Shale gas reservoir horizontal well foam drainage process yield increase potential evaluation method

Abstract

The invention discloses a shale gas reservoir horizontal well foam drainage process yield increase potential evaluation method, and relates to the technical field of petroleum and natural gas engineering, and the method comprises the following steps: S1, collecting related parameters, S2, analyzing a friction factor, S3, determining a stability coefficient, and S4, outputting a performance grade. Quantitative evaluation on diffusivity and stability of the foam scrubbing agent is realized by combining the flow pattern of the shaft, performance parameters of the foam scrubbing agent and the temperature and pressure of the shaft, and the yield increasing potential index is provided by integrating the diffusivity and stability of the foam scrubbing agent, so that the yield increasing capacity of the foam scrubbing agent of the shale gas well can be accurately reflected, and a yield increasing potential analysis grade is established; according to the method, different agents can be optimized through grading, meanwhile, a good guiding effect can be achieved during field application, the risk that the effect is not ideal and the economic cost is increased due to the fact that the agents are added according to experience is greatly reduced, and the method has application prospects and popularization value for shale gas wells of different blocks.

Description

Technical Field

[0001] This invention relates to the field of oil and gas engineering technology, specifically to a method for evaluating the production potential of horizontal well foam drainage technology in shale gas reservoirs. Background Technology

[0002] The evaluation method for the production enhancement potential of horizontal wells using foaming and drainage technology in shale gas reservoirs mainly analyzes the wellbore parameters, formation fluid physical parameters, and foaming and drainage agent performance parameters of the horizontal wells to achieve a quantitative evaluation of the production enhancement effect of the foaming and drainage agent. Patent application number 202011031095.5 discloses "a numerical simulation method for shale gas reservoir production capacity, relating to the field of geological exploration technology, including establishing a non-structured tetrahedral network model; establishing a matrix system flow equation; establishing a set of solution equations for the volumetric strain of the natural fracture skeleton and the volumetric strain of the large-scale fracture skeleton; establishing a shale gas nonlinear seepage model and determining the boundary value conditions of the shale gas nonlinear seepage model; obtaining the semi-discrete format of the matrix system flow equation, the natural fracture flow equation, and the large-scale fracture flow equation; and obtaining the horizontal well production distribution in the target area." This invention's numerical simulation method for shale gas reservoir production capacity addresses the problem of neglecting the volumetric strain of the formation skeleton in existing reservoir production simulation methods. It provides a numerical simulation method for shale gas reservoir production capacity by introducing skeleton volumetric strain into the gas reservoir production capacity simulation, thereby improving the accuracy of the simulation results.

[0003] The aforementioned existing technology solves the problem of the inability to simulate the production capacity of deep shale reservoirs. However, in practice, this method does not utilize horizontal wellbore parameters, formation fluid physical parameters, and foaming agent performance parameters to evaluate the diffusion capacity and stability of the current foaming agent. This makes the selection of agents entirely dependent on the experience of the construction personnel. This approach can easily lead to unsatisfactory agent effects and increased economic costs. Furthermore, this method does not measure the production enhancement capacity of the foaming agent, and therefore cannot provide guidance for field applications. Summary of the Invention

[0004] The purpose of this invention is to provide a method for evaluating the production potential of horizontal well foaming and drainage technology in shale gas reservoirs, so as to solve the problems mentioned in the background art.

[0005] To achieve the above objectives, the present invention provides the following technical solution: a method for evaluating the production potential of horizontal well foaming and draining technology in shale gas reservoirs, comprising the following steps: S1. Collect relevant parameters: Obtain horizontal wellbore parameters, formation fluid physical parameters, and foaming agent performance parameters; S2. Analyze the friction factor: Calculate the horizontal wellbore parameters and formation fluid physical parameters using parameter calculation formulas to obtain the actual downhole fluid Reynolds number and fluid friction factor; S3. Determine the stability coefficient: Calculate the diffusion coefficient of the foaming agent using the diffusion coefficient analysis formula, and obtain the stability coefficient of the foaming agent by analyzing the relationship between the performance parameters of the foaming agent and the wellbore parameters of the horizontal well. S4. Output Performance Level: The stability coefficient of the foaming agent is calculated using the potential index analysis formula to obtain the production increase potential index. The production increase effect of the foaming agent is rated based on the production increase potential index.

