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Geochemical characteristics and implications of hydrocarbons in reservoir rocks of Junggar Basin, China
Chemical Geology 167 Ž2000. 321–335 www.elsevier.comrlocaterchemgeo
Geochemical characteristics and implications of hydrocarbons in reservoir rocks of Junggar Basin, China Changchun Pan a,) , Jianqian Yang b a
State Key Laboratory of Organic Geochemistry, Guangzhou Institute of Geochemistry, Chinese Academy of Sciences, Wushan, Guangzhou 510640, People’s Republic of China b Research Institute of Exploration and DeÕelopment, Karamayi, Xinjiang 834000, People’s Republic of China Received 29 April 1999; accepted 19 November 1999
Abstract A practical sequential extraction approach has been applied to two core samples collected from oil zones of Triassic sandstones in Junggar Basin, northwest China. Five bitumen fractions were obtained from each sample using this approach. These fractions are free oil components in inter granular pores Žbitumen 1., adsorbed oil components on grain surfaces and liberated by HCl treatment Žbitumen 2., oil-bearing fluid inclusions hosted by grains Žbitumen 3., and adsorbed oil components on clay mineral surfaces and liberated by HCl and HCl:HF treatments Žbitumens 4 and 5.. Striking differences have been observed both in bulk compositions and in aliphatic biomarker distributions Že.g., terpanes and steranes. among the five bitumen fractions. This phenomenon is ascribed to the indigenous compositional variations and differential maturation behaviors between adsorbed oil components in a network of polar compounds Žresins and asphaltenes. and free oil components in even a same oil charge, in addition to fractional adsorption effects and compositional changes of the oil charges in reservoir rocks during filling process. The molecular compositions and homogenization temperatures of oil-bearing fluid inclusions in these two samples indicate that trapping of these types of inclusions apparently ceased in sample A, while continued in sample B after the initial oil charge, suggesting that the relative content of polar components in the initial oil charge compared to the later oil charges plays a dominant role controlling the trapping of oil-bearing fluid inclusions in an oil saturated zone. Sequential extraction studies are important and useful for reservoir geochemistry, especially in the cases where only limited samples of oil and reservoir rocks are available, andror where compositional heterogeneity of free oils has disappeared in a reservoir wKarlsen, D.A., Nedkvitne, T., Larter, S.R., Bjørlykke, K., 1993. Hydrocarbon composition of authigenic inclusions: application to elucidation of petroleum reservoir filling history. Geochim. Cosmochim. Acta 57, 3641–3659x. q 2000 Elsevier Science B.V. All rights reserved. Keywords: Oil reservoir rocks; Free oil components; Adsorbed oil components; Oil-bearing fluid inclusions; Sequential extraction; Reservoir geochemistry
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Corresponding author. E-mail address: [email protected] ŽC. Pan..
0009-2541r00r$ - see front matter q 2000 Elsevier Science B.V. All rights reserved. PII: S 0 0 0 9 - 2 5 4 1 Ž 9 9 . 0 0 2 3 6 - 3
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1. Introduction Compositional heterogeneity of oil components in reservoir rocks was well documented by Karlsen et al. Ž1993., who analyzed compositions of oil-bearing fluid inclusions hosted in different types of minerals in reservoir rocks. Oil-bearing fluid inclusions, generally believed to be samples of paleo-oil of oil reservoirs, have been heavily studied in recent years ŽGeorge et al., 1997, and references therein.. Meanwhile, an alternative method of sequential extraction has been developed and applied to oil reservoir rocks for the similar purpose of revealing the filling histories of oil reservoirs ŽWilhelms et al., 1996; Schwark et al., 1997.. Sequential extraction studies of source rocks have been reported earlier ŽSajgo et al., 1983; Spiro, 1984; Price and Clayton, 1992.. However, the forms of oil occurrence in source rocks are very different from those in reservoir rocks. Oils in reservoir rocks are dominantly in pore system, while in source rocks, according to the model presented by Pepper Ž1992. and Sandvik et al. Ž1992., mainly adsorbed by kerogens. Every step of partial extraction of oil from source rocks would naturally induce compositional fractionation between extracted and residual oil. The results of this type study can be interpreted by selective extraction and adsorption of oil components in source rocks Že.g., Price and Clayton, 1992.. Price and Clayton Ž1992. also suggested that bonding and trapping of organic compounds to and in kerogens may be partly responsible for their observation. Schwark et al. Ž1997. developed a flow-through extraction system capable of efficiently extracting core plugs while preserving the pore system of samples using two solvent systems. According to their study, extraction step 1, classified as ‘‘free oil’’, occupies 80% of the total extracts of the reservoir core. This ‘‘free oil’’ is very similar to drill stem test ŽDST. oil, both in bulk compositions and molecular biomarker distributions. In contrast, extraction steps 2, 3, 4 and 5, classified as ‘‘adsorbed oil’’, contain much more resins and asphaltenes than DST oil and ‘‘free oil’’ ŽSchwark et al., 1997, their Fig. 4.. Despite marked differences in molecular compositions, the five listed biomarker maturity parameters and n-alkane distributions do not vary consistently from extraction steps 1 to 5 ŽSchwark et al., 1997,
their Figs. 5 and 6.. The authors interpreted extraction step 5 to be a mixture of ‘‘adsorbed oil’’ and ‘‘free oil’’ in isolated pores that became accessible to solvents after the extraction of the resinsrasphaltenesrhigh molecular weight n-alkane layer which blocked narrow pore throats ŽSchwark et al., 1997.. In fact, the other ‘‘adsorbed oil’’ fractions, at least fractions 3 and 4, could also be such a mixture of oil, because ‘‘adsorbed oil’’ fractions 3, 4 and 5 have similar bulk compositions Že.g., Schwark et al., 1997, their Fig. 4.. Recently, Wilhelms et al. Ž1996. carried out a three step sequential extraction study on crushed reservoir rocks of a large sample set, using a suite of solvents with increasing polarity, and observed that although there are great differences in gross compositions, there are only very minor variations in molecular biomarker distributions among the three extracted fractions. They presented a conceptual model for oil accumulation in porous media; i.e., the onion skin model, based on the hypothesis that the first oil to enter the reservoir rocks should be the last one to be extracted out. In the present study, their conceptual model is modified under the following considerations. Ž1. Oil accumulation in reservoir rocks is a continuous and gradual process, and the oil saturation value in reservoir rocks also gradually increases if there are no secondary migration processes. During the early stage of oil filling, the oil phase may only occupy a limited part of the pore system and encounter a limited area of mineral surfaces in the reservoir rocks. An ‘‘interaction zone’’ or ‘‘adsorbed oil zone’’ between the oil phase and the minerals at different areas of mineral surfaces could not form at the same time or during the same oil charge. Ž2. Once entering oil encounters a specific area of mineral surfaces, an ‘‘interaction zone’’ or ‘‘adsorbed oil zone’’ could be established between the oil phase and the minerals by irreversible adsorption of NSO compounds. Some recent studies on polar components indicated that the adsorbed polar components rarely equilibrate further by diffusive mixing ŽLarter and Aplin, 1995; Li et al., 1995; Stoddart et al., 1995.. However, it is hard to imagine that several additional oil layers corresponding to successive oil charges during the filling process formed after the establishment of the first ‘‘adsorbed oil zone’’.
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This study, therefore, does not focus on ‘‘adsorbed oil’’ in different layers, but on oil adsorbed onto different surface areas of minerals. In reservoir sandstone rocks, there are always some clay minerals occurring in pore system or as a coating around the grains Že.g., Hamilton et al., 1992.. Once oil fills the reservoir rocks, it preferentially interacts with clay minerals, therefore, ‘‘absorbed oil’’ by clay minerals may represent the first oil charge which fills the reservoir rocks. Up till now, the facies and maturity parameters of biomarker compounds are based on aliphatic and aromatic components. Those components are not adsorbed directly by mineral surfaces with the presence of water, but are adsorbed or ‘‘trapped’’ by polar compounds themselves adsorbed by mineral surfaces. The ability of polar components to retain the adsorbed or trapped non-polar components is a critical point to the studies of sequential extraction on reservoir rocks. A recent study on desorbed hydrocarbons from asphaltenes extracted from oil reservoir rocks which suffered very strong biodegradation before 360 Ma, indicated that those components including n-alkanes in the network of asphaltenes were kept nearly ‘‘intact’’ ŽPan and Xiao, 1998.. Wilhelms et al. Ž1996. also reported a reduction in the degree of biodegradation from the first to the last extract obtained by sequential extraction. Several previous studies have also indicated that non-polar compounds entrapped within the asphaltenes were protected from the effects of in-reservoir biodegradation using mild chemical degradation methods ŽEkweozor and Strausz, 1983; Ekweozor, 1984, 1986..
2. Sample background The two samples described in this paper were collected from two hydrocarbon reservoirs of the Junggar Basin, northwest China ŽFig. 1.. Both samples, about 1 kg each, were collected from oil zones of Triassic sandstone sequences with burial depths of 4242 m Žsample A. and 4406.7 m Žsample B.. These two samples are well sorted, medium grain sandstone rocks. The mineralogical composition of the grains of sample A is about 80% quartz and 20% feldspar and plagioclase, and of sample B, about 75% quartz
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and 25% feldspar and plagioclase. Carbonate cements were not observed under microscope. Although the mineralogical compositions of the clays of these two samples are not analyzed in this study, the compositions of the clays in Triassic sandstones of these two oil reservoirs are kaolinite, illite, chlorite and mixed layer illitersmectite in the order of abundance based on a large set of unpublished analytical data. Under the microscope, abundant oilbearing fluid inclusions were observed in thin sections and fluid inclusion wafers cut from both samples.
