Introduction
Tarim Basin, with an area of about 56×104 km2, is the largest petroliferous superimposed basin in China, where a set of Sinian-Permian marine-transient sequences developed in the platform area[1,2,3], and Triassic-Jurassic lacustrine-fluvial sequences developed in foreland area[4]. Exploration practices show that there are two sets of marine source rocks in Cambrian-Lower Ordovician and Middle-Upper Ordovician in the platform area[1-3, 5]. They have very different molecular geochemical characteristics, which are the base of marine oil- source correlation in the Tarim Basin[1-3, 5-7]. The correlation results of distribution and composition of various biomarkers show that most marine oils in the platform area are highly similar and closely related to the Middle-Upper Ordovician source rocks, but few oil samples have high correlation with the Cambrian-Lower Ordovician source rocks, so it is commonly believed that the Middle-Upper Ordovician source rocks are the major source rocks for the marine oil in the Tarim Basin[8,9,10,11,12,13,14]. In addition, Li et al. suggested that most marine oils in Tarim Basin were mixture of oils generated by Cambrian-Lower Ordovician and Middle-Upper Ordovician marine source rocks, based on carbon isotope values of individual hydrocarbon compounds in crude oils from the Tarim Basin[15]. Some researchers argued that the Cambrian-Lower Ordovician source rocks were the main source rocks according to presence of aryl isoprenoid hydrocarbons, sulfur and carbon isotope values in marine oils[16,17,18,19,20,21,22,23]. The three different viewpoints about marine oil sources may lead petroleum exploration in the Tarim Basin to different directions.
The most common method for oil-source correlation is to use geochemical information of organic matter input, depositional environment, maturity and secondary alteration from various biomarkers in crude oil samples and bitumen extract from source rocks[24]. However, two basic issues about marine oil source in the Tarim Basin haven’t get to a common view:
(1) The two sets of marine source rocks in Cambrian-Lower Ordovician and Middle-Upper Ordovician have experienced very different thermal evolution history because of depositional and burial history in the Tarim Basin. A large amount of analytical data shows that the Cambrian-Lower Ordovician source rocks have been high-mature to over-mature, but the Middle-Upper Ordovician source rocks are still in liquid hydrocarbon window at present[1, 3, 25]. Previous study results suggested that distributions and compositions of steranes and terpanes in different source rocks deposited in completely different environments become very similar when they are in high-over mature stage, so the source rocks in high-over mature stage aren’t suitable for oil-source correlation any more[26,27,28]. The two sets of marine source rocks in the Tarim Basin are in very different thermal evolution stages at present, so it remains unknown or requires further study if the geochemical information provided by various biomarkers in high- and over-mature source rocks can be directly used in oil-source correlation.
(2) In the study of mixed oils, whether the end- member oils derived from two sets of marine source rocks selected are representative. Because the organic matter in Middle-Upper Ordovician source rocks is still in liquid hydrocarbon window and moderate in thermal evolution degree, the end-member oil samples which can represent oil generated by this kind of source rocks are common and can be easily selected in different tectonic units, and their oil-source correlation is relatively easy. However, organic matter in Cambrian-Lower Ordovician source rocks is too high in maturity, the end-member oil for this set of source rocks are relatively rare and difficult to select. To date, most researchers used crude oil from Well TD2 as end-member oil and correlated to over-mature Cambrian source rocks in Well KN1 and TD2[29,30,31,32,33,34,35,36], even calculated relative contribution of Cambrian source rocks in mixed oils by mixing experiment with this oil[29]. Some researchers examined the distributions and compositions of biomarkers in crude oil from Well TD2 and its accumulation history[35,36,37], and found that this oil was unique in chemical composition, such as coexistence of whole normal alkanes and 25-norhopane series and unusual polycyclic aromatic hydrocarbons[34, 36], indicating that this oil has experienced biodegradation and abnormally thermal alteration. Therefore, the crude oil from Well TD2 can’t meet the geochemical conditions to be end-member oil of Cambrian source rocks.
Petroleum geologic background of the Tarim Basin shows that direct oil-source correlation between over-mature Cambrian-Lower Ordovician source rocks and related mature oils may be unreasonable, so it is a key to select suitable end-member oil in study on the correlation of oil and Cambrian-Lower Ordovician source rocks. In this study, based on analytical data of saturate and aromatic hydrocarbon fraction of crude oil from Well TD2, and comparison of distributions and compositions of biomarkers such as steranes (including triaromatic steroids) and triterpanes in typical marine crude oils derived from different source rocks in the Tarim Basin, the possibility about crude oil from Well TD2 as end-member oil of Cambrian source rocks have been eliminated, new end-member oil for Cambrian-Lower Ordovician source rocks during mature stage and its geochemical characteristics have been determined, and limitations of triaromatic steroids in oil-source correlation have been discussed.
1. Samples and experiments
1.1. Crude oil samples
Crude oil samples were collected from the Yingmaili area, Tazhong area and Tadong area in the Tarim Basin. Their fundamental geochemical characteristics are shown in Table 1. Crude oil from Well TD2 is heavy oil, and other marine oils are normal oils based on their physical properties. Crude oils from Well YM101 and YM201 in the Yingmaili area are derived from Middle-Upper Ordovician source rocks[9-10, 12-13], and their geochemical features can be used as main evidences to discriminate crude oil generated by Cambrian-Lower Ordovician source rocks from that generated by Middle-Upper Ordovician source rocks.
Table 1 Basic geochemical parameters of crude oils in this study.
| Well name | Sampling depth/m | Horizon | Pr/Ph | Pr/nC17 | Ph/nC18 | Density/ (g·cm-3) | Viscosity/ (mP•s) | Wax content/% | Sulfur content/% | δ13C/‰ |
|---|---|---|---|---|---|---|---|---|---|---|
| YM101 | 5 912.50-5 917.00 | O | 1.14 | 0.48 | 0.54 | / | / | / | / | / |
| YM201 | 5 844.00-5 888.00 | O | 1.09 | 0.44 | 0.46 | 0.880 6 | 13.5 | 10.2 | 0.64 | -33.3 |
| TZ11 | 4 301.00-4 307.00 | S | 1.22 | 0.43 | 0.49 | 0.771 3 | 0.80 | 1.9 | 0.12 | -31.7 |
| TZ30 | 4 997.00-5 026.00 | O | 1.37 | 0.32 | 0.31 | 0.817 5 | 2.65 | 9.5 | 0.35 | -32.0 |
| TD2 | 4 561.93-5 040.00 | C | 1.55 | 0.45 | 0.37 | 1.021 7 | 2698 | 10.46 | 0.51 | -28.2 |
1.2. Experimental methods
Asphaltene was removed from the crude oil samples with n-hexane. The crude oil samples without asphaltene were separated into saturate hydrocarbon, aromatic hydrocarbon, and OSN fractions using an aluminum/silica gel column sequentially eluted with n-hexane, toluene, and chloroform/ ethanol (v/v 1:1), respectively.
Gas chromatography-mass spectrometry analysis of the saturate hydrocarbon fractions: This work was conducted on an Agilent 6890 gas chromatograph coupled to a 5975 mass selective detector equipped with an HP-5ms capillary column (30 m × 0.25 mm × 0.25 μm film thickness). The temperature program was as follows: the temperature of the oven was 50°C for 1 min, and was increased from 50 to 100 °C at a rate of 20 °C/min, and then from 100 to 315 °C at 3 °C/min, finally was maintained at 315 °C for 16 min. The injector and ion source temperatures were 300 °C and 230 °C, respectively. Helium was used as a carrier gas at a rate of 1.0 mL/min. The scan range was from 50 to 550 amu in full scan and multiple ion detector (MID) mode at 70 eV.
Gas chromatography-mass spectrometry analysis of the aromatic hydrocarbon fractions: This work was conducted on an Agilent 6890 gas chromatograph coupled to a 5975 mass selective detector equipped with an HP-5ms capillary column (60 m × 0.25 mm i.d. × 0.25 μm film thickness). The temperature program was as follows: the temperature of the oven was kept at 50 °C for 1 min, and increased from 50 to 100 °C at a rate of 20 °C/min, and then from 100 to 310 °C at 3°C/min, finally maintained at 310 °C for 21 min. The injector and ion source temperatures were 290 °C and 230 °C, respectively. Helium was used as a carrier gas at a rate of 1.0 mL/min. The scan range was from 50 to 550 amu in full scan and multiple ion detector (MID) mode at 70 eV.
2. Feasibility of using crude oil from Well TD2 as end-member oil of Cambrian source rocks
2.1. Distribution of hydrocarbon components in saturate and aromatic hydrocarbon fractions
Analytical results of GC/MS data of saturate hydrocarbon fraction in crude oil from Well TD2 show that the base line of total ion current（TIC）is fairly straight, and normal alkanes from nC11 to nC37 are whole and relatively abundant, and the relative abundances of pristane and phytane are much lower than those of nC17 and nC18 (Fig. 1a). Those features are basically consistent with other marine oils, but biomarker contents are relatively high, because abundances of steranes and triterpanes in higher molecular weight part are obviously higher than those of associated normal alkanes in TIC-GC/MS of saturated hydrocarbon fraction.
Fig. 1.
Fig. 1.
TIC-GC/MS of saturate (a) and aromatic (b) hydrocarbon fractions in crude oil from Well TD2 (N, C2-N, C3-N = alkyl naphthalene; P and MP = phenanthrene and methyl phenanthrenes; AN = anthracene; FL = fluoranthene; PY = pyrene; BAN = benzoanthracene; CH = chrysene; BFL = benzofluoranthene; B(e)PY and B(a)PY = benzo(e) pyrene and benzo(a) pyrene; PE = perylene; BPE = benzoperylene).
It is noteworthy that 3-6 ring polycyclic aromatic hydrocarbons without any alkyl group substitution are predominant in the aromatic hydrocarbon fraction (Fig. 1b), while their alkyl homologues are very low (Fig. 2). This is completely different from distributions and compositions of aromatic hydrocarbon series in most marine crude oils of the Tarim Basin. In most conventional mature marine oils in the Tarim Basin, 2- and 3-ring aromatic hydrocarbon compounds such as alkyl naphthalene series, alkyl biphenyl series, alkyl phenanthrene series, alkyl fluorene series, alkyl dibenzothiophene series are main components, but more than 4-ring polycyclic aromatic hydrocarbons are too low to be observed in the TIC- GC/MS of their aromatic hydrocarbon fractions[38]. Moreover, the relative abundances of 2- and 3-ring aromatic hydrocarbon homologues gradually decrease with the increase of carbon number of alkyl side chain, and polycyclic aromatic hydrocarbons without alkyl side chain taking absolute dominance in aromatic hydrocarbon fractions is very rare, all of them suggest the crude oil from Well TD2 experienced abnormally thermal alteration, and the temperature was much higher than that resulting from thermal evolution of organic matter in source rocks under normal burial process.
