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US20130020075A1 - Pulsed Neutron Monitoring of Hydraulic Fracturing and Acid Treatment - Google Patents

Pulsed Neutron Monitoring of Hydraulic Fracturing and Acid Treatment Download PDF

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Publication number
US20130020075A1
US20130020075A1 US13/551,105 US201213551105A US2013020075A1 US 20130020075 A1 US20130020075 A1 US 20130020075A1 US 201213551105 A US201213551105 A US 201213551105A US 2013020075 A1 US2013020075 A1 US 2013020075A1
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United States
Prior art keywords
formation
borehole
detector
fluid
parameter
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
US13/551,105
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English (en)
Inventor
David M. Chace
Daryl D. McCracken
Ansgar Baule
Freeman L. Hill
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.)
Baker Hughes Holdings LLC
Original Assignee
Baker Hughes Inc
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 Baker Hughes Inc filed Critical Baker Hughes Inc
Priority to US13/551,105 priority Critical patent/US20130020075A1/en
Priority to PCT/US2012/047122 priority patent/WO2013012888A2/fr
Priority to CA2841956A priority patent/CA2841956A1/fr
Assigned to BAKER HUGHES INCORPORATED reassignment BAKER HUGHES INCORPORATED ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: MCCRACKEN, DARYL D., BAULE, ANSGAR, CHACE, DAVID M., HILL, FREEMAN L.
Publication of US20130020075A1 publication Critical patent/US20130020075A1/en
Abandoned legal-status Critical Current

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    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • 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
    • 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
    • E21B47/11—Locating fluid leaks, intrusions or movements using tracers; using radioactivity

