Method for optimizing the shut-in time of a shale reservoir based on temperature recovery
Patent Information
- Application Number
- CN202611089910.0
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- Filing Date
- 2026-07-22
- Publication Date
- 2026-10-13
AI Technical Summary
本发明提出了一种基于温度恢复优选页岩焖井时间的方法。系统量化了焖井时间对储层基质物性的影响，建立了以温度为纽带的焖井时间确定标准，有利于制定合理的焖井时间从而提高压裂增产效果。本发明所需数据均可岩心实验和地质资料获取，操作流程明确，易于在现场实施，适用于不同埋深、不同温度体系的页岩储层，具有显著的工程应用价值和推广前景。
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Figure CN122904597A_ABST
Abstract
Description
Technical Field
[0001] This invention relates to the field of shale gas development technology, specifically to a method for optimizing shale well simmering time based on temperature recovery. This method combines indoor well simmering experiments and numerical simulations to optimize the shale well simmering time. Background Technology
[0002] Shale gas, as an important clean energy source, plays a crucial role in my country's energy structure adjustment and the achievement of its "dual carbon" goals. Due to the high density of shale reservoirs, fracturing is often required for production enhancement during development. However, the specific well-closing time before production lacks theoretical basis and is usually determined based on field experience, resulting in significant uncertainty and randomness. A reasonable well-closing time can significantly improve the production enhancement effect of fracturing. Therefore, determining the optimal well-closing time is of great significance for the efficient development of shale reservoirs. Summary of the Invention
[0003] To optimize shale well-keeping time and improve fracturing production, this invention proposes a method for selecting optimal shale well-keeping time based on temperature recovery. This method stems from a key discovery made by the inventors during laboratory core experiments: fracturing fluid injection lowers reservoir temperature, and the temperature recovery during well-keeping generates microfractures, altering matrix properties. Based on this, this invention uses core experimental data as initial physical property parameters for each grid cell in a numerical model after well-keeping, and employs an integrated numerical simulation method encompassing fracturing, well-keeping, and production to optimize the well-keeping time.
[0004] To achieve the above objectives, the present invention provides the following technical solution: A method for optimizing shale well simmering time based on temperature recovery includes the following steps: Step 1: Conduct systematic coring of the target reservoir in the study well to prepare core samples; Step 2: The core sample is placed under the temperature and pressure conditions of the target reservoir for a well-steaming test. The difference between the highest and lowest temperatures of the core sample during the preset well-steaming time is taken as the temperature difference, and the core permeability at the end of the well-steaming time is taken as the equivalent permeability, thus establishing an equivalent permeability-temperature difference data pair. By changing the preset well-steaming time, different equivalent permeability-temperature difference data pairs are obtained, and an equivalent permeability-temperature difference variation chart is established. Step 3: Determine the porosity correction model to correct the porosity after well shut-in; Step 4: Collect geological data of the target reservoir and establish a three-dimensional geological model and a geomechanical model based on relevant data including seismic interpretation, well logging data and geostress testing. Step 5: Based on the three-dimensional geological model and the geomechanical model, conduct an integrated numerical simulation of fracturing-well shut-in-production. During the simulation, the area where the temperature decreases after fracturing is taken as the fracturing fluid affected area. The difference between the highest and lowest temperatures of each matrix grid during the shut-in process is taken as the temperature difference of that matrix grid. Combined with the equivalent permeability-temperature difference chart and the porosity correction model, the permeability and porosity of each matrix grid unit in the fracturing fluid affected area after the shut-in is corrected. Finally, the well opening production process under different shut-in times is simulated. The cumulative gas production for the preset gas production time is simulated by the constant pressure production method. The shut-in time-cumulative gas production curve is established to determine the trend of the production increase rate with the shut-in time. The shut-in time when the production increase rate is lower than the preset threshold is taken as the optimal shut-in time.
[0005] As a specific implementation of the present invention, in the well-sealing test of step two, a three-dimensional visualized digital core image of the fracture system of the core sample is obtained by CT scanning to establish a digital core model. Then, the equivalent permeability of the core is calculated by finite element flow simulation. In this way, the equivalent permeability of the core at different times can be obtained quickly and accurately.
[0006] As a specific embodiment of the present invention, the porosity correction model is as follows: In the formula, This indicates the matrix porosity after well sealing, and is dimensionless. This indicates the matrix porosity before well sealing, and is dimensionless. It represents the volumetric strain of rock (positive for compression, negative for tension), and is dimensionless; This represents the coefficient of thermal expansion of the rock skeleton. ; This represents the difference between the maximum and minimum temperatures during the well-sealing process, expressed in °C.
[0007] As a specific embodiment of the present invention, the preset gas production duration during simulated well opening is one year.
[0008] In a specific embodiment of the present invention, in step five, taking into account economic factors, the optimal well-closing time is used as the benchmark value, and the well-closing time with the best economic benefits is selected within a preset floating range, and this time is determined as the well-closing time.
