US20070283751A1 - Downhole Flow Measurement In A Well - Google Patents

Downhole Flow Measurement In A Well Download PDF

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Publication number
US20070283751A1
US20070283751A1 US10/584,110 US58411004A US2007283751A1 US 20070283751 A1 US20070283751 A1 US 20070283751A1 US 58411004 A US58411004 A US 58411004A US 2007283751 A1 US2007283751 A1 US 2007283751A1
Authority
US
United States
Prior art keywords
well
inflow region
fluctuations
length
dts
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.)
Abandoned
Application number
US10/584,110
Inventor
Alexander Van Der Spek
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell USA Inc
Original Assignee
Individual
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 Individual filed Critical Individual
Assigned to SHELL OIL COMPANY reassignment SHELL OIL COMPANY ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: VAN DER SPEK, ALEXANDER MICHAEL
Publication of US20070283751A1 publication Critical patent/US20070283751A1/en
Abandoned legal-status Critical Current

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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
    • G01F1/704—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 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
  • 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.
  • 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.
  • DTS fibre optical distributed temperature sensor
  • 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.
  • 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

    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 (7)

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 a 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 claim 1, wherein the well is a hydrocarbon fluid production well.
6. The method of claim 1, 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 or processing equipment downstream of the wellhead.
US10/584,110 2003-12-24 2004-12-22 Downhole Flow Measurement In A Well Abandoned US20070283751A1 (en)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
EP03104971 2003-12-24
EP03104971.1 2003-12-24
PCT/EP2004/053672 WO2005064116A1 (en) 2003-12-24 2004-12-22 Downhole flow measurement in a well

Publications (1)

Publication Number Publication Date
US20070283751A1 true US20070283751A1 (en) 2007-12-13

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ID=34717256

Family Applications (1)

Application Number Title Priority Date Filing Date
US10/584,110 Abandoned US20070283751A1 (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)

Cited By (10)

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US20120016587A1 (en) * 2010-07-14 2012-01-19 Halliburton Energy Services, Inc. Resolution enhancement for subterranean well distributed optical measurements
US8978749B2 (en) 2012-09-19 2015-03-17 Halliburton Energy Services, Inc. Perforation gun string energy propagation management with tuned mass damper
US8978817B2 (en) 2012-12-01 2015-03-17 Halliburton Energy Services, Inc. Protection of electronic devices used with perforating guns
US8985200B2 (en) 2010-12-17 2015-03-24 Halliburton Energy Services, Inc. Sensing shock during well perforating
US8997585B2 (en) 2010-05-26 2015-04-07 Fotech Solutions Limited Fluid flow monitor
US9003874B2 (en) 2010-07-19 2015-04-14 Halliburton Energy Services, Inc. Communication through an enclosure of a line
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
GB2580445A (en) * 2019-05-28 2020-07-22 Equinor Energy As Flow rate determination

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GB2416871A (en) 2004-07-29 2006-02-08 Schlumberger Holdings Well characterisation using distributed temperature sensor data
US7793718B2 (en) 2006-03-30 2010-09-14 Schlumberger Technology Corporation Communicating electrical energy with an electrical device in a well
US8056619B2 (en) 2006-03-30 2011-11-15 Schlumberger Technology Corporation Aligning inductive couplers in a well
US8121790B2 (en) 2007-11-27 2012-02-21 Schlumberger Technology Corporation Combining reservoir modeling with downhole sensors and inductive coupling
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
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
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
WO2015040041A2 (en) 2013-09-17 2015-03-26 Mærsk Olie Og Gas A/S A system and a method for determining inflow distribution in an openhole completed well

