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societyof Petroleum En@reers
SPE 26043
Diagnosing Production Problems With Dovvnhole Video Logging
at Prudhoe Bay
T.T. Allen and S.L, Ward, ARCO Alaska Inc.; R,D. Chavers and T.N. Robertson,
Otis Engineering Corp.; and P.K, Schultz, Westech (%ophysical Inc.
SPE Members
Copy?lght 1993, Society of Petroleum Engineers, Inc.
Tltls paper waa prepared for praserrlatlorr a! the Wesiern Regional Meeting held In Anchorage, Alaska, U.S.A., 2&28 May 1993.
This permr waa ealected for presentation by an SPE Pregram Committee followlng ravlew of information containad In an abstract eubmrtted by tko aulhor(s). Contents of the Paper,
ae preeerrted, have not been reviewed by the Soclaly of Petroleum Engineem and are eubJect to corretticrr by the au!hor(e). The material, as presented, does not necessarily reflect
any ~sttion of the Sotiety of Petroleum Englnears, lte officere, or members. Papara presented at SpE meetlnss are eublacl to Publfcalion review by Efltorlal Commllfee$ of tho SOc~eW
of Pelrc-fmrm Engineers. Permlaekm 10copy Is reelricfed to an abstract of not more than 3C0 words. IIlu$lralions may not be wpled. The abstract should contain conspicuous acknowledgment
of where and by whom the paper Is preeerrted. Write Librarian, SPE, P,O. Sox S33836, Rlchardeon, TX 7E4M3-3WS, U.S.A. Telex, 163245 SPEUT.
A8sT~K,I
Thispaper describesareal time, fiber-opticdownhole
video (DIN) system and its use as a diagnostic tool
in solvingproductionproblemsin PrudhoeBaywells.
Recent developments in lens preparation technology
and advancementsin the applicationof electro-fiber-
optic cable have proven the viability of DEN logging
in oilfield applications. The case histories of three
field applications in which oownhole visual
inspections of tubulars and casing were used
successfully are presented. These opxations
determined fluid entry under flowing conditions,
verified tubing and casing integrity, and facilitated
wireline fishing operations.
UCTKM(
Until recently, real-time downhole video systems
relied on specialized large-diameter 9/16-inch
[14.3 mm] coaxial cable to transmit the high data
rates required for real-time video to surface when
loggingin wells of significantdepth.”2 These coaxial
systemshave been primarily used in wells with little
or no surface pressure because of the operational
Itsferencea snd illuctrstions st end of psper.
difficulty in maintaining pressure control with the
large-diameter cables. Using an electro-fiber-optic
cable instead of the coaxial cable improved the
picture, and more importantly, reduced the cable
diameter required for data transmission. The 7/32-
inch [5.6 mm]diameter electro-fiber-opticcable now
makes dealing with high surface pressure a routine
procedure.
A unique, highly-specializedsurfactantthat repels oil
and inhibits condensationwhen properly applied has
recently been developed. The surfactant has been
field testedand is now being used on the camera lens
and light domes to make viewing of wells while on
production possible. Before the developmentof the
new surfactant, many other products including
detergents, phosphates, petroleum-based coatings,
acid&d ethanol/isopropanolpolish, and a myriad of
other wetting agents had ken tried; however, these
products proved to be only marginally successful.
The new surfactant, which is polished into the glass
surface to prohibit oil adherence to the camem lens,
has permitted viewing for more than eight hours in
wells with high oil concentration without the oil
adhering to the camera lens and obstructingthe video
picture. Even after tmversing thousands of feet
through a column of oil, visual clarity returned when
149
2 Diagnosing Production Problems With Downhole Video Logging at Prudhoe Bay SPE 26043
a clear mediumwas encountered.
Recmt advancesin lens preparationand electro-fiber-
optic technology have eliminated the two most
persistent operational problems associated with
obtaining quality DHV logs: 1) controlling high
surface pressures and 2) logging through opaque
fluids. The capability to log or pump into a well
underhigh pressure provides operationalflexibilityin
attemptingto achievea clear mediumfor viewing. It
is no longer necessary to bad or kill a well before
running a DHV log. Wells with high shut-in surfaoe
pressures can often be logged in gaseous
environments. New surfiwtantsfor the DHV camera
lens have eliminated the need (and associated
expense) to completely sweep the wellbore of oil.