[0009] Compared with the prior art, the present invention has the following beneficial effects: This invention proposes a method for optimizing shale well-cooling time based on temperature recovery. The system quantifies the impact of well-cooling time on reservoir matrix properties and establishes a temperature-based standard for determining well-cooling time, which is beneficial for formulating reasonable well-cooling times to improve fracturing and production enhancement effects. The data required for this invention can be obtained from core experiments and geological data. The operation procedure is clear, easy to implement in the field, and applicable to shale reservoirs of different burial depths and temperature systems, demonstrating significant engineering application value and promising prospects for widespread application. Attached Figure Description
[0010] Figure 1 Equivalent penetration rate - Temperature difference plate; Figure 2 Schematic diagram of an integrated numerical model for fracturing-well shut-in-production; Figure 3 This is a diagram showing the reservoir temperature field distribution after fracturing operations; Figure 4 A trend chart of cumulative gas production within one year of well opening under different well-closing times; Figure 5 A schematic diagram showing the cumulative gas production after one year of well opening under different well shut-in times; Figure 6 This is a schematic diagram of the fitting curve of well shut-in time versus cumulative gas production and its first derivative curve. Detailed Implementation
[0011] To more clearly illustrate the present invention, specific embodiments are described below. Those skilled in the art should understand that the following description is illustrative rather than restrictive and should not be construed as limiting the scope of protection of the present invention.
[0012] Example This embodiment takes the X gas field 1000a gas well as an example to illustrate the specific method for determining the optimal well shut-in time. The main steps are as follows: Step 1: Take a core sample from the Z1 layer of well 1000a in the X gas field and process it into a cylindrical plunger sample conforming to the petroleum industry's core analysis standards (6mm diameter, 10mm axial length, ensuring end-face non-parallelism is less than 0.05mm and perpendicularity deviation is less than 0.1°). Place the core sample in a core holder and heat it to 132℃ at a rate of 2℃ / min. After reaching the target temperature, maintain this temperature for 12 hours to allow the sample to age. In the control computer of the CT equipment, set the scanning voltage to 100kV and the power to 8W and keep it constant. The distance between the detector and the sample is 15mm, and the distance between the sample and the radiation source is 40mm. After preparation, scan the dry sample to obtain a three-dimensional scan image of the fracture morphology. Then, perform median filtering and alignment on the image to observe and screen out unqualified core samples, such as those with abnormal fracture development or fractures.
[0013] Step 2: While maintaining the core at the temperature of its corresponding stratum, apply confining pressure to the core at the corresponding stratum. Then, based on the on-site construction conditions, calculate the flow rate and quantity of fracturing fluid injected into each core holder using similarity criteria. Then, inject the fracturing fluid system used on-site into the core at this flow rate. This process simulates the process of injecting fracturing fluid into high-temperature formations. After injection, no backflow was performed to simulate the well-sealing process. During the well-sealing process, the core was subjected to the first round of CT scans, and the core temperature at the fracturing fluid inlet was recorded in real time. Then, a round of CT scans was performed on each core every 1 hour. The scan results were processed using Avizo software. Based on the CT scan data every 1 hour, a digital core model was established for each scan. The equivalent permeability corresponding to the well-sealing time was calculated by finite element flow simulation. When the equivalent permeability of the digital core established by two consecutive CT scans remained unchanged or the change was less than 0.005 mD, it was indicated that the microfractures induced by well-sealing had reached a stable state, and the well-sealing experiment was stopped. After all core experiments were completed, the equivalent permeability of each core under different temperature differences (the difference between the highest and lowest temperatures during the well-sealing stage) was averaged, and the equivalent permeability was plotted. With temperature difference Changing plates ( Figure 1 ).
[0014] Step 3: Obtain the matrix porosity of the reservoir before well shut-in using geological data. The coefficient of thermal expansion of the rock skeleton is 0.05. 3.2×10 -5 Calculate the porosity after well sealing The model is as follows: In the formula: —Matrix porosity after well sealing, dimensionless; —Matrix porosity before well shut-in, dimensionless; —The volumetric strain of rock (positive for compression, negative for tension) is dimensionless; —Coefficient of thermal expansion of the rock skeleton ; —The difference between the maximum and minimum temperatures of the matrix grid during the well-sealing process, in °C.
[0015] Step 4: Collect geological data of the target reservoir. Based on seismic interpretation, well logging data, and geostress testing data, use Petrel integrated geological engineering software to establish a three-dimensional geological model and a geomechanical model.
