WO2005064116A1 - Downhole flow measurement in a well - Google Patents

Downhole flow measurement in a well Download PDF

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Publication number
WO2005064116A1
WO2005064116A1 PCT/EP2004/053672 EP2004053672W WO2005064116A1 WO 2005064116 A1 WO2005064116 A1 WO 2005064116A1 EP 2004053672 W EP2004053672 W EP 2004053672W WO 2005064116 A1 WO2005064116 A1 WO 2005064116A1
Authority
WO
WIPO (PCT)
Prior art keywords
well
inflow region
fluctuations
length
dts
Prior art date
Application number
PCT/EP2004/053672
Other languages
French (fr)
Inventor
Alexander Michael Van Der Spek
Original Assignee
Shell Internationale Research Maatschappij B.V.
Shell Canada Limited
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 Shell Internationale Research Maatschappij B.V., Shell Canada Limited filed Critical Shell Internationale Research Maatschappij B.V.
Priority to GB0612514A priority Critical patent/GB2426047B/en
Priority to US10/584,110 priority patent/US20070283751A1/en
Priority to BRPI0418076-3A priority patent/BRPI0418076A/en
Priority to CA002551282A priority patent/CA2551282A1/en
Priority to AU2004309117A priority patent/AU2004309117B2/en
Publication of WO2005064116A1 publication Critical patent/WO2005064116A1/en

Links

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
    • G01F1/704—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow using marked regions or existing inhomogeneities within the fluid stream, e.g. statistically occurring variations in a fluid parameter
    • G01F1/708—Measuring the time taken to traverse a fixed distance
    • G01F1/7084—Measuring the time taken to traverse a fixed distance using thermal detecting arrangements
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP 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
    • 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
    • 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
    • G01F1/74—Devices for measuring flow of a fluid or flow of a fluent solid material in suspension in another fluid

Definitions

  • the invention relates to a method for downhole flow measurement in a well.
  • a method for downhole flow measurement in a well is known from International patent application WO 01/75403.
  • a fibre optical cable extends in longitudinal direction through the well and is configured as a distributed temperature sensor ("DTS") , wherein one or more light pulses are transmitted through the fibre optical cable and the temperature pattern along the length of the cable is determined on the basis of determination of the intensity of Raman peaks in the backscattered optical signal.
  • DTS distributed temperature sensor
  • a DTS system In a DTS system the time of flight of the backscattered signal is used to determine the location from where the signal is backscattered in a manner similar to the operation of a radar system.
  • the DTS system measures the speed at which the cold spot imposed at each cooling station migrates in downstream direction through the production tubing.
  • a disadvantage of the known method is that the installation of one or more cooling stations and a nitrogen or other cooling fluid supply line in a well is expensive and fragile and thus prone to damage. It is an object of the present invention to provide a method of downhole flow measurement in a well, which does not require the installation of one or more cooling stations and fragile cooling fluid supply conduits downhole in the well.
  • the method according to the invention for downhole flow measurement in a well comprises installing a fibre optical distributed temperature sensor (DTS) system along at least part of the length of an inflow region of the well and using the sensor to measure one or more fluctuations of the temperature of fluids flowing from the formation into the well and the velocity at which at least one of said natural fluctuations migrates in downstream direction through the well. It has surprisingly been found that there are fluctuations of the temperature of the fluids that flow into the well, which fluctuations generally die out before the produced fluids have reached the wellhead.
  • DTS fibre optical distributed temperature sensor
  • the temperature fluctuations are generally small and may be less than 1 Degree Celsius. Accordingly it is preferred that the DTS system is configured to track the downstream migration through the well of low frequency temperature fluctuations of less than 1 Degree Celsius, typically fluctuations between 0.1 and 0.5 Degrees Celsius. It is also preferred that the DTS system extends along at least a substantial part of the length of an inflow region of the well and that the method is used to assess the fluid inflow rate at different locations along the length of the inflow region on the basis of measured variations of the velocity of the fluids in a longitudinal direction along at least part of the length of said inflow region.
  • a stationary flowrate of fluids in downstream direction along a DTS measurement interval will generally indicate that no fluid flows into the measurement interval, whereas an increased flowrate in downstream direction along a DTS measurement interval will generally indicate that fluids flow from the formation into the well along the length of the measurement interval.
  • the method according to the invention may be applied to monitor the fluid flow rate and inflow rate downhole in a hydrocarbon fluid production well.
  • the fluids flowing into the well may comprise gaseous components, such as natural gas, and/or components which at least partly evaporate in the inflow region.
  • the fluid production rate of the well may be cyclically varied over time to impose temperature fluctuations caused by variation of the expansion and/or evaporation rate of the gaseous and/or evaporating fluids.
  • the fluid production rate of the well may be cyclically varied by cyclic variation of the opening of a production choke or downhole valve or by initiating a slug flow regime in the well or in the production flowline and/or processing equipment downstream of the wellhead.

