United States
Environmental Protection
Agency
xvEPA Injection
Mechanical Integrity
M.C
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EPA/625/9-87/007
INJECTION WELL
MECHANICAL INTEGRITY
Jerry T. Thornhill
Robert S. Kerr Environmental Research Laboratory
U.S. Environmental Protection Agency
Ada, Oklahoma 74820
Bobby G. Benefield
Environmental Research Institute
Ada, Oklahoma
Office of Research and Development
U.S. Environmental Protection Agency
Washington, DC 20460
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DISCLAIMER
The information in this document has been funded wholly or in
part by the United States Environmental Protection Agency. It has
been subjected to the Agency's peer and administrative review, and
it has been approved for publication as an EPA document.
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ABSTRACT
Underground injection control regulations of the U.S.
Environmental Protection Agency require that all injection wells
demonstrate mechanical integrity, which is defined as no significant
leak in the casing, tubing or packer; and no significant fluid
movement into an underground source of drinking water through
vertical channels adjacent to the injection well bore.
This initial research project, examining the question of
mechanical injection well integrity, was conducted by the Robert S.
Kerr Environmental Research Laboratory and funded in 1981. The
three-phased project determined the state-of-the-art methods
available for mechanical integrity testing of injection wells and field
tested specific analysis methods to determine their adequacy as
mechanical integrity tests.
The first phase of the project resulted in a separate report
entitled, "Methods for Determining the Mechanical Integrity of Class II
Injection Wells." The report represented state-of-the-art methods
available for determining mechanical integrity of Class It wells. The
technology described, may also be applied to other classes of
injection wells.
The second and third phases of study involved two test wells,
constructed for mechanical integrity testing: A "Logging Well" to test
for channels in the cement behind the casing and a "Leak Test Well"
for developing methods for testing the integrity of the tubing, casing
and packer as well as locating fluid movement in channels behind the
casing.
Channels covering 90, 60, 30, and 6 degrees of the 360 degree
circle described by the casing were built into the cement of the
"Logging Well." Two generations of logging tools were run in the
Logging Well: the "cement bond" tool and the "cement evaluation"
tool.
None of the logging tools presently available located any of the 6
degree channels. The "second generation" tools located all of the
30, 60, and 90 degree channels and a calibrated "cement bond" tool
with dual receiver three foot/five foot spacing located alt but one of
the 30 degree and all of the 60 and 90 degree channels.
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The tools must be calibrated prior to their use and industry is
encouraged to continue research to increase the sensitivity of the
tools for mechanical integrity determinations.
The "Leak Test Well" was designed to generally correspond to a
typical salt water disposal well used by the petroleum industry. It
incorporates the use of surface casing, long string, tubing and
packer. Additional modifications included two packers, a sliding
sleeve on the injection tubing and a 2-3/8" tubing attached to the
outside of the long string running to the surface. Flow into the well
can be controlled so that the injected fluids are directed into the 2-
3/8" injection tubing, or to the 2-3/8" leak string. Return flows can
be controlled from the 2-3/8" leak string and also from the annulus
of the 5-1/2" casing,
Some tests have been performed and a number are planned for
the "Leak Test" well. These include: hydraulic conductivity of the
injection zone; radial differential temperature log; temperature log;
differential temperature log; radioactive tracer survey; noise log;
flowmeter survey; annulus pressure changes resulting from
temperature variances; volume-pressure relationship; "Mule Tail"
test; effect of mud in the long string/surface casing annulus; helium
leak test. Monitoring wells will be constructed to observe each of the
three zones open to the "Leak Test Well."
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CONTENTS
Abstract iii
Figures vi
Acknowledgments viii
Introduction 1
Mechanical Integrity Test Wells 1
Logging Well 1
Cement Evaluation 2
Logging Tools 2
Log Interpretation 4
Well Logging Conclusions and
Recommendations 7
Well Completion 7
Logging Equipment 9
Log Interpretation 12
Leak Test Well 12
Conclusions 17
References 18
Appendix A. Logging Well Design Specifications and
Installation Procedure and Log Interpretation 19
Logging Test Well Material
Specifications 19
Detailed Description of Well Construction . . . 19
Log Interpretation 25
Appendix B. Leak Test Well Design and Testing
Criteria and Test Summaries 44
Leak Test Well 44
Test Summaries 45
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FIGURES
Number Page
1 Logging well 3
2 Cement bond tool - single transmitter/receiver 5
3 Cement bond tool - single transmitter/
dual receiver 6
4 Second generation tool 7
5 Composite wave form 3
6 Field reference transit line g
7 Amplitude, chevron and free pipe 11
8 Tool not centered ^
9 Leak test well 14
10 Injection well head and flow lines 15
A-1 Preparing fiberglass with epoxy resin 21
A-2 Applying initial fiberglass layer 22
A-3 Completed channel - prior to using wire
brush to remove excess . 23
A-4 Removing excess fiberglass with wire brush 24
A-5a Single-receiver 3-foot spacing . 26
A-5b Single-receiver 4-foot spacing " 27
A-5c Single-receiver 5-foot spacing 28
A-5d Dual-receiver 3-foot/5-foot spacing ...'.'.'.'.'.'. 30
A-5e Second generation log - Company A 31
A-6a Single-receiver 3-foot spacing 32
A-6b Single-receiver 4-foot spacing ' '. ' 33
A-6c Single-receiver 5-foot spacing '.'.'.'.'.'. 35
A-6d Dual-receiver 3-foot/5-foot spacing ......... 36
A-6e Second generation log - Company B ......... 37
A-7a Single-receiver 3-foot spacing 33
A-7b Single-receiver 4-foot spacing '.'.'.'.', 40
A-7c Single-receiver 5-foot spacing [[[[ 41
A-7d Dual-receiver 3-foot/5-foot spacing ...'.'.'.'." 42
VI
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43
A-7e Second generation log - Company A
B-1 Injection pump and control accessories
B-2 CBL liquid flow test - Phase I
B-3 CBL liquid flow test - Phase II
B~4 Neutron activation tool liquid flow test - Phase !
B-5 Neutron activation tool liquid flow test - Phase II
B-6 Neutron activation tool liquid flow test - Phase III
B-7 Neutron activation tool liquid flow test - Phase IV
B-8 Testing for a hole in the long string
B-9 Neutron activation tool liquid flow test 64
B-10 Radial differential temperature survey 66
B-11 ROT scan no-flow condition 67
B-12 RDT scan flow condition 68
46
48
49
53
54
56
57
60
VII
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ACKNOWLEDGMENTS
This paper reflects the work done to date on two unique research
wells designed for testing methods for determining the mechanical
integrity of injection wells. The successful design of the wells is due
to the time and effort which an unusually able advisory panel was
willing to devote to the project.
