Application of Rare-Earth Elements and Comparison to Molecular Markers in Oil-Source Correlation of Tight Oil: A Case Study of Chang 7 of the Upper Triassic Yanchang Formation in Longdong Area, Ordos Basin, China.

The biomarker features of 10 Chang 7 crude oil samples were investigated by gas chromatography-mass spectrometry (GC-MS), and the rare-earth element (REE) compositions of 16 Chang 7 and Chang 8 crude oil samples were determined by inductively coupled plasma-mass spectrometry (ICP-MS) for the first time in Longdong area. Oil-source correlation analysis was improved by biomarkers and REEs. The distribution and relative ratios of a series of biomarker parameters in saturated hydrocarbons and aromatic hydrocarbons of crude oil samples indicate that Chang 7 tight oil has already reached the mature stage. The organic matter mainly comes from lower aquatic organisms of algae, with some contribution of micro-organisms and bacteria, while the forming environment of tight oil is mainly the transitional environment of sub-oxidizing to sub-reducing. The V/(V + Ni) and Ni/Co ratios of crude oil samples suggest that the specific redox conditions of Chang 71 and Chang 72 samples were slightly oxic, while Chang 73 and Chang 8 samples were formed under an anoxic environment. The results of both biomarker-based and REE-based oil-source correlation analysis indicate that Chang 71 and Chang 72 tight oils come from Chang 7 mudstone, while most of the Chang 73 tight oils are from Chang 7 oil shale, with part of mixed from Chang 7 mudstone. This recognition may indicate that Chang 7 mudstone and oil shale are two relatively independent hydrocarbon self-generation and near-storage systems. The analysis results demonstrate that the REE composition in crude oil is an efficient and accurate tool for oil-source correlation in the petroleum system.

Introduction

As the recoverable reserves of conventional oil and gas resources continue to decline, unconventional resources with great potential represented by tight oil have gradually become a new exploration field and are attracting the attention of the energy industry.[1−7] In China, tight oil is defined as a hydrocarbon resource that occurs in the source rock or the tight reservoir adjacent to the source rock in adsorbed or free state, without large-scale and long-distance migration.[5,6] Tight oil resources are widely distributed in major basins in China, such as Lucaogou Formation of Permian in Junggar Basin, Middle to Lower Jurassic in Sichuan Basin, and Upper Triassic Yanchang Formation in Ordos Basin.[1,5] Among them, Chang 7 section of Yanchang Formation is typical deep lacustrine gravitational flow type tight oil, with proved geological reserves of 10 × 108 ton.[2,3] In previous studies, Chang 7 section is generally regarded as the main source rock of the whole Yanchang Formation and is the main hydrocarbon contributor to the overlying Chang 6, Chang 8, and Chang 9 reservoirs, while its attribute as a tight oil reservoir and the source of its inner tight oil was ignored.[8−10] With the focus of tight oil exploration shifting from the traditional strata to the new target for increasing reserves and production, Chang 7 tight oil and further shale oil resources have been paid attention to. In Ordos Basin, tight oil is mainly from tight massive sandstone reservoirs, while shale oil refers to oil resources in tight sandstone–mudstone interbedded and shale reservoirs.[2,11,12] Longdong area is located in the depocenter of the lacustrine basin at the Chang 7 section depositional stage, where organic-rich source rock and turbidite sandstones are developed, thus forming a lithologic combination of source rock–reservoir interbedding. This makes the tight oil reserves of this area particularly rich.[2,3,13] However, the cyclic development of the lacustrine basin and the frequent transgression–regression lacustrine water in Chang 7 period results in strong heterogeneity of the source rock and reservoir vertically and horizontally. Meanwhile, as the source rock of Chang 7 section, the dark mudstone and oil shale have different hydrocarbon generation potentials, hydrocarbon expulsion thresholds, deposition conditions, and redox states.[14,15] All these features make it difficult to predict the distribution of tight oil pool; also, the source of crude oil is not well understood, which limits the exploration and exploitation of tight oil and further shale oil to a certain extent.

As mentioned before, previous studies on oil–source correlation in the Longdong area mainly focused on the relationship between the crude oil in Chang 6, Chang 8, and Chang 9 tight reservoirs and the source rocks of Chang 7 and Chang 9.[8,10,16,17] There is no doubt that the tight oil in the Chang 7 reservoir comes from the Chang 7 source rock, but it is rarely mentioned whether it comes from mudstone or oil shale. It is well accepted that Chang 7 mudstone and oil shale have different hydrocarbon generation potentials and times, sedimentary environments, and accumulation patterns.[14,15,18−20] Though Xu et al. proposed that Chang 7 mudstone controls the occurrence of the Chang 7 tight oil pool and Chang 7 oil shale mainly controls the occurrence of the Chang 8 tight oil pool, evidence is lacking from crude oil samples.[14] Also, the geochemical reports of crude oil in Ordos Basin are mainly on the biomarkers.[8,10,18] Biomarkers, as a traditional tool for oil–source correlation, are not effective in facing with the complicated hydrocarbon accumulation and refined oil–source correlation, not to mention that they will lose original significance because of the influence of thermal maturity and secondary alterations such as biodegradation.[21,22] In addition, the concentration ratio of biomarkers which is commonly used in oil group classification and oil–source correlation vary as a nonlinear function of the amount of different types of oils, thus affecting the comparison results of mixed-source crude oil.[23] However, some elemental ratios of crude oil remain stable in most instances, such as the V/Ni ratio.[24,25] At the same time, extensive studies demonstrate that the concentration and distribution of trace elements in crude oil can provide information about the source rock sedimentary environment, oil maturity, and origin and also be a potential tool for oil–oil correlation and oil–source correlation.[24−27] Rare-earth elements (REEs), as lanthanide elements from La to Lu, have been widely used on material origin and systematic division in various geological processes for their similar chemical properties.[28−30] Also, there are some successful applications to crude oil classification and oil–source correlation in Tarim Basin and Anadarko Basin.[31,32] However, data on the concentration and distribution of REEs in crude oil are rare in Ordos Basin, and few studies compare the application effects between REEs and biomarkers in oil–oil correlation and/or oil–source correlation. Hence, in view of the deficiencies in previous studies and the difficulties in the exploration and exploitation of tight oil, the main purpose of this study is to analyze biomarker and REE compositions of Chang 7 tight oil in the Longdong area, using traditional biomarker ratios and REE compositions to carry out the crude oil group classification, to compare the results and ultimately carry out the oil–source correlation analysis.

Geological Settings

Tectonics and Structure

Ordos Basin, formed in the west of North China Craton, is the second largest sedimentary basin in China. Ordos Basin developed on the Paleozoic North China Craton with Paleoproterozoic crystalline basement in the Mesozoic and Cenozoic.[33] From Paleozoic to Mesozoic, the Ordos Basin experienced evolution from the Cambrian-Early Ordovician craton basin with a divergence margin to the Middle Ordovician-Middle Triassic craton basin with a convergence margin and then to the Late Triassic–Early Cretaceous intraplate residual craton basin.[33] Among them, it was a huge interior freshwater lacustrine basin in the Late Triassic (Figure a).[33] The basin can be divided into six tectonic units: the Jinxi flexure belt in the east, the Yi-meng uplift in the north, the Tian-Huan depression and Western thrust belt in the west, the Yi-Shan slope in the middle and the Weibei uplift in the south (Figure b). Among them, the Yi-Shan slope gently westward with a dip angle of 1°, is stable in structure, and is the main petroleum production area in Ordos Basin.[33] The Longdong area is mainly located in the south-western part of the Yi-Shan slope and spans part of the Tian-Huan depression (Figure b,c).

