CN113006776A - Fracturing horizontal well temperature field prediction method based on optical fiber distributed temperature sensor - Google Patents
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Abstract
The invention relates to a fracturing horizontal well temperature field prediction method based on an optical fiber distributed temperature sensor, and belongs to the field of oil and gas field development and evaluation. The method solves the problems that the existing fracturing horizontal well temperature field prediction methods have different limitations and the accuracy of temperature measurement is difficult to guarantee; the technical scheme is as follows: collecting basic parameters of a gas reservoir and a gas well; recording the inflow temperature of each point of the horizontal well section which is monitored under different gas well yields and stabilized based on the optical fiber distributed temperature sensor; establishing a gas reservoir temperature model of the fractured horizontal well by combining an energy conservation law and a heat transfer effect; establishing a shaft temperature model of the fractured horizontal well; establishing a gas reservoir and shaft coupling temperature model; correcting the temperature field by using a temperature correction equation to obtain a final fractured horizontal well temperature field; the invention has the following beneficial effects: the theory is combined with actual measurement, and the reliability of the calculation result is high; the calculation is convenient and efficient; the method realizes effective monitoring of the whole well section, and has strong pertinence and wide application range.
Description
Technical Field
The invention relates to a fracturing horizontal well temperature field prediction method based on an optical fiber distributed temperature sensor, and belongs to the field of oil and gas field development and evaluation.
Background
At present, development and evaluation of oil and gas reservoirs are mostly in the aspect of mass transfer, and the development is relatively slow due to the large research difficulty in the aspect of heat transfer; however, when relevant work such as identification of reservoir fluid, judgment of water position and the like is carried out, the heat transfer is simpler and more efficient through temperature field judgment; therefore, the correct calculation and acquisition of the temperature field are the key for reasonably knowing the reservoir subsequently, ensuring the single-well productivity, guiding the reasonable development of the oil-gas reservoir and implementing related yield-increasing transformation measures.
At present, two methods are mainly used for fracturing a horizontal well: one is a direct test method, which is widely applied due to the proposal of a fiber Distributed Temperature Sensor (DTS) in the present year; the temperature profile simulation experiment device and method for the fracturing horizontal well based on the DTS, which is disclosed as CN109653741A, utilize the optical fiber distributed temperature sensors to carry out indoor experiments, but in an actual horizontal well, the length of the horizontal well is mostly hundreds to thousands of meters, the straight line state in the whole optical fiber distribution process is difficult to ensure, and the obtained temperature field is difficult to ensure to be an actual temperature field only by the optical fiber distributed temperature sensors; the other is a theoretical prediction method, which is realized by establishing a theoretical mathematical model, but different limitations exist, and the situation of deviation from reality exists. In summary, there is an urgent need for a method for predicting a temperature field of a wellbore, which can accurately predict the temperature field and ensure the accuracy.
Disclosure of Invention
The invention aims to: the method aims to solve the problems that the existing fracturing horizontal well temperature field prediction methods have different limitations and the accuracy of temperature measurement is difficult to guarantee; the invention provides a fracturing horizontal well temperature field prediction method based on an optical fiber distributed temperature sensor by means of combining actual measurement and theory, and the method is accurate in calculation and strong in applicability.
