Wellbore pressure prediction method considering fracturing fluid

Abstract

The invention discloses a wellbore pressure prediction method considering fracturing fluid, and relates to the technical field of shale gas development. Comprising the following steps: determining gas well depth and wellhead conditions, segmenting according to the gas well depth, obtaining different shaft sections and current fracturing fluid data, and calculating and obtaining flow parameter data based on the fracturing fluid data; calculating shaft section temperature according to a temperature model, and assigning an initial pressure value according to shaft section data; inputting flow parameter data into the pressure model to update parameters, coupling the pressure model and the temperature model, calculating to obtain calculated wellbore pressure, judging whether the calculated wellbore pressure is consistent with an initial pressure value or not, if not, setting the calculated wellbore pressure as the initial pressure value, if yes, judging whether the wellbore is a bottom-end wellbore or not, if not, setting the calculated wellbore pressure as the initial pressure value, and if yes, judging whether the wellbore is a bottom-end wellbore. And directly outputting the calculated pressure value as the predicted pressure. According to the method, the change rule of the viscosity of the shale gas fracturing flow-back fluid can be well predicted, and the calculation accuracy is effectively improved.

Description

Technical Field

[0001] The present invention relates to the technical field of shale gas development, and in particular to a method for predicting wellbore pressure taking fracturing fluid into consideration. Background Art

[0002] Shale gas is an unconventional natural gas resource that can be mined in dark mud shale or high-carbon mud shale. Its main component is methane. As China's need for clear water and blue sky grows day by day, the energy development model is transformed into a green and sustainable one, and the demand for clean and efficient natural gas continues to rise. At the same time, the fracturing fluid return pattern of shale gas fields is complex and the liquid accumulation is serious, which has become an important factor restricting the production capacity of gas wells. Therefore, it is particularly important to accurately predict the wellbore temperature and pressure for judging the wellbore liquid accumulation and selecting the appropriate drainage process. The conventional temperature and pressure monitoring method is mainly to place a thermometer and a pressure gauge or only measure the bottom hole or wellhead temperature and pressure, and obtain the wellbore temperature and pressure distribution through theoretical analysis. In actual production, due to the difficulty of dynamic monitoring of high-temperature and high-pressure gas wells, conventional monitoring methods cannot meet management needs, and theoretical analysis methods are needed to predict the wellbore temperature and pressure distribution.

[0003] Therefore, it is an urgent problem for those skilled in the art to propose a method for predicting wellbore pressure taking into account fracturing fluid to solve the problems existing in the prior art. Summary of the invention

[0004] In view of this, the present invention provides a method for predicting wellbore pressure taking into account fracturing fluid, which can better predict the change law of viscosity of shale gas fracturing return fluid and effectively improve the calculation accuracy.

[0005] In order to achieve the above object, the present invention adopts the following technical solution:

[0006] A method for predicting wellbore pressure considering fracturing fluid comprises the following steps:

[0007] S1. Determine the gas well depth and wellhead conditions, divide the gas well into sections according to the gas well depth, and obtain different wellbore sections;

[0008] S2, obtaining current fracturing fluid data, and calculating flow parameter data based on the fracturing fluid data;

[0009] S3, calculating the wellbore section temperature according to the temperature model, and assigning an initial pressure value according to the wellbore section data;

[0010] S4, inputting the flow parameter data into the pressure model to update the parameters, coupling the pressure model and the temperature model, and calculating the wellbore pressure;

[0011] S5, judging whether the wellbore pressure obtained in S4 is consistent with the initial pressure value, if not, setting the wellbore pressure to the initial pressure value, repeating S2-S4, if yes, proceeding to S6;

[0012] S6. Determine whether the wellbore is a bottom wellbore. If not, set the wellbore pressure to the initial pressure value and repeat S1-S4. If yes, directly output the current wellbore pressure value as the predicted wellbore pressure value.

[0013] In the above method, optionally, the flow parameter data in S2 include fracturing fluid viscosity, density and surface tension.

[0014] In the above method, optionally, the temperature model in S3 includes: establishing a temperature model based on formation heat transfer coefficient, formation thermal conductivity and gas-water fluid mixed specific heat, and the expression is:

[0015]

[0016] Among them, T fout is the wellbore fluid temperature at the outlet, T out is the formation temperature at the outlet, z is the well depth, z in is the entrance well depth, C p is the specific heat capacity of the fluid at constant pressure, C J Joule Thomson coefficient, v is the fluid velocity, T fin Wellbore fluid temperature at inlet, T ein is the ground temperature at the inlet.

[0017] In the above method, optionally, the coupling model in S4 is divided into an opening well model and a closing well model.

[0018] The well opening model expression is as follows:

[0019]

[0020] Among them, p wf is the bottom hole pressure of the segmented wellbore when the well is opened, p tf is the opening pressure of the segmented wellbore when the well is opened, and s can be expressed as T is the average temperature of the gas, Z is the gas deviation coefficient, γ is the gas density, f is the Moody friction coefficient, q sc is the gas flow rate under standard conditions, T1 is the average gas temperature when the well is opened, Z1 is the gas deviation coefficient when the well is opened, and d is the inner diameter of the wellbore.