Definitions

  • This disclosure relates to well logging methods and apparatus and more particularly to nuclear well logging techniques and well completion monitoring techniques. Specifically, the disclosure is directed towards the use of pulsed neutron methods for monitoring flow rates in the borehole indicative of the effectiveness of hydraulic fracturing, acid treatment, and polymer treatment.
  • Hydraulic fracturing of boreholes is a commonly used completion technique.
  • the fracturing may be done in either open-hole or cased hole.
  • open-hole fracturing the objective may be to increase the permeability of the earth formation over a fairly large interval.
  • Hydraulic fracturing of cased holes is commonly done when it is desired to increase the permeability of the earth formation at different depths in the borehole.
  • cased-hole fracturing the casing is perforated to produce weak points in the casing. Hydraulic fracturing, in both cases, is then carried out by increasing fluid pressure in the borehole.
  • Hydraulic fracturing can be performed using coiled tubing on multiple perforated intervals in a single stage. Hydraulic fracturing or “Frac” jobs often included multiple stages. The success of the frac job (e.g. number of intervals fractured and relative ability to produce/inject) can be determined by running production logs after the frac operation is complete.
  • an acid (usually HCl) is injected into a carbonate formation at a pressure above the formation fracture in pressure.
  • the acid may form conductive channels in the formation that remain open without a propagation of the fracture process.
  • matrix acidizing refers to the treatment of a reservoir formation, with an acid.
  • the acid reacts with soluble substances in the formation matrix and enlarges the pore spaces.
  • the acid may dissolve the entire formation matrix. In both cases, the acidizing improves the formation permeability. Matrix acidizing is done at a pressure below the fracture pressure of the formation, which reduces possible reservoir damage.
  • Hydraulic fracturing and acidizing are typically carried out using fluids conveyed on coiled tubing.
  • Another operation that may be carried out using fluids conveyed in coiled tubing is that of polymer injection.
  • the objective of polymer injection may include sealing off highly permeable zones using a polymer. Due to the difficulties associated with injecting coiled tubing into a borehole and removing coiled tubing from the borehole, it may be desirable to monitor the effectiveness of the hydraulic fracturing, acidizing, and polymer injection substantially simultaneously with the fracturing, acidizing, and polymer injection operations.
  • hydraulic fracturing, acidizing operations, and polymer injection are referred to as formation modification operations. The present disclosure satisfies the need for monitoring such operations.
  • One embodiment of the disclosure is a method of monitoring a formation modification operation in a borehole.
  • the method includes: modifying a formation using a fluid conveyed into the borehole; making measurements indicative of a flow velocity of the fluid in an annulus between an instrument conveyed in the borehole and a wall of the borehole, the instrument including a radiation source; and estimating at least one parameter of the formation modification operation using the measurements at a plurality of positions along the borehole.
  • the apparatus includes: a wellbore tubular configured to convey a fluid in the borehole and modify the formation; an instrument including a radiation source configured to be conveyed in the borehole and to make measurements indicative of a flow velocity of the fluid in an annulus between the instrument and a wall of the borehole; and a processor configured to: estimate at least one parameter of the formation modification operation using the measurements at a plurality of positions along the borehole.
  • Another embodiment of the disclosure is a non-transitory computer-readable medium product having instructions thereon that when read by a processor cause the processor to execute a method.
  • the method includes: modifying a formation using a fluid conveyed into a borehole; making measurements indicative of a flow velocity of the fluid in an annulus between an instrument conveyed in the borehole and a wall of the borehole, the instrument including a radiation source; and estimating at least one parameter of the formation modification operation using the measurements at a plurality of positions along the borehole.
  • Another embodiment of the disclosure is a method of monitoring a formation modification operation in a borehole.
  • the method includes: acquiring information relating to the formation modification using an instrument conveyed in the borehole penetrating the formation; and estimating at least one parameter of interest related to the formation modification using the acquired information, wherein the information is acquired at a plurality of positions along the borehole.
  • FIG. 1 is an exemplary schematic diagram of an apparatus suitable for use with one embodiment of the present disclosure
  • FIG. 2 is a schematic illustration of temporal signals (after normalization) measured at two spaced apart detectors
  • FIG. 3 illustrates a situation where the near detector is immediately responsive to source activation