In order to achieve the aim, the invention provides a fracturing horizontal well temperature field prediction method based on an optical fiber distributed temperature sensor, which is characterized by comprising the following steps:
s100, placing the optical fiber distributed temperature sensor on the inner side of a casing in a straight line during well completion, putting the optical fiber distributed temperature sensor into a horizontal well shaft, and collecting basic parameters of a gas reservoir and a gas well;
s101, the length of an optical fiber distributed temperature sensor placed on the inner side of a sleeve is consistent with the length of a monitored horizontal well section;
s102, collecting basic parameters of the gas reservoir and the gas well, wherein the basic parameters comprise porosity, natural gas density, rock density, natural gas specific heat capacity, rock specific heat capacity, original gas reservoir temperature, thermal expansion coefficient, gas reservoir pressure, natural gas flow rate and wellbore radius;
s200, performing well opening production, recording inflow temperatures of all points of a horizontal well section monitored under different gas well yields, and recording the temperature field distribution of the yield after data are maintained stable;
s201, setting the initial gas well yield to be 10000 square/day, recording the temperature distribution of each point of a monitored horizontal well section in real time, and recording a stable temperature field when the gas well yield is 10000 square/day after the temperature of each point is constant for 1 hour;
s202, adjusting the yield of the gas well to 50000 square/day, recording the temperature distribution of each point of the well section of the monitored horizontal well in real time, and recording a stable temperature field when the yield of the gas well is 50000 square/day after the temperature of each point is constant for 1 hour;
s203, adjusting the gas well yield to be 100000 square/day, recording the temperature distribution of each point of the monitored horizontal well section in real time, and recording a stable temperature field when the gas well yield is 100000 square/day after the temperature of each point is constant for 1 hour;
s204, adjusting the gas well yield to 150000 squares/day, recording the temperature distribution of each point of the horizontal well section in real time, and recording a stable temperature field when the gas well yield is 150000 squares/day after the temperature of each point is constant for 1 hour;
s300, establishing a gas reservoir temperature model of the fractured horizontal well by combining an energy conservation law and a heat transfer effect;
s301, natural gas flows in the gas reservoir, and an energy conservation equation in a certain unit volume of the gas reservoir can be expressed as follows: the speed of energy accumulation is the net energy transport speed + the energy generation speed;
s302, deducing a final gas reservoir temperature model of the fractured horizontal well based on the energy conservation equation in the step S301 as
Wherein phi is porosity and is dimensionless; rhogIs the density of natural gas in kg/m3；ρsIs the rock density in kg/m3；CpgThe specific heat capacity of natural gas is expressed in J/(kg. K); cpsThe specific heat capacity of the rock is J/(kg. K); t is temperature in K; t is time in units of s; beta is the coefficient of thermal expansion, and the unit is 1/K; p is a radical ofgIs the gas reservoir pressure in MPa; u. ofgIs the natural gas flow rate, and the unit is m/s; g is gravity acceleration, constant, and is 9.8m/s2；KTtIs the Joule Thomson coefficient in J/(m)3·K)；
S400, establishing a shaft temperature model of the fractured horizontal well by combining an energy conservation law and a heat transfer effect;
s401, the energy conservation equation within a certain unit volume of the wellbore can be expressed as: energy increase is energy inflow and energy outflow, external force work and energy generation;
s402, the final wellbore temperature model of the fractured horizontal well is
In the formula:
s500, establishing a gas reservoir and shaft coupling temperature model by combining the gas reservoir temperature model and the shaft temperature model, obtaining a relational expression of yield and pressure by combining a substance balance equation, and predicting the temperature field distribution when the gas well yield is 10000 square/day, 50000 square/day, 100000 square/day and 150000 square/day by using the gas reservoir and shaft coupling temperature model;
s501, obtaining a gas reservoir and shaft coupling temperature model through a coupling gas reservoir temperature model and a shaft temperature model, wherein the gas reservoir and shaft coupling temperature model is divided into two conditions of shaft and gas reservoir communication and shaft and gas reservoir communication;
s502, a gas reservoir and wellbore coupling temperature model when the wellbore is communicated with the gas reservoir is
Wherein r is the distance from the wellbore in m;
s502, when the shaft and the gas reservoir are not communicated, the gas reservoir and shaft coupling temperature model is
In the formula: k is the gas reservoir permeability in mD; alpha is effective pressure gradient with unit of MPa/m; mu is natural gas viscosity with unit of mPa.s;
s600, combining the temperature field obtained by monitoring based on the optical fiber distributed temperature sensor in the step S200 and the gas reservoir and shaft coupling temperature model, and correcting the temperature field obtained by coupling the gas reservoir and the shaft coupling temperature model based on the temperature field obtained by monitoring based on the optical fiber distributed temperature sensor by using a temperature correction equation to obtain a final fractured horizontal well temperature field, so as to complete the prediction of the fractured horizontal well temperature field;
s601, the temperature correction equation in the step S600 is
In the formula: t istThe temperature obtained by coupling the gas reservoir with a shaft temperature model is expressed in K; t issThe temperature is obtained by monitoring the optical fiber distributed temperature sensor, and the unit is K; t is0Is the original temperature of the gas reservoir in K.
The fracturing horizontal well temperature field prediction method based on the optical fiber distributed temperature sensor comprises the following steps: the method is characterized in that the material balance equation in the step S500 is determined according to the actual gas reservoir type.
Compared with the prior art, the invention has the following beneficial effects: (1) the theory is combined with the actual measurement, and the reliability of the calculation result is high; (2) a temperature prediction model is provided based on the actual condition of the fractured horizontal well, and the calculation is convenient, fast and efficient; (3) the method realizes effective monitoring of the whole well section, and has strong pertinence and wide application range.
Drawings
In the drawings:
FIG. 1 is a technical scheme of the method.
FIG. 2 is a graph of the temperature prediction field of the present method.
