons. Preferential lossof these hydrocarbons resulted in decreased oilsaturations and increased nonhydrocarbon andasphaltene contents and left behind abundant bi-tumen in the reservoirs (J. Z. Liu, 2009, personalcommunication).
In summary, the pay zones and several waterzones in the Moxizhuang field have high GOI val-ues (mostly >5%, the generally accepted thresholdGOI value for an oil column), high bitumen abun-dances, and abnormally high nonhydrocarbon andasphaltene contents. The three lines of evidencecoincide. They indicate that the present-day low-oil-saturation pay zones and several water zones intheMoxizhuang fieldwere high-saturation oil zonesin the geologic past.
Mechanisms for the Formation of theLow-Saturation Oil Reservoirs
The previous discussion confirms that the low-saturation oil reservoirs in the Moxizhuang fieldevolved from high-saturation oil reservoirs, whichmeans that significant amounts of oil were lostafter oil accumulation.
Loss of accumulated oil is a common phe-nomenon in sedimentary basins having complexhistories. Mechanisms reported in the literaturethat may cause oil loss after accumulation includebiodegradation and water washing, in-situ oil crack-ing, oil displacement by late gas charge, oil leak-age through faults, and oil leakage caused byoverpressure-induced seal failure.
Biodegradation may cause loss of large amountsof hydrocarbons, forming heavy oils that are en-riched in nonhydrocarbons and asphaltenes (Tissotand Welte, 1984; Hunt, 1996; Peters et al., 2005).
Figure 12. Distribution of grains-containing-oil-inclusions(GOI) values for present-day water zones and pay zones in theMoxizhuang field (A) and for high-saturation oil reservoirs off-shore Bohai Bay Basin (B).
ggar Basin, China
All samples from the Moxizhuang field have fullsuites of normal alkanes and display a predomi-nance of n-C17 over pristane (Pr/n-C17 between0.24 and 0.45) and n-C18 over phytane (Ph/n-C18
between 0.13 and 0.40) with no 25-norhopane(Figure 6), suggesting that the effect of biodegra-dation, if any, is minor. Water washing alone (with-out associated biodegradation) will preferentiallyremove water-soluble components of petroleum,especially low-molecular-weight aromatic hydro-carbons (Lafargue and Barker, 1988; Kuo, 1994).This will increase the n-alkane to aromatic ratiosfor the C6 and C7 fractions (de Hemptinne et al.,2001) and change the concentrations and distri-bution patterns of aromatic hydrocarbons in thewater-washed oils (Huang et al., 2003). Such phe-nomenawere not observed in theMoxizhuang field.In addition, the thin sandstone reservoirs (mostly<30 m [<98 ft]) with relatively low porosity andpermeability (Figure 4) and rapid lateral facieschanges in the central Junggar Basin might notsustain large-scale groundwater flow (Bachu 1995,1997), which appears to be essential for conveyinglarge amounts of water into the oil reservoir so thatintensivewaterwashingmay occur (deHemptinneet al., 2001). This, together with low solubility ofmost petroleum components in water except meth-ane and low-molecular-weight aromatic hydrocar-bons (Tissot and Welte, 1984), suggests that waterwashing could not account for the massive loss ofaccumulated oil in theMoxizhuang field, althoughthe influence of water washing cannot be com-pletely ruled out.
In-situ cracking of accumulated oil may occur intraps that were deeply buried after oil accumulation(Barker, 1990; Isaksen, 2004; Mankiewicz et al.,2009). Intensive oil cracking occurs at temperaturesgreater than about 160°C and thermal maturitygreater than1.3%Ro (Tissot andWelte, 1984;Hunt,1996). The present-day temperatures of the reser-voir sandstones in theMoxizhuang field are less than110°C with less than 1.2% Ro. This means that in-tense oil cracking could not have occurred, whichrules out the possibility that oil cracking caused theloss of accumulated oil in the Moxizhuang field.
Intensive late gas charge may displace accu-mulated oil (Gray, 1987; George et al., 1998; Lisk
et al., 2002; Arouri et al., 2009). In such a case,the present-day gas reservoirs have abundant oil-bearing fluid inclusions or high GOI values thatreflect oil accumulation before gas charge (Georgeet al., 1998; Lisk et al., 2002). In the Moxizhuangfield, no significant amounts of gases were found(Zou et al., 2008a), suggesting that gas chargecould not be responsible for the loss of oil.
