Controlling factors for the accumulation and enrichment of tight sandstone gas in the Xujiahe Formation,Guang’an Area,Sichuan Basin

Abstract

Tight sandstone gas characterized by a wide distribution, local enrichment and a complex gas–water distribution has high exploration potential. This study, using the Xujiahe Formation in the Guang’an gas field as an example, aims to determine the main controlling factors of the enrichment of tight gas through comprehensive analyses of the source rock and reservoir characteristics, pressure evolution and structural effects by using various methods including well logging, geochemistry, mercury injection, reservoir physical properties and formation pressure. The results show that the proximal-source, interbedded hydrocarbon accumulation results from a dispersed hydrocarbon supply, which is the root cause of the widely distributed tight sandstone gas. The abnormally high reservoir pressure caused the enrichment of tight sandstone gas even under insufficient hydrocarbon generation dynamics; in addition, natural gas preferentially accumulated in the relatively high-quality reservoirs under the same hydrocarbon supply, which means that differences in the reservoir physical properties control gas charge in the reservoir. Structure controls the gas–water differentiation under the stable tectonic background, and the higher the structure is, the more abundant the gas–water differentiation is, and the easier pure gas reservoirs form. Therefore, the accumulation and enrichment of tight sandstone gas in the Xujiahe Formation is controlled by source rocks, abnormally high reservoir pressure and the physical properties and structure of the reservoir.

Keywords

Guang’an area Xujiahe Formation tight sandstone gas abnormally high reservoir pressure reservoir structure main controlling factors

Introduction

Tight sandstone gas, with its organic-rich source rocks and wide distribution, has become a focus of unconventional gas exploration (Chen et al., 2014, 2015; Jia, 2017; Law, 2002; Lu et al., 2017; Ma et al., 2009; Qin et al., 2017; Wei et al., 2017; Zou et al., 2009a, 2012, 2014, 2015; Wei et al., 2016). Xujiahe Formation of the Sichuan Basin contains typical tight sandstone gas and has been developed by many fields, such as Bajiaochang, Chongxi, Moxi, Guang’an, Hechuan and Anyue, with proven natural gas reserves of over 3000 × 10⁸ m³ (Bian et al., 2009; Li and Qin, 2012; Wang and Lin, 2017; Zheng et al., 2017). Of these gas fields, Guang’an is the most significant due to the exploration and development of Members 4 and 6 of the Xujiahe Formation, with proven reserves of 566 × 10⁸ and 788 × 10⁸ m³, respectively (Shang et al., 2016; Xie et al., 2008).

However, many problems remain in the exploration and development of the Xujiahe Formation in the Guang’an gas field. The natural gas of the Xujiahe Formation is widely distributed but accumulates locally without unified systems or clear interfaces between gas and water. Much research has been performed on tight sandstone gas in the Xujiahe Formation, closely focusing on the natural gas source (Dai et al., 2009; Li et al., 2007; Wang et al., 2013), reservoir characteristics (Chen et al., 2016; Shi et al., 2008; Xie et al., 2008; Zhu et al., 2009) and accumulation mechanisms (Zhao et al., 2010). However, few systematic studies have been performed on the controlling factors of the local accumulation of tight sandstone gas in the Xujiahe Formation. Therefore, this study uses the Guang’an gas field as an example and aims to determine the controlling factors of the enrichment of tight sandstone gas through a comprehensive study on hydrocarbon source rocks, reservoirs, structural amplitude and gas-source correlation to provide guidance on further exploration and development of tight sandstone gas.

Geological setting

The Guang’an gas field, with an exploration area of 5100 km², lies in the central part of the Sichuan Basin east of Nanchong, south of Yingshan, west of Huaying Mountain and north of Hechuan (Figure 1). In terms of tectonics, Guang’an gas field is in the northeastern part of the palaeohigh gentle tectonic belt, which is located in the middle of the Sichuan Basin at the intersection of the Leshan-Longnvsi palaeohigh, Huaying Mountain and the Daba Mountains fold belt (Wang et al., 2002).

Figure 1.

Location map of study area.