Figure 3 is a real water outlet profile of fractured horizontal well X1.
Detailed Description
The present invention will be further described with reference to the following embodiments and drawings.
The invention provides a fracturing horizontal well temperature field prediction method based on an optical fiber distributed temperature sensor, which comprises the following steps of:
s100, placing the optical fiber distributed temperature sensor on the inner side of a casing in a straight line during well completion, putting the optical fiber distributed temperature sensor into a horizontal well shaft, and collecting basic parameters of a gas reservoir and a gas well;
s101, the length of an optical fiber distributed temperature sensor placed on the inner side of a sleeve is consistent with the length of a monitored horizontal well section;
s102, collecting basic parameters of the gas reservoir and the gas well, wherein the basic parameters comprise porosity, natural gas density, rock density, natural gas specific heat capacity, rock specific heat capacity, original gas reservoir temperature, thermal expansion coefficient, gas reservoir pressure, natural gas flow rate and wellbore radius;
s200, performing well opening production, recording inflow temperatures of all points of a horizontal well section monitored under different gas well yields, and recording the temperature field distribution of the yield after data are maintained stable;
s201, setting the initial gas well yield to be 10000 square/day, recording the temperature distribution of each point of a monitored horizontal well section in real time, and recording a stable temperature field when the gas well yield is 10000 square/day after the temperature of each point is constant for 1 hour;
s202, adjusting the yield of the gas well to 50000 square/day, recording the temperature distribution of each point of the well section of the monitored horizontal well in real time, and recording a stable temperature field when the yield of the gas well is 50000 square/day after the temperature of each point is constant for 1 hour;
s203, adjusting the gas well yield to be 100000 square/day, recording the temperature distribution of each point of the monitored horizontal well section in real time, and recording a stable temperature field when the gas well yield is 100000 square/day after the temperature of each point is constant for 1 hour;
s204, adjusting the gas well yield to 150000 squares/day, recording the temperature distribution of each point of the horizontal well section in real time, and recording a stable temperature field when the gas well yield is 150000 squares/day after the temperature of each point is constant for 1 hour;
s300, establishing a gas reservoir temperature model of the fractured horizontal well by combining an energy conservation law and a heat transfer effect;
s301, natural gas flows in the gas reservoir, and an energy conservation equation in a certain unit volume of the gas reservoir can be expressed as follows: the speed of energy accumulation is the net energy transport speed + the energy generation speed;
s302, deducing a final gas reservoir temperature model of the fractured horizontal well based on the energy conservation equation in the step S301 as
Wherein phi is porosity and is dimensionless; rhogIs the density of natural gas in kg/m3；ρsIs the rock density in kg/m3；CpgThe specific heat capacity of natural gas is expressed in J/(kg. K); cpsThe specific heat capacity of the rock is J/(kg. K); t is temperature in K; t is time in units of s; beta is the coefficient of thermal expansion, and the unit is 1/K; p is a radical ofgIs the gas reservoir pressure in MPa; u. ofgIs the natural gas flow rate, and the unit is m/s; g is gravity acceleration, constant, and is 9.8m/s2；KTtIs the Joule Thomson coefficient in J/(m)3·K)；
S400, establishing a shaft temperature model of the fractured horizontal well by combining an energy conservation law and a heat transfer effect;
s401, the energy conservation equation within a certain unit volume of the wellbore can be expressed as: energy increase is energy inflow and energy outflow, external force work and energy generation;
s402, the final wellbore temperature model of the fractured horizontal well is
In the formula:
s500, establishing a gas reservoir and shaft coupling temperature model by combining the gas reservoir temperature model and the shaft temperature model, obtaining a relational expression of yield and pressure by combining a substance balance equation, and predicting the temperature field distribution when the gas well yield is 10000 square/day, 50000 square/day, 100000 square/day and 150000 square/day by using the gas reservoir and shaft coupling temperature model;
s501, obtaining a gas reservoir and shaft coupling temperature model through a coupling gas reservoir temperature model and a shaft temperature model, wherein the gas reservoir and shaft coupling temperature model is divided into two conditions of shaft and gas reservoir communication and shaft and gas reservoir communication;
s502, a gas reservoir and wellbore coupling temperature model when the wellbore is communicated with the gas reservoir is
Wherein r is the distance from the wellbore in m;
s502, when the shaft and the gas reservoir are not communicated, the gas reservoir and shaft coupling temperature model is
In the formula: k is the gas reservoir permeability in mD; alpha is effective pressure gradient with unit of MPa/m; mu is natural gas viscosity with unit of mPa.s;
s600, combining the temperature field obtained by monitoring based on the optical fiber distributed temperature sensor in the step S200 and the gas reservoir and shaft coupling temperature model, and correcting the temperature field obtained by coupling the gas reservoir and the shaft coupling temperature model based on the temperature field obtained by monitoring based on the optical fiber distributed temperature sensor by using a temperature correction equation to obtain a final fractured horizontal well temperature field, so as to complete the prediction of the fractured horizontal well temperature field;
s601, the temperature correction equation in the step S600 is
In the formula: t istThe temperature obtained by coupling the gas reservoir with a shaft temperature model is expressed in K; t issThe temperature is obtained by monitoring the optical fiber distributed temperature sensor, and the unit is K; t is0Is the original temperature of the gas reservoir in K.
