CN210768732U

CN210768732U - Shaft production section monitoring simulation experiment device based on distributed optical fiber sound and temperature monitoring

Info

Publication number: CN210768732U
Application number: CN201921116891.1U
Authority: CN
Inventors: 刘均荣; 劳文韬; 梁文博; 刘庆文
Original assignee: Puniu Shanghai Technology Co ltd; China University of Petroleum East China
Current assignee: Puniu Shanghai Technology Co ltd; China University of Petroleum East China
Priority date: 2019-07-16
Filing date: 2019-07-16
Publication date: 2020-06-16
Anticipated expiration: 2029-07-16

Abstract

A shaft production section monitoring simulation experiment device based on distributed optical fiber sound and temperature monitoring comprises: the system comprises a distributed optical fiber sound and temperature monitoring integrated system, a shaft and reservoir simulation system, a liquid supply and control system and a liquid collection system; the distributed optical fiber sound and temperature monitoring integrated system is connected with the shaft and the reservoir simulation system through an optical cable outside the pipe and an optical cable inside the pipe; a left fluid inlet and a right fluid inlet are symmetrically arranged on the axial outer walls of the shaft and the reservoir simulation system and are respectively connected with the liquid supply system; the liquid collection system is connected with the well bore and the reservoir simulation system through a liquid discharge pipeline. The utility model discloses realize that the production profile of simulation multilayer section straight well, horizontal well, multi-branch well and inclined shaft is continuous, real-time production liquid situation monitoring, can also simulate the temperature and the acoustic response condition of pit shaft production under different liquid measure, different moisture content, different temperature and the different production position condition, provide technical thought for the test of pit shaft production profile.

Description

Shaft production section monitoring simulation experiment device based on distributed optical fiber sound and temperature monitoring

Technical Field

The utility model relates to a pit shaft production section monitoring simulation experiment device and method based on distributed optical fiber sound, temperature monitoring belongs to the technical field of oil gas exploitation.

Background

With the improvement of the underground production control technology and the improvement of the refined production management requirement of the oil field, the real-time control of the production dynamics of each underground section becomes an important development direction of the precise and intelligent production of the oil field, and especially with the development of the intelligent well technology in recent years, the real-time understanding of the production profile of the shaft becomes more and more important for the real-time optimization of the oil deposit injection and production parameters and the real-time control of the production of each well section.

In the existing underground production profile testing technology, flow measuring instruments such as a turbine flowmeter, an ultrasonic flowmeter, an electromagnetic flowmeter, an electric conduction flowmeter and the like are commonly used to match with a flow collecting umbrella to test the flow of each layer section, and the water content of each layer section is tested by means of a capacitance method, a low-energy photon method and the like.

In recent years, with the development of distributed optical fiber temperature monitoring (DTS) and distributed optical fiber acoustic monitoring (DAS) technologies, an important means is provided for distributed and real-time monitoring of wellbore production profiles. The main principle of the DTS technology is to determine the temperature of the optical fiber medium at the location by using the reflection principle of the optical fiber and the temperature sensitivity of the reverse Roman scattering of the optical fiber, depending on the quantitative relationship between the temperature change around the optical fiber medium and the light propagating in the optical fiber. The DAS technology is mainly based on the principle of coherent optical time domain reflectometry, coherent short pulse laser is injected into an optical fiber, when external vibration acts on the optical fiber, due to the elasto-optical effect, the internal structure of the fiber core can be changed minutely, so that the back Rayleigh scattering signal changes, the received reflected light intensity changes, the underground event which is happening can be detected and accurately positioned by detecting the intensity change of the Rayleigh scattering light signals before and after the underground event, and the real-time monitoring of the underground dynamics is realized. The optical fiber has the characteristics of electromagnetic interference resistance, corrosion resistance, good real-time performance and the like, so that the optical fiber has greater superiority in the aspect of underground dynamic real-time monitoring.

Due to reservoir geothermal differences, oil-water thermal property differences, and oil-water density differences, different temperature differences and sonic velocity differences will be present when fluids of different flow rates and compositions flow from the reservoir into the wellbore and in the wellbore. The temperature difference and the sound velocity difference can be sensed by using a high-sensitivity and high-precision distributed optical fiber temperature and sound sensing technology, and a shaft production profile can be obtained by combining a corresponding mathematical model.

Therefore, it is especially necessary to establish a set of wellbore production profile monitoring simulation experiment device and method based on distributed optical fiber acoustic monitoring (DAS) and distributed optical fiber temperature monitoring (DTS) for theoretically researching wellbore production profile monitoring.

The application and development prospect of the distributed optical fiber sound sensing technology in the oil field published by the authors of liu zhong honor et al discloses that in the deep water oil and gas field development process, the characteristics and advantages of the technology in the aspect of real-time monitoring of a shaft are analyzed based on the working principle of the distributed optical fiber sound sensing technology and the field application conditions in the aspects of intelligent wells, gas lift wells, wax deposition, hydraulic fracturing and the like abroad, and the problem that the technology needs to be researched urgently in the aspects of data processing, quantitative analysis, standard sound database construction and the like is pointed out.

Wherein, record in the monitoring process of intelligent well production: because different sound signals are generated by the throttling effect, the on/off process and the working state of the ICV are monitored in real time by utilizing the sensitivity of the DAS technology to sound, and the flow of each well section/branch well is obtained in real time through sound velocity analysis, so that reliable data are provided for the real-time optimization of the production of the intelligent well.

Recording in the artificial lift system monitoring: the DAS technology monitors sounds including signals with different frequencies, different downhole events correspond to specific sound frequencies, and how to select the correct frequency to analyze the DAS sound signals to extract accurate downhole event information is one of the issues that needs to be studied.

In wellbore flow assurance monitoring it is documented that: the DAS technology can hear the deposition or flowing process of the solid substances in real time, has good timeliness, and has great application potential in the early warning and monitoring of shaft flowing guarantee.

In hydraulic fracture monitoring, it is documented that: by looking at the location and intensity of the sound when DAS technology is deployed in a frac well, the field engineer can be helped to determine the intervals and perforations of the imbibed fluids, proppants and their imbibition.

The document mentions: if the DAS technology and the DTS technology are combined, the fractured interval can be determined more accurately, and therefore reliable decision support is provided for fracturing construction.

This document merely discusses a review of the fields of application of DAS and DTS technology and does not refer to specific schemes, devices and methods of how DAS and DTS technology can be implemented in the respective fields of application.

SUMMERY OF THE UTILITY MODEL

Not enough to prior art, the utility model discloses a pit shaft production section monitoring simulation experiment device based on distributed optical fiber sound, temperature monitoring.

In order to achieve the above purpose, the utility model adopts the following technical scheme:

a shaft production section monitoring simulation experiment device based on distributed optical fiber sound and temperature monitoring is characterized by comprising:

the system comprises a distributed optical fiber sound and temperature monitoring integrated system 1, a shaft and reservoir simulation system 2, a liquid supply and control system 3 and a liquid collection system 4;

the distributed optical fiber sound and temperature monitoring integrated system 1 is connected with a shaft and a reservoir simulation system 2 through an external optical cable FO1 and an internal optical cable FO 2;

a left fluid inlet and a right fluid inlet are symmetrically arranged on the axial outer walls of the shaft and the reservoir simulation system 2 and are respectively connected with the liquid supply system 3; the liquid collection system 4 is connected with the reservoir simulation system 2 through a liquid discharge pipeline 301.

According to the utility model discloses it is preferred, distributed optical fiber sound, temperature monitoring integrated system 1 includes: a temperature signal receiver 105, an audio signal receiver 106, a laser light source 107, an outside optical cable FO1, an inside optical cable FO2, an outside optical cable audio signal optical fiber 1021, an outside optical cable temperature signal optical fiber 1022, an inside optical cable audio signal optical fiber 1031, an inside optical cable temperature signal optical fiber 1032, a computer data processing and display system 109, a temperature data communication line 1091, and an audio data communication line 1092;

one end of a high-sensitivity and high-precision single-mode sound sensing optical fiber in the external optical cable FO1 and the internal optical cable FO2 is respectively connected with the laser light source 107, and one end of a high-sensitivity and high-precision multi-mode temperature sensing optical fiber in the external optical cable FO1 and the internal optical cable FO2 is respectively connected with the laser light source 107 and serves as a laser signal input end;

the high-sensitivity and high-precision single-mode sound sensing optical fiber and the high-sensitivity and high-precision multi-mode temperature sensing optical fiber in the external optical cable FO1 and the internal optical cable FO2 are simultaneously used as signal transmission media, and reflected signals are transmitted to the sound signal receiver 106 through an external optical cable sound signal optical fiber line 1021 and an internal optical cable sound signal optical fiber line 1031 and are transmitted to the temperature signal receiver 105 through an external optical cable temperature signal optical fiber line 1022 and an internal optical cable temperature signal optical fiber line 1032 respectively; the computer data processing and display system 109 is connected to the temperature signal receiver 105 and the sound signal receiver 106 through a temperature data communication line 1091 and a sound data communication line 1092, respectively, processes the sound distribution data and the temperature distribution data along the outside fiber optic cable FO1 and the inside fiber optic cable FO2 obtained from the sound signal receiver 106 and the temperature signal receiver 105, performs monitoring data interpretation by using a built-in production profile interpretation module, and displays the flow and water cut distribution of each well section in the well bore in a graphic and data mode.

