Natural Fractures in Tight Sandstone Gas Condensate Reservoirs and Their Influence on Production in the Dina 2 Gas Field in the Kuqa Depression, Tarim Basin, China

Abstract

The Dina 2 gas field in the Kuqa Depression of the Tarim Basin is one of China’s most critical oil and gas exploration areas. Natural fractures have played an important role in the low-permeability reservoirs in the Tarim area. Tectonic fractures are dominant in such reservoirs. In fact, the factors influencing tectonic fracture development have always been the source of important issues in tight reservoirs. Cores, thin sections, and borehole image logs were used to analyze the types, basic characteristics, and factors influencing tectonic fractures in the tight sandstone reservoirs of the Dina 2 gas field in the Tarim Basin. The results showed that the tectonic fractures are dominated by high-angle and upright shearing fractures, and they mainly show ENE–WSW strikes. The thin sections suggest that 60% of the fractures are fully filled with minerals, 20% are unfilled, and 20% are partially filled. The analysis also shows that lithology, faults, and in situ stress are the main factors controlling the development of the tectonic structures. Furthermore, the correlation between the unimpeded flow from a single well and the apertures of the tectonic fractures indicates that tectonic fractures play an important role in the production of hydrocarbons.

1. Introduction

As oil and gas exploration has continuously developed, many oil and gas resources have been discovered in China [1,2,3], and the Tarim Basin is one of the focal areas in China for natural gas exploration [4,5]. The Kuqa Depression in the Tarim Basin is a Cenozoic foreland depression that developed based on Paleozoic passive continental margins and Mesozoic intracontinental depressions [6,7]. There are abundant natural gas resources in the depression [8]. The maximum burial depth of the Cenozoic strata can reach 10,000 m; therefore, these reservoirs are categorized as typical deep, tight sandstone reservoirs [9]. Ultralow porosity and permeability are the main characteristics of this type of reservoir [10,11,12]. Tectonic fractures in reservoirs can not only provide storage space but can also provide fluid flow pathways. Numerous previous studies have shown that the development of tectonic fractures greatly affects the transport, aggregation, and distribution of natural gas in tight reservoirs [13,14,15]. The exploration of the Keshen and Dabei gas fields has also proven that tectonic fractures are the key factors in improving reservoir physical properties and increasing individual well productivity [16]. At the same time, they are also an important basis for making and adjusting natural gas development plans. Therefore, it is very important to study the developmental characteristics and factors influencing tectonic fractures.

Due to the importance of tectonic fractures, previous scholars have performed several studies, such as Zeng et al., who concluded that lithology, layer thickness, sedimentary facies, and in situ stress are the main factors for tectonic development [17]. Wang et al.’s research on the Keshen 2 gas field in the Kuqa Depression showed that lithology, faults, rock composition, and bed thickness have significant effects on the development of tectonic fractures [18]. Liu et al. suggested that the factors affecting fractures in tight sandstone reservoirs include tectonism, diagenesis, and in situ stresses [15]. The Dina 2 gas field in the Kuqa Depression of the Tarim Basin is the largest gas condensate reservoir that has been discovered in China. The main gas-bearing layers are the Paleocene Suweiyi Formation and the Kumgram Formation, and the reservoir is mainly composed of siltstone and fine sandstone, which are part of the low-porosity and low-permeability reservoir that is close to the tight sandstone gas. The gas reservoir is more than 1.5 billion m³/km², the gas–oil ratio values are 8100–12,948 m³/m³, and the condensate content is 60–80 g/m³ [19]. In recent years, many studies have been carried out on the Dina 2 gas field from the perspectives of geological characteristics, sedimentary reservoir characteristics, and abnormally high pressure formations, as well as their relationships with oil and gas accumulation [19,20,21,22]; however, there are no relevant studies on the fracture development characteristics, especially the influencing factors of the fracture development characteristics and the influence of fracture development on productivity. Currently, because of our poor understanding of the characteristics and influences of fractures within gas reservoirs, there has already been a decline in the production of gas-producing wells; furthermore, water has already intruded into some gas wells. A correct understanding of fractures is of great significance in controlling water invasion and improving the ultimate recovery rates of gas reservoirs.

