CN210598961U - Underground fluid distribution monitoring system based on distributed optical fiber sensing - Google Patents
Underground fluid distribution monitoring system based on distributed optical fiber sensing Download PDFInfo
- Publication number
- CN210598961U CN210598961U CN201921720166.5U CN201921720166U CN210598961U CN 210598961 U CN210598961 U CN 210598961U CN 201921720166 U CN201921720166 U CN 201921720166U CN 210598961 U CN210598961 U CN 210598961U
- Authority
- CN
- China
- Prior art keywords
- pressure sensor
- distributed
- underground
- armored
- quasi
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Active
Links
Images
Abstract
The utility model provides a fluid distribution monitoring system in pit based on distributed optical fiber sensing, including the metal sleeve, the metal sleeve embeds has coiled tubing, and the metal sleeve outside is fixed with first armor optical cable, first underground quasi-distributed pressure sensor, and the coiled tubing outside is equipped with second armor optical cable, second underground quasi-distributed pressure sensor; the system also comprises a DAS/DTS composite modulation and demodulation instrument and a downhole pressure sensor modulation and demodulation instrument which are arranged near the wellhead; the DAS/DTS composite modulation and demodulation instrument is respectively connected with the first armored optical cable and the second armored optical cable; the modulation and demodulation instrument of the underground pressure sensor is connected with the first underground quasi-distributed pressure sensor and the second underground quasi-distributed pressure sensor. The utility model discloses carry out long-term dynamic monitoring to oil and gas production well or water injection or steam injection or carbon dioxide injection or polymer well's production liquid profile or the profile that absorbs water, provide indispensable means, system and method for oil and gas reservoir scientific management and enhanced recovery ratio.
Description
Technical Field
The utility model belongs to the technical field of the well logging, concretely relates to fluid monitoring system in pit based on distributed optical fiber sensing.
Background
The optical fiber sensing technology started in 1977 and developed rapidly along with the development of the optical fiber communication technology, and the optical fiber sensing technology is an important mark for measuring the informatization degree of a country. The optical fiber sensing technology is widely applied to the fields of military affairs, national defense, aerospace, industrial and mining enterprises, energy environmental protection, industrial control, medicine and health, metering test, building, household appliances and the like, and has a wide market. There are hundreds of fiber sensing technologies in the world, and physical quantities such as temperature, pressure, flow, displacement, vibration, rotation, bending, liquid level, speed, acceleration, sound field, current, voltage, magnetic field, radiation and the like realize sensing with different performances.
The downhole optical fiber sensing system can be used for measuring pressure, temperature, noise, vibration, sound wave, seismic wave, flow, component analysis, electric field and magnetic field downhole. The system is based on a full armored optical cable structure, and the sensor and the connecting and data transmission cable are all made of optical fibers. At present, there are various underground armored optical cables, such as those placed in an underground control pipeline, placed in a coiled tubing, directly integrated into the wall of the coiled tubing made of composite material, bound and fixed outside the coiled tubing, placed in a casing, bound and fixed outside the casing and permanently fixed with well-cementing cement.
A production logging series instrument for logging production in casing or oil pipe is composed of ① three parts, including measuring temp, pressure, fluid flow and water holding rate in well, ① for knowing output and injection profile, ② for inspecting and monitoring well body, including well cementing quality, deformation and damage of casing, etc., and ③ for evaluating the reservoir of casing well.
The combined logging instrument for measuring the oil production, gas production, water content and temperature of the production well is a common multi-parameter production combined logging instrument. The logging tool is equipped with a relay operated from the surface, by means of which the logging tool to be used can be selected at will. Measuring the flow rate by a turbine instrument, measuring the water content by a capacitance probe, measuring the fluid density by a fluid density instrument and measuring the well temperature by a differential well temperature instrument. Each logging instrument is connected with a collar locator during measurement, and can record corresponding logging depth and various parameters on the depth at the same time so as to ensure the consistency of the detection depths of the logging instruments. When the logging cable moves from bottom to top, the information obtained by the downhole instrument is transmitted to the ground instrument through the cable, and various logging curves are automatically recorded. And calculating to obtain the layered oil production, the gas production, the water content and the like. However, because a large number of electronic devices and various sensors are installed in the production logging instrument, the conventional production logging instrument cannot be put down into a deep well with ultrahigh temperature and ultrahigh pressure to measure a liquid production profile or a water absorption profile.
The layered water absorption in the water injection well can be measured by adding a suspension of activated carbon with adsorbed isotopes (commonly 131I) to the injection water using an isotope carrier method. When the suspension enters the stratum along with injected water, radioactive solid phase carriers are filtered and accumulated near the well wall, the more the stratum absorbs the activated suspension, the more carrier filtering and accumulating amount is, and the stronger the radioactive isotope is. The natural gamma ray curves are measured once before and after the isotope carrier is added, and the water absorption percentage of each layer can be obtained by comparison. The method has the advantages that the method is not limited by a downhole tubular column when measuring in multi-layer exploitation, and the water absorption of each layer can be measured. The disadvantage is that the radioactive isotope pollutes the environment. The stratified water absorption in the water injection well can be measured by using a turbine type continuous flow meter test method, the instrument is centered by using the centralizer during measurement, and the rotating speed of the turbine in the flow meter is in direct proportion to the flow speed. When the sectional area of the casing or the oil pipe is a fixed value, the change of the axial movement speed of the fluid in the well is continuously measured, and the injection profile of the well can be determined. The method has the advantages that isotopes are not used, the construction is simple and convenient, but only the water absorption of the layered section can be measured when the water is put into a layered water injection well of a packer.