Figure 1

(a) Location of the Ordos Basin in China. (b) Structural divisions of the Ordos Basin. (c) Geological and geographic information of the study area.

Lithostratigraphy

The sedimentary facies of Ordos Basin experienced a transition from marine-continental to continental facies in Late Triassic, which was mainly a lacustrine environment at that period.[34] Yinshan in the north and Qinling orogenic belt in the south are the main sediment source supply areas in the southwest of the basin and gradually formed Yanchang Formation, which mainly consists of fluvial–lacustrine–deltaic deposits, including sandstone, siltstone, mudstone, shale, and tuff intercalation.[35] The Yanchang Formation, which can be further separated into 10 sections (Chang 1–10 from top to bottom) just experienced an integral lacustrine basin evolution process: the formation and development period (Chang 10 to Chang 8), the peak period (Chang 7 to Chang 4 + 5), and the extinction period (Chang 3 to Chang 1) (Figure ).[35,36] Among them, Chang 7 section is the largest flooding deposit. Organic-rich dark mudstone and oil shale are developed over a large area on the plane and overlapped with a delta front or gravity flow sand body to form a favorable lithologic trap (Figure ).[37−39] Chang 7 section can be further divided into three sub-sections from top to bottom, namely, Chang 71, Chang 72, and Chang 73 sub-sections, respectively. Oil shale is mainly developed at the bottom of Chang 73, while mudstone is mainly overlying shale, which is located from Chang 71 to Chang 73 (Figure ). Dark mudstone and oil shale are both formed in deep and semi-deep lacustrine environments. Mudstone is thick, homogeneous, massive, with partly developed horizontal lamination, and the particle diameter is generally less than 4 μm.[2,12] It is gray-black to black due to its rich aromatic organic matter.[12] Oil shale is black to brown-black flakes with horizontal lamination and a smaller grain size than mudstone.[12] Mudstone contains more sandy components than oil shale, approximately 5–20% in mudstone, while in oil shale it is generally less than 5%; the quartz content is also higher in mudstone than that in oil shale (on average, at 21.5 and 12.5%, respectively), while oil shale has more clay mineral content than mudstone (on average, at 52.1 and 43.3%, respectively).[40] In addition, the pyrite content of oil shale is 3 times more than that of mudstone.[40]

Figure 2

Lithologic profile and sedimentary facies of Yanchang Formation of Upper Triassic in the Ordos Basin.

Characteristics of Chang 7 Source Rock

Part of the hydrocarbon generation center of Chang 7 section is located in the Longdong area, with the source rock thickness of 10–40 m (Figure b,c). The organic matter type of Chang 7 source rock is dominated by lower aquatic organisms, with an average TOC of 13.75%, and the kerogen is mainly of type I, II1, and II2 based on the classification of Peters and Cassa, 1994.[14,15,40,41] Kerogen accounts for a high proportion of 15–35% approximately in the source rocks.[3] Specifically, oil shale is dominated by type I kerogen, while mudstone is mainly type II1 and II2 kerogen.[40] The average TOC of oil shale is 18.5%, which is 5 times more than that of mudstone.[40] This reveals that Chang 7 oil shale has better hydrocarbon generation potential than mudstone. Biomarker data demonstrate that the organic matter in oil shale has more alga and other aquatic micro-organism input than that of mudstone, and the reducing level of oil shale sedimentary environment is higher than that of mudstone.[14] This is supported by trace element evidence that the paleoenvironment of oil shale is anoxic, while that of mudstone is sub-oxic.[19,20] Also, the relative salinity of the mudstone deposit water body is slightly higher than that of shale, and the depth is deeper as well.[40]

Results

Physical Properties of Crude Oil

By summarizing the 87 physical property data of crude oil samples from the Changqing Oilfield Company, it is concluded that for Chang 7 crude oil in Longdong area, the average ground density is 0.838 g/cm3, the average viscosity is 4.26 mPa s, the gel point averages at 16.4 6C, the gas/oil ratio averages at 118.0 m3/t, and the average formation volume coefficient is 1.261 (Changqing Oilfield Company). This reveals that Chang 7 tight oil is characterized by low density, low viscosity, and low gel point, with relatively strong fluidity. The group components of 10 Chang 7 crude oil samples are listed in Table . It can be seen that the contents of saturated hydrocarbon, aromatic hydrocarbon, resins, and asphaltene are in the range 72.45–85.58, 9.72–15.41, 3.45–9.76, and 0.32–2.38%, with an average of 79.48, 13.44, 6.25, and 0.83%, respectively (Table ). Resins and asphaltene account for less than 10% in crude oil samples, respectively (Table ). The saturated/aromatic hydrocarbon ratio is 4.70–8.80, with an average of 5.34 (Table ). Saturated hydrocarbon accounts for the highest proportion in crude oil, showing the typical group composition characteristics of mature oils.

Table 1

Group Component of Chang 7 Crude Oil Samples

			group components
sample	formation	depth (m)	saturates (%)	aromatics (%)	resins (%)	asphaltenes (%)	Sat./Aro.
B246	Chang 71	2468.0	72.45	15.41	9.76	2.38	4.70
H56	Chang 71	2367.5	85.58	9.72	3.45	1.25	8.80
H69	Chang 71	2384.0	78.02	13.81	7.13	1.04	5.65
N50	Chang 71	1251.0	78.76	13.74	5.67	1.83	5.73
W67	Chang 72	2083.1	81.46	12.73	4.98	0.83	6.4
Z45	Chang 72	1981.6	81.44	11.28	5.61	1.67	7.22
L36	Chang 72	2439.5	77.21	13.98	7.69	1.12	5.52
L87	Chang 73	2290.3	81.24	13.24	5.2	0.32	6.14
N44	Chang 73	1503.5	75.24	14.82	7.8	2.14	5.08
N45	Chang 73	1664.5	80.09	11.67	6.42	1.82	6.86

Biomarker Compositions

The mass chromatograms of m/z 85, m/z 191, and m/z 217 were used to determine the characteristics of n-alkanes, isoprenoid alkanes, terpenoids, and steroids in saturated hydrocarbons of Chang 7 crude oil. The distribution and characteristics of polycyclic aromatic hydrocarbons were identified from m/z 178, m/z 192, m/z 168, m/z 166, and m/z 184 mass chromatograms. The related biomarker parameters of saturated and aromatic hydrocarbons were calculated from the ratio of the relevant peak area.

n-Alkanes and Isoprenoids

Figure illustrates the m/z 85 mass chromatograms of four representative Chang 7 crude oil samples, most of which have a bimodal distribution. The carbon number of all the samples is in the range of C10–C33, with the main peak carbon number of C15–C19 (Table ). The carbon preference index (CPI) and odd–even predominance (OEP) are generally low, ranging 1.13–1.24 and 1.21–1.33, averaging at 1.17 and 1.28, respectively (Table ). ∑nC21–/∑nC21+ and (C21 + C22)/(C28 + C29) ratios are relatively high, which are 1.69–3.16 and 2.68–3.96, and averaging at 2.30 and 3.22, respectively, revealing the absolute advantage of short chain n-alkanes (Table ). There is no significant difference between the content of pristane and phytane in crude oil; the Pr/Ph ratios range from 0.77 to 1.26 with an average of 1.03 (Table ). Pr/nC17 and Ph/nC18 ratios of crude oil samples are relatively low with value variations of 0.24–0.53 and 0.23–0.71, respectively (Table ).

Figure 3

m/z 85, m/z 191, and m/z 217 mass chromatograms of selective crude oil samples.