Further, the material balance equation in step S500 in the above method is determined according to the actual gas reservoir type.
Compared with the prior art, the invention has the following beneficial effects: (1) the theory is combined with the actual measurement, and the reliability of the calculation result is high; (2) a temperature prediction model is provided based on the actual condition of the fractured horizontal well, and the calculation is convenient, fast and efficient; (3) the method realizes effective monitoring of the whole well section, and has strong pertinence and wide application range.
The fractured horizontal well temperature field prediction method based on the optical fiber distributed temperature sensor is further described in combination with a specific fractured horizontal well X1:
the horizontal section length of the fractured horizontal well X1 is 1000m, and the gas reservoir and gas well basic parameters are collected by taking the gas well yield as 10000 squares/day as an example, and are shown in Table 1.
TABLE 1
| Porosity of | 0.08 | Original temperature K of |
330 |
| Natural gas density g/cm3 | 0.202 | Coefficient of thermal expansion 1/K | 4.78×104 |
| Density of rock g/cm3 | 2.57 | Pressure of gas reservoir MPa | 32 |
| Rock specific heat capacity J/(kg. K) | 107 | Natural gas flow rate m/s | 37.7 |
| Specific heat capacity of natural gas J/(kg. K) | 850 | Radius m of shaft | 0.1 |
Obtaining the temperature field distribution of the fractured horizontal well with the gas well yield of 10000 square/day through an optical fiber distributed temperature sensor, as shown by a corresponding curve in figure 2;
based on the basic parameters in table 1, performing temperature field calculation of fractured horizontal well X1 by using gas reservoir and wellbore coupling temperature models (4) and (5), as shown by corresponding curves in fig. 2;
using temperature correction equations
Correcting the temperature field obtained by the gas reservoir and shaft coupling temperature model through the temperature field obtained by monitoring the optical fiber distributed temperature sensor to obtain the final fractured horizontal well temperature field, as shown by a corresponding curve in figure 2;
identifying the water outlet position by utilizing the final fractured horizontal well temperature field, combining the actual water outlet profile on site, and performing water plugging construction on the position 500m of the horizontal well section as shown in figure 3, wherein the water outlet position is better consistent with the actual water outlet profile on site, and the water yield of the gas well is reduced to 5% of the original water yield after water plugging; the method is high in accuracy, can effectively predict the temperature field of the fractured horizontal well, and is good in field application effect.
Compared with the prior art, the invention has the following beneficial effects: (1) the theory is combined with the actual measurement, and the reliability of the calculation result is high; (2) a temperature prediction model is provided based on the actual condition of the fractured horizontal well, and the calculation is convenient, fast and efficient; (3) the method realizes effective monitoring of the whole well section, and has strong pertinence and wide application range.
Finally, it should be noted that: although the present invention has been described in detail with reference to the above embodiments, it should be understood by those skilled in the art that: modifications and equivalents may be made thereto without departing from the spirit and scope of the invention and it is intended to cover in the claims the invention as defined in the appended claims.