Fig. 2.
Fig. 2.
Relative compositions of polycyclic aromatic hydrocarbon in 3-6 rings and their methyl homologues in the aromatic hydrocarbon fraction of crude oil from Well TD2 (peak signs for P, AN, MP, BAN, CH, FL, PY, BFL, B(e)PY, B(a)PY, PE and BPE refer to those in
Previous study results showed that polycyclic aromatic hydrocarbons without alkyl side chain in aromatic hydrocarbon fractions of extracts from recent sediments, especially in surface and shallow sediments, were very abundant and predominant, and their concentrations gradually decreased with the increase of burial depth, this is because the products of burning fossil fuels are brought into modern lakes by rivers and rains[39,40]. Burning means high temperature and high maturity. In other words, unusual distribution of polycyclic aromatic hydrocarbons in the aromatic hydrocarbon fraction of crude oil from Well TD2 must be related to abnormally thermal alteration event from hydrothermal liquid in geological history, this is consistent with the result from accumulation history study[35]. Clearly, the crude oil from Well TD2 is not common mature oil generated directly from source rocks under normal thermal evolution of organic matter, but a product altered by abnormally high temperature in reservoir. Therefore, taking crude oil from Well TD2 as end-member oil from Cambrian source rocks is not appropriate, and could lead to wrong understandings and different exploration decisions or directions.
2.2. Distribution and composition of biomarkers
Distributions and compositions of sterane and terpane biomarkers can provide useful information about organic matter input, depositional environment, maturity and secondary alteration, which is the basis for oil-source correlation.
In crude oil from Well TD2, C19-26 tricyclic terpane series has a normal distribution with C21 component as the main peak (Fig. 3), the relative abundance of tricycle terpane series is moderate and lower than that of C27-35 hopane series, and the C21T/C30H ratio is only about 0.18. In triterpanes, the content of gammacerane is moderate, and gammacerane index (gammacerane/C30H) is about 0.33, indicating that its source rocks were deposited in relatively high salinity environment. In steranes, pregnane(C21) and homopregnane(C22) are relatively low, corresponding to about 5.66% of C27-29 regular and rearranged steranes, and the ratios of C27 and C29 rearranged steranes to their regular steranes are about 0.14 and 0.17, respectively. The relative content of C27R, C28R and C29R in carbon numbers of C27-29 regular steranes are 26.73%, 29.81% and 43.46%, respectively. Obviously, the distributions and compositions of steranes and terpanes in crude oil from Well TD2 are consistent with those of Cambrian source rocks from Well KN1 and TD2 in the Tarim Basin, and it is the main reason to think that this oil was derived from the Cambrian source rocks[3, 8-10, 14].
Fig. 3.
Fig. 3.
Distribution of steranes (m/z 217), extended tricyclic terpanes, triterpanes (m/z 191) and 25-norhopanes (m/z 177) in crude oil from Well TD2 (C21T, C23T = C21 and C23 tricyclic terpanes; C29H-C35H = 17α(H), 21β(H)-hopanes; C27R, C28R and C29R = C27, C28 and C29 5α(H),14α(H),17α(H)-20R steranes; “” = 25-norhopane series).
It is noteworthy that relatively abundant 25-norhopane series were identified (m/z 177 in Fig. 3), although a whole series of normal alkanes in crude oil from Well TD2 was present. This phenomenon suggests that crude oil from Well TD2 is mixed oil of severely biodegraded oil with unbiodegraded oil. As well known, normal alkanes are a kind of compounds most weakly resistant to biodegradation, they are easily biodegraded by bacteria and will completely disappear before 25-norhopane series are formed in crude oil during biodegradation[24]. In other words, normal alkane series and 25-norhopane series should not be observed at the same time in a crude oil under normal conditions. Because when a reservoir is lifted in early period, crude oil inside would be biodegraded and 25-norhopane series will be formed; and later, if the reservoir subsides again, some normal crude oil fills into it, then mixed oil of biodegraded oil and normal oil will occur, resulting in coexistence of normal alkanes and 25-norhopanes in a crude oil sample. At this time, crude oil in this reservoir may be from the same source rocks, but probably generated at different thermal evolution stage or generated by different source rocks. But it is true that mixed oil can’t be taken as end-member oil from a specific source rock. The biodegraded oil in crude oil from Well TD2 should be from the Cambrian source rocks, and the normal oil may be product from abnormally thermal alteration of early biodegraded oil or from thermal cracking of organic matter in Cambrian source rocks in high-mature stage.
Compositional characteristics of aromatic hydrocarbons in crude oil from Well TD2 show that this oil has undergone strong thermal alteration, but the assemblage of different biomarkers in the saturate hydrocarbon fraction indicate that there were two oil filling events in this reservoir, resulting in mixing of severely biodegraded oil with normal oil. Therefore, either from maturity of crude oil or accumulation history, this oil can not satisfy the basic geochemical conditions as end-member oil. Then is there true end-member oil from the Cambrian-Lower Ordovician source rocks in mature stage in the Tarim Basin?
3. End-member oil derived from Cambrian-Lower Ordovician source rocks
3.1. Distribution of hydrocarbon components in saturate and aromatic hydrocarbon fractions
Previous study results showed that crude oils from Ordovician reservoir of Well YM101 and YM201 in the Yingmaili area were mainly derived from Middle-Upper Ordovician source rocks[9-13, 30]. The geochemical characteristics of crude oils from Well TZ11 and TZ30 in the Tazhong area were analyzed by some researchers[15-16, 31], but little attention was paid to their source, origin and petroleum geological significances.
Total ion currents (TIC-GC/MS) of saturate hydrocarbon fractions in the four crude oil samples mentioned above (Fig. 4) show that their n-alkanes have a single peak distribution and lower contents of higher molecular components in their normal alkane series, which are consistent with organic matter input mainly derived from phytoplankton in the early Paleozoic period and show that those oils are mature. Moreover, like most of marine oils in the Tarim Basin, their Pr/Ph ratios are between 1.1 and 1.5, and the ratios of Pr/nC17 and Ph/nC18 are less than 0.50 (Table 1). However, it is noteworthy that steranes, triterpanes and β-carotane are much more abundant in the crude oils from Well TZ11 and TZ30 than those in the crude oils from Well YM101 and YM201 based on their TIC-GC/MS of saturate hydrocarbon fractions, which suggests that the marine crude oils from the Yingmaili and Tazhong area may have different sources and origins.
Fig. 4.
Fig. 4.
Total ion currents of GC/MS in saturate hydrocarbon fractions of four crude oil samples. (a) Well TZ11, 4 301-4 307 m, S; (b) Well TZ30, 4 997-5 026 m, O; (c) Well YM101, 5912.5- 5917.0 m, O; (d) Well YM201, 5 844-5 888 m, O.
Distributions of various aromatic hydrocarbons in the four oil samples are similar, for example, common aromatic hydrocarbon compounds such as alkyl naphthalene series and alkyl phenanthrene series with 2-3-rings are predominant, and polycyclic aromatic hydrocarbons with 4-6-rings are very low in content or even absent in their TIC-GC/MS of aromatic hydrocarbon fractions (Fig. 5). These features are very common for most marine crude oils in the Tarim Basin, but completely different from those of the aromatic hydrocarbon fraction in crude oil from Well TD 2, suggesting that abnormally thermal alteration has a big effect on distributions and compositions of aromatic hydrocarbons in crude oil. In other words, main products from sedimentary organic matter during normal thermal evolution are 2-3-ring aromatic hydrocarbon compounds, and the relative abundances of different aromatic hydrocarbon homologues decrease with the increase of ring number of aromatic hydrocarbon compounds. Unusual distributions and compositions of aromatic hydrocarbon compounds in crude oil from Well TD2 are resulted from abnormally thermal alteration, this is another important reason that this oil can not be taken as end-member oil from Cambrian source rocks. Therefore, geochemical information provided by distributions and compositions of aromatic hydrocarbon compounds from aromatic hydrocarbon fractions of crude oils can be used to evaluate their geological-geochemical processes.
Fig. 5.
Fig. 5.
Total ion currents of GC/MS of aromatic hydrocarbon fractions in four crude oil samples. (a) Well TZ11, 4 301-4 307 m, S; (b) Well TZ30, 4 997-5 026 m, O; (c) Well YM101, 5912.5- 5917.0 m, O; (d) Well YM201, 5 844-5 888 m, O.
3.2. Distributions and compositions of steranes and terpanes
Analytical results show that crude oils from Well TZ11 and TZ30 have more differences than similarities with crude oils from Well YM101 and YM201 in distributions of steranes and terpanes, suggesting that their sources and origins may be quite different. Their similarity is that their C19-26 tricyclic terpane series have an approximate normal distribution with C23 tricyclic terpane as the main peak (Fig. 6), showing features of marine oil. But the relative abundances of C19-26 tricyclic terpane series in crude oils from Well TZ11 and TZ30 are much lower than that in crude oils from Well YM101 and YM201, the former oils have a ratio of C23T/C30H of less than 0.10, the later more than 0.50. Moreover, the relative abundance of C24 tetracyclic terpane(C24TE) is similar to that of C26 tricyclic terpane (C26T) in crude oils from Well TZ11 and TZ30, and their C24TE/C26T ratios are about 0.50-0.60; but in crude oils from Well YM101 and YM201, the relative abundance of C24TE is much more than that of C26T, and their C24TE/C26T ratios are about 1.0. It is noteworthy that in crude oils from Well TZ11 and TZ30, the relative abundance of C29 norhopane (C29H) is much lower than that of C30 hopane (C30H), C29H/ C30H ratio is only about 0.40, gammacerane is relatively abundant, and their gammacerane index are about 0.30-0.40; but in crude oils from Well YM101 and YM201, the relative abundance of C29H is similar to that of C30H, C29H/C30H ratio is up to 0.85, gammacerane is very low and gammacerane index is only about 0.10 (Table 2), consistent with geochemical characteristics of Middle-Upper Ordovician source rocks. It is main evidence that crude oils from the Yingmaili area are derived from Middle-Upper Ordovician source rocks [14-16, 31]. In this case, it is reasonable to suggest that crude oils from Well TZ11 and TZ30 should be derived from different source rocks,compared with crude oils from Well YM101 and YM201.
