Sage Journals: Discover world-class research

Abstract

Light hydrocarbon has abundant geochemical information, but there are few studies on it in Shenmu gas field. Taking Upper Paleozoic in Shenmu gas field as an example, authors use gas chromatography technology to study light hydrocarbon systematically. The results show that (1) The Shenmu gas field is mainly coal-derived gas, which is mixed by partial oil-derived gas due to the experiment data. (2) Based on K₁, K₂ parameter and Halpern star chart, the Upper Paleozoic gas in Shenmu gas field belongs to the same petroleum system and the depositional environment of natural gas source rocks should be homologous. (3) The source rocks are mainly from terrestrial higher plant origins and belong to swamp facies humic due to methyl cyclohexane index and Mango parameter intersection chart, which excluded the possibility of the Upper Paleozoic limestone as source rocks. (4) The isoheptane ranges from 1.45 to 2.69 with an average of 2.32, and n-heptane ranges from 9.48 to 17.68% with an average of 11.71%, which is below 20%. The maturity of Upper Paleozoic gas in Shenmu gas field is low-normal stage, which is consistent with R_o data. (5) The Upper Paleozoic natural gas in the Shenmu gas field did not experience prolonged migration or secondary changes, thus can be analyzed by light hydrocarbon index precisely.

Keywords

Shenmu gas field light hydrocarbon genetic type maturity gas–source correlation

Introduction

As an important constituent of oil and gas, light hydrocarbons are of great geochemical significance (Yu et al., 2014), but there is no universally accepted definition for them now. As per Dai Jinxing’s definition (Dai, 1993a), light hydrocarbons are referred to as gasoline hydrocarbons with the boiling range less than 200℃, or C_5–10 alkanes including some gas-associated condensate oil and light oil. Guo et al. (2009), Mango (1997), Odden (1999), and Shen et al. (2011) defined light hydrocarbons as C_4–7, C_1–9, C_1–13, and C_5–10 alkanes, respectively. In this paper, C_1–13 alkanes are defined as light hydrocarbons in a broad sense and C_5–9 alkanes as the analogs in a narrow sense; the latter is the focus of efforts in current researches and in this paper.

Upper Paleozoic gas in Shenmu gas field is characterized by high humidity and high light hydrocarbon content but has seldom been discussed before. This paper focuses on Upper Paleozoic gas geneses, gas and source rock correlation, and natural gas maturity in Shenmu gas field based on the tests and analyses of light hydrocarbon composition of natural gas. The conclusions may have some guiding significance to future gas exploration and development.

Regional geologic setting and samples

Shenmu gas field of 4 × 10⁴ km² geographically lies in Yuyang District of Yulin City and Shenmu County, Shanxi Province and which is also positioned adjacent to Mizhi, Da niudi, Yulin, and Zizhou gas fields (Yang et al., 2015) (Figure 1). Tectonically it is a widely gentle west-inclined slope with few faults situated in the northeast of Yishan slope, a secondary tectonic unit, and the south of Yimeng uplift (Liu et al., 2009). The sedimentary system changed from marine facies to continental facies. Major pay zone is the Taiyuan Formation, which is composed of shallow deltaic deposits generated from marine transgression and low-energy carbonate rocks of littoral facies (Meng et al., 2013). There are clastic formations, limestone formations, and alternate layers in this field, especially alternate layers (Lan et al., 2011). Distributary channel grits alternate with pervasive coal-measure source rocks to form self-sourced lithologic reservoirs. Reservoir space is mainly composed of dissolved pores and the barriers are surrounding mudstone and constricted sandstone.

Figure 1.

Sketch map showing location of Shenmu gas field.

In the study of light hydrocarbon composition, 23 Upper Paleozoic gas samples were selected. The average humidity is 5.79 and the content of light hydrocarbons is relatively high (Table 1). Agilent 7890GC gas chromatograph and DB-5 elastic silica capillary column of 30 m × 0.25 mm were used. The initial temperature was 30℃. Column temperature ranged from 80 to 310℃. The heating rate was 6℃/min. Nitrogen was used as the carrier gas. The injection rate of hydrogen gas and air was 40 and 400 ml/min, respectively. The flame ionization detector was used for detection.

Table 1.

The characteristics of natural gas components from Shenmu gas field.