Abstract

A method for downhole flow measurement comprises installing a fibre optical distributed temperature sensor (DTS) system along at least part of the length of an inflow region of the well and using the sensor to measure fluctuations of the temperature of fluids flowing from the formation into the well and the velocity at which said natural fluctuations migrate in downstream direction through the well. The measured temperature variations may be low frequency temperature fluctuations of between 0.1 and 0.5 Degrees Celsius, which gradually die out downstream of the inflow region(s) of the well.

Description

DOWNHOLE FLOW MEASUREMENT IN A WELL
BACKGROUND OF THE INVENTION The invention relates to a method for downhole flow measurement in a well. Such a method is known from International patent application WO 01/75403. In the known method one or more cold spots are created in a well tubing by injecting nitrogen into the well and expanding the nitrogen at selected downhole cooling stations. A fibre optical cable extends in longitudinal direction through the well and is configured as a distributed temperature sensor ("DTS") , wherein one or more light pulses are transmitted through the fibre optical cable and the temperature pattern along the length of the cable is determined on the basis of determination of the intensity of Raman peaks in the backscattered optical signal. In a DTS system the time of flight of the backscattered signal is used to determine the location from where the signal is backscattered in a manner similar to the operation of a radar system. In the known method the DTS system measures the speed at which the cold spot imposed at each cooling station migrates in downstream direction through the production tubing. A disadvantage of the known method is that the installation of one or more cooling stations and a nitrogen or other cooling fluid supply line in a well is expensive and fragile and thus prone to damage. It is an object of the present invention to provide a method of downhole flow measurement in a well, which does not require the installation of one or more cooling stations and fragile cooling fluid supply conduits downhole in the well. It is a further object of the invention to provide a method for measuring the influx of fluids into the well along at least part of an inflow region along which fluids flow from the surrounding formation into the well. SUMMARY OF THE INVENTION The method according to the invention for downhole flow measurement in a well comprises installing a fibre optical distributed temperature sensor (DTS) system along at least part of the length of an inflow region of the well and using the sensor to measure one or more fluctuations of the temperature of fluids flowing from the formation into the well and the velocity at which at least one of said natural fluctuations migrates in downstream direction through the well. It has surprisingly been found that there are fluctuations of the temperature of the fluids that flow into the well, which fluctuations generally die out before the produced fluids have reached the wellhead. The temperature fluctuations are generally small and may be less than 1 Degree Celsius. Accordingly it is preferred that the DTS system is configured to track the downstream migration through the well of low frequency temperature fluctuations of less than 1 Degree Celsius, typically fluctuations between 0.1 and 0.5 Degrees Celsius. It is also preferred that the DTS system extends along at least a substantial part of the length of an inflow region of the well and that the method is used to assess the fluid inflow rate at different locations along the length of the inflow region on the basis of measured variations of the velocity of the fluids in a longitudinal direction along at least part of the length of said inflow region. A stationary flowrate of fluids in downstream direction along a DTS measurement interval will generally indicate that no fluid flows into the measurement interval, whereas an increased flowrate in downstream direction along a DTS measurement interval will generally indicate that fluids flow from the formation into the well along the length of the measurement interval. The method according to the invention may be applied to monitor the fluid flow rate and inflow rate downhole in a hydrocarbon fluid production well. The fluids flowing into the well may comprise gaseous components, such as natural gas, and/or components which at least partly evaporate in the inflow region. In such case the fluid production rate of the well may be cyclically varied over time to impose temperature fluctuations caused by variation of the expansion and/or evaporation rate of the gaseous and/or evaporating fluids. In such case the fluid production rate of the well may be cyclically varied by cyclic variation of the opening of a production choke or downhole valve or by initiating a slug flow regime in the well or in the production flowline and/or processing equipment downstream of the wellhead. These and other features, embodiments and advantages of the downhole flow monitoring method according to the invention are described in the accompanying claims and abstract.

