Mechanistic Analysis and Multi-Factor Coupling Optimization of Temporary Plugging Fracturing in Shale Oil Horizontal Wells: A Case Study from the Sichuan Basin, China

Abstract

Horizontal well fracturing is a pivotal technology for enhancing the efficiency of shale oil and gas development. Shale reservoirs exhibit significant heterogeneity and intricate fracture propagation patterns, often resulting in uneven multiple fractures caused by horizontal well fracturing. Temporary plugging technology plays a critical role in optimizing fracture propagation patterns; however, there is currently limited research on its optimization. Based on a hydraulic fracturing fracture propagation simulation, an optimization study was conducted on temporary plugging technology for horizontal well fracturing in shale oil reservoirs. Numerical simulation results demonstrate that the uniformity of hydraulic fracture propagation during horizontal well fracturing in shale oil reservoirs is maximized when 30 perforations are plugged. The most uniform fracture propagation pattern is achieved by adding temporary plugging agents after pumping a total volume of 30% fracturing fluid. Furthermore, a comparison between one-time plugging with temporary plugging balls and multiple plugging was made to evaluate differences in fracture propagation. It was observed that performing temporary plugging once significantly improves the uniformity of fracture propagation compared to multiple temporary plugging. These research findings have been successfully validated through the practical application of hydraulic fracturing techniques, as indicated by substantial improvements in both the mode and uniformity of fracture propagation following temporary plugging.

1. Introduction

China has identified substantial shale oil resources in the Sichuan Basin, Songliao Basin, and Sichuan Basin [1,2]. Shale oil is classified as an unconventional hydrocarbon reservoir characterized by low porosity, low permeability, and significant heterogeneity [3,4,5]. The extraction of oil and gas from shale oil reservoirs necessitates hydraulic fracturing, with horizontal well staged fracturing serving as the primary completion technology for such reservoirs [6]. The shale oil reservoirs exhibit notable heterogeneity and experience considerable stress variations. The propagation patterns of fractures induced by hydraulic fracturing display non-uniformity, while the lengths of hydraulic fractures vary considerably, thereby significantly impacting stimulation effectiveness [7].

Experts from around the world have extensively conducted research on the fracture propagation law of shale oil horizontal wells. Gao et al. [8] investigated the impact of density, viscosity, flow rate, number of boreholes, and fracturing fluid viscosity on the binding state of the spherical seal. The results demonstrate that by reducing the number of holes while utilizing high flow rates and high-viscosity fracturing fluids, it is possible to optimize the stress state of the plug ball and improve plugging efficiency. Jiang et al. [9] comprehensively examined force conditions during blocking and introduced an innovative pre-pitch pressure distribution technique. Wang et al. [10] developed a fluid–structure-coupling simulation model to investigate various factors’ impact on the fracture aperture during fracturing. The model accurately simulates both initial and diversion fractures’ propagation processes, while considering parameters such as tight plug permeability, length, Young’s modulus, rock tensile strength, in situ stress comparisons, and liquid injection rate. Zhang et al. [11] introduced a new experimental approach to simulate multiple fractures’ spread based on rock splitting and 3D reconstruction techniques for the characterizing of fracture geometry. The presence of previous fractures resulted in compression of the fracture aperture. Zou et al. [12], using a complex fracture model based on a three-dimensional discrete element method (DEM), simulated high-frequency propagation processes in naturally fractured strata during TPF. They studied how horizontal differential stress, natural fracture characteristics, plugging number/position, and pumping rate affect HF/NF interaction behavior, as well as the final HF geometry.

In order to address the issue of uneven fracture propagation in shale horizontal wells, the key parameters of temporary plugging fracturing, such as the number and timing of plugging balls, were optimized using advanced 3D fracturing software 2.0. The research findings were successfully implemented, and the fracture-monitoring results demonstrated a consistent and uniform fracture propagation during the temporary plugging fracturing process.