Grateful acknowledgment is made to the advisory group for their
contribution:
Terry Anderson
Halliburton Cementing Services
Dick Angel
Phillips Petroleum
Al Bryant
Schlumberger Well Service
Mike Cantrell
Oklahoma Basic Economy Corp.
Cecil Hill
Baker Packers
Gene Littell
Li tie 11 and Randolph Engineering
Tal Oden
Oklahoma Corporation Commission
R. C. Peckham
USEPA, Region VI
Gary Batcheller, Schlumberger Well Service, and Alerdo Maffi,
Tom Hansen Company, both made incalculable contributions to the
project through their advice, encouragement and participation in a
training course for EPA and State employees on October 16, 17, and
18, 1985.
VIII
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INTRODUCTION
Underground injection control regulations of the United States
Environmental Protection Agency (USEPA) require that all injection
wells demonstrate mechanical integrity for new wells prior to
operation and all wells demonstrate at least every five years.
The regulations state that an injection well has mechanical
integrity if:
(1) There is no significant leak in the casing, tubing or packer,
and
(2) There is no significant fluid movement into an underground
source of drinking water through vertical channels adjacent to
the injection well bore.
The initial research project to examine the question of
mechanical integrity was funded July 1, 1981. The three-phased
project was to determine the state-of-the-art for mechanical
integrity testing of injection wells and to test specific field methods to
determine their adequacy.
The first phase of the project resulted in a report, "Methods for
Determining the Mechanical Integrity of Class II Injection. Wells."
Although this report represented the state-of-the-art for
determining mechanical integrity for Class II wells, the technology
described may be applied to other classes of injection wells.
MECHANICAL INTEGRITY TEST WELLS
The second and third phases of the project involved construction
and testing of two wells designed to evaluate various tools and
techniques used to determine mechanical integrity of injection wells.
The test wells: a "Logging Well", and a "Leak Test Well" were
designed for developing methods for testing the integrity of the
tubing, casing and packer as well as locating fluid movement in
channels behind the casing, and testing channels in the cement
behind the casing; are located on a 110 acre site approximately 11
miles west of Ada, Oklahoma.
Logging Well
The purpose of the Logging Well is to determine the present
capability in the industry for evaluating the cement bond between the
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cement/casing and cement/formation coupling in injection wells, and
to provide a test facility for evaluating new tools developed for
cement evaluation.
After much discussion among members of the advisory group, it
was determined that the best method to simulate poor cement
bonding, or channels in the cement, would be to attach water-filled
PVC pipes to the outside of the casing. Thus, PVC pipe was
attached to the outside of the casing to cover either 90°, 60° 30°
or 6° of the 360° radial surface of the pipe (Figure 1).
Having installed the "channels" on the casing, attention was
turned to a second vital factor in the completion of this well, the
quality of the cement job. The planned cementing program was
designed to provide the most favorable conditions for obtaining
excellent bonding of the cement to the casing and and coupling of
the cement to the formations so that the "channels" identified by the
logging tools would be those purposely created for the project.
A thorough review of the logs run to evaluate the cement
bonding indicates that about 60 percent of the well has good cement
bonding and provides an excellent facility for determining the
sensitivity of various down-hole cement evaluation techniques. The
other 40 percent of the well provides an opportunity for testing
techniques for repairing channels in cement, and for evaluating the
success of the repair efforts.
The well specifications, along with a detailed description of the
installation process, is provided in Appendix A.
Cement Evaluation
With the completion of the well, the actual testing portion of the
project, determining the present capability for evaluating the cement
was ready to proceed. Contact was made with as many logging
companies as possible to determine the type of tools that are being
used for evaluating cement in a well, and run as many different tools
as possible in the "Logging Well." At the initial contact with each
company contracted to log the well, the construct and purpose of
the well was fully explained, except for the location of the man-
made channels. Trie company representative was also asked to
provide a complete interpretation of the condition of the cement in
the well, based on the information from their log, prior to their leavina
the site.
Nine companies have produced 16 logs on the well. Two
companies have refused to run a log on the well.
Logging Tools
Basically, two generations of logging tools have been run in the
well: the "cement bond" tool, consisting of single transmitter/single
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j 12-1/4" dia. borehole
9-5/8" dia.
casing
8-5/8" dja.
casing
7" dia.
casing
5-1/2" dia.
casing
4-1/2" dia.
casing
Jia.
dia.
- •
^ L.
dia.
ia.
530 ft dept
L_
^
rw
HJK:
^^^^m
h
->•
LI
f •
•
.
....
::P?
....
::::
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.
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annu
- form<
8-3/4" dia. borehole
Figure 1. Logging well.
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receiver or single transmitter/dual receivers; and the "cement
evaluation" tool which has eight ultrasonic transducers.
The typical "cement bond" tool presents a log with the following
data: gamma-ray and casing collar locator (CCL), which are
included for depth control; transit time (TT), which measures the time
it takes for a certain level sound wave to travel from the transmitter
to the receiver; amplitude, which measures the strength of the first
compressional cycle of the returning sound wave; and a graphic
representation of the wave form, which displays the manner in which
the received sound wave varies with time. This representation is
called variable density log (VDL), seismic spectrum, or
microseismogram, and is a function of the property of the material
through which the signal is transmitted.
There are various transmitter/receiver spacings available, the
most common being a single transmitter with a single receiver
located three feet away (Figure 2). Other tools include the single
transmitter/single receiver with four foot or five foot spacing, or a
single transmitter/dual receiver with three foot/five foot spacing
(Figure 3).
The "second generation" tools for determining the adequacy of
cement bonding includes the use of a tool having eight ultrasonic
transducers spiraled around it to survey the circumference of the
casing (Figure 4). The information presented on the log from these
tools includes: casing ovality, average casing I.D., casing collars,
hole deviation, fluid velocity, eccentering of the tool, rotation of the
tool, gamma-ray, maximum and minimum cement compressive
strength, average of the energy returned to all eight transducers, and
cement distribution around the casing.
Log Interpretation
The bonding of cement to casing can be measured quantitatively,
but the bonding, or rather the coupling, of cement to the formation is
only a qualitative estimate. Therefore, when attempting to evaluate
cement in a well, it is extremely important to obtain as much
information as possible.