Full-wellbore Distributed Temperature (DTS) measurement by laying an armored cable inside and outside a casing or binding an armored cable outside a coiled tubing has been widely applied in oil and gas resource development. The well fluid output or water injection rate can be calculated according to the temperature change measured by the underground oil and gas production well section (perforated well section) or according to the temperature change measured by the water injection well section (perforated well section). However, because the spatial resolution and the temperature measurement sensitivity of the conventional DTS modem are limited, the variation and the accurate position of the well temperature measured by the DTS method have certain errors, so that the error of the well fluid output or water injection of the perforation section calculated according to the variation of the well temperature is large, and the amount of oil, gas and water produced by the perforation section cannot be accurately calculated according to the variation of the well temperature.
Full-well-interval Distributed Acoustic Sensing (DAS) measurement performed by arranging an armored optical cable inside and outside a casing or binding the armored optical cable outside a coiled tubing has been widely applied to oil and gas resource development, but currently, DAS-VSP data acquisition, microseism monitoring and passive seismic data acquisition are mainly used. The industry has just begun to utilize DAS technology to collect downhole noise data, and noise data is utilized to infer production of oil, gas and water at downhole perforated well sections. The method is characterized in that the method only depends on the downhole noise data to infer the oil, gas and water production conditions of the downhole perforated well section, which basically belong to qualitative or semi-quantitative interpretation, and the error is relatively large.
SUMMERY OF THE UTILITY MODEL
In the whole production process from production to abandonment of oil and gas wells (including oil production wells, gas production wells, water injection wells, observation wells and the like), various testing instruments are utilized to carry out downhole testing so as to obtain corresponding underground information. The method comprises the steps of determining the temperature, the pressure, the fluid flow and the water holding rate in the well, knowing the production (liquid production) and injection (water absorption) profiles and providing a basis for oil layer reconstruction. Production logging has become an indispensable tool for scientific management of hydrocarbon reservoirs and for enhanced recovery. Due to the limitations of conventional production logging instruments operating in high temperature and high pressure wells, a method and technique for understanding the production (production) and injection (water absorption) profiles of oil and gas wells by low cost, high precision, and high reliability means is needed.
The utility model provides a when binding the armor optical cable in the vertical well, the sleeve pipe outside of inclined shaft or horizontal well and with the well cementation cement is permanent fixed, bind the metal clip for the armor optical cable in the coiled tubing outside fixed, after accurate distributing type or series-wound pressure sensor establish ties up with the photoelectric composite cable in the pit, just constructed one and carried out long-term dynamic monitoring system's the downhole sensing unit to oil and gas production well or water injection or steam injection or carbon dioxide or the production fluid section of annotating polymer well or the section of absorbing water. A distributed optical fiber acoustic wave sensing and distributed optical fiber temperature sensing (DAS/DTS) composite modulation and demodulation instrument on the wellhead ground is connected with an armored optical cable near the wellhead, and a downhole quasi-distributed pressure sensor modulation and demodulation instrument on the wellhead ground is connected with an armored photoelectric composite cable near the wellhead, so that a downhole fluid dynamic distribution long-term comprehensive monitoring system based on distributed optical fiber sensing is formed.
The utility model aims at overcoming prior art's is not enough, the utility model provides bind the armor optical cable in the vertical well, the sleeve pipe outside of inclined shaft or horizontal well is permanent fixed with well cementation cement, it is fixed in the coiled tubing outside to bind the metal checkpost for the armor optical cable, establish accurate distributed or series-wound type downhole pressure sensor with the photoelectric composite cable and establish ties, the underground sensing unit who carries out long-term dynamic monitoring system to oil and gas production well or water injection or steam injection or carbon dioxide injection or polymer well's production fluid section or the section of absorbing water has been found, provide indispensable means, system and method for oil and gas reservoir scientific management and enhanced recovery ratio.
The distributed optical fiber sensing technology is the best choice for underground permanent monitoring and is the basis for realizing true production informatization and intellectualization of oil and gas fields. The distributed downhole optical fiber sensing has the following advantages:
1) the real-time, high-density and multi-parameter parameters of the whole life cycle of oil and gas field development can be provided, and the scientific level and the efficiency of decision making are improved for the fine oil and gas reservoir description;
2) the underground operation is carried out without interrupting production, so that the production loss, the operation cost, the personnel risk and the environmental pollution risk are avoided;
3) the method can replace and surpass the conventional well logging, not only provides more real-time and high-quality data, but also has high cost performance, and is beneficial for life after being put into use;
4) special equipment is not needed, the method can be conveniently applied to large-slope horizontal wells, horizontal wells and the like, and the operation in oil pipes is not influenced.