According to the utility model discloses preferred, production fluid section explanation module include data preprocessing module and production fluid section explanation module;

the data preprocessing module is used for obtaining denoised sound data and temperature data related to the flow of fluid entering a shaft in the production process, and comprises the following steps 1-1) -1-4):

1-1) processing sound data acquired in the monitoring process of the simulation production process by adopting a frequency-space deconvolution filter to obtain sound data without random peak noise;

1-2) using a band-pass filter to limit the frequency range of the acoustic data to the range of the impact energy of the fluid flowing into the wellbore, thereby eliminating extraneous noise signals in the data;

1-3) obtaining noise-removed sound data related to the flow of fluid entering a shaft in the production process;

1-4) processing the temperature data acquired in the monitoring process of the simulation production process by adopting a Pavel Holoborodko filtering method to obtain the temperature data with noise removed;

the fluid production profile interpretation module comprises: establishing a sound intensity coordinate system and generating a sound intensity waterfall graph, comprising the following steps:

2-1) establishing a sound intensity coordinate system, wherein the length of a simulated shaft is an abscissa, and the time for monitoring the sound of fluid flowing into the shaft is an ordinate;

2-2) drawing a sound intensity 'waterfall graph' in the sound intensity coordinate system by using sound data related to the flow of fluid entering a well bore in the simulation production process:

2-3) defining a fluid production interval:

because the positions of all production intervals in the simulated wellbore are known, namely the position range covered by the production intervals in the simulated wellbore is known, a curve of the sound intensity changing along with the length of the simulated wellbore at any moment is extracted from the position range covered by the production intervals on the sound intensity waterfall diagram, as shown by a solid line in fig. 4; making a horizontal line based on the minimum sound intensity value of the sound intensity variation curve along with the length of the simulated wellbore at any time extracted in the position range covered by the production interval, as shown by a dotted line in FIG. 4;

according to the position range covered by each production interval, calculating the area of a graph formed by a horizontal line based on the minimum sound intensity value and a curve of which the sound intensity changes along with the length of the simulated shaft in the position range covered by each production interval by adopting an area method;

then, the area variance is calculated: judging the production interval with the area of a graph formed by the curve corresponding to the production interval and the area variance larger than 1 time as a liquid production interval;

2-4) calculating the fluid flow rate of each fluid production interval:

performing inversion by using the denoised temperature data and sound data obtained by processing through the data preprocessing module and combining a temperature field mathematical model and a sound velocity field mathematical model of the shaft by adopting a Markov chain-Monte Carlo method, and calculating the flow and water content distribution of each fluid production interval in the shaft;

the mathematical model of the temperature field of the well bore is

Wherein,

is temperature gradient, DEG C/m; u shape_atIs the total heat transfer coefficient of heat exchange between the oil pipe and the annulus, W/(m)²·℃)；R_tiIs the inner diameter of the oil pipe, m; c. C_pIs the specific heat capacity of fluid in a shaft, J/(kg DEG C); k_JTIs the Joule-Thomson coefficient, DEG C/Pa; w is the fluid mass flow in the oil pipe, kg/s;

for a shaftPressure gradient, Pa/m; g is the acceleration of gravity, m/s²；h_lat，jj′Enthalpy of fluid in the annulus, kJ; w is a_aj′The fluid mass flow in the annulus is kg/s; rho_tj、ρ_tjCalculating the density of the fluid flowing into and out of the unit in the oil pipe in kg/m³；

The gradient of the dissolved gas-oil ratio in the oil pipe relative to the change of the pressure is obtained;

the well bore sound velocity field mathematical model is

c＝0.5(c₊+c_-) (2)

Wherein, c₊M is the speed of sound in the same direction of propagation of the sound wave as the direction of flow of the medium_s；c_-The sound velocity is m/s when the propagation direction of the sound wave is opposite to the flowing direction of the medium.

C is as described₊And c_{_}The method comprises the steps of obtaining a time-space domain sound intensity waterfall diagram after frequency-wave number domain conversion; according to c₊And c_{_}Calculating the flow rate of the fluid in the oil pipe by using the following formula

v＝0.5(c₊-c_-) (3)

Wherein v is the flow velocity of fluid in the oil pipe, m/s;

and calculating the flow of the fluid in the oil pipe according to the flow rate of the fluid in the oil pipe and the sectional area of the oil pipe.

According to the present invention, preferably, the water-containing data is calculated according to the sound velocity of the mixed fluid in the oil pipe and the joule-thomson coefficient when the fluid flows into the wellbore; the sound velocity of the mixed fluid in the oil pipe is calculated by adopting a formula (4); calculating the Joule-Thomson coefficient of the fluid flowing into the well bore by adopting a formula (5); the sum of the proportions of the phases in the mixed fluid is equal to 1, as shown in formula (6):

α_o+α_g+α_w＝1 (6)

wherein, c_mIs the mixed fluid sound velocity, m/s; c. C_oIs the oil phase sound velocity, m/s; c. C_wIs the water phase sound velocity, m/s; c. C_gIs the velocity of sound in the gas phase, m/s, α_oα is the oil phase ratio_wIn terms of water phase ratio, decimal fraction α_gGas phase ratio, decimal; rho_oIs the density of the oil phase, kg/m³；ρ_wAs density of the aqueous phase, kg/m³；ρ_gIs gas phase density, kg/m³(ii) a E is the Young's modulus of the pipe; t is the wall thickness of the tube, m; d is the inner diameter of the oil pipe, m; c. C_p，oThe specific heat capacity of the oil phase, J/(kg. DEG C); c. C_p，wIs the specific heat capacity of the water phase, J/(kg. DEG C); c. C_p，gSpecific heat capacity of gas phase, J/(kg. DEG C.); β_oThe thermal expansion coefficient of the oil phase is 1/DEG C β_wThe thermal expansion coefficient of the aqueous phase is 1/DEG C; t is_wellWell wall temperature, deg.C; z is a gas compression factor, decimal;

is the gradient of the compression factor as a function of the borehole wall temperature.

According to the utility model discloses it is preferred, pit shaft and reservoir simulation system 2 include: the casing string 11, the screen pipe string 22, the lower sealing plug 33, the upper sealing plug 44, the simulated reservoir rock body 108 and the movable joint 66; the sieve tube string 22 is sleeved inside the casing string 11, and a simulated reservoir rock body 108 is arranged in an annular space between the sieve tube string 22 and the casing string 11; the hollow space inside the screen string 22 forms a wellbore 101 for fluid flow;

the lower sealing plug 33 and the upper sealing plug 44 are respectively connected with the sleeve string 11 to play a role in sealing; the upper sealing plug 44 is provided with an upper sealing joint optical cable through hole 55 for allowing an optical cable FO1 outside the pipe to pass through into a space between the shaft and the simulated reservoir rock 108 and the screen string 22 of the reservoir simulation system 2; the movable joint 66 passes through the upper sealing plug 44 to be communicated with the shaft 101; the loose joint 66 is circumferentially provided with loose joint optical cable through holes 104;

the wellbore and reservoir simulation system 2 may be horizontally, vertically, or tilted to simulate a horizontal, vertical, or deviated well, respectively.

According to the utility model discloses preferentially, the optical cable FO1 outside the pipe enters the shaft and reservoir simulation system 2 through the upper sealed plug optical cable through hole 55, lays between simulation reservoir rock body 108 and screen pipe string 22, closely cooperates with simulation reservoir rock body 108 inner wall and screen pipe string 22 outer wall to simulate the permanent installation of distributed optical fiber outside the pipe and monitor reservoir fluid flow;

the optical fiber cable FO2 in the pipe passes through the movable optical fiber cable passing hole 104 to enter the shaft and reservoir simulation system 2 and is arranged in the shaft 101 space inside the screen pipe string 22 so as to simulate the temporary installation and monitoring of shaft fluid flow in the distributed optical fiber pipe; the out-of-pipe optical cable FO1 is arranged between the simulated reservoir rock body 108 and the screen pipe string 22 in a straight line mode, and the in-pipe optical cable FO2 is arranged in a straight line shape or a spiral shape in the space of the shaft 101 inside the screen pipe string 22; the in-line umbilical FO2 is deployed at the bottom, middle, upper portion of the wellbore 101 or anywhere in the wellbore 101 in the space of the wellbore 101 inside the screen string 22.

According to the present invention, preferably, the liquid discharge line 301 is connected to the movable joint 66; a drain control valve 302 is installed on the drain pipeline 301; controlling the back pressure applied to the wellbore and the reservoir simulation system 2 by adjusting the drainage control valve 302 to realize the production pressure difference adjustment of the wellbore and the reservoir simulation system 2; fluid flowing from the wellbore and reservoir simulation system 2 passes through the loose joint 66 and through the drain line 301 to the sump tank 304.