Well	Strata	Main components (%)										Wetness
Well	Strata	CH₄	C₂H₆	C₃H₈	iC₄H₁₀	nC₄H₁₀	iC₅H₁₂	nC₅H₁₂	C₆+	N₂	CO₂	Wetness
S10-13	P₁sh + P₁s	91.55	4.66	0.95	0.22	0.19	0.10	0.05	0.23	0.41	1.62	6.30
S10-3	P₁s + P₁t	91.33	4.95	1.03	0.19	0.20	0.09	0.04	0.19	0.38	1.56	6.65
S10-5	P₁s + P₁t	92.17	3.78	0.75	0.16	0.15	0.07	0.03	0.14	0.51	2.22	5.08
S10-9	P₁s + P₁t	91.62	4.18	0.85	0.19	0.17	0.08	0.04	0.13	0.44	2.28	5.67
S11-15C₁	P₁s + P₁t	91.34	4.20	0.88	0.18	0.17	0.08	0.04	0.26	0.33	2.50	5.73
S11-15C₃	P₁s + P₁t	91.69	3.81	0.76	0.16	0.15	0.08	0.04	0.25	0.29	2.74	5.16
S11-4C₅	P₁sh + P₁s	89.42	6.92	1.53	0.25	0.27	0.12	0.07	0.22	0.57	0.57	9.29
S19-12	P₁s + P₁t	92.17	3.09	0.60	0.14	0.11	0.06	0.03	0.16	0.26	3.36	4.19
S20	P₁s + P₁t	91.37	4.40	0.80	0.14	0.15	0.07	0.04	0.21	0.34	2.46	5.77
S21-12	P₁s + P₁t	91.61	4.10	0.75	0.14	0.13	0.06	0.03	0.14	0.36	2.66	5.37
S3	P₁s + P₁t	91.49	4.48	0.88	0.20	0.17	0.09	0.04	0.21	0.24	2.17	6.03
S5-19	P₁x + P₁t	92.12	4.00	0.79	0.16	0.15	0.07	0.04	0.16	0.36	2.12	5.35
S6-18	P₁s + P1x	91.77	4.00	0.83	0.17	0.17	0.08	0.04	0.16	0.29	2.46	5.45
S6-19	P₁x + P₁s + P₁t	91.65	4.28	0.89	0.18	0.18	0.09	0.04	0.15	0.25	2.26	5.82
S7-11	P₁x + P₁s	93.09	4.09	0.86	0.17	0.18	0.09	0.05	0.25	0.63	0.53	5.51
S7-12	P₁sh + P₁s	92.58	3.93	0.74	0.16	0.15	0.08	0.04	0.18	0.34	1.78	5.22
S8-12	P₁sh + P₁s	94.43	2.63	0.41	0.09	0.10	0.06	0.03	0.10	0.17	1.97	3.40
S8-17C₃	P₁sh + P₁s	92.08	4.18	0.86	0.19	0.18	0.09	0.05	0.26	0.26	1.82	5.69
S8-8	P₁x	91.46	5.53	1.16	0.20	0.24	0.10	0.05	0.18	0.65	0.37	7.38
S9-11	P₁x + P₁s + P₁t	91.44	4.42	0.88	0.21	0.18	0.09	0.04	0.24	0.26	2.22	5.99
S9-11H₂	P₁t	91.97	3.39	0.61	0.14	0.11	0.06	0.03	0.19	0.26	3.21	4.51
S9-12	P₁s + P₁t	92.26	3.57	0.68	0.15	0.13	0.07	0.03	0.16	0.31	2.63	4.77
S9-13H₂	P₁t	91.34	4.77	1.06	0.25	0.22	0.11	0.05	0.26	0.30	1.61	6.61

Light hydrocarbon geochemical characteristics and their application

One notable feature of light hydrocarbon composition of Upper Paleozoic natural gas in the Shenmu gas field is that the methyl cyclohexane (MCH) content is very high. Figure 2 shows typical light hydrocarbon chromatographs of natural gas in the Shenmu gas field. In the distribution of C₇ compound of coal-derived gas, MCH is the main peak and has a distribution advantage. Prolific in alkane is another feature in this study area. In the relative volume fraction among aromatic, alkane, cycloalkane of C_6–7 findings are alkane is the most abundant, with the amount distributed in 54–76%, averaging at 58%. Next is cycloalkane, distributed in 20–40% and averaging at 33%. The content of aromatic is relatively low, distributed in 4–12% and averaging at 9%.

Figure 2.

Light hydrocarbon chromatogram of Shenmu gas field. 1: methyl cyclohexane; 2: toluene; 3: n-heptane; 4: 3-methyl hexane; 5: 2- methyl hexane; 6: cyclohexane; 7: benzene; 8: methyl cyclopentane.

Natural gas types

In addition to C_1–4 isotopic constitution, light hydrocarbon constitution, e.g. relative benzene and toluene contents; benzene toluene ratio; I_MCH6; triangular plot of C₇ light hydrocarbons; C_6–7 aromatic and branched alkane combination; and relative C_5–7N-alkanes, isoparaffin, and cycloalkane contents, could also be used as an indicator to identify natural gas geneses (Dai, 1992, 1993b; Hu et al., 1990, 2007; Lin, 1990; Qin et al., 1991). The following four indicators could be used to identify natural gas geneses accurately. In this paper, we propose the concept of alkane index for the first time.

MCH index

MCH mainly originates in lignocellulose found in higher plants and saccharide and is a major marker of humic organic matter (Guo et al., 2009). The existence of massive MCH indicates the origin of coal-derived gas. Hu et al. (1990) suggested MCH index (I_MCH6) could be used to identify the type of natural gas. I_MCH6 > (50 ± 2)% indicates coal-derived gas and I_MCH6 < (50 ± 2)% indicates oil-derived gas

I_{MCH 6} = \frac{MCH}{MCH + {RCPC}_{7} + n C_{7}} \times 100 %

(1) where I_MCH6 is MCH index, MCH is six-membered cyclic hydrocarbon, RCPC₇ is five-membered cyclic hydrocarbon, and nC₇ is linear hydrocarbon.