In order to achieve the above object, the specific technical solution of the present invention is:
the underground fluid distribution monitoring system based on distributed optical fiber sensing comprises a metal sleeve, wherein a coiled tubing is arranged in the metal sleeve, a first armored optical cable is fixed on the outer side of the metal sleeve, and a second armored optical cable is fixed on the outer side of the coiled tubing;
a first underground quasi-distributed pressure sensor is fixed on the outer side of the metal sleeve, and a second underground quasi-distributed pressure sensor is fixed on the outer side of the coiled tubing;
the system also comprises a DAS/DTS composite modulation and demodulation instrument and a downhole pressure sensor modulation and demodulation instrument which are arranged near the wellhead;
the DAS/DTS composite modulation and demodulation instrument comprises distributed acoustic wave sensing and distributed temperature sensing; the DAS/DTS composite modulation and demodulation instrument is respectively connected with the first armored optical cable and the second armored optical cable;
the modulation and demodulation instrument of the underground pressure sensor is connected with a first underground quasi-distributed pressure sensor through a first armored photoelectric composite cable, and is connected with a second underground quasi-distributed pressure sensor through a second armored photoelectric composite cable.
Furthermore, the first armored optical cable and the second armored optical cable are armored optical cables and comprise single-mode or multi-mode or special optical fibers, and the single-mode or multi-mode or special optical fibers are sequentially provided with inner continuous metal thin tubes and outer continuous metal thin tubes outside for packaging.
The first underground quasi-distributed pressure sensor and the second underground quasi-distributed pressure sensor are fiber optic pressure sensors with Fabry-Perot cavities, or grating pressure sensors, or piezoelectric crystal pressure sensors.
The plurality of first underground quasi-distributed pressure sensors are connected in series through first armored photoelectric composite cables at equal intervals;
and the plurality of second underground quasi-distributed pressure sensors are connected in series through second armored photoelectric composite cables at equal intervals.
The metal sleeve is characterized by further comprising a first annular metal clip, and the first annular metal clip is fixedly arranged at the position of the metal sleeve shoe. The coiled tubing oil pipe structure is characterized by further comprising a second annular metal clip, wherein the second annular metal clip is fixedly arranged on the outer side of the coiled tubing.
The monitoring method of the underground fluid distribution monitoring system based on the distributed optical fiber sensing comprises the following steps:
(a) synchronously and slowly descending the metal sleeve and the first armored optical cable into a drilled well hole;
(b) the first annular metal clip is arranged at the joint of the two metal sleeves at the wellhead, so that the first armored optical cable is fixed and protected from moving and/or being damaged in the process of casing running;
(c) pumping cement slurry from the well bottom by using a high-pressure pump truck, returning the cement slurry to the well head from the well bottom along an annular area between the outer wall of the metal casing and the drill hole, and permanently fixing the metal casing, the first armored optical cable and the stratum rock together after the cement slurry is solidified;
(d) synchronously and slowly putting the coiled tubing and the second armored optical cable into a metal cased well for well cementation and completion;
(e) the second annular metal clips are arranged on the coiled tubing at the wellhead according to the same interval, so that the second armored optical cable is fixed and protected from being damaged in the installation process of the lower coiled tubing, and the armored optical cable and the coiled tubing are well coupled by acoustic signals;
(f) connecting the single-mode optical fiber in the first armored optical cable to a DAS signal input end of a DAS/DTS composite modulation and demodulation instrument at a wellhead, and connecting a single multimode optical fiber or two multimode optical fibers in the first armored optical cable to a DTS signal input end of the DAS/DTS composite modulation and demodulation instrument;
(g) connecting the single-mode optical fiber in the second armored optical cable to a DAS signal input end of a DAS/DTS composite modulation and demodulation instrument at a wellhead, and connecting a single multimode optical fiber or two multimode optical fibers in the second armored optical cable to a DTS signal input end of the DAS/DTS composite modulation and demodulation instrument;
(h) respectively connecting the first armored photoelectric composite cable and the second armored photoelectric composite cable to the signal input end of a modulation and demodulation instrument of the underground pressure sensor at a wellhead;
(i) continuously monitoring and measuring DAS and DTS signals in a first armored optical cable outside the metal sleeve and a second armored optical cable outside the coiled tubing by a DAS/DTS composite modulation and demodulation instrument placed beside a wellhead during oil and gas production, and continuously monitoring and measuring pressure signals of a first underground quasi-distributed pressure sensor and a second underground quasi-distributed pressure sensor which are connected outside the metal sleeve and outside the coiled tubing in series by a downhole pressure sensor modulation and demodulation instrument placed beside the wellhead;
(j) carrying out modulation and demodulation on DAS signals and DTS signals continuously measured by the DAS/DTS composite modulation and demodulation instrument, and converting DAS data and DTS data into distribution data of downhole noise intensity and temperature;
(k) modulating and demodulating continuously measured underground pressure signals by an underground pressure sensor modulating and demodulating instrument, and calculating pressure data of each underground pressure sensor position;
(l) And according to the monitored and measured downhole noise, temperature and pressure data, calculating the flow rate and the change (liquid production profile) of oil, gas and water of each downhole oil and gas production well section by using a multi-parameter comprehensive inversion method, or the injection amount and the change (water absorption profile) of each downhole water injection or steam injection or carbon dioxide injection or polymer injection well section, thereby realizing the long-term dynamic monitoring of the development and production process and the change of the oil and gas well.