3. Experimental The samples were first crushed into smaller pieces Ž1–2 cm in dimension. and then several pieces were randomly selected and immersed in dichloromethane ŽDCM. in flasks for 48 h. The extract obtained in this step was defined as bitumen 1. Other pieces were disintegrated gently to obtain isolated grains. Clay minerals coating the surfaces of grains were separated by disturbing the grains in distilled water and obtained by the conventional settling method based on Stokes’ formula. About 5 g dry clay minerals Ž- 2 m . were obtained from each sample. The contents of clay minerals in the sandstone samples are less than 1%. The individual quartz and feldspar grains after clay separation were sieved to obtain 0.3–0.1 mm fractions, which appeared to be fully isolated under the microscope. One hundred grams of grains from these fractions were Soxhlet extracted with DCM:MeOH Žmethanol., 93:7 vol.% for 48 h. The extract obtained in this step extraction was discarded under the consideration that the biomarker distributions of this extract would be very similar to those of bitumen 1. According to some recent studies ŽKarlsen et al., 1993; Wilhelms et al., 1996; Schwark et al., 1997., there was still a significant amount of residual oil dominated by polar components strongly adsorbed onto grain surfaces after the first extraction. The grain fractions were further treated with HCl to remove carbonate minerals and to change some residual adsorbed components so that they were extractable, and then extracted again with DCM:MeOH Ž48 h. to obtain bitumen 2. Carbonate minerals are
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Fig. 1. Isopach map of Upper Permian through Tertiary sedimentary rocks and locations of samples A and B in the Junggar Basin; Ž1. thickness contours; Ž2. postulated thickness contours; Ž3. drill holes Žmodified from King et al., 1994..
relatively rare in both samples, because no strong reactions were observed during HCl treatment. After the second extraction, the grain fractions were treated with chromic acid Ž12 h. to remove any residual external organic matter. The fully cleaned grains were ground Ždry. to powder to liberate oil-bearing fluid inclusions, and then extracted with DCM:MeOH Ž48 h. to obtain bitumen 3. Clay minerals separated from the core samples were firstly extracted with DCM:MeOH Ž48 h.. The extract from this step was discarded. The clay minerals were further treated with HCl to remove chlorite and to change some residual adsorbed components so that they were extractable. A second extraction Ž48 h. was carried out and the extract obtained was defined as bitumen 4. After treated with HCl:HF Ž1:2 mol. to remove all minerals, the residual matter Žkerogen-like. was extracted with DCM:MeOH Ž48 h. to obtain bitumen 5.
Of the five bitumen fractions obtained from each core sample using our sequential extraction procedures, bitumen 1 is the oil component in intergranular pore space, comparable to currently reservoired oils. Bitumen 2 is the oil component closely adsorbed on grain surfaces and liberated by HCl treatment. Bitumen 3 is the oil component in oil-bearing fluid inclusions. Bitumen 4 is the oil component adsorbed closely onto clay minerals and liberated by HCl treatment. Bitumen 5 is the oil component further closely adsorbed by clay minerals and liberated after HCl:HF treatment. All bitumen extracts of both samples were deasphaltened Žby 40 times excess of petroleum ether. and then fractionated using mixed silicaraluminum liquid chromatography columns, with petroleum ether and petroleum ether:DCM Ž1:2 vol.. yielding the aliphatic and aromatic hydrocarbon fractions. Gas chromatography ŽGC. analyses of the aliphatic frac-
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tions from all extracts were performed on a Varian 3700 GC fitted with a 25 m = 0.25 mm i.d. column coated with 0.25 mm film of DB-1 phase, with nitrogen as carrier gas. The column oven temperature programme for the analyses was as follows: 908C for 2 min, 90–2908C at 48Crmin, and 2908C for 60 min. Gas chromatography–mass spectrometry ŽGC–MS. analyses of the aliphatic fractions of bitumen 1 of both samples were carried out on a HP 5972 MSD interfaced to a HP 5890 GC fitted with a 50 m = 0.25 mm i.d. column coated with 0.17 mm film of HP-5 phase, using helium as the carrier gas. The column oven temperature programme was 608C for 5 min, 60–2908C at 48Crmin, and 2908C for 30 min. GC– MS analyses of the other aliphatic fractions were performed on a Finnigan TSQ-70B interfaced with a Varian 3400 GC fitted with a 25 m = 0.20 mm i.d. column coated with 0.33 mm film of HP-1 phase, using helium as the carrier gas. The column oven temperature programme was 708C for 5 min, 70– 2208C at 38Crmin, 220–2908C at 28Crmin and 2908C for 30 min.
4. Results and discussions
4.1. Gross composition The gross compositions of various extract fractions are shown in Table 1. Although these data obtained by the gravimetric method are relatively inaccurate, because the amounts of the extract fractions are too small, it is quite certain that bitumens 2, 4 and 5 of both samples are dominated by polar components Žresins and asphaltenes., very similar to the gross compositions of ‘‘adsorbed oil’’ reported by Wilhelms et al. Ž1996. and Schwark et al. Ž1997.. The contents of polar components of bitumen 3 Žoil-bearing fluid inclusions. are relatively higher than that of bitumen 1 but much lower than that of bitumens 2, 4 and 5. The relative contents of polar components of currently reservoired light oils in both reservoirs could be even lower than that of bitumen 1 because of evaporation of aliphatic and aromatic components of oil during analysis.
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Table 1 Gross compositions of various extract fractions of samples A and B Total Žmg.
Alip Žmg.
Aro Žmg.
Alip Ž%.
Aro Ž%.
Aspq Res Ž%.
Sample A Bitumen 1 Bitumen 2 Bitumen 3 Bitumen 4 Bitumen 5
2.5a 10.9 4.7 2.4 3.9
1.6 1.1 2.1 0.2 0.4
0.2 0.2 0.4 0.1 0.1
64 10 45 8 10
8 2 8 4 3
28 88 47 88 87
Sample B Bitumen 1 Bitumen 2 Bitumen 3 Bitumen 4 Bitumen 5
6.5a 5.9 8.4 5.5 6.7
3.9 0.5 3.9 0.5 0.6
0.5 0.1 0.8 0.1 0.1
60 8 46 9 9
8 2 10 2 1
32 90 44 89 90
a
The amounts of bitumen 1 obtained from both samples were large, the listed were just taken for further analyses.
4.2. n-Alkanes and acyclic isoprenoids In sample A, the distribution patterns of n-alkanes and acyclic isoprenoids in bitumens 1, 2 and 3 are very similar, while in the other two extracts Žbitumens 4 and 5., these hydrocarbons seem distorted because of partial loss of n-alkanes and acyclic isoprenoids ŽFig. 2.. Nevertheless, the parameters PrrnC 17 , PhrnC 18 and PrrPh correlated very well except the relatively low ratio of PrrPh of bitumen 5 in comparison with those of the other four extracts ŽTable 2.. In sample B, gas chromatograms of the aliphatic fractions from bitumens 1 and 3 are very similar while of those from the other three extracts are more variable ŽFig. 3.. The parameters PrrnC 17 , PhrnC 18 and PrrPh of bitumens 1 and 3 are very similar while of the other three extracts are dramatically different, for example, bitumen 2 with relative high ratios of PrrnC 17 and PhrnC 18 , and relative low ratio of PrrPh, and both bitumens 4 and 5 with relative low ratios of PrrnC 17 and PhrnC 18 ŽTable 2.. There are two basic types of oils in this area. The type 1 oil, which is very similar to bitumen 2 of sample B in the gas chromatograms, occurs mainly to the north and northwest of the location of sample B, and the type 2 oil, similar to the oil in sample A, occurs mainly to the south of the location of sample B ŽZhou et al., 1989; Yang et al., 1992.. It is likely
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Fig. 2. Gas chromatograms of the aliphatic fractions of five bitumen fractions from sample A; Ža. bitumen 1; Žb. bitumen 2; Žc. bitumen 3; Žd. bitumen 4; Že. bitumen 5.
that currently reservoired oil in sample B is a mixture of those two basic types of oil.