Fig. 6.
Fig. 6.
Distributions of terpanoid biomerkers in four crude oil samples (m/z 191). (a) Well TZ11, 4 301-4 307 m, S; (b) Well TZ30, 4997- 5026 m, O; (c) Well YM101, 5 912.5-5 917.0 m, O; (d) Well YM201, 5 844-5 888 m, O.
Table 2 Parameters of terpane compounds in different marine crude oils from the Tarim Basin.
| Well | Depth/m | Age | Ts/Tm | Gammacerane index | C24TE/C26T | C29H/C30H | C23T/C30H |
|---|---|---|---|---|---|---|---|
| YM101 | 5912.5-5917.0 | O | 0.44 | 0.13 | 0.93 | 0.83 | 0.49 |
| YM201 | 5844.0-5888.0 | O | 0.49 | 0.09 | 0.96 | 0.85 | 0.51 |
| TZ11 | 4301.0-4307.0 | S | 0.41 | 0.36 | 0.64 | 0.43 | 0.08 |
| TZ30 | 4997.0-5026.0 | O | 0.39 | 0.38 | 0.53 | 0.38 | 0.02 |
| TD2 | 4561.93-5040.00 | C | 0.58 | 0.33 | 0.58 | 0.43 | 0.12 |
As shown in Fig. 7, there is an obvious difference in distributions of sterane series of different crude oils. For example, pregnane (C21) and homopregnane (C22) contents in crude oils from Well TZ11 and TZ30 are very low, their relative abundances are about 0.5%-3.5% of C27-29 steranes; moreover, their diasterane contents are very low, the ratios of C27 and C29 diasteranes to their regular steranes are less than 0.10 (Table 3), but C28 steranes are relatively abundant, the variation of relative abundances for C27-29 20R isomers is C29>C28>C27. In contrast, in crude oils from Well YM101 and YM201, C21 and C22 steranes are very abundant, their relative abundances are about 10%-12% of C27-29 steranes; in addition, diasterane contents are moderate in those oils, with the ratios of C27 and C29 diasteranes to their regular steranes being 0.25-0.30 and 0.35-0.45, respectively, but the content of C28 steranes is relatively low, the relative abundances of C27-29 20R isomers are C29>C27>C28. Obviously, these features are consistent with distributions and compositions of sterane series in the Middle-Upper Ordovician source rocks[14-16, 31], and are important evidences to attribute those oils to this set of source rocks. At the same time, it demonstrates that the crude oils from Well TZ11 and TZ30 should have a different source compared with those oils from Well YM101 and YM201.
Fig. 7.
Fig. 7.
Distributions of sterane series in four crude oil samples (m/z 217). (a) Well TZ11, 4 301-4 307 m, S; (b) Well TZ30, 4 997-5 026 m, O; (c) Well YM101, 5 912.5-5 917.0 m, O; (d) Well YM201, 5 844-5 888 m, O.
Table 3 Parameters of sterane series in different marine crude oil samples from the Tarim Basin.
| Well | Depth/m | Age | C27R/% | C28R/% | C29R/% | diaC27/reC27 | diaC29/reC29 | C21+22/C27-29/% |
|---|---|---|---|---|---|---|---|---|
| YM101 | 5 912.50-5 917.00 | O | 29.4 | 26.3 | 44.3 | 0.25 | 0.35 | 9.92 |
| YM201 | 5 844.00-5 888.00 | O | 34.1 | 21.9 | 44.1 | 0.31 | 0.45 | 11.59 |
| TZ11 | 4 301.00-4 307.00 | S | 20.5 | 31.9 | 47.6 | 0.07 | 0.11 | 2.40 |
| TZ30 | 4 997.00-5 026.00 | O | 19.9 | 33.4 | 46.7 | 0.03 | 0.10 | 0.55 |
| TD2 | 4 561.93-5 040.00 | C | 26.7 | 29.8 | 43.5 | 0.14 | 0.17 | 5.66 |
Based on m/z 231 mass chromatograms, the two kinds of crude oils from the Yingmaili and Tazhong area both contain C28-30 4-methyl sterane series (Fig. 8), the difference between them is that the former only contains C28-30 4-methyl sterane series, while the later contains abundant C30 dinosteranes besides C28-30 4-methyl sterane series (Fig. 8). Although 4-methyl steranes and dinosteranes are indistinctly related to input of dinoflagellates, 4α-methyl-24-ethyl cholestane may be derived from 4α-methyl-24-ethyl cholesterols in prymnesiophyte algae, and are less specific for dinoflagellates than dinosteranes[41,42]. Therefore, the differences in distribution and composition of 4-methyl sterane series in different marine oils are good evidences to demonstrate that they come from different source rocks.
Fig. 8.
Fig. 8.
4-methyl sterane series in four crude oil samples (m/z 231; “•” = C28-30 4-methylsterane; “*” = C30 dinosteranes). (a) Well TZ11, 4301-4 307 m, S; (b) Well TZ30, 4 997-5 026 m, O; (c) Well YM201, 5 844-5 888 m, O; (d) Well YM101, 5 912.5-5 917.0 m, O.
It is worth noting that the relative abundances of C19-26 trycyclic terpanes and C21-22 steranes in crude oils from Well TZ11 and TZ30 are very low, compared with those in crude oils from Well YM101 and YM201 (Figs. 6 and 7). Based on the previous results, the relative abundances of these lower molecular weight biomarkers in geological samples incerase with the increase of maturity, for example, contents of these compounds are generally abundant in high-over mature source rocks and pyrobitumen from paleo-reservoir[26,27,28]. Is the reason of the big difference in relative abundances of C19-26 trycyclic terpanes and C21-22 steranes in the two kinds of different marine crude oils their maturity? The answer seems to be negtive. Because their biomarker maturity parameters such as Ts/Tm (about 0.40) and C29 20S/20S+20R (about 0.42-0.52) are similar, that means that their maturity should be colse. In other words, the main reason causing the big difference in relative abundances of lower molecular weight biomarkers in the two kinds of marine crude oils is not their maturity, but different sources. Furthermore, concentrations of C27-29 steranes and C27-35 hopanes in the two kinds of marine crude oils are very different, and their concentrations in crude oils from Well TZ11 and TZ30 are about 4-5 times of those in crude oils from Well YM101 and YM201. It is another good evidence that they have independent sources.
In summary, based on distributions and compositions of various biomarkers in two kinds of marine crude oils, and combined with research results about geochemistry of different biomarkers in two sets of main marine source rocks in the Tarim Basin[8,9,10,11,12,13,14], crude oils from Well TZ11 and TZ30 should be derived from Cambrian-Lower Ordovician source rocks.
Although crude oils from Well TZ11 and TZ30 are generated by Cambrian-Lower Ordovician source rocks, the prerequisite condition for them to become end-member oil is that they are primary, that is, they aren’t altered by biodegradation. In m/z 177 and m/z 191 mass chromatograms of the saturate hydrocarbon fractions, no 25-norhopane compounds are detected (Fig. 9), suggesting that these crude oils are not biodegraded and can be use as end-member oil of Cambrian-Lower Ordovician source rocks. This conclusion provides a reference or tool for marine oil-source correlation in the Tarim Basin. At the same time, this kind of crude oil could remedy the inconvenience caused by absence of mature Cambrian-Lower Ordovician source rocks.
Fig. 9.
Fig. 9.
Partial m/z 191 and m/z 177 mass chromatograms in crude oils from Well TZ30 and TZ11. (a) Well TZ30, 4 997-5 026 m, O, m/z 191; (b) Well TZ30, 4 997-5 026 m, O, m/z 177; (c) Well TZ11, 4 301-4 307 m, S, m/z 191; (d) Well TZ11, 4 301-4 307 m, S, m/z 177.
Although crude oils from Well TZ11 and TZ30 can be used as end-member oils of Cambrian-Lower Ordovician source rocks in the Tarm Basin, but their geochemical characteristics would vary with organic matter input, depostional enviroment and water chemical conditions of the source rocks. In other words, for the Tarim Basin with an area of about 56×104 km2, it is expected that end-member oil from any sequence of source rocks such as Middle-Upper Ordovician or Cambrian-Lower Ordovician would be more than one kind, this is very important. Zhu et al.[43] found that there were two sets of carbon isotope values, light one (δ13C=-36‰ to -34‰) and heavy one (δ13C=-30‰ to -27‰) in kerogen from Cambrian source rocks in the Tarim Basin, corresponding to lower Cambrian and Middle-Upper Cambrian, respectively. The heavy carbon isotope values in kerogen from Middle-Upper Cambrian source rocks are similar to those in kerogen from Middle-Upper Ordovician source rocks. This shows that geochemical characteristics of Cambrian-Lower Ordovician source rocks are diverse, which demonstrates that end-member oil from Cambrian-Lower Ordovician source rocks could be more than one kind of end-member oil, certainly, every kind of end-member oil should have its own geochemical features.
4. Limitations of triaromatic steroids in oil-source correlation
In marine oil-source correlation of the Tarim Basin, much more attention have been paid to distributions and compositions of triaromatic steroids in crude oils and source rocks, and they are usually used as main envidences to discriminate crude oil generated by Cambrian-Lower Ordovician source rocks from that generated by Middle-Upper Ordovician source rocks[3,33-42,44-45]. Liang et al. thought that triaromatic steroids not only provided organic input information from different age and different lithology source rocks, but also were a good fingerprint not affected by maturity, and would become a useful indicator to oil-source correlation in high- over mature area[26]. However, distributions and compositions of aromatic steroids in diffetent marine crude oils from the Tarim Basin are not simple as they thought, and the influence of maturity on this kind of biomarkers should not be neglected.
As mentioned above, crude oils from the Yingmaili and Tazhong area (Figs. 7 and 8) have big differences in distributions and compositions of C27-29 sterane series (m/z 217) and C28-30 4-methyl sterane series (m/z 231). But unexpectedly, they have a very similar distribution of C26-28 triaromatic sterane series (m/z 231) and C27-29 methyl triaromatic sterane series (m/z 245).