Stress changes caused by fluid flow can cause the fracture artificial cracks to open or close, noise and micro-seismic signals are generated, the reconstruction conditions of the fracturing sections of different reservoirs are judged through the distribution of the noise and the micro-seismic signals of different sections of the vertical well or the horizontal well, and meanwhile, the activity conditions of the reconstruction wells in different stages of liquid drainage, testing, normal production and the like are comprehensively analyzed; whether the artificial seam network between different wells of the same platform generates stress interference and other influences is analyzed, influences of different geological conditions on oil gas output are analyzed, the crack scale formed by the comparative fracturing and the oil gas output is compared, and the liquid sweep range and the vibration and effective output range caused by stress transmission are evaluated. And monitoring and analyzing the liquid discharge and oil production conditions in real time during production, and calculating and analyzing the flow of different sections of the horizontal well. In order to solve the problems of horizontal well flow and water content after fracturing, the underground real-time monitoring and analysis of the water content of the oil well are carried out, the high water-bearing layer is closed in time, and the oil well is controlled to produce in the low water-bearing layer or the low water-bearing part.
According to the distributed optical fiber acoustic wave monitoring (DAS) technology, two clusters of laser pulses are sent to the interior of an optical fiber by using an interrogator, one part of light is reflected due to the fact that the optical fiber is not absolutely pure, Rayleigh waves of backscattered light are affected by the acoustic waves to generate phase change, namely the distance between two Rayleigh peaks is affected by the acoustic waves to generate corresponding change, and the amplitude of the acoustic waves on each meter of the optical fiber is determined through analysis and calculation. The fiber is effectively converted into a string of acoustic signal sensors (or microphones) to identify fluid density, fluid migration, casing leaks, or equipment wear and failure early detection.
The distributed optical fiber temperature measurement system (DTS) is used for measuring the temperature profile in a shaft in real time, and the principle of the DTS is that Raman (Raman) scattering and Optical Time Domain Reflection (OTDR) principles generated when light is transmitted in optical fibers are used for obtaining space temperature distribution information. After the high-power narrow-pulse-width laser pulse LD is incident to the sensing fiber, weak back scattering light is generated, and the weak back scattering light is Rayleigh (Rayleigh), Anti-Stokes (Anti-Stokes) and Stokes (Stokes) light respectively according to different wavelengths. DTS is the most widely used distributed temperature monitoring technology, and can accurately measure the temperature per meter on the optical fiber, wherein the maximum working temperature reaches 300 ℃, the accuracy is 0.1 ℃ and the resolution is 0.01 ℃.
The distributed optical fiber acoustic wave monitoring technology is applied as follows: monitoring a fluid flow noise signal, monitoring a microseism, determining a productivity section, calculating a fluid flow range, and determining a well spacing and a water plugging scheme.
The distributed optical fiber sound wave monitoring technology and the distributed optical fiber temperature measuring technology are applied as follows: calculating the fluid flow and researching the gas oil water distribution in a distinguishing way. In the perforation section of the oil and gas production well, the noise characteristics and frequency of the oil, gas and water flowing into the well are different, and the oil, gas or water flowing into the well can be distinguished according to the recorded noise characteristics and frequency in the well.
And (3) carrying out flow calculation by combining temperature data measured by the underground optical fiber, noise data measured by the optical fiber and pressure data with other parameters: if a certain production exists in the production zone, theoretically, as long as the production of the production zone is greater than zero, the reservoir pressure of the production zone is necessarily greater than the well stream pressure of the corresponding section.
From the point of view of temperature and conservation of energy, the two above cases will correspond to the following energy forms:
Twf+Tentry＝Tmix(fluid pressure PwfLess than reservoir pressure Pres)
TwfIs the temperature of the fluid in the wellbore, TentryTo obtain a temperature of fluid flowing down the wellbore from the reservoir, TmixThe temperature of the mixed gas flowing along the shaft to the wellhead. The above formula represents a certain mass of TwfMixing working medium with T of certain massentryWorking medium to obtain T with total mass being the sum of the twomixWorking medium. T isentryWith formation temperature TresIs unequal in the case of production, due to Joule of fluidCaused by the Muson effect (J-T effect for short).
During the hydraulic fracturing, the movement process of the fracturing fluid can be reflected by the change of the temperature of the whole well section; the temperature change around the perforation interval can analyze and judge the amount of fracturing fluid entering the formation and the flow-back speed. The DTS is used for monitoring the downhole temperature change, and the lower the temperature can be reflected from the DTS data, the larger the gas production rate at the position is.
The method combines noise or vibration signals monitored by the underground distributed optical fiber sensing system with temperature information, and distinguishes the oil-water distribution rule by utilizing the characteristic that the oil temperature changes faster than the water temperature and combining the noise or vibration distribution condition to carry out comprehensive analysis.