4.3. Terpanes and steranes Maturity data of terpanes and steranes varies dramatically among the five bitumen fractions of both samples ŽTable 2, Figs. 4 and 5.. According to the terpane parameter C 23 tricyclicrŽC 23 tricyclic q
C 30 17a Ž H .-hopane. ŽVan Graas, 1990; Peters and Moldowan 1993., maturities decrease in the order bitumens 1, 3, 2, 4 and 5 for both samples. However, based on the isomerization parameters, the maturity variation trends are somewhat different. For example, based on parameter C 29 steranes 20SrŽ20S q 20 R . ŽMackenzie, 1984., maturities decrease in the order bitumens 1, 4, 3, 5 and 2 for sample A, and bitumens 1, 3, 4, 2 and 5 for sample B, while based on parameter C 29 steranes abbrŽ a a a q abb . ŽMackenzie, 1984., in the order bitumens 1, 3, 2, 5
C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335 Table 2 Biomarker parameters of various extract fractions of samples A and B A: Terpane parameter C 23 -trirŽC 23-triqC 30 17a Ž H .-hopane. measured on m r z 191 chromatograms; B: 20SrŽ20 Rq20S . of C 29 sterane; and C: bb rŽbbq a a . of C29 sterane, both B and C measured on m r z 217 chromatograms. PrrnC 17
PhrnC 18
PrrPh
A
B
C
Sample A Bitumen 1 Bitumen 2 Bitumen 3 Bitumen 4 Bitumen 5
0.52 0.50 0.32 0.47 0.38
0.43 0.49 0.33 0.39 0.51
1.21 1.27 1.27 1.24 0.97
0.63 0.25 0.32 0.21 0.16
0.56 0.35 0.45 0.47 0.41
0.58 0.43 0.44 0.28 0.39
Sample B Bitumen 1 Bitumen 2 Bitumen 3 Bitumen 4 Bitumen 5
0.84 1.35 0.81 0.69 0.51
0.90 1.62 0.92 0.71 0.71
1.17 0.91 1.16 1.24 1.03
1.00 0.29 0.70 0.24 0.20
0.62 0.46 0.51 0.48 0.38
0.65 0.45 0.55 0.42 0.42
and 4 for sample A, and bitumens 1, 3, 2, 4 and 5 for sample B. These parameters indicate that the maturities of current oils Žbitumen 1. in both samples are very high, and clearly, much higher in sample B than in sample A. These maturity parameters also indicate that maturities of oil-bearing fluid inclusions and adsorbed oil components on mineral surfaces are lower than that of currently reservoired oils in both samples, consistent with the observations of similar studies by others ŽWilhelms et al., 1996; Schwark et al., 1997.. However, the maturites of oil-bearing fluid inclusions are higher than that of adsorbed oil components on mineral surfaces, especially for sample B, opposite to the results reported by Wilhelms et al. Ž1996.. 4.4. Indigenous compositions and thermal maturation behaÕiors of adsorbed oil components in the network of polar compounds According to the gross compositions of oil-bearing fluid inclusions and adsorbed oil on mineral surfaces ŽKarlsen et al., 1993; Wilhelms et al., 1996; Schwark et al., 1997; and this study., the contents of polar components in oil-bearing fluid inclusions are usually less than 50%, while in adsorbed oils usually more than 80% and up to 90%. It can be concluded
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that biomarkers in oil-bearing fluid inclusions are mainly free components, but in adsorbed oils are adsorbed components in the network of polar components. As the retention of the adsorbed, relatively small molecular weight oil components by the polar compounds was very strong, just as indicated by studies on biodegraded oil reservoirs rocks ŽWilhelms et al., 1996; Pan and Xiao, 1998., those adsorbed components were not easily replaced by free components in the accompanying oil. Furthermore, when polar compounds generated from kerogens in source rock, they had already adsorbed the non-polar components because these newly generated polar compounds, such as asphaltenes, were definitely not pure, hydrocarbon free ones. In other words, the adsorption of the non-polar components by the polar compounds actually occurred before the oil entered the reservoir rocks. Part of the currently adsorbed components have entered and stayed in the network of polar compounds since the oil generation in source rocks, andror even inherited the components in the network of kerogens in source rocks before oil generation because the polar compounds were just the large fragments of kerogens and formed during kerogen thermal degradation ŽTissot and Welte, 1984.. In order to achieve a clear understanding of the nature of adsorbed components by polar compounds in oil, it is useful to discuss the composition of residual oil in source rocks. It is well defined already that the two basic types of oil in this area, are from the source rocks of Permian age, the type 1 oil sourced from the Fencheng Formation and the type 2 oil sourced from the Lower Werhe Formation orrand the Jiamuhe Formation ŽZhou et al., 1989; Yang et al., 1992.. Of the Permian source rocks, the Lower Werhe Formation is the youngest, the Fencheng Formation the middle, and the Jiamuhe Formation the oldest. The maturities of all these source rocks in this area are very high, mostly with the vitrinite reflectance values %R o ) 1.3 ŽPan, 1987; King et al., 1994.. However, biomarker maturity parameters of bitumen extracted from those source rocks vary irregularly with vitrinite reflectance or burial depths. No matter how high the maturities Ževen %R o ) 2., terpanes extracted from these source rocks always contain relatively high contents of pentacyclics and low contents of tricyclics, and in most cases, C 29 sterane isomerization has not reached thermal equi-
328
C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335
Fig. 3. Gas chromatograms of the aliphatic fractions of five bitumen fractions from sample B; Ža. bitumen 1; Žb. bitumen 2; Žc. bitumen 3; Žd. bitumen 4; Že. bitumen 5.
librium yet. For example, the vitrinite reflectance values of samples of Permian age with burial depths from 4777.3 to 5600.3 m at Aican 1 well in this area, are between 1.51 and 2.02, but the parameter C 29 steranes 20SrŽ20S q 20 R . of four samples in this
burial depth interval of the same well, is between 0.38 and 0.46 ŽKing et al., 1994, their Table 2.. These data are very difficult to interpret based on the isomerization kinetic model of C 29 steranes ŽMackenzie, 1984.. Furthermore, terpanes of these four
Fig. 4. Terpane and sterane mass chromatograms Ž mrz 191, mrz 217. of five bitumen fractions from sample A; Ža. – Že. terpane mass chromatograms Žmrz191.; Ža. bitumen 1; Žb. bitumen 2; Žc. bitumen 3; Žd. bitumen 4; Že. bitumen 5; Žf. – Žj. sterane mass chromatograms Ž mrz 217.; Žf. bitumen 1; Žg. bitumen 2; Žh. bitumen 3; Ži. bitumen 4; Žj. bitumen 5.
C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335
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C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335
331
Table 3 Homogenization temperatures of oil-bearing fluid inclusions measured on samples A and B
Fig. 6. Terpane and sterane mass chromatograms Ž m r z 191, m r z 217. of a Permian source rock sample Ž5268.9 m, %R o 1.86. from Aican 1 well Žafter Yang et al., 1992..
samples are dominated by pentacyclics Že.g., Fig. 6., opposite to that of free oil in reservoir rocks with these maturity levels. In recent years, Pepper Ž1992. and Sandvik et al Ž1992. presented a new model of hydrocarbon expulsion from the source rocks, demonstrating the importance of organic adsorption. In this model, bitumen Žresidual oil. in source rocks was mainly adsorbed by solid organic matter Žkerogen.. In our point of view, it could be exact true that, in source rocks of very high maturity, free oil components with relative high molecular weight including biomarker compounds have been completely broken down, and the residual oil components extracted are actually adsorbed by solid kerogen. Possibly because of the lack of catalysts in the kerogen networks, the residual oil in source rocks with high maturity has retained biomarkers indicating relatively low maturities. In fact, the retardation of thermal maturation of biomarkers trapped in kerogen and asphaltenes has been recognized for many years ŽRubinstein et al.,
Th range Ž8C.
Measured Th data Ž8C.
Sample A
58.7–64.4
Sample B
53.4–88.4
61.6, 62.4, 59.4, 61.2, 59.6, 58.7, 64.4, 59.4 88.4, 55.5, 54.6, 57.5, 63.9, 72.8, 75.8, 77.9, 72.4, 53.4
1979; Samman et al., 1981.. If the indigenous compositions and thermal maturation behavior of adsorbedrtrapped biomarkers in the networks of kerogen and asphaltenes both in source rocks and reservoir rocks are comparable, the lower maturity level of adsorbed oil components on mineral surfaces compared to that of oil-bearing fluid inclusions hosted by grains in reservoir rocks can be easily understood. 4.5. Oil filling histories of samples A and B The homogenization temperature data of oilbearing fluid inclusions measured for both samples are listed in Table 3. The range of homogenization temperatures for sample A is quite narrow, 58.7– 64.48C, but for sample B the range is relatively wide, 53.4–88.48C. If the oil-bearing fluid inclusions were saturated with respect to gas during entrapment, these data suggested that the first oil charge entered sample A during the Late Jurassic, and sample B during the Early–Middle Jurassic ŽFig. 7.. During this time, most Permian source rocks already reached or passed the main oil generation stage in this area ŽPan, 1987; King et al., 1994, their Fig. 13.. In sample A, the homogenization temperatures of oil-bearing fluid inclusions are very similar, therefore, these inclusions could be expected to be trapped mainly within a short duration, and to be relatively homogeneous in composition. In other words, bitumen 3 may represent the early oil charge that entered the reservoir rocks. With increasingly high maturity oil charging the reservoir, the reservoired oil evolved from that similar to bitumen 3 to the current compo-
Fig. 5. Terpane and sterane mass chromatograms Ž mrz 191, mrz 217. of five bitumen fractions from sample B; Ža. – Že. terpane mass chromatograms Ž mrz191.; Ža. bitumen 1; Žb. bitumen 2; Žc. bitumen 3; Žd. bitumen 4; Že. bitumen 5; Žf. – Žj. sterane mass chromatograms Ž mrz 217.; Žf. bitumen 1; Žg. bitumen 2; Žh. bitumen 3; Ži. bitumen 4; Žj. bitumen 5.