Table 2

Molecular Composition and Related Parameters of Chang 7 Crude Oil Samplesa

	saturated biomarker distribution
	m/z 85 (n-alkanes and isoprenoids)									m/z 191 (terpanes)				m/z 217 (steranes)							aromatic biomarker distribution
	Cmain	Crange	CPI	OEP	A	B	C	D	E	F	GI	H	I	J	K	L	M	regular steranes (%)			DBT (%)	DBF (%)	Flu (%)	MPI	Rc (%)
sample																		C27	C28	C29
B246	nC19	C12–C31	1.13	1.33	2.05	2.77	1.19	0.27	0.23	9.53	0.04	0.54	1.00	0.46	0.59	6.05	1.26	0.46	0.25	0.29	0.22	0.24	0.53	1.20	1.12
H56	nC16	C12–C32	1.20	1.26	1.78	2.80	1.03	0.42	0.42	0.29	0.06	0.56	0.51	0.50	0.57	0.26	0.62	0.47	0.26	0.26	0.19	0.53	0.28	0.65	0.79
H69	nC15	C11–C32	1.24	1.22	1.69	2.68	1.09	0.53	0.51	0.26	0.06	0.57	0.58	0.48	0.55	0.22	0.55	0.50	0.24	0.26	0.17	0.56	0.27	0.64	0.78
N50	nC17	C14–C33	1.14	1.31	2.30	2.96	1.03	0.31	0.31	7.98	0.05	1.00	0.87	0.46	0.59	2.62	1.52	0.47	0.24	0.29	0.32	0.27	0.41	1.00	1.00
W67	nC16	C12–C29	1.14	1.30	2.38	3.16	1.02	0.36	0.37	0.89	0.09	0.50	0.64	0.47	0.60	0.54	0.92	0.50	0.24	0.27	0.32	0.30	0.38	0.80	0.88
Z45	nC19	C10–C32	1.15	1.29	3.16	3.96	1.26	0.28	0.24	10.70	0.02	0.57	0.91	0.44	0.58	3.39	2.06	0.42	0.25	0.32	0.24	0.40	0.36	0.69	0.81
L36	nC17	C14–C32	1.13	1.32	2.32	2.84	1.09	0.24	0.23	9.13	0.06	1.00	0.84	0.46	0.58	3.00	3.07	0.48	0.25	0.27	0.27	0.28	0.45	1.02	1.01
L87	nC17	C13–C32	1.17	1.27	2.86	3.82	0.92	0.35	0.42	1.62	0.08	0.48	0.68	0.48	0.60	0.72	1.08	0.47	0.24	0.29	0.26	0.36	0.38	0.76	0.86
N44	nC16	C15–C31	1.17	1.27	2.07	3.93	0.88	0.36	0.38	1.58	0.16	0.43	0.75	0.49	0.61	1.03	0.61	0.49	0.24	0.27	0.27	0.32	0.41	0.81	0.89
N45	nC18	C12–C32	1.21	1.21	2.38	3.27	0.77	0.51	0.71	2.63	0.21	0.43	0.58	0.47	0.60	1.30	0.81	0.46	0.26	0.28	0.28	0.30	0.43	0.88	0.93

Cmain: main peak carbon number; Crange: carbon number range; CPI: carbon preference index = 2[C23 + C25 + C27 + C29]/[C22 + 2(C24 + C26 + C28) + C30]; OEP: odd–even predominance = [(C + 6C + C)/(4C + 4C)](−1), i = C24–C34; A: ∑nC21–/∑nC22+; B: (C21 + C22)/(C28 + C29); C: Pr/Ph; D: Pr/nC17, E: Ph/nC18, F: ∑tricyclic terpenes/∑hopanes; GI: gammacerane index = gammacerane/C30 hopane; H: C31 hopane 22S/(22S + 22R); I: Ts/(Ts + Tm); J: C29 sterane 20S/20S + 20R; K: C29 sterane ββ/αα + ββ; L: ∑regular steranes/∑17(α)H-hopane; M: (pregnane + homopregnane)/C29 regular sterane; DBT: dibenzothiophenes = DBT/(DBT + DBF + Flu); DBF: dibenzofuranes = DBF/(DBT + DBF + Flu); Flu: fluorenes = Flu/(DBT + DBF + F); MPI: methylphenanthrene index = 1.5 × [(2 – MP) + (3 – MP)]/[phenanthrene + (1 – MP) + (9 – MP)], where MP-methylphenanthrene; Rc = 0.6 × MPI + 0.4. Pr: pristane; Ph: phytane; Ts: C27 18(α)H-trisnornehopane; Tm: C27 17(α)H-trisnorhopane.

Terpenoids

Based on the m/z 191 mass chromatogram of the saturated hydrocarbon (Figure ), it can be found that terpane biomarkers such as gammacerane, Ts (C27 18α(H)-trisnomehopan), Tm (C27 17α(H)-trisnorhopane), and C30-hopane are relatively abundant, and their relationship is pentacyclic terpane > tricyclic terpane > tetracyclic terpane. The hopane series compounds of pentacyclic terpane are characterized by relatively high contents, mainly distributed between C27 and C35, with C30-hopane as the main peak (Figure ). C31–C35 hopanes are relatively low in abundance and decrease in order (Figure ). The ∑tricyclic terpene/∑hopane ratios of all crude oil samples vary significantly, most of which are greater than 1, ranging from 0.26 to 10.70, with an average of 4.46 (Table ). The content of Ts is absolutely higher than that of Tm, with Ts/(Ts + Tm) ratios ranging from 0.51 to 1.00 and averaging at 0.74 (Table ). Meanwhile, the gammacerane/C30 hopane ratios are pretty low at 0.02–0.21, with a mean value of 0.08, demonstrating the relatively low concentration of gammacerane (Table ). C31 homohopane is dominant in the homohopane distribution, which C31 hopane 22S/(22S + 22R) ratios are in the range of 0.43–1.00, with a mean of 0.61 (Table ).

Steroids

Pregnane, homopregnane, C27–C29 regular steranes, and diasterane were detected by the m/z 217 mass chromatogram of saturated hydrocarbon in crude oil samples (Figure ). For regular steranes, the content of C27 sterane is absolutely greater than those of C28 sterane and C29 sterane, while C29 sterane is slightly greater than C28 sterane in relative content. The specific relative content relationship is C27(0.42–0.50%) > C29(0.26–0.32%) > C28(0.24–0.26%) (Figure and Table ). The C27, C28, and C29 regular steranes are generally distributed in V-shape on the m/z 217 mass chromatogram (Figure ). The regular steranes are pretty discrepancy from hopanes in abundance, which lead to the significant variation on ∑regular steranes/∑17(α)H-hopane ratios of 0.22–6.05, with an average of 1.91 (Table ). The C29 sterane 20S/20S + 20R and C29 sterane ββ/αα + ββ ratios are generally high, which range from 0.44–0.50 and 0.55–0.61, with mean values of 0.47 and 0.59, respectively (Table ). The (pregnane + homopregnane)/C29 regular sterane ratios are also calculated to be slightly high at 0.55–3.07 (Table ).

Polycyclic Aromatic Hydrocarbons

The aromatic compounds of phenanthrene (Phen) series, fluorenes (Flu), dibenzothiophenes (DBT), and dibenzofuranes (DBF) were detected by the combination of the total ion chromatogram (TIC) and m/z 178, m/z 192, m/z 168, m/z 166, and m/z 184 mass chromatograms of aromatic hydrocarbon in crude oil (Figure ). Phen series are high in abundance relative to Flu, DBT, and DBF in the distribution of aromatic compounds (Figure ). Because of the extensive application in identifying the depositional environment, the relative contents of Flu, DBT, and DBF are calculated;[42] the relative content of Flu (0.26–0.52%) is the highest, followed by DBF (0.24–0.53%) which is slightly lower, and then DBT (0.18–0.30%) which is the lowest (Table ). As the most commonly used maturity parameter of phenanthrene compounds, methylphenanthrene index (MPI) of crude oil is also calculated as 0.64–1.20 (Table ).[43] The Rc (calculated vitrinite reflectance) calculated by MPI is between 0.78 to 1.12%,[43] averaging at 0.91% (Table ).

