Multi-Fracture Synchronous Propagation Mechanism of Multi-Clustered Fracturing in Interlayered Tight Sandstone Reservoir

Abstract

A numerical model was established by using the 3D lattice method to investigate the synchronous propagation mechanism of multiple clusters of hydraulic fractures in interlayered tight sandstone reservoirs in the Songliao Basin in China. The multi-fracture synchronous propagation model under different geological factors and fracturing engineering factors was simulated. The results show that the vertical stress difference, interlayer Young’s modulus, and lithologic interface strength are positively correlated with the longitudinal propagation ability of multiple hydraulic fractures. The three clusters of hydraulic fractures can have adequate longitudinal extension capacity and transverse propagation range with 15 m cluster spacing and a 12 m³/min pumping rate. The viscosity of the fracturing fluid is positively correlated with the ability of hydraulic fracture to penetrate the interlayer longitudinally but negatively correlated with the transverse propagation length. It is recommended that high viscosity fracturing fluid is used in the early stage of multi-clustered fracturing in interlayered tight sandstone reservoirs to promote hydraulic fractures to penetrate more interlayers and communicate more pay layers in the longitudinal direction, and low viscosity fracturing fluid in the later stage to make multiple clusters of fractures propagate to the far end where possible and obtain a more ideal SRV.

1. Introduction

The exploration and development potential of tight oil resources in the northern Songliao basin is enormous, but the early development practice indicates that hydraulic fracturing in tight oil reservoirs in this region faces two technological challenges. On the one hand, the natural fractures in the reservoir are not developed, the horizontal in-situ stress difference is large, and the reservoir brittleness is low. The hydraulic fractures cannot effectively activate the natural fractures in the extension process, and the complex fracture network is difficult to form. On the other hand, sandstone and mudstone layers are alternately developed in the vertical direction of the reservoir, which belongs to a typical interlayered tight sandstone reservoir. The interlayer of mudstone is thin, and its shielding capacity is weak, which limits the vertical extension of hydraulic fractures and makes it difficult to obtain an ideal stimulated reservoir volume (SRV). The multi-clustered fracturing technology with small cluster spacing can obtain relatively dense transverse propagation artificial fractures, greatly shorten the distance of fluid seepage from the matrix to the fractures, and effectively improve the fracturing effect of reservoirs with strong plasticity, a large in-situ stress difference, and the inability to create a complex fracture network. However, under the effect of stress shadow, decreasing the distance between clusters makes it harder for hydraulic fractures to penetrate interlayers and connect with multiple pay layers next to them. This greatly reduces the development efficiency of oil and gas resources in interlayered tight sandstone reservoirs.