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Fig. 7. Burial and oil filling histories of samples A and B; Ža. sample A; Žb. sample B.
sition with high maturity. As the clay minerals in the reservoir rocks mainly occur in the intergranular pores and as coatings around the grains, once oil entered the reservoir rocks, oil components preferentially reacted with those clay minerals. Therefore, the adsorbed oil by clay minerals Žbitumens 4 and 5. are mainly polar components with some non-polar components in their networks of the early oil charge in the reservoir rocks. As discussed previously, biomarker distributions of these adsorbed oils did not represent that of the whole early oil charge. The interaction oil zone between oil phases and grain surfaces, however, formed from the beginning to long after the first oil charge, depending on the oil saturation value in the reservoir rocks. As a result, the adsorbed oil on grain surfaces may represent the
polar components with non-polar components in the networks of various oil charges during filling process. In sample B, the homogenization temperatures of oil-bearing fluid inclusions are in a wide range, indicating these inclusions were trapped over a relatively long duration. Therefore, oil-bearing fluid inclusions of this sample are, in fact mixtures of various oil charges, as is the current oil. Alkane and biomarker distributions of the oil-bearing fluid inclusions Žbitumen 3. and the current oil Žbitumen 1. are quite similar, and the maturity of the former is just slightly lower than the latter, but both are very high ŽTable 2 and Fig. 5.. In this case, it is difficult to determine the maturity of the first oil charge, however, the maturity could be higher than that of the adsorbed oils by minerals Žbitumens 2, 4 and 5.. As indicated by alkane distributions and the parameters PrrnC 17 , PhrnC 18 and PrrPh of the five bitumen fractions obtained from this sample ŽTable 2 and Fig. 3., oils of this sample are mixtures of two basic types of oil with different origins. As discussed previously, adsorbed oils by clay minerals Žbitumens 4 and 5. may represent the early oil charge. Therefore, the initial oil charge may be type 2 oil similar to oil in sample A, sourced from the Lower Werhe Formation Žyoungest. orrand the Jiamuhe Formation Žoldest., and the later oil charge may be type 1 oil, similar to bitumen 2 of this sample, sourced from the Fencheng Formation. In this case, the initial oil was more likely derived from the Jiamuhe Formation, rather than the Lower Werhe Formation, due to the consideration that the source rock of the initial oil could be relatively older than that of the later oil. The source rocks of the Fencheng Formation were classified to be a good type, with type I kerogen, while of both the Jiamuhe Formation and the Lower Werhe Formation, a much poorer type, with type III kerogen ŽZhou et al., 1989; Yang et al., 1992.. Therefore, according to the oil expulsion model presented by Pepper Ž1992. and Sandvik et al. Ž1992., oils from the Fencheng formations can be expected to be rich in polar components, in comparison with those from the Jiamuhe Formation and the Lower Werhe Formation. The oil components adsorbed relatively later by grain surfaces Žbitumen 2. are polar components, mainly from the later oil charge sourced from the Fencheng Formation. As a result, the alkane
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distributions and parameters PrrnC 17 , PhrnC 18 and PrrPh of bitumen 2 are more similar to that of the later oil charge than that of any other bitumen fractions. 4.6. Trapping of oil-bearing fluid inclusions Up till now, the mechanism of the formation of oil-bearing fluid inclusions is unclear. It is generally expected that oil-bearing fluid inclusions most likely form during the initial filling of a reservoir unit ŽGeorge et al., 1997.. However, in some cases, such as sample B of this study and examples reported by many others ŽWalderhaug, 1990; Saigal et al., 1992; Nedkvitne et al., 1993., the formation of oil-bearing fluid inclusions continued, while in other cases, such as sample A of this study and examples reported by George et al. Ž1997., it apparently ceased after the initial filling. Previous discussions on this topic were mainly based on mineral diagenesis in oil saturated zones ŽNedkvitne et al., 1993; George et al., 1997.. Principally, polar components play a critical role in the formation of oil-bearing fluid inclusions. Without polar components, oil would have no chance to encounter minerals with the presence of water. Our personal view on this issue is that oil-bearing fluid inclusions preferentially form during the early oil charge, and if the later oil charge contains more polar components than the early, the trapping of oil-bearing fluid inclusions would continue at a considerable rate, and the composition of oil-bearing fluid inclusions would bear the signatures of both the early and the later oil charges. In contrast, if the later oil charge contains less polar components, the trapping of oil-bearing fluid inclusions would continue at an insignificant rate, and the composition of oilbearing fluid inclusions, revealed by the current approach, would mainly bear the signatures of the early oil charge. In sample A, the early oil charge with low maturity was expected to contain more polar components than the later oil charge with high maturity, while in sample B, the early oil charge sourced from the Jiamuhe Formation with type III kerogen, was expected to contain less polar components than the later oil charge sourced from the Fencheng Formation with type I kerogen. Therefore, in sample A, oil-bearing fluid inclusions formed dominantly dur-
333
ing the early oil charge, but in sample B, significant amount of oil-bearing fluid inclusions formed during the later oil charge, as was indicated by the results of the composition analysis and homogenization temperature measurements of oil-bearing fluid inclusions. 4.7. Oil and source rock correlations Routine oil and source rock correlations are carried out based on oils of the reservoirs and residual oils extracted from source rocks ŽTissot and Welte, 1984., However, in this study, indicated by Figs. 4–6, biomarkers Žterpanes and steranes. of residual oil in the source rocks correlate poorly with those of the current oil in reservoirs Žbitumen 1., at least, in terms of maturity, but correlate well with those of adsorbed components in the network of polar compounds Žbitumens 2, 4 and 5. in both samples. As the polar compounds of oil are generally believed to be fragments of kerogen in source rocks ŽTissot and Welte, 1984., and the residual oils in source rocks are mainly adsorbed by kerogen ŽPepper, 1992; Sandvik et al., 1992., the residual oils in source rocks could correlate well with those adsorbed by the polar compounds, but differentiate more or less with the free oil components due to partitioning. Furthermore, absorbed oil components by polar compounds would change much less than free oil components during oil expulsion, secondary migration and emplacement into a reservoir, and therefore maintain a good correlation with those of kerogen Žresidual oil components in source rocks.. As described above, biomarker compounds, such as terpanes and steranes etc. in bitumens 2, 4 and 5 are absorbed components by polar compounds. Oil source correlations based on those absorbed components would be much more efficient than those based on free components. In most cases, if the origins of the oil charges varied during the filling process, there would be marked differences between the oil in fluid inclusions and the currently reservoired oil ŽKarlsen et al., 1993; George et al., 1997.. However, this observation is not consistent with this study on sample B. Although the reservoired oil in this sample is apparently a mixture of two basic types of oil with different origins, the recovered oil in fluid inclusions is
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very similar to the current oil. One interpretation for this case might be that the mixing process occurred before the oil entered the reservoir. However, clear variations of molecular compositions were observed among the adsorbed oil components by the grains Žbitumen 2. and by the clay minerals Žbitumens 4 and 5., and the current reservoired oil, indicating the compositions of the oil charges varied during the filling process of the reservoir.
5. Conclusions The gross and molecular compositions of the five bitumen fractions obtained by sequential extraction methods from two Triassic reservoir sandstone samples from Junggar Basin, indicate compositional variations of oil charges during the filling process. The lowest molecular maturities of bitumens 4 and 5 suggest that the adsorbed oil components on clay minerals represent the initial oil charge entering reservoir rocks. This phenomenon is interpreted to be due to the first oil charge preferentially interacting with the clay minerals occurring in the pores and as coatings around the grains. In comparison with the maturities of free oil components Žbitumen 1. and oil-bearing fluid inclusions Žbitumen 3., the relatively lower maturities of adsorbed oil components by the grain surfaces Žbitumen 2. and clay minerals Žbitumens 4 and 5. are accredited to the indigenous composition variations and differential maturation behaviors between oil components in the network of polar compounds and free oil components even in a same oil charge, in addition to fractional adsorption effects and compositional changes of oil charges during filling process. The molecular compositions and homogenization temperatures of oil-bearing fluid inclusions of these two samples demonstrate the trapping of those inclusions apparently ceased in sample A, while continued in sample B after the initial oil charges. These results lead us to postulate that the relative contents of polar compounds in the initial oil charge compared to the following oil charges may be a dominant factor controlling the formation of oil-bearing fluid inclusions in oil saturated zones.