Claims (2)
1. The fracturing horizontal well temperature field prediction method based on the optical fiber distributed temperature sensor is characterized by comprising the following steps of:
s100, placing the optical fiber distributed temperature sensor on the inner side of a casing in a straight line during well completion, putting the optical fiber distributed temperature sensor into a horizontal well shaft, and collecting basic parameters of a gas reservoir and a gas well;
s101, the length of an optical fiber distributed temperature sensor placed on the inner side of a sleeve is consistent with the length of a monitored horizontal well section;
s102, collecting basic parameters of the gas reservoir and the gas well, wherein the basic parameters comprise porosity, natural gas density, rock density, natural gas specific heat capacity, rock specific heat capacity, original gas reservoir temperature, thermal expansion coefficient, gas reservoir pressure, natural gas flow rate and wellbore radius;
s200, performing well opening production, recording inflow temperatures of all points of a horizontal well section monitored under different gas well yields, and recording the temperature field distribution of the yield after data are maintained stable;
s201, setting the initial gas well yield to be 10000 square/day, recording the temperature distribution of each point of a monitored horizontal well section in real time, and recording a stable temperature field when the gas well yield is 10000 square/day after the temperature of each point is constant for 1 hour;
s202, adjusting the yield of the gas well to 50000 square/day, recording the temperature distribution of each point of the well section of the monitored horizontal well in real time, and recording a stable temperature field when the yield of the gas well is 50000 square/day after the temperature of each point is constant for 1 hour;
s203, adjusting the gas well yield to be 100000 square/day, recording the temperature distribution of each point of the monitored horizontal well section in real time, and recording a stable temperature field when the gas well yield is 100000 square/day after the temperature of each point is constant for 1 hour;
s204, adjusting the gas well yield to 150000 squares/day, recording the temperature distribution of each point of the horizontal well section in real time, and recording a stable temperature field when the gas well yield is 150000 squares/day after the temperature of each point is constant for 1 hour;
s300, establishing a gas reservoir temperature model of the fractured horizontal well by combining an energy conservation law and a heat transfer effect;
s301, natural gas flows in the gas reservoir, and an energy conservation equation in a certain unit volume of the gas reservoir can be expressed as follows: the speed of energy accumulation is the net energy transport speed + the energy generation speed;
s302, deducing a final gas reservoir temperature model of the fractured horizontal well based on the energy conservation equation in the step S301 as
Wherein phi is porosity and is dimensionless; rhogIs the density of natural gas in kg/m3；ρsIs the rock density in kg/m3；CpgThe specific heat capacity of natural gas is expressed in J/(kg. K); cpsThe specific heat capacity of the rock is J/(kg. K); t is temperature in K; t is time in units of s; beta is the coefficient of thermal expansion, and the unit is 1/K; p is a radical ofgIs the gas reservoir pressure in MPa; u. ofgIs the natural gas flow rate, and the unit is m/s; g is gravity acceleration, constant, and is 9.8m/s2；KTtIs the Joule Thomson coefficient in J/(m)3·K)；
S400, establishing a shaft temperature model of the fractured horizontal well by combining an energy conservation law and a heat transfer effect;
s401, the energy conservation equation within a certain unit volume of the wellbore can be expressed as: energy increase is energy inflow and energy outflow, external force work and energy generation;
s402, the final wellbore temperature model of the fractured horizontal well is
In the formula:
s500, establishing a gas reservoir and shaft coupling temperature model by combining the gas reservoir temperature model and the shaft temperature model, obtaining a relational expression of yield and pressure by combining a substance balance equation, and predicting the temperature field distribution when the gas well yield is 10000 square/day, 50000 square/day, 100000 square/day and 150000 square/day by using the gas reservoir and shaft coupling temperature model;
s501, obtaining a gas reservoir and shaft coupling temperature model through a coupling gas reservoir temperature model and a shaft temperature model, wherein the gas reservoir and shaft coupling temperature model is divided into two conditions of shaft and gas reservoir communication and shaft and gas reservoir communication;
s502, a gas reservoir and wellbore coupling temperature model when the wellbore is communicated with the gas reservoir is
Wherein r is the distance from the wellbore in m;
s502, when the shaft and the gas reservoir are not communicated, the gas reservoir and shaft coupling temperature model is
In the formula: k is the gas reservoir permeability in mD; alpha is effective pressure gradient with unit of MPa/m; mu is natural gas viscosity with unit of mPa.s;
s600, combining the temperature field obtained by monitoring based on the optical fiber distributed temperature sensor in the step S200 and the gas reservoir and shaft coupling temperature model, and correcting the temperature field obtained by coupling the gas reservoir and the shaft coupling temperature model based on the temperature field obtained by monitoring based on the optical fiber distributed temperature sensor by using a temperature correction equation to obtain a final fractured horizontal well temperature field, so as to complete the prediction of the fractured horizontal well temperature field;
s601, the temperature correction equation in the step S600 is
In the formula: t istThe temperature obtained by coupling the gas reservoir with a shaft temperature model is expressed in K; t issThe temperature is obtained by monitoring the optical fiber distributed temperature sensor, and the unit is K; t is0Is the original temperature of the gas reservoir in K.
2. The method for predicting the temperature field of the fractured horizontal well based on the optical fiber distributed temperature sensor as claimed in claim 1: the method is characterized in that the material balance equation in the step S500 is determined according to the actual gas reservoir type.
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Application publication date: 20210622 |