Many scholars have studied the longitudinal propagation behavior of hydraulic fractures in multi-lithologic formations. Hanson et al. [1] and Fu et al. [2] carried out a series of hydraulic fracturing simulation experiments and found that the cementation strength and friction coefficient of the lithologic interface are the key factors affecting whether the hydraulic fracture penetrates the lithologic interface. When the interface is not fully cemented, the hydraulic fracture will deflect when it encounters the interface. The tests of Goldstein et al. [3] revealed that the hydraulic fracture will also penetrate the friction interface without cementation strength as long as the interface friction coefficient is large enough. The differences in mechanical properties and stress states of different layers will also significantly affect the vertical propagation behavior of hydraulic fractures in multi-layered formations. Biot’s theoretical calculation results demonstrated that the product of interlayer shear modulus and fracture surface energy is the most important component in controlling fracture vertical propagation behavior [4]. Some studies found that when other conditions are certain, the interlayer with a high horizontal minimum in-situ stress, high tensile strength, and small elastic modulus can inhibit the propagation of hydraulic fractures along the interface and increase the vertical extension ability [5,6,7,8,9]. Furthermore, the factors influencing the longitudinal propagation of hydraulic fractures have a combined effect [10,11,12]. Some scholars studied the fracture propagation mechanism of multi-layered formations by numerical simulation. They discovered that even when the interface strength is low, hydraulic fractures can penetrate the lithologic interface if the vertical stress difference and interface angle are large enough. When the included angle between the hydraulic fracture and the interface is less than 45° and the tensile strength ratio of the pay layer and the interlayer is less than 0.3, the hydraulic fracture cannot penetrate the interface no matter how large the vertical stress difference is [13,14]. Some studies experimentally discovered that the fracture can directly penetrate the interface only when the vertical stress reaches a certain threshold, but the threshold gradually increases with the decrease in the interface friction coefficient [15,16]. In addition to the geological considerations mentioned above, the fracturing treatment parameters will considerably impact the longitudinal propagation pattern of hydraulic fractures. When the geological conditions are the same, the greater the net pressure in the hydraulic fracture, the easier it is for the hydraulic fracture to penetrate the lithologic interface. The net pressure in the fracture is significantly related to the fracturing fluid pumping rate and viscosity [17,18]. Tan et al. [19,20] performed several hydraulic fracturing experiments, and Fu et al. [21] used a finite element numerical simulation to show that the viscosity and injection rate of the fracturing fluid have a significant effect on how the fracture propagates and penetrates the barriers. Liu et al. [22] numerically found that there is a threshold for the injection rate of fracturing fluid to ensure the propagation of hydraulic fractures in the barrier. When the ratio of net pressure to in-situ stress difference is less than 0.56, hydraulic fractures cannot penetrate through the interface and into the barrier.

Most of the present research focuses on the longitudinal propagation mechanism of a single hydraulic fracture in multi-layered formations. However, as multi-clustered fracturing has become the key technology of tight oil development, the multiple hydraulic fractures propagation has a competitive effect, which is significantly different from the single fracture propagation mechanism. Therefore, it is necessary to explore the vertical and horizontal propagation mechanism of multi fracture synchronization in the multi-clustered fracturing process of the interlayered tight reservoir. In this work, a multiple fracture propagation numerical model by the 3D lattice method is established to investigate the transverse and longitudinal propagation mechanism of multiple fractures in the process of multi-clustered fracturing of interlayered tight sandstone reservoirs. Through this numerical model, based on clarifying the multiple fractures’ propagation behavior under different interlayer elastic modulus, lithologic interface strength and reservoir stress state, the control effect of engineering parameters such as cluster spacing, fracturing fluid pumping rate and viscosity on the transverse and vertical propagation capacity of multi-fractures is revealed.

2. Multiple Fracture Propagation Model of Interlayered Tight Sandstone Reservoir

2.1. Simulation Method

The 3D lattice model of Xsite is coded by the integrated rock mass grid algorithm, which can simulate the meso damage of rock mass and the relative slip of rock matrix on the discontinuity plane. It is very suitable for the numerical analysis of the initiation and extension processes of hydraulic fractures. The connection between particles in the model is based on the particle cementation algorithm and the discrete element algorithm. The 3D lattice is connected by a series of quasi-randomly distributed nodes through elastomers, as shown in Figure 1. The connection mode of nodes is similar to the particle cementation algorithm, but it has higher computational efficiency. When the distance between nodes is small relative to the size of the whole model, the model is a continuum, which is used to characterize the rock matrix. At the same time, joints of any size and direction can be inserted into the model by breaking the elastomer. The nodes at the joints are calculated using the smooth joint model. When the stress of the spring between nodes exceeds its strength, it breaks and forms cracks. The gap between nodes is defined as a pipe, which is used to calculate the micro flow of fluid and act the fluid pressure on the rock matrix. At the same time, the deformation of the matrix will cause a change in pore pressure and pore diameter [23,24].