Acknowledgements This project was supported by the National Natural Sciences Fundation of China Žgrant No. 49302032., the State Key Laboratory of Organic Geochemistry, CAS, and the Karamayi Research Institute of Exploration and Development, CNPC. The authors are grateful to Junhong Chen, Shanfa Fan, Jiamo Fu, Ansong Geng, Pingan Peng, Guoying Sheng, Qilai Xie and Zhongyi Zhou of the Guangzhou Institute of Geochemistry and Hanping Dong, Xulong Wang, Yitao Wang, Xinhou Wu, Wenxiao Yang and Yijie Zhang of the Karamayi Research Institute of Exploration and Development for their support and help in this study. Drs. Simon George and Zhang Ming and two anonymous reviewers are gratefully acknowledged for their constructive reviews and language improvements. [SB]
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C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335 applications and opportunities. In: Cubitt, J.M., England, W.A. ŽEds.., The Geochemistry of Reservoirs. Geological Society, London, pp. 2–32, Special Publication No. 86. Li, M., Larter, S.R., Stoddart, D.P., Bjoroy, M., 1995. Fractionation of pyrolic nitrogen compounds in petroleum during migration: derivation of migration related geochemical parameters. In: Cubitt, J.M., England, W.A. ŽEds.., The Geochemistry of Reservoirs. Geological Society, London, pp. 103–125, Special Publication No. 86. Mackenzie, A.S., 1984. Application of biomarkers in petroleum geochemistry. In: Brooks, J., Welte, D. ŽEds.., Advances of Petroleum Geochemistry Vol. 1 Academic Press, pp. 115–214. Nedkvitne, T., Karlsen, D.A., Bjørlykke, K., Larter, S.R., 1993. Relationship between reservoir diagenetic evolution and petroleum emplacement in the Ula Field, North Sea. Mar. Petrol. Geol. 10, 255–270. Pan, C., 1987. Thermal history of Junggar Basin. MS dissertation, Institute of Geochemistry, Academica Sinica Žin Chinese.. Pan, C., Xiao, Z., 1998. Geochemical significance of hydrocarbons desorbed from asphaltenes. Science in China: Series D 41, 75–81. Pepper, A.S., 1992. Estimating the petroleum expulsion behavior of source rocks: a novel quantitative approach. In: England, W.A., Fleet, A.J. ŽEds.., Petroleum Migration. Geological Society, London, pp. 9–32, Special Publication No. 59. Peters, K.E., Moldowan, J.M., 1993. The Biomarker Guide: Interpreting Molecular Fossils in Petroleum and Ancient Sediments. Prentice-Hall, Englewood Cliffs, NJ. Price, L.C., Clayton, J.L., 1992. Extraction of whole versus ground source rocks: fundamental petroleum geochemical implications including oil-source rock correlation. Geochim. Cosmochim. Acta 56, 1213–1222. Rubinstein, I., Spyckerelle, C., Strausz, O.P., 1979. Pyrolysis of asphaltenes: a source of geochemical information. Geochem. Cosmochim. Acta 43, 1–6. Saigal, G.C., Bjørlykke, K., Larter, S.R., 1992. The effects of oil emplacement on diagenetic process — examples from the Fulmar reservoir sandstones, central North Sea. Am. Assoc. Petrol. Geol. Bull. 76, 1024–1033. Sajgo, C., Maxwell, J.R., Mackenzie, A.S., 1983. Evaluation of
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Geochemical characteristics and implications of hydrocarbons in reservoir rocks of Junggar Basin, China Changchun Pan a,) , Jianqian Yang b a
State Key Laboratory of Organic Geochemistry, Guangzhou Institute of Geochemistry, Chinese Academy of Sciences, Wushan, Guangzhou 510640, People’s Republic of China b Research Institute of Exploration and DeÕelopment, Karamayi, Xinjiang 834000, People’s Republic of China Received 29 April 1999; accepted 19 November 1999
Abstract A practical sequential extraction approach has been applied to two core samples collected from oil zones of Triassic sandstones in Junggar Basin, northwest China. Five bitumen fractions were obtained from each sample using this approach. These fractions are free oil components in inter granular pores Žbitumen 1., adsorbed oil components on grain surfaces and liberated by HCl treatment Žbitumen 2., oil-bearing fluid inclusions hosted by grains Žbitumen 3., and adsorbed oil components on clay mineral surfaces and liberated by HCl and HCl:HF treatments Žbitumens 4 and 5.. Striking differences have been observed both in bulk compositions and in aliphatic biomarker distributions Že.g., terpanes and steranes. among the five bitumen fractions. This phenomenon is ascribed to the indigenous compositional variations and differential maturation behaviors between adsorbed oil components in a network of polar compounds Žresins and asphaltenes. and free oil components in even a same oil charge, in addition to fractional adsorption effects and compositional changes of the oil charges in reservoir rocks during filling process. The molecular compositions and homogenization temperatures of oil-bearing fluid inclusions in these two samples indicate that trapping of these types of inclusions apparently ceased in sample A, while continued in sample B after the initial oil charge, suggesting that the relative content of polar components in the initial oil charge compared to the later oil charges plays a dominant role controlling the trapping of oil-bearing fluid inclusions in an oil saturated zone. Sequential extraction studies are important and useful for reservoir geochemistry, especially in the cases where only limited samples of oil and reservoir rocks are available, andror where compositional heterogeneity of free oils has disappeared in a reservoir wKarlsen, D.A., Nedkvitne, T., Larter, S.R., Bjørlykke, K., 1993. Hydrocarbon composition of authigenic inclusions: application to elucidation of petroleum reservoir filling history. Geochim. Cosmochim. Acta 57, 3641–3659x. q 2000 Elsevier Science B.V. All rights reserved. Keywords: Oil reservoir rocks; Free oil components; Adsorbed oil components; Oil-bearing fluid inclusions; Sequential extraction; Reservoir geochemistry
)
Corresponding author. E-mail address: [email protected] ŽC. Pan..
0009-2541r00r$ - see front matter q 2000 Elsevier Science B.V. All rights reserved. PII: S 0 0 0 9 - 2 5 4 1 Ž 9 9 . 0 0 2 3 6 - 3
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1. Introduction Compositional heterogeneity of oil components in reservoir rocks was well documented by Karlsen et al. Ž1993., who analyzed compositions of oil-bearing fluid inclusions hosted in different types of minerals in reservoir rocks. Oil-bearing fluid inclusions, generally believed to be samples of paleo-oil of oil reservoirs, have been heavily studied in recent years ŽGeorge et al., 1997, and references therein.. Meanwhile, an alternative method of sequential extraction has been developed and applied to oil reservoir rocks for the similar purpose of revealing the filling histories of oil reservoirs ŽWilhelms et al., 1996; Schwark et al., 1997.. Sequential extraction studies of source rocks have been reported earlier ŽSajgo et al., 1983; Spiro, 1984; Price and Clayton, 1992.. However, the forms of oil occurrence in source rocks are very different from those in reservoir rocks. Oils in reservoir rocks are dominantly in pore system, while in source rocks, according to the model presented by Pepper Ž1992. and Sandvik et al. Ž1992., mainly adsorbed by kerogens. Every step of partial extraction of oil from source rocks would naturally induce compositional fractionation between extracted and residual oil. The results of this type study can be interpreted by selective extraction and adsorption of oil components in source rocks Že.g., Price and Clayton, 1992.. Price and Clayton Ž1992. also suggested that bonding and trapping of organic compounds to and in kerogens may be partly responsible for their observation. Schwark et al. Ž1997. developed a flow-through extraction system capable of efficiently extracting core plugs while preserving the pore system of samples using two solvent systems. According to their study, extraction step 1, classified as ‘‘free oil’’, occupies 80% of the total extracts of the reservoir core. This ‘‘free oil’’ is very similar to drill stem test ŽDST. oil, both in bulk compositions and molecular biomarker distributions. In contrast, extraction steps 2, 3, 4 and 5, classified as ‘‘adsorbed oil’’, contain much more resins and asphaltenes than DST oil and ‘‘free oil’’ ŽSchwark et al., 1997, their Fig. 4.. Despite marked differences in molecular compositions, the five listed biomarker maturity parameters and n-alkane distributions do not vary consistently from extraction steps 1 to 5 ŽSchwark et al., 1997,
their Figs. 5 and 6.. The authors interpreted extraction step 5 to be a mixture of ‘‘adsorbed oil’’ and ‘‘free oil’’ in isolated pores that became accessible to solvents after the extraction of the resinsrasphaltenesrhigh molecular weight n-alkane layer which blocked narrow pore throats ŽSchwark et al., 1997.. In fact, the other ‘‘adsorbed oil’’ fractions, at least fractions 3 and 4, could also be such a mixture of oil, because ‘‘adsorbed oil’’ fractions 3, 4 and 5 have similar bulk compositions Že.g., Schwark et al., 1997, their Fig. 4.. Recently, Wilhelms et al. Ž1996. carried out a three step sequential extraction study on crushed reservoir rocks of a large sample set, using a suite of solvents with increasing polarity, and observed that although there are great differences in gross compositions, there are only very minor variations in molecular biomarker distributions among the three extracted fractions. They presented a conceptual model for oil accumulation in porous media; i.e., the onion skin model, based on the hypothesis that the first oil to enter the reservoir rocks should be the last one to be extracted out. In the present study, their conceptual model is modified under the following considerations. Ž1. Oil accumulation in reservoir rocks is a continuous and gradual process, and the oil saturation value in reservoir rocks also gradually increases if there are no secondary migration processes. During the early stage of oil filling, the oil phase may only occupy a limited part of the pore system and encounter a limited area of mineral surfaces in the reservoir rocks. An ‘‘interaction zone’’ or ‘‘adsorbed oil zone’’ between the oil phase and the minerals at different areas of mineral surfaces could not form at the same time or during the same oil charge. Ž2. Once entering oil encounters a specific area of mineral surfaces, an ‘‘interaction zone’’ or ‘‘adsorbed oil zone’’ could be established between the oil phase and the minerals by irreversible adsorption of NSO compounds. Some recent studies on polar components indicated that the adsorbed polar components rarely equilibrate further by diffusive mixing ŽLarter and Aplin, 1995; Li et al., 1995; Stoddart et al., 1995.. However, it is hard to imagine that several additional oil layers corresponding to successive oil charges during the filling process formed after the establishment of the first ‘‘adsorbed oil zone’’.
C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335
This study, therefore, does not focus on ‘‘adsorbed oil’’ in different layers, but on oil adsorbed onto different surface areas of minerals. In reservoir sandstone rocks, there are always some clay minerals occurring in pore system or as a coating around the grains Že.g., Hamilton et al., 1992.. Once oil fills the reservoir rocks, it preferentially interacts with clay minerals, therefore, ‘‘absorbed oil’’ by clay minerals may represent the first oil charge which fills the reservoir rocks. Up till now, the facies and maturity parameters of biomarker compounds are based on aliphatic and aromatic components. Those components are not adsorbed directly by mineral surfaces with the presence of water, but are adsorbed or ‘‘trapped’’ by polar compounds themselves adsorbed by mineral surfaces. The ability of polar components to retain the adsorbed or trapped non-polar components is a critical point to the studies of sequential extraction on reservoir rocks. A recent study on desorbed hydrocarbons from asphaltenes extracted from oil reservoir rocks which suffered very strong biodegradation before 360 Ma, indicated that those components including n-alkanes in the network of asphaltenes were kept nearly ‘‘intact’’ ŽPan and Xiao, 1998.. Wilhelms et al. Ž1996. also reported a reduction in the degree of biodegradation from the first to the last extract obtained by sequential extraction. Several previous studies have also indicated that non-polar compounds entrapped within the asphaltenes were protected from the effects of in-reservoir biodegradation using mild chemical degradation methods ŽEkweozor and Strausz, 1983; Ekweozor, 1984, 1986..