[0006] Preferably, the horizontal wellbore parameters in S1 are specifically the wellbore diameter and wellbore pressure; the formation fluid physical parameters are specifically the formation fluid viscosity, fluid density, fluid velocity, fluid temperature, and fluid pressure; and the foaming agent performance parameters are specifically the surface tension, critical surface tension, and the critical pressure of the wellbore where the foaming agent is most stable.

[0007] Preferably, step S2 includes the following steps: S201. The formation fluid density, fluid velocity, fluid viscosity, and wellbore diameter are calculated using parameter determination formulas to obtain the actual downhole fluid Reynolds number, which represents the flow pattern of the formation fluid. S202. Using the parameter calculation formula, the corresponding fluid friction factor is analyzed based on the actual downhole fluid Reynolds number. The fluid friction factor represents the interaction relationship between fluids.

[0008] Preferably, the formula for obtaining the parameter in S201 is as follows: ;

[0009] in, Represents the Reynolds number. Indicates fluid density, Indicates fluid velocity. represents the wellbore diameter, Indicates fluid viscosity, This represents the fluid friction factor.

[0010] Preferably, step S3 specifically includes the following steps: S301. After obtaining the fluid temperature and fluid friction factor, the diffusion coefficient of the foaming agent is calculated by using the diffusion coefficient analysis formula. The diffusion coefficient of the foaming agent represents the diffusion capacity of the foaming agent under the corresponding wellbore conditions. S302. After reading the surface tension of the foaming agent, wellbore pressure, critical surface tension of the foaming agent, critical wellbore pressure of the most stable foaming agent, and stability coefficient of the foaming agent, calculate them using the stability coefficient analysis formula. Analyze the relationship between the surface tension of the foaming agent and the wellbore pressure to obtain the stability coefficient of the foaming agent, where the stability coefficient of the foaming agent represents the ability of the foaming agent to exist stably after being mixed into the fluid.

[0011] Preferably, step S4 specifically includes the following steps: S401. The production potential index is obtained by calculating the fluid temperature, the diffusion coefficient of the foaming agent, and the stability coefficient of the foaming agent through the potential index analysis formula. S402. Based on the production potential index, the production increase effect of the foaming and desiccant is initially divided into three levels: excellent, medium and poor.

[0012] Preferably, step S4 further includes the following steps: S403. When the production potential index is greater than zero and less than or equal to 0.35, the performance of the current foaming agent is judged to be poor. S404. When the production potential index is greater than 0.35 and less than or equal to 0.7, the performance of the current foaming agent is judged to be medium. S405. When the production potential index is greater than 0.7 and less than or equal to 1, the performance of the current foaming agent is judged to be excellent.

[0013] Preferably, the diffusion coefficient analysis formula in S301 is as follows:

[0014] in, Indicates the diffusion coefficient of the foaming agent. Indicates fluid temperature. This represents the fluid friction factor.

[0015] Compared with the prior art, the beneficial effects of the present invention are: This invention combines wellbore flow morphology, foaming agent performance parameters, wellbore temperature, and pressure to achieve a quantitative evaluation of the diffusion capacity and stability of foaming agents. It also proposes a production potential index that accurately reflects the production-enhancing capacity of foaming agents in shale gas wells. Furthermore, it establishes a production potential analysis grading system, which allows for the optimal selection of different agents and provides excellent guidance for field applications. This significantly reduces the risk of unsatisfactory results and increased economic costs due to relying on experience in adding agents, and has promising application prospects and promotional value for shale gas wells in different blocks. Attached Figure Description

[0016] Figure 1 An overall method flowchart is provided for embodiments of the present invention; Figure 2 The daily gas production dynamic curve is provided for an embodiment of the present invention. Detailed Implementation