Leakage through faults is an important mech-anism for petroleum loss in many basins world-wide, especially where fault reactivation occurred(Gartrell et al., 2003; Zhang et al., 2009). Gartrellet al. (2006) showed that oil columns can be com-pletely lost because of leakage through faults, sug-gesting that oil leakage through faults may be quiterapid in certain circumstances (Gartrell et al.,2003). As a result, oil loss through faults has beenconsidered a major risk for preservation of trappedoil (O’Brien andWoods, 1995; O’Brien et al., 1996,1999; Gartrell et al., 2003, 2004, 2006; Langhiet al., 2010). Interpretation of three-dimensional(3-D) seismic data indicated that no faults cuttingthrough the Jurassic Sangonghe Formation existin the Moxizhuang field and nearby area (Li et al.,2010, cf. inset in Figures 1, 2), suggesting that oilloss through faults cannot be important.
Overpressure-induced seal fracturing is anothermechanism for vertical oil leakage. Case studies andtheoretical considerations indicate that overpres-sure alone or the combination of overpressure, tec-tonic stress, and the oil-gas column may cause caprock fracturing (Darby et al., 1996; Holm, 1998;Bhullar et al., 1999a;Hao et al., 2000; Sibson, 2000,2003; Cosgrove, 2001; Hao, 2005). Overpressure-induced fractures are intermittently opening andsealing (“crack-seal”) (Laubach, 1988; Hunt, 1990),causing episodic release of overpressured fluidsand reduction in formation pressure (Dewers andOrtoleva, 1994; Caillet et al., 1997; Holm, 1998).Flow rates in fractures may be high (Roberts andNunn, 1995) and leakage through overpressure-induced fracturesmay empty petroleum-filled traps(Ungerer et al., 1990; Bhullar et al., 1999a; Løsethet al., 2009). In theMoxizhuang field, the reservoirsare normally pressured to weakly overpressured.Although fractures can grow in normally pressuredrock (Olson et al., 2009) and remain open for a long
Hao et al. 999
period (Becker et al., 2010), the following obser-vations and considerations seem to indicate thatoverpressure-induced seal failure cannot accountfor the massive loss of oil in the Moxizhuang field.(1) The central Junggar Basin has experiencedsuccessive subsidence and sedimentation since theEarly Cretaceous (Li et al., 2010) (cf. Figure 2),and sandstone reservoirs in the Sangonghe For-mation in the Moxizhuang field are currently attheir maximum burial depths and probably at theirmaximum pressures. The weak overpressure, plusthe compressional stress regime (Li et al., 2010)and thin oil columns (Figures 10, 11), could nothave caused intensive fracturing (Sibson, 2000,2003). (2) The Moxizhuang field is located in thebasin center, and both the Sangonghe Formationand the overlying Lower Cretaceous are dominatedby shales. Although individual fractures may existand even remain open, it seems unlikely that thesefractures connected to one another to form effec-tive vertical conduits for intense oil loss across thethick shales. (3) Intense petroleum leakage throughfractures may cause seismic anomalies (Løsethet al., 2009). A detailed survey of 3-D seismicdata over the Moxizhuang field and nearby area,however, suggests no leakage-related seismic anom-alies (J. Z. Liu, 2010, personal communication).(4) Rapid leakage through overpressure-inducedfractures commonly causes geologic and geochem-ical anomalies in the overlying strata, such as ab-normally highdrill-stem test temperatures and fluid-inclusion homogenization temperatures (Duddyet al., 1994; Hao et al., 2000), enhanced vitrinitereflectance and claymineral transformation (Whelanet al., 1994; Hao et al., 2000), and abnormally highRock-Eval S1 peaks (milligrams of hydrocarbonsthat can be thermally distilled from 1 g of rock), butabnormally low Tmax (the temperature at which themaximum amount of hydrocarbons is generated bypyrolytic degradation of the kerogen) values (be-cause of migration contamination) (Whelan andCathles, 1994; Hao et al., 1995, 2007b). Such ab-normal phenomena were not observed in the Mox-izhuang field and nearby wells.