2. Sample background The two samples described in this paper were collected from two hydrocarbon reservoirs of the Junggar Basin, northwest China ŽFig. 1.. Both samples, about 1 kg each, were collected from oil zones of Triassic sandstone sequences with burial depths of 4242 m Žsample A. and 4406.7 m Žsample B.. These two samples are well sorted, medium grain sandstone rocks. The mineralogical composition of the grains of sample A is about 80% quartz and 20% feldspar and plagioclase, and of sample B, about 75% quartz
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and 25% feldspar and plagioclase. Carbonate cements were not observed under microscope. Although the mineralogical compositions of the clays of these two samples are not analyzed in this study, the compositions of the clays in Triassic sandstones of these two oil reservoirs are kaolinite, illite, chlorite and mixed layer illitersmectite in the order of abundance based on a large set of unpublished analytical data. Under the microscope, abundant oilbearing fluid inclusions were observed in thin sections and fluid inclusion wafers cut from both samples.
3. Experimental The samples were first crushed into smaller pieces Ž1–2 cm in dimension. and then several pieces were randomly selected and immersed in dichloromethane ŽDCM. in flasks for 48 h. The extract obtained in this step was defined as bitumen 1. Other pieces were disintegrated gently to obtain isolated grains. Clay minerals coating the surfaces of grains were separated by disturbing the grains in distilled water and obtained by the conventional settling method based on Stokes’ formula. About 5 g dry clay minerals Ž- 2 m . were obtained from each sample. The contents of clay minerals in the sandstone samples are less than 1%. The individual quartz and feldspar grains after clay separation were sieved to obtain 0.3–0.1 mm fractions, which appeared to be fully isolated under the microscope. One hundred grams of grains from these fractions were Soxhlet extracted with DCM:MeOH Žmethanol., 93:7 vol.% for 48 h. The extract obtained in this step extraction was discarded under the consideration that the biomarker distributions of this extract would be very similar to those of bitumen 1. According to some recent studies ŽKarlsen et al., 1993; Wilhelms et al., 1996; Schwark et al., 1997., there was still a significant amount of residual oil dominated by polar components strongly adsorbed onto grain surfaces after the first extraction. The grain fractions were further treated with HCl to remove carbonate minerals and to change some residual adsorbed components so that they were extractable, and then extracted again with DCM:MeOH Ž48 h. to obtain bitumen 2. Carbonate minerals are
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Fig. 1. Isopach map of Upper Permian through Tertiary sedimentary rocks and locations of samples A and B in the Junggar Basin; Ž1. thickness contours; Ž2. postulated thickness contours; Ž3. drill holes Žmodified from King et al., 1994..
relatively rare in both samples, because no strong reactions were observed during HCl treatment. After the second extraction, the grain fractions were treated with chromic acid Ž12 h. to remove any residual external organic matter. The fully cleaned grains were ground Ždry. to powder to liberate oil-bearing fluid inclusions, and then extracted with DCM:MeOH Ž48 h. to obtain bitumen 3. Clay minerals separated from the core samples were firstly extracted with DCM:MeOH Ž48 h.. The extract from this step was discarded. The clay minerals were further treated with HCl to remove chlorite and to change some residual adsorbed components so that they were extractable. A second extraction Ž48 h. was carried out and the extract obtained was defined as bitumen 4. After treated with HCl:HF Ž1:2 mol. to remove all minerals, the residual matter Žkerogen-like. was extracted with DCM:MeOH Ž48 h. to obtain bitumen 5.
Of the five bitumen fractions obtained from each core sample using our sequential extraction procedures, bitumen 1 is the oil component in intergranular pore space, comparable to currently reservoired oils. Bitumen 2 is the oil component closely adsorbed on grain surfaces and liberated by HCl treatment. Bitumen 3 is the oil component in oil-bearing fluid inclusions. Bitumen 4 is the oil component adsorbed closely onto clay minerals and liberated by HCl treatment. Bitumen 5 is the oil component further closely adsorbed by clay minerals and liberated after HCl:HF treatment. All bitumen extracts of both samples were deasphaltened Žby 40 times excess of petroleum ether. and then fractionated using mixed silicaraluminum liquid chromatography columns, with petroleum ether and petroleum ether:DCM Ž1:2 vol.. yielding the aliphatic and aromatic hydrocarbon fractions. Gas chromatography ŽGC. analyses of the aliphatic frac-
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tions from all extracts were performed on a Varian 3700 GC fitted with a 25 m = 0.25 mm i.d. column coated with 0.25 mm film of DB-1 phase, with nitrogen as carrier gas. The column oven temperature programme for the analyses was as follows: 908C for 2 min, 90–2908C at 48Crmin, and 2908C for 60 min. Gas chromatography–mass spectrometry ŽGC–MS. analyses of the aliphatic fractions of bitumen 1 of both samples were carried out on a HP 5972 MSD interfaced to a HP 5890 GC fitted with a 50 m = 0.25 mm i.d. column coated with 0.17 mm film of HP-5 phase, using helium as the carrier gas. The column oven temperature programme was 608C for 5 min, 60–2908C at 48Crmin, and 2908C for 30 min. GC– MS analyses of the other aliphatic fractions were performed on a Finnigan TSQ-70B interfaced with a Varian 3400 GC fitted with a 25 m = 0.20 mm i.d. column coated with 0.33 mm film of HP-1 phase, using helium as the carrier gas. The column oven temperature programme was 708C for 5 min, 70– 2208C at 38Crmin, 220–2908C at 28Crmin and 2908C for 30 min.
4. Results and discussions
4.1. Gross composition The gross compositions of various extract fractions are shown in Table 1. Although these data obtained by the gravimetric method are relatively inaccurate, because the amounts of the extract fractions are too small, it is quite certain that bitumens 2, 4 and 5 of both samples are dominated by polar components Žresins and asphaltenes., very similar to the gross compositions of ‘‘adsorbed oil’’ reported by Wilhelms et al. Ž1996. and Schwark et al. Ž1997.. The contents of polar components of bitumen 3 Žoil-bearing fluid inclusions. are relatively higher than that of bitumen 1 but much lower than that of bitumens 2, 4 and 5. The relative contents of polar components of currently reservoired light oils in both reservoirs could be even lower than that of bitumen 1 because of evaporation of aliphatic and aromatic components of oil during analysis.
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Table 1 Gross compositions of various extract fractions of samples A and B Total Žmg.
Alip Žmg.
Aro Žmg.
Alip Ž%.
Aro Ž%.
Aspq Res Ž%.
Sample A Bitumen 1 Bitumen 2 Bitumen 3 Bitumen 4 Bitumen 5
2.5a 10.9 4.7 2.4 3.9
1.6 1.1 2.1 0.2 0.4
0.2 0.2 0.4 0.1 0.1
64 10 45 8 10
8 2 8 4 3
28 88 47 88 87
Sample B Bitumen 1 Bitumen 2 Bitumen 3 Bitumen 4 Bitumen 5
6.5a 5.9 8.4 5.5 6.7
3.9 0.5 3.9 0.5 0.6
0.5 0.1 0.8 0.1 0.1
60 8 46 9 9
8 2 10 2 1
32 90 44 89 90
a
The amounts of bitumen 1 obtained from both samples were large, the listed were just taken for further analyses.
4.2. n-Alkanes and acyclic isoprenoids In sample A, the distribution patterns of n-alkanes and acyclic isoprenoids in bitumens 1, 2 and 3 are very similar, while in the other two extracts Žbitumens 4 and 5., these hydrocarbons seem distorted because of partial loss of n-alkanes and acyclic isoprenoids ŽFig. 2.. Nevertheless, the parameters PrrnC 17 , PhrnC 18 and PrrPh correlated very well except the relatively low ratio of PrrPh of bitumen 5 in comparison with those of the other four extracts ŽTable 2.. In sample B, gas chromatograms of the aliphatic fractions from bitumens 1 and 3 are very similar while of those from the other three extracts are more variable ŽFig. 3.. The parameters PrrnC 17 , PhrnC 18 and PrrPh of bitumens 1 and 3 are very similar while of the other three extracts are dramatically different, for example, bitumen 2 with relative high ratios of PrrnC 17 and PhrnC 18 , and relative low ratio of PrrPh, and both bitumens 4 and 5 with relative low ratios of PrrnC 17 and PhrnC 18 ŽTable 2.. There are two basic types of oils in this area. The type 1 oil, which is very similar to bitumen 2 of sample B in the gas chromatograms, occurs mainly to the north and northwest of the location of sample B, and the type 2 oil, similar to the oil in sample A, occurs mainly to the south of the location of sample B ŽZhou et al., 1989; Yang et al., 1992.. It is likely
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Fig. 2. Gas chromatograms of the aliphatic fractions of five bitumen fractions from sample A; Ža. bitumen 1; Žb. bitumen 2; Žc. bitumen 3; Žd. bitumen 4; Že. bitumen 5.
that currently reservoired oil in sample B is a mixture of those two basic types of oil.