The utility model provides a fluid distribution monitoring system in pit and data acquisition handles explanation method based on distributed optical fiber sensing is low-cost, high accuracy, the fluid distribution developments in pit of high reliability comprehensive monitoring method and technique. The utility model provides a bind the armor optical cable in the vertical well, the sleeve pipe outside of inclined shaft or horizontal well and with well cementation cement permanent fixation, the metal checkpost for the armor optical cable is binded in the coiled tubing outside and is fixed, connect the photoelectric composite cable of accurate distributed or serial-type downhole pressure sensor in series, construct a downhole sensing unit that carries out long-term dynamic monitoring system to oil and gas production well or water injection well, including distributed acoustic sensing and distributed temperature sensing (DAS/DTS) composite modulation demodulation instrument near the well head, the modulation demodulation instrument of accurate distributed pressure sensor in the pit, constitute the downhole fluid distribution monitoring system based on distributed optical fiber sensing and its data acquisition processing interpretation method jointly, carry out long-term dynamic monitoring to the oil and gas production well or the liquid production section or the water absorption section of water injection or steam injection or carbon dioxide injection polymer well, provides indispensable means, systems and methods for scientific reservoir management and enhanced oil recovery.
Drawings
Fig. 1 is a schematic structural diagram of the present invention.
Fig. 2 is a schematic diagram of the structure of the downhole casing of the present invention.
Fig. 3 is a schematic structural view of the coiled tubing of the present invention.
Fig. 4 is a schematic structural diagram of the armored optical cable of the present invention.
Detailed Description
The embodiments of the present invention will be described in detail with reference to the accompanying drawings, but they are not to be construed as limiting the invention, and are presented by way of example only, and the advantages of the invention will become more apparent and can be easily understood by description.
The utility model discloses a fluid distribution monitoring system's in pit based on distributed optical fiber sensing concrete implementation mode, as follows:
referring to fig. 1 to 3, the downhole fluid distribution monitoring system based on distributed optical fiber sensing comprises a metal sleeve 1, a coiled tubing 2 arranged in the metal sleeve 1, a DAS/DTS composite modem 3 arranged near a wellhead and including distributed acoustic sensing and distributed temperature sensing, a first armored cable 4 permanently fixed outside the metal sleeve 1, a second armored cable 5 semi-permanently fixed outside the coiled tubing 2, a downhole pressure sensor modem 6 arranged near the wellhead, a first annular metal clip 8 arranged at a boot of the metal sleeve 1 to protect the first armored cable 4, a second annular metal clip 9 arranged outside the coiled tubing 2 to protect the second armored cable 5, a first downhole quasi-distributed pressure sensor 10 permanently fixed outside the metal sleeve 1, and a first armored photoelectric composite cable 11 permanently fixed outside the metal sleeve 1 and connected with the first downhole quasi-distributed pressure sensor 10, The second underground quasi-distributed pressure sensor 12 is fixed on the outer side of the coiled tubing 2, and the second armored photoelectric composite cable 13 is fixed on the outer side of the coiled tubing 2 and connected with the second underground quasi-distributed pressure sensor 12;
the first armored optical cable 4 is arranged on the outer wall of the metal sleeve 1; the second armored optical cable 5 is arranged on the outer wall of the coiled tubing 2;
the first armored optical cable 4 arranged on the outer wall of the metal sleeve 1 and the second armored optical cable 5 arranged on the outer wall of the coiled tubing 2 are connected with the DAS/DTS composite modulation and demodulation instrument 3 at a wellhead;
as shown in fig. 4, the first armored optical cable 4 and the second armored optical cable 5 both include single-mode or multi-mode or special optical fibers 21; the single-mode or multi-mode or special optical fiber 21 is externally provided with an inner continuous metal tubule 22 and an outer continuous metal tubule 23 in sequence for packaging.
The first downhole quasi-distributed pressure sensor 10 and the second downhole quasi-distributed pressure sensor 12 can be F-P cavity fiber optic pressure sensors with Fabry-Perot cavities, or grating pressure sensors, or piezoelectric crystal pressure sensors.
The first underground quasi-distributed pressure sensor 10 and the second underground quasi-distributed pressure sensor 12 are connected in series through a first armored photoelectric composite cable 11 and a second armored photoelectric composite cable 13 at equal intervals.
The first annular metal clip 8 is fixedly arranged at the boot of the metal sleeve 1 to protect the first armored cable 4 from moving and/or being damaged in the process of casing running.
The second annular metal clip 9 is fixedly arranged on the outer side of the coiled tubing 2, so that the second armored optical cable 5 is protected from being damaged in the installation process of the coiled tubing 2, and the second armored optical cable 5 and the coiled tubing 2 have good acoustic signal coupling.
In order to adapt to the severe environment of underground high temperature and high pressure, most of the underground optical cables are armored by different materials and different structures, and the underground optical cables are high temperature resistant, high pressure resistant, stretch resistant, extrusion resistant and impact resistant, so that the integrity and smoothness of the underground optical cables during underground operation are ensured. One of the commonly used armoring techniques is to place a single or several high temperature resistant single-mode or multi-mode or special optical fibers into a sealed fine stainless steel tube for protection. According to the magnitude of underground pressure and the external force intensity in the underground operation process, sometimes, one or more layers of stainless steel pipes with slightly larger diameters are sleeved outside a fine stainless steel pipe provided with a single or a plurality of high-temperature-resistant optical fibers, and even one or more layers of armored stainless steel wires are wound outside the layers of stainless steel pipes to enhance the tensile resistance, the extrusion resistance and the impact resistance of the armored optical cable.