Figure 4

TIC and m/z 178, m/z 192, m/z 168, m/z 166, and m/z 184 aromatic hydrocarbon mass chromatograms of W67 crude oil samples.

REE Compositions

REE determination results of crude oil samples are listed in Table (the chondrite data are from Sun and McDonough, 1989).[44] The ∑REE (total content of REE) values in crude oil exhibit a wide variation and range from 42.02 to 684.66 ppb, with a mean value of 209.93 ppb (Table ). The sum content of light REEs (LREEs of La to Eu) is higher than that of heavy REE (HREEs of Gd to Lu) with the LREE/HREE ratios ranging from 6.25 to 15.35 and averaging at 10.11 (Table ). Both LREEs and HREEs are characterized by relatively strong fractionation, with the (La/Yb)CN values between 5.95 and 15.45, with an average of 9.60 (Table ). Whereas the higher (La/Sm)CN values (ranging 3.50–6.59 and averaging at 5.14) than the (Gd/Yb)CN values (ranging 0.82–1.57 and averaging at 1.18) indicate that LREEs are more fractionated than HREEs (Table ). The δEu and δCe values of crude oil are in the range 0.39–1.33 and 0.90–1.46, with an average of 0.79 and 1.12, respectively, demonstrating slightly negative Eu anomalies without an obvious Ce anomaly (Table ). All REE distribution patterns of crude oil normalized by chondrite data display a right deviation curve with relatively high content of LREE (the chondrite data are from Sun and McDonough, 1989) (Figure a–c).[44] According to the distribution pattern of each sample, all crude oil samples can be further divided into three categories, most of which belong to the first group, with the features of slightly negative Eu anomalies, similar to the chondrite-normalized REE distribution of the upper continental crust (UCC) (data from Taylor and McLennan, 1985) (Figure a,d).[45] There are two Chang 7 crude oil samples in the second group, that is, L140 and Z71, showing slightly positive Eu anomalies, which is consistent with the chondrite-normalized REE distribution of the lower continental crust (LCC) (data from Taylor and McLennan, 1985) (Figure b,d).[45] Only one Chang 7 crude oil sample of Z182 belongs to the last group, the curve of which is relatively smooth without an obvious Eu anomaly (Figure c). This discrepancy may be due to the fact that the first type crude oil is mainly affected by the interaction of the fluids and materials derived from UCC in the migration process, which is also the normal formation process of typical sedimentary rocks. The second type is chiefly mixed by materials from the LCC, while the last type may be in-between.

Table 3

REE Contents (ppb) and Related Parameters of Chang 7 and Chang 8 Crude Oil Samplesa

sample	Z120	B457	L169	Z71	Z52	L140	Z87	X255	Z24	L16	Z233	X237	Z182	X133	Z172	L91
formation	Ch 71	Ch 71	Ch 71	Ch 71	Ch 71	Ch 72	Ch 72	Ch 72	Ch 72	Ch 72	Ch 72	Ch 73	Ch 73	Ch 73	Ch 8	Ch 8
depth (m)	1715.20	1988.20	2351.30	1852.30	1826.10	2114.30	2004.20	1910.40	1924.60	1879.20	1774.60	2017.54	1952.80	2079.2	1842.3	2402.3	ave
La	32.71	25.33	17.99	9.86	29.56	23.79	17.54	33.50	9.35	26.58	34.06	59.21	122.92	140.33	10.84	173.23	47.92
Ce	60.43	52.94	33.82	24.46	56.73	52.15	38.66	61.71	17.11	54.50	55.36	144.24	292.85	279.16	22.68	277.26	95.25
Pr	7.23	4.88	3.18	2.37	5.94	5.58	2.95	6.56	1.91	5.14	6.64	11.68	25.49	25.26	2.4	32.46	9.36
Nd	24.66	15.86	10.34	8.59	19.90	20.54	10.27	21.88	6.64	15.64	22.19	45.75	86.04	80.99	8.01	110.99	31.77
Sm	4.97	3.10	1.76	1.82	4.20	3.15	1.91	3.83	1.37	3.08	3.98	7.09	17.79	15.02	1.37	21.51	6.00
Eu	1.17	0.63	0.37	0.68	1.04	1.13	0.41	1.02	0.35	0.53	0.90	1.56	5.12	2.39	0.15	5.71	1.45
Gd	4.37	2.60	1.63	1.35	3.88	2.67	1.56	3.56	1.29	2.40	3.91	6.12	14.22	12.13	0.96	19.06	5.11
Tb	0.72	0.49	0.28	0.23	0.66	0.50	0.28	0.62	0.21	0.42	0.64	1.01	2.26	2.12	0.14	2.77	0.83
Dy	3.86	2.26	1.54	1.14	3.56	1.98	1.46	3.13	1.26	2.63	4.13	6.57	12.97	12.18	0.71	15.03	4.65
Ho	0.78	0.42	0.33	0.27	0.81	0.46	0.31	0.68	0.26	0.57	0.80	1.07	3.19	2.48	0.15	3.39	1.00
Er	2.17	1.34	1.00	0.73	2.19	1.44	0.99	1.90	0.81	1.84	2.66	3.69	8.21	8.02	0.38	9.48	2.93
Tm	0.42	0.25	0.20	0.15	0.46	0.28	0.18	0.36	0.17	0.37	0.50	0.64	1.56	1.67	0.07	1.71	0.56
Yb	2.54	1.58	1.33	1.08	2.73	1.59	1.28	2.17	1.13	2.41	3.30	4.01	9.48	11.45	0.5	10.61	3.57
Lu	0.36	0.24	0.18	0.17	0.39	0.22	0.17	0.36	0.16	0.36	0.52	0.58	1.49	1.72	0.06	1.46	0.53
∑REE	146.37	111.92	73.95	57.26	132.04	115.48	77.96	141.30	42.02	116.47	119.39	293.2	603.59	594.92	48.4	684.66	209.93
L/HREE	8.62	11.20	10.39	10.20	8.00	11.64	11.53	10.05	6.95	9.58	6.25	11.39	10.31	10.49	15.35	9.78	10.11
(La/Yb)CN	9.25	11.49	9.72	6.56	7.76	10.72	9.83	11.05	5.95	7.91	7.41	10.6	9.3	8.79	15.45	11.71	9.60
(La/Sm)CN	4.25	5.27	6.59	3.50	4.54	4.88	5.95	5.65	4.39	5.58	5.52	5.39	4.46	6.03	5.1	5.20	5.14
(Gd/Yb)CN	1.43	1.36	1.02	1.04	1.18	1.39	1.00	1.36	0.94	0.82	0.98	1.26	1.24	0.88	1.57	1.49	1.18
δEu	0.77	0.68	0.66	1.33	0.78	1.20	0.73	0.85	0.80	0.59	0.69	0.72	0.98	0.54	0.39	0.86	0.79
δCe	0.96	1.17	1.10	1.46	1.05	1.11	1.32	1.02	0.99	1.14	0.90	1.34	1.28	1.15	1.09	0.91	1.12

Ch-Chang; δEu = EuCN/(SmCN × GdCN)1/2; δCe = CeCN/(LaCN × PrCN)1/2; CN stands for chondrite-normalized values.

