WO2015153549A1 - Mesure de flux thermique réparti - Google Patents

Mesure de flux thermique réparti Download PDF

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Publication number
WO2015153549A1
WO2015153549A1 PCT/US2015/023493 US2015023493W WO2015153549A1 WO 2015153549 A1 WO2015153549 A1 WO 2015153549A1 US 2015023493 W US2015023493 W US 2015023493W WO 2015153549 A1 WO2015153549 A1 WO 2015153549A1
Authority
WO
WIPO (PCT)
Prior art keywords
cable
heating
metering system
flow metering
temperature
Prior art date
Application number
PCT/US2015/023493
Other languages
English (en)
Inventor
Paul Dickenson
Gareth Lees
Colin Allan WILSON
Maxwell HADLEY
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
Schlumberger Technology Corporation
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited, Schlumberger Technology Corporation filed Critical Schlumberger Canada Limited
Publication of WO2015153549A1 publication Critical patent/WO2015153549A1/fr

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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/68—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using thermal effects
    • G01F1/684—Structural arrangements; Mounting of elements, e.g. in relation to fluid flow
    • G01F1/688—Structural arrangements; Mounting of elements, e.g. in relation to fluid flow using a particular type of heating, cooling or sensing element
    • G01F1/6884—Structural arrangements; Mounting of elements, e.g. in relation to fluid flow using a particular type of heating, cooling or sensing element making use of temperature dependence of optical properties
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/103—Locating fluid leaks, intrusions or movements using thermal measurements