The embodiment provides a downhole fluid distribution monitoring system based on distributed optical fiber sensing and a monitoring method thereof, and provides a low-cost, high-precision and high-reliability downhole fluid distribution dynamic comprehensive monitoring method and technology. The utility model provides a bind first armor optical cable 4 in the vertical well, the metal casing 1 outside of inclined shaft or horizontal well is permanently fixed with well cementation cement, second armor optical cable 5 is binded in 2 outsides of coiled tubing fixedly with second annular metal checkpost 9, first underground quasi-distributed pressure sensor 10, second underground quasi-distributed pressure sensor 12 is established ties respectively, a downhole sensing unit of carrying out long-term dynamic monitoring system to oil and gas production well or water injection well has been established, DAS/DTS composite modulation demodulation instrument 3 near well head, downhole pressure sensor modulation demodulation instrument 6, constitute the downhole fluid distribution monitoring system based on distributed optical fiber sensing jointly, carry out long-term dynamic monitoring to oil and gas production well or water injection or steam injection or carbon dioxide injection or polymer well's production fluid section or profile that absorbs water, provide indispensable means for oil and gas scientific management and improvement recovery ratio, Systems and methods.
A continuous metal casing 1, hundreds to thousands of metres long, is run downhole by successively lowering tens to hundreds of metal casing sections, of the order of 10 metres in length, into the wellbore. The diameter of the bottom of each metal casing section with the length of about 10 meters is slightly larger than that of the casing shoe, so that the two metal casing sections are fixed together end to end, and the upper and lower metal casing sections are prevented from being eccentric or misaligned at the butt joint. In order to protect the first armored cable 4 from being worn out during the operation of simultaneously lowering the metal casing 1 into the well or being crushed or broken at the position of the casing shoe, a first annular metal clip 8 is fixedly arranged at the position of each casing shoe for protecting the first armored cable 4 passing through the position of the casing shoe from moving and/or being damaged.
The first armored cable 4 is arranged outside the metal casing 1 of the vertical well, the inclined well or the horizontal well, and the metal casing 1 and the outside first armored cable 4 and the stratum are permanently fixed together by using cementing cement. When the coiled tubing 2 and the second armored optical cable 5 are synchronously and slowly put into the well of the metal casing 1 after well cementation and completion, the second annular metal clips 9 are arranged on the coiled tubing 2 at the well head according to the same interval, so that the second armored optical cable 5 is fixed and protected from being damaged in the installation process of the coiled tubing 2, and the second armored optical cable 5 and the coiled tubing 2 have good acoustic signal coupling. The single-mode optical fibers in the first armored optical cable 4 and the second armored optical cable 5 are connected to the DAS signal input end of the DAS/DTS composite modulation and demodulation instrument 3 at a wellhead, and the single multimode optical fiber or the two multimode optical fibers in the first armored optical cable 4 and the second armored optical cable 5 are connected to the DTS signal input end of the DAS/DTS composite modulation and demodulation instrument 3 so as to carry out single-end input measurement or double-end input measurement. And the first armored photoelectric composite cable 11 and the second armored photoelectric composite cable 13 are connected to the signal input end of the modulation and demodulation instrument 6 of the downhole pressure sensor at the wellhead.
The monitoring method of the underground fluid distribution monitoring system based on the distributed optical fiber sensing comprises the following steps:
a. synchronously and slowly descending the metal sleeve 1 and the first armored optical cable 4 into a drilled well hole;
b. the first annular metal clip 8 is arranged at the joint of the two metal casing pipes 1 at the wellhead, so that the first armored optical cable 4 is fixed and protected from moving and/or being damaged in the casing pipe descending process;
c. pumping cement slurry from the well bottom by using a high-pressure pump truck, returning the cement slurry to the well head from the well bottom along an annular area between the outer wall of the metal casing 1 and the drilled hole, and permanently fixing the metal casing 1, the first armored optical cable 4 and the stratum rock together after the cement slurry is solidified;
d. synchronously and slowly putting the continuous oil pipe 2 and the second armored optical cable 5 into the well of the metal casing 1 for well cementation and completion;
e. the second annular metal clips 9 are arranged on the coiled tubing 2 at the wellhead at the same intervals, so that the second armored cable 5 is fixed and protected from being damaged in the installation process of the lower coiled tubing 2, and the armored cable 5 and the coiled tubing 2 have good acoustic signal coupling;
f. connecting the single-mode optical fiber in the first armored optical cable 4 to the DAS signal input end of the DAS/DTS composite modulation and demodulation instrument 3 at a wellhead, and connecting the single multimode optical fiber or two multimode optical fibers in the first armored optical cable 4 to the DTS signal input end of the DAS/DTS composite modulation and demodulation instrument 3;
g. connecting the single-mode optical fiber in the second armored optical cable 5 to the DAS signal input end of the DAS/DTS composite modulation and demodulation instrument 3 at a wellhead, and connecting the single multimode optical fiber or two multimode optical fibers in the second armored optical cable 5 to the DTS signal input end of the DAS/DTS composite modulation and demodulation instrument 3;
h. the first armored photoelectric composite cable 11 and the second armored photoelectric composite cable 13 are respectively connected to the signal input end of the modulation and demodulation instrument 6 of the downhole pressure sensor at the wellhead;
i. during oil and gas production, DAS and DTS signals in a first armored optical cable 4 outside a metal sleeve 1 and a second armored optical cable 5 outside a coiled tubing 2 are continuously monitored and measured through a DAS/DTS composite modulation and demodulation instrument 3 placed beside a wellhead, and meanwhile pressure signals of a first underground quasi-distributed pressure sensor 10 and a second underground quasi-distributed pressure sensor 12 which are connected outside the metal sleeve 1 and outside the coiled tubing 2 in series are continuously monitored and measured through a downhole pressure sensor modulation and demodulation instrument 6 placed beside the wellhead;
j. DAS signals and DTS signals continuously measured by the DAS/DTS composite modulation and demodulation instrument 3 are modulated and demodulated, DAS data and DTS data are converted into distribution data of downhole noise intensity and temperature;
k. the modulation and demodulation instrument 6 of the underground pressure sensor modulates and demodulates the continuously measured underground pressure signals and calculates the pressure data of each underground pressure sensor position;
and l, according to the monitored and measured downhole noise, temperature and pressure data, calculating the flow rate and the change (liquid production profile) of oil, gas and water of each downhole oil and gas production well section by using a multi-parameter comprehensive inversion method, or the injection amount and the change (water absorption profile) of each downhole water injection or steam injection or carbon dioxide injection or polymer injection well section, so as to realize the long-term dynamic monitoring of the development and production process and the change of the oil and gas well.
