This study presents an avant-garde approach for predicting and optimizing production in tight reservoirs, employing a dual-medium unsteady seepage model specifically fashioned for volumetrically fractured horizontal wells. Traditional models often fail to fully capture the complex dynamics associated with these unconventional reservoirs. In a significant departure from these models, our approach incorporates an initiation pressure gradient and a discrete fracture seepage network, providing a more realistic representation of the seepage process. The model also integrates an enhanced fluid-solid interaction, which allows for a more comprehensive understanding of the fluid-structure interactions in the reservoir. This is achieved through the incorporation of improved permeability and stress coupling, leading to more precise predictions of reservoir behavior. The numerical solutions derived from the model are obtained through the sophisticated finite element method, ensuring high accuracy and computational efficiency. To ensure the model’s reliability and accuracy, the outcomes were tested against a real-world case, with results demonstrating strong alignment. A key revelation from the study is the significant difference between uncoupled and fully coupled volumetrically fractured horizontal wells, challenging conventional wisdom in the field. Additionally, the study delves into the effects of stress, fracture length, and fracture number on reservoir production, contributing valuable insights for the design and optimization of tight reservoirs. The findings from this study have the potential to revolutionize the field of tight reservoir prediction and management, offering significant advancements in petroleum engineering. The proposed approach brings forth a more nuanced understanding of tight reservoir systems and opens up new avenues for optimizing reservoir management and production.

In recent years, the proportion of new proven reserves in sand conglomerate reservoirs has been increasing every year, and the development of sand conglomerate reservoirs is gradually gaining attention. A conglomerate is a rock formed by the sedimentation of rock fragments, which mainly consists of a matrix connecting the pebbles in the conglomerate and the pebbles compacted in the conglomerate. Due to its dense lithology and low permeability, large-volume fracturing is required to open the oil and gas seepage channel when exploiting the conglomerate reservoir.

Analytical models for predicting the volumetric production of fractured horizontal wells are typically based on more assumptions. Trilinear flow models have been pioneered in fractured horizontal well seepage studies [

Modified hyperbolic decline, power-law exponential decline, stretched exponential decline, Duong’s method, and logistic growth model have been developed to predict production in shale reservoirs. However, they are all based on empirical observations of a particular scenario. To quantify their differences, different methods of history matching for production of unconventional hydraulically fractured reservoirs were investigated by forecasting future production and predicting EURs [

Based on this, the fracture pressure prediction model, which considers the variation of formation pressure, was used to determine the variation pattern of fracture pressure at different production periods and locations [

Its seepage properties are more complex due to the presence of conglomerate, and its production after volume fracturing is difficult to predict. The presence of conglomerates complicates seepage properties within geological formations due to factors such as heterogeneity, anisotropy, irregular pore spaces, tortuosity, and variable cementation. These characteristics result in complex and unpredictable fluid flow patterns, making it challenging to accurately model and predict seepage behavior. Zeng et al. [

Adopt core experiment and theoretical analysis method, combined with fracture engineering geological characteristics and design parameters, to analyze the fracture penetration criterion and investigate the effect of design factors and reservoir geological characteristics on the law of fracture penetration [

This paper uses the established volumetric fractured horizontal well model as a foundation. The actual flow-solid coupling effect on production is considered, and the permeability-stress coupling relationship of tight is improved to make the model results more realistic.

Based on previous studies, it is believed that the reservoir area for a general volumetric fractured horizontal well consists of two parts: the reservoir matrix-naturally fractured (unmodified) zone, and the artificially fractured (modified) zone [

Assumed conditions: (1) Block reservoir, thickness h. (2) Outer boundary is closed and natural fractures exist. (3) Rock and fluid are slightly compressible. (4) Seepage process does not consider the effect of gravity and temperature change.

The matrix system considers the initiation pressure gradient and the fluid equation of motion is

^{−3} m/s;

^{−1}; _{i} is the original formation pressure, MPa; ^{3}.

Taking into account the equation of motion

^{−1}

Within an artificial fracture, the fluid seepage in it obeys Darcy’s law, so its controlling equation can be expressed as

^{−1}.

The matrix pressure boundary condition is the second type of boundary condition, and the crack system pressure boundary equals the matrix pressure boundary.

The following assumptions are made: (1) the rock undergoes deformation as a porous medium; (2) rock particles are incompressible while particle pores are compressible; (3) temperature change effects on rock deformation are disregarded; (4) rock deformation exhibits elastic-plastic minor deformation; (5) the pore compressibility factor is variable. The stress field’s mathematical model primarily includes the current constitutive equations, geometric equations, equilibrium differential equations, and boundary solution conditions.

In this paper, the elastic-plastic intrinsic equation is used to describe the stress and strain intrinsic relationships during the stressing of the rock, and the tensor expression is

The geometric relationship equation mainly refers to the relationship between displacement and strain during the deformation of reservoir rocks. The following tensor form describes it:

The following equation can express the equilibrium differential equation for a unitary body’s stress and volume force:

_{i} is the volume force on one side;

To establish the dynamic interrelation between permeability and stress in tight reservoirs, this study incorporates three key parameters: Poisson’s ratio, initial permeability and Young’s modulus [

^{−1};

The coupled model for the permeability and effective stress of the target layer is

The porosity deformation of a tight reservoir is more complex, and the coupled model of porosity in this paper is

The oil-water two-phase flow simulation of shale reservoirs can be realized by solving sequentially.