  • FIGS. 4( a ) and 4 ( b ) illustrate changes in flow rate measured by a pulsed neutron instrument in a fractured portion of a borehole
  • FIG. 5 shows an exemplary apparatus suitable for monitoring of acid treatment.
  • FIG. 1 is an exemplary schematic diagram of an apparatus suitable for use with one embodiment of the present disclosure. This embodiment is directed to the evaluation of a fracturing operation being carried out in a previously perforated cased borehole. Shown therein is an earth formation 101 with a borehole 102 . Inside the borehole is a casing 103 .
  • the casing includes two exemplary perforated sections. The first section includes perforations 105 a , 105 b , 105 c , and 105 d .
  • the second perforated section includes perforations 115 a , 115 b , 115 c , and 115 d.
  • the fracturing operations may be carried out by fluid injected 163 into the borehole through a suitable wellbore tubular, such as coiled tubing 131 .
  • Suitable wellbore tubular may include, but are not limited to, coiled tubing, jointed tubulars, production tubing, and casing liners.
  • An instrument such as sensor unit 135 , may be configured to estimate a parameter of interest in the annulus between the instrument and the wall of borehole 102 .
  • a sensor unit 135 is disposed at the end of the coiled tubing 131 . Space is provided in the annulus between the sensor unit 135 and the inside of an enlarged section of the coiled tubing 131 for the injection fluid to flow into the borehole 102 .
  • the injected fluid 163 returns up the borehole as indicated by arrows 161 through the annulus between the coiled tubing 131 and the casing 103 . In doing so, the returning fluid 161 flows by the perforations in the casing 103 .
  • the sensor unit 135 may include a source of pulsed neutrons 151 , and two or more gamma ray detectors 153 , 155 , 157 , that are commonly referred to as the short spacing (SS), long-spacing (LS), and extra long spacing (XLS) detectors.
  • sensor unit 135 may include additional detectors, such as, but not limited to, one or more of: acoustic detectors, nuclear magnetic resonance detectors, electric field detectors, and magnetic field detectors.
  • a signal processor 122 is installed in the sensor 135 .
  • the detector count rates are digitized downhole and are telemetrically transmitted to the surface through suitable conductors in wireline 133 to processing and archival storage unit at the surface (not shown). Alternatively, all the processing may be done by the downhole processor 122 and the results stored in a downhole memory for subsequent retrieval.
  • the processor, acoustic telemetry may be used to communicate data to the surface through the coiled tubing 131 .
  • Activation of the pulsed neutron source 151 activates elemental oxygen- 16 in the fluid flow 161 .
  • the gamma ray detectors 153 , 155 , 157 may detect the decay of the unstable isotope nitrogen- 16 .
  • the neutron source 151 may be ramped up to a maximum level over a ten second interval, maintained at a substantially constant value for twenty to forty seconds or so, and then ramped down over a ten second interval.
  • the source activation and deactivation may be substantially instantaneous.
  • Each of the detectors 153 , 155 , 157 may measure count rates or signals. Count rates from each of the detectors 153 , 155 , 157 are accumulated by a processor over a suitable time sampling interval. In one embodiment of the disclosure, the temporal sampling interval is 0.5 seconds. These count rates are made over a suitable energy level. In one embodiment of the disclosure, received gamma rays having energies above 3.0 MeV are counted. The upper limit of the energy window may be 8 MeV or so. The accumulated count rates define a temporal signal.
  • curves 201 and 203 that depict temporal signals measured at two detectors.
  • the abscissa is time and the ordinate is the accumulated count rate over the temporal sampling interval.
  • the time sampling interval is typically 0.5 seconds. Note that in the plot, time increases to the left.
  • the signal 201 corresponds to measurements made by a detector that is closer to the source than the detector that measured signal 203 . Since the signals are the result of radioactive decay of nitrogen-16 with a half life of about 7.13 seconds, the absolute level of the signal measured by the farther detector will be less than the absolute level of the signal measured by the closer detector. In the plot shown in FIG.
  • This determined velocity v r is a measurement of fluid velocity relative to the velocity of the logging tool v t .
  • the velocity v r will be the same as the actual fluid velocity.
  • the actual fluid velocity v f is given by:
  • the time delay ⁇ t is obtained by cross-correlation of the signals 201 and 203 .
  • the signal 201 corresponds to the activation of oxygen-16 to nitrogen-16 and the resulting gamma rays produced by decay of nitrogen-16.
  • the near detector is sufficiently close to the source (i.e. proximate to the source), it may respond immediately to the source activation due to gamma radiation produced by fast neutron inelastic scattering and thermal neutron capture events. This is depicted in FIG.
  • the near detector D 1 ′ if the near detector D 1 ′ is within the region of inelastic or capture events denoted by 221 , then the near detector D 1 ′ responds immediately to the source activation.