2. Geological Setting

The Dina 2 gas field is located in the Kuqa Depression in the northern Tarim Basin, which consists of four tectonic zones and three depressions (Figure 1). From north to south, they are the northern monoclinal belt, the Krasu–Yichiklik tectonic belt, the Qiulitage tectonic belt, and the southern slope belt; the three depressions from west to east are the Wush Depression, the Baicheng Depression, and the Yangxia Depression [4,23,24,25]. The Qiulitage tectonic belt, located in the central part of the Kucha foreland basin (Figure 1), is an arc-shaped tectonic belt with an east–west spread [26,27]. The Dina 2 tectonic belt is located at the eastern end of the Dongqiulitage tectonic belt. Two retrograde thrusting faults mainly control it, i.e., the Dongqiulitage Fault in the south and the Dina North Fault in the north, and these controlling faults (the Dina North and Dongqiulitage Faults) extend from the Triassic to the Neoproterozoic Jidike Formations, disappearing downward within the basement slip surface, upward in the Neoproterozoic Jidike Formation saline rocks, and past the mudstones [21].

The Dina 2 gas field is a near-W–E-trending long-axis anticline, with a basically symmetrical long axis, which consists of two tectonic plateaus in the east and the west. The dip of the strata in the east is high, and the gradient is steep, but the tectonic plateau in the west is relatively flat [28]. Historically, the Dina region has undergone three major tectonic movements: the early Himalayan movement, the late Himalayan movement, and neotectonic movements from the Quaternary to 730,000 years ago, resulting in the present-day tectonic pattern [29]. Cretaceous, Paleoproterozoic (Kumgrem Group and Suwiyi Formation), and Neoproterozoic (Jidik, Kangchun, and Kuqa Formations) strata are developed in the Dina region from the bottom upward (Figure 2) [30]. The Paleogene strata are in angular unconformity contact with the underlying Cretaceous strata. The main productive layers are the Paleoproterozoic Kumgrem Group and the Suwaii Formation. The Suwiyi Formation has burial depths of 500–5500 m and thicknesses of 167–223 m. The study area is dominated by fan delta facies followed by lacustrine facies; fan delta plain deposits are mainly present, but fan delta front deposits are rarely present [21]. The porosity values of the reservoir range from 2% to 15%, with an average value of 5.8%, and the permeability values are mainly distributed from 0.01 to 1.0 mD, with an average value of 0.49 mD, indicating a low-porosity and low-permeability reservoir [31].

3. Dataset and Methodology

In this study, we collected core, thin section, and borehole image log data of the Paleogene Suweiyi Formation in the Dina 2 gas field in the Kuqa Depression in the Tarim Basin in Northern China. Different parameters of the fractures are used in this paper, including the size, dip angle, strike, apertures, line density, and degree of fracture filling. There are 29 drilled wells in the study area, and 13 wells have image log data (Figure 1B). The basic characteristics of these fractures were obtained by analyzing 9 well cores, 300 thin sections, and 13 borehole image logs in the study area. Thin sections were coated with red dye resin to highlight fractures and pores. Tectonic fractures always show sinusoidal curves on borehole image logs [32]. Inclination and azimuth were obtained by analyzing these sinusoidal curves. All borehole image logs were measured under water-based mud conditions. The line density data of the fractures were obtained by counting the number of fractures developed per meter in the cores or borehole image logs. The fracture aperture data used in this study were all calculated from borehole image logs. Based on borehole image log data, by analyzing borehole breakouts and fractures induced by drilling, the direction of in situ stresses can be obtained [33]. The open-flow capacity data, representing the initial production capacity of a single well in this paper, are mainly from the PetroChina Tarim Oilfield.

4. Fracture Characteristics

4.1. Fracture Characteristics of the Cores

Cores are the most direct medium for identifying macroscopic tectonic fractures, and information such as the geometry, filling, and mechanical properties of tectonic fractures can be measured through core observations [34,35]. Core observations suggest that most of the fractures in the Dina 2 gas field are shear fractures (Figure 3A,B), and the fracture surfaces are straight. Scours and steps are visible on the fracture surfaces (Figure 3B); the yellow arrow indicates that scours are visible on the fracture surface. In general, according to the dip angle, fractures can be divided into four categories, namely, vertical fractures (>75°), high-angle fractures (45–75°), low-angle fractures (15–45°), and horizontal fractures (<15°) (Feng, 2018). The statistical results of core observation show that the proportion of vertical fractures in core observation is about 47.5%, the proportion of high-angle fractures is about 36.2%, and the proportion of low-angle fractures and horizontal fractures is about 16.3%; these data indicate that the study area is dominated by vertical fractures (Figure 3C,E), followed by high-angle fractures, while low-angle fractures and horizontal fractures are rare. Core observations also show that the filling minerals are mainly calcite (Figure 3C,D) and argillite, with a small amount of hard gypsum (Figure 3E); 53.8% of the fractures are fully filled, 33.13% are half-filled, and 13% are unfilled (Figure 4).