Wells can be logged while on production without
fouling the camera lens and obstructing the DHV
picture. DHV technologyhas progressed to the point
that DHV logging is now viable for a variety of
downholeapplications.
POWN~OLK!QQL CONFl~URATl~M
A schematicof the DHV cameras wed in the logging
is shownin Figure 1. The 1-1l/16-inch- [42.9 mm]
diameter cameras are Comprised of four
subassemblies; the cablehead, electronic chassis,
housing or pressure barrel, and the lighthead. The
l-3/8-inch [34.9 mm] cableheadincludes an external
fishing neck on top of a cable packoff and ekdrical
and fiber-optic connectors. The electronic chassis
includes an electronics package and a fiber-optic
transmitter. The housinghas internal supportsfor the
electronic chassis. The lighthead attaches to the
lower end of the housing and typically consists of a
set of three rods that supports two opposing lamps,
which are psitioned in front of the lens.
The lights are powered by direct current (DC)
through the conductors in the cable, and their
intensity is adjusted from the surfkceby varying the
voltage. For optimal viewing, the distancesbetween
the camera lens and the light sourcxware adjusted
prior to thejob for the dueter of the tubulars. It is
often desirable to view smalldiarneter production
tubingwith the upper lamp and large-diametercasing
with the lower lamp in the same logging run.
Switchingbetween the upper and lower lamp during
logging is performed by varying the voltage at the
surface.
~~SIDE~ATIO~S
The DHV system still presents several operational
challenges that must be considered in job design to
obtain a successful DHV log. These challenges
includ%
1.
2.
C@en@ngternpmaturesfor the DHV cameras -
Current DHV cameras are rated to a maximum
working temperature of 175‘F [79°CJ, although
a few have been able to operate up to 195*F
[91°CJ, As the temperature increases above
175*F[79”C], the picture will gradually degrade
and fimlly disappear completely. However, the
picturewill return once the temperatureis reduced
to within the camera’s operating range. With
bottomholetemperaturesranging from 180-235°F
[82”-113”C.]at Prudhoe Bay, cold fiuids often
have to be pumpeddownholeprior to loggingthe
wells. High-temperature DHV cameras are
currently under development.
~fectiw Ulumindbn area of the Eghthewis-
Current lightheads typically used for DHV
logging illuminate only a relatively small section
of the pipe wall. For a standard two-lamp
lighthead, approximately 4 inches [102 mm] of
the pipe wall can be seenwith the upper lampand
10-16 inches [254 -406 mm] of the pipe wall
with the lower lamp, depending on the tubing or
casing size. While this allows close inspectionof
the casing and tubulars, the close perspective
makesit difficult to discern subtle changes in the
internal diameters of the tubulars. Uniform wall
loss from corrosion or scale buildup is often
diflicult to differentiateon pipe wails on DHVlog
remds (i.e. video tape).
150
q

SPE 26043 Thomas T. Men, Ste@hrn L. Ward, Raymond D. Chavera, Thomas N. Robertson, Philip K. Schultz 3
3.
New lighting systems are being devebped that
will project the light further down the hole. The
narrow field of view of the present system makes
it difficult to log dynamic fluid changes.
Meeting tubing kdrs while tubing and annulus
fluids equab is typically a “hit or miss”
proposition. Swapping of fluids will often
obscure the DHV in the areas of mostinterest. In
addition, the narrow viewing area also dictates
slow traveling and logging speeds. Traveling
SpeOdS of 10150 fthnin [0.51-0.76 III/S] and
logging speeds of 10-30 ft/min [0.05-0.15 lrds]
are typical fos a DHV log. The new lighting
systems shouIdincrease viewingarea and cIarity,
allow faster movement,and reduce actual logging
time and expse.
Mhxhuns won@ine tensiim of the elec$n7-
jtboptic cdk - The electro-fibmoptic cable
has a maximumworking strength of 1,200 lbs
[544kg]. Pulling the line above this point begins
to break the optic fibers inside the cable even
thoughthe breaking strengthof the armor is 4,700
lbs ~,132 kg]. The potential for becoming
caught on a fish downhole and not being able to
pull free without damaging the line bemmes an
operational concern when performing DHV
logging for fishing operations. The limited
surfhce pull also places an effective limit on the
logging depth of the DHV camera system. With
a line weight of 85 lbs/1000 ft [0.126 kg/m], a
maximum logging depth of 14,000 ft [4,267 m]
MD is possible, and North Slope wells have been
SUCC4Wfid 10~ed to thiS depth.