Claims (5)
1. The underground fluid distribution monitoring system based on distributed optical fiber sensing is characterized by comprising a metal sleeve (1), wherein a coiled tubing (2) is arranged in the metal sleeve (1), a first armored optical cable (4) is fixed on the outer side of the metal sleeve (1), and a second armored optical cable (5) is fixed on the outer side of the coiled tubing (2);
a first underground quasi-distributed pressure sensor (10) is fixed on the outer side of the metal sleeve (1), and a second underground quasi-distributed pressure sensor (12) is fixed on the outer side of the coiled tubing (2);
the system also comprises a DAS/DTS composite modulation and demodulation instrument (3) and a downhole pressure sensor modulation and demodulation instrument (6) which are arranged near a wellhead;
the DAS/DTS composite modulation and demodulation instrument (3) comprises distributed acoustic wave sensing and distributed temperature sensing; the DAS/DTS composite modulation and demodulation instrument (3) is respectively connected with a first armored optical cable (4) and a second armored optical cable (5);
the underground pressure sensor modulation and demodulation instrument (6) is connected with a first underground quasi-distributed pressure sensor (10) through a first armored photoelectric composite cable (11), and is connected with a second underground quasi-distributed pressure sensor (12) through a second armored photoelectric composite cable (13).
2. A downhole fluid distribution monitoring system based on distributed optical fiber sensing according to claim 1, wherein the first armored optical cable (4) and the second armored optical cable (5) are armored optical cables and comprise single-mode or multi-mode or special optical fibers (21), and the single-mode or multi-mode or special optical fibers (21) are sequentially encapsulated by an inner continuous metal thin tube (22) and an outer continuous metal thin tube (23) outside the single-mode or multi-mode or special optical fibers.
3. The downhole fluid distribution monitoring system based on distributed optical fiber sensing of claim 1, wherein the first downhole quasi-distributed pressure sensor (10), the second downhole quasi-distributed pressure sensor (12) is a fiber optic pressure sensor with a Fabry-Perot cavity, or a grating pressure sensor, or a piezoelectric crystal pressure sensor;
a plurality of first underground quasi-distributed pressure sensors (10) are connected in series through first armored photoelectric composite cables (11) at equal intervals;
and a plurality of second underground quasi-distributed pressure sensors (12) are connected in series through second armored photoelectric composite cables (13) at equal intervals.
4. A distributed optical fiber sensing-based downhole fluid distribution monitoring system according to claim 1, further comprising a first annular metal clip (8), wherein the first annular metal clip (8) is fixedly installed at a metal casing (1) shoe.
5. A distributed fibre sensing based downhole fluid distribution monitoring system according to claim 1, further comprising a second annular metal clip (9), wherein the second annular metal clip (9) is fixedly mounted on the outside of the coiled tubing (2).