The change in normal force and tangential force of the spring can be calculated by the relative displacement of the node, that is [25]:

$$F_i^N\leftarrow F_i^N+{\dot{u}}_i^N{k}^N\Delta t,$$

(1)

$$F_i^S\leftarrow F_i^S+{\dot{u}}_i^S{k}^S\Delta t,$$

(2)

where: F^N and F^S are normal force and tangential force, N; ${\dot{u}}_i^N$ and ${\dot{u}}_i^S$ are normal velocity and tangential velocity, m/s; k^N and k^S are the normal stiffness and shear stiffness of the spring, respectively, N/m.

If F^N exceeds the tensile strength or F^S exceeds the shear strength, it is judged that the spring has a tensile failure or shear failure. The flow q along the pipe between two nodes (A and B) is calculated according to the following relationship:

$$q=\beta K_r\frac{a^3}{12\mu }[P^A-P^B+{\rho }_{w}g(Z^A-Z^B)],$$

(3)

where: q is the flow between nodes, m³/s; β is the correction factor; K_r is the relative permeability, 10⁻³ μm²; a is the pipe diameter, m; μ Is the fluid viscosity, Pa·s; P^A and P^B are node pressure, Pa; ρ_w is the fluid density, kg/m³; g is the acceleration of gravity, m/s²; Z^A and Z^B are node heights, m.

In the fluid time step Δt_f, fluid pressure increment in ΔP is:

$$\Delta P=\frac{Q}{V}{K}_f\Delta t_f,$$

(4)

$$Q={\displaystyle \sum _{i=1}^n{q}_i},$$

(5)

where: ΔP is the pressure increment, Pa; q is the sum of all flows of connecting node pipes, m³/s; i represents the ith pipeline connected to the node; V is node volume, m³; K_f is the apparent fluid bulk modulus, Pa; Δt_f is the fluid time step, s.

2.2. Establishment of Numerical Model and Parameter Setting

According to the geological characteristics of interlayered tight oil reservoirs in the north of the Songliao Basin, a multiple fractures’ propagation model of an interlayered tight sandstone reservoir is established by using the 3D lattice method, as shown in Figure 2. The model size is 60 m × 80 m × 48 m, including three pay layers with a thickness of 12 m and two interlayers with a thickness of 6 m. There is a lithologic interface between the pay layer and the interlayer. A horizontal well with three perforation clusters is set in the middle pay layer, and the initial cluster spacing is 10 m. In the model, the minimum horizontal principal stress (σ_h = 35 MPa), the vertical stress (σ_v = 38 MPa) and the maximum horizontal principal stress (σ_H = 40 MPa) are applied in the x, y and z directions, respectively. The rock mechanical parameters and fracturing treatment parameters in the model are shown in

Table 1. Rock mechanics parameters and fracturing treatment parameters in the model.

Parameters	Pay Layer	Interlayer
Tensile strength (MPa)	3.5	4.5
Uniaxial compressive strength (MPa)	79.5	89.5
Young’s modulus (GPa)	26.2	21.2
Poisson’s ratio	0.22	0.23
Permeability (10−15 m2)	0.5	1.2
Vertical in-situ stress (MPa)	38	38
Minimum horizontal principal stress (MPa)	35	35
Maximum horizontal principal stress (MPa)	40	40
Pumping rate of fracturing fluid (m3/min)	8
Viscosity of fracturing fluid (MPa·s)	6

. The rock mechanical parameters are obtained from the laboratory mechanical tests, and the treatment parameters are based on the field data.

3. Influence of Formation Mechanical Properties on Vertical Propagation of Multiple Clusters of Hydraulic Fractures

This section investigates the effects of formation mechanical properties such as vertical stress difference, interlayer Young’s modulus, and lithologic interface strength on the synchronous propagation of multiple clusters of hydraulic fractures under different formation dip angles using the multi-fracture propagation numerical model of an interlayered tight sandstone reservoir.