Definitions

  • Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. Once a wellbore is drilled, various forms of well completion components may be installed in order to control and enhance the efficiency of producing the various fluids from the reservoir.
  • One piece of equipment which may be installed is a monitoring system, to monitor wellbore conditions.
  • Some monitoring systems may include distributed sensor systems, such as fiber optic distributed sensors.
  • Embodiments of the present disclosure are directed to a distributed flow metering system, including a cable positioned in a wellbore.
  • the cable can include a fiber optic component configured to measure temperature at specific locations along the cable in the wellbore, and a heating component configured to periodically direct heat into the wellbore.
  • the system also includes a fluid inducing component configured to induce fluid flow in heated areas of the wellbore.
  • the system still further includes a monitoring component configured to monitor temperature when the heating component is active and to deduce fluid flow rates from a monitored temperature.
  • the present disclosure is directed to a method of metering flow in a wellbore.
  • the method includes heating select portions of a wellbore by directing energy to the select portions, and measuring a temperature at the select portions using a fiber optic cable.
  • the method also includes interpreting a flow rate from a temperature at the select portions as a function of the energy directed to the selected portions.
  • Figure 1 is a schematic illustration of a distributed flow metering system according to embodiments of the present disclosure.
  • Figure 2 is a cross-sectional view of a cable of a distributed flow metering system according to embodiments of the present disclosure.
  • Figure 3 is a schematic illustration of a distributed flow metering system having varying flow rates according to embodiments of the present disclosure.
  • Figure 4 is a graph of time and temperature using a curve-fitting technique according to embodiments of the present disclosure.
  • Figure 5 is a chart of time and phase for various configurations of the distributed flow metering system according to embodiments of the present disclosure.
  • Figure 6 illustrates two cable configurations for use with the distributed flow metering system according to embodiments of the present disclosure.
  • Figure 1 illustrates a cable 10 in a well 12 with fluid 14 being injected through a casing 16 into reservoir zones 18 according to embodiments of the present disclosure.
  • a similar arrangement can be implemented during production with the direction of flow being reversed.
  • the cable 10 cable is run into the well 12 and is interrogated from surface to determine the flow rate or velocity past the cable 10 at several points along the length of the cable 10.
  • the flow generally velocity decreases along the cable 10 with increasing distance from the surface as flow enters the reservoir from the well 12.
  • temperature may be measured at points along the cable 10 using an optical fiber contained within it.
  • DTS Distributed Temperature Sensor
  • Such a system may be used to determine flow rates during production by comparison to the background geothermal temperature distribution. However, this mode of operation may be less effective when injecting fluid or when the well is highly deviated.
  • FIG. 2 is a cross-sectional view of a cable 10 according to embodiments of the present disclosure.
  • the cable 10 includes multiple lines, such as a fiber line 20, a heating line 22, and a communication line 24. Any combination of lines can be used in a given embodiment.
  • the cable 10 can include insulation 26 and an outer cover 28.
  • the heating line 22 can be used to heat the cable to monitor flow.
  • the cable 10 may be heated by electrical, chemical or other means.
  • the embodiments of this disclosure describe several methods to interrogate a heated cable, and several refinements to the heated cable concept. These may be used to improve the reliability of the measurement and increase its feasibility in an operational environment.
  • a cable 10 may be placed into a well 12 as shown in Figure 1.
  • the cable 10 may also be permanently installed on production tubing, attached to the casing 16 or otherwise placed in the well 12.
  • the heating line 22 of the cable 10 can be used to heat the line, and the fiber 20 is used to make distributed measurements. Fluid flows past the cable 10 during production, injection, stimulation or cross-flow in the well 12.
  • the heating line 22 may be pulsed on and off using an electrical power supply placed at surface.
  • Figure 3 is a schematic representation of a distributed temperature sensing
  • the flow velocity past the cable 10 may be estimated by measuring the temperature difference between the condition when the heating is off and when it is on. The greater the flow velocity the smaller will be the temperature rise upon heating and, to a lesser extent, the faster the temperature rise.
  • flow rates are high, more of the thermal energy is carried away from the cable 10 during heating, resulting in a lower temperature at the site of the cable 10.
  • the size of the arrows in Figure 3 represents rates of flow and heat transfer.
  • Energy 30, in the form of electrical power or another suitable type, is directed down the cable 10 and into the formation.
  • the first site 31 results in a relatively low temperature 32, which is evidence of a high flow 34.
  • the second site 33 results in a relatively high temperature 36, evidencing a relatively lower flow rate 38.
  • DTS Distributed Temperature Sensing
  • the temperature rise due to heating can be measured using DTS. This may be achieved by establishing the equilibrium temperatures with the heating off and with the heating on.
  • the DTS typically has a relatively low temporal resolution, outputting a temperature distribution several times a minute. In many conditions there will be background temperature variations in addition to those caused by the cable heating.
  • the effect of these can be removed by fitting a pair of curves 39 and 41, for example polynomials, to a section of the temperature data of limited duration as shown in Figure 4.
  • the two curves can have identical parameters, except for a constant term which takes one of two values depending on whether the heating was on or off: the fitting procedure may be operated to adjust both these values independently in addition to the common parameters.
  • the fitted curves are used to detrend the data and also to determine the equilibrium temperature difference between the heating off and heating on conditions.
  • DTS distributed vibration
  • DAS distributed acoustic
  • the phase of the reflected light is measured and differentiated over distance along the fiber. At high frequencies this may give a measure of vibration while at low frequencies it may give a measure of temperature change.
  • Figure 5 shows an example of DVS data influenced by changes in temperature. In this case, an increase in temperature causes a negative change in phase.
  • measurements based on Coherent Rayleigh backscatter may give no absolute value of temperature. Instead they may give a measure of the temperature change.
  • the heating may preferably be repeatedly pulsed on and off with a known period.
  • the DVS data may then be segmented to match the pulse period and stacked.
  • the coherent Rayleigh measurement contributions due to vibration are generally random and of high frequency, and will be substantially removed by the stacking leaving only the effect of temperature changes.
  • the pulse on/off time will be related to the time constant of the heating/cooling process, for example a full on/off cycle may take place over 4 time constants.
  • the potentially high temporal and temperature resolutions of the DVS measurement may allow it to be used as a measure of transient flow.
  • the heating may be rapidly pulsed on and off and the resulting small temperature changes monitored using the DVS. From these the flow velocity and/or fluid type surrounding the cable may be determined at high temporal resolution.
  • One possible application of this is the tracking of gas slugs moving past or along the cable.
  • cable heating may cause thermal expansion which may be detected using a distributed strain measurement.
  • a higher flow velocity will cause a smaller temperature rise and hence a smaller thermal expansion.
  • a length of cable may remain on the deployment drum for anchoring.
  • An additional length of cable is in the upper part of the well and unlikely to measure flow of interest. It is therefore optimal to place maximum heating in the lower (far) section of cable. We can achieve this by changing the material of the heating element along its length. A low resistance material may be used for the first section, followed by a high resistance material in the far section.
  • the cable may be designed so as to allow electrical connection of the heating power to be made at or near the wellhead.
  • the connection may be galvanic, inductive or capacitive in nature
  • maximum heating power per unit length of cable may be sought.
  • the cable may be equipped with alternating sections of high and low resistance heating element, so focusing heating power in short sections. Additionally, such a cable will heat fluid as it passes the high resistance sections and then allow it to cool as it passes the low resistance sections.
  • the variation of temperature with distance is used to track the advection of warmed fluid along the cable, giving another measure of flow velocity. Such a method may be desirable when the flow velocity is very low and hence there is minimum fluid mixing.
  • the heating along the cable may also be possible to vary the heating along the cable by not only changing the conductor material but also changing the lay length of the resistive materials. Shorter lay lengths will give a higher density of resistive material and so more heating. Longer lay lengths will give a lower density of resistive material and so less heating. This approach could be used to give alternating high and low heating regions, and also to create a longer zone of increased heating within the cable.
  • FIG. 6 illustrates further embodiments in which a cable is modified to accommodate heating and measurement techniques disclosed herein.
  • a cable 40 has a heating element 44 on the outside of the cable 40 in the form of a metal tube through which current is passed.
  • a fiber 42 is placed inside the tube, measuring the temperature. The temperature will be generally uniform within the tube.
  • a cable 50 includes an outer coating 52, a heating element 54, armour wires 56, a return current path 58, and an optical fiber 60.
  • the heating element is included in the outer layers of the cable 50.
  • the heating element 54 can be in addition to the armour wires 56, or the armor wires 56 themselves could be used as the heating element.
  • connection means “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element”.
  • the terms “couple”, “coupling”, “coupled”, “coupled together”, and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements”.
  • the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the disclosure.