The components of the sound wave that are of primary interest
when analyzing a "bond log" are the casing, formation and fluid
(mud) signals. Each medium has different characteristics, thus the
sound waves will have different amplitudes, and velocities. Figure 5
indicates these wave forms and a composite signal.
A recommended approach to evaluating the "cement bond" log
is to first determine the information available from the graphic
representation of the wave form (VDL), then examine the amplitude
curve to see if the two are in agreement. For example, if the casing
diameter and transmitter/receiver spacing are known, the transit time
for the casing arrivals can be predicted. Figure 6 is a chart that, for
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Electronic
Section
Trans.
Acoustical
Section
Receiver
Bore Hole
Liquid
Casing
Bonded Cement
Sheath
Sonic Pulse
-Path
jf —
— — Formation
>*
Figure 2. Cement Bond Tool - Single Transmitter/Receiver.
practical field or reference purposes, gives an idea of the
approximate transit time for the casing signal for various tool spacing
and casing I.D. By examining the VDL, the time, in microseconds of
the first arrival, can be determined. This time can then be checked
against the chart to determine if they are casing signals.
The fluid, or mud, wave has a velocity of about 189
microseconds/foot, and its arrival can be predicted if the tool spacing
is known by multiplying the tool spacing by 189. The fluid wave has a
destructive interference, thus when it enters the receiver, distortion
of the wave occurs. Because of this, the only part of the VDL that is
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Transmitter
3' Receiver
5' Receiver
1
n-
D.
•
•
^ — '
T"" i
: i \
' '•'••'. -
7]-. =
;-1 ':. -
' .:.V'
! :'/"••
:-t
•'•'';'
' '•(•'
"••.'•• •
w ''. -
/ >'• '
Figure 3. Cement Bond Too! - Single Transmitter/Dual Receiver.
useful for interpretive purposes is that part prior to the arrival of the
fluid wave.
The "second generation" tools generate a pulse of untrasonic
energy from each of the eight focused transducers that are arranged
around the circumference of the tool. The strength and duration of
the echoes reflected from the casing and cement are used to form
an image of the cement distribution and quality around the casing.
This information and the cement compressive strengths are two very
useful pieces of data for evaluating the casing/cement bonding in a
well.
As stated earlier, 16 different logs have been produced from the
well. Appendix A containes a detailed comparison of specific sections
of the well that have been logged by "first generation" tools with
single transmitter/receiver, three-, four- or five-foot spacing; amd
the "second generation" ultrasonic logging tool. '
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Eight
Ultrasonic
Transducers
Fluid
Velocity
Transducer
-.--_—- Casing
z^~**=2- Bonded
;->"-: Cement Sheath
Formation
Figure 4. Second Generation Tool.
Well Logging Conclusions and Recommendations
Well Completion
Greater care must be exercised in planning the cement job and
in carrying out that plan when cementing injection wells, especially
Class I wells where cement is to be circulated to the surface around
the long string. The plan should include equipment and activities that
will enhance the possibility for obtaining the best cement bonding
possible This should include the use of a caliper log to determine
exact hole size to better estimate the volume of cement necessary to
complete the well; properly conditioned drilling mud prior to beginning
the cementing operation; centralizes, to ensure that the casing is
centered in the hole; pre-flush, to help clean out the hole prior to
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Fluid
Casing
Formation
[]
u
Composite
Figure 5. Composite wave form.
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4
D" 5
6
7
3
235
250
265
280
A
4
292
307
322
337
5
349
364
379
394
A - Receiver spacing D" - Casing diameter
Figure 6. Field reference transit time.
pumping cement; rotating and/or reciprocating the pipe during the
cementing operation to further aid in cleaning out the hole; and at
least 100 percent excess cement. The experience in cementing the
"Logging Well" indicates that in those areas where the greatest
volume of cement flowed past, the cleaner the hole and the better
the cement bond, thus the use of 100 percent excess cement will
enhance the probability of a good cement job throughout the casing
length.
In the "Logging Well," although cement was circulated to the
surface, after the cement set for 72 hours, the top of cement behind
the casing was 132 feet below land surface. This "fall back" of the
cement behind the casing must be monitored and corrected so that
there is cement fill-up behind the casing to the surface of the
ground.
Logging Equipment
None of the logging tools presently available located any of the
six degree channels in the "Logging Well." The "second generation"
tools located all of the 30, 60, and 90 degree channels that were
designed into and could be identified in the well. A calibrated single
transmitter/dual receiver "cement bond" tool with three foot/five foot
spacing located the 60 and 90 degree channels and all but one of the
30 degree channels. The other "cement bond" tools with single
transmitter/single receiver three foot, four foot, or five foot spacing
presented very inconsistent results.
The three foot spacing is the best currently available for
measuring and evaluating the amplitude of the first compressional
arrival and the attenuation of this signal is a measure of the bonding
of the cement to the casing. However, this spacing is not satisfactory
for determining data on or evaluating the relationship of the cement
to the formation. Five foot spacing between the transmitter and
receiver is the best currently available for evaluating the relationship
of the cement to the formation, but it is not accurate for determining
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bonding to the casing. Four foot spacing is being used, however it
does not have satisfactory resolution for evaluating the relationship of
the cement to either the casing or formation.
The significant fact remains that none of the toots located
channels smaller than 30 degrees in the well. Such channels
represent a significant avenue for movement of fluid and methods
must be developed to locate these and even smaller channels. It is
recommended that the logging industry continue research efforts
toward increasing the sensitivity of the logging tools.
The research conducted on the "Logging Well" indicates that
with the presently available tools, the ideal approach for evaluating
the cement in an injection well is to run both the "second
generation" tool and a calibrated "cement bond" tool with single
transmitter/dual receiver three foot/five foot spacing. This
combination gives the most information for interpretive purposes.
An alternative to this approach is the use of either the "second
generation" tool or a calibrated "bond tool" with single
transmitter/dual receiver three foot/five foot spacing. The "second
generation" tool gives no information on the cement/formation
coupling, but gives excellent information on the cement/casing
bonding and its presentation allows for easy interpretation. The
"cement bond" tool provides information on both casing/cement
bonding and coupling to the formation, but is somewhat harder to
interpret and may be less sensitive in some specific situations.
Calibration of both tools is imperative for reliable data to be
produced. The size and weight of the casing must be available for
use with the "second generation" tool. A standard shop calibration of
the "cement bond" tool is essential to its use and must be included
for there to be any hope that reliable information can be obtained.
Quality control on the "cement bond" tools can be included, to some
degree, on site, in that certain checks can be made to determine
whether or not the tool is working properly.