4.2. Fracture Characteristics in Thin Section

Thin sections show that microfractures are widely developed in the Suweiyi Formation, which is the main production layer of the Dina 2 gas field. Tectonic fractures (Figure 5A,B) are the most predominant type; the apertures vary from 0 to 0.05 mm, and some can reach 1 mm. The second type is shrinkage fractures (Figure 5C,D), formed by diagenesis, which are generally considered to be tensile fractures formed by the shrinkage of the mineral volume caused by compaction, dehydration shrinkage, or recrystallization during burial diagenesis and resulting in tensile stress. In this study area, shrinkage fractures are mostly developed in mudstone or in the argillaceous bands that develop in sandstone. At the same time, a small number of dissolution fractures (Figure 5E,F) can be seen; specifically, many dissolution fractures are visible in the thin sections of A2. The widths of the fractures are mostly less than 0.5 mm, the extension is short, and most of them are unfilled; only a few dissolution channels are filled with calcite and anhydrite.

4.3. Fracture Characteristics in Borehole Image Logs

There are abundant borehole image log data. A total of 13 wells has borehole image logs, all of which were measured in a water-based mud environment. The tectonic fractures are characterized by sinusoidal curves in the imaging. The open fractures are visible as dark colors on the electrical image logging, and the fractures, filled with high-resistivity minerals, show as bright colors on the borehole image logs [36]. In addition, the stratification interface, the layer interface, and the induced fractures can be reflected in the imaging. They should be excluded when calculating the relevant structural fracture parameters using borehole image log data. The tectonic fractures in this area mainly show the characteristics of high-angle (Figure 4 and Figure 6a) and parallel oblique (Figure 6b) fractures in borehole image logs, and a small number of conjugate (Figure 6c) and network fractures are also visible (Figure 6f); in addition, fully filled low-angle fractures and unfilled low-angle parallel fractures can be seen (Figure 6d,e). Parameters such as apertures and the porosity of structural fractures in this area can be extracted. XRMI (Extend-Range Micro-resistivity Imager) shows that the strikes of tectonic fractures in the study area are NE–SW and appear at a small angle to the current principal stress direction in the area. The structural fractures have large dip angles and are mainly composed of high-angle and vertical fractures, accounting for approximately 76.9% of the total number of fractures. The wells are mostly less than 0.3 mm deep. The linear density represents the number of fractures per unit length in the well interval, and its value is the apparent fracture density [37], which is one of the important parameters in characterizing the seepage capacity of a fracture system. This parameter can be directly counted by manual statistics, and its calculation method is as follows in Formula (1). The fracture linear density values of the Suweiyi Formation range from 0.004 to 0.93, with an average of 0.47 (Figure 4).

$${\mathrm{D}}_{\mathrm{L}}={\displaystyle \frac{1}{L}}{{\displaystyle \sum }}_{i=1}^{n}Li$$

(1)

In the formula:

D_L stands for apparent fracture density 1/m.

$Li$ stands for the length of the $i$th fracture on the image logging map, in m.

$L$ stands for the length of the well section in m.

Figure 6. Tectonic fractures in the image logs in the Dina 2 gas reservoir. (a) High-angle tectonic fractures that are not filled from well A1. The red lines indicate conductive fractures, which means the fracture is not filled. (b) Parallel high-angle fractures that are not filled with water from the well. (c) Conjugate fractures that are not filled from well A1. (d) Low-angle fractures that are fully filled. The green line represents fully filled A6. (e) Low-angle parallel fractures that do not fill A6. (f) Conjugate fractures that are not filled from well A1.

Figure 6. Tectonic fractures in the image logs in the Dina 2 gas reservoir. (a) High-angle tectonic fractures that are not filled from well A1. The red lines indicate conductive fractures, which means the fracture is not filled. (b) Parallel high-angle fractures that are not filled with water from the well. (c) Conjugate fractures that are not filled from well A1. (d) Low-angle fractures that are fully filled. The green line represents fully filled A6. (e) Low-angle parallel fractures that do not fill A6. (f) Conjugate fractures that are not filled from well A1.

4.4. Analysis of the Main Factors Controlling Fracturing

The above studies describe the basic characteristics of the tectonic fractures in the study area. According to comprehensive research, the lithology, faults, and in situ stresses have been found to control the development and distribution of tectonic fractures.