According to the utility model, the liquid supply and control system 3 preferably comprises a liquid supply group and a data acquisition and control system PC 10; as shown in FIG. 1, 3 sets of liquid supply 381, liquid supply 382, and liquid supply 383 are arranged; the liquid supply and control system 3 can comprise 1 group, 10 groups and 100 groups of liquid supply groups, and can also comprise any plurality of groups of liquid supply groups;

each liquid supply group 381 comprises a liquid storage tank, a variable frequency plunger pump and a gate valve group;

the gate valve group comprises a plurality of liquid supply pipes, each liquid supply pipe comprises a heater and two-way valves, and the two-way valves are respectively communicated with symmetrically arranged fluid inlets; the liquid supply pipe is also provided with a flow meter and a temperature and pressure integrated sensor. Taking the liquid supply group 381 as an example, a liquid storage tank G1 in the liquid supply group 381 is connected with a variable frequency plunger pump M91 through a liquid storage tank fluid outflow pipeline 91, the variable frequency plunger pump M91 is connected with a gate valve group C1 through a variable frequency plunger pump fluid outflow pipeline 911, a manual gate valve V1 on the gate valve group C1 is connected with a heater H1 through a gate valve fluid outflow pipeline 9111, the heater H1 is connected with a two-way valve W1 through a heater fluid outflow pipeline 91111, and the two-way valve W1 is respectively connected with a right fluid inlet B1 and a left fluid inlet a1 through a right fluid inflow pipeline L1 and a left fluid inflow pipeline L2; a manual gate valve V3 of the gate valve group C1 is connected to a heater H2 through a gate valve fluid outflow line 9112, the heater H2 is connected to a two-way valve W2 through a heater fluid outflow line 91112, and the two-way valve W2 is connected to a right fluid inlet B3 and a left fluid inlet A3 through a right fluid inflow line L3 and a left fluid inflow line L4, respectively; the variable-frequency plunger pump M91 is connected with a data acquisition and control system PC10 through a variable-frequency plunger pump signal control line KP 1; the flow meter R1 mounted on the gate valve fluid outflow line 9111 is connected to the data acquisition and control system PC10 via a flow meter signal line KH 2; the flow meter R2 mounted on the gate valve fluid outflow line 9112 is connected to the data acquisition and control system PC10 via a flow meter signal line KH 2; the integrated temperature and pressure sensor PT1 mounted on the heater fluid effluent line 91111 is connected to the data acquisition and control system PC10 by an integrated temperature and pressure sensor signal line KPT 1; a temperature and pressure integrated sensor PT2 mounted on the heater fluid outflow line 91112 is connected to a data acquisition and control system PC10 via a temperature and pressure integrated sensor signal line KPT 2.

The simulation experiment method for monitoring the production profile of the shaft when the single-phase fluid flows in from different layer sections is used for monitoring the multi-well section of the horizontal well of the homogeneous or heterogeneous reservoir stratum by using the simulation experiment device, and is characterized by comprising the following steps:

step 1: installing the monitoring simulation experiment device, arranging 6 in total linear and spiral 2 in-pipe optical cables FO2 at the same position at the bottom, middle and upper parts of the wellbore 101, respectively, arranging 1 out of linear outside optical cables FO1 outside the sieve tube, connecting optical fibers in the simulation experiment device, connecting pipelines of a feed liquid group 381, a feed liquid group 382 and a feed liquid group 383 in the simulation experiment device, connecting a two-way valve W1 in the feed liquid group 381 with a right fluid inlet B1 and a left fluid inlet A1 through a right fluid inflow pipeline L1 and a left fluid inflow pipeline L2, respectively, connecting a two-way valve W2 in the feed liquid group 381 with a right fluid inlet B3 and a left fluid inlet A3 through a right fluid inflow pipeline L3 and a left fluid inflow pipeline L4, respectively, connecting a two-way valve W3 in the feed liquid group 382 with a right fluid inlet B5 and a left fluid inlet A5 through a right fluid inflow pipeline L5 and a left fluid inflow pipeline L6, respectively, connecting the two-way valve W4 in the feed set 382 to the right fluid inlet B7 and the left fluid inlet a7 via a right fluid inflow line L7 and a left fluid inflow line L8, respectively, and connecting the two-way valve W5 in the feed set 383 to the right fluid inlet B19 and the left fluid inlet a19 via a right fluid inflow line L9 and a left fluid inflow line L10, respectively; the drain line 301 is put into a liquid collecting tank 304; adding a proper amount of single-phase simulated crude oil into the liquid storage tank G1, adding a proper amount of single-phase water into the liquid storage tank G2, and filling a proper amount of nitrogen into the liquid storage tank G3;

step 2: the inlet ends of a liquid storage tank fluid outflow pipeline 91, a liquid storage tank fluid outflow pipeline 92 and a liquid storage tank fluid outflow pipeline 93 are respectively connected to a four-way valve at the bottom of a liquid storage tank G1 so as to simulate the condition that each layer section produces oil;

and step 3: adjusting a drainage control valve 302, opening heaters W1, W2, W3, W4, W5 and variable-frequency plunger pumps M91, M92 and M93, manually adjusting manual gate valves V1, V3, V4, V5 and V8, opening flow meters R1, R2, R3, R4 and R5, and starting a data acquisition and control system PC 10; the data acquisition and control system PC10 is respectively provided with the temperatures of heaters W1, W2, W3, W4 and W5 and the frequencies of variable-frequency plunger pumps M91, M92 and M93; the temperatures of the heaters W1, W2, W3, W4 and W5 may be the same or different; the frequencies of the variable-frequency plunger pumps M91, M92 and M93 can be set to be the same or different;

and 4, step 4: turning on the temperature signal receiver 105 and the sound signal receiver 106, turning on the laser light source 107 and the computer data processing and display system 109;

and 5: after the temperature and pressure readings on the temperature and pressure integrated sensors PT1, PT2, PT3, PT4 and PT5 are stabilized, the temperature profile data and the sound profile data measured by the temperature signal receiver 105 and the sound signal receiver 106 are observed on the computer data processing and displaying system 109, and after the temperature profile data and the sound profile data are stabilized, the temperature profile data and the sound profile data are recorded;

step 6: processing and interpreting the acquired temperature and sound data by using a liquid production profile interpretation module arranged in the computer data processing and display system 109 to obtain the liquid production profile distribution of the horizontal well shaft; comparing and verifying the flow and water containing data obtained by interpreting the fluid production profile interpretation module with the data obtained by the flow meters R1, R2, R3, R4 and R5;

preferably, the method further comprises the step 7:

and 7: changing the frequency of the variable frequency plunger pumps M91, M92 and M93, and repeating the steps from 5 to 6 to obtain the liquid production profile distribution of the horizontal well shaft under different flow rates;

preferably, the method further comprises the step 8:

and 8: stopping the variable-frequency plunger pumps M91, M92 and M93, stopping the temperature signal receiver 105 and the sound signal receiver 106, stopping the laser light source 107, changing the connection positions of the left fluid inflow pipeline and the right fluid inflow pipeline in the liquid supply group 381, the liquid supply group 382 and the liquid supply group 383 and the left fluid inlet and the right fluid inlet so as to simulate the production process of reservoirs with different layer distances, and repeating the steps 3 to 7 to obtain the production profile distribution of the horizontal well shaft under the condition of different layer distances;

preferably, the method further comprises the step 9:

and step 9: stopping the variable frequency plunger pumps M91, M92 and M93, stopping the temperature signal receiver 105, the sound signal receiver 106 and the laser light source 107, and respectively connecting the inlet ends of the liquid storage tank fluid outflow pipeline 91, the liquid storage tank fluid outflow pipeline 92 and the liquid storage tank fluid outflow pipeline 93 to a four-way valve at the bottom of the liquid storage tank G2 so as to simulate the condition that each layer produces water; repeating the step 3 to the step 8 to obtain the distribution condition of the liquid production profile of the horizontal well shaft under the condition of uniform water production of each layer;

preferably, the method further comprises the step 10:

step 10: stopping the variable frequency plunger pumps M91, M92 and M93, stopping the temperature signal receiver 105, the sound signal receiver 106 and the laser light source 107, and respectively connecting the inlet ends of the liquid storage tank fluid outflow pipeline 91, the liquid storage tank fluid outflow pipeline 92 and the liquid storage tank fluid outflow pipeline 93 to a four-way valve at the bottom of the liquid storage tank G3 so as to simulate the condition that each layer generates gas; directly interfacing

reservoir fluid flowlines

91, 92, 93 and variable frequency plunger

pump fluid flowlines

911, 921, 931 across variable frequency plunger pumps M91, M92, M93, respectively; and (5) repeating the steps 3 to 8 to obtain the liquid production profile distribution condition of the horizontal well shaft under the condition that each layer generates gas.