The Sichuan Basin formed by long-term joint tectonism that occurred in the Upper Yangtze area during development of the Tethyan tectonic domain, Qinling structural belt and Pacific Ocean tectonic domain from the period of Indonesian plate movements to the period of Himalayan plate movements Continental deposition of the Upper Yangtze area occurred in the early period, with the original basin being altered during the later multi-level, multi-period progressive compression, leading to the formation of the tectonic basin in the late stage of Himalayan plate movements. A major period of change in the tectonic structure of the Upper Yangtze area occurred in the period of Indonesian plate movements when the tectonic movement changed from tension to twist compression. Major compressive folding occurred in the Longmen Mountains, Daba Mountains and Hu’nan-Guangxi area after the Middle Triassic. This compressive folding resulted in the end of marine sediment deposition in the basin and the conversion to terrestrial clastic deposition of the Xujiahe Formation in the Late Triassic (Li et al., 2010; 2014).

The Xujiahe Formation of the Sichuan Basin is a set of terrigenous lacustrine shallow-water delta sedimentary systems with a stable depth of 1800–2500 m (Yang and Zhu, 2013). The top is conformable to the Jurassic Ziliujing Formation, and the bottom is unconformable to the Middle Triassic Leikoupo Formation. The layers can be divided into six members from bottom to top (Figure 2), of which Members 1, 3 and 5 are the main cap and gas source rocks. The layers consist of lacustrine mud sediments with mainly mudstones, fine sandstone and coal seams as intermediate rocks. Members 2, 4 and 6 are the main reservoirs, where coast and shallow lake–delta sedimentary systems developed. The low-porosity, low-permeability and heterogeneous layers are composed of fine- to medium-grained lithic sandstone, with minor shale and coal intercalations. In terms of the flat tectonic setting, a downlap and onlap pattern reflects the extensive interphase distribution of Members 1, 3 and 5 and Members 2, 4 and 6, which greatly contributed to the accumulation of the Xujiahe Formation in the Sichuan Basin (Yang et al., 2010).

Figure 2.

Stratigraphy column of the Xujiahe Formation in the Central Sichuan Basin.

Samples and experimental methods

A total of 118 samples from the Xujiahe Formation in the Guang’an area were collected, consisting of 30 source rock samples (10 each from Xu-1, 3 and 5), 50 reservoir samples (Member 6 of the Xujiahe Formation) and 38 natural gas samples. In addition, data on the physical properties of 211 reservoir samples from Member 6 and carbon isotopes of 15 natural gas samples from other layers were collected from previous studies. Analyses of organic carbon in the source rocks, elemental composition of kerogen, vitrinite reflectance, composition and carbon isotopes of natural gas and mercury intrusion of the reservoirs were performed on these samples.

The source rock, natural gas and mercury intrusion analyses were performed in the Sichuan Key Laboratory of Natural Gas, Southwest Petroleum University. Total organic carbon (TOC) of the source rocks was measured by an organic carbon sulphur analyser (CS230SH), Ro analysis was performed by a vitrinite reflectance tester (DM4500P + QDI308), and the kerogen composition was measured by an elemental analyser (EA2400 II, USA). The hydrocarbon composition of natural gas was estimated by a gas chromatograph (HP5890 II, 0.53 mm × 50 m, with helium as the carrier gas) equipped with a flame ionization detector and a thermal conductivity detector. Carbon isotopes of natural gas were estimated by a gas isotope ratio mass spectrometer (MAT 252, 24°C, 55% RH); the capillary column (HP-PLOTQ, 30 mm × 0.32 mm × 20.0 µm) was chosen with highly purified helium as the carrier gas. Mercury intrusion of the reservoir samples (2.5 cm × 3.5 cm) was carried out by an automatic mercury pressure metre PoreMaster 60 in the Key Laboratory of Oil and Gas Reservoir Geology and Development Engineering in Southwest Petroleum University.

Results and discussion

Source rock characteristics

The Xujiahe Formation source rocks are composed of mudstone and coal seams within Members 1, 3 and 5 (Zhao et al.,2011). Of those Members, Member 1 developed in the western central Sichuan Basin and contains residual estuarine facies, while Members 3 and 5 are widely developed in the central part and contain limnetic facies. Dark mudstone over 130 m and coal seams over 3 m are distributed in multilayers with abundant organic carbon, which is mainly humic type and at a mature to early high-mature stage. Overall, Member 5 performed best, and Member 1 performed worst, with a total gas intensity less than 20 × 10⁸ m³/km² (Zou et al., 2009b).