Some of the checks that can be made include:
1. If the well contains free pipe, the chevron effect must be
obvious. The chevron effect is the "W" seen opposite casing
collars in free pipe. Figure 7 indicates a bond log with free
pipe. Note the well developed chevron effect opposite the
casing collars.
2. In free pipe, certain casing diameters call for certain
amplitude readings. For example, for 5 inch (I.D.) casing the
amplitude should read about 74 millivolts (mv); 7 inch - 60
mv; 8 inch - 55 mv; 9 inch - 30 mv-35mv. Such
information can be used to determine if the tool has been
calibrated. Figure 7 indicates an amplitude reading of over
10
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Figure 7. Amplitude, chevron and free pipe.
11
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c'altated lnCh free Pipe' TWS indicates tha< »« tool was no,
'
Log Interpretation
company personnel inter* he logs The v'orodurT i0""9,
have trained personnel that ar 9 V 9 n° must
—~ a ••r*wirjr, MijctjlHJH WON i
have trained personnel that are
determine as i— *~ ' '
cement behind i
Leak Test Well
me 0T t^e -
packer and for testing the camhS^ iUbing' casi"9 and
detect fluid movemen ar'°US d°Wn-h°le tOOls to
en
•he outside of ,he ^'string
12
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TTJ
Figure 8. Tool not centered.
13
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680'
710'
905'
935'
Injection Zones
1057'Depth of
Upper Packer
Cement
1070'
Baker Model "C-1" Tandem Tension Packer
2 3/8" Tubing
Baker Model "L" Sliding Sleeve
Baker Model "R" Profile Nipple
Baker Model "Ad-1" Tension Packer
2 3/8" Tubing
Baker Model "R" Profile Nipple
Baker Model "F" Profile Nipple
5 1/2" Long String
Perforations
1 084' Depth of
Lower Packer
-1120'
1130'
Figure 9. Leak test well.
14
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Detailed discussion on well design and installation is provided in
Appendix B.
Flow into the well can be controlled so that the injected fluids are
directed into the 2-3/8" injection tubing, or to the 2-3/8" leak
string. Returned flows can be controlled from the 2-3/8" leak string
and also from the annulus of the 5-1/2" casing (Figure 10).
5 1/2" Casing
Head\
2 3/8"Long
String Tubing
2 3/8"Leak
String
Flow Return to
Water Supply Tanks
5 1 /2" Annulus Connection
Figure 10 Injection well head and flow lines.
Monitoring wells will be constructed to each of the zones open to
the "Leak Test Well." One well will be drilled to a depth of 680 feet.
This is open to injection through a Baker Model "F" profile nipple in
the 2-3/8" leak tubing. A second well will be drilled to a depth of
935 feet. This is the second zone open to flow through a Baker
Model "R" profile nipple. A third well is to be drilled 1,130 feet deep
to monitor the pressure changes in the injection zone.
15
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A number of tests have been conducted or are planned for the
'Leak Test" well. Some of these include:
nata Completed
Test
1. Hydraulic conductivity of 5/13/86
the injection zone 4/27/87
2. Radial differential temperature log "^
3. Temperature log Planned
4 Differential temperature log 5/19/86
5. Radioactive tracer survey 4/6/Q7
6. Noise log 1/23/87
7. Acoustic cement bond tool 1/24/87
8. Nuclear activation tool 2/12/87
9. Gas pressure test 1/27/87
10. Down-hole TV 4/8/87
11. PDK-100 tool (oxygen activation) planned
12. Flowmeter survey
13. Annulus pressure changes due to p|anned
temperature changes Planned
14. Volume/pressure relationship
15. Effect of mud in the long string/surface ^^
casing annulus Planned
16. Helium leak test.
Planned
17. "Mule tail test
16
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CONCLUSIONS
alternative rests on the f^yj°fr^p Jnderaroind "sources "of
between the well's o^er casing ana construct and operate
cementing. Although **no technology for
MO one test provides '
determination of *e mech^caM ^ ^ ^
this determination s mad®'r°m1H evaluated together in making an
' of an iniection
research «.
state regulatory agenciest.a"dq lPrAdeterm?ning mechanical integrity.
evaluate a variety of ^e of industry and permitung
acceptance of
new
that may be developed.
17
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REFERENCES
Batcheller, Gary W, Schlumberger .Well Services Cement Evaluation
Seminar.
Gearhart, undated material, Pulse Echo Log, Cement Evaluation.
Casing Inspection.
Maffi A Tom Hansen Co., Cement Evaluation Seminar.
Tom Hansen Co, undated material, Lazer Logging Systems Cement
Bond Log. .
Schlumberger, undated publication, Cement Bond, Variable Dens.ty
Log.
Schlumberger, undated publication, Cement Evaluation Tool.
B G., Mechanical Integrity
March 3-5, 1986.
18
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APPENDIX A
LOGGING WELL DESIGN SPECIFICATIONS AND
INSTALLATION PROCEDURES
LOGGING TEST WELL MATERIAL SPECIFICATIONS:
Casing Weiqht
3 joints of 9-5/8"
3 joints of 9-5/8"
8 joints of 8-5/8"
4 joints of 7"
2 joints of 5-1/2"
3 joints of 5-1/2"
3 joints of 5-1/2"
2 joints of 4-1/2"
4 joints of 4-1/2"
5 joints of 4-1/2"
Equipment
Swage nipple
Swage nipple
Swage nipple
Swage nipple
Swage nipple
10 centralizers
7 centralizers
3 centralizers
7 centralizers
5 centralizers
53.5#/ft
36.0#/ft
24.0#/ft
23.0#/ft
23.0#/ft
17.0#/ft
15.5#/ft
13.5#/ft
11.6#/ft
9.5#/ft
Size
5-1/2" x 4-1/2"
7" x 5-1/2"
8-5/8" x 7"
9-5/8" x 8-5/8"
9-5/8" x 5-1/2"
4-1/2"
5-1/2"
7"
8-5/8"
9-5/8"
Grade
N-80
K-55
J-55
K-55
N-80
J-55
J-55
N-80
J-55
J-55
Grade
DETAILED DESCRIPTION OF WELL CONSTRUCTION
On August 14, 1984, the process of preparing the "channels"
was begun. PVC pipe, either 3/4" or 1/2" in diameter, was sealed on
one end, filled with water saturated with boric acid and capped. The
next step was to attach the PVC pipe to the outside of the casing so
that the "channel" would cover either 90°, 60°, 30°, or 6° of the
360° radial surface of the pipe (Figure 1). This was accomplished by
attaching the PVC pipe to the surface of the casing using fiberglass
cloth and epoxy resin. Three layers of fiberglass were used to ensure
that the PVC pipe was securely sealed and attached to the casing
19
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(Figures A-1 to A-4). This phase of the project was completed on
September 17, 1984.