The method for monitoring and simulating the production profile of the shaft when two single-phase fluids flow in from different layer sections in the multi-well section of the horizontal well of the homogeneous or heterogeneous reservoir stratum by using the simulation experiment device is characterized by comprising the following steps of:

step 2: the inlet ends of a liquid storage tank fluid outflow pipeline 91 and a liquid storage tank fluid outflow pipeline 93 are respectively connected to a four-way valve at the bottom of a liquid storage tank G1, and the inlet end of a liquid storage tank fluid outflow pipeline 92 is connected to a four-way valve at the bottom of a liquid storage tank G2, so that the conditions of water outflow of two layers and oil production of three layers are simulated;

preferably, the method further comprises step 7:

preferably, the method further comprises the step 8:

preferably, the method further comprises step 9:

and step 9: stopping the variable frequency plunger pumps M91, M92 and M93, stopping the temperature signal receiver 105, the sound signal receiver 106 and the laser light source 107, respectively connecting the inlet ends of the liquid storage tank fluid outflow pipeline 91 and the liquid storage tank fluid outflow pipeline 93 to the four-way valve at the bottom of the liquid storage tank G1, and connecting the inlet end of the liquid storage tank fluid outflow pipeline 92 to the four-way valve at the bottom of the liquid storage tank G3; directly butting the fluid outflow pipeline 92 of the liquid storage tank and the fluid outflow pipeline 921 of the variable frequency plunger pump across the variable frequency plunger pump M92 to simulate the conditions of gas production of two intervals and oil production of three intervals; repeating the steps 3 to 8 to obtain the liquid production profile distribution condition of the horizontal well shaft under the conditions of gas production of two intervals and oil production of three intervals;

preferably, the method further comprises the step 10:

step 10: stopping the variable frequency plunger pumps M91, M92 and M93, stopping the temperature signal receiver 105, the sound signal receiver 106 and the laser light source 107, respectively connecting the inlet ends of the liquid storage tank fluid outflow pipeline 91 and the liquid storage tank fluid outflow pipeline 93 to the four-way valve at the bottom of the liquid storage tank G2, and respectively connecting the inlet end of the liquid storage tank fluid outflow pipeline 92 to the four-way valve at the bottom of the liquid storage tank G3; directly butting the fluid outflow pipeline 92 of the liquid storage tank and the fluid outflow pipeline 921 of the variable frequency plunger pump across the variable frequency plunger pump M92 to generate gas in two intervals and generate water in three intervals; and (5) repeating the steps 3 to 8 to obtain the liquid production profile distribution condition of the horizontal well shaft under the conditions of gas production of two intervals and water production of three intervals.

The monitoring simulation experiment method for monitoring the production profile of the shaft when the single-phase fluid and the oil-water mixture flow in from different layer sections at the multi-well section of the horizontal well of the homogeneous or inhomogeneous reservoir stratum by using the simulation experiment device is characterized by comprising the following steps of:

step 1: installing the monitoring simulation experiment device, arranging 6 in total linear and spiral 2 in-pipe optical cables FO2 at the same position at the bottom, middle and upper parts of the wellbore 101, respectively, arranging 1 out of linear outside optical cables FO1 outside the sieve tube, connecting optical fibers in the simulation experiment device, connecting pipelines of a feed liquid group 381, a feed liquid group 382 and a feed liquid group 383 in the simulation experiment device, connecting a two-way valve W1 in the feed liquid group 381 with a right fluid inlet B1 and a left fluid inlet A1 through a right fluid inflow pipeline L1 and a left fluid inflow pipeline L2, respectively, connecting a two-way valve W2 in the feed liquid group 381 with a right fluid inlet B3 and a left fluid inlet A3 through a right fluid inflow pipeline L3 and a left fluid inflow pipeline L4, respectively, connecting a two-way valve W3 in the feed liquid group 382 with a right fluid inlet B5 and a left fluid inlet A5 through a right fluid inflow pipeline L5 and a left fluid inflow pipeline L6, respectively, connecting the two-way valve W4 in the feed set 382 to the right fluid inlet B7 and the left fluid inlet a7 via a right fluid inflow line L7 and a left fluid inflow line L8, respectively, and connecting the two-way valve W5 in the feed set 383 to the right fluid inlet B19 and the left fluid inlet a19 via a right fluid inflow line L9 and a left fluid inflow line L10, respectively; the drain line 301 is put into a liquid collecting tank 304; adding a proper amount of single-phase simulated crude oil into a liquid storage tank G1, adding a proper amount of single-phase water into a liquid storage tank G2, and adding a proper amount of oil-water mixture into a liquid storage tank G3;

step 2: respectively connecting the inlet ends of a liquid storage tank fluid outflow pipeline 91 and a liquid storage tank fluid outflow pipeline 93 to a four-way valve at the bottom of a liquid storage tank G1, and connecting the inlet end of a liquid storage tank fluid outflow pipeline 92 to a four-way valve at the bottom of a liquid storage tank G3 so as to simulate the conditions of oil and water mixture production of two layers and oil production of three layers;

preferably, the method further comprises step 7:

preferably, the method further comprises the step 8:

preferably, the method further comprises step 9:

and step 9: stopping the variable frequency plunger pumps M91, M92 and M93, stopping the temperature signal receiver 105, the sound signal receiver 106 and the laser light source 107, respectively connecting the inlet ends of the liquid storage tank fluid outflow pipeline 91 and the liquid storage tank fluid outflow pipeline 93 to a four-way valve at the bottom of the liquid storage tank G2, and connecting the inlet end of the liquid storage tank fluid outflow pipeline 92 to a four-way valve at the bottom of the liquid storage tank G3, so as to simulate the conditions of producing oil-water mixture in two intervals and producing water in three intervals; and (5) repeating the steps 3 to 8 to obtain the distribution condition of the production profile of the horizontal well shaft under the conditions that the oil-water mixture is produced in two intervals and the water is produced in three intervals.

The method for monitoring and simulating the production profile of the shaft when the multi-well section of the horizontal well of the homogeneous or heterogeneous reservoir stratum alternatively flows in from different layer sections by utilizing the simulation experiment device is characterized by comprising the following steps of:

step 2: the inlet ends of reservoir fluid outflow line 91, reservoir fluid outflow line 92 and reservoir fluid outflow line 93 are connected to a four-way valve at the bottom of reservoir G1, respectively;

preferably, the method further comprises step 7:

and 7: the inlet end of a fluid outflow pipeline 92 of the liquid storage tank is quickly connected to a four-way valve at the bottom of a liquid storage tank G2, and the inlet ends of the fluid outflow pipeline 91 of the liquid storage tank and a fluid outflow pipeline 93 of the liquid storage tank are kept unchanged from being connected with the four-way valve at the bottom of a liquid storage tank G1, so that the situation of water burst at the edge of a horizontal well or bottom water is simulated; repeating the step 5 to the step 6 to obtain the liquid production profile distribution of the side water or bottom water of the horizontal well which intrudes into the shaft;

preferably, the method further comprises the step 8:

and 8: changing the frequency of the variable frequency plunger pumps M91, M92 and M93, and repeating the steps from 5 to 7 to obtain the liquid production profile distribution of the horizontal well shaft under different flow rates;

preferably, the method further comprises step 9:

and step 9: stopping the variable-frequency plunger pumps M91, M92 and M93, stopping the temperature signal receiver 105 and the sound signal receiver 106, stopping the laser light source 107, changing the connection positions of the left fluid inflow pipeline and the right fluid inflow pipeline in the liquid supply group 381, the liquid supply group 382 and the liquid supply group 383 and the left fluid inlet and the right fluid inlet so as to simulate the production process of reservoirs with different layer distances, and repeating the steps 3 to 8 to obtain the production profile distribution of the horizontal well shaft under the condition of different layer distances;

preferably, the method further comprises the step 10:

step 10: the inlet end of a fluid outflow pipeline 92 of the liquid storage tank is quickly connected to a four-way valve at the bottom of a liquid storage tank G3, the connection between the inlet ends of the fluid outflow pipeline 91 of the liquid storage tank and a fluid outflow pipeline 93 of the liquid storage tank and the four-way valve at the bottom of a liquid storage tank G1 is kept unchanged, and the fluid outflow pipeline 92 of the liquid storage tank and a fluid outflow pipeline 921 of the variable frequency plunger pump are directly butted across a variable frequency plunger pump M92 so as to simulate the situation that gas of a; and (5) repeating the step (3) to the step (8) to obtain the liquid production profile distribution of the gas outburst wellbore of the horizontal well.

Compared with the prior art, the beneficial effects of the utility model reside in that:

1. shaft production section monitoring simulation experiment device based on distributed optical fiber sound, temperature monitoring can realize simulating the production section monitoring of multilayer section straight well, horizontal well, multilateral well and inclined shaft.

2. The device can also realize the monitoring of the continuous and real-time liquid production condition of the whole shaft.

3. The device can also simulate the temperature and the acoustic sound of pit shaft production under different liquid measure, different moisture content, different temperature and the different production position condition and answer the condition, provides technical thought for the pit shaft production section test in the actual production process.

Drawings

Fig. 1 is a schematic structural diagram of a wellbore production profile monitoring simulation experiment device based on distributed optical fiber sound and temperature monitoring according to the present invention;

FIG. 2 is a schematic cross-sectional view of an upper sealing plug I-I of the present invention;

FIG. 3 is a schematic sectional view of a wellbore and reservoir simulation system II-II of the present invention;

fig. 4 is a schematic diagram of a simulated wellbore production profile monitoring result monitored at a certain moment by the method of the present invention.