Having eliminated other factors, we believethat the only plausible mechanism for intensive oilloss in the Moxizhuang field was lateral leakage
1000 Formation of the Low-Oil-Saturation Moxizhuang Field, Ju
caused by a change in geologic framework. Inten-sive oil charge in the Moxizhuang field occurred inthe Late Cretaceous and the Paleogene (Zou et al.,2008a). A paleoanticline existed before the Neo-gene, and the present-day Moxizhuang field wasthen on the north wing of the paleoanticline (theJurassic Sangonghe Formation dipped to the north)(Figure 2A). The uplift and northward obductionof the northern Tian Shan since theNeogene causedrapid subsidence and sedimentation in the southernJunggar Basin, which fundamentally changed thestructural framework of the basin (Li et al., 2010).As a result, the paleoanticline trap disappeared, andthe Jurassic Sangonghe Formation gradually be-came a south-dipping monocline (Figure 2B). Oilthat had accumulated in the paleoanticline trapremigrated updip (to the north) and was drainedfrom the Moxizhuang field, causing the loss of oil.
The driving forces for petroleum migration inporous reservoirs are buoyancy and groundwaterflow, and the restraining force is capillary pressurethat increases with decreasing pore-throat size,increasing interfacial tension, and increasing wet-tability (Schowalter, 1979; England et al., 1987;England, 1994; Hindle, 1997). When oil enters atrap, it will preferentially accumulate in reservoirzones having higher porosity and permeability(England et al., 1987; Leythaeuser and Rückheim,1989; Bhullar et al., 1999b; Leythaeuser et al., 2000).As a result, oil saturation increases with increas-ing porosity and permeability in filled reservoirs,as was observed in the Pearl River Mouth Basin(Figure 9C) and in the Frøy field in the North Sea(Figure 9D) (Bhullar et al., 1999b). When oil leaksfrom a trap, the larger pores are drained moreeasily than the smaller ones, resulting in a decreaseof residual oil saturation with increasing porosityand permeability in drained reservoirs (Figure 9D)(Bhullar et al., 1999b). The following character-istics make the Moxizhuang field atypical of boththe filled and the drained reservoirs. (1) Both waterzones and low-oil-saturation pay zones have highGOI values. For example, a water zone with GOIvalues between 14.6 and 27.3% occurs 2 m (6.6 ft)below a low-oil-saturation pay zone (4352.9–4373.7 m [14,281.2–14,349.4 ft]) with GOI val-ues between 9.5 and 18.6% in well Z1 (Figure 10),
nggar Basin, China
whereas a water zone withGOI values up to 35.9%occurs 2 m (6.6 ft) above a low-oil-saturation payzone in well Z2 (Figure 11). (2) The correlationsbetween oil saturation and porosity and perme-ability are complex. As shown in panels A and Bof Figure 9, the data points on the oil saturationversus porosity and permeability plots are highlyscattered. Although relatively high oil saturation(>25%) always occurs in samples with measuredporosity less than 10% and permeability less than10 md, and samples with porosity greater than15% always display oil saturations less than 20%,neither positive nor negative correlations betweenoil saturation and porosity and permeability canbe observed. Note that the ranges of oil satura-tions decrease as porosity and permeability increase(Figure 9A, B).
Given the change in geologic framework afteroil accumulation (Figure 2), the complex distri-bution of GOI values and present-day oil satura-tions can be readily explained as the combinedresult of “preferential oil accumulation” in and“differential oil leakage” from heterogeneous res-ervoirs having different lateral connectivities.
Preferential Oil AccumulationDuring oil charge when the paleoanticlinal trapexisted (Figure 2A), oil preferentially accumulatedin laterally continuous sandstone layers havinghigh porosity and permeability. Within a givensandstone layer, oil preferentially accumulated inzones having relatively higher porosity and per-meability. As a result, high-quality sandstone lay-ers with good lateral connectivity had the highestoil saturation (and probably the highest GOI val-ues). In contrast, sandstone layers at the lowerpart of the paleoanticline trap, such as the sand-stone layer below 4365 m (14,321 ft) in well Z2(Figure 11), were only weakly charged, probablybecause of poor reservoir quality (Brincat et al.,2006). This is perhaps the major reason thissandstone interval displays the unusual GOI val-ues between 1 and 5% (Figure 11) (Brincat et al.,2006). Within both fully filled and weakly filledsandstone layers, a positive correlation betweenoil saturation and porosity and or permeability isexpected.