[0021] The above method can optionally be used to close the well expression as follows:

[0022] p ws =p ts e s ,

[0023] Among them, p ws is the bottom hole pressure of the segmented wellbore when the well is shut in, p ts The opening pressure of the segmented wellbore when the well is shut in.

[0024] It can be seen from the above technical solution that, compared with the prior art, the present invention provides a method for predicting wellbore pressure taking into account fracturing fluid, which has the following beneficial effects: 1) The present invention fits a relationship that can better predict the change law of the viscosity of shale gas fracturing return fluid; 2) The present invention establishes a wellbore temperature-pressure coupling model, which can effectively improve the calculation accuracy. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on the provided drawings without paying creative work.

[0026] Figure 1 A flow chart of a method for predicting wellbore pressure considering fracturing fluid disclosed in the present invention;

[0027] Figure 2 The present invention discloses a principle diagram of a method for predicting wellbore pressure taking fracturing fluid into consideration. DETAILED DESCRIPTION

[0028] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0029] In this application, relational terms such as first and second, etc. are used only to distinguish one entity or operation from another entity or operation, and do not necessarily require or imply any such actual relationship or order between these entities or operations. The terms "include", "comprise" or any other variants thereof are intended to cover non-exclusive inclusion, so that a process, method, article or device including a series of elements includes not only those elements, but also other elements not explicitly listed, or also includes elements inherent to such process, method, article or device. In the absence of more restrictions, the elements defined by the sentence "comprise one..." do not exclude the existence of other identical elements in the process, method, article or device including the elements.

[0030] Reference Figure 1 and Figure 2 As shown, the present invention discloses a method for predicting wellbore pressure considering fracturing fluid, comprising the following steps:

[0031] S1. Determine the gas well depth and wellhead conditions, divide the gas well into sections according to the gas well depth, and obtain different wellbore sections;

[0032] S2, obtaining current fracturing fluid data, and calculating flow parameter data based on the fracturing fluid data;

[0033] S3, calculating the wellbore section temperature according to the temperature model, and assigning an initial pressure value according to the wellbore section data;

[0034] S4, inputting the flow parameter data into the pressure model to update the parameters, coupling the pressure model and the temperature model, and calculating the wellbore pressure;

[0035] S5, judging whether the wellbore pressure obtained in S4 is consistent with the initial pressure value, if not, setting the wellbore pressure to the initial pressure value, repeating S2-S4, if yes, proceeding to S6;

[0036] S6. Determine whether the wellbore is a bottom wellbore. If not, set the wellbore pressure to the initial pressure value and repeat S1-S4. If yes, directly output the current wellbore pressure value as the predicted wellbore pressure value.

[0037] Furthermore, the flow parameter data in S2 include fracturing fluid viscosity, density and surface tension.

[0038] Specifically, the flowback fluid parameters are little affected by pressure and are mainly affected by temperature, so the viscosity, density and surface tension of the flowback fluid are mainly tested.

[0039] The viscosity of the flowback fluid was tested using a Hake MARSIII rotational rheometer, and the viscosity-temperature of the fracturing flowback fluid was obtained by fitting. The density of the flowback fluid was tested using a DMA HPA high-temperature and high-pressure densitometer, and the relationship between the density and temperature of the fracturing flowback fluid was obtained by fitting. The surface tension of the flowback fluid was tested using a KRUSSDSA30S interface parameter integrated measurement system, and the relationship between the surface tension and temperature of the fracturing flowback fluid was obtained by fitting.

[0040] Furthermore, the temperature model in S3 includes: establishing a temperature model based on the formation heat transfer coefficient, the formation thermal conductivity and the mixed specific heat of the gas-water fluid, and the expression is:

[0041]

[0042] Among them, T fout is the wellbore fluid temperature at the outlet, T out is the formation temperature at the outlet, z is the well depth, z in is the entrance well depth, Cp is the specific heat capacity of the fluid at constant pressure, C J Joule Thomson coefficient, v is the fluid velocity, T fin Wellbore fluid temperature at inlet, T ein is the ground temperature at the inlet.

[0043] Specifically, the bottom of the well is defined as the coordinate origin and the vertical upward is positive. A microelement with a length of dz is taken on the wellbore. When the gas flows through the microelement, the heat flowing into the microelement by convection is equal to the sum of the heat flowing out of the microelement and the heat transferred to the formation. The radial heat transfer within the microelement segment can be calculated based on the temperature difference between the wellbore at the starting point of the microelement segment and the wellbore-formation interface.

[0044] Furthermore, the coupling model in S4 is divided into an open well model and a closed well model.