PHV C~~l=OR@
_ her inspectionand I%oductionFrof~e
A DHV log was run in a high-rate waterflood
producer to help determine the appropriate remedkai
wellwork needed to improve oil production. Two
alternatives under considenition were w 1) cement
squeeze for water shut off or 2) sidetrack the well.
The cement squeezewould be more economical, but
there was concern about the integrity of the
productioncasingand achievinga successfulsqueeze.
If production tubing or casing integrity had been
compromised, sidetracking the well would be more
cost effwtive.
The well unum considerationwas completed in 1978
with 9-5/8-inch [244 mm]production casing and a 7-
inch [178 mm] by 5-1/2-inch [140 mm] tapered
production tubing string with side-pocket gas-lift
mandrels (GLMs). Directionallydrilled, the well had
an average deviation of 50° across the !ladlerochit
formation. TIMreservoir consists of five hydraulic-
flow units in the area of the waterflood where the
well was drilled. At the time of the DHV,logging,
the well was producing from all five flow units at
2,000 BOI?D, [318 m3/d oil] 8’7% watercut, and
2,950 scf/STB [525 std m3/stock-tankm3].
Previous surveillance work on the well consisted
primarily of two productionprot51es,which were run
in 1988 and 1989. Neither profile was effective in
interpretation of production splits and oil entry
sources. Each profile was run immediately prior to
adding additional perforation interwds. The mom
recent profde indicatedsignificantliquid fallbackthat
prevented determinationof representativeproduction
rates from the lower perforation intervals.
A proposal was made to investigate the feasibilityof
visually logging the perforations to determine phase
entry while the well was on production. lMs would
be an alternative to a conventional productional
profile, which typically consists of a combinationof
flowmeter, fluid density, fluid capacitance,
temperate, pressure, or gamma-ray logging tools,
Basedon the results from the previous work, another
production profile was not expected to provide
conclusive information. The high watercut of the
well wasexpectedto render inconclusivefluiddensity
and capacitanceresponses. A production profile was
also expectedto showconsiderablewater fallback. A
flowingattemptwas to be made since a DHVlog was
already planned to inspect the production tubing and
casing for damage.
151
4
q

Diagnosing Production Problems With Downhola Video Logging at Prudhoe Bay SPE 26043
1
TM well was shut in 12 hours prior to logging with
the DHVcamera to allow wellborefluidsto segregate
into their respective phases. A fluid hwel,
determined with an echo meter, was found to be at
11,550 ft [3,520 m] MD with 2,700 psi [18.62 mPa]
shut-in tubing pressure (!UTP). The tubing was
logged in gas at 60-120 fthnin [0.30-0.61 rnh], and
the casing was loggedin gas at 25 fthnin [0.127tis]
from the tubingtail at 11,262ft [3,433 m] MD to the
liquid Ievel. Filtered sea water was then pumped
down the tubing at 1.5 bblhnin [0.238 m’hnin] to
depress the liquid level. The casing was logged in
gas to 11,802 ft [3,597 m] MD where fill that
covered the bottom two sets of perforations was
encountered.
The staticDHV log results showedthe tubing was in
relatively gocxl cundition with only minor pitting
above and below the bottom GLM. The casing was
also in relatively good condition with only moderate
pitting observed near the tubing tail. Across the
perforations, the DHV log showed seven isolated
perforations ercxled to nearly l-inch [25.4 mm]
diameters,doublethetypica10.4-O.5-inch[10-13mm]
entrance hole diameter.
The well was slowly brought on production and
flowed to a test separator, once the static DHV
logging passes of the tubing and casing were
completed. Productionwas restricted to 6,600 BLPD
[1.049 m3/d]and 8000 Msef/D [227 Mm’/d] at 1100
psi [7.58 mPa]FTP. The rate was restricted because
of operationalconcerns about potentially flowing the
DHV camera uphole and damagingthe electro-fiber-
optic cable. As the well was brought on production,
several flowing DHV camera passes were made
across the entire perforated interval to investigate
phase entry points. While the production rate was
stabilizing, the downhole flow regime changed
significantly. Production was observed from the
upper perforations only on thf ffist pass and from
progressively lower perforums on subsequent
passes.