Figure 5

(a–c) Chondrite-normalized plots of REEs in Chang 7 and Chang 8 crude oil samples from Longdong area in the Ordos Basin; (d) chondrite-normalized plots of REEs of the upper and lower crust; (e) chondrite-normalized plots of REEs of Chang 7 oil shale in the Ordos Basin; and (f) chondrite-normalized plots of REEs of Chang 7 mudstone in the Ordos Basin.

Discussion

Thermal Maturity of Crude Oil

The maturity of crude oil is of great significance to the inversion and understanding of the thermal history, the fluidity of crude oil in the reservoir, and the oil–source correlation analysis. In this study, a series of relative biomarker parameters including C29 sterane 20S/20S + 20R, C29 sterane ββ/αα + ββ, OEP, CPI, C31 hopane 22S/(22S + 22R), MPI, and Ts/Tm were used to evaluate the maturity of Chang 7 crude oil samples.

In the cross-plot of C29 sterane ββ/αα + ββ and C29 sterane 20S/20S + 20R, all data points fall in the area of mature (the identification map is from Li et al., 2017) (Figure a),[15] that is, the C29 sterane ββ/αα + ββ and C29 sterane 20S/20S + 20R ratios of all samples are greater than 0.4, which is roughly equivalent to the Ro (vitrinite reflectance) of oil equal to 0.8%,[46] indicating that all crude oil samples are mature. The cross-plot of OEP and CPI continue to exhibit this feature, in which the OEP (1.21–1.33) and CPI (1.13–1.24) of crude oil samples are both less than 1.5 (the identification map is from Li et al., 2017) (Figure b) (Table ).[15] C31 hopane 22S/(22S + 22R) ratios (0.43–1.00) of crude oil samples are consistent with the C29 sterane maturity parameters mentioned above (Table ), which have reached the isomerization equilibrium, revealing that crude oils are already mature.[47] In addition, the difference in thermal stability between Ts and Tm makes them suitable maturity parameters.[48] The Ts/(Ts + Tm) ratio of crude oil samples is greater than 0.5 (0.51–1.00) (Table ), reflecting a higher maturity condition.[48] As the most commonly used maturity parameter of phenanthrene compounds,[8] MPI is in high correlation with Ro.[43,49] The Rc (calculated vitrinite reflectance) of crude oil samples (0.78–1.12%) calculated by MPI is in relatively good agreement with the oil maturity reflected by C29 sterane (Table ). On performing the analysis of the above biomarker maturity parameters, Chang 7 crude oils in Longdong area are found to be already mature. This feature is just consistent with the maturity of Chang 7 source rocks proposed by previous research.[14,50]

Figure 6

Discrimination diagrams of maturity level by biomarker parameters of Chang 7 crude oil samples. Cross-plots of (a) C29 sterane ββ/(αα + ββ) vs C29 sterane 20S/20S + 20R and (b) OEP vs CPI.

Origin and Forming Environment of Crude Oil

The source and forming environment of organic matter in crude oil are of great significance to trace the formation process and conditions of crude oil and are also critical evidence in the oil–source correlation analysis, especially for the refined correlation of mixed oil sources.[8,10] In this study, the source of organic matter in crude oil and the redox condition of the forming environment were evaluated using both biomarkers and trace elements, specifically including the distribution characteristics of n-alkanes and aromatics and several related biomarker parameters, along with V/Ni and Ni/Co ratios.[21,25]

Organic Matter Source of Crude Oil Based on Biomarkers

Before the interpretation of biomarker parameters, it is necessary to determine the degree of biodegradation, which will lead to changes in the structure of biomarker compounds and thus affect their effectiveness.[51] The relatively complete n-alkane sequence (C10–C33) and the high Sat/Aro ratio (>4.70) of all crude oil samples, as well as the m/z 85 mass chromatograms of all samples without an obvious unresolved complex mixture, all indicate the low level or no biodegradation of crude oils and the validity of biomarker parameters (Tables and 2 and Figure ).[51,52] The Cmain of crude oil samples (mainly C15–C19) demonstrates that the organic matter is derived from plankton and/or algae (Table and Figure ).[53] Also, the slightly odd carbon advantage (OEP > 1.21) and the absolute short-chain n-alkane advantage (∑nC21–/∑nC22+ > 1.69, (C21 + C22)/(C28 + C29) > 2.68) further proved that the organic matter is mainly of lower aquatic organisms such as algae and micro-organisms (Table ).[54]

The relative content of regular sterane is widely used to identify the source of organic matter.[8,10,14] It is generally believed that C27 and C28 steranes are mainly from algae and other lower aquatic organisms, while C29 steranes are derived from higher plants or algae.[48,52] According to the ternary diagram of the relative contents of C27, C28, and C29 sterane, the data points of crude oil fall in the area of mixed sources (except for one data point at the junction of phytoplankton dominated and mixed sources) (the identification map is from Li et al., 2017; the data of Chang 7 oil shale and mudstone are from Xu et al., 2019) (Figure a).[14,15] Combined with the distribution pattern of m/z 217 (Figure ), it demonstrates that the phytoplankton mixed with algae is the main source input. Similarly, the cross-plots of Pr/nC17 versus Ph/nC18 and C27/C29 regular sterane versus Pr/Ph also reveal this conclusion (the identification maps and the data of Chang 7 oil shale and mudstone are from Xu et al., 2019) (Figure b,c).[14] As an important component of hopane series compounds, tricyclic terpane mainly comes from bacteria, algae, and other lower organisms, and the abundant tricyclic terpanes reflect the input of lower organisms.[55] The ∑tricyclic terpene/∑hopane ratios of crude oil samples are mostly more than 1, indicating the contribution of bacteria and algae in organic matter (Table ). Because the regular sterane is mainly derived from algae or higher plants while the hopane comes from bacteria, the ∑regular sterane/∑17(α)H-hopane ratio can be used to indicate the proportion of different sources.[16] The ∑regular sterane/17(α)H-hopane ratios of crude oils (0.22–6.05) show the same features as mentioned before (Table ), that is, the organic matter of crude oils is mainly derived from algae, with some contribution of bacteria. This understanding can be compared with previous research conclusions that the organic matter of Chang 7 oil shale and mudstone originated from algae and aquatic micro-organisms, with some contribution of higher plants.[14,15]

Figure 7

Ternary diagram and scatter plots of biomarker parameters to determine the origin of organic matter in crude oil and the redox conditions of the formation environment. (a) Ternary diagrams of C27, C28, and C29 regular sterane compositions in Chang 7 crude oil, oil shale, and mudstone, showing the origin of organic matter; (b) cross-plots of Pr/nC17 vs Ph/nC18, (c) C27/C29 regular sterane vs Pr/Ph, and (d) DBF/F + DBF vs DBT/F + DBT of Chang 7 crude oil, oil shale, and mudstone, showing the organic matter source and the forming environment.