Differential Oil LeakageAs the paleoanticline gradually became a south-dipping monocline (Figure 2B), oil formerly pre-sent in the paleoanticline remigrated updip (to thenorth). The so-called differential oil leakage dur-ing the remigration phase can be observed at threelevels.
1. Oil leaked preferentially from high-quality res-ervoir layers having good lateral connectivity.As a result, filled sandstone layers having goodlateral connectivity and the highest oil satura-tions before leakage because of “preferentialaccumulation” were drained completely, form-ing the present-day water zones with high GOIvalues (e.g., 4376.0–4385.3m [14,357–14,387 ft]in well Z1 and 4333–4340 m [14,216–14,239 ft]in well Z2; Figures 10, 11). The formerly filledsandstone layers having poorer lateral connec-tivity had lesser oil loss, and the accumulated oilwas partially preserved, forming the present-daylow-oil-saturation pay zones with GOI valuesgreater than 5% (Figures 10, 11).
2. Within any formerly filled layer, reservoir zoneshaving relatively high porosity and permeabil-ity were drained more easily. In the partiallydrained reservoirs, a negative correlation betweenoil saturation and porosity and permeability,like that in the Rind discovery in the North Sea(Figure 9D) (Bhullar et al., 1999b), is expected.In contrast, the weakly charged reservoirs in-dicated by the rare GOI values between 1 and5% (Brincat et al., 2006) had minor oil lossbecause of poor reservoir quality. In such poorlycharged reservoirs, the positive correlationbetween oil saturation and porosity and per-meability as a result of preferential accumula-tion should be preserved. The combination ofthese two opposite correlations caused the scat-tered distribution of the data points and the ob-served trend that the ranges of oil saturationsdecrease as porosity and permeability increases(Figure 9A, B).
3. Low-molecular-weight compounds in petro-leum, which have greater buoyancy and smallermolecular size, were preferentially lost, leadingto the abnormally high nonhydrocarbon and
Hao et al. 1001
asphaltene contents in some extremely depletedreservoirs (Figures 10, 11).
Implication for Petroleum Exploration inBasins Having Complex Histories
It seems that the combination of preferential ac-cumulation in and “differential leakage” from het-erogeneous reservoirs can be inferred from the geo-logic histories and could explain all the observedfacts. Compared with other postaccumulation phys-icochemical alteration processes previously dis-cussed, lateral leakage has been rarely recognized insedimentary basins. Recognizing differential lat-eral leakage of accumulated petroleum has im-portant implications for petroleum exploration insedimentary basins having complex histories.
1. High-quality cap rock and preservation of ac-cumulated petroleum. Finding areas with high-quality cap rocks is an important strategy forpetroleum exploration in superimposed basinsin China, considering that petroleum accumu-lations in these areas would be preserved (Maet al., 2004). The massive loss of accumulatedoil in the Moxizhuang field, however, indicatesthat even areas with high-quality unfaulted caprocks still had a major risk of petroleum loss bylateral leakage in basins that experienced fun-damental changes in structural framework afterintensive petroleum generation.