[0045] The well opening model expression is as follows:

[0046]

[0047] Among them, p wf is the bottom hole pressure of the segmented wellbore when the well is opened, p tf is the opening pressure of the segmented wellbore when the well is opened, and s can be expressed as T is the average temperature of the gas, Z is the gas deviation coefficient, γ is the gas density, f is the Moody friction coefficient, q sc is the gas flow rate under standard conditions, T1 is the average gas temperature when the well is opened, Z1 is the gas deviation coefficient when the well is opened, and d is the inner diameter of the wellbore.

[0048] Furthermore, the shut-in expression is as follows:

[0049] p ws =p ts e s ,

[0050] Among them, p ws is the bottom hole pressure of the segmented wellbore when the well is shut in, p ts The opening pressure of the segmented wellbore when the well is shut in.

[0051] Specifically, since the physical properties of the fluid in the shale gas wellbore change with temperature and pressure, and the fluid physical property parameters required for calculating the temperature are affected by the pressure, and the fluid physical property parameters required for calculating the pressure are affected by the temperature, the relationship between the fluid physical property parameters, the pressure calculation model and the temperature calculation model affects each other; if the temperature and pressure are solved separately, it will cause large errors, so it is necessary to calculate through a coupled iterative method.

[0052] Each embodiment in this specification is described in a progressive manner, and the same or similar parts between the embodiments can refer to each other, and each embodiment focuses on the differences from other embodiments. In particular, for the system or system embodiment, since it is basically similar to the method embodiment, the description is relatively simple, and the relevant parts can refer to the partial description of the method embodiment. The system and system embodiments described above are merely schematic, wherein the units described as separate components may or may not be physically separated, and the components displayed as units may or may not be physical units, that is, they may be located in one place, or they may be distributed on multiple network units. Some or all of the modules may be selected according to actual needs to achieve the purpose of the scheme of this embodiment. Ordinary technicians in this field can understand and implement it without creative work.

[0053] The above description of the disclosed embodiments enables one skilled in the art to implement or use the present invention. Various modifications to these embodiments will be apparent to one skilled in the art, and the general principles defined herein may be implemented in other embodiments without departing from the spirit or scope of the present invention. Therefore, the present invention will not be limited to the embodiments shown herein, but rather to the widest scope consistent with the principles and novel features disclosed herein.

Claims

1. A method for predicting wellbore pressure considering fracturing fluid, characterized in that: The following steps are involved: S1. Determine the gas well depth and wellhead conditions, divide the gas well into sections according to the gas well depth, and obtain different wellbore sections; S2, obtaining current fracturing fluid data, and calculating flow parameter data based on the fracturing fluid data; S3, calculating the wellbore section temperature according to the temperature model, and assigning an initial pressure value according to the wellbore section data; S4, inputting the flow parameter data into the pressure model to update the parameters, coupling the pressure model and the temperature model, and calculating the wellbore pressure; S5, determine whether the wellbore pressure obtained in S4 is consistent with the initial pressure value. If not, set the wellbore pressure to the initial pressure value and repeat S2-S4. If yes, proceed to S6; S6. Determine whether the wellbore is a bottom wellbore. If not, set the wellbore pressure to the initial pressure value and repeat S1-S4. If yes, directly output the current wellbore pressure value as the predicted wellbore pressure value.

2. A method for predicting wellbore pressure considering fracturing fluid according to claim 1, characterized in that: The flow parameter data in S2 include fracturing fluid viscosity, density and surface tension.

3. A method for predicting wellbore pressure considering fracturing fluid according to claim 1, characterized in that: The temperature model in S3 includes: a temperature model is established based on the formation heat transfer coefficient, formation thermal conductivity and gas-water fluid mixed specific heat, and the expression is: Among them, T fout is the wellbore fluid temperature at the outlet, T out is the formation temperature at the outlet, z is the well depth, z in is the entrance section depth, C p is the specific heat capacity of the fluid at constant pressure, C J Joule Thomson coefficient, v is the fluid velocity, T fin Wellbore fluid temperature at inlet, T ein is the ground temperature at the inlet.

4. A method for predicting wellbore pressure considering fracturing fluid according to claim 1, characterized in that: The coupling model in S4 is divided into an open well model and a closed well model. The expression of the well opening model is as follows: Among them, p wf is the bottom hole pressure of the segmented wellbore when the well is opened, p tf is the opening pressure of the segmented wellbore when the well is opened, and s can be expressed as T is the average temperature of the gas, Z is the gas deviation coefficient, γ is the gas density, f is the Moody friction coefficient, q sc is the gas flow rate under standard conditions, T1 is the average gas temperature when the well is opened, Z1 is the gas deviation coefficient when the well is opened, and d is the inner diameter of the wellbore.

5. A method for predicting wellbore pressure considering fracturing fluid according to claim 4, characterized in that: The shut-in expression is as follows: p ws =p ts e s , Among them, p ws is the bottom hole pressure of the segmented wellbore when the well is shut in, p ts The opening pressure of the segmented wellbore when the well is shut in.

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