The casing was then wrapped with heat tape and insulation to
prevent freezing of the "channels" while awaiting the availability of
the drilling rig.
The driller began moving the rig to the site on December 13
1984. Rigging up continued on the 14th and 15th and drilling began
at 2:30 p.m. on December 15, 1984. The procedure followed and the
date each step was accomplished are indicated below:
Date Completed
12/13/84
Prepare site
(Baulch Drilling Company)
2) Move in rig and rig up
3) Drill 15" hole to 40', set 13-3/8"
conductor pipe (OK Cement, 35 sx)
4) Drill 8-3/4" hole to 1530'. Collect
drill cuttings every 10' starting at 100'
5) Condition hole for logging
6) Run Dual Induction Laterolog, Gamma
Ray, Compensated Neutron, Compensated
Density, and B.H.C. Sonic Log (Gearhart)
7) Ream 12-1/2" hole to 758'
8) Clean out hole to TD, condition for
setting casing
9) Set casing
10) Run 2-3/8" tubing and sting into Baker
Duplex Cement shoe. Condition hole
for cementing.
11) Cement casing
(Halliburton, 700 sx. 50/50 Posmix)
12) Remove tubing, flush out hole
13) Weld steel plate between 9-5/8" and
13-3/8" casing. Install 9-5/8'? x 5-1/2"
swage nipple on 9-5/8" casing.
Screw locking cap on swage.
14) Install rock pad and cement slab
12/15/84
12/15/84
12/18/84
12/18/84
12/18/84
12/20/84
12/20/84
12/20/84
12/20/84
12/20/84
12/20/84
12/27/84
09/10/85
The design of the "Logging Well" presumed that the "channels"
would remain in place during the process of setting and cementing
the casing. The driller took special precautions when moving the pipe
from the pipe racks to the rig, and during the pipe setting process to
20
-------
Figure A-1. Preparing fiberglass with epoxy resin.
21
-------
Figure A-2. Applying initial fiberglass layer.
22
-------
Figure A-3. Completed channel - prior to using wire brush to remove
excess.
23
-------
Figure A-4. Removing excess fiberglass with wire brush.
24
-------
. j rQ ;n niapfl as desioned. Later review 01 toys tun un
the well reinforced this'confidence.
Log Interpretation
from the log being interpreted.
s ss
bon throughout the remainder of the sect.or,
c,o
microannuL in the upper part of the secbon.
Coupling to the formation cannot be
determined.
.
o
microannulus in the upper part of the section.
No coupling to the formation.
25
-------
Figure A-5a. Single receiver 3-foot spacing.
26
-------
Figure A-5b. Single receiver 4-foot spacing.
27
-------
Figure A-5c. Single receiver 5-foot spacing.
28
-------
»-"s'
VDL shows tormabon
---^SS-
PossfbleSpling to formation.
Rgure A-5e is the same
Mogs.Thewhrteareas
is available on formation coupling.
A second comparison *
Togging Well" **™££SM' **» 'eceiver' lhhre?
section from a tool with single "a h receiver at about 567
spacing. The fluid wave should JJ**^ on «, log. There
microseconds, however it 's, "otD^ation, however they are not
may be formation signals "«he present , ^^ Qf
piaces °n the '°9' and m
-
transit time curve is not definitive.
" pretation: Exceiie, casing/cement bonding throughout
H the section.
Figure A-Sb is the same s f££X»SfftF&
transmitter/ single receiver fou * ^« sPfnc /C9ement bonding but no
CS^ c^ indicates casing/cement
Client casing/cement bonding, no —on
coupling.
Figure A-6C represents a Jog «rom a
r
the center o, the
29
-------
Figure A-5d.
Dual receiver 3-foot/5-foot spacing.
30
-------
Figure A-5e. Siecond generation log - Company A.
31
-------
I
TT
Figure A-6a. Single receiver 3-foot spacing.
32
-------
t I
Figure A-6b. Single receiver 4-foot spacing.
33
-------
of the section. Formation
indicate coupling to the formation
sionak
9
f T
formation signals throuahom h^ f, °' SPacin9' The VDL
signals near the middle and in °he ower oaT nffn ^''"^ CaS'n9
amplitude curve indicates cempn u?*l?™ I P? °' the sectlon- The
response in the miS of ,he sectfon 9 b°nd'n9' W''th a ver* Sli9ht
Interpretation: Excellent casing/cement bonding with
t,
channels or microannulione in
'
two
Interpretation:
Excellent casing/cement bonding with the
" °r mi-oannu,' in
section- N°
exhibit a ,rave, time that „ eq t,
'°0ls
some casing ^fs™^^ — indicates
Interpretation: Poor casing/tement bondin9 in the upper part
The ampl.tude curve and VDL are
CvnS lntthe IOW6r Part of the sec^
fh« rafi- ? at6? casin9^ement bonding and
^amplitude .nd.cates poor bonding in one
34
-------
Figure A-6c. Single receiver 5-foot spacing.
35
-------
LY'iM » " 'H» w U'AJJ'iM^^ >
SOtaiy^gSSg
Figure A-6d. Dual receiver 3-foot/5-foot spacing.
36
-------
Figure A-6e. Second generation log - Company B.
37
-------
Figure A-7a
Single receiver 3-foot spacing.
38
-------
Fiqure A-7b is a log of the same section with a tool with single
transmitter/single receiver, four foot spacing. The VDL indicates
casino/ cement bonding in most of the section with one area of
Sion signal in the lower part. The amplitude curve ,nd(cates
casing signal in the lower part.
Interpretation: Good casing/cement bonding in the upper part
of the section. No formation coupling in the
upper part. The amplitude curve and VDL are
contradictory in the lower part of the section.
Figure A-7c is a log of the same section from a tool with single
transmitter/single receiver, five foot spac.ng. The VDL indicates
oSon signals throughout the section with possible casing signals
n the uDDer part The amplitude curve indicates poor casing/cement
bonclngTh%uPghout most of the section except for about 10 feet ,n
the upper part and the lower 20 feet.
Interpretation: Poor cement/casing bonding throughout the
iniBrHiBUHiuM. ( ^ nKrt..t m foot jn the upper
part and the lowermost 20 feet. The amplitude
curve and VDL are contradictory in the lower
part. The amplitude curve reads over 70mv,
which indicates free pipe.