4.3. Terpanes and steranes Maturity data of terpanes and steranes varies dramatically among the five bitumen fractions of both samples ŽTable 2, Figs. 4 and 5.. According to the terpane parameter C 23 tricyclicrŽC 23 tricyclic q
C 30 17a Ž H .-hopane. ŽVan Graas, 1990; Peters and Moldowan 1993., maturities decrease in the order bitumens 1, 3, 2, 4 and 5 for both samples. However, based on the isomerization parameters, the maturity variation trends are somewhat different. For example, based on parameter C 29 steranes 20SrŽ20S q 20 R . ŽMackenzie, 1984., maturities decrease in the order bitumens 1, 4, 3, 5 and 2 for sample A, and bitumens 1, 3, 4, 2 and 5 for sample B, while based on parameter C 29 steranes abbrŽ a a a q abb . ŽMackenzie, 1984., in the order bitumens 1, 3, 2, 5
C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335 Table 2 Biomarker parameters of various extract fractions of samples A and B A: Terpane parameter C 23 -trirŽC 23-triqC 30 17a Ž H .-hopane. measured on m r z 191 chromatograms; B: 20SrŽ20 Rq20S . of C 29 sterane; and C: bb rŽbbq a a . of C29 sterane, both B and C measured on m r z 217 chromatograms. PrrnC 17
PhrnC 18
PrrPh
A
B
C
Sample A Bitumen 1 Bitumen 2 Bitumen 3 Bitumen 4 Bitumen 5
0.52 0.50 0.32 0.47 0.38
0.43 0.49 0.33 0.39 0.51
1.21 1.27 1.27 1.24 0.97
0.63 0.25 0.32 0.21 0.16
0.56 0.35 0.45 0.47 0.41
0.58 0.43 0.44 0.28 0.39
Sample B Bitumen 1 Bitumen 2 Bitumen 3 Bitumen 4 Bitumen 5
0.84 1.35 0.81 0.69 0.51
0.90 1.62 0.92 0.71 0.71
1.17 0.91 1.16 1.24 1.03
1.00 0.29 0.70 0.24 0.20
0.62 0.46 0.51 0.48 0.38
0.65 0.45 0.55 0.42 0.42
and 4 for sample A, and bitumens 1, 3, 2, 4 and 5 for sample B. These parameters indicate that the maturities of current oils Žbitumen 1. in both samples are very high, and clearly, much higher in sample B than in sample A. These maturity parameters also indicate that maturities of oil-bearing fluid inclusions and adsorbed oil components on mineral surfaces are lower than that of currently reservoired oils in both samples, consistent with the observations of similar studies by others ŽWilhelms et al., 1996; Schwark et al., 1997.. However, the maturites of oil-bearing fluid inclusions are higher than that of adsorbed oil components on mineral surfaces, especially for sample B, opposite to the results reported by Wilhelms et al. Ž1996.. 4.4. Indigenous compositions and thermal maturation behaÕiors of adsorbed oil components in the network of polar compounds According to the gross compositions of oil-bearing fluid inclusions and adsorbed oil on mineral surfaces ŽKarlsen et al., 1993; Wilhelms et al., 1996; Schwark et al., 1997; and this study., the contents of polar components in oil-bearing fluid inclusions are usually less than 50%, while in adsorbed oils usually more than 80% and up to 90%. It can be concluded
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that biomarkers in oil-bearing fluid inclusions are mainly free components, but in adsorbed oils are adsorbed components in the network of polar components. As the retention of the adsorbed, relatively small molecular weight oil components by the polar compounds was very strong, just as indicated by studies on biodegraded oil reservoirs rocks ŽWilhelms et al., 1996; Pan and Xiao, 1998., those adsorbed components were not easily replaced by free components in the accompanying oil. Furthermore, when polar compounds generated from kerogens in source rock, they had already adsorbed the non-polar components because these newly generated polar compounds, such as asphaltenes, were definitely not pure, hydrocarbon free ones. In other words, the adsorption of the non-polar components by the polar compounds actually occurred before the oil entered the reservoir rocks. Part of the currently adsorbed components have entered and stayed in the network of polar compounds since the oil generation in source rocks, andror even inherited the components in the network of kerogens in source rocks before oil generation because the polar compounds were just the large fragments of kerogens and formed during kerogen thermal degradation ŽTissot and Welte, 1984.. In order to achieve a clear understanding of the nature of adsorbed components by polar compounds in oil, it is useful to discuss the composition of residual oil in source rocks. It is well defined already that the two basic types of oil in this area, are from the source rocks of Permian age, the type 1 oil sourced from the Fencheng Formation and the type 2 oil sourced from the Lower Werhe Formation orrand the Jiamuhe Formation ŽZhou et al., 1989; Yang et al., 1992.. Of the Permian source rocks, the Lower Werhe Formation is the youngest, the Fencheng Formation the middle, and the Jiamuhe Formation the oldest. The maturities of all these source rocks in this area are very high, mostly with the vitrinite reflectance values %R o ) 1.3 ŽPan, 1987; King et al., 1994.. However, biomarker maturity parameters of bitumen extracted from those source rocks vary irregularly with vitrinite reflectance or burial depths. No matter how high the maturities Ževen %R o ) 2., terpanes extracted from these source rocks always contain relatively high contents of pentacyclics and low contents of tricyclics, and in most cases, C 29 sterane isomerization has not reached thermal equi-
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C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335
Fig. 3. Gas chromatograms of the aliphatic fractions of five bitumen fractions from sample B; Ža. bitumen 1; Žb. bitumen 2; Žc. bitumen 3; Žd. bitumen 4; Že. bitumen 5.
librium yet. For example, the vitrinite reflectance values of samples of Permian age with burial depths from 4777.3 to 5600.3 m at Aican 1 well in this area, are between 1.51 and 2.02, but the parameter C 29 steranes 20SrŽ20S q 20 R . of four samples in this
burial depth interval of the same well, is between 0.38 and 0.46 ŽKing et al., 1994, their Table 2.. These data are very difficult to interpret based on the isomerization kinetic model of C 29 steranes ŽMackenzie, 1984.. Furthermore, terpanes of these four
Fig. 4. Terpane and sterane mass chromatograms Ž mrz 191, mrz 217. of five bitumen fractions from sample A; Ža. – Že. terpane mass chromatograms Žmrz191.; Ža. bitumen 1; Žb. bitumen 2; Žc. bitumen 3; Žd. bitumen 4; Že. bitumen 5; Žf. – Žj. sterane mass chromatograms Ž mrz 217.; Žf. bitumen 1; Žg. bitumen 2; Žh. bitumen 3; Ži. bitumen 4; Žj. bitumen 5.
C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335
329
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C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335
331
Table 3 Homogenization temperatures of oil-bearing fluid inclusions measured on samples A and B
Fig. 6. Terpane and sterane mass chromatograms Ž m r z 191, m r z 217. of a Permian source rock sample Ž5268.9 m, %R o 1.86. from Aican 1 well Žafter Yang et al., 1992..
samples are dominated by pentacyclics Že.g., Fig. 6., opposite to that of free oil in reservoir rocks with these maturity levels. In recent years, Pepper Ž1992. and Sandvik et al Ž1992. presented a new model of hydrocarbon expulsion from the source rocks, demonstrating the importance of organic adsorption. In this model, bitumen Žresidual oil. in source rocks was mainly adsorbed by solid organic matter Žkerogen.. In our point of view, it could be exact true that, in source rocks of very high maturity, free oil components with relative high molecular weight including biomarker compounds have been completely broken down, and the residual oil components extracted are actually adsorbed by solid kerogen. Possibly because of the lack of catalysts in the kerogen networks, the residual oil in source rocks with high maturity has retained biomarkers indicating relatively low maturities. In fact, the retardation of thermal maturation of biomarkers trapped in kerogen and asphaltenes has been recognized for many years ŽRubinstein et al.,
Th range Ž8C.
Measured Th data Ž8C.
Sample A
58.7–64.4
Sample B
53.4–88.4
61.6, 62.4, 59.4, 61.2, 59.6, 58.7, 64.4, 59.4 88.4, 55.5, 54.6, 57.5, 63.9, 72.8, 75.8, 77.9, 72.4, 53.4
1979; Samman et al., 1981.. If the indigenous compositions and thermal maturation behavior of adsorbedrtrapped biomarkers in the networks of kerogen and asphaltenes both in source rocks and reservoir rocks are comparable, the lower maturity level of adsorbed oil components on mineral surfaces compared to that of oil-bearing fluid inclusions hosted by grains in reservoir rocks can be easily understood. 4.5. Oil filling histories of samples A and B The homogenization temperature data of oilbearing fluid inclusions measured for both samples are listed in Table 3. The range of homogenization temperatures for sample A is quite narrow, 58.7– 64.48C, but for sample B the range is relatively wide, 53.4–88.48C. If the oil-bearing fluid inclusions were saturated with respect to gas during entrapment, these data suggested that the first oil charge entered sample A during the Late Jurassic, and sample B during the Early–Middle Jurassic ŽFig. 7.. During this time, most Permian source rocks already reached or passed the main oil generation stage in this area ŽPan, 1987; King et al., 1994, their Fig. 13.. In sample A, the homogenization temperatures of oil-bearing fluid inclusions are very similar, therefore, these inclusions could be expected to be trapped mainly within a short duration, and to be relatively homogeneous in composition. In other words, bitumen 3 may represent the early oil charge that entered the reservoir rocks. With increasingly high maturity oil charging the reservoir, the reservoired oil evolved from that similar to bitumen 3 to the current compo-
Fig. 5. Terpane and sterane mass chromatograms Ž mrz 191, mrz 217. of five bitumen fractions from sample B; Ža. – Že. terpane mass chromatograms Ž mrz191.; Ža. bitumen 1; Žb. bitumen 2; Žc. bitumen 3; Žd. bitumen 4; Že. bitumen 5; Žf. – Žj. sterane mass chromatograms Ž mrz 217.; Žf. bitumen 1; Žg. bitumen 2; Žh. bitumen 3; Ži. bitumen 4; Žj. bitumen 5.