3.1. Influence of Vertical In Situ Stress Difference

The vertical stress difference (σ_v−h) in this paper is defined as the difference between the vertical in-situ stress and the horizontal minimum principal stress. As shown by comparing the fracture propagation modes in Figure 3, σ_v−h has a significant impact on multi-fracture propagation. When σ_v−h = 1 MPa, the three hydraulic fractures have different longitudinal propagation behaviors after encountering the upper and lower lithologic interface. Due to the small vertical stress difference, the induced stress near the wellbore is reversed, and the intermediate hydraulic fractures have significant torsional propagation before encountering the interface. At the initial stage, the outer hydraulic fractures deflect and propagate along the interface, then penetrate into the interlayer again and extend towards the direction of the horizontal minimum principal stress in the interlayer. Until the fracturing procedure is completed, the three clusters of hydraulic fractures cannot penetrate into the adjacent pay layers. When σ_v−h = 3 MPa, the outer two clusters of hydraulic fractures penetrate the interlayers in the longitudinal direction, so as to better communicate the upper and lower pay layers. However, when the intermediate fracture encounters the interface, an “H” shaped extension mode appears, and its extension path is completely limited to the intermediate pay layer. When σ_v−h increases to 7 MPa, the upper end of the middle hydraulic fracture still extends along the lithologic interface, but the lower end of the fracture penetrates the interlayer and communicates with the adjacent pay layer. When σ_v−h increases to 9 MPa, the longitudinal propagation capacity of the intermediate hydraulic fracture is improved, but it still cannot penetrate the upper interlayer.

Figure 4 shows the statistical results of the stimulated reservoir area (SRA) under different σ_v−h. The tensile SRA reflects the tensile fracture in the rock matrix, which includes the extended fracture in the pay layer and fractures that penetrate into the interlayer, whereas the shear SRA represents the shear fracture that deflects and extends along the lithologic interface. When there is no dip angle in the interlayer, the total SRA of the three clusters of hydraulic fractures gradually increases with the increase in σ_v−h, in which SRA significantly increases and shear SRA gradually decreases, indicating that the increase in σ_v−h will limit the ability of hydraulic fractures to extend along the interface, so as to increase the ability of hydraulic fractures to penetrate the interlayer and communicate with adjacent pay layers. Figure 5 shows the variation of tensile SRA with σ_v−h under different interlayer inclinations. In the interlayered tight sandstone formation with different dip angles, the promotion effect of σ_v−h on the vertical propagation ability of hydraulic fractures is different. When the dip angle of the interlayer increases to 20°, although the tensile SRA still increases with the increase in the σ_v−h, the increased amplitude decreases with the increase in the dip angle of the interlayer, indicating that the dip angle of the interlayer has a significant inhibitory effect on the vertical expansion of hydraulic fractures. To improve the vertical propagation ability of multiple clusters of fractures and the communication effect of longitudinal pay layers, it is critical to select a reservoir with a large vertical stress difference and a small interlayer dip angle.

3.2. Influence of Young’s Modulus of Interlayer

Figure 6 compares the effect of the Young’s modulus (E_i) of the interlayer on the longitudinal propagation of multiple hydraulic fractures under the condition of a non-inclined interlayer. When E_i = 15 GPa, the propagation of three clusters of hydraulic fractures is almost completely limited to the middle pay layer. When E_i reaches 20 GPa, the outer two clusters of hydraulic fractures penetrate the lithologic interface but stop extending into the interlayer. When E_i increases to 25 GPa, the longitudinal propagation ability of the outer two clusters of hydraulic fractures is further improved, both penetrating the interlayer and connecting the adjacent pay layers. When E_i increases to 30 GPa, the Young’s modulus of the interlayer has exceeded that of the pay layer. The outer two clusters of hydraulic fractures communicate with the adjacent pay layers and the upper part of the middle fracture penetrates the interlayer and enters the pay layer.