Fiqure A-7d indicates a log of the same section from a tool with
le transmitter/dual receiver with three foot/five foot spacing. The
£5as formation ^^^^.^J^B^^B
Annals in the upper part. The amplitude curve indicates
cemenVcLsing bonding with one possible problem in the upper part
of the log.
Interpretation: Excellent cement/casing bonding throughout
P most of the section. Possible channels or
microannuli in the upper part of the section.
Formation coupling throughout most of the log.
Fioure A-7e is the same section from one of the "second
qene ation" logs. The bond image part of the log indicates three
channe s or microannuli in the upper two-thirds of the log _The
minimum compressive strength curve supports that some problem
exists in these areas.
Interpretation: Excellent cement/casing bonding with three
in p channels or microannuli. No information on
formation coupling.
As can be seen from these examples, casing signals and
formation signals are very difficult to differentiate when a fast
formation is involved.
39
-------
Figure A-7b. Single receiver 4-foot spacing.
40
-------
Figure A-7c. Single receiver 5-foot spacing.
41
-------
Figure A-7d.
Dual receiver 3-fool/5-foot spacing.
42
-------
Figure A-7e. Second generation log - Company A.
43
-------
APPENDIX B
CRm"'A
LEAK TEST WELL
K TEST WELL g faci||ty „
The purpose of the Leak Te We I « P casing and
develop methods for ^ *^°S Carious down-hole tools to
water disposal well used 'nr^a°'ong string, tubing, and packer
Deludes the use of s"^" ^includes two packers and a
The deviation from the norm in this ^we attached to
v e « face Figure 9).
^
« JffSS to surface (Figure 9).
f
the outs.de of the long smny based on
The depth to which surface cansin9o^rSvetrequirements to
"Logging Well.* extends from
The 2-3/8" tubing, out* the 5-1/2 tang -jy. h
"
571 feet of 13-3/8" casing
44
-------
Baker Model "R" Profile Nipple 1.78
Baker Model "RW Profile Nipple 1.81
Baker Model "F" Profile Nipple 1.87
Baker 5-1/2" Float Shoe
Hinderliter 10FSF Wellhead for dual completions (5-1/2" and
2 -3/8")
3 centralizers 5-1/2"
The surface equipment for the "Leak Test Well" consists of two
100-barrel fiberglass tanks, a 10-horsepower electric powered
injection pump, high pressure injection flow lines, and schedule 40
plastic return flow lines (Figure 10). The water supply is from the City
of Ada, Oklahoma. The control accessories are an air chamber,
which smooths out the pumping actions of the pump pistons; a
pressure control valve, which can be set to any predetermined
pressure from 10 to 600 psi; a check value which prevents back flow
in the injection line; a strainer to catch foreign material that may be
pumped into the line; a flow meter to record the number of barrels of
liquid pumped; a flow outlet pipe used to calibrate the flow meter; a
control valve to regulate the flow to the injection well; a thermometer
to determine the temperature of the injected fluids; and pressure
gauges to indicate the injection pressure (Figure B-1).
Flow into the well can be controlled so that the injected fluids are
directed into the 2-3/8" injection tubing, the tubing/casing annulus,
or to the 2-3/8" outside tubing. Returned flows can be controlled
from the 2-3/8" outside tubing and also from the annulus of the 5-
1/2" casing.
Wells will be constructed to monitor each of the zones open to
the "Leak Test Well." One well will be 700 feet deep, to monitor the
sand at 680-710 feet; a second will be about 920 feet deep, to
monitor the sand at 905-935 feet; and the third will be 1,130 feet
deep, to monitor the pressures and water quality in the injection
zone.
TEST SUMMARIES
A number of specific tests are planned for the "Leak Test Well."
As the tests are completed, brief summaries are prepared and
forwarded to the Underground Injection Control Program Offices in
EPA Headquarters and the regions. Summaries of those tests
completed to date are presented in the remainder of this appendix.
45
-------
Flow Return Line
Flow Thermometer
Meter
From Water
Supply Tank
O
To
Injection
Well
Pressure
Gauges
Figure B-1. Injection pump and control accessories.
46
-------
' 1: ACOUSUC Cemem Bond T°01 Test to' Flow Behind
ir field off0lney
2=
tO°'(S) be tested in the
conditions under which it will or will not work
'2; "Mac"Mc1Gre90r. a log analyst for Dresser Atlas, contacted
^
the
Tesf IVe// Conditions
wave from a cement bond tool. The test
was
-**
Figure B-2 indicates the configuration of the Leak Test Well
s -sr
into the 5-1/2 casing and out the perforations.
Test - Phase I
The tool was placed in the injection tung a 57 feet and
the oscHloscope was viewed in the no-flow and flow conditions
47
-------
680'
710'
905'
injection Zones
935'
CBU Liquid F*w Test -Ph.-
V Unseat packers
Sleeve
Baker Model ' R
Profile Nipple
5 eater Model Ad-1
Tension Packer
6 2 3/8" Tubing
°f 7 Baker Model R
„
Profile Nipple
g 5 1/2" Long String
1120'
1130'
Leak Test Well
Figure B-2.
CBL liquid now test - Phase
48
-------
Cement Bond Log Tool
m.4
•51/2'
Plug
-*<-4
Lt,
"•
\
.
j
(
•4—
X
\
*
H<
*-
-4
^*.X$M&:t$$. Flow= 1
M-.-.-. x&tfy:^ ::::::::;:;: Injection Zones
— 1
CBL Liquid Flow Test - Phase II
1 . Pull tubing and packers
2. Set plug in 5 1 /2" casing at
1010'
3. Pull tubing
4. Fill 5 1 /2" casing with water
5. Set CBL tool in 5 1 /2" casing
at variable depths
6. Pump water down 2 3/8" leak
tube at 3 different rates
Cement
1. 2 3/8" Tubing
2. Baker Model "R" Profile Nipple
3. Baker Model "F" Profile Nipple
4. 5 1/2" Long String
1120'
1130'
Leak Test Well
Figure B-3. CBL liquid flow test - Phase
49
-------
Test - Phase I Oscilloscope
Response
Row Rate
Time_ • None
1:50p.m. No flow Yes
loopm. 4gpm Yes
1-17 pm. a™9P™ +air Yes
1-20 om 0.78 gpm + ™ Yes
A 6 gpm + air ves
2:24 p.m. Stopped injection
Tesf - P^se « , the tubing and packers
The second test was • ^ Ph'ase
and a bridge Plu9,s.S " for this test was a 3:5/8
Test - Oscjlloscope
Tool
teet ar None
600 | None
700 * None
800 I None
900 B None
tubing.