In fig. 1, 2, 3, 1, distributed fiber optic sound and temperature monitoring integrated system, 2, wellbore and reservoir simulation system, 3, liquid supply and control system, 4, liquid collection system, 101, wellbore, FO1, cable outside pipe, FO2, cable inside pipe, 104, loose joint cable through hole, 105, temperature signal receiver, 106, sound signal receiver, 107, laser light source, 108, simulated reservoir rock mass, 109, computer data processing and display system, 1091, DTS temperature data communication line, 1092, DAS sound data communication line, 1021, cable outside pipe sound signal fiber line, 1022, cable outside pipe temperature signal fiber line, 1031, cable inside pipe sound signal fiber line, 1032, cable inside pipe temperature signal fiber line, 11, casing string, 22, screen string, 33, lower seal plug, 44, upper seal plug, 55, upper seal plug fiber cable through hole, 66. a joint for activating collaterals;

a1, a2, A3, a4, a5, A6, a7, A8, a9, a18, a19, a20 are all left side fluid inlets;

b1, B2, B3, B4, B5, B6, B7, B8, B9, B18, B19, B20 are all right fluid inlets;

l1, L3, L5, L7, L9 are all right fluid inflow lines;

l2, L4, L6, L8, L10 are all left side fluid inflow lines;

301. a liquid drainage pipeline 302, a liquid drainage control valve 304 and a liquid collection tank;

381. 382, 383 are liquid supply groups respectively;

w1, W2, W3, W4 and W5 are two-way valves respectively;

PT1, PT2, PT3, PT4 and PT5 are temperature and pressure integrated sensors respectively;

h1, H2, H3, H4 and H5 are respectively heaters;

r1, R2, R3, R4 and R5 are flow meters respectively;

v1, V2, V3, V4, V5, V6, V7, V8 and V9 are manual gate valves respectively;

c1, C2 and C3 are gate valve sets respectively;

m91, M92 and M93 are variable frequency plunger pumps respectively;

g1, G2 and G3 are liquid storage tanks respectively; PC10, data acquisition and control system;

91. 92, 93 are fluid outflow pipelines of the liquid storage tank respectively;

911. 921, 931 are respectively variable frequency plunger pump fluid outflow lines;

9111. 9112, 9211, 9212, 9311 are gate valve fluid outflow lines, respectively;

91111. 91112, 92111, 92112, 93111 are heater fluid outflow lines, respectively; KPT1, KPT2, KPT3, KPT4, KPT5 are temperature and pressure integrated sensor signal lines respectively; KR1, KR2, KR3, KR4 and KR5 are respectively flow meter signal lines;

KH1, KH2, KH3, KH4 and KH5 are heater temperature control lines respectively;

KP1, KP2, KP3 are frequency conversion plunger pump signal control lines respectively.

Detailed Description

The present invention will be described in detail below with reference to the following examples and drawings, but is not limited thereto.

Examples 1,

A shaft production section monitoring simulation experiment device based on distributed optical fiber sound and temperature monitoring comprises:

The distributed optical fiber sound and temperature monitoring integrated system 1 comprises a temperature signal receiver 105, a sound signal receiver 106, a laser light source 107, an outside optical cable FO1, an inside optical cable FO2, an outside optical cable sound signal optical fiber line 1021, an outside optical cable temperature signal optical fiber line 1022, an inside optical cable sound signal optical fiber line 1031, an inside optical cable temperature signal optical fiber line 1032, a computer data processing and display system 109, a temperature data communication line 1091 and a sound data communication line 1092. The optical cable FO1 outside the tube is formed by armoring two optical fibers, namely a high-sensitivity and high-precision single-mode temperature sensing optical fiber and a high-sensitivity and high-precision multi-mode temperature sensing optical fiber, through a seamless stainless steel tube; the optical cable FO2 in the tube is formed by armoring two optical fibers, namely a high-sensitivity and high-precision single-mode temperature sensing optical fiber and a high-sensitivity and high-precision multi-mode temperature sensing optical fiber, through a seamless stainless steel tube; one end of a high-sensitivity and high-precision single-mode sound sensing optical fiber in the external optical cable FO1 and the internal optical cable FO2 is respectively connected with the laser light source 107, and one end of a high-sensitivity and high-precision multi-mode temperature sensing optical fiber in the external optical cable FO1 and the internal optical cable FO2 is respectively connected with the laser light source 107 and serves as a laser signal input end; the high-sensitivity and high-precision single-mode sound sensing optical fiber and the high-sensitivity and high-precision multi-mode temperature sensing optical fiber in the external optical cable FO1 and the internal optical cable FO2 are simultaneously used as signal transmission media, and reflected signals are transmitted to the sound signal receiver 106 through an external optical cable sound signal optical fiber line 1021 and an internal optical cable sound signal optical fiber line 1031 and are transmitted to the temperature signal receiver 105 through an external optical cable temperature signal optical fiber line 1022 and an internal optical cable temperature signal optical fiber line 1032 respectively; the computer data processing and display system 109 is respectively connected with the temperature signal receiver 105 and the sound signal receiver 106 through a temperature data communication line 1091 and a sound data communication line 1092, processes sound distribution data and temperature distribution data which are obtained from the sound signal receiver 106 and the temperature signal receiver 105 and are along the outside optical cable FO1 and the inside optical cable FO2, utilizes a built-in production profile interpretation module to interpret monitoring data, and displays the liquid amount and water content distribution of each well section in the shaft in a graph and data mode;

The fluid production profile interpretation module comprises a data preprocessing module and a fluid production profile interpretation module;

2-3) defining a fluid production interval:

2-4) calculating the fluid flow rate of each fluid production interval:

the mathematical model of the temperature field of the well bore is

Wherein,

is the pressure gradient of the shaft, Pa/m; g is the acceleration of gravity, m/s²；h_lat，jj′Enthalpy of fluid in the annulus, kJ; w is a_aj′For fluid mass flow in annulusAmount, kg/s; rho_tj、ρ_tj′For calculating the density of the fluid flowing into and out of the unit in the tubing, kg/m³；

the well bore sound velocity field mathematical model is

c＝0.5(c₊+c_-) (2)

Wherein, c₊The sound velocity is the sound velocity m/s when the sound wave propagation direction is the same as the medium flowing direction; c. C_{_}The sound velocity is m/s when the propagation direction of the sound wave is opposite to the flowing direction of the medium.

v＝0.5(c₊-c_{_}) (3)

Wherein v is the flow velocity of fluid in the oil pipe, m/s;

The water-containing data is obtained by calculation according to the sound velocity of mixed fluid in the oil pipe and the Joule-Thomson coefficient when the fluid flows into the shaft; the sound velocity of the mixed fluid in the oil pipe is calculated by adopting a formula (4); calculating the Joule-Thomson coefficient of the fluid flowing into the well bore by adopting a formula (5); the sum of the proportions of the phases in the mixed fluid is equal to 1, as shown in formula (6):

α_o+α_g+α_w＝1 (6)

wherein,c_mis the mixed fluid sound velocity, m/s; c. C_oIs the oil phase sound velocity, m/s; c. C_wIs the water phase sound velocity, m/s; c. C_gIs the velocity of sound in the gas phase, m/s, α_oα is the oil phase ratio_wIn terms of water phase ratio, decimal fraction α_gGas phase ratio, decimal; rho_oIs the density of the oil phase, k_g/m³；ρ_wIs the density of the aqueous phase, k_g/m³；ρ_gIs gas phase density, k_g/m³(ii) a E is the Young's modulus of the pipe; t is the wall thickness of the tube, m; d is the inner diameter of the oil pipe, m; c. C_p，oThe specific heat capacity of the oil phase, J/(kg. DEG C); c. C_p，wIs the specific heat capacity of the water phase, J/(kg. DEG C); c. C_p，gSpecific heat capacity of gas phase, J/(kg. DEG C.); β_oThe thermal expansion coefficient of the oil phase is 1/DEG C β_wThe thermal expansion coefficient of the aqueous phase is 1/DEG C; t is_wellWell wall temperature, deg.C; z is a gas compression factor, decimal;

The optical cable FO1 outside the pipe enters the shaft and reservoir simulation system 2 through the upper sealing plug optical cable through the hole 55, is arranged between the simulated reservoir rock body 108 and the sieve tube string 22 and is tightly matched with the inner wall of the simulated reservoir rock body 108 and the outer wall of the sieve tube string 22 so as to simulate the flow of reservoir fluid permanently installed and monitored outside the distributed optical fiber pipe; the optical fiber cable FO2 in the pipe passes through the movable optical fiber cable passing hole 104 to enter the shaft and reservoir simulation system 2 and is arranged in the shaft 101 space inside the screen pipe string 22 so as to simulate the temporary installation and monitoring of shaft fluid flow in the distributed optical fiber pipe; the out-of-pipe optical cable FO1 is arranged between the simulated reservoir rock body 108 and the screen string 22 in a straight line mode, and the in-pipe optical cable FO2 can be arranged in a straight line shape or a spiral shape in the space of the shaft 101 inside the screen string 22; the in-line umbilical FO2 may be deployed at the bottom, middle, upper portion of the wellbore 101 or anywhere in the wellbore 101 in the space in the wellbore 101 inside the screen string 22.