An analysis of the flowing DHV log is shown in
Figure 2 with results horn a conventionalproduction
profile. The analysisis a quaMativeevaluationof the
oil and gas entry observed horn the DHV log. A
three-tier scale was used to quanti~ the magnitudeof
the oil and gas entry obsemxi on the DHV log. The
three levels of the scale represenfi 1) no fluid entry,
2) minor fluid entry, and 3) major fluid entry. Any
perforations without oil or gas entry were either
nonproductiveor producing only water.
The DHV analysis showed oil and gas production
from only about 10% of the open perforations. The
oil and gas production was distributed across the
length of the open perforations with only isolated
perforations producing in each inteml. A major
casing leak was found in a casing collsr at 11,458ft
[3,492 m] MD. No analysis of the top two
perforationintervalswas done becauseof an oil/water
interface, logged at 11,400 ft [3,475 m] MD. The
interfaceobscuredany video results above tlds depth.
Had the oillwater interface occurred at a greater
depth, the amount of DEW production information
would have been significantlyreduced.
Two weeks after the DHV log had been run, a
productionprofde was run with conventionallogging
tools for oornparativepurposes, The comparisonwas
to determine if the DHV results would provide
information that was not readily available from
conventional logging tools. Since conventional
production profiles am already available fo~most of
the producers, the comparison would ako aid in
evaluating future candidates for DHV production
logging.
Theconventionalprofile response, as shownin Figure
2, generally correlated with the DHV results. The
flowmeter (or spinner) confirmed that approximately
8% of the prw!uction was coming from the casing
leak at 11,458 ft [3,492 m] MD. The fluid density
response indicated 100% water flow from 11,802-
11,400 ft [3,597-3,475 m] MD, an oil/water
transition layer between 11,400-11,360 ft [3,475-
3,463 m]
11,300 ft
~, and a gas/oil layer from 11,360-
[3,463-3,444 m] MD. The DHV log
I
152
.
q
SPE 26043 Thomas~. Mm, Stephrn L. Ward. Raymond D. Chav@rs.Thomas N. Roba@son, ~illP K- S*U~Z 5
results showed water as the primary phase between
11,802-11,400 ft [3,597-3,475 m] MD and oil as a
continuous phase above the oil/water interface at
11,400 ft [3,475 m] MD. The gradient temperature
response also correlated well with the DHV gas
analysis. The temperatureresponse shows major gas
entry at 11,400 ft [3,475 m], 11,458 ft [3,492 m],
11,572ft [3,527 m], 11,656ft [3,553 m], and 11,767
ft [3,587 m] MD that matched with the gas entry
observed on the DHV log.
The primary lfference between the conventional
profile results and the DHV log results is the
identificationof oil producingperforations below the
oil/water interface. The fluid density indicates only
water production fkomthe perforations below 11,400
ft [3,475 m] MD. Oil production shownon the DHV
log from the lower perforation intervals was not
detected by conventional logging tools. The fluid
density results suggest only the top two intervals
produce oil and gas.
Based on the DHV results and other collaborating
surveillance information, it was decided to squeeze
the well and reperforate two of the lower perforation
intervals. J?irst, zone 1 was to be perforated from
11,720-11,740ft [3,572-3,578 m] MD. After flow
testing this zone, zone 3 was to be reperforated from
11,418-11,460ft [3,480-3,493 m] MD.
Withoutthe data providedby the IX-IVlog, the lower
oil-producingintervals mightnot have been identified
and reperforated, which would have resulted in a
reduction of oil production and less chance for
ultimaterecovery.
The productioncharacteristicsnecessaryto define the
range of applicability for DHV logging require
further investigation. Until W range is better
defined,judicious selectionof candidatesand careful
job design is recommended if DHV production
logging is to be successful.
Some of the primary factors contributing to the
successfidlogging of this well were
1. High watercut. Provides a clear viewingmedium.
2. Deviatedwellbore. Allows oil and gas production
to rise to the high side of the pipe.
3. Large productioncasing. The larger the diameter
of the casing, the smaller the area of view
obscuredby opaque fluids.
C3MQ2 Annular Conununication
Troubleshooting and Fishing Operations
A gravity-drainage producer bordering the Flow
Station 2 ()?S-2)waterflood area was diagnosed as
having annular communication. The well was
completed in 1978 with 9-5/8-inch [244 mm]
production casing and 5-1/2-inch [140 mm] tubing
without GLM’s. Later, as the watercut increased, ‘
two retrievablepackoff gas-lift mandrels (POGLM’S)
were run for artificial lift. At the time of the DHV
log, the well was producing at 1,850 BOPD [294
mVd oil], 85% watercut, and 2,950 scf/STB GOR
[525 std m%tock-tiankm3] at 350 psi [2.41 MPa]
flowing tubing pressure @TP).