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  • Physics & Mathematics (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Fluid Mechanics (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Geophysics (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • General Physics & Mathematics (AREA)
  • Measuring Volume Flow (AREA)

Abstract

La présente invention concerne un système de mesure de flux réparti à l'aide d'un composant chauffant et d'un système de mesure de température. La vitesse de changement de température dans un câble est associée à un débit à travers un puits de forage. Le système comprend une combinaison entre une fibre optique et un câble d'élément chauffant conçue pour mesurer un flux à l'aide de la température et sans composant de mesure direct de flux.
PCT/US2015/023493 2014-03-31 2015-03-31 Mesure de flux thermique réparti WO2015153549A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201461973038P 2014-03-31 2014-03-31
US61/973,038 2014-03-31

Publications (1)

Publication Number Publication Date
WO2015153549A1 true WO2015153549A1 (fr) 2015-10-08

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Cited By (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2017131530A1 (fr) * 2016-02-16 2017-08-03 Wellstarter As Système et procédé de surveillance de fluide en temps réel
CN110185434A (zh) * 2019-05-23 2019-08-30 张建华 油气水井的流体注入或产出分布流量的测量装置及其方法
US10578464B2 (en) 2015-11-24 2020-03-03 Schlumberger Technology Corporation Identification of features on an optical fiber using a distributed temperature sensor
US10656041B2 (en) 2015-11-24 2020-05-19 Schlumberger Technology Corporation Detection of leaks from a pipeline using a distributed temperature sensor
US11353367B2 (en) 2015-12-23 2022-06-07 Optasense Holdings Limited Fibre optic temperature measurement
CN115128298A (zh) * 2022-07-06 2022-09-30 中国华能集团清洁能源技术研究院有限公司 一种测量地下水流速流向的测量装置
WO2023288122A1 (fr) * 2021-07-16 2023-01-19 Conocophillips Company Instrument de diagraphie de production passif utilisant la chaleur et la détection acoustique distribuée
WO2023091020A1 (fr) * 2021-11-22 2023-05-25 Wellstarter As Procédé de surveillance d'écoulement de fluide dans un conduit, et ensemble outil et système associés
EP4202380A1 (fr) * 2021-12-23 2023-06-28 Solexperts GmbH Débitmètre
US20230243989A1 (en) * 2022-01-31 2023-08-03 Halliburton Energy Services, Inc. Simultaneous distributed acoustic sensing with multiple gauge lengths