The shaft and reservoir simulation system 2 consists of a casing string 11, a screen pipe string 22, a lower sealing plug 33, an upper sealing plug 44, a simulated reservoir rock body 108 and an adjustable joint 66; 20 left fluid inlets A1-A20 and 20 right fluid inlets B1-B20 are symmetrically arranged on the casing string 11 to simulate the flow of fluid into the wellbore 101 from different layers; as shown in fig. 1, left fluid inlets a1, a2, A3, a4, a5, A6, a7, A8, a9, a18, a19, a20 and right fluid inlets B1, B2, B3, B4, B5, B6, B7, B8, B9, B18, B19, B20 are arranged; the positions of the 20 left fluid inlets A1-A20 and the positions of the 20 right fluid inlets B1-B20 are in one-to-one correspondence, and one left fluid inlet and one right fluid inlet which are in the corresponding positions form 1 group of liquid supply channels, so that 20 groups of symmetrical liquid supply channels are provided for the simulated reservoir rock mass 108; the distance between the 20 groups of liquid supply channels can be equal or unequal; the distance between the 20 groups of liquid supply channels can be 1 meter, 2 meters and 5 meters, and can also be any meter; the liquid supply channels can be 1 group, 10 groups and 100 groups, and can also be any multiple groups; the liquid supply channels on the sleeve string 11 can be linearly arranged along the circumferential direction of the sleeve string 11, and can also be spirally arranged at any angle; the shaft and reservoir simulation system 2 can be horizontally placed, vertically placed or obliquely placed so as to respectively simulate a horizontal well, a vertical well or an inclined well; the sleeve string 11 is formed by connecting steel pipes with different lengths, equal inner diameters and equal wall thicknesses in a sealing manner through interpolation; the total length of the casing string 11 can be 10 meters, 20 meters and 50 meters, and can also be adjusted between 10 meters and 50 meters;

the sieve tube string 22 is formed by connecting equal-diameter hollow slotted steel tubes with different lengths in an inserting and sealing manner; the length of the sieve tube string 22 is equal to that of the sleeve string 11; the outer diameter of the sieve tube string 22 is smaller than the inner diameter of the casing string 11 and is arranged in the casing string 11, and the simulated reservoir rock 108 is distributed in an annular space between the sieve tube string 22 and the casing string 11; the hollow space inside the screen string 22 forms a wellbore 101 for fluid flow;

the simulated reservoir rock body 108 is a hollow cylinder, and a channel for penetrating through an external optical cable FO1 is preset in the axial direction of the inner wall of the hollow cylinder; the inner wall of the simulated reservoir rock body 108 and the outer wall of the sieve tube string 22 and the outer wall of the simulated reservoir rock body 108 and the inner wall of the sleeve string 11 can be tightly matched, and a certain gap can be reserved to simulate the interlayer fluid channeling condition; the simulated reservoir rock 108 may be an integral cemented model, sintered model or 3D printed model, or may be formed by splicing a plurality of segmented cemented models, sintered models or 3D printed models; the permeability of the simulated reservoir rock mass 108 can be uniformly distributed with equal permeability or non-uniform distribution with unequal permeability along the axial direction; under the condition of unequal permeability and non-uniform distribution, each permeability section can be equal in length or unequal in length; the total length of the simulated reservoir rock body 108, the total length of the screen string 22 and the total length of the casing string 11 are equal;

the lower sealing plug 33 is connected with the lower end of the sleeve string 11 in a threaded connection mode to play a role in sealing; the upper sealing plug 44 is connected with the upper end of the sleeve string 11 in a threaded connection mode to play a role in sealing; the upper sealing plug 44 is provided with an upper sealing joint optical cable through hole 55 for allowing an optical cable FO1 outside the pipe to pass through into a space between the shaft and the simulated reservoir rock 108 and the screen string 22 of the reservoir simulation system 2; the movable joint 66 passes through the upper sealing plug 44 to be communicated with the shaft 101; 8 optical cable penetrating holes 104 of the loose joint are arranged at equal intervals in the circumferential direction of the loose joint 66, so that optical cables in different packaging modes and different arrangement modes can penetrate through and enter the shaft 101 to evaluate the response conditions of the optical cables in different packaging modes and different arrangement modes to temperature and sound;

after the casing string 11 is tightly screwed and sealed by the lower sealing plug 33 and the upper sealing plug 44, the screen string 22, the simulated reservoir rock 108 in the annular space of the screen string 22 and the casing string 11 are squeezed, and a closed shaft and reservoir simulation system 2 is formed; the casing string 11, the screen string 22, the lower sealing plug 33, the upper sealing plug 44, the movable joint 66 and the simulated reservoir rock body 108 are on the same coaxial line.

The liquid discharge pipeline 301 is connected with the movable joint 66; a drain control valve 302 is installed on the drain pipeline 301; controlling the back pressure applied to the wellbore and the reservoir simulation system 2 by adjusting the drainage control valve 302 to realize the production pressure difference adjustment of the wellbore and the reservoir simulation system 2; fluid flowing from the wellbore and reservoir simulation system 2 passes through the movable joint 66 and enters the fluid collection tank 304 through the drainage line 301;

the liquid supply and control system 3 consists of a

liquid supply group

381, 382 and 383 and a data acquisition and control system PC 10; as shown in FIG. 1, 3 sets of liquid supply 381, liquid supply 382, and liquid supply 383 are arranged; the liquid supply and control system 3 may include 1, 10, 100 liquid supply sets, or any number of liquid supply sets.

The liquid supply and control system 3 comprises a liquid supply group and a data acquisition and control system PC 10; as shown in FIG. 1, 3 sets of liquid supply 381, liquid supply 382, and liquid supply 383 are arranged; the liquid supply and control system 3 can comprise 1 group, 10 groups and 100 groups of liquid supply groups, and can also comprise any plurality of groups of liquid supply groups;

the gate valve group comprises a plurality of liquid supply pipes, each liquid supply pipe comprises a heater and two-way valves, and the two-way valves are respectively communicated with symmetrically arranged fluid inlets; the liquid supply pipe is also provided with a flow meter and a temperature and pressure integrated sensor. The liquid supply group 381 is composed of a liquid storage tank G1, a variable-frequency plunger pump M91, a gate valve group C1, a heater H1, a heater H2, a two-way valve W1, a two-way valve W2, a temperature and pressure integrated sensor PT1, a temperature and pressure integrated sensor PT2, a flow meter R1 and a flow meter R2; the gate valve group C1 comprises a manual gate valve V1, a manual gate valve V2 and a manual gate valve V3; the gate valve group C1 may include 1, 10, 100 manual gate valves, or any number of manual gate valves;

a liquid storage tank G1 in the liquid supply group 381 is connected with a variable-frequency plunger pump M91 through a liquid storage tank fluid outflow pipeline 91, the variable-frequency plunger pump M91 is connected with a gate valve group C1 through a variable-frequency plunger pump fluid outflow pipeline 911, a manual gate valve V1 on the gate valve group C1 is connected with a heater H1 through a gate valve fluid outflow pipeline 9111, the heater H1 is connected with a two-way valve W1 through a heater fluid outflow pipeline 91111, and the two-way valve W1 is respectively connected with a right fluid inlet B1 and a left fluid inlet A1 through a right fluid inflow pipeline L1 and a left fluid inflow pipeline L2; a manual gate valve V3 of the gate valve group C1 is connected to a heater H2 through a gate valve fluid outflow line 9112, the heater H2 is connected to a two-way valve W2 through a heater fluid outflow line 91112, and the two-way valve W2 is connected to a right fluid inlet B3 and a left fluid inlet A3 through a right fluid inflow line L3 and a left fluid inflow line L4, respectively; the variable-frequency plunger pump M91 is connected with a data acquisition and control system PC10 through a variable-frequency plunger pump signal control line KP 1; the flow meter R1 mounted on the gate valve fluid outflow line 9111 is connected to the data acquisition and control system PC10 via a flow meter signal line KH 2; the flow meter R2 mounted on the gate valve fluid outflow line 9112 is connected to the data acquisition and control system PC10 via a flow meter signal line KH 2; the integrated temperature and pressure sensor PT1 mounted on the heater fluid effluent line 91111 is connected to the data acquisition and control system PC10 by an integrated temperature and pressure sensor signal line KPT 1; a temperature and pressure integrated sensor PT2 mounted on the heater fluid outflow line 91112 is connected with a data acquisition and control system PC10 through a temperature and pressure integrated sensor signal line KPT 2;

as shown in fig. 1, the gate valve fluid outflow line 9111 is arranged to be connected to a manual gate valve V1 on gate valve set C1, and the gate valve fluid outflow line 9112 is connected to a manual gate valve V3 on gate valve set C1; the gate valve fluid outflow pipelines connected with the manual gate valves on the gate valve group C1 can be 1, 10 or 100, or any number of the gate valve fluid outflow pipelines, and each 1 gate valve fluid outflow pipeline is only connected with 1 manual gate valve on the gate valve group C1;