Among 23 samples selected from Shenmu gas field (Table 2), there are 22 samples with I_MCH6 > (50 ± 2)%, indicating the origin of coal-derived gas, which is consistent with the judgment by δ¹³C₂ > −28.5‰. For Well Shuang 8-12, I_MCH6 < (50 ± 2)% indicates the origin of oil-derived gas, whereas δ¹³C₂ of −24.7‰ indicates coal-derived gas. Carbon isotopic reversal, i.e. δ¹³C₁ < δ¹³C₂ > δ¹³C₃ < δ¹³C₄, observed from this well may be caused by the mixture of organic genetic gas and inorganic genetic gas, mixture of coal-derived gas and oil-derived gas, mixture of the same type of gases from different sources or gases generated in different periods from the same source, or alkane gas oxidation by some bacteria (Dai et al., 2004). In accordance with regional geologic setting and neighboring well scenarios, carbon isotopic reversal for this well should be caused by the mixture of coal-derived gas and oil-derived gas; that is why δ¹³C₂ index is inconsistent with I_MCH6 index.

Table 2.

The relative content of light hydrocarbon and methyl cyclohexane index.

Well	Strata	nC₇	MCH₆	1,1-DMCC₅	1c3-DMCC₅	1t3-DMCC5	1t2-DMCC₅	I_MCH6/%
S7-11	P₁x + P₁s	3.94	11.32	0.59	0.75	0.71	1.04	61.69
S3	P₁s + P₁t	2.26	8.52	0.69	0.72	0.62	0.95	61.93
S5-19	P₁x + P₁t	2.23	7.43	0.59	0.7	0.55	0.9	59.93
S6-18	P₁s + P₁x	2.04	6.71	0.7	0.35	0.48	0.81	60.45
S6-19	P₁x + P₁s + P₁t	2.34	6.96	0.58	0.63	0.48	0.72	59.46
S7-12	P₁sh + P₁s	2.5	9.08	0.56	0.7	0.49	0.95	63.59
S8-8	P₁x	1.65	6.52	0.52	0.73	0.6	0.92	59.57
S8-12	P₁sh + P₁s	3.64	4.44	0.44	0.26	0.2	0.57	46.50
S8-17C₃	P₁sh + P₁s	2.42	7.42	0.77	0.56	0.53	0.94	58.67
S9-11	P₁x + P₁s + P₁t	1.54	5.8	0.52	0.51	0.39	0.66	61.50
S9-11H₂	P₁t	2.49	7.61	0.59	0.47	0.5	0.94	60.33
S9-12	P₁s + P₁t	2.02	7.02	0.63	0.46	0.46	0.88	60.34
S9-13H₂	P₁t	2.32	9.87	0.67	0.85	0.69	1.12	63.58
S10-3	P₁s + P₁t	2.1	8.29	0.56	0.77	0.65	1.01	73.48
S10-5	P₁s + P₁t	2.14	7.4	0.6	0.7	0.61	1	59.48
S10-9	P₁s + P₁t	1.95	7.25	0.61	0.6	0.5	0.91	61.42
S10-13	P₁sh + P₁s	2.25	9.43	0.63	0.89	0.63	1.26	62.53
S11-4C₅	P₁sh + P₁s	1.92	8.72	0.62	0.86	0.67	1.14	62.62
S11-15C₁	P₁s + P₁t	2.39	8.82	0.63	0.76	0.65	1.02	61.84
S11-15C₃	P₁s + P₁t	1.96	6.31	0.49	0.56	0.58	0.61	60.05
S20	P₁s + P₁t	2.14	5.48	0.47	0.6	0.45	0.76	55.35
S19-22	P₁s + P₁t	1.88	5.92	0.52	0.52	0.36	0.74	59.55
S21-12	P₁s + P₁t	2.04	8.02	0.64	0.65	0.48	1	62.52

I_MCH6: methyl cyclohexane index; MCH₆: methyl cyclohexane; nC₇: normal heptane; 1c3-DMCC₅: 1, cis-3-dimethyl cyclopentane; 1,1-DMCC₅: 1,1-dimethyl cyclopentane; 1t2-DMCC₅: 1, trans-2-dimethyl cyclopentane; 1t3-DMCC₅: 1, trans-3-dimethyl cyclopentane.

Alkane index

The parent material of organic matter has a great impact on C_6–7 light hydrocarbons. Oil-derived gas generated from sapropelic parent materials is relatively rich in alkane hydrocarbons and coal-derived gas generated from humic materials is relatively rich in cycloalkane and aromatic (Leythaeuser et al., 1979; Snowdon and Powell, 1982). Yu et al. (2013) analyzed light hydrocarbon composition of oil-derived gas in the Tarim Basin and found relative alkane content > relative cycloalkane content > relative aromatic content. In this paper, a concept of alkane index (I_a) is formulated as follows based on the study of relative C_6–7 alkane, cycloalkane, and aromatic content

I_{a} = \frac{R_{p}}{R_{a} + R_{c}}

(2) where I_a is alkane index, R_p is relative alkane content in C_6–7 compounds, R_a is relative aromatic content in C_6–7 compounds, and R_c is relative cycloalkane content in C_6–7 compounds.

