U.S. patent application number 13/551105 was filed with the patent office on 2013-01-24 for pulsed neutron monitoring of hydraulic fracturing and acid treatment.
This patent application is currently assigned to Baker Hughes Incorporated. The applicant listed for this patent is Ansgar Baule, David M. Chace, Freeman L. Hill, Daryl D. McCracken. Invention is credited to Ansgar Baule, David M. Chace, Freeman L. Hill, Daryl D. McCracken.
Application Number | 20130020075 13/551105 |
Document ID | / |
Family ID | 47554972 |
Filed Date | 2013-01-24 |
United States Patent
Application |
20130020075 |
Kind Code |
A1 |
Chace; David M. ; et
al. |
January 24, 2013 |
Pulsed Neutron Monitoring of Hydraulic Fracturing and Acid
Treatment
Abstract
Hydraulic fracturing, acidizing and polymer injection using
coiled tubing are commonly used techniques in wellbore completion.
A pulsed neutron tool may be conveyed at the bottom of the coiled
tubing to monitor the effectiveness of these operations by
measuring the flow velocity of the borehole fluid of the annulus
between the pulsed neutron tool and the borehole wall. Gamma rays
resulting from Oxygen activation and/or .SIGMA. measurements are
used for measuring the flow velocity.
Inventors: |
Chace; David M.; (Houston,
TX) ; McCracken; Daryl D.; (Houston, TX) ;
Baule; Ansgar; (Kingwood, TX) ; Hill; Freeman L.;
(Spring, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Chace; David M.
McCracken; Daryl D.
Baule; Ansgar
Hill; Freeman L. |
Houston
Houston
Kingwood
Spring |
TX
TX
TX
TX |
US
US
US
US |
|
|
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Family ID: |
47554972 |
Appl. No.: |
13/551105 |
Filed: |
July 17, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61508899 |
Jul 18, 2011 |
|
|
|
Current U.S.
Class: |
166/250.1 ;
166/250.01; 166/53; 166/65.1; 73/152.01 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 47/10 20130101; E21B 47/11 20200501 |
Class at
Publication: |
166/250.1 ;
166/250.01; 166/65.1; 166/53; 73/152.01 |
International
Class: |
E21B 47/00 20120101
E21B047/00; E21B 43/27 20060101 E21B043/27; E21B 43/26 20060101
E21B043/26 |
Claims
1. A method of monitoring a formation modification operation in a
borehole, the method comprising: 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.
2. The method of claim 1 wherein the formation modification
operation is at least one of: (i) a hydraulic fracturing, (ii) an
acid treatment, and (iii) a polymer injection.
3. The method of claim 1 wherein the radiation source further
comprises a pulsed radiation source, and making measurements
indicative of the flow velocity of the fluid further comprises:
irradiating the formation with the pulsed radiation source;
obtaining a first temporal signal resulting from the irradiation at
a first detector; obtaining at least one second temporal signal
resulting from the irradiation at at least one second detector
spaced apart from the first detector; and determining the flow
velocity based on analysis of the first temporal signal, the at
least one second temporal signal, and a distance between one of (A)
the first detector and the at least one second detector, and (B)
the source and the at least one second detector.
4. The method of claim 1 wherein the at least one parameter of
interest includes at least one 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.
5. The method of claim 3 wherein the first temporal signal is
selected from: (i) gamma rays resulting from nitrogen-16 and (ii) a
cross section .SIGMA. of the fluid.
6. The method of claim 3 wherein the first detector is proximate to
the radiation source and is responsive immediately to inelastic and
capture events resulting from the pulsed radiation, and wherein the
at least one second detector is responsive to the produced gamma
rays.
7. The method of claim 3 wherein determining the flow velocity is
based on a correlation between the first temporal signal and the at
least one second temporal signal.
8. The method of claim 1 further comprising: positioning a
processor at a downhole location, wherein the processor is
configured to estimate the at least one parameter using the
measurements at a plurality of positions along the borehole; and
performing a remedial action based on the at least one
parameter.
9. An apparatus configured to monitor a formation modification
operation in a borehole, the apparatus comprising: 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.
10. The apparatus of claim 9 wherein the formation modification
operation is one of: (i) a hydraulic fracturing, (ii) an acid
treatment, and (iii) a polymer injection.