[0017] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0018] Please see Figures 1-2 This invention provides a technical solution: a method for evaluating the production potential of horizontal well foaming and draining technology in shale gas reservoirs, comprising the following steps: S1. Collect relevant parameters: Obtain horizontal wellbore parameters, formation fluid physical parameters, and foaming agent performance parameters; S2. Analyze the friction factor: Calculate the horizontal wellbore parameters and formation fluid physical parameters using parameter calculation formulas to obtain the actual downhole fluid Reynolds number and fluid friction factor; S3. Determine the stability coefficient: Calculate the diffusion coefficient of the foaming agent using the diffusion coefficient analysis formula, and obtain the stability coefficient of the foaming agent by analyzing the relationship between the performance parameters of the foaming agent and the wellbore parameters of the horizontal well. S4. Output Performance Level: The stability coefficient of the foaming agent is calculated using the potential index analysis formula to obtain the production increase potential index. The production increase effect of the foaming agent is rated based on the production increase potential index.

[0019] The specific wellbore parameters in S1 are the wellbore diameter and wellbore pressure, with the diameter being... The specific physical parameters of the formation fluid include formation fluid viscosity, fluid density, fluid velocity, fluid temperature, and fluid pressure, with the fluid viscosity being... The fluid density is The fluid velocity is The fluid temperature is and fluid pressure is The specific performance parameters of the foaming agent are its surface tension, critical surface tension, and the most stable critical pressure in the wellbore. The surface tension of the foaming agent is... The critical surface tension is And the most stable critical pressure in the wellbore for the foaming agent is ; S2 includes the following steps: S201. The formation fluid density, fluid velocity, fluid viscosity, and wellbore diameter are calculated using parameter determination formulas to obtain the actual downhole fluid Reynolds number, which represents the flow pattern of the formation fluid. S202. Using the parameter calculation formula, the corresponding fluid friction factor is analyzed based on the actual downhole fluid Reynolds number, where the fluid friction factor represents the interaction relationship between fluids. The specific formula for obtaining the parameters in S201 is as follows: ;

[0020] in, Represents the Reynolds number. Indicates fluid density, Indicates fluid velocity. represents the wellbore diameter, Indicates fluid viscosity. Indicates the fluid friction factor; S3 specifically includes the following steps: S301. After obtaining the fluid temperature and fluid friction factor, the diffusion coefficient of the foaming agent is calculated by using the diffusion coefficient analysis formula. The diffusion coefficient of the foaming agent represents the diffusion capacity of the foaming agent under the corresponding wellbore conditions. S302. After reading the surface tension of the foaming agent, wellbore pressure, critical surface tension of the foaming agent, critical wellbore pressure at which the foaming agent is most stable, and the stability coefficient of the foaming agent, calculate them using the stability coefficient analysis formula. Analyze the relationship between the surface tension of the foaming agent and the wellbore pressure to obtain the stability coefficient of the foaming agent, where the stability coefficient of the foaming agent represents the ability of the foaming agent to exist stably after being mixed with the influent. S4 specifically includes the following steps: S401. The production potential index is obtained by calculating the fluid temperature, the diffusion coefficient of the foaming agent, and the stability coefficient of the foaming agent using the potential index analysis formula. The specific formula for the potential index analysis is as follows:

[0021] in, Indicating the potential for increased production, Indicates the diffusion coefficient of the foaming agent. Indicates the stability coefficient of the foaming agent. Indicates fluid temperature; S402. Based on the production potential index, the production increase effect of the foaming and draining agent is initially divided into three levels: excellent, medium and poor. S4 further includes the following steps: S403. When the production potential index is greater than zero and less than or equal to 0.35, the performance of the current foaming agent is judged to be poor. S404. When the production potential index is greater than 0.35 and less than or equal to 0.7, the performance of the current foaming agent is judged to be medium. S405. When the production potential index is greater than 0.7 and less than or equal to 1, the performance of the current foaming agent is judged to be excellent. The diffusion coefficient analysis formula in S301 is as follows:

[0022] in, Indicates the diffusion coefficient of the foaming agent. Indicates fluid temperature. This represents the fluid friction factor.

[0023] It should be noted that, in this document, relational terms such as "first" and "second" are used only to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus.

[0024] Although embodiments of the invention have been shown and described, it will be understood by those skilled in the art that various changes, modifications, substitutions and alterations can be made to these embodiments without departing from the principles and spirit of the invention, the scope of which is defined by the appended claims and their equivalents.