China’s shale oil resources are mainly distributed in the Sichuan, Ordos, Songliao, and Junggar Basins. Chinese shale oil reservoirs have a strong heterogeneity. The shale oil reservoirs in the Ordos Basin are mainly fine sandstone, while the Junggar Basin is mainly sandstone and shale, and the Sichuan Basin is mainly sandstone and shale. The shale oil and gas reservoirs in the Songliao Basin have well-developed bedding planes, with an average of 1000–3000 bedding fractures per meter of oil and gas reservoirs. The average porosity is 7.2%, and the average permeability is 1.37 mD. It is a typical low-porosity and low-permeability oil and gas reservoir [13]. The brittle mineral content of the Jurassic shale oil reservoir in the Sichuan Basin is 56.4%, with an average porosity of 2.84% and an average permeability of 0.83 mD. On average, there are 500 to 1000 bedding fractures per meter of reservoir development [14].

China’s shale oil geological resources are estimated at 300–500 billion tons, with substantial variations in distribution across major sedimentary basins [15]. The Songliao Basin contains the largest share (100–150 billion tons), predominantly within the Cretaceous Qingshankou Formation. Significant resources are also identified in the Ordos Basin (70–100 billion tons) and the Junggar Basin (50–80 billion tons). Smaller but economically viable accumulations occur in the Sichuan Basin (30–50 billion tons) and the Bohai Bay Basin (20–30 billion tons) [16,17,18].

Shale oil reservoirs in North America (e.g., Bakken, Eagle Ford) and China (e.g., Ordos Basin, Songliao Basin) exhibit distinct geological and geochemical characteristics. Foreign reservoirs typically feature a higher thermal maturity (Ro > 1.0%) and greater brittle mineral content (40–60% quartz/carbonate), enabling efficient hydraulic fracturing [19]. In contrast, Chinese shale reservoirs are generally less mature (Ro: 0.6–1.0%), with an elevated clay content (20–40%), resulting in poor fracability and complex fracture networks. Additionally, Chinese basins face a stronger tectonic heterogeneity, including multi-stage faults and stress anisotropy, complicating fracture propagation [20].

Compared to conventional reservoirs, shale oil reservoirs have a lower porosity and permeability, and the segmented fracturing of horizontal wells is a necessary means of increasing production in shale oil reservoirs. Due to the strong heterogeneity and low porosity and permeability of the reservoir, the clusters of fractures formed by horizontal well fracturing in shale oil reservoirs exhibit a non-uniform expansion pattern, which seriously affects the uniform exploitation of the reservoir.

2. Optimization of Temporary Plugging Fracturing Parameters

Temporary plugging fracturing is an advanced stimulation technique aimed at enhancing the complexity of fracture networks in unconventional reservoirs by redirecting hydraulic energy to understimulated zones. The fundamental principle involves the injection of degradable particulate or fibrous materials, referred to as “temporary plugging agents”, to seal pre-existing fractures during multi-stage fracturing operations. This process increases the near-wellbore pressure, overcoming local stress anisotropy and inducing fracture reorientation or branching through mechanisms governed by stress shadow effects and fluid diversion (Figure 1).

2.1. Introduction to Numerical Simulation Methods and Models

This paper focuses on a shale oil block located in the Sichuan Basin as its research subject. The shale oil reservoir is primarily composed of carbonate shale, exhibiting an average porosity of 3.6% and an average permeability of 0.052 mD, with matrix porosity being the predominant type of reservoir space. The lower limit for total organic carbon (TOC) associated with mobile oil is established at 1%, while the lower limit for porosity is set at 2.2%. Staged fracturing in horizontal wells represents a crucial technical approach to enhance oil production from these wells [21]. A key factor in improving the precision of the fracturing design lies in accurately understanding the fracture morphology resulting from staged fracturing operations conducted on shale horizontal wells within the Sichuan Basin. Due to significant reservoir heterogeneity, fractures generated during the fracturing process of shale oil horizontal wells in this region exhibit non-uniform extension patterns. This conclusion is further substantiated by microseismic monitoring data.

The shale oil reservoir in the Sichuan Basin exhibits significant heterogeneity, with fracture propagation characterized by non-planar extension due to interference effects. To enhance the fracturing design of horizontal shale wells in the Sichuan Basin, we employed a three-dimensional displacement discontinuity method to accurately model fracture interactions and deformation. This approach allows for a more precise simulation of multi-cluster fracturing processes in horizontal shale wells within this region.

We used the 3DDDM method developed by Wang Zhen [22] to characterize the deformation of multiple fracture clusters during the fracturing of shale horizontal wells in the Sichuan Basin. The displacement discontinuity equation of each fracture element is shown in Formula (1).

$$\begin{array}{c}{\sigma }_s^i=\sum _{j=1}^N{K}_{sl,sl}^{ij}{D}_{sl}^j+\sum _{j=1}^N{K}_{sl,sh}^{ij}{D}_{sh}^j+\sum _{j=1}^N{K}_{sl,nn}^{ij}{D}_{nn}^j\\ {\sigma }_{sh}^i=\sum _{j=1}^N{K}_{sh,sl}^{ij}{D}_{sl}^j+\sum _{j=1}^N{K}_{sh,sh}^{ij}{D}_{sh}^j+\sum _{k=1}^N{K}_{sh,nn}^{ij}{D}_{nn}^j\\ {\sigma }_{nn}^i=\sum _{j=1}^N{K}_{nn,sl}^{ij}{D}_{sl}^j+\sum _{j=1}^N{K}_{nn,sh}^{ij}{D}_{sh}^j+\sum _{j=1}^N{K}_{nn,nn}^{ij}{D}_{nn}^j\end{array}$$

(1)

${\sigma }_{sl}^i$: Shear slip stress at the $i$-th element (or node), representing the tangential stress along the slip direction.

${\sigma }_{sh}^i$: Transverse shear stress at the $i$-th element (or node), associated with the orthogonal shear direction.

${\sigma }_{nn}^i$: Normal stress at the $i$-th element (or node), acting perpendicular to the discontinuity surface.

$D_{sl}^j$: Shear slip displacement discontinuity at the$j$-th element (or node), quantifying the tangential relative displacement along the slip direction.

$D_{sh}^j$: Transverse shear displacement discontinuity at the $j$-th element (or node), describing the relative displacement in the orthogonal shear direction.

$D_{nn}^j$: Normal displacement discontinuity at the$j$-th element (or node), defining the separation or closure perpendicular to the discontinuity surface.

$K_{\alpha ,\beta }^{ij}$: Stiffness coefficient linking the displacement discontinuity component $D_{\beta }^j$ at the $j$-th element to the stress component ${\sigma }_{\alpha }^i$at the $i$-th element.

Subscripts $\alpha ,\beta$: Indicate the directional coupling between stress ($\alpha$) and displacement discontinuity ($\beta$), where $\alpha ,\beta \in \left\{sl,sh,\right.\left.nn\right\}$ correspond to $sl$ (shear slip), $sh$ (transverse shear), and $nn$ (normal).

Superscript $ij$: Denotes the interaction between the$j$-th source element and the $i$-th target element, reflecting geometric and material dependencies.

Equation (2) characterizes the governing equations for intra-fracture fluid flow, expressed as

$${\displaystyle \frac{\partial w}{\partial t}}=\nabla q+q_i-q_L$$

(2)

$q$ denotes the sand-carrying fluid volume, $q_i$represents the volumetric injection rate per unit area per unit time, and $q_L$ characterizes the fluid loss coefficient governing the leak-off behavior.

Based on the geological engineering parameters of typical wells in the Sichuan shale oil basin, we have established a large-scale numerical simulation model for horizontal well fracturing. The dimensions of the model are 400 m in both length and width, with a minimum unit size of 0.5 m. A horizontal well designated as “A” is positioned at the center of the fracturing simulation model. To streamline the calculation process and reduce the computational load, we focused on simulating fracturing within the horizontal section. Each stage measures 50 m in length and has been perforated into four clusters, with a flow rate set at 18 m³/min. The simulated fracturing fluid consists of low-viscosity slippery water, exhibiting a viscosity measurement of 10 mPa·s. The proppant employed is a blend of 70/140 mesh quartz sand and 40/70 mesh quartz sand, mixed in a volume ratio of 7:3.

Segmental fracturing is a crucial technique for enhancing the production of shale oil reservoirs. Given the significant variations in the maximum and minimum horizontal principal stresses within these reservoirs, the microseismic monitoring of the fracture morphology reveals notable differences, with individual clusters of fractures demonstrating a highly uneven expansion pattern.

Adding temporary plugging agents during fracturing seems very simple, but it involves multiple factors such as the addition time, amount, and frequency of temporary plugging agents, which affect the distribution of flow among the clusters and thus the fracture expansion pattern [21,23].

This paper investigates the fracture propagation modes of temporary plugging agents under varying addition times, quantities, and frequencies through numerical simulations. The objective is to optimize the temporary plugging fracturing scheme for shale oil reservoirs to achieve a uniform fracture expansion. The input data utilized in this fracturing simulation are presented in

Table 1. Input data for the fracturing simulation.

Porosity, %	3.6
Permeability, mD	0.052
Young’s modulus, 104 MPa	4.15
Poisson’s ratio	0.21
Horizontal maximum principal stress, MPa	54.3
Horizontal minimum principal stress, MPa	46.1
Fracturing fluid injection displacement, m3/min	18
Reservoir thickness, m	10
Compressive strength of rock, MPa	405.5
Fracturing fluid viscosity, mPa·s	10

.

2.2. Optimization of Temporary Plugging Agent Amount

A numerical model was developed using Frsmart fracturing simulation software 2.0 (developed by the China National Petroleum Corporation, Beijing, China) to investigate the effects of diverter concentration on fracture propagation in horizontal wells. The simulation domain, measuring 400 m × 400 m in horizontal dimensions, was discretized with a minimum grid size of 0.5 m to ensure the adequate resolution of fracture development characteristics.

Each section of the horizontal well was perforated with four clusters, with a cluster spacing of 10 m and a total of 48 perforations per section. The horizontal well used slick water as the fracturing fluid, with a viscosity of 10 mPa·s and an injection displacement of 18 m³/min.

We simulated the fracture propagation after various numbers of perforation holes were temporarily plugged with temporary blocking agents, as shown in Figure 2. When temporary blocking agents were not used for plugging perforation holes during fracturing, the extension lengths of each fracture varied significantly. With the use of temporary blocking agents to plug perforation holes during fracturing, the extension lengths of each fracture gradually became more uniform [24,25,26,27], especially after 30 perforation holes were plugged, with the extension lengths of each fracture becoming essentially identical.

To more accurately assess the impact of temporarily blocked perforations on fracture propagation, we simulated the fracture growth morphology by plugging 5, 10, 15, 20, 30, and 35 holes. We utilized the area of fractured zones to evaluate the extent of reconstruction. As illustrated in Figure 3, the fracture area is minimized when no holes are plugged—19% smaller than when 30 holes are obstructed. With an increasing number of plugged perforations, the area of fractured zones progressively enlarges. This phenomenon primarily arises because fracturing fluid can penetrate various perforation clusters more uniformly as some perforations become blocked, thereby enhancing the uniformity of the fractures. However, with 35 perforations blocked, the fracture area is reduced by 6% compared to when only 30 are obstructed; this reduction occurs mainly due to an insufficient extension within each cluster caused by excessive blocking. Consequently, it is recommended that shale oil horizontal well fracturing in the Sichuan Basin be conducted with a blockage of approximately 30 holes to optimize the fracture area. The fracture area is calculated as the product of fracture length and fracture height.