11. The apparatus of claim 9 wherein the at least one parameter of
interest includes at least one 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.
12. The apparatus of claim 9 wherein the radiation source further
comprises a pulsed radiation source further configured to irradiate
the earth formation with the pulsed radiation source; and wherein
the instrument further comprises: a first detector configured to
obtain a first temporal signal resulting from the irradiation; at
least one detector spaced apart from the first detector configured
to obtain at least one second temporal signal resulting from the
irradiation; and wherein the processor is further configured to
estimate the flow velocity based on analysis of the first temporal
signal, the at least one second temporal signal, and a distance
between one of (A) the first detector and the at least one second
detector, and, (B) the source and the at least one second
detector.
13. The apparatus of claim 12 wherein the first temporal signal is
selected from: (i) gamma rays resulting from nitrogen-16 and (ii) a
cross section .SIGMA. of the fluid.
14. The apparatus of claim 12 wherein the first detector is
proximate to the source and is responsive to inelastic and capture
events resulting from the pulsed radiation, and wherein said at
least one second detector is responsive to the produced gamma
rays.
15. The apparatus of claim 9 wherein the processor is configured to
estimate the flow velocity based on a correlation between the first
and at least one second signal.
16. The apparatus of claim 9 wherein the processor is further
configured to perform a remedial action based on the at least one
parameter.
17. 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 comprising: 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.
18. The non-transitory computer-readable medium product of claim 17
further comprising at least one of: (i) a ROM, (ii) an EPROM, (iii)
an EEPROM, (iv) a flash memory, and (v) an optical disk.
19. A method for monitoring a formation modification operation, the
method comprising: 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.
20. The method of claim 19, further comprising: performing an
additional operation based on the at least one estimated parameter
of interest.
21. The method of claim 20, further comprising: estimating a change
in the formation after the additional operation.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims priority from U.S. Provisional
Patent Application Ser. No. 61/508,899, filed on 18 Jul. 2011,
incorporated herein by reference in its entirety.
BACKGROUND OF THE DISCLOSURE
[0002] 1. Field of the Disclosure
[0003] 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.
[0004] 2. Description of the Related Art
[0005] Hydraulic fracturing of boreholes is a commonly used
completion technique. The fracturing may be done in either
open-hole or cased hole. In 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. In
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.
[0006] 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.
[0007] In the process of fracture acidizing, 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.
[0008] The term "matrix acidizing" refers to the treatment of a
reservoir formation, with an acid. In sandstones, the acid reacts
with soluble substances in the formation matrix and enlarges the
pore spaces. In carbonate formations, 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.
[0009] 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. For
the purposes of the present disclosure, hydraulic fracturing,
acidizing operations, and polymer injection are referred to as
formation modification operations. The present disclosure satisfies
the need for monitoring such operations.
SUMMARY OF THE DISCLOSURE
[0010] 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.
[0011] Another embodiment of the disclosure is an apparatus
configured to monitor a formation modification operation in a
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.
[0012] 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.
[0013] 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.
BRIEF DESCRIPTION OF THE FIGURES
[0014] The present disclosure is best understood with reference to
the accompanying figures in which like numerals refer to like
elements, and in which
[0015] FIG. 1 is an exemplary schematic diagram of an apparatus
suitable for use with one embodiment of the present disclosure;
[0016] FIG. 2 is a schematic illustration of temporal signals
(after normalization) measured at two spaced apart detectors;
[0017] FIG. 3 illustrates a situation where the near detector is
immediately responsive to source activation;
[0018] FIGS. 4(a) and 4(b) illustrate changes in flow rate measured
by a pulsed neutron instrument in a fractured portion of a
borehole; and
[0019] FIG. 5 shows an exemplary apparatus suitable for monitoring
of acid treatment.
DETAILED DESCRIPTION OF THE DISCLOSURE
[0020] 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 105a, 105b, 105c, and 105d. The second perforated
section includes perforations 115a, 115b, 115c, and 115d.
[0021] 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. In one
embodiment of the present disclosure, 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.