Table 3 shows the alkane index (I_a) of 22 gas sample ranges 1.17–1.91% and the index (I_a) for Well Shuang 8-12 is 3.22, which is abnormally high (Figure 3). This is caused by the mixture of oil-derived gas and coal-derived gas. Therefore, alkane index (I_a) could be used to identify natural gas geneses.

Table 3.

The index of alkane of Shenmu gas field.

Well	Strata	Aromatic	Alkane	Cycloalkane	I_a	Type
S7-11	P₁x + P₁s	0.08	0.57	0.36	1.30	Coal-derived
S3	P₁s + P₁t	0.11	0.56	0.33	1.30	Coal-derived
S5-19	P₁x + P₁t	0.10	0.57	0.33	1.30	Coal-derived
S6-18	P₁s + P₁x	0.09	0.57	0.33	1.35	Coal-derived
S6-19	P₁x + P₁s + P₁t	0.11	0.57	0.32	1.33	Coal-derived
S7-12	P₁sh + P₁s	0.12	0.55	0.33	1.23	Coal-derived
S8-8	P₁x	0.05	0.60	0.35	1.50	Coal-derived
S8-12	P₁sh + P₁s	0.04	0.76	0.20	3.22	Mixed
S8-17C₃	P₁sh + P₁s	0.08	0.59	0.32	1.45	Coal-derived
S9-11	P₁x + P₁s + P₁t	0.09	0.61	0.30	1.58	Coal-derived
S9-11H2	P₁t	0.12	0.57	0.31	1.33	Coal-derived
S9-12	P₁s + P₁t	0.10	0.59	0.31	1.45	Coal-derived
S9-13H2	P₁t	0.09	0.54	0.37	1.19	Coal-derived
S10-3	P₁s + P₁t	0.08	0.56	0.36	1.26	Coal-derived
S10-5	P₁s + P₁t	0.11	0.57	0.33	1.31	Coal-derived
S10-9	P₁s + P₁t	0.11	0.56	0.33	1.29	Coal-derived
S10-13	P₁sh + P₁s	0.08	0.55	0.37	1.23	Coal-derived
S11-4C₅	P₁sh + P₁s	0.06	0.54	0.40	1.17	Coal-derived
S11-15C₁	P₁s + P₁t	0.10	0.56	0.34	1.25	Coal-derived
S11-15C₃	P₁s + P₁t	0.10	0.61	0.29	1.54	Coal-derived
S20	P₁s + P₁t	0.05	0.66	0.29	1.91	Coal-derived
S19-22	P₁s + P₁t	0.11	0.60	0.29	1.51	Coal-derived
S21-12	P₁s + P₁t	0.10	0.55	0.34	1.25	Coal-derived

Figure 3.

The triangle chart of alkane, aromatic, and cycloalkane.

Triangular plot of light hydrocarbons

Common C₇ light hydrocarbons mainly include (1) MCH, which originates in terrigenous parent materials of humic type. Massive MCH is an indicator of coal-derived gas; (2) dimethyl cyclopentanes (ΣDMCP) of different constitutions, which originate in lipids from aquatic organisms and indicate oil-derived gas of sapropelic type; (3) normal heptane (nC₇), which originates in various parent materials including bacteria, algae, and higher plants and is a good index of maturity. A triangular plot composed of above three compounds could then be used to distinguish natural gas geneses (Figure 4(a)) (Dai, 1993b; Dai and Li, 1994; Dai et al., 1985; Mango, 1990a; Snowdon and Powell, 1982).

Figure 4.

The triangle chart of (a) C₇ light hydrocarbon system and (b) N-alkanes, isoparaffin, cycloalkane.

As per the plot, Upper Paleozoic gas samples from Shenmu gas field have high relative MCH content of 46–73% with an average of 61% and low relative normal heptane (nC₇) content of 14–38% with an average of 18%. Hu et al. (2007) proposed that oil-derived gas has relative nC₇ content over 30% and relative MCH content under 70%, while coal-derived gas has relative nC₇ content under 35% and relative MCH content over 50%. As per these criteria, 22 samples are of coal-derived gas origin and additional one sample from Well Shuang 8-12 falls in the overlapping interval, which is consistent with the judgment of coal-derived gas and oil-derived gas mixture by I_MCH6 index.

The composition of aliphatic in natural gas is dependent on sedimentary environments and source rocks with different parent materials. Oil-derived gas generated from sapropelic parent materials is rich in N-alkanes; coal-derived gas generated from humic materials is rich in aromatic and isoparaffin (Dai, 1992); terrigenous materials are rich in cycloalkane. This means relative contents of C_5–7 N-alkanes, isoparaffin, and cycloalkane could be used to identify natural gas geneses (Figure 4(b)).

The above figure shows 23 Upper Paleozoic gas samples concentrate in a local area on the triangular plot. As per the argument proposed by Hu et al. (2007) that coal-derived gas has relative C_5–7 content below 30%, 23 samples are of coal-derived gas origin.