Our focus extends beyond the realm of hydraulic fractures to include their uniformity as well. To characterize this uniformity more accurately, we define the shortest fracture length as $L_1$ and the longest fracture length as $L_2$. When $R={\displaystyle \frac{L_1}{L_2}}$ approaches 1, it indicates a high degree of uniformity in the extension of each cluster of fractures. $R$ denotes the fracture uniformity coefficient, reflecting the extent of fracture uniformity

As illustrated in Figure 4, when no perforation holes are blocked, the fracture uniformity coefficient reaches its maximum value, indicating a high degree of non-uniformity in the extension of fractures within each cluster. This phenomenon primarily occurs because fracturing fluid tends to preferentially enter strata characterized by a high porosity and low ground stress, leading to variations in fracture lengths. Upon introducing temporary plugging balls, some perforation holes become obstructed, compelling the fracturing fluid to penetrate formations with a lower porosity and relatively higher ground stress. This results in a marked enhancement in the uniformity of fracture extension across each cluster. As depicted in Figure 4, there is minimal difference between the fracture uniformity coefficients for scenarios where 30 holes are blocked compared to those with 35 holes blocked. To optimize fracturing costs and considering that the fractured area associated with blocking 30 holes exceeds that of blocking 35 holes, it is recommended that the fracturing design for horizontal shale oil wells in the Sichuan Basin be based on blocking 30 holes per section. The requirement for temporary plugging balls can be quantitatively determined based on the one-to-one sealing principle, where each temporary plugging ball effectively seals a single perforation orifice. Consequently, complete occlusion of 30 distinct perforation orifices necessitates the deployment of 30 temporary plugging balls.

2.3. Optimization of the Addition Time of Temporary Plugging Agent

Adding a temporary plugging agent to seal perforations during fracturing can significantly enhance the fracture morphology and improve stimulation effectiveness [28,29,30,31]. The timing of the addition of the temporary plugging agent plays a crucial role in determining the fracture growth morphology [32,33,34]. Simulations were conducted to analyze the expansion of hydraulic fractures with temporary plug clusters following the injection of 30%, 45%, 60%, and 75% of the total fracturing fluid volume, maintaining a constant fluid volume and injection rate throughout. The design for the number of temporary plug balls is based on the requirement to seal 30 perforations within the simulation.

Figure 5 illustrates the simulation results of the expansion patterns of clusters of fractures at various stages of fracturing, with the addition of temporary blocking agents. It is evident from Figure 3 that when 30% by volume of fracturing fluid is mixed with temporary blocking agents, the uniform expansion of fractures is not significantly improved, and the clusters still exhibit non-uniform expansion characteristics. However, when 60% by volume of fracturing fluid is mixed with temporary blocking agents, the clusters exhibit a uniform expansion, and their lengths are essentially consistent. On the other hand, when 75% by volume of fracturing fluid is mixed with temporary blocking agents, the clusters exhibit non-uniform expansion, primarily due to the late addition of temporary blocking agents. Therefore, it is recommended that the hydraulic fracturing of shale oil reservoirs should be swiftly mixed with the use of temporary blocking agents after 60% by volume of fracturing fluid has been injected, to enhance the uniform expansion of each cluster of fractures.

Figure 6 shows the simulation results of the fracture expansion area after adding temporary plugging agents at different stages of fracturing. The horizontal coordinate of 30% in Figure 6 represents the addition of temporary plugging agents after injecting 30% of the total volume of fracturing fluid and then continuing to inject the remaining 70% of fracturing fluid into the formation.

As shown in Figure 6, compared to the case where the temporary plugging agent is added after injecting 30% or 75% of the total volume of fracturing fluid, the total area of the fracture clusters is maximized when the temporary plugging agent is added after injecting 60% of the total volume of fracturing fluid. The simulation results in Figure 6 further demonstrate that the hydraulic fracturing of shale oil reservoirs should be carried out by injecting 60% of the total volume of fracturing fluid, followed by the addition of temporary plugging agents to block perforation holes, in order to obtain the maximum stimulation area.

2.4. Optimization of the Frequency of Temporary Plugging Agent Additions

Figure 7 shows the simulation results of fracture propagation under different temporary blocking times. It can be seen from Figure 7 that the uniformity of fracture extension is better for temporary blocking once than for temporary blocking twice or three times, which is mainly due to the fact that temporarily blocking 30 perforation holes at a time can quickly adjust the flow distribution of the perforation cluster, thereby improving the uniformity of fracture propagation [20,31,35,36,37,38].