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US6497279B1 (en) * 1998-08-25 2002-12-24 Sensor Highway Limited Method of using a heater with a fiber optic string in a wellbore
US20030140711A1 (en) * 2000-03-30 2003-07-31 Brown George A Method and apparatus for flow measurement
US20030236626A1 (en) * 2002-06-21 2003-12-25 Schroeder Robert J. Technique and system for measuring a characteristic in a subterranean well
US20040129424A1 (en) * 2002-11-05 2004-07-08 Hosie David G. Instrumentation for a downhole deployment valve
US20040140092A1 (en) * 2003-01-21 2004-07-22 Robison Clark E. Linear displacement measurement method and apparatus
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US20060214098A1 (en) * 2003-04-23 2006-09-28 Rogerio Ramos Fluid flow measurement using optical fibres
US7240547B2 (en) * 2004-07-17 2007-07-10 Schlumberger Technology Corp. Method and apparatus for measuring fluid properties

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DE69914462T2 (en) * 1998-03-06 2004-07-01 Shell Internationale Research Maatschappij B.V. ACCESS DETECTION DEVICE AND IMPLEMENTATION SYSTEM
GB9916022D0 (en) * 1999-07-09 1999-09-08 Sensor Highway Ltd Method and apparatus for determining flow rates
US8011430B2 (en) * 2003-03-28 2011-09-06 Schlumberger Technology Corporation Method to measure injector inflow profiles
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US6497279B1 (en) * 1998-08-25 2002-12-24 Sensor Highway Limited Method of using a heater with a fiber optic string in a wellbore
US20030140711A1 (en) * 2000-03-30 2003-07-31 Brown George A Method and apparatus for flow measurement
US6826954B2 (en) * 2000-03-30 2004-12-07 Sensor Highway Limited Method and apparatus for flow measurement
US6751556B2 (en) * 2002-06-21 2004-06-15 Sensor Highway Limited Technique and system for measuring a characteristic in a subterranean well
US20030236626A1 (en) * 2002-06-21 2003-12-25 Schroeder Robert J. Technique and system for measuring a characteristic in a subterranean well
US20040129424A1 (en) * 2002-11-05 2004-07-08 Hosie David G. Instrumentation for a downhole deployment valve
US6997256B2 (en) * 2002-12-17 2006-02-14 Sensor Highway Limited Use of fiber optics in deviated flows
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Cited By (14)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8997585B2 (en) 2010-05-26 2015-04-07 Fotech Solutions Limited Fluid flow monitor
US8930143B2 (en) * 2010-07-14 2015-01-06 Halliburton Energy Services, Inc. Resolution enhancement for subterranean well distributed optical measurements
US20120016587A1 (en) * 2010-07-14 2012-01-19 Halliburton Energy Services, Inc. Resolution enhancement for subterranean well distributed optical measurements
US9003874B2 (en) 2010-07-19 2015-04-14 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
US8978817B2 (en) 2012-12-01 2015-03-17 Halliburton Energy Services, Inc. Protection of electronic devices used with perforating guns
US9447678B2 (en) 2012-12-01 2016-09-20 Halliburton Energy Services, Inc. Protection of electronic devices used with perforating guns
US9909408B2 (en) 2012-12-01 2018-03-06 Halliburton Energy Service, Inc. Protection of electronic devices used with perforating guns
US9926777B2 (en) 2012-12-01 2018-03-27 Halliburton Energy Services, Inc. Protection of electronic devices used with perforating guns
GB2580445A (en) * 2019-05-28 2020-07-22 Equinor Energy As Flow rate determination

Also Published As

Publication number Publication date
BRPI0418076A (en) 2007-04-17
CN1898455A (en) 2007-01-17
CA2551282A1 (en) 2005-07-14
WO2005064116A1 (en) 2005-07-14
GB2426047B (en) 2007-07-25
GB2426047A (en) 2006-11-15
GB0612514D0 (en) 2006-08-16
AU2004309117B2 (en) 2007-09-13
AU2004309117A1 (en) 2005-07-14

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AS Assignment

Owner name: SHELL OIL COMPANY, TEXAS

Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:VAN DER SPEK, ALEXANDER MICHAEL;REEL/FRAME:019765/0245

Effective date: 20061103

STCB Information on status: application discontinuation

Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION