1 Introduction

Tight sandstone gas is an important unconventional hydrocarbon resource (Jia et al. 2012; Guo et al. 2013; Dai et al. 2012; Zhang et al. 2014; Yang et al. 2018; Zhang et al. 2014; Li et al. 2012; Zeng 2009; Zhan et al. 2017; Zeng et al. 2012). The strong compaction effect (including both normal burial compaction and abnormal structural compression) results in low matrix porosity (< 10%) and low permeability (air permeability < 1 × 10−3 μm2 or overburden permeability < 0.1×10−3 μm2) in tight sandstone reservoirs, therefore an industrial-scale natural gas reservoir cannot be formed by the rock matrix porosity alone (Fossen 2010; Orlando et al. 2010; Solum et al. 2010; Lander and Laubach 2015; Ju et al. 2014). The presence of tectonic fractures is a very important factor for improving the physical properties of tight sandstone reservoirs and increasing natural gas productivity (Ding et al. 2015; Zeng et al. 2010a, b; Estibalitz et al. 2016; Feng et al. 2018). Therefore, the systematic study of the effectiveness of tectonic fractures in tight sandstone reservoirs is of great significance for discovering tight sandstone sweet spot and improving gas reservoir productivity (Kara et al. 2017; Lander and Laubach 2015; Nian et al. 2017).

The Keshen gas field is located in the deep zone of the Kelasu tectonic belt in the Kuqa depression, the Tarim Basin, and its target formation, the Lower Cretaceous Bashijiqike Formation, is a typical ultra-deep (> 6000 m) naturally fractured tight sandstone reservoir (Wang 2014; Zeng et al. 2008; Lai et al. 2017a). Regarding the foreland thrust belt of the Kuqa depression and the tectonic fractures in Keshen gas field, numerous studies have carried out in various aspects before, including quantitative description and prediction of fractures (Zeng and Wang 2014; Zhao et al. 2014; Wang et al. 2014; Lai et al. 2019), indicative implications of regional stress field inversion provided by fractures (Zhang and Wang 2004; Zeng et al. 2004), formation mechanisms of fractures and influential factors (Zeng et al. 2010a, b; Liu et al. 2017; Chang et al. 2014; Gong et al. 2015). These studies have revealed that fractures lead to obvious modification of ultra-deep tight sandstone reservoirs (Wang et al. 2018). The Cretaceous Bashijiqike Formation is found with extensive development of tectonic fractures, which controls high productivity of natural gas in the Keshen gas field. In this paper, on the basis of analysis of tectonic fracture types and characteristics as well as information obtained from cores, thin sections and image logs, the effectiveness of tectonic fractures is studied, with the aim to provide geological guidance on the efficient development of the Keshen gas field.

2 Geological settings

The Tarim Basin is the biggest petroliferous basin in China (Lai et al. 2020), and a large number of giant gas fields have been found in the Kuqa depression recently (Ju and Wang 2018). In this paper, the study area—the Keshen gas field is located in the Kelasu tectonic belt of the Kuqa depression, the Tarim Basin, which is rich in natural gas resources, with multiple faulted anticline gas reservoirs such as KeS5, KeS6, KeS2, KeS8, KeS9, and KeS13 (Fig. 1). The proven geological reserves of natural gas exceed 10,000×108 m3 (Wang 2014). The gas-bearing target layer of the Keshen gas field is the Bashijiqike Formation of the Lower Cretaceous, which is mainly composed of reddish brown fine sandstone, siltstone, medium sandstone and thin mudstone, with burial depths of 5500–8500 m, an average thickness of about 300 m, matrix porosity of 1.5%–5.5%, and matrix permeability of (0.01–0.1) × 10−3 μm2 (Zhang et al. 2014). Data from cores and image logs indicate that tectonic fractures with a density higher than 0.3 m−1 have developed in the Bashijiqike Formation. The physical property measurements of fractured cores show that the permeability provided by fractures is of (0.1–10.0) × 10−3 μm2, which suggests a typical low-porosity naturally fractured tight sandstone reservoir.