5. Lithology

Lithology is one of the important factors affecting the development of structural fractures [38]. Under the same tectonic stress, since the rock composition and structure of different lithologies are different, fractures develop at different levels. Typically, stronger formations exhibit brittleness; under the same strain, structural fractures are more likely to develop in strong rocks than in weak rocks [39]. The most common brittle minerals in rocks are quartz, calcite, and dolomite. Zeng Lianbo’s [17] study of the Cretaceous system in the Kuqa Depression concluded that structural fractures develop the easiest in dolomite and limestone with strong brittleness, followed by siltstone and fine sandstone, and finally siltstone and mudstone, while the fractures are the least likely to develop in coarse-grained rocks, such as medium sandstone, fine sandstones, and conglomerate. Wang Ke et al. studied the structural fractures of the Cretaceous strata in the Keshen 2 gas field of the Kuqa Depression; they found that, in the Keshen 2 gas field, the density of structural fractures is the highest in argillaceous siltstone and silty mudstone, followed by mudstone and argillaceous siltstone; they also found that the density of the fractures is the lowest in fine sandstone and medium sandstone [18]. According to the core observations and borehole image log statistics of the Dina 2 gas field, the linear density of structural fractures in coarse sandstone is the highest, up to 1.75/m, followed by medium sandstone and conglomerate; their linear densities of structural fractures are 1.32/m and 0.91/m, and the density of structural fractures in fine sandstone is 0.86/m (Figure 7). Different from the Cretaceous strata in the Kuqa Depression, the densities of structural fractures in the Paleogene mudstone and argillaceous siltstone in the Dina 2 gas field are relatively low, i.e., 0.32/m and 0.37/m. Previous results show that the content of brittle minerals, i.e., quartz and calcite, in the coarse sandstone in the Dina 2 gas field reservoir is much higher than that in the mudstone and siltstone [31]. This may be an important reason for the high density of structural fractures in the coarse sandstone with relatively coarse grains in this area.

6. Faults

The Dina 2 gas field has experienced the early Himalayan, late Himalayan, and neotectonic movements, and the faults are mainly ENE-oriented. After three major tectonic movements, the Dina 2 structure has become a subsalt fault in the transitional fold of the Kedike Formation, which is mainly controlled by two northern and southern anticline thrust faults. The main fault is the eastern Qiulitage fault in the south, with a fault distance of 400–700 m, and the northern fault is controlled by the Dibei fault with a fault distance of 200–400 m, both of which are from the Triassic to the Tertiary Kedike Formation.

The Dina 2 structure is a gentle long-axis anticline with symmetrical wings in the east–west direction, and it is steeper in the east than in the west. Image logs show that the fractures are mainly oriented in the ENE–WSW direction, which is consistent with the regional fault strike. Structural faults developed in Dina 2 gas reservoir, and most have the similar direction with the main fracture strike. However, the fractures in different positions of the Dina 2 anticline are slightly different. In the eastern and western wings of the anticline, the fracture trend is more inclined to the east–west trend, which is consistent with the fault trend. In the middle of the anticline, there are also some fractures that intersect with the major fault trend at a small angle. In this study, the distances between the 13 gas wells in the study area, the adjacent faults, and the average apertures of the fractures in the target layer were calculated. It is obvious based on the scatterplot of the average fracture density and the distance from the fault that, as the distance from the fault gradually increases, the degree of fracture development gradually deteriorates (Figure 8). Studies have found that, because of the relative movement of the geological bodies in the two walls of the fault, there are obvious stress concentrations along the fracture zone, and the fractures are remarkably developed [40]. Due to stress concentration, tectonic fractures easily develop at the intersection of faults, at the end of faults, and at the turning end of faults. The research suggests that the development of the faults in this region not only has an important control effect on the development degree of fractures, but also has an important influence on the direction of fractures.