3. Field Application

The M1 well is a horizontal well deployed in the Sichuan Gongshanmiao Oilfield, China. Situated in the northeastern part of the Central Sichuan oil region, the Gongshanmiao Oilfield occupies a structural position within the northern segment of the Central Sichuan Paleo-Uplift gentle structural belt, characterized by a near E-W trending short-axis anticline. The shallow Jurassic structure exhibits inherited characteristics with gentle flanks.

Geologically, the Gongshanmiao Oilfield resides in the shallow to semi-deep lacustrine subfacies zone of the Da’anzhai and Lianggaoshan lake basins. The Da’er submember (30–40 m thickness) and Liang’er/Liangsan members (15–20 m) demonstrate well-developed black shales, serving as high-quality hydrocarbon source rocks. The Da’yi and Da’san intervals contain shell limestones, while the Liang’er/Liangsan members and Shaximiao Formation sandstones constitute the principal reservoir rocks. This stratigraphic architecture reflects favorable source–reservoir configurations within the basin’s depositional framework. The Lianggaoshan Formation is characterized by high-pressure to abnormally high-pressure conditions, a normal temperature, and an undersaturated oil reservoir system. This formation exhibits a pressure coefficient ranging from 1.24 to 1.47, with a reservoir temperature of 70 °C. The surface crude oil displays a relative density of 0.75–0.85, a viscosity spanning 0.67–14.35 Pa·s, and a wax content between 5% and 15%.

The M1 well, a horizontal well targeting the Lianggaoshan Formation in the Gongshanmiao Oilfield of Sichuan Basin, China, features a lateral section of 1001 m. Wireline logging interpretation reveals a 10 m thick reservoir dominated by primary intergranular porosity (85–90% of total pore volume), with poorly developed secondary dissolution pores. Core analysis indicates an ultra-low permeability averaging 0.05 mD (range: 0.02–0.08 mD) and an absence of natural fractures, classifying it as a typical tight sandstone reservoir. Petrographic characterization identifies the lithology as a heterogeneous assemblage of fine-grained sandstone (45–55%), siltstone (30–40%), and argillaceous siltstone (10–15%), exhibiting strong vertical heterogeneity, with permeability variations up to one order of magnitude.

To enhance reservoir connectivity, M1 employed an advanced staged multi-cluster fracturing design comprising 20 individually engineered stages. Each stage incorporated four perforation clusters spaced at 10 m intervals, stimulated using variable-viscosity slickwater injected at 18 m³/min. A novel temporary fiber-laden diverting agent was implemented at 60% of total fluid volume per stage to seal 30 perforations. Microseismic mapping demonstrated sustained fracture propagation, with an average half-length of 182 m and fracture height containment within ±10 m of the target zone.

Post-fracturing production testing yielded an initial oil production rate of 20 tonnes per day, quadruple the average output of offset vertical wells. This performance enhancement is attributed to the engineered fracture network covering 92% of the lateral section, as evidenced by production logging tools. The success of this stimulation strategy highlights the critical importance of temporary diversion technology in overcoming reservoir heterogeneity and achieving uniform cluster activation in ultra-low-permeability formations.

4. Conclusions

(1) Adding temporary plugging agents to seal the perforation holes during the staged fracturing of shale oil horizontal wells can effectively improve the uniformity of each cluster of fractures.

(2) In order to achieve a good crack extension effect, at least 30 perforations need to be sealed in each stage of fracturing, and temporary plugging agent should be added after injecting 60% of the total volume of fracturing fluid.

(3) The fracture area and fracture uniformity coefficient are critical indicators for optimizing temporary plugging fracturing designs, where maximizing the areal coverage while achieving homogeneous fracture distribution constitutes the primary engineering objective.

(4) Compared to multi-stage diverter injection, single-stage placement of all diverters during fracturing proves optimal. This approach maximizes fracture network uniformity, while streamlining operations and mitigating stimulation risks.