Fig. 1
figure 1

Structural map of the deep zone of the Kelasu tectonic belt in the Kuqa depression

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3 Tectonic fracture characteristics

The observation of core and interpretation of FMI image logs indicate that there are both tensile and shear fractures developing in the Keshen gas field. The fracture surface of the tensile fracture is crooked unevenly, with an aperture of 0.5–1 mm, and the tensile fractures are mostly high-angle fractures, filled with calcite, dolomite or anhydrite. Moreover, a few of these filled fractures can be re-opened and become effective fractures due to the later tectonic stress. The shear fractures, which are mostly vertical, with flattened surfaces and long extension, often penetrate through the core with small aperture (< 0.5 mm), and most of them are unfilled. Micro-fractures are usually grain-piercing-through cracks with a width of 10–100 microns, which are often re-opened along the early filled fractures (Lai et al. 2017a; Wang et al. 2016, 2018). In FMI image logs, tectonic fractures are mainly present themselves in the group form of the parallel, echelon, broom-like, and adjustment patterns (Fig. 2), among which the parallel pattern is dominant and displayed the combination of multiple sinusoids with identical or similar shapes. The linear density of tectonic fractures interpreted by image log is generally between 0.2 and 2.3 fractures/m, with an average of about 0.6 fracture/m.

Fig. 2
figure 2

Tectonic fracture characteristics of the Cretaceous Bashijiqike Formation in the Keshen gas field, the Kuqa depression

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The interpretation results of image logs indicate that the tectonic fractures in the Keshen gas field include EW-trending tensile fractures and NS-trending shear fractures. Considering the structural evolution, reservoir sedimentary burial history and the results of temperature determination based on the carbon and oxygen isotopes of tectonic fracture fillings (Ding et al. 2015; Zeng et al. 2010a, b; Wang 2014), it is considered that the EW-trending tectonic fracture is suggested to be related to the Cretaceous and Paleogene regional extension, the bending and arching of the anticline, and the abnormal high pressure of Neogene. Such fractures are formed in the early stage and thus the filling rate is relatively high. The NS-trending tectonic fracture is mainly controlled by the compressive tectonic stress in the mid-late Himalayan Period along the NS-direction, and it occurs relatively late, which results in that most of them are not filled.

4 Results

4.1 Distribution law of effective fractures

4.1.1 Differentiated characteristics of effective fractures in the thrust anticline

The effective fractures are defined as factures that can permeate fluids effectively. In other words, they are fractures that have not been completely filled by minerals. Unfilled and semi-filled fractures are both effective fractures. Induced fractures and borehole breakouts, which appear at two symmetrical azimuths, are easily recognized on images and to be differentiated from natural fractures (Prioul et al. 2007; Ameen et al. 2012; Etchecopar et al. 2013; Nian et al. 2016; Ju et al. 2017; Lai et al. 2021).

Through the observation of similar outcrops in the field (Fig. 3) and the analysis of downhole measurements, it is found that the fractures in the long axis of the anticline are mostly dominated by large vertical fractures penetrating through strata. In addition, the distribution of the fractures is generally parallel to the long axis, with large fracture aperture, low filling degrees and high effectiveness. Along the two wings, the fracture density increases slightly, but the fracture aperture decreases gradually, accompanied by the growing filling degrees. Near the thrust fault, the fractures are mostly densely networked, which are often filled with the late-stage gypsum (outcrops) or calcite, dolomite and other minerals. The fracture effectiveness is inferior, and with the increasing distance to the fault, the fracture density decreases. In the north wing of the anticline, interlayer and oblique fractures often develop, with low filling degrees and good effectiveness. For instance, the filling rate of fractures found on cores from Well KeS8 at the higher part of the long axis of the KeS8 anticline is only 26%, the fracture aperture is 0.275 mm, and the linear density is 0.43 fractures/m, indicating a highly satisfactory fracture effectiveness. As for Well KeS801 located at the wing of the fold, the core fracture filling rate is 35%, and the aperture is 0.21 mm, while the density is 0.33 fractures/m (Fig. 4).

Fig. 3
figure 3

A fracture development model of the box-shaped anticline in the East QiulitageKezilenuer gully, the Kuqa depression. a fracture model; b the relationship between fracture density and fault distance; c the planar geological map of the anticline

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Fig. 4
figure 4

Histograms showing differences of fracture characteristics at different structural locations in Block 8 of Keshen in the Kuqa depression. a fracture filling rate; b effective fracture aperture; c image log FMI-based fracture line density. The wells marked as red, orange and yellow colors correspond to the highest, higher and high gas production wells, respectively