7. In Situ Stress

In situ stress is defined as the present natural stress in the Earth’s crust, which is closely related to gravity and tectonic stress. The formation of fractures in rocks is closely related to the stress state [41]. The direction and magnitude of the original in situ stress and the mechanical properties of the rock, such as Poisson’s ratio and internal friction coefficient of the rock, all have important influences on the occurrence of fracture borehole breakout and collapse of the rock wall. In this study, borehole image log data were used to evaluate the direction of current in situ stress in the study area by using the induced fractures and borehole breakouts generated by drilling [42]. Stress-type borehole breakouts are visible in image logs in this study area, which is mainly due to the concentration of borehole stress caused by horizontal principal stress imbalance. Shear blocking of borehole collapse usually occurs in the direction of the minimum principal stress [43] (Figure 9). The elliptic hole is symmetrical, and the direction of the long axis indicates the direction of the minimum principal stress. In addition, two main types of induced fractures are present in the study area, namely, tensile symmetric fractures and stress release fractures. The former is caused by excessive density of the drilling fluid. When the vertical stress is at the maximum in situ principal stress or the intermediate principal stress, the fractures with heavy mud pressure are generally dominated by high-angle tensile fractures with large apertures and extension. Stress-relief fractures are produced after drilling through the formation. As the stress is released, a set of parallel fractures is produced, and as the stress is released, a set of parallel echelon fractures is produced, characterized by a visible “eight” or inverted “eight” shape. According to the method of Lai Jin et al., the direction of principal stress in the Dina 2 area is analyzed, and the results show that the current in situ stress direction of the structure in the Dina 2 block varies between S–N and NE–SW (Figure 10). By evaluating the correlation between the fracture trend and the current maximum principal stress direction and fracture apertures (Figure 11), it can be seen that, with the increase in the angle between the two parameters, the fracture apertures gradually decrease. The stress direction has a certain controlling effect on the degree of fracture apertures, and the smaller the angle is, the larger the fracture apertures, this phenomenon also occurs in in the tight reservoirs of Keshen 5 gas field and Keshen 6 gas field in the Tarim Basin [44]; this is more conducive to the transport of oil and gas for the low-porosity and low-permeability reservoirs in the study area. This may be because, when the current maximum principal stress is parallel to the fracture advantage, the fracture is not easy to close under pressure. When the fracture trend is perpendicular to the current maximum principal stress, the fracture is easy to close under pressure [17,44].

8. The Effect of Tectonic Fractures on Yield

The Dina 2 tectonic deformation began in the Neogene Kuqa period and formed in the Quaternary period. At the beginning of Pleistocene, the orogeny of the mountain movement reached its peak, and the Kuqa foreland basin entered the most active period of tectonic movement. The East Qiulig fault and Dibei fault developed rapidly and formed the present tectonic pattern. The main period of trap formation in Dina 2 has been since 3 Ma [45,46]. Based on the hydrocarbon generation history and inclusion analysis results of coal measure source rocks, the research of Zhu Guangyou et al. [19] suggested that the main accumulation period of Dina 2 gas field is the early Kuqa–Xiyu stage (2.5–1 Ma). Combined with the data of burial history and thermal history (a typical III kerogen hydrocarbon generation kinetic parameters and carbon isotope fractionation model), they concluded that the main time of oil and gas charging in the Dina 2 gas field has occurred since 2.5 Ma. This means that the formation of major tectonic fractures in the Kucha Depression in the Tarim Basin occurred earlier than, or coincided with, the period of massive natural gas injection; therefore, the development of fractures greatly improved the efficiency of natural gas injection. In fact, fractures can not only modify the storage space by connecting the isolated micropores, they can also increase the effective permeability of natural gas by reducing the start-up pressure required for natural gas transport and decreasing the replacement pressure in tight reservoirs. In this study, to investigate the effect of fractures on production, the ungrouped flow rate was used to represent the raw gas production capacity. The open-flow capacity refers to the daily gas production of a gas well when the bottom hole flow pressure is equal to the atmosphere pressure. Previous studies have shown the open-flow capacity reflects the maximum production capacity of a gas well [47,48]. The results suggest that, as the fracture aperture increases, the natural gas production capacity tends to increase significantly, and the correlation coefficient can reach 0.75 (Figure 12); in addition, there is a positive correlation between fracture density and open-flow capacity (Figure 13). This means that the fractures in the Dina 2 gas field have a significant control on the gas production capacity. Compared with conventional gas reservoirs, the porosity and permeability of tight sandstone reservoirs are low; thus, it is difficult to form an efficient seepage system, so fractures are usually an important factor in improving the physical properties of such reservoirs [17,49].

9. Conclusions

1: Structural fractures are important components of the Dina 2 gas field in the Kuqa Depression, Tarim Basin, China. The tectonic fractures are mostly high-angle and vertical fractures, the strike is mainly NE–SW, the fracture apertures are mostly less than 0.3 mm, the fractures are highly filled, and 55% of the fractures are in the filling state.

2: The lithology, faults, and in situ stresses are the main factors that control fracture development. The greater the fracture density in coarse sandstone, medium sandstone, or fine sandstone is, the greater the number of fractures that will develop; meanwhile, the fracture apertures are mainly controlled by the distance from the fault. The closer the drilling is to the fault, the greater the fractures’ apertures will be. The present stress is also an important factor controlling fracture apertures. The smaller the angle between the overall fracture trend and the current stress direction is, the smaller the fracture apertures.

3: There is a significant positive correlation between open flow and tectonic fracture apertures in the study area, and tectonic fracture apertures control the production capacity of natural gas in the study area to a certain extent.