During a routine mechanical integrity test,
communication was discovered’between the tubing
and the casing. The well would flow to surfaceIkom
the tubingby casing annulus at 950 BLPD [151 m3/d
liquid]. It was suspected that one of the two gas lift
valves ((3LVS)was leaking or was out of the pocket.
To eliminatethis communication,wireline operations
were undertakento change out the two GLVS.
Subsequentwireline operations were unsuccessfulin
locating or latching the top GLV. When additional
attempts were made to replace the bottom GLV, a
restriction was discovered just above the bottom
POGLM. It was suspectedthe bottom POGLM had
collapsed. It was decided that a DHV log to
determine the status of the POGLM’Sand the cause
of the tubing restriction was needed.
To ~repare the well for DHV logging, the tubingwas
displaced with 1-1/2 wellbore volumes (400 bbls
153
.
.
6 tliegnosingProductionProbiems With Downhoie VideoLog@ng at Prudhoe Bay WE 26043
[64m3])of fiitered (2 microns)seawater. Produced
gas,usedforartificialiift, wastheninjecteddownthe
tubing to depress the liquid level. ‘NMinjection
continueduntii the surface pressure of the tubing had
equaiizedwith the iift-gas injectionpressure of 2,000
psi [13.79 MPa]. The DHV camera was then run in
the weii at 150 fthin [0.76 rids]. The top POGLM
at 4,075 ft [1,242 m] MD was logged in gas. The
DHV log showed that the bottom three f~t of the
POGLMwere gone. As shownin the expandedview
of Figure 3, the missing section consisted of a
locating slot, 2 gas guide tubes, and GLV pocket.
With the integrity of the POGLM compromised, the
cause of the annuiar communication between the
tubing and annulus had been determined.
The DEIVcamera was lowered further to fmd the
missing part of the POGLM. The iiquid level was
foundjust below the top POGJ.M at 4,100 h [1,250
m] MD. Rather than risk running into the fish while
DHV logging through oii, sea water was injected
down the tubing at 3 bbihnin [0.48 m3/min] and
2,200 psi [15.17 MPa] to pump the column of
wellboregas to bottom. The DHV camera was then
lowered while stayingjust above ftig iiquid level.
As shown in figure 3, the fish was found stiii intact
just above the bottom POGLM at 6,940 ft [2,115 m]
MD. The gas guide tubes of the fish were located
fwst, foiiowed by the locating slot. The DHV log
showed that the locating slot was cracked. This
would later become a problem in retrieving the fish.
Xnitiaiattempts to log past the locating slot at 20-80
Mnin [0.10-0.41 mls] were not successful..
Eventually, the DHV camera went through the
locating siot at 200 ft/min [1.0 m/s] and stoppedtwo
feet below on top of the GLV pocket. Efforts to run
deeper were not succe.ssfid. However, the DHV log
showedthe top of the pocket with the GLV and both
gas guide tubes in piace. Also shownwas the top of
the three-foot barrel missing from the top POGLM.
Based on the DHV log, subsequent wireline
operations puiied the top POGLM and retrieved the
fish. However, additicmaiattempts to change out the
bottom GLV were still unsuccessful. The bottom
POGLMhad not cdiapsed, but instead, had fded in
a manner similar to the top one. Again, the results
from the DHV log . were instrumental in
troubleshooting this problem and diagnosing the
second fishing situation. The bottom POGLM was
pulled, and the second fish was retrieved. One gas
tube was left in the bottom of the weii. New
POGLM’S were later run, alleviating the annular
communication, and the weii was returned to
production.
- ‘Ihbing and Liner inspection
This was anotherwaterfloodproducer withan annular
communication problem. Previous conductor iine
operations had found two tubing leaks; one was just
above the bottom GLM and the other wasjust above
the polishedbore receptacleof the productionpacker,
as illustrated in Figure 4. Becauseof multipleleaks,
it was suspectedthat the tubingwas severelyemmded
and required replacement. A DHV log was run to
help determine whether the leaks could be
successfully patched and the weii returned to
production. The alternative was to leave the wei.i
shut-in untii a rig could replace the tubing.
The well was a producer in the FS-2 waterfloodam.
