Physical Properties of Hydrocarbon Source Reservoir in the Lucaogou Formation in Junggar Basin (China) and Its Influence on Adsorption Ability and Surface Free Energy

Abstract

A physical property of a shale gas reservoir affects shale gas content, then restricts the shale gas resource potential. In this paper, lithofacies and spatial distribution of the southern margin of the Junggar Basin in Xinjiang Province are identified and occurrence strata, gas content, and reservoir properties of shale gas are studied. Based on adsorption potential theory, adsorption and surface free energy of all the sample is discussed. The conclusions are as follows. (1) All the shale samples can be divided into five lithological phases. For example, black oil shale/shale (lithology) phase and gray-black-gray/dolomite mudstone (lithology) phase are the most developed; compared with the middle and lower sections, the vertical development continuity of the upper hydrocarbon source rock is better. Lithology of this section is mainly composed of shale mixed with marlstone and dolomite interlayer. From the horizontal view of this section, the overall trend is gradually thickening from west to east and from north to south. (2) Semi-deep lake-phase is the most developed, indicating a decreasing trend of thickness from sedimentary center to surrounding strata. (3) Sedimentary period of Lucaogou Formation is a deep water area of the lake basin; then, the TOC content is affected by the sedimentary environment. As sedimentary water depth increases, TOC content will increase, which results in the highest TOC content in the area. A specific surface area is roughly positively correlated with porosity, clay mineral content, and percentage of illite/montmorillonite interlayer ratio and negatively correlated with TOC content. (4) During the adsorption process, adsorption potential decreases with an increase in equilibrium pressure, and adsorption space increases with an increase in equilibrium pressure. Maximum adsorption space of all the sample were 0.20~0.25 cm³·g⁻¹; then, its value is larger than the maximum adsorption space of other coal samples (0.025~0.20 cm³·g⁻¹). In the same adsorption space, the corresponding adsorption potential of the coal sample is much larger than that of other samples. The reason is that the porosity permeability of this sample is relatively larger, leading to its better physical properties.

1. Introduction

At present, the Southern margin of Junggar Basin in Xinjiang Province is enriched in unconventional oil and gas resources, such as shale gas, coalbed methane, oil shale, etc. Upper Permian Lucaogou Formation is mainly composed of carboniferous and carboniferous terrigenous clastic fine-grained sedimentary rocks, some of which are mixed with carbonate rocks, and is an important regional source of rock [1,2,3,4]. The relevant literature also indicates that the region has good exploration potential for unconventional oil and gas [5]. It is of great significance for shale gas drainage in this area to accurately describe the basic physical properties of source rocks under specific strata [6,7,8,9].

Research on the accumulation and occurrence characteristics of coal-measure source rocks of Junggar Basin in Xinjiang Province was carried out by means of drilling, outcrop, and experimental tests [10,11,12,13,14,15]. Quantitative fluorescence technology was used to conduct fluorescence analysis on shale, tight reservoir, and crude oil of the Lukou Formation, and indicated that hydrocarbons in the upper section have better physical properties and higher thermal maturity. Li [16] found that an enhancement of brittle deformation is more conducive to the migration of shale gas in a later stage. Liang [17] believed that reservoir capacity is affected by the scale, abundance, and connectivity of pore space, which is controlled by lithofacies, mineral composition, TOC content, and microfracture characteristics. Other studies in the literature have conducted physical simulation experiments on the T1b conglomerate reservoir and found that the reservoir in class I had good physical properties. Shale samples are collected in typical areas using scanning electron microscope (SEM) images, and show that pores of different sizes and shapes were distributed in shale samples. Yan [6] suggested that shale pores are composed of intergranular and intragranular pores. Zhang [18] found that the coal measure shale of the Jurassic Badaowan Formation in the Fukang area of Xinjiang contained inner and intergranular pores. Wang [19] studied petrophysical properties of typical continental shale and believed that reservoir spaces of shale are organic pores, intergranular pores of clay minerals, dissolved pores, and micro-fractures [19,20,21,22,23].