Redox Conditions of Crude Oil Forming Environment Based on Biomarkers

Several biomarker parameters were also used to evaluate the redox conditions of Chang 7 crude oil formation environment. As a commonly used depositional redox condition indicator, it is generally considered that the Pr/Ph ratio greater than 1 represents the oxic environment, while the less than 1 ratio reflects the anoxic conditions or hypersaline depositional environment.[56,57] The average Pr/Ph ratio of Chang 7 crude oil in the Longdong area is 1.03 (Table ), which displays the transitional environment characteristic of sub-reducing to sub-oxidizing. Further evidence is shown in the cross-plots of Pr/nC17–Ph/nC18 and C27/C29 regular sterane-Pr/Ph (Figure b,c), in which the data points of crude oil fall in the transition environment of sub-oxidizing to sub-reducing.[48,58] In addition, the relative abundance of Flu, DBT, and DBF in aromatic compounds is the common indicator to determine the depositional environment of organic matter. These compounds may come from the same source, while Flu may be replaced by sulfur to DBT in an anoxic environment and oxidized to DBF in sub-oxidizing to oxidation conditions.[42] The cross-plot of DBT/(F + DBT) versus DBF/(F + DBF) shows the transitional environment feature with all data points located near the line of sub-oxidizing to sub-reducing (the identification map is from Li and He, 2008) (Figure d).[42] Gammacerane can be used to distinguish the water salinity. The salinity and reducibility of water increased with increasing content of gammacerane.[48] The gammacerane/C30 hopane ratio, also known as the gammacerane index (GI), reflects the relative content of gammacerane.[59] The average gammacerane/C30 hopane ratio of Chang 7 crude oil is 0.08 (Table ), exhibiting the fresh to sub-saline water depositional environment, which is kind of equal to the oxic to dysoxic conditions. The (pregnane + homopregnane)/C29 sterane ratios are between 0.55 and 3.07, with an average of 1.25 (Table ), while pregnane and homopregnane are considered to come from algae or bacteria in a hypersaline environment.[57] This feature indicates the fresh to brackish water of the depositional condition and is a further proof of the input of algae and bacteria in organic matter. Thus, according to the biomarker evidence, the overall formation environment of Chang 7 crude oil is the transitional condition of sub-oxidizing to sub-reducing.

Redox Conditions of Crude Oil Forming Environment Based on V/Ni and Ni/Co Ratios

The ratios between some trace elements are extensively used as an indicator for the depositional environment of source rocks,[60] among which are some important bio-indicator elements such as V, Ni, and Co; though the concentration of these elements in crude oil will be influenced by the biodegradation, thermal degradation, and migration process in reservoirs.[25] It has been confirmed that the V/Ni and Ni/Co ratios in crude oil incline to be constant, which makes them the most convincing parameters for speculating the redox conditions of the crude oil forming environment and for conducting oil–oil or oil–source correlation analysis.[24,26,27] The V/(V + Ni) ratio greater than 0.5 and less than 0.5 indicates that crude oil is formed in anoxic and oxic conditions, respectively.[24] While the Ni/Co ratio greater than 7.0, between 5.0 and 7.0, and less than 5.0 represents the anoxic, dysoxic, and oxic environment, respectively.[61] V/(V + Ni) ratios of all crude oil samples ranged from 0.07 to 0.80, with a mean of 0.31, displaying a slight oxic condition (Table ). Ni/Co ratios range from 1.23 to 16.58, averaging at 5.58, showing a dysoxic tendency (Table ). Yet, specifically, all crude oil samples can be obviously classified into two groups through V/(V + Ni) and Ni/Co ratios. The first group includes all Chang 71 and Chang 72 samples, exhibiting that V/(V + Ni) and Ni/Co ratios are all less than 0.5 and 7.0, respectively (Table ). While the second group consists of all Chang 73 and Chang 8 crude oil samples, their V/(V + Ni) and Ni/Co ratios are greater than 0.5 (except for one sample of X237) and 7.0, respectively (Table ). The diversity between the two groups of samples reflects their respective different redox conditions of the formation environment, that is, Chang 71 and Chang 72 samples formed under slight oxic conditions, while Chang 73 and Chang 8 samples were from the anoxic environment. This further reveals the internal homology of crude oil samples in each group and different sources between two groups.

Table 4

V, Ni, and Co Contents (ppb) along with the Related Ratios of Chang 7 and Chang 8 Crude Oil Samples

sample	formation	depth (m)	V	Co	Ni	V/(V + Ni)	Ni/Co
Z120	Chang 71	1715.20	120.79	293.24	838.65	0.13	2.86
B457	Chang 71	1988.20	137.49	355.81	778.28	0.15	2.19
L169	Chang 71	2351.30	70.13	150.34	357.93	0.16	2.38
Z71	Chang 71	1852.30	60.90	168.24	794.93	0.07	4.72
Z52	Chang 71	1826.10	220.67	294.15	361.39	0.38	1.23
L140	Chang 72	2114.30	28.85	61.58	300.52	0.09	4.88
Z87	Chang 72	2004.20	130.01	156.05	409.67	0.24	2.63
X255	Chang 72	1910.40	106.98	95.88	249.41	0.30	2.60
Z24	Chang 72	1924.60	77.31	116.27	380.35	0.17	3.27
L16	Chang 72	1879.20	158.45	293.25	1575.75	0.09	5.37
Z233	Chang 72	1774.60	82.83	183.24	882.99	0.09	4.82
X237	Chang 73	2017.54	1072.26	172.24	1292.52	0.45	7.50
Z182	Chang 73	1952.8	135.25	9.51	82.54	0.62	8.68
X133	Chang 73	2079.2	105.24	7.61	72.64	0.59	9.55
Z172	Chang 8	1842.3	29.81	0.44	7.26	0.80	16.58
L91	Chang 8	2402.30	109.95	6.57	65.89	0.63	10.03
average			165.43	147.78	528.17	0.31	5.58

Oil–Source Rock Correlation Analysis

It is generally accepted that the Chang 7 section is the thickest and most geographically extensive source rock in Yanchang Formation, which supply hydrocarbons to the adjacent reservoir of top and bottom.[8,10,16] Despite being rarely mentioned in previous research works, the Chang 7 crude oil should come from the Chang 7 source rock theoretically. However, there is no literature that refers to the respective contribution and lateral range of Chang 7 mudstone and oil shale to Chang 7 crude oil. Through the distribution pattern of REE, it can be seen that most of the crude oil samples have comparability with that of Chang 7 oil shale and mudstone, which indicates the same source attribute (Chang 7 oil shale data are from Qiu et al., 2015,[19] while Chang 7 mudstone data are from Qiu et al., 2015[20]) (Figure a,e,f). This feature also emerged in the identification maps of organic matter origin and forming environment redox conditions in crude oil, in particular, the data points of Chang 7 crude oil coincide with those of Chang 7 oil shale and mudstone (Figure a–c). The above evidence can directly prove that Chang 7 crude oil comes from Chang 7 mudstone and oil shale, but such relatively traditional qualitative comparison of the REE distribution pattern and the single parameter chart coincidence cannot meet the refined oil–source correlation. The data of Chang 7 source rock in the existing literature may cause unexpected errors in the oil−source correlation analysis.[14,19,20] Only data of crude oil samples in this study are used for refined oil–source correlation analysis. Meanwhile, based on the generally accepted viewpoint that the most remarkable difference between Chang 7 oil shale and mudstone is the depositional environment redox condition, of which Chang 7 oil shale is anoxic, while mudstone is sub-oxic.[9,14,18−20,40] We carry out an oil group classification using biomarker parameters and REE of crude oil samples and further discuss the source rock corresponding to each oil group.

Using Biomarker Parameters

Only the most sensitive biomarker parameters (Pr/Ph ratios, C27–29 regular steranes, and GI values) to the origin of organic matter and redox conditions were selected as the partition variables for the oil group classification. Hierarchical cluster analysis (HCA) using SPSS 19.0 statistical software is the most suitable method for considering the number of variables and samples. According to the dendrogram of HCA analysis results shown in Figure , all samples were divided into two oil families of group I and group II. Group I includes all Chang 71 and Chang 72 crude oil samples with Pr/Ph ratios >1 and GI values <0.09 (Table ), representing the crude oil formed in the slightly oxic with fresh to brackish water environment, which is consistent with the depositional environment of Chang 7 mudstone. Group II consists of three Chang 73 samples, displaying Pr/Ph ratios <1 and GI values >0.08. This reflects that the samples in this group were formed in the anoxic with slightly brackish water conditions, in which Chang 73 crude oil has stronger reducibility and is just similar to that of Chang 7 oil shale. According to the above analysis, the crude oil samples of group I are mainly from Chang 7 mudstone, while group II is principally from Chang 7 oil shale. Specifically, Chang 71 and Chang 72 crude oil come from Chang 7 mudstone, while Chang 73 crude oil originated from Chang 7 oil shale entirely.