This paper solves the above equations by substituting them into COMSOL Multiphysics software. The fractured horizontal well in a conglomerate reservoir is numerically simulated with a reservoir size of 1000 * 800 m^{2}, a fracture network cluster spacing of 30 m, half-length, and bandwidth of 200 and 8 m. The volume fracture zone is encrypted and refined, the maximum cell size at the fracture face is set to 0.1 m, and the flow pressure at the bottom of the horizontal well is set to 20 MPa. The actual reservoir geological parameters and horizontal well data in the model are adopted from the actual destination block data. The grid outline is shown in

Parameter | Value | Parameter | Value |
---|---|---|---|

Reservoir size (m^{2}) |
1000 * 800 | Horizontal well length (m) | 700 |

Initial formation pressure (MPa) | 50 | Fluid density (kg/m^{3}) |
800 |

Fluid viscosity (mPa·s) | 6 | Fluid compression coefficient (MPa^{−1}) |
0.001 |

Pore compression coefficient (MPa^{−1}) |
0.00075 | Fracture compression coefficient (MPa^{−1}) |
0.0075 |

Matrix porosity | 0.07 | Fracture porosity | 0.38 |

Initiation pressure gradient (MPa/m) | 0.01 | Matrix permeability^{−3} μm^{2}) |
1.89 |

Bottom of well flow pressure (MPa) | 20 | Fracture permeability^{−3} μm^{2}) |
1890 |

Fracture half-length (m) | 200 | Fracture width (m) | 0.01 |

Parameter | Value | Parameter | Value |
---|---|---|---|

Maximum principal stress (MPa) | 50 | Minimum principal stress (MPa) | 20 |

Matrix Young’s modulus (GPa) | 44 | Fracture Young’s modulus (GPa) | 20 |

Matrix solid density (kg/m^{3}) |
2000 | Rock Poisson’s ratio | 0.24 |

The parameters were substituted into the model and solved for the pressure variation, as shown in

The actual production curves of the well were fitted for comparative analysis, as shown in

The fluid-solid coupling model for tight reservoirs, established earlier, reveals that the primary influence on fluid-solid coupling in the reservoir stems from alterations in pore permeability properties due to pressure fluctuations during the production process. Among these factors, permeability changes are more significant. The effective stress sensitivity factor is a parameter that represents the impact of stress variations on permeability, taking into account the comprehensive rock mechanical properties of the tight reservoir. Using the developed model, a single-factor analysis is conducted with actual parameters while maintaining flow pressure at 20 MPa and keeping other parameters constant. Fractures are set as inclined fractures. The simulation assesses the influence on oil production for various stress sensitivity coefficient scenarios.

As shown in ^{−1}, with production decline noticeably slower at 0.02 MPa^{−1}.

Volume-based hydraulic fracturing in horizontal wells forms an SRV (Stimulated Reservoir Volume) zone around the wellbore, allowing for the production of a large volume of fluids. The size of the SRV zone significantly impacts production. By extending the fracture length, the reservoir area can be effectively expanded, greatly influencing the production rate of horizontal wells.

^{3} when the fracture half-length expands from 100 to 150 m, but only by 2700 m^{3} when it extends from 200 to 250 m.

The size of the SRV zone has a significant impact on production, and the number of fractures is another crucial parameter controlling the size of the SRV zone. By creating more fractures, the seepage around the wellbore can be effectively enhanced, offering considerable advantages for initial oil production. Nevertheless, in cases where the length of horizontal well sections is limited, increasing the number of fractures may cause interference issues between fractures, affecting the production of horizontal wells. Therefore, the changes in production are studied by constructing different numbers of fractures.

As illustrated in ^{3}, an increase of 12.5%. In contrast, when the number of fractures increased from 4 to 5, the cumulative oil production increased by only 1000 m^{3}, an increase of only 1.8%.

As observed from the pressure distribution comparison in

Alongside stress sensitivity, fracture half-length, and the number of fractures, permeability stands as a pivotal geological parameter impacting fluid dynamics within the reservoir. In

As demonstrated in

This study focuses on the problem of mutual coupling of stress and seepage fields in tight reservoirs during the development process. To address this issue, a flow-solid coupling model was developed for volumetrically fractured horizontal wells in dense sandy conglomerate reservoirs. The model was based on the cross-coupling relationship of permeability stress, which was improved through seepage mechanics, rock mechanics, and numerical model analysis.

The primary findings of this study include the following. First, the model takes into account the dual medium composed of a fracture network and matrix by integrating artificial fractures. Second, a production prediction model was developed and its accuracy was validated by comparing it with real production wells through finite element numerical simulation. Third, the fluid-solid coupled model was employed to assess the impact of various factors on reservoir production, such as stress sensitivity, fracture length, and the number of fracture clusters.

The results show that the productivity of horizontal wells is negatively affected by the increase of stress sensitivity coefficient. When the coefficient is 0.02 MPa^{−1}, the production reaches its maximum. The trend of cumulative oil production increase with fracture length becomes more evident, achieving the maximum production when the fracture length is 250 m. Within the range of fracture number provided in this study, although more fracture number lead to an increase in cumulative oil production, well interference may also occur.

In this study, sensitivity analyses reveal that stress sensitivity, fracture half-length, number of fractures, and matrix permeability emerge as critical factors influencing the productivity of horizontal wells in tight reservoirs. Specifically, a stress sensitivity coefficient of 0.02 MPa^{−1} slows the production decline significantly, while fracture half-length shows diminishing returns in FOPT beyond 250 m. The number of fractures has a more considerable impact on early production, with diminishing incremental gains beyond 4 fractures. Matrix permeability, as detailed in

None.

The authors received no specific funding for this study.

The authors confirm contribution to the paper as follows: study conception and design: XZ; data collection: XZ; analysis and interpretation of results: XZ, ML, KY; draft manuscript preparation: KY, LY. All authors reviewed the results and approved the final version of the manuscript.

The data that support the findings of this study are available from the corresponding author, upon reasonable request.

The authors declare that they have no conflicts of interest to report regarding the present study.