2. Types of potential petroleum reservoirs asso-ciated with lateral leakage. The degree to whichthe accumulated petroleum was lost seems tobe mostly controlled by the lateral connectivityof the reservoir rocks. This implies that theremight be different types of petroleum accumu-lations associated with lateral leakage in sedi-mentary basins in which fundamental changesin structural framework occurred after inten-sive petroleum generation. (1) Preserved pe-troleum reservoirs: Petroleum accumulated inreservoir rocks surrounded by nonpermeablerocks (such as sandstone lens in mudstones and/or shales and permeable dolomite in nonper-meable limestone) would be preserved. For ex-ample, the Puguang gas field in the Sichuan
1002 Formation of the Low-Oil-Saturation Moxizhuang Field, Ju
Basin, the largest gas field inmarine carbonate inChina, evolved from a large paleo-oil accumu-lation (Hao et al., 2008). Intensive oil chargeinto the Lower Triassic oolitic dolomites oc-curred during the Early and Middle Jurassicwhen the reservoir rock dipped to the south-west (Zou et al., 2008b). The Triassic reservoirsexperienced deep burial and then uplift afteroil accumulation and gradually became north-east dipping (Hao et al., 2009c). Because ofrapid lateral changes from permeable ooliticdolomites to nonpermeable limestones thatacted as a lateral seal, the reversal in dip direc-tions of reservoir rock did not result in intensivelateral leakage of accumulated oil or oil-crackinggases (Hao et al., 2009c). (2) Partially preservedpetroleum reservoir: Part of the accumulatedpetroleum would be preserved in reservoirs withpoorer lateral connectivity, forming the partiallypreserved petroleum reservoirs, like the low-saturation pay zones in the Moxizhuang field.(3) Reaccumulated petroleum reservoir: Filledreservoirs having good lateral connectivitywould be completely drained (the water zoneswith high GOI values in theMoxizhuang field).Petroleum that was drained from these reser-voirs would remigrate updip and might reaccu-mulate in traps in present-day updip areas. Thesetraps, although they might be formed long afterintensive petroleum generation, have the chanceto contain commercial petroleum accumulation.
3. Recognition of low-resistivity oil reservoirs. Inthe Moxizhuang field, the pay zones exhibitlow resistivity (Figures 10, 11). Two principalmechanisms cause low resistivity: high irreduc-ible water saturation or the existence of con-ductive minerals (such as clays, metal sulfides,graphite, and pyrite) in a clean reservoir rock(Hamada et al., 2001). Obviously, the high mo-bile water saturation as a result of oil loss fromfilled reservoirs is the main cause of the low re-sistivity of the pay zones in the Moxizhuangfield. Resistivity logs are the most effective meansto identify pay zones (Hamada et al., 2001). Theresults of this work suggest that care must betaken to ensure that the potentially productivezones are not overlooked.
nggar Basin, China
CONCLUSIONS
Based on our studies, the following conclusionscan be drawn.
1. Biomarker distributions and hierarchical clusteranalysis indicate that oil in the Moxizhuang fieldis distinctly different from oil from the C1 andD1 discoveries. Oil in theMoxizhuang field wasgenerated from Permian source rock depositedin brackish to hypersaline anoxic environmentswith minor contributions from higher plant or-ganicmatter. In contrast, oil from theC1 andD1discoveries originatedmainly from Jurassic coal-bearing strata dominated by higher plant organicmatter and deposited under freshwater dysoxicto oxic conditions.
2. Pay zones in the Moxizhuang field are low-saturation, low-resistivity oil reservoirs. TheMoxizhuang field displays a complex relation-ship between oil saturation and porosity andpermeability, atypical of either the filledordrainedreservoirs. Both pay zones and water zones haveGOI values higher than the generally acceptedthreshold GOI value for an oil column (5%).These GOI values are comparable to those forhigh-saturation oil reservoirs elsewhere, suggest-ing that both the pay zones and water zones werehigh-saturation oil reservoirs (filled reservoirs) inthe geologic past. Therefore, the reservoirs hadmassive oil loss after oil accumulation.
3. Tectonic activity converted a paleoanticline trapto a south-dipping monocline. The resultant re-migration of accumulated oil was responsible forthe intense oil loss and the abnormal phenom-ena. During the remigration phase, high-qualityreservoirs with good lateral connectivity werecompletely drained, forming present-day waterzones with high GOI values. The formerly filledsandstone layers with fair lateral connectivityhad lesser oil loss, and the accumulated oil waspartially preserved, forming present-day low-oil-saturation pay zoneswithGOI values greaterthan 5%.Differential leakage of accumulated oilin different sandstone layers was responsible forthe complex relationships between oil satura-tion and porosity and permeability. Lateral leak-
age represents a major risk of petroleum loss inareas with high-quality unfaulted cap rocks insedimentary basins that experienced fundamen-tal changes in structural framework after inten-sive petroleum generation.
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