In Figure 7, when there is no dip angle in the interlayer, the total SRA and tensile SRA of the three clusters of hydraulic fractures increase with the increase in E_i, but the shear SRA does not increase significantly, indicating that the increase in the Young’s modulus of the interlayer promotes the ability of hydraulic fracture to penetrate the lithologic interface and interlayers and has little effect on the deflecting of hydraulic fracture along the interface. Through the comparison in Figure 8, it can be further seen that with the increase in interlayer inclination, the promoting effect of interlayer Young’s modulus on the longitudinal propagation ability of hydraulic fractures gradually decreases. Therefore, to ensure the effect of layer-penetration fracturing of interlayered tight oil reservoirs, it is necessary to select the layer with a small interlayer dip angle and a high interlayer Young’s modulus for hydraulic fracturing.

3.3. Influence of the Strength of Lithologic Interface

In Figure 9, the lithologic interface tensile strength (σ_ti) has a significant impact on the longitudinal propagation of multiple clusters of fractures. When σ_ti = 1.0 MPa, the middle hydraulic fracture completely deflects along the upper and lower lithologic interfaces, showing an “H” shaped extension mode, while the outer hydraulic fractures first deflect along the interfaces, then re-enter the interlayers but never penetrate them. When σ_ti increases to 1.5 MPa, the entire right hydraulic fracture and the upper part of the left hydraulic fracture penetrate the interlayer and connect with the adjacent pay layers. When σ_ti reaches 2.5 MPa, the ability of the two clusters of hydraulic fracture on the outside to propagate longitudinally is further strengthened, and they continue to extend into the neighboring pay layers after penetrating the upper and lower interlayers. When σ_ti increases to 3.0 MPa, three clusters of hydraulic fractures penetrate the interlayers and effectively communicate with the adjacent pay layers.

In Figure 10, the total SRA of the three clusters of hydraulic fractures increases and subsequently drops as σ increases, with the tensile SRA greatly increasing and the shear SRA dramatically decreasing. It demonstrates that increasing the tensile strength of the lithologic interface increases the longitudinal propagation ability of hydraulic fractures while inhibiting the deflecting of hydraulic fractures along the interface. To achieve a significant fracture height and a fracture extension area at the same time, it is critical to choose an interlayered tight sandstone reservoir with adequate lithologic interface strength for multi-clustered fracturing. In Figure 11, when the interlayer dip angle is small, increasing the lithologic interface strength increases the tensile fracture area in the rock matrix, improving the longitudinal extension capability of the hydraulic fracture. However, as the interlayer dip angle increases to 20°, the influence of interface strength on fracture penetration behavior reduces.

4. Influence of Fracturing Operation Parameters on Propagation of Multiple Clusters of Hydraulic Fractures

Fracturing operation parameters also have a significant impact on the multi-fracture propagation mode in interlayered tight sandstone reservoirs [26,27]. This part uses the established numerical model to study the effects of cluster spacing (S), fracturing fluid pumping rate (Q), and fracturing fluid viscosity (η) on reservoir fracturing effects to optimize the multi-clustered fracturing operation parameters.

4.1. Influence of Perforation Cluster Spacing

Cluster spacing (S) has an important influence on whether an efficient fracture network can be formed [28,29]. At present, the cluster spacing in the multi-clustered fracturing design scheme of the tight sandstone reservoir in the north of the Songliao basin ranges from 5 m to 15 m. However, the reasonable cluster spacing to ensure the longitudinal capacity and transverse extension range of multiple fractures still needs to be further explored. In Figure 12, the numerical simulation results show that when S = 5 m, the interaction between multiple fractures is the most significant, which is characterized by the continuous torsion of the intermediate hydraulic fracture when it propagates in the middle pay layer. In the longitudinal direction, the middle fracture deflects along the upper and lower lithologic interface, while in the transverse direction, only one end of the middle fracture extends to the far field, and the other end twists violently near the well and communicates with the outer two clusters of fractures. A more complex fracture shape is formed near the wellbore, but the longitudinal extension range of the fracture is small. When S increases to 10 m, the interaction among hydraulic fractures near the wellbore is significantly weakened, and there is no communication between multiple fractures in the middle pay layer, and the longitudinal propagation ability of the three clusters of fractures is improved. When S increases to 15 m, the multiple fractures hardly interfere with each other near the wellbore, and the three clusters of hydraulic fractures penetrate the sandstone interlayers in the longitudinal direction, successfully communicating with multiple nearby pay layers. In the transverse direction, with the increase in cluster spacing, the length of the middle fracture increases while the length of the two outer clusters decreases. It demonstrates that increasing cluster spacing can greatly reduce interference among hydraulic fractures. The larger the cluster spacing is, the lower the inhibition degree of the outer fracture to the propagation of the middle fracture is.