In different marine end-member oils derived from Cambrian-Lower Ordovician and Middle-Upper Ordovician source rocks, C28 triaromatic steranes are predominant, and C26 and C27 components are of low abundance in C26-28 triaromatic sterane series (Fig. 10). Analytical results show that the marine crude oils from Cambrian-Lower Ordovician and Middle-Upper Ordovician source rocks have almost the same carbon number compositions of C26-28 triaromatic sterane series, but completely different carbon number compositions of C27-29 sterane series (Table 4 ). This phenomenons seems to show that there is not correspondence between carbon number compositions of C27-29 sterane series and C26-28 triraomatic sterane series in a geological sample with similar maturity. In other words, during aromatization of steroids, different precursors of steroids such as sterols and sterones would not be converted to corresponding aromatic steranes in the same extent. Therefore, it should be cautious to use distributions and compositions of triaromatic sterane series in oil-source correlation.
Fig. 10.
Fig. 10.
Distributions of triaromatic steroids in different marine crude oil samples (m/z 231). (a) Well TZ11, 4 301-4 307 m, S; (b) Well TD2, 4 561.93-5 040.00 m, C; (c) Well YM101, 5912.5- 5917.0 m, O; (d) Well YM201, 5844-5888 m, O.
Table 4 Compositions of C27-29 steranes and C26-28 triaromatic steranes in different marine oil samples from the Tarim Basin.
| Well | Depth/m | Age | C26-28 triaromatic steranes | C27-29 steranes | ||
|---|---|---|---|---|---|---|
| C26/C28 | C27/C28 | C27/C29 | C28/C29 | |||
| YM101 | 5 912.50-5 917.00 | O | 0.03 | 0.21 | 0.55 | 0.47 |
| YM201 | 5 844.00-5 888.00 | O | 0.04 | 0.21 | 0.68 | 0.39 |
| TZ11 | 4 301.00-4 307.00 | S | 0.05 | 0.23 | 0.33 | 0.58 |
| TZ30 | 4 997.00-5 026.00 | O | 0.06 | 0.36 | 0.38 | 0.62 |
| TD2 | 4 561.93-5 040.00 | C | 0.21 | 0.73 | 0.55 | 0.67 |
Methyl triaromatic sterane series, especially triaromatic dinosteranes, are a kind of biomarkers most widely used in marine oil-source correlation in the Tarim Basin[3,8-16,33-36,44-45]. However, distributions of methyl triaromatic sterane series in different end-member oils in this study are very similar, for example, C27-29 methyl triaromatic sterane series are predominant, and triaromatic dinosteranes are very low in abundance or even absent in the two kinds of marine crude oils (Fig. 11). This is completely different from their distributions of C27-29 methyl sterane series, because C30 dianosteranes are relatively abundant in end-member oil from Cambrian-Lower Ordovician source rocks in Well TZ11 and TZ30, but their relative abundance of triaromatic dinosteranes are very low and mismatches with that of C30 dianosteranes in this kind of crude oil. In other words, there is no correspondence between the relative abundances of C30 dianosteranes and triaromatic dianosteranes in the same crude oil observed. This phenonmenon is easily understandable for crude oil from Middle- Upper Ordovician source rocks without C30 dianosteranes, but it is unexpected for crude oil rich in C30 dianosteranes from Cambrian-Lower Ordovician source rocks. Apparently, it should be very careful to use the relative abundance of triaromatic dinosteranes as main envidences to discriminate the two kinds of marine crude oils in the Tarim Basin.
Fig. 11.
Fig. 11.
Distributions of methyl triaromatic steroids in different marine crude oil samples from the Tarim (m/z 245; 2-m, 3-m and 4-m refer to C27-29 2-methyl, 3-methyl and 4-methyl triaromatic steranes; “” —4, 23, 24-trimethyl triaromatic dinosteranes). (a) Well TZ11, 4301-4 307 m, S; (b) Well TD2, 4 561.93-5 040.00 m, C; (c) Well YM101, 5 912.5-5 917.0 m, O; (d) Well YM201, 5 844-5 888 m, O.
As mentioned above, crude oil from Well TD2 is a mixed oil altered by abnormally thermal event. Based on the results from Zhang et al.[35], the oil experienced an thermal event of about 200 °C-210 °C and thus was high in maturity. It is inferred that its compositions of aromatic hydrocarbons should be related to this thermal event (Fig. 1). However, it is noted that there is a big difference in distributions and compositions of triaromatic steranes and methyl triaromatic steranes between the crude oil from Well TD2 and end-member oil of Cambrian-Lower Ordovician source rocks from Well TZ11and TZ30. For example, in crude oil from Well TD2, carbon number compositions of C27-29 regular steranes and C26-28 triaormatic steranes are similar (Fig. 10 and Table 4), and triaromatic dinosterans are relatively abundant (Fig. 11), these features are basically consisitent with those of similar biomarkers in high-over mature Cambrian source rocks. These are the main evidences to use this oil from Well TD2 as end-member oil from Cambrian source rocks in most known literatures. Because of alteration by abormally high temperature, its maturity is much higher than that of common marine mature oils in the Tarim Basin and matches with high-over mature Cambrian source rocks. This is an important reason that there is a similar distribution and composition of C26-28 triaromatic steranes and C27-29 methyl triaromatic steranes between crude oil from Well TD2 and high-over mature Cambrian source rocks in the Tarim Basin. Bao et al. observed that there is a vary similar distribution of C26-28 triaromatic steranes and C27-29 methyl triraomatic steranes, especially rich in triaromatic dinosteranes, in pyrobitumen derived from Upper Paleozoic coal source rocks in the Xiaocaoba paleoreservoir (δ13C values of pyrobitumen>-26‰) and from Lower Paleozoic marine source rocks in the Yankong paleoreservoir (δ13C of pyrobitumen <-32‰) in the northern Guizhou Depression[28]. This phenonmenon clearly shows that distributions and compositions of C26-28 triaromatic steranes and C27-29 methyl triaromatic steranes could not provide reliable information about organic matter input in geological samples.
Therefore, crude oils from different source rocks could have similar distribution and composition of C26-28 triaromatic steranes and C27-29 methyl triaromatic steranes, and abundant triaromatic dinosteranes in over-mature geological samples are not necessarily related to organic matter input, and could be products of higher thermal evolution only. Therefore, it should be very cautiou to use C26-28 triaromatic steranes and C27-29 methyl triaromatic steranes in oil-source correaltion, because they could provide some contradictory geochemical information. In addition, geological samples used in oil-source correlation such as crude oils or source rocks should have similar maturity, to make the conclusion as objective and reliable as possible, because distribution and composition of various biomarkers in geological samples could be very easily affected by thermal maturity.
Steroids, such as varoius sterenes, steranes and triaromatic steranes in geological samples, are derived from various stanols or sterones in living organisms through diagenesis and thermal evolution[46]. At present, understanding on triaromatic steroids in geological samples is reletively limited compared to steranes. It is generally agreed that sterols in living organisms are converted to monoaromatic steroids through defunctionalization and dehydrogenation, and then to triaromatic steroids through further aromatization. However, few literatures reported the correspondence between carbon number of steranes and triaromatic steranes in geological samples. Abroad, these biomarkers are mostly used in evaluation of organic matter maturity[47,48], but in China, they are used in marine oil-source correlation in the Tarim Basin[3,8-16,33-36,44-45]. The analytical results in this study show that marine oils generated by different source rocks could have similar distribution and composition of triaromatic steroids, so it should be very careful to use them in marine oil-source correlation.
5. Conclusions
Although crude oil from Well TD2 may be derived mainly from Cambrian source rocks, it is a mixed oil of biodegraded and unbiodegraded oil and altered by abnormally high temperature, based on coexistence of whole normal alkane series and 25-norhopane series, and abnormally abundant 3-6-ring polycyclic aromatic hydrocarbons. Hence, it can’t be taken as end-member oil from Cambrian source rocks in the Tarim Basin.
Moderately mature crude oils from Well TZ11 and TZ30 have completely different distribution and composition of varoius biomarkers from crude oils derived from Middle- Upper Ordovician source rocks in Well YM101 and YM201, so they are two kinds of marine crude oils with different sources. Moreover, crude oils from Well TZ11 and TZ30 have no 25-norhopane series, suggesting that they are not biodegraded severely and are primary, so they can be used as end-member oil from Cambrian-Lower Ordovician source rocks.
The two kinds of marine end-member oils have similar distribution and composition of C26-28 triaromatic steranes and C27-29 methyl triaromatic steranes, such as predominant C28 triaromatic steranes and basically absent triaromatic dinosteranes, but in highly mature mixed oil altered by abnormally thermal event from Well TD2, C26, C27 triaromatic steranes and triaromatic dinosteranes are more abundant. These phenonmenan show that the distribution and composition of triaromatic steroids are easily affected by maturity, and it should be very cautious to use this kind of biomarkers in marine oil-source correlation.
Reference
Understanding on marine oil generation in China based on Tarim basin
Distribution of major hydrocarbon source rocks in the Lower Palaeozoic, Tarim Basin
Discovery and basic characteristics of the high-quality source rocks of the Cambrian Yuertusi Formation in Tarim Basin
DOI:10.1016/j.jnggs.2016.05.002
URL
[Cited within: 2]
The Upper Paleozoic strata of Tarim Basin have abundant resources of marine oil and gas.In the Tahe area,Halahatang area,Tazhong area of the basin,many large-scale oilfields have been found.These oilfields have been confirmed with oil and gas reserves more than 2.5billion tons of oil equivalent and have completed the annual output of more than 14 million tons of marine oil and gas equivalent.The view that the main hydrocarbon source rocks are the Cambrian or Ordovician is still controversial.Geochemists have made much work and effectively guide the oil and gas exploration in Tarim Basin.Because of the complexity of the basin and the limitation of samples,the research work and fine contrast are restricted.In this article,we investigated the Cambrian strata outcrop of Tarim Basin in detail.Through analyzing large amount of outcrops,high-quality hydrocarbon source rocks of Yuertusi Formation have been found in more than 10 outcrop points in Aksu region.The source rocks lithology is black shale,of which total organic carbon(TOC)content are between 2%-16%.Total organic carbon(TOC)of the black shale layer can be up to4%-16%,especially in outcrops of the Yutixi and Shiairike.This is the best marine hydrocarbon source rock which has found in China by now.The source rocks distribute stably in the Aksu region,the thickness of which is about 10-15 m.It is formed in sedimentary environment of middle gentle slope to low gentle slope.Organic matter enrichment is controlled by upwelling currents.Thick strata of dolostone developed in Xiaoerblak Formation are considered as good reservoir of beach and microbial reef in the upper strata of Yuertusi Formation.No hydrocarbon source rocks have been found in outcrop of Xiaoerblak Formation.Thick strata of gyprock and mudstone development are a set of good cap layer in the Lower Cambrian.This hydrocarbon accumulation combination has great exploration potential.