Conclusions h „ jd wave of the
1 a ™ ~-' s
3/8"
50
-------
Thus, flow in the manmade channel behind the 5-1/2" casing could
not be detected under the test conditions.
One explanation for the responses observed under the test
conditions previously outlined is that under free pipe conditions, the
paths for movement of the sound wave are through the casing and
fluid. Thus, under static conditions where the tool is not moving and
there is no movement of f|uid in or behind the pipe, the fluid wave, as
presented on the oscilloscope, is also static. On the other hand, flow
of fluid behind the pipe while the tool is stationary affects the sound
wave as it moves through the fluid, causing a distortion of the wave.
This distortion shows up as rapid changes in amplitude in the display
of the fluid wave on the oscilloscope and indicates movement of the
fluid. Thus, under free pipe conditions, the fluid wave has the
capacity to reflect fluid movement behind pipe.
The presence of cement behind pipe presents a much more
difficult set of conditions for identifying fluid movement with the
cement bond tool. The paths for the sound wave under these
conditions are: movement along the casing and cement (small signal
because of the attenuation effect of the cement behind the casing),
movement through the formation and movement through the fluid.
The heterogeneity of the formation, the size of the channel, and type
and amound of fluid movement will all affect the ability of the tool to
identify fluid flow in channels in cement. Thus, the capability of the
acoustic cement bond tool to identify fluid flow in channels is
unproven, though certainly not impossible.
Recommendations
Field data should be accumulated to determine the capability of
this type of tool for detecting flow behind casing in varying well
conditions; i.e. free pipe and channels in cement.
When running other tools, such as temperature or noise surveys
for detecting flow behind pipe, service companies should run the
bond tool for comparison purposes to determine if flow in channels
can be detected.
51
-------
Test No. 2: Nuclear Activation Technique for Detecting Row
Behind Casing
Introduction
On January 23 and 24, 1987, personnel from the Robert S Kerr
Environmental Research Laboratory (RSKERL) and Dresser Atlas
conducted a series of tests for determining flow behind pipe using
two neutron activation tools.
The purpose of the tests was to determine if flow of water at
various rates could be detected behind the pipe using the data
presented by a pulsed neutron lifetime logging system (PDK-100)
and a Cyclic Activation Tool.
Tools Tested
Two tools were tested during the two-day period:
• a 1-11/16" diameter,PDK-100 Tool
• a 3-5/8" diameter Cyclic Activation Tool
The operation of both tools is based on a nuclear activation
technique in which flowing water is irradiated with neutrons emitted
by a logging sonde. These neutrons interact with oxygen nuclei in the
water to product nitrogen -16. 16N decays with a half-life of 7 13
seconds, emitting gamma radiation. The flow is then computed from
the energy and intensity response of two gamma ray detectors
mounted in the logging sonde.
Test Well Conditions
The tests were developed in four phases, the first three using the
PDK-100 Tool and the last using the Cyclic Activation Tool.
Figure B-4 indicates the configuration of the Leak Test Well for
the initial test. In this configuration, water was pumped down the
tubing/casing annulus into the injection zone with the 1-11/16"
diameter PDK - 100 Tool held stationary in the 2-3/8" injection
tubing. This condition represented How in the free-pipe condition
i.e., with no cement behind the pipe (2-3/8" tubing in this case) A
valve at the surface on the outside 2-3/8" tubing was closed so that
circulation was not possible up that tubing.
Figure B-5 indicates the well configuration for the second test,
which was designed to simulate upward flow in a channel in cement'
Water, pumped down the tubing/casing annulus moves through a
1/4" hole in the 5-1/2" casing at 1,070 feet and up the 2-3/8"
outside tubing. The section of the wall between 1,070 and 950 feet
has cement behind the 5-1/2" casing and thus around the 2-3/8"
tubing. The tubing in that area represents, to some degree, a channel
in the cement.
52
-------
1057'Depth of
Upper Packer
TT 680'
i 710'
Flow =
905'
935
Injection Zones
NAT Liquid Flow Test - Phase I
Cement
1070'
1084'Depth of
Lower Packer
1 1 00'
1.
2.
3.
4.
5.
6.
7.
8.
9.
Unseat packers #1
Set NAT tool in 2 3/8" tubing
at variable depths
Pump water down 5 1/2"
casing at 3 different rates
Baker Model "C-1" Tandem
Tension Packer
2 3/8" Tubing
Baker Model "L" Sliding Sleeve
Baker Model "R" Profile Nipple
Baker Model "Ad-1 "Tension
Packer
2 3/8" Tubing
Baker Model "R" Profile Nipple
Baker Model "F" Profile Nipple
5 1/2" Long String
1120'
1130'
Leak Test Well
Figure B-4.
Neutron activation tool liquid flow test - Phase
53
-------
5-
>,;
if
\
*
_
i^
i
looo
t~
1
/-
1 II
* II
\
m
_^
N,
1,
-/I
~
•r-
-^
<
(
|
*?
t
*~
>
.^ ^
t
T
-g
pr
tpr: 8 :•:•:•:-:-••;-:;:.;.:•:•:•:•••:••••:•
I'.I.M "7 '•'•'-'•'. '.::•.:- \-.-.r.\\\\
— 6
1057' Depth of
Upper Packer
NAT
1.
2.
3.
4.
Cement
1.
2. .
3. I
4. E
5. E
F
6. ;
7. E
8. E
9. e
1084' Depth of
Lower Packer
1100'
y.v. .,,;.;.;,.;.;.;..;. ., . II
680'
710'
905'
935'
Flow =
= J
Injection Zones
NAT Liquid Flow Test - Phase II
Unseat packer #1
Plug profile nipple #4
Set NAT tool in 2 3/8" tubing
at variable depths
Pump water down 5 1 /2"
casing and up 2 3/8" tubing
Baker Model "C-1" Tandem
Tension Packer
2 3/8" Tubing
Baker Model "L" Sliding Sleeve
Baker Model "R" Profile Nipple
Baker Model "Ad-1 "Tension
Packer
2 3/8" Tubing
Baker Model "R" Profile Nipple
Baker Model "F" Profile Nipple
5 1/2" Long String
Leak Test Well
Figure B-5. Neutron activation tool liquid flow test - Phase II.