In Figure 13, with the increase in S from 5 m to 15 m, the total SRA shows a trend of first rising and then falling and has the highest value when S = 10 m. The tensile SRA gradually increases, and the shear SRA gradually decreases, which indicates that the increase in cluster spacing will improve the longitudinal propagation ability of multiple hydraulic fractures and weaken the deflecting extension ability of fractures at the interfaces. Figure 14 shows the variation of hydraulic fracture length of each cluster with cluster spacing. Both the intermediate hydraulic fracture length and the total length of three fractures increase significantly as cluster spacing increases, indicating that increasing cluster spacing weakens the horizontal competitive propagation effect of multiple hydraulics. When the cluster spacing exceeds 15 m, although the induced stress among multiple fractures is lowered further and each fracture tends to propagate separately, the matrix seepage region between hydraulic fractures is too wide. Based on the above analysis, a cluster spacing of 15 m may ensure that multiple fractures penetrate the interlayer in the longitudinal direction, allowing multiple pay layers to connect, and that multiple clusters of fractures fully propagate in the transverse direction.

4.2. Influence of Fracturing Fluid Pumping Rate

The fracturing fluid pumping rate (Q) will significantly affect the fluid pressure distribution in hydraulic fractures, thus changing the characteristics of fracture propagation [30,31]. The pumping rate is the most important controllable parameter in hydraulic fracturing design. In previous studies, a larger pumping rate was conducive to a single hydraulic fracture penetrating the lithologic interface in the interlayered formation [32,33]. In this paper, the effect of the fracturing fluid pumping rate on the longitudinal propagation ability of multiple fractures is further studied by using the multi-clustered fracturing numerical model.

In Figure 15, when Q = 4 m³/min, the three hydraulic fractures show different propagation characteristics in the longitudinal direction. The lower end of the left hydraulic fracture penetrates the lithologic interface and interlayer, thus connecting the lower pay layer, but the upper end of the fracture stops extending into the upper interlayer. The intermediate fracture exhibits a substantial “H” deflection propagation mode when it encounters the lithologic interface and does not enter the upper and lower interlayers. The right hydraulic fracture first deflects briefly near the lithologic interface, and then re-enters the interlayer but does not penetrate the interlayer into the adjacent pay layer. Furthermore, the middle and right fractures twist violently towards the well and communicate with one another. When Q increases to 8 m³/min, the two hydraulic fractures on the outside penetrate the upper and lower interlayers and better communicate with the adjacent pay layers. However, the middle fracture’s longitudinal extension ability is poor as it does not penetrate the interlayer and twists near the wellbore and connects to the right hydraulic fracture. When Q increases to 12 m³/min, the two outside fractures’ longitudinal propagation is unchanged, but the middle fracture penetrates into the adjacent pay layers, and the three vertical pay layers are effectively joined by three clusters of hydraulic fractures.