  • the far detector D 2 responds to the nitrogen- 16 after a time delay corresponding to fluid flow from the source position to the detector position D 2 and the associated distance ⁇ d′.
  • Those versed in the art would know other methods of estimating the travel time. This includes identifying the point of inflection of signals from the rising and falling edge of signals 201 and 203 .
  • FIGS. 4( a ) and 4 ( b ) the flow rate that would be measured by the method described above is illustrated by 401 as a function of position along the borehole 102 .
  • the decreases in the flow rate are indications that the perforated intervals have been satisfactorily fractured and that fluid is leaking out of the borehole 102 .
  • a curve such as 403 would indicate that no fluid is leaking out of the borehole 102 at the perforations.
  • This monitoring can be done in real time and remedial action can be taken to improve the fracturing. This may be done, for example, by increasing the fluid pressure.
  • FIG. 5 shows an open-hole 102 in which a sensor unit 135 ′ has been deployed.
  • the sensor unit 135 ′ differs from the sensor unit 135 in that the pulsed neutron source 151 is above the gamma ray detectors 153 , 155 , 157 .
  • the port for acid injection or polymer injection is indicated by 145 .
  • the orientation or position of the port 145 is not critical for fracturing or acid injection.
  • One benefit of having the sensor unit 135 ′ below the port 145 is that the sensor unit 135 ′ would not require a larger diameter bypass sub on the coiled tubing 131 . This would allow access into smaller diameter wellbores or completions.
  • the sensor unit 135 ′ can detect and measure acid flow rate in a downhole direction using oxygen activation methods such as that described above with reference to the fracture monitoring device.
  • oxygen activation methods such as that described above with reference to the fracture monitoring device.
  • acidization may increase the formation porosity, so that leakage of fluid into the formation may occur.
  • acid flow or exit into the formation may be detected using borehole ⁇ as a change in wellbore salinity (chloride in acid).
  • An increase in formation ⁇ would be detected in intervals where the acid moved out into the formation.
  • the movement of the acid may also be measured using oxygen activation of the oxygen in the water associated with the acid.
  • Coiled tubing may be placed at any point in the well, but for example, if the acid is injected near the top of the interval and enters the formation along the wellbore, then oxygen activation can be used to measure the velocity—as a continuous log or as stationary measurements—to determine the injection profile.
  • coiled tubing could deployed to bottom of the interval, acid injected, and movement of the acid tracked by logging out of the well. This may be done at discrete locations or continuously.
  • the pulsed neutron tool can be configured to measure up or down flow accordingly.
  • Acid increases the formation sigma by increasing porosity and chloride effects.
  • the injection intervals can be identified by the increases in measured ⁇ (as compared to a base log run in the same operation but prior to acid treatment). Acid-induced porosity increases can be determined by comparing ⁇ values before and after acid treatment. The porosity increase could be determined by comparison of the formation ⁇ before and after acid injection.
  • an interval of the borehole above and/or below the tool may be isolated using suitable well isolating tools, including, but not limited to, packers, bridge plugs, etc.
  • the sensor unit 135 may be used to acquire information related to the formation modification operation.
  • the acquired information may include information from a plurality of locations along the borehole.
  • the acquired information may be used to estimate at least one parameter of interest related to the formation modification as understood by those of ordinary skill in the art.
  • An additional operation may selected based on the estimated at least one parameter.
  • Sensor unit 135 may be used to monitor and/or measure a change in the formation due to the additional operation. The change may or may not be in the at least one parameter of interest.
  • the at least one parameter of interest may include one or more of: (i) an indicator of a degree of fracturing in the formation, (ii) a change in fluid flow in the annulus, and (iii) flow rate of fluid into the formation.
  • Implicit in the processing of the data is the use of a computer program implemented on a suitable computer-readable medium that enables the processor to perform the control and processing.
  • the computer-readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks.
  • the determined results of formation modification may be recorded on a suitable medium and used for subsequent processing upon retrieval of the BHA.
  • the measurements (partially or fully processed) may be telemetered uphole.
  • the formation fracture profiles and acidization profiles may be determined in situ and additional treatment may be made if warranted.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Analysing Materials By The Use Of Radiation (AREA)
  • Geophysics And Detection Of Objects (AREA)
US13/551,105 2011-07-18 2012-07-17 Pulsed Neutron Monitoring of Hydraulic Fracturing and Acid Treatment Abandoned US20130020075A1 (en)