Claims

C L I M S
1. A method for downhole flow measurement in a well, the method comprising installing a fibre optical distributed temperature sensor (DTS) system along at least part of the length of an inflow region of the well and using the sensor to measure one or more fluctuations of the temperature of fluids flowing from the formation into the well and the velocity at which at least one of said natural fluctuations migrates in downstream direction through the well.
2. The method of claim 1, wherein the DTS system is configured to track the downstream migration through the well of low frequency temperature fluctuations of less than 1 Degree Celsius.
3. The method of claim 2, wherein the DTS system is configured to track the downstream migration through the well of natural low frequency temperature variations between 0.1 and 0.5 Degrees Celsius.
4. The method of claim 1, wherein the DTS system extends along at least a substantial part of the length of an inflow region of the well and the method is used to assess the fluid inflow rate at different locations along the length of the inflow region on the basis of measured variations of the velocity of the fluids in a longitudinal direction along at least part of the length of said inflow region.
5. The method of any preceding claim, wherein the well is a hydrocarbon fluid production well.
6. The method of any preceeding claim, wherein the fluids flowing into the well comprise gaseous components and or components which at least partly evaporate in the inflow region and the fluid production rate of the well is cyclically varied over time.
7. The method of claim 6, wherein the fluid production rate of the well is cyclically varied by cyclic variation of the opening of a production choke or downhole valve or by initiating a slug flow regime in the well or in the production flowline and/or processing equipment downstream of the wellhead.
PCT/EP2004/053672 2003-12-24 2004-12-22 Downhole flow measurement in a well WO2005064116A1 (en)

Priority Applications (5)

Application Number Priority Date Filing Date Title
GB0612514A GB2426047B (en) 2003-12-24 2004-12-22 Downhole flow measurement in a well
US10/584,110 US20070283751A1 (en) 2003-12-24 2004-12-22 Downhole Flow Measurement In A Well
BRPI0418076-3A BRPI0418076A (en) 2003-12-24 2004-12-22 method for measuring downhole flow in a well
CA002551282A CA2551282A1 (en) 2003-12-24 2004-12-22 Downhole flow measurement in a well
AU2004309117A AU2004309117B2 (en) 2003-12-24 2004-12-22 Downhole flow measurement in a well

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
EP03104971 2003-12-24
EP03104971.1 2003-12-24

Publications (1)

Publication Number Publication Date
WO2005064116A1 true WO2005064116A1 (en) 2005-07-14

Family

ID=34717256

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/EP2004/053672 WO2005064116A1 (en) 2003-12-24 2004-12-22 Downhole flow measurement in a well

Country Status (7)

Country Link
US (1) US20070283751A1 (en)
CN (1) CN1898455A (en)
AU (1) AU2004309117B2 (en)
BR (1) BRPI0418076A (en)
CA (1) CA2551282A1 (en)
GB (1) GB2426047B (en)
WO (1) WO2005064116A1 (en)

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WO2006010875A1 (en) * 2004-07-29 2006-02-02 Schlumberger Holdings Limited Well characterisation method
US8121790B2 (en) 2007-11-27 2012-02-21 Schlumberger Technology Corporation Combining reservoir modeling with downhole sensors and inductive coupling
US8235127B2 (en) 2006-03-30 2012-08-07 Schlumberger Technology Corporation Communicating electrical energy with an electrical device in a well
US8783355B2 (en) 2010-02-22 2014-07-22 Schlumberger Technology Corporation Virtual flowmeter for a well
US8839850B2 (en) 2009-10-07 2014-09-23 Schlumberger Technology Corporation Active integrated completion installation system and method
US9175523B2 (en) 2006-03-30 2015-11-03 Schlumberger Technology Corporation Aligning inductive couplers in a well
US9175560B2 (en) 2012-01-26 2015-11-03 Schlumberger Technology Corporation Providing coupler portions along a structure
US9249559B2 (en) 2011-10-04 2016-02-02 Schlumberger Technology Corporation Providing equipment in lateral branches of a well
US9644476B2 (en) 2012-01-23 2017-05-09 Schlumberger Technology Corporation Structures having cavities containing coupler portions
US9938823B2 (en) 2012-02-15 2018-04-10 Schlumberger Technology Corporation Communicating power and data to a component in a well
US10036234B2 (en) 2012-06-08 2018-07-31 Schlumberger Technology Corporation Lateral wellbore completion apparatus and method