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Stress field modeling analysis is commonly used to unravel mechanical development of a fault-related fold (Sun et al. 2017). The magnitudes of tectonic stress were correlated with core test (Acoustic emission (AE) analysis) stress magnitudes. The numerical simulation of the curvature and stress change of the bending anticline shows when the rock is bent and deformed into the anticline shape, due to existence of a neutral plane, the strata above the neutral plane are subjected to the tensile strain, where the formed tectonic fracture is mainly tensile fractures with large aperture (Fig. 5) (Sun et al. 2017). At the same time, as these parts are located at the top of the gas reservoir, less affected by formation water, the fracture filling degree is low and the effectiveness is good, yet with a small fracture line density is small. On the other hand, the strata below the neutral plane are mainly subjected to compressive strains, where the formed fractures are mainly netted fractures with small aperture, and the nearby formation water causes high filling degrees. Therefore the effectiveness of these tectonic fractures is low, yet associated with high fracture line density (Table 1). The thickness of the tension zone on the anticline hinge and the higher part of the hinge zone is thick, and the thickness becomes thinner towards the two wings. The thickness of the tension zone near the fault or the steep south wing is large; the thickness of the gentle wing far away from the fault is relatively smaller (Fig. 6) (Sun et al. 2017).

Fig. 5
figure 5

Finite element simulation results of tectonic stresses in anticlines with different bending degrees

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Table 1 Zonal characteristics of fractures in reverse thrust anticline
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Fig. 6
figure 6

Zonal fracture development patterns of the faulted anticline of the Keshen gas field, the Kuqa depression

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4.1.2 Development patterns of effective fractures

Due to the tectonic mechanics-based origin, the spatial distribution of the longitudinal tensile fracture zone, adjustment fracture zone and netted fracture zone in the Keshen gas field is closely related to the high productivity of gas wells. The actual drilling and test data show that among the three types of fracture zones, the NS adjustment fracture zone has the strongest longitudinal extension ability and high effectiveness, followed by the EW longitudinal tensile fracture zone and at last the netted fracture zone with multiple dip angles. During the deployment of well sites, it is suggested in principle that the location deployment and completion of appraisal wells and development wells should first select the area of the NS adjustment fracture zone that communicate with the EW longitudinal tensile fracture zone (Fig. 7a), where the fracture effectiveness is high and high-rate industrial gas streams can be obtained without reservoir stimulation or with only acidizing (e.g., Well KS2-2-8). For the borehole that is confirmed later by actual drilling to encounter the relatively independent EW longitudinal tensile fracture zone (Fig. 7b), the fracture filling degree is relatively high and large-scale reservoir stimulation such as acidizing fracturing or propped fracturing are often required.

Fig. 7
figure 7

The fracture zones and the development pattern of fracture effectiveness in the Bashijiqike Formation in the Keshen gas field in the foreland thrust zone of the Kuqa depression

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5 Discussion

5.1 Main factors controlling fracture effectiveness

Fracture effectiveness refers to the fluid seepage capacity through fractures, mainly represented by the fracture aperture and filling degrees of fractures. The effectiveness of open fractures is good, while that of filled fractures and closed fractures is poor. The comprehensive parameter of fracture effectiveness is mainly reflected by the influence of fractures on reservoir permeability, namely, fracture permeability. On the basis of the tectonic stress field simulation, with the constraints of outcrop fracture model and fracture parameters identified by core description, fracture ICT (industrial computed tomography) scanning (Lai et al. 2017b) and FMI image log of wells (Lai et al. 2018), combined with research results in lost circulation while drilling and well testing interpretation and introduction of the concept of fracture filling degrees, the three-dimensional spatial distribution of fracture effectiveness (fracture permeability) is determined (Eq. 1) (Song et al. 2001), with respect to the fracture density, aperture and filling degrees in the Keshen gas field, using the tectonic fracture-tectonic stress correlation model developed in previous studies (Wang et al. 2016). In general, the fracture permeability is in direct proportion to the fracture line density and the cube of the fracture aperture, and in inverse proportion to the filling degree. Among these parameters, the most sensitive control factor is the fracture aperture, which is mainly controlled by the structural pattern and the fracture tensile zone. The thickness of the tensile zone of the faulted anticline gradually increases with the increase in the thrust shortening rate and the decrease of the wing angle. The thickness of the transition zone and tensile zone at the southward hinge zone is larger, and the tensile zone thickness of the southern wing is larger than that of the northern wing. With the increase in the thrust shortening rate, the tensile-transition zone gradually extends from the hinge zone to both wings (Fig. 8).