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Fig. 7. Burial and oil filling histories of samples A and B; Ža. sample A; Žb. sample B.
sition with high maturity. As the clay minerals in the reservoir rocks mainly occur in the intergranular pores and as coatings around the grains, once oil entered the reservoir rocks, oil components preferentially reacted with those clay minerals. Therefore, the adsorbed oil by clay minerals Žbitumens 4 and 5. are mainly polar components with some non-polar components in their networks of the early oil charge in the reservoir rocks. As discussed previously, biomarker distributions of these adsorbed oils did not represent that of the whole early oil charge. The interaction oil zone between oil phases and grain surfaces, however, formed from the beginning to long after the first oil charge, depending on the oil saturation value in the reservoir rocks. As a result, the adsorbed oil on grain surfaces may represent the
polar components with non-polar components in the networks of various oil charges during filling process. In sample B, the homogenization temperatures of oil-bearing fluid inclusions are in a wide range, indicating these inclusions were trapped over a relatively long duration. Therefore, oil-bearing fluid inclusions of this sample are, in fact mixtures of various oil charges, as is the current oil. Alkane and biomarker distributions of the oil-bearing fluid inclusions Žbitumen 3. and the current oil Žbitumen 1. are quite similar, and the maturity of the former is just slightly lower than the latter, but both are very high ŽTable 2 and Fig. 5.. In this case, it is difficult to determine the maturity of the first oil charge, however, the maturity could be higher than that of the adsorbed oils by minerals Žbitumens 2, 4 and 5.. As indicated by alkane distributions and the parameters PrrnC 17 , PhrnC 18 and PrrPh of the five bitumen fractions obtained from this sample ŽTable 2 and Fig. 3., oils of this sample are mixtures of two basic types of oil with different origins. As discussed previously, adsorbed oils by clay minerals Žbitumens 4 and 5. may represent the early oil charge. Therefore, the initial oil charge may be type 2 oil similar to oil in sample A, sourced from the Lower Werhe Formation Žyoungest. orrand the Jiamuhe Formation Žoldest., and the later oil charge may be type 1 oil, similar to bitumen 2 of this sample, sourced from the Fencheng Formation. In this case, the initial oil was more likely derived from the Jiamuhe Formation, rather than the Lower Werhe Formation, due to the consideration that the source rock of the initial oil could be relatively older than that of the later oil. The source rocks of the Fencheng Formation were classified to be a good type, with type I kerogen, while of both the Jiamuhe Formation and the Lower Werhe Formation, a much poorer type, with type III kerogen ŽZhou et al., 1989; Yang et al., 1992.. Therefore, according to the oil expulsion model presented by Pepper Ž1992. and Sandvik et al. Ž1992., oils from the Fencheng formations can be expected to be rich in polar components, in comparison with those from the Jiamuhe Formation and the Lower Werhe Formation. The oil components adsorbed relatively later by grain surfaces Žbitumen 2. are polar components, mainly from the later oil charge sourced from the Fencheng Formation. As a result, the alkane
C. Pan, J. Yang r Chemical Geology 167 (2000) 321–335
distributions and parameters PrrnC 17 , PhrnC 18 and PrrPh of bitumen 2 are more similar to that of the later oil charge than that of any other bitumen fractions. 4.6. Trapping of oil-bearing fluid inclusions Up till now, the mechanism of the formation of oil-bearing fluid inclusions is unclear. It is generally expected that oil-bearing fluid inclusions most likely form during the initial filling of a reservoir unit ŽGeorge et al., 1997.. However, in some cases, such as sample B of this study and examples reported by many others ŽWalderhaug, 1990; Saigal et al., 1992; Nedkvitne et al., 1993., the formation of oil-bearing fluid inclusions continued, while in other cases, such as sample A of this study and examples reported by George et al. Ž1997., it apparently ceased after the initial filling. Previous discussions on this topic were mainly based on mineral diagenesis in oil saturated zones ŽNedkvitne et al., 1993; George et al., 1997.. Principally, polar components play a critical role in the formation of oil-bearing fluid inclusions. Without polar components, oil would have no chance to encounter minerals with the presence of water. Our personal view on this issue is that oil-bearing fluid inclusions preferentially form during the early oil charge, and if the later oil charge contains more polar components than the early, the trapping of oil-bearing fluid inclusions would continue at a considerable rate, and the composition of oil-bearing fluid inclusions would bear the signatures of both the early and the later oil charges. In contrast, if the later oil charge contains less polar components, the trapping of oil-bearing fluid inclusions would continue at an insignificant rate, and the composition of oilbearing fluid inclusions, revealed by the current approach, would mainly bear the signatures of the early oil charge. In sample A, the early oil charge with low maturity was expected to contain more polar components than the later oil charge with high maturity, while in sample B, the early oil charge sourced from the Jiamuhe Formation with type III kerogen, was expected to contain less polar components than the later oil charge sourced from the Fencheng Formation with type I kerogen. Therefore, in sample A, oil-bearing fluid inclusions formed dominantly dur-
333
ing the early oil charge, but in sample B, significant amount of oil-bearing fluid inclusions formed during the later oil charge, as was indicated by the results of the composition analysis and homogenization temperature measurements of oil-bearing fluid inclusions. 4.7. Oil and source rock correlations Routine oil and source rock correlations are carried out based on oils of the reservoirs and residual oils extracted from source rocks ŽTissot and Welte, 1984., However, in this study, indicated by Figs. 4–6, biomarkers Žterpanes and steranes. of residual oil in the source rocks correlate poorly with those of the current oil in reservoirs Žbitumen 1., at least, in terms of maturity, but correlate well with those of adsorbed components in the network of polar compounds Žbitumens 2, 4 and 5. in both samples. As the polar compounds of oil are generally believed to be fragments of kerogen in source rocks ŽTissot and Welte, 1984., and the residual oils in source rocks are mainly adsorbed by kerogen ŽPepper, 1992; Sandvik et al., 1992., the residual oils in source rocks could correlate well with those adsorbed by the polar compounds, but differentiate more or less with the free oil components due to partitioning. Furthermore, absorbed oil components by polar compounds would change much less than free oil components during oil expulsion, secondary migration and emplacement into a reservoir, and therefore maintain a good correlation with those of kerogen Žresidual oil components in source rocks.. As described above, biomarker compounds, such as terpanes and steranes etc. in bitumens 2, 4 and 5 are absorbed components by polar compounds. Oil source correlations based on those absorbed components would be much more efficient than those based on free components. In most cases, if the origins of the oil charges varied during the filling process, there would be marked differences between the oil in fluid inclusions and the currently reservoired oil ŽKarlsen et al., 1993; George et al., 1997.. However, this observation is not consistent with this study on sample B. Although the reservoired oil in this sample is apparently a mixture of two basic types of oil with different origins, the recovered oil in fluid inclusions is
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very similar to the current oil. One interpretation for this case might be that the mixing process occurred before the oil entered the reservoir. However, clear variations of molecular compositions were observed among the adsorbed oil components by the grains Žbitumen 2. and by the clay minerals Žbitumens 4 and 5., and the current reservoired oil, indicating the compositions of the oil charges varied during the filling process of the reservoir.
5. Conclusions The gross and molecular compositions of the five bitumen fractions obtained by sequential extraction methods from two Triassic reservoir sandstone samples from Junggar Basin, indicate compositional variations of oil charges during the filling process. The lowest molecular maturities of bitumens 4 and 5 suggest that the adsorbed oil components on clay minerals represent the initial oil charge entering reservoir rocks. This phenomenon is interpreted to be due to the first oil charge preferentially interacting with the clay minerals occurring in the pores and as coatings around the grains. In comparison with the maturities of free oil components Žbitumen 1. and oil-bearing fluid inclusions Žbitumen 3., the relatively lower maturities of adsorbed oil components by the grain surfaces Žbitumen 2. and clay minerals Žbitumens 4 and 5. are accredited to the indigenous composition variations and differential maturation behaviors between oil components in the network of polar compounds and free oil components even in a same oil charge, in addition to fractional adsorption effects and compositional changes of oil charges during filling process. The molecular compositions and homogenization temperatures of oil-bearing fluid inclusions of these two samples demonstrate the trapping of those inclusions apparently ceased in sample A, while continued in sample B after the initial oil charges. These results lead us to postulate that the relative contents of polar compounds in the initial oil charge compared to the following oil charges may be a dominant factor controlling the formation of oil-bearing fluid inclusions in oil saturated zones.
Acknowledgements This project was supported by the National Natural Sciences Fundation of China Žgrant No. 49302032., the State Key Laboratory of Organic Geochemistry, CAS, and the Karamayi Research Institute of Exploration and Development, CNPC. The authors are grateful to Junhong Chen, Shanfa Fan, Jiamo Fu, Ansong Geng, Pingan Peng, Guoying Sheng, Qilai Xie and Zhongyi Zhou of the Guangzhou Institute of Geochemistry and Hanping Dong, Xulong Wang, Yitao Wang, Xinhou Wu, Wenxiao Yang and Yijie Zhang of the Karamayi Research Institute of Exploration and Development for their support and help in this study. Drs. Simon George and Zhang Ming and two anonymous reviewers are gratefully acknowledged for their constructive reviews and language improvements. [SB]
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