Correlation of natural gas source rocks

K₁ and K₂ parameter

Mango discovered four isoheptane compounds, i.e. 2-methyl-hexane, 3-methyl-hexane, 2,3-dimethyl-pentane, and 2,4-dimethyl-pentane from more than 2000 light hydrocarbon samples worldwide. For a same chemical reaction, its isomer products are constituted in a relatively fixed proportion which does not vary with the concentration of intermediums and substrates. Mango (1987) defined this proportion as K₁ constant (equation (3)). The discrepancies in the constitution of humic kerogen and sapropel kerogen would lead to the discrepancies in the route and subsequent dynamic process of chemical reaction (Mango, 1997). This means different parent materials would generate isoparaffin with various abundances, which would be demonstrated by the discrepancies in isoparaffin parameters. Therefore, K₁ constant could be used for oil and gas–source rock correlation

K_{1} = \frac{2 - MH + 2, 3 - DMP}{3 - MH + 2, 4 - DMP}

(3) where 2-MH is 2-methyl-hexane, 2,3-DMP is 2,3-dimethyl-pentane, 3-MH is 3-methyl-hexane, and 2,4-DMP is 2,4-dimethyl-pentane.

K₁ value of 23 Upper Paleozoic gas samples from Shenmu gas field consistently ranges 1.00–1.23 with an average of 1.08 (Figure 5), which indicates natural gas in Shenmu gas field originates in the same petroleum system.

Figure 5.

The distribution plot of K₁ in natural gas from Shenmu gas field.

Based on the kinetic model of steady-state catalysis for C₇ genesis, Mango (1990b) supposed each reaction has its individual rate to generate cyclic compound with different carbon number, but the reaction rate to generate equal carbon number and identical ring should be in proportion; in accordance with this argument, Mango presented a K₂ parameter (defined in equation (4)). Zhu and Zhang (1999) proposed that light hydrocarbons generated from the same source rocks within the entire oil-generating window should have equal K₂ value, i.e. cyclopentane content in proportion to isopentane content

K_{2} = \frac{P_{3}}{P_{2} + N_{2}}

(4) where P₃ is 2,2-dimethyl-cyclopentane + 2,4-dimethyl-pentane + 2,3-dimethyl-pentane + 3,3-dimethyl-pentane + 3-ethyl-pentane, P₂ is 2-methyl-hexane + 3-methyl-hexane, and N₂ is 1,1-dimethyl-cyclopentane + cis-1,3-dimethyl-cyclopentane + trans-1,3-dimethyl-cyclopentane.

For 23 Upper Paleozoic gas samples from Shenmu gas field, K₂ value ranges 0.44–0.80 with an average of 0.55 and standard deviation of 0.09 (Figure 6), indicating natural gas in Shenmu originates in the same petroleum system, which is consistent with K₁ judgment.

Figure 6.

The distribution plot of K₂ in natural gas from Shenmu gas field.

Star chart of Halpern

Halpern (1995) optimized five parameters in light hydrocarbons and named them C₁–C₅. The star chart consists of five ratios involving compounds that are source related and resistant to the effects of transformation. Therefore, they are useful for correlation. We put the samples from Shenmu gas field into the star chart and found that the trend tends to be identical (Figure 7). Although we cannot distinguish the depositional environment of the source rocks from the star chart, it is useful to identify natural gas from different depositional environment (Huang et al., 2014; Liu et al., 2015; Ten Haven, 1996). So it is certain that the natural gas source rocks of the Upper Paleozoic Shenmu gas field should be consistent.

Figure 7.

C₇ oil gas correlation star diagram for Upper Paleozoic gas in Shenmu gas field.

Types of source rocks

Hu et al. (1990) proposed to use MCH index (I_MCH6) to distinguish parent materials forming in different sedimentary environments. In accordance with this standard, Upper Paleozoic gas source rocks in Shenmu gas field are mainly of humic genesis of swamp facies (Figure 8). As per the principle that C_6–7 compounds have equal carbon number, different constitutions and configurations, and similar boiling points, two naphthenic indices, CA₁ and CA₂, were formulated (equations (5) and (6)) as follows. If gas source rocks have similar parent materials, these two parameters would have good correlation

{CA}_{1} = {RCPC}_{7} / n C_{7}

(5)

{CA}_{2} = MCH / n C_{7}

(6) where RCPC₇ is a five-membered cyclic hydrocarbon, MCH is a six-membered cyclic hydrocarbon, and nC₇ is a linear hydrocarbon.

Figure 8.

The identification triangle chart using IMCH₆ index.

Gas samples demonstrate good correlation between CA₁ and CA₂ (with correlation coefficient of 0.85), which indicates these samples originate from the same source rocks (Figure 9). This conclusion is consistent with the judgment by MCH index (I_MCH6).

Figure 9.

The relationship scatter diagram between CA₁ and CA₂.

Ten Haven (1996) used Mango parameters to successfully distinguish lacustrine lower plant origins, mixed origins, and terrestrial higher plant origins. We use this chart to distinguish the samples from Shenmu gas field. From the chart, we can see that the samples all fall on the bottom, which indicates that the sources are terrestrial higher plant origins (Figure 10(a)). From Figure 10(b), we can see that oil from lacustrine organic has higher P₃/P₂ + N₂ value and lower N₂/P₃ than oil from terrestrial organic. The samples are from terrestrial higher plant origins, which are consistent with the I_MCH6 index.