After clarifying physical properties of shale reservoirs, adsorption characteristics are beginning to be discussed under physical constraints of reservoirs. Liang [17] used data from drilling and field outcrops to posit that the shale of the Telecula Formation has brittle mineral content and low reservoir properties, which is conducive to the formation and preservation of adsorption gas. Clay–organic complexes were extracted for rock physics and adsorption experiments and indicated that the adsorption capacity of clay–organic complexes was significantly higher than that of conventional shale in a reservoir [24]. Fu [25] concluded that the complexity of smaller pores has a significant effect on CH4 adsorption capacity, while larger pores have almost no effect. Guo [26] demonstrated the adsorption and desorption characteristics of shale through experiments and found that under high pressure, shale permeability increases when gas desorption is enhanced. Liu [27] found that the gas adsorption capacity of organic-rich shale is directly proportional to TOC, clay mineral content, maturity, and pressure, and inversely proportional to quartz content, carbonate minerals, and temperature.

Much research has been conducted on physical properties of shale gas reservoirs in Xinjiang [28,29], but there are still some problems. First of all, there are few studies on source rocks of the Lucaogou Formation which restricts the exploration potential of shale gas resources. Secondly, studies on adsorption characteristics and mechanism of shale reservoirs under a restriction of physical properties are weak, and its influence on surface free energy in the adsorption process needs to be further studied.

Therefore, Upper Permian source rocks in the eastern part of the southern margin of the Junggar Basin are taken as the research object in this paper. According to the contrast of three-dimensional spatial differences, spatial distribution characteristics of source rocks are determined from four aspects: rock mineralogy, reservoir space type, source rock physical properties, and pore structure. On this basis, through organic geochemical characteristics and reservoir characteristics of source rocks in area, change in adsorption capacity under the restriction of reservoir physical properties and the change law of surface free energy in the adsorption process are discussed.

2. Geological Setting and Sample Preparation

2.1. Geological Setting

The tectonic location of the study area is located in the east of the Dahuangshan Dalongkou anticline. Since the Bogda Mountain piedmont thrust belt, the tectonic deformation dominated by compressive stress is relatively developed. In the Lucaogou Formation, deformation from south to north can be seen. Regional and secondary faults are relatively developed in the area, in the east of Junnan thrust belt. A large fold is behind it, namely the Dalongkou Syncline and West Dalongkou Anticline. The Lucaogou Formation in the study area is the main source rock, which can be divided into the upper and middle lower section. Lithology is gray-black, black, and brown-gray lake-phase terrigenous fine clastic rock, oil shale mixed with dolomite, limestone, and phosphoric site, with a thickness of 90–1102 m. It is in conformity with the underlying Upper Permian Jingzigou Formation and overlying Upper Permian Hongyanchi Formation.

2.2. Sample and Experimental Methods

All the samples from the upper, middle, and lower parts of Lucaogou group were tested and the mineral composition and organic geochemical of collected samples were analyzed. Then, FE-SEM tests were used to observe shape and state, and the PCAS software 3.0 was used for analysis. Finally, specific surface area, pore size distribution, and pore volume were studied by the N₂ adsorption method.

All the samples (approximately 15 × 15 × 15 cm³) were collected from one well, with their distribution and parameters shown in Figure 1. Gas porosity (%) and permeability (mD) of the core sample were measured using an Ultrapore-200A helium core porosimeter and CMS-300 Automated Permeameter. Meanwhile, all the samples were polished with red epoxy resin and observed using polarized light microscope technology, then the mineral composition, structure, pore type, and face ratio of the sandstone samples were determined. The mineral composition of each sample was analyzed, and then pore volume, specific surface area and pore size distribution were quantitatively studied using HPMI tests. The analysis scheme is as follows. HPMI analysis was conducted on the samples using an IV9500 mercury intrusion instrument. One hundred twenty pressure points were measured for each sample with an analysis time for each end of 5 s. The working pressure of the mercury intrusion analyses ranged from 0.124 to 270.79 MPa.