Geochemical characteristics of Cambrian-Ordovician marine source rocks in the Tarim Basin
A kind of coccoid diaoflagellates-like fossils gives a new explanation of source of dinosteranes in the early-middle Cambrian
Reviews on sources of marine oils in the Tarim Basin
Molecular fossils and oil-source correlations in Tarim Basin, NW China
DOI:10.1360/02tb9003 URL [Cited within: 4]
Paleozoic oil-source rock correlations in the Tarim Basin, NW China
DOI:10.1016/S0146-6380(00)00003-6 URL [Cited within: 4]
Molecular organic geochemistry of the Tarim Basin, northwest China
Middle-Upper Ordovician: The main source of the oils in the Tarim Basin
Upper-Middle Ordovician source rocks geochemistry of the Tarim Basin
Geochemical characteristics of the Cambrian source rocks in the Tarim Basin and oil-source correlation with typical marine crude oil
Generation, migration and accumulation model for the marine oils in the Tarim Basin
DOI:10.3799/dqkx.2010.081 URL [Cited within: 2]
Origin and quantitative source assessment of deep oils in the Tazhong Uplift, Tarim Basin
DOI:10.1016/j.orggeochem.2014.10.004
URL
[Cited within: 6]
A large amount of deep oil has been discovered in the Tazhong Uplift, Tarim Basin whereas the oil source is still controversial. An integrated geochemical approach was utilized to unravel the characteristics, origin and alteration of the deep oils. This study showed that the Lower Cambrian oil from well ZS1C (1x) was featured by small or trace amounts of biomarkers, unusually high concentration of dibenzothiophenes (DBTs), high δ34S of DBTs and high δ13C value of n-alkanes. These suggest a close genetic relationship with the Cambrian source rocks and TSR alteration. On the contrary, the Middle Cambrian oils from well ZS1 (2a) were characterized by low δ13C of n-alkanes and relatively high δ34S of individual sulfur compounds and a general “V” shape of steranes, indicating a good genetic affinity with the Middle–Upper Ordovician source rocks. The middle Cambrian salt rock separating the oils was suggested to be one of the factors responsible for the differentiation. It was suggested that most of the deep oils in the Tazhong Uplift were mixed source based on biomarkers and carbon isotope, which contain TSR altered oil in varied degree. The percentage of the oils contributed by the Cambrian–Lower Ordovician was in the range of 19–100% (average 57%) controlled by several geological and geochemical events. Significant variations in the δ34S values for individual compounds in the oils were observed suggesting a combination of different extent of TSR and thermal maturation alterations. The unusually high DBTs concentrations in the Tazhong-4 oilfield suggested as a result of mixing with the ZS1C oil (1x) and Lower Ordovician oils based on δ34S values of DBT. This study will enhance our understanding of both deep and shallow oil sources in the Tazhong Uplift and clarify the formation mechanisms of the unusually high DBTs oils in the region.
Aryl isoprenoids in crude oil and its implication in geological exploration
Investigations of aryl-isoprenoids in sedimentary organic matter suggest that these compounds are the diagenetic products of certain precursors from photosynthetic green sulphur bacteria Chlorobiaceae,indicating that its source rock was formed in an intense reductive environment.Marine oils from the tableland-basin region in Tarim basin generally contain abundant aryl-isoprenoids with the carbon number range of C10～C23.The pyrolytic products of the bitumen fraction in the oils are also characterized by a typical sulphur bacteria origin,i.e.,an abnormal enrichment of tetra-methyl benezenes in the C2～C5alkyl benzene fraction.These data indicate that the major marine oil and gas were originated at least from one set of the important source rocks developed in a water-layered anaerobic sedimentary environment in the tableland-basin region of Tarim basin,in addition to the consensus that they were derived from the Upper-Mid Ordovician sedimentary rocks with clay-mottar dome facies controlled by the upwelling ocean current in an incline at the platform margin.
Source facies of the Paleozoic petroleum systems in the Tabei uplift, Tarim Basin, NW China: Implications from aryl isoprenoids in crude oils
DOI:10.1016/S0146-6380(03)00063-9
URL
[Cited within: 1]
Aryl isoprenoids have been detected for the first time in crude oils from Paleozoic petroleum systems in the Tabei uplift, Tarim Basin, northwestern China. The principal compounds possess the 1-alkyl-2,3,6-trimethyl substitution pattern characteristic of diaromatic carotenoids found in the Chlorobiaceae family of photosynthetic sulfur bacteria, with a predominance of C 13 鈥 C 23 homologues in these samples. Flash pyrolysates of the asphaltene fractions isolated from crude oils show an unusual abundance of 1,2,3,4-tetramethylbenzene, an indicator for a significant contribution of diaromatic carotenoids to the source kerogen of these oils. The wide distribution of these compounds in crude oils reveals that penetration of the photic zone by sulfidic waters during deposition enabled prolific growth of photosynthetic green sulphur bacteria ( Chlorobiaceae). This suggests that the source rocks for the Paleozoic petroleum systems in the Tabei uplift were likely deposited under euxinic conditions with sulfate and sulfide-rich water bodies, which doesn't support previously published conclusions of a Middle-Upper Ordovician source that marks the slope facies at the margins of structural uplifts.
Distinguishing Cambrian from Upper Ordovician source rocks: Evidence from sulfur isotopes and biomarkers in the Tarim Basin
DOI:10.1016/j.orggeochem.2009.04.008
URL
[Cited within: 1]
The reported source rocks for the abundant petroleum in the Tarim Basin, China range from Cambrian to Lower Ordovician and/or Upper Ordovician in age. However, the difference between the two groups of source rocks is not well characterized. In this study, pyrite was removed from eleven mature to over mature kerogen samples from source rocks using the method of CrCl reduction and grinding. The kerogen and coexisting pyrite samples were then analyzed for S values. Results show that the kerogen samples from the Cambrian have S values between +10.4‰ and +19.4‰. The values are significantly higher than those from the Lower Ordovician kerogen (S of between +6.7‰ and +8.7‰), which in turn are generally higher than from the Upper Ordovician kerogen samples (S of between 6115.3 and +6.8‰). The associated pyrite shows a similar trend but with much lower S values. This stratigraphically controlled sulfur isotope variation parallels the evolving contemporary marine sulfate and dated oil S values from other basins, suggesting that seawater sulfate and source rock age have an important influence on kerogen and pyrite S values. The relatively high S values in the Cambrian to Lower Ordovician source rocks are associated with abundant aryl isoprenoids, gammacerane and C homohopanes in the extractable organic matter, indicating that these source rocks were deposited in a bottom water euxinic environment with water stratification. Compared with the Upper Ordovician, the Cambrian to Lower Ordovician source rocks show abundance in C 20R sterane, C tricyclic terpanes, 4,23,24-trimethyl triaromatic dinosteroids and depletion in C tetracyclic terpane, C hopane. Thus, S values and biomarkers of source rock organic matter can be used for distinguishing the Cambrian and Upper Ordovician source rocks in the Tarim Basin.
Application of sulfur and carbon isotopes to oil-source rock correlation: A case study from the Tazhong area, Tarim Basin, China
DOI:10.1016/j.orggeochem.2015.03.012
URL
[Cited within: 1]
Up until now,it has been assumed that oil in the Palaeozoic reservoirs of the Tazhong Uplift was derived from Upper Ordovician source rocks.Oils recently produced from the Middle and Lower Cambrian in wells ZS1 and ZS5 provide clues concerning the source rocks of the oils in the Tazhong Uplift,Tarim Basin,China.For this study,molecular composition,bulk and individual n-alkane δ~(13)C and individual alkyl-dibenzothiophene δ~(34)S values were determined for the potential source rocks and for oils from Cambrian and Ordovician reservoirs to determine the sources of the oils and to address whether δ~(13)C and δ~(34)S values can be used effectively for oil-source rock correlation purposes.The ZS1 and ZS5 Cambrian oils,and six other oils from Ordovician reservoirs,were not significantly altered by TSR.The ZS1 oils and most of the other oils,have a "V" shape in the distribution of C_(27)-C_(29) steranes,bulk and individual n-alkane δ~(13)C values predominantly between-31‰ to-35‰ VPDB,and bulk and individual alkyldibenzothiophene δ~(34)S values between 15‰ to 23‰ VCDT.These characteristics are similar to those for some Cambrian source rocks with kerogen δ~(13)C values between-34.1‰ and-35.3‰ and δ~(34)S values between 10.4‰ and 21.6‰.The oil produced from the Lower Ordovician in well YM2 has similar features to the ZS1 Cambrian oils.These new lines of evidence indicate that most of the oils in the Tazhong Uplift,contrary to previous interpretations,were probably derived from the Cambrian source rocks,and not from the Upper Ordovician.Conversely,the δ~(13)C and δ~(34)S values of ZSIC Cambrian oils have been shown to shift to more positive values due to thermochemical sulfate reduction(TSR).Thus,δ~(13)C and δ~(34)S values can be used as effective tools to demonstrate oil-source rock correlation,but only because there has been little or no TSR in this part of the section.