Figure 10.

Cross plots of (a) P₂ + N₂ versus P₃ and (b) N₂/P₃ versus P₂ (modified from Liu et al. (2015) and Ten Haven (1996)).

Natural gas maturity

Some light hydrocarbons are related with formation temperature of sedimentary rocks during burial; therefore, heptane value (H) and isoheptane value (I) could be jointly used to estimate natural gas maturity (Shen et al., 2010; Thompson, 1983). Biodegraded gas has isoheptane value less than 0.8 and heptane value less than 16; low-mature gas has isoheptane value of 0.8–2.2 and heptane value of 16–22; mature gas has isoheptane value of 2.5–5 and heptane value of 22–30; high-mature gas has isoheptane value over 5 and heptane value over 30.

For 23 Upper Paleozoic gas samples from Shenmu gas field, isoheptane value of 22 samples ranges 1.45–2.69 with an average of 2.32; additional one sample has isoheptane value of 6.39. Heptane value of 23 samples ranges 9.48–17.68 with an average of 11.71, all less than 20 (Figure 11). As per above criteria, coal-derived gas in Shenmu is low mature to mature. The maximum values occur in Well Shuang 8-12 with isoheptane value of 6.39 and heptane value of 17.68. These two values are closely related with source rock maturity; for the same maturity, oil-derived gas of sapropelic type would have higher heptane value than coal-derived gas of humic type (Shen et al., 2010). Due to the mixture of some oil-derived gas in Well Shuang 8-12, its heptane value and isoheptane value are abnormally high.

Figure 11.

Maturity of light hydrocarbon in natural gas in Shenmu gas field.

R_o value of 23 gas samples was estimated to be 0.62–0.82% with an average of 0.72% (Table 4) using the equation of R_o dependence on δ¹³C₁ proposed by Dai et al. (1992). In terms of the standards for coal-derived gas maturity in eastern China (including the Ordos and Sichuan Basins) (Gang and Lin, 2011) (Figure 12), Upper Paleozoic gas in Shenmu is low mature to mature, which is consistent with the above judgment by isoheptane and heptane values. This demonstrates the credibility of gas maturity estimation by light hydrocarbons. Similar maturity estimated by methane carbon isotopes and light hydrocarbons also demonstrates that Upper Paleozoic gas in Shenmu was generated from the same source rocks and is trapped to form gas reservoirs in the same period (Chen et al., 2010)

δ^{13} C_{1} = 14.12 \lg R_{o} - 34.39

(7) where δ¹³C₁ is methane carbon isotopic value and R_o is vitrinite reflectance.

Table 4.

The δ¹³C and R_o value of Shenmu gas field.

Well	δ¹³C (‰, VPDB)						R_o/%
Well	CH₄	C₂H₆	C₃H₈	C₄H₁₀	iC₄H₁₀	nC₄H₁₀	R_o/%
S9-11	−36	−23.1	−22	−21.70	−21.82	−21.57	0.77
S5-19	−36.5	−23.9	−22.7	−22.18	−22.37	−21.98	0.71
S3	−36.7	−23.2	−22	−21.65	−21.86	−21.41	0.69
S6-18	−36.7	−23.7	−22.4	−21.80	−22.09	−21.49	0.69
S6-19	−37	−23.8	−22.4	−21.92	−22.09	−21.75	0.65
S7-11	−36.7	−24.7	−23.1	−22.53	−22.75	−22.32	0.69
S7-12	−36.1	−23.4	−22.2	−21.88	−22.21	−21.51	0.76
S8-12	−37.3	−24.7	−26.4	−25.62	−24.70	−26.40	0.62
S8-17C₃	−36.6	−25.6	−23.4	−22.42	−22.40	−22.44	0.70
S8-8	−37.1	−25.1	−24.3	−23.61	−23.52	−23.68	0.64
S9-11H₂	−35.6	−22.8	−22	−21.01	−20.92	−21.12	0.82
S9-12	−36.5	−23.2	−22.1	−21.10	−21.15	−21.03	0.71
S9-13H₂	−36	−23.2	−22.1	−21.86	−22.08	−21.61	0.77
S10-13	−35.9	−23.5	−22.3	−22.15	−22.44	−21.82	0.78
S10-3	−36.5	−24.8	−23.7	−22.97	−23.05	−22.90	0.71
S10-5	−36.1	−23.8	−22.8	−22.02	−22.14	−21.90	0.76
S10-9	−36.5	−23.5	−22.3	−21.73	−21.94	−21.49	0.71
S11-15C₁	−36.4	−23.3	−22.3	−21.73	−21.97	−21.47	0.72
S11-15C₃	−36	−23.2	−22.2	−21.54	−21.79	−21.28	0.77
S11-4C₅	−36.8	−25.4	−24.2	−23.78	−24.10	−23.49	0.68
S19-12	−35.9	−23.2	−21.8	−21.06	−21.43	−20.59	0.78
S20	−36.2	−25.8	−24.2	−23.48	−23.26	−23.69	0.74
S21-11	−35.9	−24.1	−22.9	−21.03	−20.84	−21.24	0.78

Figure 12.