as shown in fig. 1, the right fluid inflow line L1 and the left fluid inflow line L2 are connected to the right fluid inlet B1 and the left fluid inlet a1, respectively, or the right fluid inflow line L1 and the left fluid inflow line L2 are connected to the left fluid inlet a1 and the right fluid inlet B1, respectively, and the right fluid inlet B1 and the left fluid inlet a1 form the group 1 liquid supply channel; the right fluid inflow line L1 and the left fluid inflow line L2 may be connected to other sets of feed channels, but only 1 feed channel at a time;

the fluid stored in the liquid storage tank G1 in the liquid supply group 381 enters the variable-frequency plunger pump M91 through a liquid storage tank fluid outflow pipeline 91, and flows into the gate valve group C1 from a variable-frequency plunger pump fluid outflow pipeline 911 after being pressurized and flow-regulated by the variable-frequency plunger pump M91; the flow rate and pressure of the fluid flowing from the manual gate valve V1 and the manual gate valve V3 into the gate valve fluid outflow line 9111 and the gate valve fluid outflow line 9112, respectively, are controlled by adjusting the opening degrees of the manual gate valve V1 and the manual gate valve V3 on the gate valve group C1; fluid flowing from the gate valve fluid outflow line 9111 enters heater H1 for heating to simulate reservoir fluid at different temperatures; the heated fluid enters the two-way valve W1 through the heater fluid outflow line 91111, and the fluid flows through the right fluid inlet line L1 and the left fluid inlet line L2 connected to the two-way valve W1, respectively, through the right fluid inlet B1 and the left fluid inlet a1 into the simulated reservoir rock 108; after flowing through the simulated reservoir rock 108, the fluid enters the wellbore 101 through the screen string 22 and then flows into the reservoir 304 through a drainage line connected with the movable joint 66; the heating temperature of the heater H1 is automatically controlled by a data acquisition and control system PC10 through a heater temperature control line KH 1; the data acquisition and control system PC10 acquires the temperature and pressure data of the fluid flowing out of the heater H1 from the temperature and pressure integrated sensor PT1 in real time through a temperature and pressure integrated sensor signal line KPT1 and acquires the flow data of the fluid flowing out of the manual gate valve V1 from the flow meter R1 in real time through a flow meter signal line KH 1; fluid flowing from the gate valve fluid outflow line 9112 enters the heater H2 for heating to simulate reservoir fluid at different temperatures; the heated fluid enters the two-way valve W1 through the heater fluid outflow line 91112, and the fluid enters the simulated reservoir rock mass 108 through the right fluid inlet B3 and the left fluid inlet a3, respectively, through the right fluid inflow line L3 and the left fluid inflow line L4 connected to the two-way valve W1; after flowing through the simulated reservoir rock 108, the fluid enters the wellbore 101 through the screen string 22 and then flows into the reservoir 304 through a drainage line connected with the movable joint 66; the heating temperature of the heater H2 is automatically controlled by a data acquisition and control system PC10 through a heater temperature control line KH 2; the data acquisition and control system PC10 acquires the temperature and pressure data of the fluid flowing out of the heater H2 in real time from the temperature and pressure integrated sensor PT2 through a temperature and pressure integrated sensor signal line KPT 2; the data acquisition and control system PC10 acquires the flow data of the fluid flowing out of the manual gate valve V3 from the flow meter R2 in real time through a flow meter signal line KH 2; the running frequency of the variable frequency plunger pump M91 is controlled by the data acquisition and control system PC10 through a variable frequency plunger pump signal control line KP 1.

The fluid stored in the liquid storage tanks G1, G2 and G3 can be single-phase oil, single-phase water, single-phase gas or oil-water two-phase mixture; four-way valves are arranged at the bottoms of the liquid storage tanks G1, G2 and G3 and can be respectively and independently or simultaneously connected with a liquid storage tank fluid outflow pipeline 91, a liquid storage tank fluid outflow pipeline 92 and a liquid storage tank fluid outflow pipeline 93;

the fluid collected in the collection tank 304 may be single phase oil, single phase water, single phase gas or oil-water two phase mixture, oil-gas two phase mixture or gas-water two phase mixture.

Examples 2,

The simulation experiment method for monitoring the production profile of the shaft when the single-phase fluid flows in from different layer sections is used for monitoring the multi-well sections of the horizontal well of the homogeneous or heterogeneous reservoir by using the simulation experiment device, and comprises the following steps:

the simulation experiment device designed by the utility model shown in fig. 1 simulates 5 fluid inflow well sections, but the utility model is not limited to simulating 5 fluid inflow well sections,

step 1: installation the monitoring simulation experiment device, simulation reservoir rock body 108 is homogeneous model or inhomogeneous model, arrange 2 intraductal optical cables FO2 of straight line shape and spiral shape respectively in the same position on pit shaft 101 bottom, middle part and upper portion and count 6 totally, arrange the outside optical cable FO1 of straight line shape and count 1 totally outside the screen pipe, connect the optic fibre in this simulation experiment device, connect the pipeline of confession liquid group 381, confession liquid group 382, confession liquid group 383 in this simulation experiment device, will supply two-way valve W1 in liquid group 381 to pass through right side fluid inflow pipeline L1 and left side fluid inflow pipeline L2 and be connected with right side fluid entry B1 and left side fluid entry A1 respectively, will supply two-way valve W2 in liquid group 381 to pass through right side fluid inflow pipeline L3 and left side fluid inflow pipeline L4 and be connected with right side fluid entry B3 and left side fluid entry A3 respectively, will supply two-way valve W3 in liquid group 382 to pass through right side fluid inflow pipeline L5 and left side fluid inflow pipeline L35 6 and left side fluid inflow pipeline L387L 5 and flow with right side The body inlet B5 and the left fluid inlet a5 are connected, the two-way valve W4 in the feed set 382 is connected to the right fluid inlet B7 and the left fluid inlet a7 through the right fluid inflow line L7 and the left fluid inflow line L8, respectively, and the two-way valve W5 in the feed set 383 is connected to the right fluid inlet B19 and the left fluid inlet a19 through the right fluid inflow line L9 and the left fluid inflow line L10, respectively; the drain line 301 is put into a liquid collecting tank 304; adding a proper amount of single-phase simulated crude oil into the liquid storage tank G1, adding a proper amount of single-phase water into the liquid storage tank G2, and filling a proper amount of nitrogen into the liquid storage tank G3;

reservoir fluid flowlines

91, 92, 93 and variable frequency plunger

pump fluid flowlines

Examples 3,

The monitoring simulation experiment method for monitoring the production profile of the shaft when two single-phase fluids flow in from different layer sections in the multi-well section of the horizontal well of the homogeneous or heterogeneous reservoir by using the simulation experiment device comprises the following steps:

step 1: installing the monitoring simulation experiment device, wherein the simulated reservoir rock body 108 is a homogeneous or heterogeneous model, 6 optical cables FO2 in 2 inner pipes in a straight line shape and a spiral shape are respectively arranged at the same positions of the bottom part, the middle part and the upper part of the shaft 101, 1 optical cable FO1 outside the straight line shape is arranged outside a sieve pipe, an optical fiber in the simulation experiment device is connected, pipelines of a liquid supply group 381, a liquid supply group 382 and a liquid supply group 383 in the simulation experiment device are connected, a two-way valve W1 in the liquid supply group 381 is respectively connected with a right fluid inlet B1 and a left fluid inlet A1 through a right fluid inflow pipeline L1 and a left fluid inflow pipeline L2, a two-way valve W2 in the liquid supply group 381 is respectively connected with a right fluid inlet B3 and a left fluid inlet A3 through a right fluid inflow pipeline L3 and a left fluid inflow pipeline L4, a two-way valve W3 in the liquid supply group 382 is respectively connected with a right fluid inlet B3 and a left fluid inlet A3 through a right fluid inflow pipeline L5 and a left fluid inflow pipeline A fluid inlet a5, connecting the two-way valve W4 in the feed set 382 with a right fluid inlet B7 and a left fluid inlet a7 via a right fluid inflow line L7 and a left fluid inflow line L8, respectively, and connecting the two-way valve W5 in the feed set 383 with a right fluid inlet B19 and a left fluid inlet a19 via a right fluid inflow line L9 and a left fluid inflow line L10, respectively; the drain line 301 is put into a liquid collecting tank 304; adding a proper amount of single-phase simulated crude oil into the liquid storage tank G1, adding a proper amount of single-phase water into the liquid storage tank G2, and filling a proper amount of nitrogen into the liquid storage tank G3;