Figure 8

Dendrogram result of HCA using biomarker parameters of crude oil samples, showing oil group classification.

Using REEs

The theoretical basis of the oil group classification by REEs is that the REEs content and distribution pattern of crude oil from the same source should be similar.[19,20,26,31,32] Also, δCe, δEu, (La/Yb)CN, (La/Sm)CN, and (Gd/Yb)CN ratios are important feature parameters of REE distribution patterns. Hence, a total of 21 variables including these featured parameters and REE contents were used for oil group classification of Chang 7 and Chang 8 crude oil samples. In order to improve the data discrimination from so many variables, factor analysis and principal component analysis are the most appropriate analysis measurements for data similarity comparison. Using SPSS 19.0 statistical software, the components with eigenvalues greater than 1, total variance greater than 10%, and cumulative variance greater than 70% were selected through the Caesar criterion. Finally, four principal components were extracted from 21 variables, whose eigenvalues and variances are shown in Table . It can be seen that the first two principal components account for more than 80% of the total variance (Table ), so only these two were applied for further classification, and their component matrix scores are shown in Figure .

Table 5

Eigenvalues and Variances (%) of Four Principal Components in 21 Variables

principal component	eigenvalues	total variance (%)	cumulative variance (%)
PC 1	14.73	70.12	70.12
PC 2	2.52	12.02	82.14
PC 3	1.83	8.73	90.87
PC 4	1.31	6.25	97.12

Figure 9

Component matrix score diagram of REE and related parameters in principal component 1 and principal component 2.

PC1 (principal component 1) accounts for 70.12% of the total variance and is composed of specific REE content (La to Lu) and ∑REE, reflecting the content of REE (Table ).

PC2 accounts for 12.02% of the total variance and is composed of L/HREE, (La/Yb)CN, (La/Sm)CN, and (Gd/Yb)CN ratios, in which the score of (La/Yb)CN ratio is the highest, followed by L/HREE, (Gd/Yb)CN, and (La/Sm)CN ratios, respectively (Table ). PC2 mainly represents the REE distribution patterns.

The δCe and δEu ratios are negative related to both PC1 and PC2 except for a weak positive of δEu ratios to PC1, which reflects that these two parameters are not comparable and inheritable in oil group classification. The δCe ratio can be an indicator for paleoredox conditions in sediments.[62−64] Some researchers believe that the δCe ratio in organic extracts and solid bitumen is inherited from the precursor kerogens.[62,64] However, the δCe ratio will be easily obliterated by diagenetic alterations.[65] Eu is the only other REE with many factors and a complex process affecting its content.[66] In general, negative Eu anomalies in sediments are indicator of the oxidation environment;[62] yet, in a word, there are few studies on the source and impact factors of Ce and Eu anomalies in crude oil. Therefore, the cause of Ce and Eu anomalies in crude oil is not clear. What can be confirmed in this study is that δCe and δEu ratios have no obvious comparative fingerprint in the oil–oil correlation, which also proves the complex influencing factors of Ce and Eu anomalies in crude oil.

Based on the fact that the PC1 and PC2 represent the absolute content and distribution pattern of REE in crude oil samples, it can be seen that these two features are key in the oil group classification by REE. The PC1 and PC2 component scores of all crude oil samples are plotted in Figure , in which two groups can be discriminated obviously: group A and group B (except for one outlier sample Z172), and group A have two subgroups A1 and A2.

Figure 10

Cross-plot of component scores of PC1 and PC2 for all crude oil samples.

Group A includes all Chang 71 and Chang 72 crude oil samples with one Chang 73 sample. Samples of this group are characterized by ∑REE values <300 ppb, a relatively low PC1 score, and a moderate PC2 score (Table and Figure ). Among them, the main distinguishing fact for A2 subgroup from that of A1 subgroup is that the Chang 73 sample X237 has clearly larger ∑REE value and PC1 score than those of A1 subgroup.

Group B consists of one Chang 8 sample (L91) and two Chang 73 samples (Z182 and X133), featured by ∑REE values >590 ppb, a moderate PC2 score, and a high PC1 score (Table and Figure ).

Though the crude oil samples for analysis are different, the results of oil group classification by REE are quite similar to those by biomarker parameters, that is, Chang 71 and Chang 72 crude oils are generally related, whereas Chang 73 and Chang 8 crude oil may have the same source. On the basis of REE classification, combined with the V, Ni, and Co features of all crude oil samples discussed above, it can be found that V/(V + Ni) and Ni/Co ratios of Chang 71 and Chang 72 crude oil (<0.5 and <7.0, respectively) in subgroup A1 represent the slight oxic forming condition (Table ), which is consistent with that of Chang 7 mudstone, while V/(V + Ni) and Ni/Co ratios of three samples in group B reflect the anoxic condition, which are the same as those of Chang 7 oil shale. V/(V + Ni) and Ni/Co ratios of the Chang 73 sample X237 in subgroup A2 are 0.45 and 7.50, respectively (Table ), just showing a transitional environment between the forming conditions of Chang 7 mudstone and oil shale. Only one outlier, Chang 8 sample Z172, has an obviously higher Ni/Co ratio than other Chang 8 samples, as well as obviously lower trace element contents and δEu ratio than those of other samples, which may be caused by the unexpected error in the sample pretreatment and experimental processes. Therefore, from the oil classification results by REE and redox conditions reflected by V/(Vi + Ni) and Ni/Co ratios, it can be concluded that Chang 71 and Chang 72 crude oil are from Chang 7 mudstone, Chang 73 crude oil has a mixed source of Chang 7 mudstone and oil shale, and part of Chang 8 crude oil is from Chang 7 oil shale.

It can be seen that the absolute content and the distribution pattern of REE in crude oil are two key indexes for oil group division, among which the absolute content of REE represented by PC1 is the most relevant because of its nearly 70% total variance. There are few studies of the source and interfering factors of REE in crude oil.[27,67−70] Previous studies on the occurrence of REEs in crude oil suggested the following: REEs occur in clay minerals;[27] they are organocombined;[67] they are adsorbed by hydrogen functional groups or directly bonded by carbon;[68] they are related to the abundance of different functional groups in crude oil;[69] and they do not mainly occur in a certain organic compound.[70] Lately, based on the REE data collection and correlation analysis of various types of crude oil and extracts around the world, Gao et al., 2015 pointed out that metal complexes and/or functional groups that provide complexing sites for V could be carriers for REEs; also, the distribution pattern of REE has a certain correlation with the type of organic matter types of source rock.[70] There is no direct evidence for the origin of REEs in crude oil in this study. The ∑REE and the content of V, Ni, and Co show poor to no correlation. In short, it is still controversial whether REEs in crude oil are controlled by organic components or inorganic metal complexes. Thus, more studies on the mechanism of occurrence and transformation of REEs in crude oil are urgently needed to expand the applicability of REEs in oil–oil and oil–source correlations.