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201921720166.5U CN210598961U (en) | 2019-10-14 | 2019-10-14 | Underground fluid distribution monitoring system based on distributed optical fiber sensing |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201921720166.5U CN210598961U (en) | 2019-10-14 | 2019-10-14 | Underground fluid distribution monitoring system based on distributed optical fiber sensing |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CN210598961U true CN210598961U (en) | 2020-05-22 |
Family
ID=70714726
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN201921720166.5U Active CN210598961U (en) | 2019-10-14 | 2019-10-14 | Underground fluid distribution monitoring system based on distributed optical fiber sensing |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN210598961U (en) |
Cited By (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN110541702A (en) * | 2019-10-14 | 2019-12-06 | 中油奥博(成都)科技有限公司 | underground fluid distribution monitoring system and method based on distributed optical fiber sensing |
| CN112360433A (en) * | 2020-11-11 | 2021-02-12 | 中石化石油工程技术服务有限公司 | Method for arranging monitoring optical fibers in horizontal well |
| CN112664179A (en) * | 2020-12-31 | 2021-04-16 | 核工业北京地质研究院 | Device and method for positioning water flowing fracture in drilling layered test process |
| CN113513302A (en) * | 2021-05-17 | 2021-10-19 | 中油奥博(成都)科技有限公司 | Underground fluid monitoring system and method based on distributed optical fiber hydrophone |
| CN113530524A (en) * | 2021-07-12 | 2021-10-22 | 中国石油大学(华东) | Shaft flow monitoring system and flow and water content interpretation method |
| CN113847019A (en) * | 2021-10-18 | 2021-12-28 | 中油奥博(成都)科技有限公司 | Seismic and geological engineering integrated data acquisition system and method based on optical fiber sensing |
-
2019
- 2019-10-14 CN CN201921720166.5U patent/CN210598961U/en active Active
Cited By (9)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN110541702A (en) * | 2019-10-14 | 2019-12-06 | 中油奥博(成都)科技有限公司 | underground fluid distribution monitoring system and method based on distributed optical fiber sensing |
| CN110541702B (en) * | 2019-10-14 | 2024-04-05 | 中油奥博(成都)科技有限公司 | Underground fluid distribution monitoring system and method based on distributed optical fiber sensing |
| CN112360433A (en) * | 2020-11-11 | 2021-02-12 | 中石化石油工程技术服务有限公司 | Method for arranging monitoring optical fibers in horizontal well |
| CN112360433B (en) * | 2020-11-11 | 2023-11-07 | 中石化石油工程技术服务有限公司 | Method for arranging monitoring optical fiber in horizontal well |
| CN112664179A (en) * | 2020-12-31 | 2021-04-16 | 核工业北京地质研究院 | Device and method for positioning water flowing fracture in drilling layered test process |
| CN113513302A (en) * | 2021-05-17 | 2021-10-19 | 中油奥博(成都)科技有限公司 | Underground fluid monitoring system and method based on distributed optical fiber hydrophone |
| CN113530524A (en) * | 2021-07-12 | 2021-10-22 | 中国石油大学(华东) | Shaft flow monitoring system and flow and water content interpretation method |
| CN113530524B (en) * | 2021-07-12 | 2023-05-26 | 中国石油大学(华东) | Shaft flow monitoring system and flow and water content interpretation method |
| CN113847019A (en) * | 2021-10-18 | 2021-12-28 | 中油奥博(成都)科技有限公司 | Seismic and geological engineering integrated data acquisition system and method based on optical fiber sensing |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| CN110541702B (en) | Underground fluid distribution monitoring system and method based on distributed optical fiber sensing | |
| CN210598961U (en) | Underground fluid distribution monitoring system based on distributed optical fiber sensing | |
| CN112593924A (en) | Underground gas storage safety operation monitoring system and monitoring method | |
| CN110331973B (en) | Hydraulic fracturing monitoring method based on distributed optical fiber sound monitoring and distributed optical fiber temperature monitoring | |
| CN112780256B (en) | Horizontal well microseism monitoring system and monitoring method based on distributed optical fiber sensing | |
| CN111648762B (en) | Underground long-term dynamic monitoring special distributed armored optical cable and monitoring system and method | |
| US6913079B2 (en) | Method and system for monitoring smart structures utilizing distributed optical sensors | |
| US20230213669A1 (en) | Intelligent geophysical data acquisition system and acquisition method for shale oil and gas optical fiber | |
| CN110344815B (en) | Production profile monitoring method based on distributed optical fiber sound monitoring and distributed optical fiber temperature monitoring | |
| Baldwin | Fiber optic sensors in the oil and gas industry: Current and future applications | |
| CN113513302B (en) | Underground fluid monitoring system and method based on distributed optical fiber hydrophone | |
| CN112268642A (en) | Underground stress measuring device and method based on distributed optical fiber sensing | |
| CN111456716A (en) | Underground strain distribution monitoring system and method based on distributed optical fiber sensing | |
| Sun et al. | Fiber optic distributed sensing technology for real-time monitoring water jet tests: Implications for wellbore integrity diagnostics | |
| CN112647936A (en) | Optimized oil reservoir development data acquisition system and method based on distributed optical fiber sensing | |
| CN112031743A (en) | Underground fluid identification device and measurement method based on distributed optical fiber sensing technology | |
| CN112780257A (en) | Drilling fluid leakage monitoring system and monitoring method based on distributed optical fiber sensing | |
| CN214366030U (en) | Horizontal well micro-seismic monitoring system based on distributed optical fiber sensing | |
| CN115079250A (en) | CO based on optical fiber sensing technology 2 System and method for address selection and safety monitoring of sealed storage location | |
| CN212454396U (en) | Underground strain distribution monitoring system based on distributed optical fiber sensing | |
| CN214091843U (en) | Underground gas storage safety operation monitoring system | |
| CN212454394U (en) | Special distributed armored optical cable for underground long-term dynamic monitoring and monitoring system | |
| WO2023024364A1 (en) | Underground fluid pressure measurement system based on continuous grating optical fiber, and measurement method | |
| CN213543861U (en) | Underground stress measuring device based on distributed optical fiber sensing | |
| Chen et al. | Real-time down-hole monitoring of gas injection profile using fibre-optic distribute temperature and acoustic sensing in tarim |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| GR01 | Patent grant | ||
| GR01 | Patent grant |