Accumulation conditions and play targets of oil and gas in the Cambrian subsalt dolomite, Tarim Basin, NW China
DOI:10.1016/S1876-3804(16)30043-X
URL
[Cited within: 1]
Based on seismic, well drilling and crop data in the Tarim Basin, the accumulation conditions including source rock, reservoir, caprock and paleouplift of the Cambrian subsalt dolomites have been investigated, and favorable exploration areas have been selected. The research results reveal: there are two sets of source rock, the excellent Cambrian Yuertusi Formation source rock and the potential Nanhua-Sinian source rock, in the Tarim Basin. The dolomite reservoir of platform mound-shoal and platform margin reef-shoal facies is extensive in the Lower Cambrian Xiaoerbulake Formation in Taixi terrace area. The Middle Cambrian high quality gypsum-salt caprock has an area of about 11 104km2; three inherited paleouplifts control the distribution of reservoirs and development of lithology stratigraphic traps and hydrocarbon accumulation, therefore, there are very good geologic conditions for the formation of large oil and gas fields in the Tarim Basin. Five oil and gas plays, namely, Tazhong-Badong intra-platform shoal, Tabei platform margin-reef bank, Keping platform margin-reef bank, Yulong-Moyu evaporative dolomite flat and Lunnan-Gucheng platform margin have been picked out, which provides a scientific basis for the oil and gas exploration and development in the Lower Cambrian dolomite.
Characteristics of carbon and sulfur isotopes in crude oils and oil-source correlation in the Tarim Basin
DOI:10.11781/sysydz200603281
URL
[Cited within: 1]
Based on the fractionation of carbon and sulfur isotopes in the process of petroleum generation and evolvement,the crude oils and their sources in the Tarim Basin have been discussed.The δ~(13)C of crude oil inherited the one of its biologic matrix.The δ~(13)C value of marine crude oil is less than-32‰ or more than-24‰,and the δ~(13)C value of continental crude oil is from-32‰ to-24‰.The organic sulfur in crude oil originates from the sulfate in source rock.But the δ~(34)S value of mature crude oil with temperature being higher than 80-120 ℃ is 3‰-4‰ lighter than the δ~(34)S value of the sulfate in source rock.The crude oils in the Tarim Basin can be classified into four types according to the characteristics of carbon and sulfur(isotopes) as well as other physical and chemical properties of crude oil.The second is 21‰-26‰ and δ~(13)C value is less than-32‰.It is typical marine crude oil.The second is Permo-Carboniferous crude oil whose δ~(34)S value is 5‰-7‰ and δ~(13)C value is less than-32‰.It is also marine crude oil,but the biologic matrix is poor.The third is Triassic-Jurassic crude oil whose(δ~(34)S) value is 10‰-14‰ and δ~(13)C value is about26‰.It is typical continental crude oil.The fourth is mixed oil of the above three types of crude oil.Its δ~(34)S value is between that of marine and continental oil.The mixed oil composed of Cambrian-Ordovician and Permo-Carboniferous crude oil has characteristics of marine oil,and the mixed oil composed of Cambrian-Ordovician and Triassic-Jurassic crude oil has characteristics of mixed oil facies.The mixed oil composed of Permo-Carboniferous and Triassic-Jurassic crude oil has not yet been discovered.
Origin and differential accumulation of hydrocarbons in Cambrian sub-salt dolomite reservoirs in Zhongshen Area, Tarim Basin, NW China
DOI:10.1016/S1876-3804(17)30006-X
URL
[Cited within: 1]
The origin and differential accumulation of hydrocarbons in the Cambrian sub-salt dolomite reservoirs in Zhongshen Area were studied based on comprehensive geochemical analysis of core samples, crude oil samples and natural gas samples. Mass spectrometric detection shows the core samples and crude oil samples are characterized by high C28sterane content, low diasterane content, high gammacerane content and abundant aryl-Isoprenoids, and the associated gas has a low nitrogen content of 0.24%614.02%, so it is inferred that the oil and gas are derived from Cambrian – Lower Ordovician source rock. The natural gas in the Middle Cambrian has a methane carbon isotope value of 6151.4‰ 61 6144.7‰ and dryness coefficient of 0.65610.78, representing associated gas, and the natural gas in the Lower Cambrian has a methane carbon isotope value of 6141.4‰ 61 6140.6‰, and dryness coefficient of 0.99, representing cracking gas. The deep formations in the Tarim Basin contain cracking gas with high H2S content produced by thermo-chemical sulfate reduction (TSR). Due to the poorer reservoir properties and undeveloped fracture network system, the Middle Cambrian reservoirs have low charging degree of this kind of gas, so low H2S content (0.003 8%610.200 0%); in contrast, with good reservoir properties and developed fracture network system, the Lower Cambrian reservoirs have a higher charging degree of this kind of gas, and thus high H2S content of 3.25%618.20%. In summary, the oil and gas of Cambrian sub-salt dolomite reservoirs in Zhongshen Area are derived from Cambrian – Lower Ordovician source rock, and the differential accumulation of gas is the joint effect of reservoir physical property and development degree of fracture network system.
Maturity and its history of Cambrian marine source rocks in the Tarim Basin
DOI:10.1016/S0955-2219(02)00073-0
URL
[Cited within: 1]
The reflectance of primary organic macerals(vitrinite-like maceral and zooclast)are effective index for assessing the maturity of Cambrian m arine source rocks in the Tarim Basin,According to the primary organic macerals reflectance data of more th an 110samples from Cambrian marine s ource rocks in wells and outcrops,th e middle and lower Cambrian source roc ks of the Tarim Basin are in the high ma ture and overmature phase,no Cambrian source rocks still exist in the maturity phase of oil windows pre sently.Maturity distribution and e volution of Cambrian source rocks are delinea ted using software BasinMod-1D on 250wells and 340pseudowells from the 26seismic profiles.Presently,the vitrinite reflectance equivalents(VRE)of Cambrian source rocks are higher t han3%in the Manjaer Depression,and hig her than 4%in the central area of the Manjee Depression.The relative lower maturity area of the middle and lower Cambrian source rocks are loca ted in the high areas of the Tazhong Uplift and the Tabei Uplift,and limi ted area of the Bachu Uplift,with VRE ranging from 1.6%to 2.0%.
Oil-source correlations for high and over matured marine source rocks in South China
DOI:10.1016/j.molcatb.2005.02.001
URL
[Cited within: 3]
The high and over matured marine source rocks, with vitrinite reflectance value (R_o) over (1.3%) and 2%, respectively, widely developed in South China, in which abundant paleo-oil traps and oil showing have been found. Some common biomarkers as isoprenes, sterane and terpane have been used for correlating of oil and source. With the increase of maturity, it might be a big problem since the biomarkers extracted from oils, bitumen and source rocks would become a similar developing pattern, lose their original significations and are hardly to be used for the correlations. The carbon isotopic composition shows a clear fractionation of thermal evolution and it is difficult for precious correlating. The researches on the samples from Shiwandashan Basin suggest that triaromatic steroid could be practically used for identifying different strata and lithological rocks, including mudstone and limestone source rocks, under high and over matured conditions, so triaromatic steroid is very likely to be an effective tool for correlating in these cases. Correlations show that the effective source rocks in South China are mainly mudstone but not carbonate. This correlation method and biomarkers could be widely used for oil-source correlation of high and over matured source rocks developed in either north or south China.
Biological organic source and depositional environment of over-mature source rocks of Longtan Formation in Sichuan basin
Study on origin and source of solid bitumen from the Xiaocaoba Paleo-reservoir in the Northern Guizhou Depression
The Xiaocaoba paleo-reservoir was recently discovered in the northern Guizhou Depression,but its source and origin remain unknown.About 3.4%of solid bitumen reflectance and more than 65%of methyl diamantane index(MD1) indicate that these solid bitumens are at the over-mature stage,and are derived from the cracking of early-accumulated crude oils.By the comparison of their geochemical characteristics with those of the solid bitumens in the Yankong paleo-reservoir,derived from the Niutitang Formation source rocks of Lower Cambrian,it is found that the solid bitumens in the two paleo-reservoirs are very similar in distributions and compositions of various biomarkers,such as alkanes,terpanes,steranes,and triaromatic steranes.Thus,their source and origin cannot be identified based on these biomarkers,because the convergence of geochemical characteristics for various biomarkers at the post-mature stage leads to the ineffectiveness of related geochemical parameters in oil-source correlation.However,their δ~(13)C values show obvious differences due to the inheritance of organic precursor δ~(13)C,for example,the solid bitumens from the Xiaocaoba paleo-reservoir are enriched in heavy carbon isotope and their δ~(13)C values are more than-26‰,while for the solid bitumens from the Yankong paleo-reservoir,the δ~(13)C values are less than about-32‰,indicating that they have different sources.In other words,the solid bitumens from the Xiaocaoba paleo-reservoir cannot be derived from the Lower Cambrian source rocks with a relatively light carbon isotope in the study area.The kerogen from the C-P containing-coal source rocks in the adjacent areas has a relatively heavier carbon isotope,their δ~(13)C values ranging from-27‰ to-22‰,very similar to that of the solid bitumen from the Xiaocaoba paleo-reservoir.Therefore,it reasonably infers that the solid bitumen from the Xiaocaoba paleo-reservoir should be derived from the C-P source rocks.The existence of the Xiaocaoba paleo-reservoir shows that the C-P containing-coal source rocks have an important contribution to petroleum reserves in the study area.Therefore,stable carbon isotope of organic matter can also supply much more useful and reliable geochemical information for source correlation at the post-mature stage,compared to various biomarkers.
The distribution and origin of Cambrian crude oil in North Tarim Basin
Potential petroleum sources and exploration directions around the Manjar Sag in the Tarim Basin
DOI:10.1007/s11430-015-5573-7 URL [Cited within: 2]
Geochemistry of Palaeozoic marine petroleum from the Tarim Basin, NW China: Part 1. Oil family classification
DOI:10.1016/j.orggeochem.2005.01.013
URL
[Cited within: 4]
A series of Palaeozoic marine oils ranging from condensates to very heavy oils from the cratonic region of the Tarim Basin, NW China have been examined to delineate oil families. Crude oils from the Mesozoic foreland Kuqa Depression were also analyzed for comparison. The genetic family was assessed using bulk hydrocarbon isotopic composition, alkylation pattern of polycyclic aromatic hydrocarbons (PAHs) and biomarker distributions. Detailed oil il correlation suggests two distinct families occur in the cratonic region. Despite the diversity of the reservoir rocks and some variability in oil physical properties, the Tabei and Tazhong oils are classified, in general, into a single family, with a possible indication for secondary subdivision. These oils are characterized by low pristane/phytane (Pr/Ph) ratio, high dibenzothiophene/phenanthrene (DBT/P) ratio, light bulk isotopic composition, high degree of PAH alkylation, high proportion of C 23 and C 24 tricyclic terpanes and low abundance of C 24 tetracyclic terpane and triaromatic dinosteroids. This family is inferred to have a Middle鈥揢pper Ordovician source rock. The Tadong family, distinctly different from the Tabei and Tazhong families, is characterized by relatively high Pr/Ph ratio, low DBT/P ratio, slightly heavier bulk isotopic compositions and low degree of PAH alkylation. It also has a unique biomarker signature, with a high proportion of triaromatic dinosteroids, possibly indicating Cambrian鈥揕ower Ordovician source rocks. The oils from the Kuqa Depression are easily distinguished from the other two families due to their terrigenous origin. The major characteristics of the Kuqa oils are high Pr/Ph ratio, very low DBT/P ratio, heavy bulk isotopic composition, low PAH alkylation degree, high proportion of C 20 and C 21 tricyclic terpanes and C 24 tetracylic terpane, and abundance of triaromatic dinosteranes and 4-methyl-24-ethyltriaromatic cholestanes. These characteristics are consistent with terrestrial organic source rocks deposited under sub-oxic conditions.