[0016] Step 5: Based on the above model, perform an integrated numerical simulation of fracturing-well shut-in-production. Using the actual pumping procedure, fracturing fluid, and proppant as a reference, simulate the fracturing propagation of the well and generate an unstructured mesh. Figure 2 The well was designated as an injection well, and the injection regime was set according to the pump injection procedure. Injection was performed in stages based on the actual fracturing intervals to simulate the changes in the reservoir temperature field caused by fracturing fluid injection. The reservoir and fluid properties after fracturing were used as the non-equilibrium initialization conditions for the well-suspension simulation, and the area of temperature reduction after fracturing was defined as the fracturing fluid sweep area. During the well-suspension simulation, multiple gradient well-suspension times (1d, 3d, 5d, 7d, 9d, 11d) were set, and the maximum temperature difference of different grids during the well-suspension process was calculated based on the changes in reservoir temperature distribution during the well-suspension stages. (The difference between the maximum and minimum temperatures) is used to calculate the matrix porosity using a porosity correction calculation model, and porosity correction is applied to different matrix grids in the fracturing fluid-sweeped region; simultaneously, based on the equivalent permeability... - Temperature difference The chart is corrected for the permeability of different matrix grids in the fracturing fluid-sweeped area. Then, the cumulative gas production after one year of post-fracturing well operation is simulated using a constant bottomhole flowing pressure of 10 MPa (the bottomhole flowing pressure is determined according to the actual block). Figure 4 , Figure 5 By comparing the cumulative gas production corresponding to different well-keeping times, it was found that the cumulative gas production increases with the extension of the well-keeping time. Fitting the well-keeping time-cumulative gas production curve, the relationship between the cumulative gas production y for one year of well operation and the well-keeping time x was obtained as: y = 4567.95 + 117.27x - 6.30x 2 +0.047x 3 Differentiating this function, we get y = 117.27 - 12.6x + 0.141x 2It was found that when the well was shut-in time was 9 days, the cumulative gas production growth rate decreased to 15×10. 4 m 3 / d( Figure 6 , with 15×10 4 m 3 (Using / d as a threshold), considering economic factors, continuing to shut down the well at this point is not very meaningful, and the longer the shut-down time is not necessarily better, so the optimal shut-down time for this well is 9d.
[0017] A survey of most gas wells in the X gas field block revealed that 18 wells, after being shut down for 9 days following fracturing, began production. The average cumulative gas production after one year of operation was 51,236,504.2 m³. 3 The simulated production value of 5141 × 10⁻⁶ after well opening following 9 days of well simmering in the example was compared with that of the example. 4 m 3 The results are very close, indicating that the present invention can determine a reasonable well-closing time through temperature recovery with high accuracy. Compared with the prior art, it has made significant progress and can provide scientific guidance for the well-closing time after shale reservoir compression.
[0018] The above are merely preferred embodiments of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the embodiments of the present invention should be included within the scope of protection of the present invention.
Claims
1. A method for optimizing shale well simmering time based on temperature recovery, characterized in that, Includes the following steps: Step 1: Conduct systematic coring of the target reservoir in the study well to prepare core samples; Step 2: The core sample is placed under the temperature and pressure conditions of the target reservoir for a well-steaming test. The difference between the highest and lowest temperatures of the core sample during the preset well-steaming time is taken as the temperature difference, and the core permeability at the end of the well-steaming time is taken as the equivalent permeability, thus establishing an equivalent permeability-temperature difference data pair. By changing the preset well-steaming time, different equivalent permeability-temperature difference data pairs are obtained, and an equivalent permeability-temperature difference variation chart is established. Step 3: Determine the porosity correction model to correct the porosity after well shut-in; Step 4: Collect geological data of the target reservoir and establish a three-dimensional geological model and a geomechanical model; Step 5: Conduct integrated numerical simulation of fracturing-well shut-in-production based on the three-dimensional geological model and the geomechanical model; During the simulation, the area where the temperature decreases after fracturing is taken as the fracturing fluid affected area. The difference between the highest and lowest temperatures of each matrix grid during the well-shutting process is taken as the temperature difference of that matrix grid. Combined with the equivalent permeability-temperature difference chart and porosity correction model, the permeability and porosity of each matrix grid in the fracturing fluid affected area after well-shutting are corrected. Finally, the well-opening production process under different well-shutting times is simulated. The cumulative gas production for the preset gas production time is simulated by constant pressure production method. The well-shutting time-cumulative gas production curve is established to determine the trend of the production increase rate with the well-shutting time. The well-shutting time when the production increase rate is lower than the preset threshold is taken as the optimal well-shutting time.
2. The method for optimizing shale well simmering time based on temperature recovery according to claim 1, characterized in that, In step two, the well-sealing test, a three-dimensional visualized digital core image of the fracture system of the core sample is obtained through CT scanning to establish a digital core model. Then, the equivalent permeability of the core is calculated through finite element flow simulation. In this way, the equivalent permeability of the core at different times can be obtained quickly and accurately.
3. The method for optimizing shale well simmering time based on temperature recovery according to claim 1, characterized in that, In the second step of the well-steaming test, the preset gas production time for simulating well opening production is one year.
4. The method for optimizing shale well simmering time based on temperature recovery according to claim 1, characterized in that, The porosity correction model is as follows: In the formula, This indicates the matrix porosity after well sealing, and is dimensionless. This indicates the matrix porosity before well sealing, and is dimensionless. It represents the volumetric strain of the rock and is dimensionless. This represents the coefficient of thermal expansion of the rock skeleton. ; This represents the difference between the maximum and minimum temperatures during the well-sealing process, expressed in °C.
5. The method for optimizing shale well simmering time based on temperature recovery according to claim 1, characterized in that, In step five, taking into account economic factors, the optimal well-sealing time is used as the benchmark value. Within a preset fluctuation range, the well-sealing time with the best economic benefits is selected and determined as the well-sealing time.