Claims

1. A method for evaluating the production potential of horizontal well bubble drainage technology in shale gas reservoirs, characterized in that, The method includes the following steps: S1. Collect relevant parameters: Obtain horizontal wellbore parameters, formation fluid physical parameters, and foaming agent performance parameters; S2. Analyze the friction factor: Calculate the horizontal wellbore parameters and formation fluid physical parameters using parameter calculation formulas to obtain the actual downhole fluid Reynolds number and fluid friction factor; S3. Determine the stability coefficient: Calculate the diffusion coefficient of the foaming agent using the diffusion coefficient analysis formula, and obtain the stability coefficient of the foaming agent by analyzing the relationship between the performance parameters of the foaming agent and the wellbore parameters of the horizontal well. S4. Output Performance Level: The stability coefficient of the foaming agent is calculated using the potential index analysis formula to obtain the production increase potential index. The production increase effect of the foaming agent is rated based on the production increase potential index.

2. The method for evaluating the production potential of horizontal well foam drainage technology in shale gas reservoirs according to claim 1, characterized in that: The horizontal wellbore parameters in S1 are specifically the wellbore diameter and wellbore pressure. The formation fluid physical parameters are specifically the formation fluid viscosity, fluid density, fluid velocity, fluid temperature, and fluid pressure. The foaming agent performance parameters are specifically the surface tension, critical surface tension, and the critical pressure of the foaming agent in the wellbore where it is most stable.

3. The method for evaluating the production potential of horizontal well foam drainage technology in shale gas reservoirs according to claim 1, characterized in that: S2 includes the following steps: S201. The formation fluid density, fluid velocity, fluid viscosity, and wellbore diameter are calculated using parameter determination formulas to obtain the actual downhole fluid Reynolds number, which represents the flow pattern of the formation fluid. S202. Using the parameter calculation formula, the corresponding fluid friction factor is analyzed based on the actual downhole fluid Reynolds number. The fluid friction factor represents the interaction relationship between fluids.

4. The method for evaluating the production potential of horizontal well foam drainage technology in shale gas reservoirs according to claim 3, characterized in that: The specific formula for obtaining the parameters in S201 is as follows: in, Represents the Reynolds number. Indicates fluid density, Indicates fluid velocity. represents the wellbore diameter, Indicates fluid viscosity, This represents the fluid friction factor.

5. The method for evaluating the production potential of horizontal well foam drainage technology in shale gas reservoirs according to claim 1, characterized in that: S3 specifically includes the following steps: S301. After obtaining the fluid temperature and fluid friction factor, the diffusion coefficient of the foaming agent is calculated by using the diffusion coefficient analysis formula. S302. After reading the surface tension of the foaming agent, wellbore pressure, critical surface tension of the foaming agent, critical wellbore pressure at which the foaming agent is most stable, and stability coefficient of the foaming agent, calculate them using the stability coefficient analysis formula. Analyze the relationship between the surface tension of the foaming agent and the wellbore pressure to obtain the stability coefficient of the foaming agent.

6. The method for evaluating the production potential of horizontal well foam drainage technology in shale gas reservoirs according to claim 1, characterized in that: S4 specifically includes the following steps: S401. The production potential index is obtained by calculating the fluid temperature, the diffusion coefficient of the foaming agent, and the stability coefficient of the foaming agent through the potential index analysis formula. S402. Based on the production potential index, the production increase effect of the foaming and desiccant is initially divided into three levels: excellent, medium and poor.

7. The method for evaluating the production potential of horizontal well foam drainage technology in shale gas reservoirs according to claim 6, characterized in that: S4 further includes the following steps: S403. When the production potential index is greater than zero and less than or equal to 0.35, the performance of the current foaming agent is judged to be poor. S404. When the production potential index is greater than 0.35 and less than or equal to 0.7, the performance of the current foaming agent is judged to be medium. S405. When the production potential index is greater than 0.7 and less than or equal to 1, the performance of the current foaming agent is judged to be excellent.

8. The method for evaluating the production potential of horizontal well foam drainage technology in shale gas reservoirs according to claim 5, characterized in that: The diffusion coefficient analysis formula in S301 is as follows: in, Indicates the diffusion coefficient of the foaming agent. Indicates fluid temperature. This represents the fluid friction factor.

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