TOC experiment. According to National Standard (GB/T 19145-2003) [30], this test was conducted at the Jiangsu Institute of Geology and Mineral Design. In the XRD experiment, clay samples were manually broken into 60–80 pieces, weighing 200 g. A small piece weighing 30 g was taken from the whole rock sample and ground to a total of <200 pieces, which was completed at the test center of the Sinopec East China Branch. The experiment was conducted by using industry standards of SY/T 5163-2010 [31,32,33].

FE-SEM experiments. Small samples after argon ion polishing were selected, then analyzed by Quanta250 scanning electron microscopy. PCAS software adopted by Liu [27] was used to quantitatively analyze FE-SEM photos and identify micropore structures in high-resolution SEM photos.

Isothermal adsorption test. An IS-10 high-pressure gas isotherm adsorption desorption instrument was used to grind 60~80 pieces strictly according to the GB/T 19560-2008 [34] test methods, and 100 g was weighed out and put into the vacuum drying oven. The coal sample was dried at 373 K for 6 h. Methane adsorption experiments were carried out at room temperature and within the measurement pressure range of 0 to 15 MPa. The adsorption equilibrium time at each pressure point shall not be less than 12 h [35,36].

2.3. Isothermal Adsorption Theory and Method

2.3.1. Adsorption Potential and Adsorption Space

The adsorption potential theory is shown in Equation (1)

$$\mathsf{\epsilon }{\int }_{p_i}^{p_0}\frac{RT}{P}{d}_{p}RTln\left(\frac{p_0}{P_i}\right)$$

(1)

where ε is adsorption potential, J·mol⁻¹; P_i is equilibrium pressure, MPa; R is gas constant, 8.314 J (mol·K)⁻¹; T is experimental temperature, 303 K; p₀ is saturated vapor pressure, MPa.

Methane is supercritical at 303 K. The saturated vapor pressure (P₀) is replaced by the supercritical saturated vapor pressure (P_s).

$$P_s=P_c{\left(T/Tc\right)}^2$$

(2)

where P_s is the supercritical saturated vapor pressure, MPa; P_c is the critical pressure of ethane, 4.62 Mpa; Tc is the critical temperature of methane, 190.6 K; T is the experimental temperature, 303 K.

The adsorption space characterizes the microporous structure, which represents space occupied by gas in an adsorption state.

$$\omega =V\frac{M}{p_{ad}}$$

(3)

where ω is a volume of adsorption space, cm³/g; M is relative molecular mass of methane,16 g·mol⁻¹; V is amount of methane adsorption, mol·g⁻¹; p_ad is adsorption phase density, g/cm³.

The adsorption experiment measured excessive adsorption and the theoretical adsorption is absolute adsorption.

$$v_{ad}=\frac{v}{1-\frac{p_g}{p_{ad}}}$$

(4)

where V is amount of methane adsorption under equilibrium pressure (cm³·g⁻¹); T is experimental temperature; p_g is gas phase density at pressure P (g·cm³).

The gas phase density is:

$$p_g=\left(MP\right)/\left(RT\right)$$

(5)

2.3.2. Surface Free Energy

Surface free energy is the increment of system free energy when a unit area of adsorbent is increased under constant temperature and pressure. The results show that a force field on solid surface molecules is asymmetric.

The decreasing value of the surface free energy ∆r is as follows:

$$\mathsf{\Delta }r=\frac{V_{L}RT}{V_{0}S}\ln (1+\frac{P}{P_L})$$

(6)

where r is the drop in value of the surface free energy, which represents the difference between the surface free energy of coal in an un-adsorbed gas state and the surface free energy after adsorbed gas, J/m².