In Figure 16, the total SRA and tensile SR dramatically A rise when Q increases from 4 m³/min to 12 m³/min, but shear SRA changes little, indicating that increasing Q improves the longitudinal extension capacity of multiple clusters of hydraulic fractures. Existing studies indicate that increasing the Q in homogeneous reservoirs increases the fluid pressure in the fracture, which increases the height and width of the hydraulic fracture and reduces the length to some extent, indicating that the fracturing operation with higher Q is conducive to the formation of short and wide fractures [34,35]. However, the results of this study are different from the above conclusions. In the interlayered tight sandstone reservoir, the total length of the three clusters of fractures increases first and then decreases with Q (Figure 17). The reasons behind this law can be summarized in two aspects. On the one hand, when Q is small, the filtration of fracturing fluid in the lithologic interface is large, which reduces the net pressure in the fractures, thus weakening the horizontal and vertical extension ability of hydraulic fractures. On the other hand, when Q is small, multiple clusters of hydraulic fractures near the wellbore will communicate the torsional fractures generated by other hydraulic fractures. The torsional fractures near the wellbore will also weaken the vertical and horizontal extension ability of hydraulic fractures. Therefore, when Q increases from 4 m³/min to 8 m³/min, the total length of the three clusters of fractures shows an increasing trend. When Q is increased from 8 m³/min to 12 m³/min, however, the propagation of hydraulic fractures along the lithologic interface and torsional propagation near the wellbore cease to be significant. At this time, the overall length of the three fracture clusters decreases as Q increases. Although the multiple clusters of hydraulic fractures’ total length are slightly reduced under the injection rate of 12 m³/min compared with the pumping rate of 8 m³/min, they are ideal for communicating with the adjacent pay layers to improve the SRV and improve the production efficiency of multi-layered reservoirs.

4.3. Influence of Fracturing Fluid Viscosity

The fracturing fluid viscosity (η) is another important controllable operation parameter in hydraulic fracturing design. In Figure 18, although the two clusters of fractures on the outside penetrate the upper and lower interlayers when η = 1 mPa·s, they do not communicate efficiently with the adjacent pay layers, and the extension of the middle hydraulic fracture is limited to the interlayer. When η increases to 11 mPa·s, the longitudinal extension ability of three clusters of hydraulic fractures is enhanced. When η increases to 21 mPa·s, the hydraulic fractures on the outside communicate better with the adjacent pay layers, and the intermediate fracture penetrates the top interlayer and enters the neighboring pay layer. It is obvious that increasing the viscosity of the fracturing fluid can improve the longitudinal extension ability of hydraulic fractures.

Figure 19 shows that when η increases, the overall SRA increases, but not dramatically; on the other hand, the tensile SRA grows significantly, and the shear SRA gradually declines. This demonstrates that increasing η can inhibit the propagation of hydraulic fractures along the lithologic interface, increasing the capacity to penetrate the interface and interlayer. In terms of fracture length (Figure 20), when η grows, the width of each cluster of hydraulic fractures increases but the length decreases, showing that it is easier to produce short width hydraulic fractures under high fracturing fluid viscosity conditions. To summarize, η is positively connected with hydraulic fracture longitudinal propagation ability but negatively correlated with transverse propagation ability. As a result, it is recommended that in the early stage of hydraulic fracturing of an interlayered tight sandstone reservoir, high viscosity fracturing fluid (above 21 mPa·s) be used to promote the hydraulic fractures to penetrate more interlayer and communicate more pay layers in the longitudinal direction, and low viscosity (about 1 mPa·s) fracturing fluid be utilized to guarantee that many hydraulic fractures have a large propagation range in the transverse direction, hence improving the ultimate SRV.