Petroleum source in the Tazhong Uplift, Tarim Basin: New insights from geochemical and fluid inclusion data
DOI:10.1016/j.orggeochem.2010.02.018
URL
[Cited within: 1]
A total of 108 drill stem test (DST) crude oil samples and 10 reservoir fluid inclusion samples were investigated geochemically to identify the characteristics and origin of the crude oil in the Tazhong Uplift, Tarim Basin, NW China. Results show that the majority of oils share typical biomarker characteristics from the Middle-Upper Ordovician (O) source rock and related crude oil features. These features include a distinct “V” shape in the relative abundance of C, C and C regular steranes, and low abundances of dinosterane, 24-norcholestanes, triaromatic dinosteroids and gammacerane. Only a few oils display typical biomarker features indicating a Cambrian–Lower Ordovician (?-O) genetic affinity, such as linear or “anti-L” shape C, C and C regular sterane distributions, and relatively high concentrations of dinosterane, 24-norcholestanes, triaromatic dinosteroids and gammacerane. It appears that most of the oils studied were derived from the O intervals, as suggested by previous studies. However, the δC values of individual -alkanes indicate that most of the crude oils in the Tazhong Uplift represent a mixture of two end member oils, an O-? derived oil, such as from well TD2 (or TZ62 (S)), and an O derived oil, such as from well YM2. The data suggest that most of the oils in the uplift have a mixed origin, and do not originated from the Middle-Upper Ordovician strata alone. This conclusion is supported by data on the molecular composition of petroleum inclusions. This new oil mixing model is critical for reconstructing the hydrocarbon formation and accumulation history for the region, and may have important implications for further petroleum exploration in the Tarim Basin.
Geochemistry of the heavy oils from well TD2 in Tarin basin, NW Chian
Origin of oils from well Tadong 2 in Tarim Basin
Oil accumulation history in Tadong 2 Reservoir in Tarim basin, NW China: A case study of oil stability and cracking
The oil from the Well Tadong 2 ( TD2 ) in the Cambrian reservoir in eastern Tarim Basin contains high concentration of 4-methyl steranes, dinosteranes and their aromatic dinosteroids, which is different from heavy oils discovered in the Lunnan area and their Middle-Upper Ordovician source rocks, suggesting a clear affinity with the Cambrian source rock extracts but distinctly. Present maturity of the Cambrian source rocks is as high as 2. 67%-2. 75% VRE. Burial history and hydrocarbon generation history analysis suggest that major liquid hydrocarbon generation time from this source rock suite was in the Middle and Late Ordovician and petroleum generation process was rapidly completed within 10 Ma. All these indicate that the oil accumulation has been severely affected by high temperature processes, which caused oil densification and cracking to gas. During subsequent stratigraphic elevation after the Devonian, TD2 oil pool was uplifted to 1730m undersurface and reservoir temperature dropped to about 70℃( brine inclusion homogenization temperature of 50-90℃). Newly formed fractures and tectonic fissures linked up early accumulated oil and gas in the Cambrian fissure system, leading to oil and gas diffusion upward and biodegradation. High concentration of 25-norhopanes occurrence in oil is one obvious result of biodegradation, which causes further oil densification. Discovery of TD2 heavy oil inspire some new considerations. An oil pool formed more than 400Ma ago, which has experienced paleotemperature of higher than 200℃, can be preserved till present, indicating much higher oil stability than previously believed.
Geochemical characteristics and reservoir formation of Cambrian heavy oil of well Tadong 2 in Tarim Basin
DOI:10.1016/S1874-8651(10)60080-4
URL
[Cited within: 5]
Studying the geochemical characteristics and formation history of heavy oil from Well Tadong 2 is of great importance to clarify the oil accumulation of Tarim marine crude oil.The writer synthetically apply the isotope mass spectrogram,chromatogram and chromatogram-mass spectrogram methods to the research of molecular fossil characteristic of heavy oil from Well Tadong 2,and results reveal that heavy oil from Well Tadong 2 is characterized by high gammacerane,high C28 sterane,low rearranged sterane and high C27-triaromatic steroid,these characteristics are similar to that of Cambrian-Lower Ordovician source rock,which demonstrate that Cambrian crude oil come from Cambrian-Lower Ordovician source rock;condensed compounds(fluoranthene,pyrene,benzo[a]anthracene,bow,benzo fluoranthene,benzopyrene) with high abundance are detected in the heavy oil of Well Tadong 2,and carbon isotope value of whole oil evidently lean to heavier,all foregoing characteristics revealing that hydrocarbons in crude oil become densification by thermal alteration.Homogenization temperature of fluid inclusion and burial-thermal evolution history imply that accumulation period of heavy oil from Well Tadong 2 may be at 450~440 Ma.
Timing of pale-oils accumulation in Tadong No.2 well, Tarim Basin
Origin of the unusually high dibenzothiophene oils in Tazhong-4 Oilfield of Tarim Basin and its implication in deep petroleum exploration
DOI:10.1016/j.orggeochem.2012.04.008
URL
[Cited within: 1]
Unusually high dibenzothiophene (DBT) concentrations are present in the oils from the Tazhong-4 Oilfield in the Tazhong Uplift, Tarim Basin. Positive-ion electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) was used in combination with conventional geochemical approaches to unravel the enrichment mechanisms. Significant amounts of S1 species with relatively low DBE values (0–8), i.e., sulfur ethers, mercaptans, thiophenes and benzothiophenes, were detected in three Lower Ordovician oils with high thermal maturity, which were suggested to be the products of thermochemical sulfate reduction (TSR) in the reservoir. The occurrence of TSR was also supported by the coexistence of thiadiamondoids and abundant H2S in the gases associated with the oils. Obviously low concentrations of the DBE=9 S1 species (mainly equivalent to C0–C35 DBTs) compared to its homologues were observed for the three oils which were probably altered by TSR, indicating that no positive relationship existed between TSR and DBTs in this study. The sulfur compounds in the Tazhong-4 oils are quite similar to those in the majority of Lower Ordovician oils characterized by high concentrations of DBTs and dominant DBE=9 S1 species with only small amounts of sulfur compounds with low thermal stability (DBE=0–8), suggesting only a small proportion of sulfur compounds were derived from TSR. It is thermal maturity rather than TSR that has caused the unusually high DBT concentrations in most of the Lower Ordovician oils. We suggest that the unusually high DBT oils in the Tazhong-4 Oilfield are caused by oil mixing from the later charged Lower Ordovician (or perhaps even deeper), with high DBT abundances from the earlier less mature oils, which was supported by our oil mixing experiments and previous relevant investigations as well as abundant authigenic pyrite of hydrothermal origin. We believe that TSR should have occurred in the Tazhong Uplift based on our FT-ICR MS results. However, normal sulfur compounds were detected in most oils and no increase of δ13C2H6–δ13C4H10 was observed for the gas hydrocarbons, suggesting only a slight alteration of the oils by TSR currently and/or recently. We suspect that the abnormal sulfur compounds in the Lower Ordovician oils might also be a result of deep oil mixing, which might imply a deeper petroliferous horizon, i.e., Cambrian, with a high petroleum potential. This study is important to further deep petroleum exploration in the area.
The global distribution of polycyclic aromatic hydrocarbons in recent sediments
DOI:10.1016/0016-7037(78)90182-5
URL
[Cited within: 1]
Polycyclic aromatic hydrocarbons (PAH) and their alkyl homologs are distributed in sediments throughout the world. The qualitative PAH pattern is remarkably constant for most of the locations studied, and the quantitative PAH abundance increases with proximity to urban centers. These findings are consistent with anthropogenic combustion's being the major source of these compounds. Two non-combustion sources of PAH have also been noted: retene coming from abietic acid and perylene probably coming from various extended quinone pigments.
Polycyclic aromatic hydrocarbons in recent lake sediments-I. Compounds having anthropogenic origins
DOI:10.1016/0016-7037(80)90040-X
URL
[Cited within: 1]
Polycyclic aromatic hydrocarbons (PAH) in sediment cores from Lake Lucerne, Lake Zürich, and Greifensee, Switzerland, and Lake Washington, northwest U.S.A., have been isolated, identified and quantified by glass capillary gas chromatography and gas chromatography/mass spectrometry. Surface sediment layers are greatly enriched in PAH—up to 40 times—compared to deeper layers. In addition, concentration increases in upper sediments generally correspond to increasing industrialization and urbanization in the catchment basins of the lakes. Few PAH could be detected in pre-industrial revolution sediments, indicating that background levels for most PAH in aquatic sediments are extremely low. These results are consistent with an anthropogenic source for most of the aromatic hydrocarbons present in the modern sediments. A comparison of PAH distributions in the sediments and in possible source materials shows that urban runoff of street dust may be the most important PAH input to these lacustrine sediments. There is evidence that a significant contribution to the PAH content of street dust comes from material associated with asphalt.