Priority Applications (3)

Application Number Priority Date Filing Date Title
US13/551,105 US20130020075A1 (en) 2011-07-18 2012-07-17 Pulsed Neutron Monitoring of Hydraulic Fracturing and Acid Treatment
PCT/US2012/047122 WO2013012888A2 (fr) 2011-07-18 2012-07-18 Contrôle par neutrons pulsés de fracture hydraulique et de traitement acide
CA2841956A CA2841956A1 (fr) 2011-07-18 2012-07-18 Controle par neutrons pulses de fracture hydraulique et de traitement acide

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201161508899P 2011-07-18 2011-07-18
US13/551,105 US20130020075A1 (en) 2011-07-18 2012-07-17 Pulsed Neutron Monitoring of Hydraulic Fracturing and Acid Treatment

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CA (1) CA2841956A1 (fr)
WO (1) WO2013012888A2 (fr)

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20140219056A1 (en) * 2013-02-04 2014-08-07 Halliburton Energy Services, Inc. ("HESI") Fiberoptic systems and methods for acoustic telemetry
US9840912B2 (en) * 2014-10-28 2017-12-12 Halliburton Energy Services, Inc. Determining casing fluid capture cross section using gamma count rate ratio
US10162078B2 (en) 2017-01-12 2018-12-25 Baker Hughes In-well monitoring of components of downhole tools

Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5404752A (en) * 1993-09-28 1995-04-11 Western Atlas International, Inc. Method for measuring the velocity of water flow through nested conduits
US20060233049A1 (en) * 2005-04-14 2006-10-19 Gerhardus Cilliers Repelling Pests
US20070095528A1 (en) * 2005-11-02 2007-05-03 Murtaza Ziauddin Method of Monitoring Fluid Placement During Stimulation Treatments
US7227129B2 (en) * 2004-06-29 2007-06-05 Baker Hughes Incorporated Flowshot technique
US20080142212A1 (en) * 2006-12-18 2008-06-19 Hartog Arthur H System and method for sensing a parameter in a wellbore
US20080156977A1 (en) * 2006-12-23 2008-07-03 Schlumberger Technology Corporation Methods and systems for determining mud flow velocity from measurement of an amplitude of an artificially induced radiation
US20090321622A1 (en) * 2008-06-27 2009-12-31 Christian Stoller Determining downhole fluid flow

Family Cites Families (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4825073A (en) * 1987-12-14 1989-04-25 Halliburton Logging Services Inc. Method for determining depth of penetration of radioactive tracers in formation fractures
US4926940A (en) * 1988-09-06 1990-05-22 Mobil Oil Corporation Method for monitoring the hydraulic fracturing of a subsurface formation
US5413179A (en) * 1993-04-16 1995-05-09 The Energex Company System and method for monitoring fracture growth during hydraulic fracture treatment
GB2399111B (en) * 2003-03-07 2005-10-05 Schlumberger Holdings Methods for detecting while drilling underbalanced the presence and depth of water produced from the formation and for measuring parameters related thereto

Patent Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5404752A (en) * 1993-09-28 1995-04-11 Western Atlas International, Inc. Method for measuring the velocity of water flow through nested conduits
US7227129B2 (en) * 2004-06-29 2007-06-05 Baker Hughes Incorporated Flowshot technique
US20060233049A1 (en) * 2005-04-14 2006-10-19 Gerhardus Cilliers Repelling Pests
US20070095528A1 (en) * 2005-11-02 2007-05-03 Murtaza Ziauddin Method of Monitoring Fluid Placement During Stimulation Treatments
US20080142212A1 (en) * 2006-12-18 2008-06-19 Hartog Arthur H System and method for sensing a parameter in a wellbore
US20080156977A1 (en) * 2006-12-23 2008-07-03 Schlumberger Technology Corporation Methods and systems for determining mud flow velocity from measurement of an amplitude of an artificially induced radiation
US20090321622A1 (en) * 2008-06-27 2009-12-31 Christian Stoller Determining downhole fluid flow

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20140219056A1 (en) * 2013-02-04 2014-08-07 Halliburton Energy Services, Inc. ("HESI") Fiberoptic systems and methods for acoustic telemetry
US9840912B2 (en) * 2014-10-28 2017-12-12 Halliburton Energy Services, Inc. Determining casing fluid capture cross section using gamma count rate ratio
US10162078B2 (en) 2017-01-12 2018-12-25 Baker Hughes In-well monitoring of components of downhole tools

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Publication number Publication date
CA2841956A1 (fr) 2013-01-24
WO2013012888A3 (fr) 2013-04-11
WO2013012888A2 (fr) 2013-01-24

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