$$\left[ {\begin{array}{*{20}c} {K_{\text{f}X} } \\ {K_{\text{f}Y} } \\ {K_{\text{f}Z} } \\ \end{array} } \right] = \mathop \sum \limits_{i}^{n} \left[ {\begin{array}{*{20}c} {K_{\text{f}Xi} } \\ {K_{\text{f}Yi} } \\ {K_{\text{f}Zi} } \\ \end{array} } \right] = \left( {1 - C} \right)^{3} \mathop \sum \limits_{i}^{n} \frac{{b_{\text{m}i}^{3} D_{1\text{f}i} }}{12}\left[ {\begin{array}{*{20}c} {1 - n_{\text{f}1i}^{2} } \\ {1 - n_{\text{f}2i}^{2} } \\ {1 - n_{\text{f}3i}^{2} } \\ \end{array} } \right]$$
(1)

where K is the fracture permeability; KfX, KfY, and KfZ represent the fracture permeability in three directions, respectively, 10−3 μm2; KfXi, KfYi, and KfZi represent the fracture permeability component in three directions, 10−3 μm2; Dlf is the fracture line density, fractures/m; C is the fracture filling coefficient (measured quantitatively by core observation and ICT scanning). When the fracture is not filled, C = 0; when the fracture is completely filled, C = 1. b is the fracture aperture, mm; n is the permeability tensor (obtained from the fracture occurrence of the core observation or FMI logging).

Fig. 8
figure 8

Simulation diagram of dynamic evolution of the tension zone and transition zone of the Keshen gas field in the foreland thrust belt of Kuqa depression

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The filling degree in different structural parts is an important factor influencing fracture effectiveness. Core observation demonstrates that fractures on the limb always have higher filling degree than that on the hinge of anticline (Fig. 4a), especially which close to the boundary faults, where the fracture filling degree can reach to 70% (Well Keshen207).

5.2 Petroleum geological significance of effective fractures

5.2.1 Contributions/effects of fractures to/on reservoir storage space and permeability

According to the ICT experimental study of fractured core, for tight sandstone reservoirs, the porosity provided by effective fractures is generally less than 0.5% (Fig. 9). Therefore, tectonic fracture usually does not exist as the main type of reservoir space, but as an efficient seepage channel, which can greatly improve the permeability of reservoir. The core measurement of Keshen gas field shows that the matrix permeability without fractures is generally (0.01–0.1) × 10−3 μm2, while the permeability with fracture is generally (1–10) × 10−3 μm2 (Fig. 10), which is 1–2 orders of magnitude higher than the matrix permeability, and the maximum permeability of single well test is 116.5 × 10−3 μm2, proving that the effective fracture significantly improves the permeability of tight sandstone reservoir.

Fig. 9
figure 9

Histogram of fracture porosity of the Keshen gas field in the foreland thrust zone of Kuqa depression

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Fig. 10
figure 10

Matrix permeability and fracture permeability of the Keshen gas field in the foreland thrust zone of the Kuqa depression

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5.2.2 Influence of fracture-pore-throat homogeneous network on natural gas productivity

Core plug testing and well logging interpretation demonstrate that the matrix physical property has not significant variations in different structural belts. Therefore, the development of effective fractures in tight sandstones will become the most important factors influencing gas production (Lai et al. 2017a; Ameen et al. 2012).

The gas reservoir of the Kuqa foreland thrust belt is all associated with a faulted anticline structure. Due to the concentrated tectonic strain in the high part of anticline, tectonic fractures relatively extensively develop in the higher part, with larger aperture and lower filling degrees than those of tectonic fractures in other structural positions. The netted tectonic fracture has a good communication with reservoir matrix pores and throats, forming superior seepage channels, which are important guarantees for high and stable production. When the netted open fractures and vertical open fractures densely develop in the higher part of the structure, they communicate effectively with the reservoir matrix pores and throats (generally fine mesopores and fine throats, classified in accordance with SYT 6285-1997 Evaluating Methods of Oil and Gas Reservoirs), and thus form a fracture-pore-throat seepage network system. The formation fluid pressure is balanced with the supply from fractures to the wellbore by the fluid supply from matrix rock to fracture, which leads to an apparent-homogenous to medium-heterogeneous body (Fig. 11), which can present high production and moreover long-term stable production of natural gas.

Fig. 11
figure 11

Contributions of the reservoir fracture-pore-throat network system to hydrocarbon production in the Keshen area of the foreland thrust belt of the Kuqa depression

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Many wells including KeS8, 801, 802, 8-1, 8-2, 8003, 8004 are of this type. The 6746-6897 m section of Well KeS8003 is recovered with a 10 mm choke after completion of acid fracturing, resulting in daily output of 113.604 × 104 m3. On November 12, 2013, it starts the production testing, with a daily natural gas production of 88 × 104 m3. After 54 days of production, the tubing pressure drops from 88.2 to 85.09 MPa, and the monthly pressure drop rate is 1.73 MPa/month, which indicates the tubing pressure is basically stable (Fig. 12).

Fig. 12
figure 12

Distribution of high-production stable-production zones in Block 2, the Keshen area, the foreland thrust belt, the Kuqa depression

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Reservoir production testing characteristics

Open flow test results, 104 m3 d−1

Static characteristics of reservoir structures

Reservoir properties

Representative wells

Reservoir control factors

Well performan-cetypes

Homogeneity of double-porosity media

Typical production testing curves

Fracture characteristics

Matrix pores

Matrix throat

Fracture-pore-throat configuration type

Structural model (linear fracture, star-flake pore)

Porosity, %

Permeability, 10−3 μm2

High yield with stable tubing pressures (Ia)

The fractures are well developed, and the supply of matrix rocks to fractures matches the supply of fractures to the wellbore

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 > 200

Dense netted open fractures

Mainly mesopores

Mainly Micro throat

Highly efficient and apparent-homogeneous, with netted fractures and medium hole micro throat

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Well logging: 6.0–10.0

Well logging: 0.06–0.08 Testing: > 100

kes2-1-6, 2-1-14, 8003, 801, 8004, 802etc

Fracture, dissolution, lithofacies

High yield yet with slow decline (Ib)

Fractures are developed, the supply capacity of matrix rocks to fractures is less than that of fractures to wellbore

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150–200

Dense netted and vertical open fractures

Mainly fine-to-medium pores

Mainly fine throat

Medium-heterogeneous, with vertical fractures, fine mesopores, and fine throats

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Well logging: 6.0–8.0

Well logging: 0.05–0.08 Testing: 10–100

kes2-2-4, 2-2-8, 3, 201, 203, 206, 8, 8-1, 8-2

Fracture, dissolution, lithofacies

6 Conclusion

  1. (1)

    Tectonic fractures in the thrust belt include EW-trending high-angle tensile fractures and nearly NS-trending vertical shear fractures. The former is related to the Cretaceous and Paleogene EW regional extension and the bending and arching of the anticline, and the fracture filling rate is relatively high. The latter is related to the NS tectonic compression in the mid-late Himalayan Period, and most of these fractures are unfilled. Microstructural cracks are usually grain-piercing-through cracks with width of 10–100 microns. In FMI image log, tectonic fractures are mainly arranged in parallel.

  2. (2)

    In the planar view, the effective fractures are concentrated in the high part and the wing zones of the long axis of anticline, and along the vertical direction they mainly develop in the tensile fracture zone above the neutral plane. The adjustment fracture zone has strong longitudinal extension abilities and high effectiveness, followed by the nearly EW longitudinal tensile fracture zone, and the netted fracture zone with multiple dip angles.

  3. (3)

    Fracture effectiveness is mainly controlled by fracture density, aperture and filling degrees, among which the fracture aperture is the most critical and most sensitive factor. High fracture aperture is mainly seen in the fracture tensile zone. The tectonic fracture can directly increase permeability of the reservoir matrix by 1–2 orders of magnitude, and increase the porosity by less than 0.5%. The higher part of the thrust anticline is characterized by concentrated tensile strains, high fracture density, large aperture, low filling degrees, and thus good fracture effectiveness. Such zones are associated with high tectonic fracture permeability, which controls enrichment and high production of natural gas.

  4. (4)

    When the netted open fractures and vertical open fractures densely develop in the high part of the structure, they communicate effectively with the reservoir matrix pores and throats, which forms a fracture-pore-throats seepage network system. The formation fluid pressure is balanced with the supply from fractures to the wellbore by the fluid supply from matrix rock to fracture, which leads to an apparent-homogenous to medium-heterogeneous body that is seen with high yield and long-term stable production of natural gas.