The maturity map of coal-derived gas in East China (including Ordos Basin and Sichuan Basin).

Study on preservation conditions

Compared with oil, natural gas is more easily lost and more difficult to be saved. Therefore, it is necessary to study the preservation conditions of Shenmu gas field, in order to exclude secondary effects on light hydrocarbon index. An increase in aromatic hydrocarbons and cycloalkanes relative to N-alkanes indicates secondary evaporative fractionation of lighter components of the gas during migration or other postexpulsion processes. We projected the samples to chart and found that gas samples were located in the normal area of crude oil, which indicates that the preservation conditions of Shenmu gas field are good and natural gas has not experienced late damage (Figure 13).

Figure 13.

Cross plot of nC₇/MCH versus TOL/nC₇ (modified from Thompson (1987)).

Halpern (1995) used parameters Tr1–Tr8 to judge if the oil had experienced prolonged migration or secondary changes. The parameters put the antisecondary transformation of the compound as the denominator and eight compounds which are susceptible to secondary effects as the numerator. The parameters are in the order of sensitivity of molecular compounds. The samples from the Upper Paleozoic of Shenmu gas field are almost identical in the Halpern star map, which indicates that natural gas did not experience prolonged migration or secondary changes (Figure 14). Therefore, light hydrocarbon characteristics could reflect their original state within the source rock.

Figure 14.

C₇ oil transformation star diagram (modified from Halpern (1995)).

Conclusions

As per light hydrocarbon composition, Upper Paleozoic gas in Shenmu gas field is mainly composed of coal-derived gas mixed with some oil-derived gas partly.

The concept of alkane index (I_a) is proposed. For Upper Paleozoic gas in Shenmu, alkane index of coal-derived gas ranges 1.17–1.91% and is less than 2%. For oil-derived gas or the mixture of oil-derived gas, alkane index should be higher than 2%.

K₁ value, a Mango parameter, of 23 Upper Paleozoic gas samples from Shenmu gas field consistently ranges 1.00–1.23 with an average of 1.08 and K₂ value, another Mango parameter, ranges 0.44–0.80 with an average of 0.55 and standard deviation of 0.09. The samples in star chart tend to be consistent. Both K₁,K₂ value and star chart indicate natural gas in Shenmu gas field originates in the same petroleum system.

Based on MCH index and Mango parameter cross plot, the source rocks of Upper Paleozoic in the Shenmu gas field are humic types originated from terrestrial higher plants. This result excludes the possibility of Upper Paleozoic limestone acting as source rocks.

For 23 Upper Paleozoic gas samples from Shenmu gas field, isoheptane value (I) of 22 samples ranges 1.45–2.69 with an average of 2.32; heptane value (H) of 23 samples ranges 9.48–17.68 with an average of 11.71, all less than 20. R_o value of 23 gas samples ranges 0.62–0.82. In terms of isoheptane, heptane, and R_o values, Upper Paleozoic gas in Shenmu is low mature to mature.

The Upper Paleozoic natural gas in the Shenmu gas field experienced few damages in the late period, thus can be analyzed by light hydrocarbon index.

Authors' note

The abbreviations and their corresponding light hydrocarbons are listed in Table 5 in the appendix.

Footnotes

Acknowledgments

We appreciate professor Jinxing Dai for his constructive reviewing.

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research, authorship, and/or publication of this article.

Funding

The author(s) received no financial support for the research, authorship, and/or publication of this article.

Appendix

References

Chen

Miao

Zhang

(2010) Geochemical characteristics of light hydrocarbons in natural gas in the Tabei Uplift of the Tarim Basin and their implications. Oil and Gas Geology 31(3): 271–276.

Dai

(1992) Identification of various alkane gases. Science in China: Series B 22(2): 185–193.

Dai

(1993a) Identification of coal formed gas and oil type gas by light hydrocarbons. Petroleum Exploration and Development 20(5): 26–32.

Dai

(1993b) Characteristics of carbon and hydrogen isotopic and identification of gas. Natural Gas Geoscience 4(3): 1–40.

Dai

(1994) Study on carbon isotopic of the light hydrocarbon monomer of the major oil-and gas-bearing basins in China. Chinese Science Bulletin 39(22): 2071–2073.

Dai

Pei

(1992) Natural Gas Geology of China. Volume 1, Beijing: Petroleum Industry Press (in Chinese).

Dai

Song

(1985) On the indicators for identifying gas from oil and gas from coal measure. Acta Petrolei Sinica 6(2): 31–38.

Dai

Xia

Qin

(2004) Origins of partially reversed alkane δ¹³C values for biogenic gases in China. Organic Geochemistry 35(4): 405–411.

Gang

Lin

(2011) Application of Oil and Gas Geochemistry, Beijing: Petroleum Industry Press (in Chinese).

10.

Guo

Wang

(2009) Application of light hydrocarbon parameters in geochemical analysis of hydrocarbon accumulation. Special Oil and Gas Reservoirs 16(5): 5–9.

11.

Halpern

(1995) Development and applications of light-hydrocarbon-based star diagrams. AAPG Bulletin 79(6): 801–815.

12.