5. Discussion

With the gradual reduction in recoverable reserves of conventional oil and gas resources and the increasing difficulty of development, tight oil has become an important kind of alternative energy to conventional oil and gas resources, which is expected to promote the sustainable development of petroleum industry. It is an important prerequisite for successful hydraulic fracturing and tight oil development to clarify the fracture propagation mechanism in tight reservoirs with complex geological conditions. For the hydraulic fracture propagation in the interlayered tight sandstone reservoir, most of the existing studies are carried out for the vertical propagation mechanism of a single hydraulic fracture, and do not consider the competition of multiple fracture propagation and the synergistic effect of vertical and transverse fracture propagation [10,12,36,37,38]. Compared with other finite element methods and discrete element methods, the 3D discrete lattice method is more efficient, and can be used for 3D hydraulic fracturing simulation at the field scale. The multiple fracture propagation numerical model established by the 3D discrete lattice method in this paper is innovative in three aspects: (a) The competition effect of multi fracture propagation is considered; (b) The existence of lithologic interfaces between pay layer and interlayer is considered; (3) SRA and fracture propagation length can be used to comprehensively explore the longitudinal and transverse propagation of multiple fractures. This study clarifies the influence of geological factors on the synchronous propagation of multiple fractures in the interlayered tight sandstone reservoir and reveals the engineering parameters that promote the longitudinal and transverse propagation of multiple hydraulic fractures. As the important parameters that engineers can master and adjust, the viscosity and pumping rate of fracturing fluid also have a double-sided impact on the propagation of hydraulic fractures. Higher pumping rate and fracturing fluid viscosity can promote multiple hydraulic fractures to connect multiple adjacent pay layers vertically and improve hydraulic fracturing efficiency. However, a lower injection rate or lower fluid viscosity will allow more fluids to enter natural fractures, which is conducive to the reactivation of natural fractures and increases the complexity of fractures [39,40,41,42]. As the formation conditions of unconventional reservoirs become more and more complex, it is obvious that the fixed fracturing operation procedure cannot achieve the desired vertical communication effect of multiple pay zones and transverse propagation range at the same time [43,44,45,46]. The fracturing method of variable pumping rate and variable fracture fluid viscosity is hopeful in solving this contradiction. The use of high viscosity fluid during the initial stage of fracturing can ensure that the hydraulic fracture can communicate with more pay layers in the longitudinal direction, whereas the use of low viscosity fluid during the latter stage of fracturing can ensure that the hydraulic fracture can continue to propagate to the far field and communicate with more natural fractures, thereby maximizing the hydraulic fracture’s propagation range. High pumping rates in the early stages can form a complex fracture network and improve hydraulic fracture vertical extension and communication with other pay zones. In the late stage, gradually decreasing the pumping rate can promote the reactivation of more far-field natural fractures. The results of this paper clarify the reasonable fracturing treatment parameters and provide a new research direction for the development of hydraulic fracturing technology in interlayered tight reservoirs, which is of great significance for realizing the efficient development of oil and gas resources and promoting the sustainable development of oil fields in the Songliao Basin in China.

6. Conclusions

(1)

In the multi-clustered fracturing process of interlayered tight sandstone reservoirs, the large vertical stress difference and lithologic interface strength are favorable to hydraulic fracture penetration into the upper and lower interlayers and limit their deflection along the interface. The interlayer Young’s modulus is only related to the longitudinal propagation of hydraulic fractures and has little effect on their deflecting propagation along the interface;

(2)

Under the same pumping rate and time, the increase in cluster spacing can improve the longitudinal propagation ability of multiple fractures and weaken the competitive effect of multiple fractures in transverse propagation. The 15 m distance between clusters can make sure that fractures connect to multiple pay layers in the longitudinal direction, and it can make sure that they have an ideal range of propagation in the transverse direction;

(3)

Although the multiple clusters of hydraulic fractures’ total length is slightly reduced under the injection rate of 12 m³/min compared with the pumping rate of 8 m³/min, they are ideal for communicating with the adjacent pay layers so as to improve the SRV;

(4)

The viscosity of the fracturing fluid is positively related to hydraulic fracture longitudinal penetration ability but negatively related to transverse propagation length. To obtain a larger SRV, the fracturing process needs to inject different viscosities of fracturing fluid at different times.