The abundance of organic matter is important in the evaluation of source rocks by the quantitative content of organic carbon. The lower limit value of organic carbon is from 0.4% to 0.5% globally and 0.5% in China. Analyses of the 30 source rock samples showed that the content of organic carbon in Member 1 ranged from 0.61% to 2.54%, with an average of 1.11%, Member 3 ranged from 0.49% to 2.83%, with an average of 1.23% and Member 5 ranged from 0.59% to 2.97%, with an average of 1.66%, which indicates better hydrocarbon generation potential than that of Members 1 or 3.

Stable carbon isotopes vary in different organisms from distinct sources and environments, and light carbon isotopes occur in aquatic organisms and lipids. According to the experiments, the carbon isotopes of kerogen, an effective indicator for the evaluation of organic matter type (Tissot and Durand, 1974), ranged from −29.17% to −24.38%, with an average of −26.48%, and H/C was below 1, indicating type III and partial humic-type organic matter.

Ro, as the best indicator of organic matter maturity, was relatively high in the Xujiahe Formation, from 1.02% to 1.53%, indicating mature to early high-mature organic matter (Table 1).

Table 1.

Experimental data of source rocks in studied area.

Well	Formation	TOC (%)	Ro (%)	δ¹³C (‰)
GA1	T₃x₅	2.18	1.42	−28.82
	T₃x₃	0.97	1.49	−28.82
	T₃x₁	0.73	1.53	−29.17
GA2	T₃x₅	0.96	1.37	−24.38
	T₃x₃	1.11	1.42	−25.58
	T₃x₁	1.36	1.48	−25.02
GA3	T₃x₅	2.97	1.12	−27.54
	T₃x₃	1.35	1.28	−25.47
	T₃x₁	1.08	1.39	−25.71
GA12	T₃x₅	2.12	1.22	−26.53
	T₃x₃	1.11	1.26	−26.32
	T₃x₁	2.54	1.39	−28.34
GA13	T₃x₅	1.79	1.34	−26.12
	T₃x₃	2.83	1.38	−26.14
	T₃x₁	1.24	1.47	−26.38
GA101	T₃x₅	1.23	1.28	−25.11
	T₃x₃	0.49	1.36	−26.01
	T₃x₁	0.74	1.39	−26.57
GA102	T₃x₅	1.31	1.41	−27.13
	T₃x₃	2.04	1.44	−26.37
	T₃x₁	0.83	1.50	−27.11
GA107	T₃x₅	0.59	1.18	−25.34
	T₃x₃	0.72	1.27	−27.01
	T₃x₁	1.05	1.34	−26.93
GA111	T₃x₅	1.89	1.02	−25.44
	T₃x₃	1.08	1.22	−25.61
	T₃x₁	0.61	1.29	−26.46
GA112	T₃x₅	1.56	1.36	−26.26
	T₃x₃	0.6	1.38	−25.87
	T₃x₁	0.92	1.41	−26.87

As a result, the Xujiahe Formation source rocks are thick, have high gas generation potential, and developed mainly from humic organic matter with a high abundance of mature to early high-mature organic matter.

Reservoir characteristics

The reservoir sands of the Xujiahe Formation mainly consist of delta plain distributary channels, underwater distributary channels and few delta front estuaries. Member 6 is composed of litharenite, feldspar lithic sandstone and lithic quartz sandstone with features of low component maturity, namely, 62% quartz, 11% feldspar and 27% debris.

The statistical data of 211 reservoir samples revealed low-porosity and low-permeability reservoirs with local high-porosity and high-permeability hot spots (Figure 3). The porosity ranged from 0.01% to 18.74%, with an average of 5.05%, while the permeability ranged from 0.01 × 10⁻³ µm² to 0.05 × 10⁻³ µm², with an average of 0.18 × 10⁻³ µm².

Figure 3.

Casting sheet micrographs of Xu-6 reservoir in Guang’an area. (a) Well Guang’an 101, Xu-6, 2079.43 m, lithic sandstone; (b) Well Guang’an 123, Xu-6, 2098.51 m, feldspar lithic sandstone; (c) Well Guang’an 101, Xu-6, 2081.25 m, feldspathic quartz sandstone; (d) Well Guang’an 108, Xu-6, 1935.82 m, feldspar lithic sandstone.