Zhang

(1990) The development and application of fingerprint parameters for hydrocarbons absorbed by source rocks and light hydrocarbons in natural gases. Petroleum Geology and Experiment 12(4): 375–394.

13.

(2007) Preliminary study on the origin identification of natural gas by parameters of light hydrocarbon. Science in China: Series D 37(A02): 111–117.

14.

Huang

Wang

(2014) Geochemical identification of marine and terrigenous condensates—A case study from the Sichuan Basin, SW China. Organic Geochemistry 74: 44–58.

15.

Lan

Zhang

Tao

(2011) Sedimentary characteristics and evolution of the Upper Carboniferous Taiyuan formation, Shenmu gas field, northeastern Ordos Basin. Acta Geologica Sinica 85(4): 533–542.

16.

Leythaeuser

Schaefer

Cornford

(1979) Generation and migration of light hydrocarbon (C₂-C₇) in sedimentary basin. Organic Geochemistry 1(4): 191–204.

17.

Lin

(1990) Application of Light Hydrocarbon Technology in Oil and Gas Exploration, Beijing: China University of Geosciences Press (in Chinese).

18.

Liu

Zhao

Sun

(2009) Tectonic background of Ordos Basin and its controlling role for basin evolution and energy mineral deposits. Energy Exploration and Exploitation 27(1): 15–27.

19.

Liu

Huang

(2015) Using light hydrocarbons to identify the depositional environment of source rocks in the Ordos Basin, central China. Energy Exploration and Exploitation 33(6): 869–890.

20.

Mango

(1987) An invariance in the isoheptanes of petroleum. Science 237(4814): 514–517.

21.

Mango

(1990a) The origin of light cycloalkanes in petroleum. Geochimica et Cosmochimica Acta 54(1): 23–27.

22.

Mango

(1990b) The origin of light hydrocarbons in petroleum: A kinetic test of the steady-state catalytic hypothesis. Geochimica et Cosmochimica Acta 54(5): 1315–1323.

23.

Mango

(1997) The light hydrocarbons in petroleum review. Organic Geochemistry 26(7): 417–440.

24.

Meng

Zhang

Feng

(2013) Gas accumulation conditions of the Permian Taiyuan Formation in Shenmu gas field, Ordos Basin. Oil and Gas Geology 34(1): 37–41.

25.

Odden

(1999) A study of natural and artificially generated light hydrocarbons (C4–C13) in source rocks and petroleum fluids from offshore Mid-Norway and the southernmost Norwegian and Danish sectors. Marine and Petroleum Geology 16(8): 747–770.

26.

Qin

Guo

Wang

(1991) Geochemical characteristics of Suqiao coal-formed gas field and their contrast. Natural Gas Industry 11(5): 21–26.

27.

Shen

Wang

(2010) Geochemical characteristics of light hydrocarbons in natural gases from the Turpan-Hami Basin and identification of low-mature gas. Chinese Science Bulletin 55(23): 2307–2311.

28.

Shen

Wang

Liu

(2011) Geochemical characteristics of light hydrocarbon in natural gas in the middle member of the west Sichuan Depression, China. Journal of Chengdu University of Technology: Science and Technology Edition 38(5): 500–506.

29.

Snowdon

Powell

(1982) Immature oil and condensate-Modification of hydrocarbon generation model for terrestrial organic matter. AAPG Bulletin 66(6): 755–788.

30.

Ten Haven

(1996) Applications and limitations of Mango's light hydrocarbon parameters in petroleum correlation studies. Organic Geochemistry 24(10/11): 957–976.

31.

Thompson

(1983) Classification and thermal history of petroleum based on light hydrocarbons. Geochimica et Cosmochimica Acta 47(2): 303–316.

32.

Thompson KFM (1987) Fractionated aromatic petroleums and the generation of gas-condensates. Organic Geochemistry 11(87): 573–590.

33.

Yang

Liu

Yan

(2015) The Shenmu Gas Field in the Ordos Basin: Its discovery and reservoir-forming geological characteristics. Natural Gas Industry 35(6): 1–13.

34.

Gong

Huang

(2014) Characteristics of light hydrocarbons of tight gases and its application in the Sulige gas field, Ordos basin, China. Energy Exploration and Exploitation 32(1): 211–226.

35.

Tian

(2013) The characteristics of light hydrocarbon in oil-associated gas and its application in platform area of Tarim Basin. Natural Gas Geoscience 24(4): 774–783.

36.

Zhu

Zhang

(1999) Applications of Mango’s light hydrocarbon parameters in classification of oils from Tarim basin. Geochimica 28(1): 26–33.

Light hydrocarbon geochemical characteristics and their application in Upper Paleozoic,Shenmu gas field,Ordos Basin

Abstract

Keywords

Introduction

Regional geologic setting and samples

Light hydrocarbon geochemical characteristics and their application

Natural gas types

MCH index

Alkane index

Triangular plot of light hydrocarbons

Correlation of natural gas source rocks

K1 and K2 parameter

Star chart of Halpern

Types of source rocks

Natural gas maturity

Study on preservation conditions

Conclusions

Authors' note

Footnotes

Acknowledgments

Declaration of conflicting interests

Funding

Appendix

References

K₁ and K₂ parameter