The variation rate of surface free energy at each pressure point is as follows:

$$\mathsf{\Delta }{r}_P=\frac{V_{L}RT{P}_L}{V_{0}S(P_L+P)}$$

(7)

In this paper, generalized fractal dimensions are selected as an example, parameter D_q includes D₋₁₀, D₁₀, D₋₁₀–D₁₀, D₀–D₁₀, and D₋₁₀–D₀. D_q is a monotonically decreasing function with a sigmoidal shape. D₋₁₀ is influenced by the lowest probability measure areas, whereas D₁₀ is affected by highest probability measure areas. D₀–D₁₀ and D₋₁₀–D₀. are the amplitudes of the right and left branches of D_q, which represent the high and low probability measure areas heterogeneity, respectively.

The data sources of above fractal models are all mercury injective curves, and the fractal dimension is calculated to discuss pore fracture structure heterogeneity of the reservoir. Whether the mercury removal curve is fractal or not, its restriction on the change in porosity and permeability needs to be discussed. The fractal dimension of three fractal models was calculated based on the same sample’s mercury removal curve. The difference in fractal characteristics between the mercury injective curve and the withdrawal curve of the same samples was discussed.

3. Results and Discussion

3.1. Lithofacies Types and Spatial Distribution of Source Rocks

Outcrop observation and drilling show that typical sedimentary of the Lucaogou Formation (P_3l) are oil shale, siltstone with dolomite, limestone lens, and so on. According to differences in lithology, sedimentary structure, contents, and mineral composition, the Lucaogou Formation can be chopped up into five lithologic facies, that is, black oil shale facies, gray-black calcareous rock facies, gray-beige pelitic dolomite facies, beige micrite dolomite lithofacies, and granular limestone facies.

The most important lithologic facies of Lusaogou Formation in this area is black oil shale facies. The black, black-brown oil shale, and gray-black shale are the main lithologies. Siltstone laminae or bands (mm) are found in many shales. The turbidite sandstone at the far end of the semi-deep lake may be siltstone (Figure 2).

Source rocks are distributed longitudinally in the upper, middle, and lower sections of the Lucaogou Formation, but their thickness and lithologic combination are different. In the lower section, lithology is mainly silty carbonaceous mudstone and siltstone slightly rhythmically interbedded, with a total thickness of about 460 m; in the middle section, lithology is pure carbonaceous mudstone and mid-thick layered siltstone, which are about equal thickness interbedded, with a total thickness of about 130 m; in the upper section, lithology is mud shale with mud limestone and dolomite interlayer, with a total thickness of about 253–550 m. In conclusion, source rocks of upper members of Lucaogou Formation have good continuity.

Figure 1 shows that the most favorable source rocks in each member of the Lucaogou Formation are semi-deep lacustrine facies. In Lucaogou stage, Bogda Mountain was a depositional center where the thickest source rock strata were deposited, and the thickness of source rock gradually decreased from depositional center to surrounding strata.

3.2. Organic Geochemical Characteristics of Source Rocks

Organic maceral components of kerogen are sapropelic and humic amorphous bodies. Its relative abundance was 0 to 86%, with an average of 43.57%; Non-resinous bodies were keratinoid bodies. Their relative abundance was 0–97%, with an average of 23.29%; the mirror group included structural and unstructured bodies, with a relative abundance of 2–60%; the relative abundance of the inert group was 1–63%, with an average of 14.17%. Kerogen is yellowish-brown with no-weak fluorescent and a kerogen-type index of −82 to 81.

Organic carbon content of source rocks is higher. A total of 22 non-source rock samples with TOC content ranging from 0.02 to 0.49%, with an average of 0.33%, among which TOC content was distributed between 0.6 and 7.0% (Figure 3). Hydrocarbon generation potential (S₁ + S₂) was 0.16–244.41 mg/g, with an average of 24.42 mg/g.