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20060071158A1 (en) * 2003-03-05 2006-04-06 Van Der Spek Alexander M Coiled optical fiber assembly for measuring pressure and/or other physical data
US20070110355A1 (en) * 2003-08-11 2007-05-17 Kari-Miko Jaaskelainen Method for installing a double ended distributed sensing fiber optical assembly within a guide conduit
US20080185138A1 (en) * 2007-02-07 2008-08-07 Vladimir Hernandez-Solis Active Cable for Wellbore Heating and Distributed Temperature Sensing
US20110048136A1 (en) * 2007-10-31 2011-03-03 William Birch Pressure sensor assembly and method of using the assembly
US20120277995A1 (en) * 2007-11-02 2012-11-01 Schlumberger Technology Corporation Systems and methods for distributed interferometric acoustic monitoring

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20060071158A1 (en) * 2003-03-05 2006-04-06 Van Der Spek Alexander M Coiled optical fiber assembly for measuring pressure and/or other physical data
US20070110355A1 (en) * 2003-08-11 2007-05-17 Kari-Miko Jaaskelainen Method for installing a double ended distributed sensing fiber optical assembly within a guide conduit
US20080185138A1 (en) * 2007-02-07 2008-08-07 Vladimir Hernandez-Solis Active Cable for Wellbore Heating and Distributed Temperature Sensing
US20110048136A1 (en) * 2007-10-31 2011-03-03 William Birch Pressure sensor assembly and method of using the assembly
US20120277995A1 (en) * 2007-11-02 2012-11-01 Schlumberger Technology Corporation Systems and methods for distributed interferometric acoustic monitoring

Cited By (17)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10578464B2 (en) 2015-11-24 2020-03-03 Schlumberger Technology Corporation Identification of features on an optical fiber using a distributed temperature sensor
US10656041B2 (en) 2015-11-24 2020-05-19 Schlumberger Technology Corporation Detection of leaks from a pipeline using a distributed temperature sensor
US11353367B2 (en) 2015-12-23 2022-06-07 Optasense Holdings Limited Fibre optic temperature measurement
AU2017210891B2 (en) * 2016-02-16 2022-09-08 Wellstarter As A real-time fluid monitoring system and method
JP2019504955A (ja) * 2016-02-16 2019-02-21 ウェルスターター・アーエス リアルタイム流体監視システムおよび方法
GB2563544A (en) * 2016-02-16 2018-12-19 Wellstarter As A real-time fluid monitoring system and method
GB2563544B (en) * 2016-02-16 2020-06-24 Wellstarter As A real-time fluid monitoring system and method
US10697291B2 (en) 2016-02-16 2020-06-30 Wellstarter As Real-time fluid monitoring system and method
WO2017131530A1 (fr) * 2016-02-16 2017-08-03 Wellstarter As Système et procédé de surveillance de fluide en temps réel
CN110185434A (zh) * 2019-05-23 2019-08-30 张建华 油气水井的流体注入或产出分布流量的测量装置及其方法
WO2023288122A1 (fr) * 2021-07-16 2023-01-19 Conocophillips Company Instrument de diagraphie de production passif utilisant la chaleur et la détection acoustique distribuée
US11802783B2 (en) 2021-07-16 2023-10-31 Conocophillips Company Passive production logging instrument using heat and distributed acoustic sensing
WO2023091020A1 (fr) * 2021-11-22 2023-05-25 Wellstarter As Procédé de surveillance d'écoulement de fluide dans un conduit, et ensemble outil et système associés
EP4202380A1 (fr) * 2021-12-23 2023-06-28 Solexperts GmbH Débitmètre
US20230243989A1 (en) * 2022-01-31 2023-08-03 Halliburton Energy Services, Inc. Simultaneous distributed acoustic sensing with multiple gauge lengths
US12092779B2 (en) * 2022-01-31 2024-09-17 Halliburton Energy Services, Inc. Simultaneous distributed acoustic sensing with multiple gauge lengths
CN115128298A (zh) * 2022-07-06 2022-09-30 中国华能集团清洁能源技术研究院有限公司 一种测量地下水流速流向的测量装置

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