The origin and fate of 4-methyl steroid hydrocarbons 1. 4-methyl sterenes
DOI:10.1016/0016-7037(86)90187-0
URL
[Cited within: 1]
Treatment of 4-methylcholest-4-ene under mild acid conditions at low temperatures gives chemical evidence for certain features seen in the distributions of sedimentary 4-methyl steroid hydrocarbons, and further indicates that many low temperature diagenetic reactions of steroids are explicable in terms of acid catalysed rearrangements. Specifically, the results provide: (i) Indirect evidence that the 4-ene skeleton is a key intermediate in the dehydration of 4-methyl stanols in sediments. (ii) An explanation for the distribution of 4-methyl sterenes and A-nor sterenes in the lacustrine Messel shale (Eocene). (iii) An explanation for the presence of 4β-methyl steranes in relatively immature sedimentary rocks, despite the precursor stanols having the 4α-methyl configuration. With increasing maturity in the Paris Basin shales (Lower Toarcian), the less stable 4β-methyl steranes decrease gradually in abundance relative to their 4α-methyl counterparts, at a rate fairly similar to the change in pristane stereochemistry.
A new source of 4-methyl and 5α(H)-stanols in sediments: Prymnesiophyte microalgae of the genus Pavlova
DOI:10.1016/0146-6380(90)90094-G
URL
[Cited within: 2]
Lipid analyses of four species of marine unicellular prymnesiophyte algae of the genus Pavlova have shown that each contains significant amounts of 4α-methyl sterols, the major one being the C 30 sterol 4α-methyl-24-ethyl-5α-cholest-22E-en-3gb-ol. This sterol has a similar structure to dinosterol, which occurs in dinoflagellates, except that the side-chain contains a 24-ethyl group rather than 23,24-dimethyl substitution. Other 4-methyl sterols include 4α,24-dimethyl-5α-cholest-22E-en-3β-ol, 4α,24-dimethyl-5α-cholestan-3β-ol and 4α-methyl-24-ethyl-5α-cholestan-3β-ol. The major 4-dimethyl sterol in each of the species is 24-ethylcholesta-5,22E-dien-3β-ol. Two species also contain significant amounts of the 5α(H)-stanol 24-ethyl-5α-cholest-22E-en-3β-ol. Unusual hydroxylated compounds found in each species were tentatively identified as dihydroxylated 4-methylsteranes. Species of Pavlova are common in marine and brackish water environments and so might be important sources of 4-methyl and 4-desmethyl stenols and stanols in some sediments.
Carbon isotopic compositions and origin of Paleozoic crude oil in the platform region of Tarim Basin, NW China
DOI:10.1016/S1876-3804(17)30119-2
URL
[Cited within: 1]
Based on the carbon isotopic compositions of Cambrian-Ordovician source rocks Kerogen Samples and Paleozoic crude oil in the platform region of Tarim Basin, the origin and source of Paleozoic crude oil were investigated. There are at least two sets of source rocks with different carbon isotope compositions in the Cambrian, the Lower Cambrian source rock with lighter carbon isotope composition and Middle-Upper Cambrian source rock with heavier carbon isotope composition, while the Ordovician source rock is somewhere in between. The δ 13 C values of Paleozoic crude oil samples are wide in distribution range, from 6135.2‰ to 6128.1‰. The crude oil with lighter carbon isotopic compositions ( δ 13 C6129.0‰) was mainly derived from the Middle-Upper Cambrian source rocks, and the crude oil with δ 13 C value in between may be derived from Cambrian source rocks. It is concluded through analysis that the Cambrian source rock could become the major source rock in the Tarim Basin and the platform region has huge potential oil and gas resources in the deep formations.
Palaeozoic oil-source correlation in the Tarim Basin, NW China: A review
DOI:10.1016/j.orggeochem.2016.01.008
URL
[Cited within: 3]
Oil–source correlation in the cratonic region of the Tarim Basin, NW China has long been controversial. Current knowledge of the potential source rock distribution, end-member selection, oil–source correlation and impacts of secondary alteration processes have been reviewed. Two source rock systems from the Cambrian–Lower Ordovician (07–O1) and Middle–Upper Ordovician (O2–3) potentially contributed to oil accumulations in the cratonic region. Geochemical correlations suggest that oils are dominantly derived from the O2–3source rocks, while geological evidence and sulfur isotopic compositions supports the 07–O1source rocks as a main contributor. Such inconsistency is rooted in the selection of end-members and their characterization. Changes in some biomarker parameters, such as sterane distribution, gammacerane index and ratio of tricyclic terpanes to pentacyclic terpanes, are mainly controlled by thermal maturation and biodegradation rather than source input and depositional environment variation. No clear boundary between the two source systems can be established using biomarkers except for a few diagnostic components. Some 07–O1source signatures, such as even/odd predominance ofn-alkanes, unusual tricyclic terpane distribution, unusually enriched13C carbon isotopic compositions of oils and kerogens, and the occurrence of combustion related polycyclic aromatic hydrocarbons, largely result from an abnormal heating influence either from igneous intrusion or hydrothermal fluid activity. Local thermochemical sulfate reduction can also remove most source-related signatures. These so-called markers in currently selected end-members result from extensive secondary alteration processes and do not reflect source input differences. While more research is needed for full reconstruction of oil–source correlation in the cratonic region of the Tarim Basin, the main source rocks most likely reside in the 07–O1succession rather than O2–3.
The significance of 24-norcholestanes, triaromatic steroids and dinosteroids in oils and Cambrian-Ordovician source rocks from the cratonic region of the Tarim Basin, NW China
DOI:10.1016/j.apgeochem.2012.03.006
URL
[Cited within: 3]
Two oil families in Ordovician reservoirs from the cratonic region of the Tarim Basin are distinguished by the distribution of regular steranes, triaromatic steroids, norcholestanes and dinosteroids. Oils with relatively lower contents of C28 regular steranes, C26 20S, C26 20R+C27 20S and C27 20R regular triaromatic steroids, dinosteranes, 24-norcholestanes and triaromatic dinosteroids originated from Middle鈥揢pper Ordovician source rocks. In contrast, oils with abnormally high abundances of the above compounds are derived from Cambrian and Lower Ordovician source rocks. Only a few oils have previously been reported to be of Cambrian and Lower Ordovician origin, especially in the east region of the Tarim Basin. This study further reports the discovery of oil accumulations of Cambrian and Lower Ordovician origin in the Tabei and Tazhong Uplifts, which indicates a potential for further discoveries involving Cambrian and Lower Ordovician sourced oils in the Tarim Basin. Dinosteroids in petroleum and ancient sediments are generally thought to be biomarkers for dinoflagellates and 24-norcholestanes for dinoflagellates and diatoms. Therefore, the abnormally high abundance of these compounds in extracts from the organic-rich sediments in the Cambrian and Lower Ordovician and related oils in the cratonic region of the Tarim Basin suggests that phytoplankton algae related to dinoflagellates have appeared and might have flourished in the Tarim Basin during the Cambrian Period. Steroids with less common structural configurations are underutilized and can expand understanding of the early development history of organisms, as well as define petroleum systems.
Chemical fossils: The geological fate of steroids
DOI:10.1126/science.217.4559.491
URL
PMID:17820518
[Cited within: 1]
Steroids are used to illustrate some of the significant advances that have been made in recent years in understanding the biological origin and geological fate of the organic compounds in sediments. The precursor sterols are transformed, initially by microbial activity and later by physicochemical constraints, into thermodynamically more stable saturated and aromatic hydrocarbons in mature sediments and petroleums. The steps in this transformation result in a complex web linking biogenesis, diagenesis, and catagenesis. Indeed, the complexity and variety of biological lipids such as the steroids are evidently matched in the corresponding geolipids. The extent of preservation of the biochemical imprint in the structures and stereochemistry of these geolipids, even over hundreds of millions of years, is startling, as is the systematic and sequential nature of the geochemical changes they evidently undergo. This new understanding of molecular organic geochemistry has applications in petroleum geochemistry, where biological marker compounds are valuable in the assessment of sediment maturity and in correlation work.
Molecular parameters of maturation in Toarcian shales, Paris Basin: Ⅲ. Changes in the aromatic steroids hydrocarbons
DOI:10.1016/0016-7037(81)90227-1
URL
[Cited within: 1]
Three series of monoaromatic steroid hydrocarbons ( base peak = m/ z 239, 253 and 267) and four series of triaromatic steroid hydrocarbons ( base peak = m/ z 217, 231, 245 and 259) have been recognised by computerised gas chromatography-mass spectrometry in a variety of samples of Lower Toarcian shales from the Paris Basin. An increase in the extent of aromatisation of the monoaromatic steroid hydrocarbons in the m/ z 253 series (measured by the abundance of monoaromatic components relative to triaromatic components in the m/ z 231 series) is observed with increasing maturity. Variations between reported maximum burial depth and extent of aromatisation are explicable partly in terms of new maximum burial depth information for some of the shales. The extent of carbon-carbon bond cracking in the side chains of the aromatic steroid hydrocarbons has only begun to be significant in certain of the deepest samples.
Steroids hydrocarbons and the thermal history of sediments
DOI:10.1038/295223a0
URL
[Cited within: 1]
Assessment of the extents to which certain organic chemical reactions have occurred in sedimentary rocks with increasing burial depth and the associated temperature rise, can distinguish differences in the extent of their thermal maturation 1–10 . Heating experiments with sediments have suggested that these different reaction types have different kinetic constants 11 . Therefore, a measurement of the extent to which one reaction type has occurred might be expected to correspond to different values of a measurement based on a different reaction type, depending, for example, on the average sedimentary heating rate (°C Myr 611 ) 12 of the sample. We use here two reaction types to investigate this hypothesis: (1) configurational isomerization in steroid alkanes, represented by the conversion of the biologically inherited configuration, 5α(H), 14α(H), 17α(H), 20R, in a C 29 sterane to an approximately equal mixture of itself and the corresponding 20S configuration formed in the sediment 6,13 ; and (2) apparent aromatization of two C 29 monoaromatic steroid hydrocarbons (Fig. 2) assumed to be isomeric at C-5 (refs 14–21), based on retention time comparisons with synthesized C-27 analogues, to a presumed product, the C 28 triaromatic steroid hydrocarbon 9,14 . Comparison of the extents to which these two reactions have occurred in suites of sediment samples has allowed three basins [Pannonian Basin (Pliocene), Mahakam Delta (Miocene), Paris Basin (Toarcian)] with different thermal histories to be distinguished. Extension of the hypothesis to two other sedimentary sequences suggests a higher average heating rate for the Oligocene of the Zhanhua Depression (north-east China) than for the Cretaceous of the Wyoming Overthrust Belt.