TOC content in the upper, middle, and lower was above 2%. Figure 4 shows that a higher TOC value area is distributed around the Bogda area. The reason is that this area was a deep water area of lake basin during sedimentation period of Lucaogou Formation, and TOC content was affected by sedimentary environment.

Chloroform asphalt “A”. Figure 5 shows that the content of asphalt chloroform “A” ranges from 0.0013 to 0.8187%, with an average value of 0.0927%. Good, medium, poor, and non-source rock accounts for 32, 29, 27, and 12%, respectively. Vertically, upper and middle members are good source rocks, followed by medium source rocks.

Maturity. Figure 6 shows Ro, max of source rocks ranges from 0.35 to 1.27%, with an average of 0.77%. Distribution of source rocks follows a normal distribution, with the main rocks in mature stage, second in lower mature stage, and a few in immature stage with low thermal evolution. It indicates that frequency distribution presents a symmetrical normal distribution. Maturity of organic matter is 0.7–0.8%, accounting for 32% of total samples. Maximum, minimum, and mean organic matter maturity in the western part are slightly higher than those in the eastern part.

3.3. Detailed Description of Reservoir Physical Property

Petro-mineralogical characteristics. Figure 7 shows that the maximum clay mineral content of drilling samples (62%) was slightly higher than maximum clay content of outcrop samples (59%) and the minimum clay content (2%) was similar to that of outcrop samples (2%). Composition of clay minerals in both underground and outcrop samples is dominated by illite, followed by epizootic and epizootic layers, while kaolinite, chlorite, and epizootic are relatively small. The average illite content in the clay composition of a good sample (52.70%) was significantly lower than that of an outcrop sample (60.62%). In both outcrop and well samples, the interlayer of illite decreases with an increase in illite content.

Brittle minerals: Quartz, feldspar, calcite, and dolomite are the main brittle minerals in both downhole and outcrop samples. Average content of quartz and feldspar in outcrop samples (58.96%) is higher than that in drilling samples (56.64%), average content of carbonate rocks (10.25%) is lower than that in drilling samples (16.20%), and average content of total brittle minerals (69.12%) is lower than that in drilling samples (72.42%). In addition, development of ferridolomite and siderite was much more common in downhole samples than in outcrop samples.

Reservoir space type. Figure 8 shows that the reservoir space of organic-rich mud shale is of various types, including macroscopic pores, fractures, and microscopic pores and crevices. Pores include macro-scale dissolution pores, micro-scale intergranular dissolution pores, intra-granular dissolution pores, intergranular pores, intra-granular pores, and organic matter micropores. Fractures include macro-scale cracks, dissolution cracks, intergranular cracks, and internal cracks of clay minerals. For fluids, fractures are used not only as migration channels, but also as effective storage space.

Porosity and permeability. Figure 9a,b show that density in drilling is significantly higher than that in the outcrop. The density of source rocks has an obvious negative correlation with TOC content. Therefore, density logging data are adopted to identify carboniferous shale segments during drilling. Figure 9c,d show that minimum, maximum, and average porosity are 0.02, 11.81, and 1.33%, respectively. Figure 9e,f show that there is little correlation between porosity and permeability. Some samples with low porosity have high permeability values, which indicates that permeability values are affected by microfractures. Some samples with high porosity have very low permeability, which indicates poor pore connectivity.

Figure 10a,b show that average specific surface value in drilling is lower than that of outcrop samples. Specific surface is positively correlated with porosity, clay mineral content, and volume percentage of interlayer. However, it was negatively correlated with TOC content and percentage of clay minerals.

3.4. Adsorption Ability and Surface Free Energy Variation during Methane Adsorption

A total of 18 samples were collected for isothermal adsorption tests. Laboratory temperature 30 °C; helium concentration: 99.999%; methane concentration: 99.99%. The results show that Langmuir volume VL and Langmuir pressure PL are 2.93 m³/t and 7.83 Mpa, respectively (Figure 11).