Examples 4,

The monitoring simulation experiment method for monitoring the production profile of the shaft when the single-phase fluid and the oil-water mixture flow in from different layer sections in the multi-well section of the horizontal well of the homogeneous or inhomogeneous reservoir stratum by using the simulation experiment device comprises the following steps:

the simulation experiment device designed by the utility model shown in fig. 1 simulates 5 fluid inflow well sections as an example, but the utility model is not limited to simulating 5 fluid inflow well sections;

step 1: installing the monitoring simulation experiment device, wherein the simulated reservoir rock body 108 is a homogeneous or heterogeneous model, 6 optical cables FO2 in 2 inner pipes in a straight line shape and a spiral shape are respectively arranged at the same positions of the bottom part, the middle part and the upper part of the shaft 101, 1 optical cable FO1 outside the straight line shape is arranged outside a sieve pipe, an optical fiber in the simulation experiment device is connected, pipelines of a liquid supply group 381, a liquid supply group 382 and a liquid supply group 383 in the simulation experiment device are connected, a two-way valve W1 in the liquid supply group 381 is respectively connected with a right fluid inlet B1 and a left fluid inlet A1 through a right fluid inflow pipeline L1 and a left fluid inflow pipeline L2, a two-way valve W2 in the liquid supply group 381 is respectively connected with a right fluid inlet B3 and a left fluid inlet A3 through a right fluid inflow pipeline L3 and a left fluid inflow pipeline L4, a two-way valve W3 in the liquid supply group 382 is respectively connected with a right fluid inlet B3 and a left fluid inlet A3 through a right fluid inflow pipeline L5 and a left fluid inflow pipeline A fluid inlet a5, connecting the two-way valve W4 in the feed set 382 with a right fluid inlet B7 and a left fluid inlet a7 via a right fluid inflow line L7 and a left fluid inflow line L8, respectively, and connecting the two-way valve W5 in the feed set 383 with a right fluid inlet B19 and a left fluid inlet a19 via a right fluid inflow line L9 and a left fluid inflow line L10, respectively; the drain line 301 is put into a liquid collecting tank 304; adding a proper amount of single-phase simulated crude oil into a liquid storage tank G1, adding a proper amount of single-phase water into a liquid storage tank G2, and adding a proper amount of oil-water mixture into a liquid storage tank G3;

Example 5

and step 9: the inlet end of a fluid outflow pipeline 92 of the liquid storage tank is quickly connected to a four-way valve at the bottom of a liquid storage tank G3, the connection between the inlet ends of the fluid outflow pipeline 91 of the liquid storage tank and a fluid outflow pipeline 93 of the liquid storage tank and the four-way valve at the bottom of a liquid storage tank G1 is kept unchanged, and the fluid outflow pipeline 92 of the liquid storage tank and a fluid outflow pipeline 921 of the variable frequency plunger pump are directly butted across a variable frequency plunger pump M92 so as to simulate the situation that gas of a; and (5) repeating the step (3) to the step (8) to obtain the liquid production profile distribution of the gas outburst wellbore of the horizontal well.

The utility model discloses utilize monitoring simulation experiment device is not limited to horizontal wellbore, still is applicable to the simulation of various production wells such as vertical shaft, multilateral well and inclined shaft, and monitoring method corresponds as embodiment 2-4 and shows.

Claims

1. A shaft production section monitoring simulation experiment device based on distributed optical fiber sound and temperature monitoring is characterized by comprising:

the system comprises a distributed optical fiber sound and temperature monitoring integrated system (1), a shaft and reservoir simulation system (2), a liquid supply and control system (3) and a liquid collection system (4);

the distributed optical fiber sound and temperature monitoring integrated system (1) is connected with a shaft and a reservoir simulation system (2) through an external optical cable (FO1) and an internal optical cable (FO 2);

a left fluid inlet and a right fluid inlet are symmetrically arranged on the axial outer wall of the shaft and the reservoir simulation system (2) and are respectively connected with the liquid supply and control system (3); the liquid collection system (4) is connected with the shaft and the reservoir simulation system (2) through a liquid discharge pipeline (301).

2. The distributed optical fiber sound and temperature monitoring-based wellbore production profile monitoring simulation experiment device according to claim 1, wherein the distributed optical fiber sound and temperature monitoring integrated system (1) comprises: the temperature signal receiver (105), the sound signal receiver (106), the laser light source (107), the out-of-tube optical cable (FO1), the in-tube optical cable (FO2), the out-of-tube optical cable sound signal optical fiber line (1021), the out-of-tube optical cable temperature signal optical fiber line (1022), the in-tube optical cable sound signal optical fiber line (1031), the in-tube optical cable temperature signal optical fiber line (1032), the computer data processing and display system (109), the temperature data communication line (1091) and the sound data communication line (1092);

one end of a high-sensitivity and high-precision single-mode sound sensing optical fiber in the external optical cable (FO1) and one end of a high-sensitivity and high-precision multi-mode temperature sensing optical fiber in the internal optical cable (FO2) are respectively connected with the laser light source (107), and one end of a high-sensitivity and high-precision multi-mode temperature sensing optical fiber in the external optical cable (FO1) and the internal optical cable (FO2) are respectively connected with the laser light source (107) and serve as laser signal input ends;

the high-sensitivity and high-precision single-mode sound sensing optical fiber and the high-sensitivity and high-precision multi-mode temperature sensing optical fiber in the external optical cable (FO1) and the internal optical cable (FO2) are simultaneously used as signal transmission media, and reflected signals are transmitted to the sound signal receiver (106) through an external optical cable sound signal optical fiber line (1021) and an internal optical cable sound signal optical fiber line (1031) and are transmitted to the temperature signal receiver (105) through an external optical cable temperature signal optical fiber line (1022) and an internal optical cable temperature signal optical fiber line (1032); the computer data processing and display system (109) is respectively connected with the temperature signal receiver (105) and the sound signal receiver (106) through a temperature data communication line (1091) and a sound data communication line (1092), sound distribution data and temperature distribution data along the outside optical cable (FO1) and the inside optical cable (FO2) obtained from the sound signal receiver (106) and the temperature signal receiver (105) are processed, monitoring data interpretation is carried out by using a built-in production fluid profile interpretation module, and flow and water containing distribution of each well section in the shaft are displayed in a graphical and data mode.

3. The distributed optical fiber sound and temperature monitoring based wellbore production profile monitoring simulation experiment device as claimed in claim 1, wherein the wellbore and reservoir simulation system (2) comprises: the device comprises a casing string (11), a screen pipe string (22), a lower sealing plug (33), an upper sealing plug (44), a simulated reservoir rock mass (108) and an adjustable joint (66); the sieve tube string (22) is sleeved inside the casing string (11), and a simulated reservoir rock mass (108) is distributed in an annular space between the sieve tube string (22) and the casing string (11); the hollow space inside the screen pipe string (22) forms a well shaft (101) for fluid to flow;

the lower sealing plug (33) and the upper sealing plug (44) are respectively connected with the sleeve string (11) to play a role in sealing; the upper sealing plug (44) is provided with an upper sealing plug optical cable passing hole (55) for allowing an external optical cable (FO1) to pass through into a space between a shaft and a simulated reservoir rock body (108) and a screen pipe string (22) of the reservoir simulation system (2); the movable joint (66) penetrates through the upper sealing plug (44) to be communicated with the shaft (101); the loose joint (66) is circumferentially provided with loose joint optical cable through holes (104).

4. The distributed optical fiber sound and temperature monitoring-based wellbore production profile monitoring simulation experiment device is characterized in that the optical fiber cable outside the pipe (FO1) enters the wellbore and reservoir simulation system (2) through the upper seal plug optical cable through the hole (55), is arranged between the simulated reservoir rock mass (108) and the screen string (22), and is tightly matched with the inner wall of the simulated reservoir rock mass (108) and the outer wall of the screen string (22) to simulate the flow of reservoir fluid permanently installed and monitored outside the distributed optical fiber pipe;

the optical cable in the pipe (FO2) passes through the movable joint optical cable passing hole (104) to enter a shaft and reservoir simulation system (2) and is arranged in a shaft (101) space inside the screen pipe string (22) so as to simulate the temporary installation in the distributed optical fiber pipe to monitor the shaft fluid flow; the optical cable outside the pipe (FO1) is arranged between the simulated reservoir rock body (108) and the screen pipe string (22) in a straight line mode, and the optical cable inside the pipe (FO2) is arranged in a shaft (101) space inside the screen pipe string (22) in a straight line shape or a spiral shape; the optical fiber cable in pipe (FO2) is arranged at the bottom, the middle, the upper part of the well bore (101) or any position in the well bore (101) in the space of the well bore (101) inside the screen string (22).

5. The wellbore production profile monitoring simulation experiment device based on distributed optical fiber sound and temperature monitoring is characterized in that the liquid discharge pipeline (301) is connected with a movable joint (66); a liquid discharge control valve (302) is arranged on the liquid discharge pipeline (301); controlling back pressure applied to the wellbore and the reservoir simulation system (2) by adjusting the drainage control valve (302) to realize production differential pressure adjustment of the wellbore and the reservoir simulation system (2); fluid from the wellbore and reservoir simulation system (2) passes through the loose joint (66) and through the drainage line (301) into a collection tank (304).

6. The distributed optical fiber sound and temperature monitoring based wellbore production profile monitoring simulation experiment device as claimed in claim 3, wherein the liquid supply and control system (3) comprises a liquid supply group and a data acquisition and control system;

each liquid supply group (381) comprises a liquid storage tank, a variable frequency plunger pump and a gate valve group;

the gate valve group comprises a plurality of liquid supply pipes, each liquid supply pipe comprises a heater and two-way valves, and the two-way valves are respectively communicated with symmetrically arranged fluid inlets; the liquid supply pipe is also provided with a flow meter and a temperature and pressure integrated sensor.