Source of natural gas

The carbon isotope composition of natural gas is closely related to the parent type and maturity of source rocks and plays an important role in determining the source of natural gas. Detailed stable isotopic analyses of 12 gas samples (Table 2) show that natural gas in the study area exhibited the order of δ¹³C₁ < δ¹³C₂ < δ¹³C₃ < δ¹³C₄ and was definitely organically derived gas. In addition, natural gas in the Xujiahe Formation is typically coaliferous gas without mixed sources based on the distribution of ethane carbon isotopes (from −27.34% to −24.19%, with an average of −26.11%) and the standard for identifying genetic types of natural gas (petroliferous gas, δ¹³C₂ < −29%; coaliferous gas, δ¹³C₂ > −27.5%; mixed gas, −29% < δ¹³C₂ < −27.5%) (Dai, 1992). Furthermore, natural gas in the Upper Triassic Xujiahe Formation is likely self-generated and self-accumulated from humic source rocks, as the carbon isotopes of both methane and ethane in the Xujiahe Formation is different from those in other strata (Figure 4). In addition, the natural gases in Members 6 and 4 did not mix, since the carbon isotopes of methane and ethane in Member 4 are both higher than those in Member 6, indicating a higher maturity of the source rocks in Member 4.

Table 2.

Natural gas carbon isotopes of Members 4 and 6 of the Xujiahe Formation, Guang’an area.

Well	Formation	δ¹³C₁ (‰)	δ¹³C₂ (‰)	δ¹³C₃ (‰)	δ¹³C₄ (‰)
GA1	T₃x₆	−40.25	−27.34	−25.05	−23.85
GA2	T₃x₆	−39.7	−26.58	−25.24	−23.99
GA7	T₃x₆	−42.49	−27.18	−24.2	−23.79
GA11	T₃x₆	−41.09	−27.37	−22.7	−23.65
GA12	T₃x₆	−40.75	−25.52	−23.11	−22.9
GA15	T₃x₆	−42.35	−27.82	−25.9	−25.63
GA101	T₃x₆	−39.22	−26.22	−25.1	−23.6
GA3	T₃x₄	−37.68	−24.19	−22.12	−20.39
GA5	T₃x₄	−37.2	−24.97	−23.7	−22.17
GA12	T₃x₄	−36.17	−25.67	−22.47	−21.41
GA13	T₃x₄	−38.21	−24.52	−21.35	−19.56
GA14	T₃x₄	−37.02	−25.95	−21.18	−20.51

Figure 4.

Carbon isotopes of methane and ethane of different strata in Central Basin (Li et al., 2007). (1) Jurassic in Guang’an; (2) Member 6 in Guang’an; (3) Member 4 in Guang’an; (4) Leikoupo formation in Moxi; (5) Sinian in Weiyuan.

The components of natural gas are the most important and reliable proof used to determine the source and type of natural gas. The natural gas from Xujiahe is mainly hydrocarbon gas with a high methane content and low heavy hydrocarbon content. Based on the analyses of 38 gas samples, the methane content, heavy hydrocarbons and gas dryness coefficient differed between Members 6 and 4, with a trend of higher methane and dryness coefficient values but lower heavy hydrocarbons in Member 4 than in Member 6. The methane content of Member 6 ranged from 85.98% to 93.92%, with an average of 89.36%, while that of Member 4 was relatively higher from 91.35% to 94.71%, with an average of 92.66%. The heavy hydrocarbon content in Member 6 ranged from 6.08% to 14.02%, with an average of 9.94%, while that in Member 4 ranged from 5.29% to 9.43%, with an average of 6.61%. The gas dryness coefficient of Member 4 (0.94) was slightly higher than that of Member 6 (0.91). These regular changes in compositions in different strata indicate the differences in the natural gas sources of distinct strata and no mixture between the strata.

The residual light hydrocarbon in the source rock has a certain correlation with the light hydrocarbon generated by the source rock. Therefore, the correlation of light hydrocarbon between source rocks and oil and gas reservoirs is often used for gas-source correlation. From the comparative analysis of the light hydrocarbons of natural gas in the reservoirs and source rocks of the Guang’an area (Figure 5), the Xu-4 natural gas reservoir is similar to the Xu-3 hydrocarbon source rocks, while the Xu-6 natural gas reservoir is similar to the Xu-5 hydrocarbon source rocks. The comparison of the light hydrocarbon fingerprint of the source rocks and natural gas reservoirs shows that Xu-4 gas mainly comes from Xu-3 source rocks, while Xu-6 natural gas comes from Xu-5 source rocks, which is consistent with the results of the above analysis.