ε-ω adsorption characteristic curves can be obtained from Equations (1) and (3) (Figure 12). At the same temperature (30 °C), with a gradual increase in adsorption space, adsorption potential decreases in logarithmic form. Therefore, in the process of adsorption, adsorption potential decreases with an increase in equilibrium pressure, and adsorption space increases with an increase in equilibrium pressure. Maximum adsorption space of sample 1 is 0.20~0.25 cm³·g⁻¹, which is larger than that of other coal samples (0.025~0.20 cm³·g⁻¹). In the same adsorption space, the corresponding adsorption potential of sample 1 is much greater than that of the latter.

Equation (7) was used to calculate the change in surface free energy of different coal samples with adsorption pressure at the same temperature (Figure 13). Figure 13a shows the declining value of coal surface free energy. The low-pressure stage (0~6 MPa) increases rapidly with the increase in experimental pressure, while the high-pressure stage (6~10 MPa) is relatively gentle. This indicates that pressure has a positive effect on adsorption of a gas on the surface of coal, which makes the free energy of a coal surface develop into a low-energy state. The space available for methane adsorption in coal and the adsorption potential of corresponding coal samples both increase with the increase in nanopores, resulting in a gradual increase in Langmuir volume and surface free energy decline value of coal, and a continuous enhancement of the methane adsorption capacity.

With the increase in experimental pressure, the drop rate of surface free energy decreases gradually (Figure 13b), indicating that the adsorption capacity of coal to methane is gradually weakened with an increase in adsorption capacity. Methane molecules preferentially occupy strong adsorption sites on the surface of coal at an initial stage of methane adsorption (experimental pressure is less than 6 Mpa), and the decreased rate of surface free energy is the largest, resulting in a rapid decrease in surface free energy; as methane is continuously adsorbed (experimental pressure is greater than 6 MPa), the strong adsorption site gradually decreases, making it more and more difficult for methane molecules to be adsorbed by coal surface. As a result, the decrease rate of free energy on coal surface gradually decreases, resulting in a slow decrease in free energy on the surface. This is in good agreement with variation in methane adsorption capacity. Adsorption experiments of methane show that the adsorption capacity of methane increases rapidly in the low-pressure section (0~6 MPa), but increases slowly in the high-pressure section (6~10 MPa).

4. Conclusions

In this paper, the shale gas resources rich in organic matter in the southern margin of the Junggar Basin in Xinjiang are evaluated. On this basis, the shale gas resources of the Lucaogou Formation are investigated and evaluated. The reservoir characteristics, preservation requirements, compressibility, and gas content of the gas-bearing shale section are determined. The main results are as follows.

(1) The source rocks in the upper part of Lugou Formation are relatively developed. The thickness of the source rock is about 78.12~513.73 m, and the main lithology is gray-black shale, silty mudstone, and oil shale. The oil shale includes black oil shale/shale (lithology) phase, gray-black-gray/dolomite mudstone (lithology) phase; compared with the middle and lower section, the longitudinal development continuity of the lithology is mainly mud shale with mud limestone and a dolomite interlayer, showing the overall trend of gradually thickening from west to east and from north to south. The black oil shale phase is the most important lithologic phase of the Lugou Formation in this area.

(2) The high-value area of TOC is distributed around Bogda. TOC content is affected by the sedimentary environment. The deeper the sedimentary water is, the TOC content will increase, leading to the highest TOC content in this area. The surface average of source rock in drilling is lower than that of outcrop source rock. The specific surface area is roughly positively correlated with porosity, and clay mineral content, and negatively correlated with TOC content and IN/interlayer percentage.

(3) At the same temperature (30 °C), the adsorption potential decreases logarithmically with the logarithm. Adsorption potential decreases as the equilibrium pressure increases, and the adsorption space increases as the equilibrium pressure increases. The maximum adsorption space of the sample was 0.20~0.25 cm³·g⁻¹, greater than the maximum adsorption space of other coal samples (0.025~0.20 cm³·g⁻¹).