54
-------
tK-^ i- . ' K""'[jeu uown thp 9 Q/Q" „ , -. channel in
through the 1/4" hole in the 5 1/9-6 Outs'de tubin9 moves
5- 1/2" asing to the surface. CaS'n9 at 1'070 *** and up the
tes,
J:
- P/Jase /
!st was conducted with the PDk- mn T ,
ocated below the neutron QPn / ol Wlth tne two
could be detected. With the tool Inratn S° that downward flow
a3n8d Sre.TS f^^^^XS1?,,?^
thoi-rt ti yaiion per minute /nnmi -r nuw
these flow rates were conducted anri flnl? (9P J' wo reP''cations of
all instances. °'ed and flow was detected by the tool in
Test - Phase II
Too, Wlth the
he outside 2-3/8 could be detected9 ^K° delermine " *« up
'eet, data was obtained under no fll'^^ t00' located « 600
ROW UP the °u's* 2-3/8" '
Test - Phase HI
JJ« r(:idPDI<-1«> Tool at 600 feet
Water was pumped OoSffl^.*™* f »e Phase II
1/2 casing at three different rates (flat! Ub'"9 and UP *e 5
W3S det '' 1
"as then chanaed with *h~ ^ .
'•:-='«' "> determine if downward ftow in thf'6?'0;8
-—..» v.^u.u be detected Flow ri^,n ^ In tne outside
could not be detected. - °Wn the Outside 2-3/8" tubing
Test - Phase IV
Te a(H8" diame- Cyclic
detechng f,ow in the 2 sT^'ls^r ^ the Seneratorlor
through the 1/4" hole into the 51/9" m°'/ed down the tubing
-o the inaction intervaf
55
-------
%&X&xg$< 680'
^:::::^v^:':-f:: 710'
1057'Depth of
Upper Packer
Flow =
905'
935
Injection Zones
1070'
1084'Depth of
Lower Packer
NAT Liquid Flow Test - Phase III
1. Unseat packer#1
2. Plug profile nipple #4
3. Set NAT tool in 2 3/8" tubing
at variable depths
4. Pump water down 2 3/8"
tubing and up 5 1/2" casing
1. Baker Model "C-1" Tandem
Tension Packer
2. 2 3/8" Tubing
3. Baker Model "L" Sliding Sleeve
4. Baker Model "R" Profile Nipple
5, Baker Model "Ad-1 "Tension
Packer
6. 2 3/8" Tubing
7. Baker Model "R" Profile Nipple
8. Baker Model "F" Profile Nipple
9. 5 1/2" Long String
1100'
1120'
1130'
Leak Test Well
Figure B-6.
Neutron activation tool liquid flow test - Phase
56
-------
680'
710'
905'
935'
FIOW=
Injection Zones
NAT Liquid Flow Test - Phase 111
1. Pull tubing and packers
2. Set plug in 5 1/2" casing at 1010'
3. Pull tubing
4. Set NAT tool in 5 1 /2" casing at
variable depths
5. Pump water down 2 3/8" leak
tube at 3 different rates
1. 2 3/8" Tubing
2. Baker Model "R" Profile Nipple
3. Baker Model "F" Profile Nipple
4. 5 1/2" Long String
1100'
1120'
1130'
Leak Test Well
Figure B-7. Neutron activation tool liquid flow test - Phase IV.
57
-------
0.79 gpm. All three flow rates were detected by the tool and fin*
veloc,t,es were calculated from the data collected by theTool
Conclusions
The PDK-100 Tool was able to detect all three flow rates when
ow was up or down the 5-1/2" casing. The tool did not
flow up or down the outside 2-3/8" tubing.
*£* t0 detect a" three f'ow rates
Recommendations
Dnal work should be done to increase the sensitivity of
Tool. It should be noted here that since the tests v
tnhnn n , ab'6 t0 aele^ ^W in Outside
S^SLS, »ell constructed very similarly to the Leak Test We7 The
adjusted tool w,ll be retested at the RSKERL Test Facility as soon as
t can be arranged. In the meantime, Dresser Atlas personnel S run
by Mob"'and
. The capability of this equipment to locate flow behind pipe could
DG £1 ^IflI"!lrlf"*3nf rimolxtl^*-*-* it t i " r*** *-***-**JHJ
Especially the PDK-100 Tool^hich^aTbyTurfin Tubfnq'ffll^f'witti
water or with only air present. Thus, no workover costs would be
involved ,n testmg a well, i.e. setting plugs, pulling tubing, etc
58
-------
Test No. 3: Testing for a Hole in the Long String
Introduction
On January 23, 24 and 25, 1987, while testing tools for detecting
flow behind casing, test results indicated a possible hole in the 5
1/2 long string of the research well. A series of tests was conducted
on the well on January 25, 27, February 2, 3, 10, 11 and 12 to
determine whether or not there was a hole in the pipe.
Test Well Conditions
The attached diagram (Figure B-8) indicates the well
configuration dunng most of the tests to be discussed. Any changes
in the well will be noted as the various tests are discussed.
While testing an Acoustic Cement Bond Tool (ACBT) the 5-
1/2" casing was full of fluid above a bridge plug and water was being
pumped down the outside 2-3/8" tubing at about eight gpm
Pumping had been in progress only about 5 minutes when water
began flowing out of the 5-1/2" casing at about 2 1/2 gpm.
The immediate thought was the bridge plug was leaking
however, the Baker Packer representative was confident that the
bndge plug could not leak. In checking the setting depth for the plug
it appeared possible that it was located opposite a casing collar The
plug was reset to insure that it was properly set between collars.
Acoustic Cement Bond Tool
A plan was developed to systematically check the well to
determine where the leak was in the system. The first approach was
to use the ACBT to determine if flow in the 5-1/2" casing was
occurmg. The tool was set immediately above the bridge plug which
was set at 1,010 feet, and readings were taken to determine'if flow
would be reflected by the fluid wave. The tool was then moved up
the well at 100 foot increments and readings taken, with the following
results: y
Flow Indicated
1,000 No
900 No
800 No
700 No
600 No
500 No
400 No
300 Yes
250 Yes
200 Yes
59
-------
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— 3
— 2
Injection Zones
— 1
Cement
1. 2 3/8" Tubing
2. Baker Model "R" Profile Nipple
3. Baker Model "F" Profile Nipple
4. 5 1/2" Long String
1 100'
1 1 20'
'•••.•.•.•.•.•,•,•.-.•.•• 1 1 30'
Leak Test Welt
Figure B-8. Testing for a hole in the long string.
60
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Pressure Test - Gas
Pressure Test - Water
Pressure Test - Packer
Packer
in Pressure
feet
115 g2
295 ^g None
595 1QO None
None
61
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