[0022] Those versed in the art and having benefit of the present
disclosure would recognize that, as the returning fluid 161 flows
by a perforation, some of the returning fluid would leak into the
formation 101. Specifically, the more effective the fracturing of
the formation 101 is at a perforation, the greater would be the
amount of leakage of the borehole fluid 161 into the formation 101.
Consequently, if the velocity of the returning fluid would be
measured, it would steadily decrease in the uphole direction, and
the magnitude of the decrease would be indicative of the
fracturing. This velocity of the fluid in the annulus between the
coiled tubing 131 and the casing 103 is measured by the sensor unit
135.
[0023] 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. In some embodiments, 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.
[0024] A signal processor 122 is installed in the sensor 135. In
one embodiment of the disclosure, 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. In another embodiment of the disclosure, the
processor, acoustic telemetry may be used to communicate data to
the surface through the coiled tubing 131.
[0025] 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.
[0026] In the present disclosure, 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. Alternatively,
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.
[0027] Turning now to FIG. 2, the basic principle of the method of
the present disclosure are described. Shown are 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. As noted above, 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.
2, suitable normalization of the signals has been done so that they
appear to be of comparable amplitude. The spacing Ad between the
near detector and the far detector is a known quantity. Hence by
measuring the time delay At between signal 201 and signal 203, a
velocity of flow v.sub.r can determined by:
v r = .DELTA. d .DELTA. t ( 1 ) ##EQU00001##
[0028] This determined velocity v.sub.r is a measurement of fluid
velocity relative to the velocity of the logging tool v.sub.t. When
the logging tool is stationary, then the velocity v.sub.r will be
the same as the actual fluid velocity. When the logging tool is in
motion, then the actual fluid velocity v.sub.f is given by:
v.sub.f=v.sub.r+v.sub.t (2)
where it is understood that the summation is a vector summation.
For the remainder of the discussion of the method of the present
disclosure, it is assumed that the logging tool is stationary, and
that suitable correction for the velocity of motion of the tool can
be made.
[0029] In one embodiment of the present disclosure, the time delay
.DELTA.t is obtained by cross-correlation of the signals 201 and
203. When the near detector is sufficiently far from the source,
the signal 201 corresponds to the activation of oxygen-16 to
nitrogen-16 and the resulting gamma rays produced by decay of
nitrogen-16. However, if 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. 3 wherein, if the near
detector D.sub.1' is within the region of inelastic or capture
events denoted by 221, then the near detector D.sub.1' responds
immediately to the source activation. The far detector D.sub.2
responds to the nitrogen-16 after a time delay corresponding to
fluid flow from the source position to the detector position
D.sub.2 and the associated distance .DELTA.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.
[0030] Turning now to 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. In contrast, a curve such as 403 would indicate that
no fluid is leaking out of the borehole 102 at the perforations.
The feature of the present disclosure is that 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.
[0031] Another embodiment of the disclosure may be used for
monitoring of acid treatment real-time using a pulsed neutron
logging instrument attached at the bottom of the coiled tube
immediately below a flow port that allows acid treatment or
diverter fluid to exit the tubing. 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.
[0032] 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. Those versed in the art would recognize that acidization
may increase the formation porosity, so that leakage of fluid into
the formation may occur. In another embodiment of the disclosure,
acid flow or exit into the formation may be detected using borehole
.SIGMA. as a change in wellbore salinity (chloride in acid). An
increase in formation .SIGMA. 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.
[0033] 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. In an
alternate embodiment, 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 .SIGMA. (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 .SIGMA. values before and after acid treatment. The
porosity increase could be determined by comparison of the
formation .SIGMA. before and after acid injection.
[0034] As noted above, It is sometimes desirable to seal off
certain intervals in a borehole to restrict the flow of fluids into
or out of the borehole. This may be done by injecting a polymer at
the selected intervals. When a water-based polymer is used, the
effectiveness of the sealing operation can be monitored by using
the oxygen activation technique discussed above. In some
embodiments, 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.
[0035] In another embodiment, 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.
[0036] 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. Alternatively, the formation fracture profiles and
acidization profiles may be determined in situ and additional
treatment may be made if warranted.
[0037] Those skilled in the art will devise other embodiments of
the disclosure which do not depart from the scope of the disclosure
as disclosed herein. Accordingly the disclosure should be limited
in scope only by the attached claims.
* * * * *