Figure 5.

Light hydrocarbon characteristics of natural gas and source rocks of Xujiahe Formation in Guang’an area. (a) Isohexane/n-hexane; (b) methyl cyclohexane/n-heptane; (c) methyl cyclohexane/isoheptane; (d) 2-methyl pentane/3-methyl pentane; (e) cyclopentane/2,3-dimethyl butane; (f) n-hexane/(methyl cyclopentane + 2,2-dimethyl pentane).

Main controlling factors of accumulation

Small, widely distributed gas reservoirs under the control of a distributed hydrocarbon supply

The key causes of the formation of small, widely distributed tight gas reservoirs in the study area are the ‘sandwich’ accumulation and scattered pressure difference between the source and the reservoir under stable tectonic conditions. The supplying hydrocarbon was very uniform, and each gas reservoir was supplied directly by the underlying source rock.

Despite their sizeable thickness, the source rocks have a vertically discontinuous distribution with interbedded thin sandstone. The well-tie section (Figure 6) revealed that the source rocks in Member 5 were discontinuous and developed with interactive reservoirs, resulting in an insufficient gas supply to a single reservoir, low gas saturation and a complicated gas–water distribution due to high inhomogeneity. The gas saturation in the reservoir is closely related to the thickness of the source rocks. Member 6 comprises the highest gas saturation (generally over 50%) due to the thickness of Member 5 (>110 m). Member 4 has high water production (water saturation is approximately 30%); however, Member 2 has low gas production because Member 1 contains the thinnest source rocks.

Figure 6.

Connecting-well section of Member 5 source rocks of the Xujiahe Formation, Guang’an. GR: Natural gamma logging, API; Rt: Resistivity well logging, Ω*m.

Relationship between pressure evolution and hydrocarbon accumulation

Analysis of formation pressure test data shows that the abnormally high pressure of the Xujiahe Formation is common in the central Sichuan Basin. According to the standard of pressure division put forward by Hao Fang and others, the formation pressure in the central Sichuan Basin can be divided into three types (Figure 7(a)): (1) normal pressure section: the pressure coefficient is between 0.90 and 1.10, including the Hebaochang and Weiyuan gas reservoirs; (2) high-pressure section: the pressure coefficient is between 1.1 and 1.4, including most gas reservoirs in the Guang’an and Hechuan areas; and (3) ultra-high-pressure section: the pressure coefficient is greater than 1.4, such as gas reservoirs in Chongxi and Bajiaochang. Previous studies on the genesis of abnormally high pressure in the Xujiahe Formation, Sichuan Basin, are more in-depth. Tectonic compression is generally believed to be the main cause of the overpressure of the Xujiahe Formation in the western Sichuan Basin (Gao et al., 2004; Yang et al., 2003), and the formation of abnormally high pressure in central Sichuan Basin is mainly related to hydrocarbon generation pressure (Hao et al., 2011; Ma et al., 2011).

Figure 7.

Abnormal pressure distribution and evolution in central Sichuan Basin (Hao et al., 2010; Ma et al., 2011). (a) Pressure coefficient of gas fields of Xujiahe Formation; and (b) relationship between hydrocarbon accumulation and pressure evolution of Well Hechuan-1.

The timing of abnormal high-pressure evolution in reservoirs plays an important role in oil–gas accumulation. The reservoir of the Xujiahe Formation in the Guang’an area is tight with high heterogeneity, and hence, the development of abnormally high pressure is beneficial to the migration and accumulation of oil and gas. A previous study on the reservoir of the Guang’an gas field shows that the reservoir of the Xujiahe Formation is relatively developed with tight intercalation, high reservoir heterogeneity and superposition and development of various genetic sand bodies (Jiang, 2009; Zou et al., 2009b). The tight intercalation displacement pressure (0.94–8.38 MPa) is much larger than that of the reservoir displacement pressure (0.34–1.32 MPa), and the charging of natural gas must overcome the tight interlayers between reservoirs and needs a higher formation pressure, so the abnormally high pressure is beneficial to the migration and accumulation of natural gas. In addition, through the simulation analysis of pressure and hydrocarbon generation evolution in the central Sichuan Basin (Figure 7(b)), the formation pressure evolution of the Xujiahe Formation has a good correlation with hydrocarbon generation evolution and tectonic evolution of source rocks. With increasing source rock evolution, formation pressure gradually increases. Under the influence of Himalayan movement, uplift and denudation of strata and pressure release are beneficial to the desorption of water-soluble gas and the resolution of coalbed gas, thus improving the efficiency of natural gas accumulation and developing a series of large-scale gas fields in the central Sichuan Basin under the conditions of an insufficient gas source (Chen et al., 2007; Ma et al., 2011).