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EP2223126B1 (en) * 2007-12-07 2018-08-01 Landmark Graphics Corporation, A Halliburton Company Systems and methods for utilizing cell based flow simulation results to calculate streamline trajectories
CN101338668B (en) * 2008-08-29 2012-02-22 北京豪仪测控工程有限公司 Method and system for determining drilling fluids leakage and overflow
GB201008823D0 (en) 2010-05-26 2010-07-14 Fotech Solutions Ltd Fluid flow monitor
US8930143B2 (en) * 2010-07-14 2015-01-06 Halliburton Energy Services, Inc. Resolution enhancement for subterranean well distributed optical measurements
US8584519B2 (en) 2010-07-19 2013-11-19 Halliburton Energy Services, Inc. Communication through an enclosure of a line
US8985200B2 (en) 2010-12-17 2015-03-24 Halliburton Energy Services, Inc. Sensing shock during well perforating
US9091152B2 (en) 2011-08-31 2015-07-28 Halliburton Energy Services, Inc. Perforating gun with internal shock mitigation
US9297228B2 (en) 2012-04-03 2016-03-29 Halliburton Energy Services, Inc. Shock attenuator for gun system
US9598940B2 (en) 2012-09-19 2017-03-21 Halliburton Energy Services, Inc. Perforation gun string energy propagation management system and methods
US8978749B2 (en) 2012-09-19 2015-03-17 Halliburton Energy Services, Inc. Perforation gun string energy propagation management with tuned mass damper
WO2014084868A1 (en) 2012-12-01 2014-06-05 Halliburton Energy Services, Inc. Protection of electronic devices used with perforating guns
EP3047098B1 (en) * 2013-09-17 2021-03-03 Total E&P Danmark A/S A system and a method for determining inflow distribution in an openhole completed well
GB2580445A (en) * 2019-05-28 2020-07-22 Equinor Energy As Flow rate determination

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Cited By (13)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2006010875A1 (en) * 2004-07-29 2006-02-02 Schlumberger Holdings Limited Well characterisation method
US7778780B2 (en) 2004-07-29 2010-08-17 Schlumberger Technology Corporation Well characterisation method
US9175523B2 (en) 2006-03-30 2015-11-03 Schlumberger Technology Corporation Aligning inductive couplers in a well
US8235127B2 (en) 2006-03-30 2012-08-07 Schlumberger Technology Corporation Communicating electrical energy with an electrical device in a well
US8121790B2 (en) 2007-11-27 2012-02-21 Schlumberger Technology Corporation Combining reservoir modeling with downhole sensors and inductive coupling
US8839850B2 (en) 2009-10-07 2014-09-23 Schlumberger Technology Corporation Active integrated completion installation system and method
US8783355B2 (en) 2010-02-22 2014-07-22 Schlumberger Technology Corporation Virtual flowmeter for a well
US10669837B2 (en) 2010-02-22 2020-06-02 Schlumberger Technology Corporation Virtual flowmeter for a well
US9249559B2 (en) 2011-10-04 2016-02-02 Schlumberger Technology Corporation Providing equipment in lateral branches of a well
US9644476B2 (en) 2012-01-23 2017-05-09 Schlumberger Technology Corporation Structures having cavities containing coupler portions
US9175560B2 (en) 2012-01-26 2015-11-03 Schlumberger Technology Corporation Providing coupler portions along a structure
US9938823B2 (en) 2012-02-15 2018-04-10 Schlumberger Technology Corporation Communicating power and data to a component in a well
US10036234B2 (en) 2012-06-08 2018-07-31 Schlumberger Technology Corporation Lateral wellbore completion apparatus and method

Also Published As

Publication number Publication date
BRPI0418076A (en) 2007-04-17
US20070283751A1 (en) 2007-12-13
CN1898455A (en) 2007-01-17
AU2004309117A1 (en) 2005-07-14
AU2004309117B2 (en) 2007-09-13
GB0612514D0 (en) 2006-08-16
GB2426047A (en) 2006-11-15
GB2426047B (en) 2007-07-25
CA2551282A1 (en) 2005-07-14

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