Application Comparison of REEs and Biomarkers in Oil–Source Correlation

By using biomarker parameters and REEs for oil–source correlation analysis, the results mutually reinforce the conclusion that Chang 7 mudstone controls the hydrocarbon supply of Chang 71 and Chang 72 tight oil, while Chang 7 oil shale is the main hydrocarbon contribution to Chang 73 tight oil. The difference between the results of the two methods is that the REE classification provides additional evidence that Chang 73 crude oil has mixed hydrocarbons from Chang 7 mudstone and Chang 8 crude oil is also from Chang 7 oil shale. Although there is no evidence or discussion on the hydrocarbon accumulation mechanism in this study, previous research works on Chang 7 mudstone and oil shale may give some mechanistic explanation and insight. Although Chang 7 oil shale has a better hydrocarbon generation potential than the mudstone, its expulsion threshold is higher, and the main driving force of hydrocarbon migration from the source to the reservoir is the overpressure in the Chang 7 source rock.[14,71,72] In general, Chang 7 mudstone and oil shale are two sets of independent source rocks and nearby reservoir systems. Because oil shale is mainly developed in Chang 73 and mudstone is overlapping in Chang 71 and Chang 72, mudstone and oil shale mainly control Chang 71–72 and Chang 73 tight oil pools, respectively. However, the second migration of hydrocarbons started earlier in mudstone because of its lower expulsion threshold, which will partly mix with hydrocarbons from oil shale in the Chang 73 reservoir. Of course, more targeted research is needed to confirm this. Nevertheless, the basis and analysis process of the two oil–source correlation methods are quite different. The biomarker-based oil–source correlation method compares the similarity of the related feature parameters ratio of crude oil and source rock samples. The parameters for comparison are selected according to the largest differences between potential source rocks, such as parameters reflecting the organic matter origin, redox condition, thermal maturity level, and so forth. The advantage of this method lies in the strong applicability of classification, but the related parameter ratio is not accurate enough and has multiple solutions. Whereas the most application limits are that the parameters used for the characterization of crude oil or source rock and oil–source correlation are just the same set of parameters, that is, the evidence is too simple, so relative studies usually add other experimental means (e.g., stable carbon isotope) to verify the analysis results. The REE-based oil–source correlation method in this study just makes up for this weakness: the oil group classification is established on the REE contents and REE distribution pattern, and the classification results are further verified and the source rock is determined by specific trace element ratios. This workflow can be regarded as a double check by alternate experimental means, which is more efficient and accurate. Although the two experimental methods were not performed on the same samples in this study, there is no doubt that the finding and understanding have inspiration for the theoretical study of oil–source correlation, especially for the multi-source and complex system and the exploration of Chang 7 tight oil as well as shale oil in the future.

Conclusions

A large number of physical properties, biomarker parameters, REEs, and trace elements were utilized to analyze and evaluate the integral features, thermal maturity, source, and forming environment redox condition of Chang 7 tight oil in Longdong area, Ordos Basin. Ultimately, a refined oil–source correlation analysis between crude oil, mudstone, and oil shale of Chang 7 section was carried out systematically.

Chang 7 crude oil is generally characterized by low density, low viscosity, low gel point, and relatively strong fluidity. The thermal maturity of Chang 7 crude oil has already reached the mature stage. The distribution features of n-alkanes, C27–29 regular steranes of crude oil, combined with the relatively high ratio of ∑tricyclic terpenes/∑hopanes, as well as the discrimination of the cross-plots of Pr/nC17–Ph/nC18 and Pr/Ph–C27/C29 regular steranes show that the organic matter in crude oil mainly comes from lower aquatic forms such as algae, with some contribution of micro-organisms and bacteria. The cross-plots of Pr/nC17–Ph/nC18, Pr/Ph–C27/C29 regular steranes and DBT/F + DBT – DBF/F + DBF exhibit the transitional depositional environment feature of sub-oxidizing to sub-reducing. The V/(V + Ni) and Ni/Co ratios of crude oil samples display specifically that Chang 71 and Chang 72 samples were formed under slight oxic conditions, while Chang 73 and Chang 8 samples were formed in the anoxic environment.

Both the biomarker-based and REEs-based oil–source correlation analyses show that Chang 7 mudstone controls the hydrocarbon supply of Chang 71 and Chang 72 tight oil, while Chang 73 tight oil mainly comes from Chang 7 oil shale, with part of mixed from Chang 7 mudstone. Also, compared with the oil–source correlation analysis based on biomarkers, the comprehensive method based on REEs and trace elements is effective, accurate and has a broader application prospect.

Samples and Methods

In this study, 26 crude oil samples were systematically collected from 26 wells in Longdong area (Figure c), 24 of which were from Chang 7 tight oil reservoir and two from Chang 8 tight oil reservoir. Simultaneously, 10 Chang 7 crude oil samples were used for group component separation and gas chromatography–mass spectrometry (GC–MS) experiments for biomarker characterization, and the other 16 samples were used for elemental analysis. All the samples were first stored in brown bottles with glass plugs and then analyzed directly in the laboratory. Moreover, a dataset including the physical properties of Chang 7 crude oil was also collected from the Changqing Oilfield Company to evaluate the comprehensive properties of Chang 7 tight oil.

Biomarker Characterization

Ten Chang 7 crude oil samples were separated into saturated hydrocarbon, aromatic hydrocarbon, and nonhydrocarbon fractions by liquid column chromatography. The saturated hydrocarbon fraction was collected by n-hexane extraction 4 times, the aromatic hydrocarbon fraction was collected by dichloromethane extraction, and the nonhydrocarbon fraction was eluted with a methanol solution. During the experiment, the mixture of standard compounds and samples were fractionated to ensure qualitative and quantitative repeatability. Finally, the saturated hydrocarbon and aromatic hydrocarbon fractions of the crude oil samples were further analyzed by GC–MS.

Geochemical detection of biomarkers in saturated and aromatic hydrocarbon fractions of Chang 7 crude oil was carried out on an Agilent 7890 GC system coupled with an Agilent 5975c mass spectrometer. The HP-5MS elastic quartz capillary column (60 m × 0.25 mm × 0.25 μm) is used as the chromatographic column and helium gas with a flow rate of 1 mL/min as the carrier gas. The temperature of the column oven is programed as follows: the initial temperature 50 °C is kept for 1 min, followed by an increase to 250 °C at 4 °C/min, and ultimately to 310 °C at 3 °C/min, with an isothermal time of 30 min. The temperatures of the sample inlet and the transmission line are both 300 °C. Electron ionization is adopted for MS, with the ionization voltage of 70 eV, the electron multiplier voltage of 1200 V, and the filament current of 100 A. According to the retention time of the analytical results and comparison with the literature data, the types of biomarkers were determined.[73,74] The saturated hydrocarbon ratio, the relative abundance of steranes and terpanes, and the aromatic hydrocarbon ratio were calculated from the comprehensive peak area of the related ion chromatography.[21,75,76]

Trace and REEs Analyses

Trace and REE contents of 16 crude oil samples were carried out on a Nu Attom Inductively Coupled Plasma Mass Spectrometry (ICP–MS) instrument at the IGGCAS, Lanzhou, China. In consideration of the previous successful determination on REEs in crude oil,[69,70,77] an acid digestion method is also used in this study for sample pretreatment. The specific steps are as follows: about 1 g of crude oil was decomposed by heating (at ca. 180 °C) for a week in 68 wt % HNO3 solution in a Teflon vessel with a screw cap. After evaporation of the solution, the organic matter was thoroughly digested by drying in H2SO4 (at ca. 230 °C). After the solution was evaporated again, the sample was ultimately dissolved in 2 wt % HNO3 for measurement. Selective trace elements (V, Ni, and Co) and REEs of crude oil samples were determined by ICP–MS. The measurement accuracy of all trace elements is better than 2%. In order to dispel the abundance difference between odd and even atomic number elements and to facilitate the comparison with the related source rock REE concentration distribution pattern, the chondrite data from Sun and McDonough, 1989[44] were used as a reference to normalize the REE concentration in crude oil samples.