Control of the physical properties of reservoirs on gas charge

Pore throat size largely contributes to gas floating in sandstone reservoirs. This means that floating is key in large pore throats of high-permeability sandstone, while capillary force is integral to small pore throats for tight sandstone reservoirs (Cook et al., 2011; Nelson, 2009). Therefore, for tight sandstone gas reservoirs in the central basin, density is important for gas–water transition zones without interfaces.

The Xujiahe Formation consists of a set of delta sediments with low-porosity, low-permeability and highly inhomogeneous reservoirs accompanied with high-quality sweet spots such as water distributary channels in delta plains (Xu et al., 2014). Based on current exploration, high-yield wells are mainly distributed in superposed areas of high-quality main channels, revealing a good correlation between gas-bearing sandstone and reservoirs and the strong control of physical properties on gas charge (Figure 8).

Figure 8.

Physical property distribution of gas-bearing and non–gas-bearing layers of Member 6 of Xujiahe Formation in Well Guang’an-101.

Delta plain channels in the Xujiahe Formation are the main reservoirs, and these reservoirs are concentrated in Members 2, 4 and 6 as multiple sets of thick, vertically superimposed reservoirs, with a wide distribution and high inhomogeneity. Sedimentary microfacies control the physical properties of reservoirs and then the enrichment of natural gas. Using Well Guang’an-101 as an example, there are significant differences among the intervals from 2010 to 2087 m, even though these intervals have the same sandstone lithology. The upper part of Member 6 (2010–2026 m) in Well Guang’an-101 contains the worst properties (average porosity is 4.31%, and permeability is almost below 0.1 × 10⁻³ µm²) and well tests show water production from the fine-grained sandstone of the channel flank. However, the lower part (2026–2087 m) is much better (average porosity is 10.56% and permeability is almost over 0.1 × 10⁻³ µm²) and significantly contributes to the gas production, with 2.51 × 10⁴ m³/d of daily gas production from the sedimentary sand body of the channel flank.

The gas-bearing intervals in Well Guang’an-108 are similar to those in Well Guang’an-101 (Figure 9). Even with the same sandstone lithology, large differences exist among the intervals from 1930.84 to 1955.31 m of Member 6. In the bottom (1952.45–1955.31 m) and top (1930.84–1938.67 m) intervals, the layers mainly produce from the sedimentary sand body of the channel flank, with a high replacement pressure of 1.61 MPa on average and worse properties. However, well tests show that the middle intervals (1938.67–1952.45 m) are the gas-bearing layers with 10.58 × 10⁴ m³ of daily gas owing to the better properties and low replacement pressure of 0.54 MPa on average, which indicates that the enrichment of natural gas is controlled by the physical properties of the reservoirs.

Figure 9.

Comprehensive interpretation picture of Well Guang’an-108. AC: acoustic logging, us/ft.

Variability in the physical properties is an important factor in complex gas–water distributions and local accumulations of tight sandstone gas under such high inhomogeneity. This is because the distribution and accumulation of hydrocarbons in favourable reservoirs are based on effective source rocks, tectonic background and migration systems. The high inhomogeneity, resulting from multiple sets of superimposed sandstone from the frequent lateral migration of channels, allows for the migration of natural gas into high-porosity and high-permeability hot spots and makes for much more complete gas–water differentiation.

Control of structure on the gas–water distribution

Reservoir structure controls the gas–water distribution in the background of low structures coupled with favourable reservoir properties and source rocks. The higher the structure is, the better the gas–water differentiation, and pure gas reservoirs are easily developed. Abundant natural gas reserves in the low slopes of Guang’an cover an area of approximately 1.5 × 10⁸ m³/km², with water saturation up to 50–60% in the co-production of gas and water (e.g. Well(s) Guang’an-101 and 107); however, in the structurally high areas, the area is up to 3.5 × 10⁸ m³/km², with low water saturation in high-yield wells (e.g. Well Guang’an-2) (Figure 10).

Figure 10.

Profile map of gas reservoir distribution in Member 6 of Xujiahe Formation in Guang’an area.

Gas–water distribution is controlled not only by physical properties but also by structure, and the latter is much more important. Wells Guang’an-103 and 101 contain gas from the same source rocks with similar lithologies and thicknesses. Well Guang’an-103 possesses a similar porosity and lower permeability than 101 (Guang’an-101, 2026.7–2085.6 m, porosity 8.73%, permeability 2.501 mD; Guang’an-103, 1769.8–1829.5, porosity 8.1%, permeability 1.509 mD) but produces pure gas (1.569 × 10⁴ m³ of daily gas) because of its high structural position.

Based on the theory of gravitative differentiation, movable water can be expelled by the net buoyancy of gas (oil) over capillary pressure to form a gas (oil)–water interface in low-porosity and low-permeability layers. The degree of gas–water distribution is controlled by the structure and physical properties of reservoirs because of the wide range and multiple levels of the pore throats (Tao et al., 2016). Better physical properties lead to a higher amplitude and a higher gas–water differentiation degree, which adds to the possibility of forming pure gas reservoirs (Figure 11).

Figure 11.

The differentiation principle of low-porosity and low-permeability reservoirs (PetroChina Southwest Oil and Gas Company).

In theory, transition zone heights, which can be calculated from different physical properties that form pure gas reservoirs, vary widely (Table 3). Equation (1) can be used to calculate the transition zone height of the T₃x₆ gas reservoirs in the Guang’an gas field.

h = \frac{P_{c}}{(ρ_{w} - ρ_{g}) g}

(1)

where h is height of gas–water transition zone, m; P_c is capillary pressure, MPa; ρ_w – ρ_g: gas–water density difference, kg/m³; and g is acceleration of gravity.

Table 3.

Trap depth of pure gas column by different types of reservoirs in Guang’an area.

Reservoir type	Porosity (％)	Sample numbers	Trap height of pure gas column (m)
Reservoir type	Porosity (％)	Sample numbers	Range	Average
I	12	20	8–53	31
II	9.2	8	45–161	107
III	6.8	27	96–280	186

Wells Guang’an-2, 103, Guang-19 and 51 are located in all pure gas based on well tests. The Daxingchang Formation has type I and II reservoirs (length: 18.23 km; width: 3.69 km) with a closing height of 147 m, which satisfies the required height of pure gas traps. However, other zones in the Guang’an area are different, with complicated gas–water distributions.

Above all, large-area interbedded source rocks and thin sandstone, ‘sandwich’ accumulation (transgressive and regressive) and scattered supply are important for small, widely distributed tight sandstone gas. Moreover, high-yield wells usually develop in the structurally low superimposed sand bodies of main channels due to effective source rocks and migration systems.

Conclusions

Natural gas in the Xujiahe Formation of the Guang’an area is characterized by self-generation, self-storage and source-proximal interbedded hydrocarbon accumulations. From Xu-4 to Xu-6, the amount of methane and heavy hydrocarbons in the natural gas decrease, and the gas drying coefficient decreases. In addition, the light hydrocarbons in the gas show similar characteristics to the nearby strata, which means that the Xu-6 natural gas is sourced from Xu-5 source rocks and the Xu-4 gas is from Xu-3 source rocks.

The enrichment of tight gas in the Xujiahe Formation is controlled by source rocks, abnormally high pressure, physical properties and structure. The proximal-source, interbedded hydrocarbon accumulation results in a large but locally accumulated distribution. Abnormal pressure causes gas migration and accumulation under insufficient hydrocarbon generation dynamics. In addition, natural gas is preferentially accumulated into relatively high-quality reservoirs under the same hydrocarbon supply, which means that the differences in reservoir physical properties control the gas charge in the reservoir. In addition, structure controls the gas–water differentiation under the gentle tectonic background, and the higher the structure is, the more abundant the gas–water differentiation is, and the easier it is to form pure gas reservoirs.

Footnotes

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) disclosed receipt of the following financial support for the research, authorship, and/or publication of this article: This research was supported by the National Key Basic Research and Development Plan ‘973’ (no. 2014CB239005), National Natural Science Foundation of China (nos. 41502146 and 41572137), National Science and Technology Major Project (nos. 2016ZX05007003-007 and 2017ZX05001002-003) and Southwest Petroleum University funding plan of oil and gas accumulation geochemistry for Youth Science and Technology innovation team (no. 2015CXTD02).

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