It was completed with 9-5/8-inch [244 mm]
production casing and 5-1/2-inch [140 mm]
production tubing with conventionalGLM’s. At the
time of logging, the well was producing at 4850
BOPD, ~71 m3/d oil] 50% watercut, and 2,950
scf/STB [525 std m3/stocktank m3]GOR at 300 psi
[2.1 MPa] FI’P.
The well was prepared for DHSl logging by
displacingthe casing by tubingannulus with 450 bbls
[72 m3]of fiitered sea water and then the tubingwith
300 bbls [48 m3](1.2 wellbore volumes) of filtered
sea water. The fluids were allowed to segregatefor
six hours. Because of the annular communication
between the tubing and casing, it was necmary to
sweepthe annulus with char fluid before Ioadiig the
tubing. Any produced fluids behind the tubing wiii
equaiizewith tubingfluidsduring the logging. Often,
154
v
*’
SPE26043 Thomas T. Allen, Stephen L. Ward, E?aymondD. Chavera, Thomas N. Robertson, Philip K. Schultz 7
this fluid swappingwill obscure the DHV in the areas
of mostinterest unless a good sweepwith clear fluids
is obtainedprior to logging.
With the well shut-in, the tubing was loggedin gas to
the liquid level at 6,428 [1,959 m] ft MD. The
camerawasloweredthrough the oil untilthe oil/water
interfhcewas encountered at 9400 ft ~,865 m] MD.
Unable to view the tubing or the leaks at 9,030-9,150
ft [2,752-2,789 m] MD through the oil, the DHV
camera was pulled back up above the liquid level.
Sea water was then iqjected down the tubing at 1.5
bblhin [0.24 m%nin] to pump the wellbore gas
columnto the perforations. The DHV cameralogged
the tubing in gas by folIowingthe fidlingliquid level
downhole. Just above tie packer, at 9,155 ft [2,790
m] MD, the water injection caught up with the DHV
camera. lMperience has shown that being hit by a
“wall of water” is a good indication of annular
communication. With no annularcommunication,the
gas columnor bubble can generallybe pumpedto the—
perforations without significant water bypass.
While the initial DHV logging provided good visual
coverageof the tubing areas around the leaks, further
investigationwas prevented becauseof the turbulence
.resmltingfrom the injected sea water mixing with the
gas. Parking the DHV camera 200ft [61 m] below
the tubing tail, the sea water injection rate was
increasedto 8 bblhnin [1.3 m3/min]at 2500psi [43.1
MI%]. After pumping 325 bbls [52 m3]down the
tubing, the picture was sufficientlyclear to continue
DHV logging. While maintaininga pumpmte of 3
bblhnin [.48 m3hnin], several passes wwe made
aoross the tubing leaks ftom 9000-9250ft [2,743-
2,819m]MD. As the tubing and annulusequalized,
five separate tubing leaks were observed. The leaks
were on the bottom side of the tubing and originated
ffom a narrow groove (possiblya wireline cut) in the
tubing. The DHV log showed that the rest of the
tubing was not severely corroded and could be
~y patohed.
The produedoncasing was aIsologgedwith the IXIV
camera. The camera showed significantwall 10ssin
the casing from the tubing td to the top of the
perforations. More significantly,severalcasingleaks
were observedat 9,557-9,568 ft [2,913-2,916m]MD
and at 9,598-9,618 ft [2,925-2,932 m] MD. Both
setsof leaks were above the top of the perforationsat
9,630 fi [2,935 m] MD. The DHV log showedan
exposedvoid behind the casing at 9,557 h [2,913 m]
MD extendingdownwardfor approximatelyten feet.
The bottom leak had several jagged holes over it’s
entire length, with the casing appearing to sag on the
bottom side of the hole. Continued DHV logging
revealed that the bottom two perforation intervals
were covered with fill. The casing damage was
extensiveenough to preclude any attempts to cement
squeeze the well.
From the DHV log, the tubing was patched with two
soft-setpatches. This allowed the well to be returned
to production while waiting for a rig workover.
Rather than replacingthe tubingnow, the well willbe
sidetrackedin ‘enear future.
A DHV camera was sucawdidly run in a producing
well, and the results were used to determine oil-and
gas-producing perforations. As a diagnostic tool,
DHV logging is a viable alternative to conventional
productionlogging for evaluatingpxforated intervals
in high watercut wells. It is a credible tool for
corrosion determination and for wireline fishing-
operation determination.
!lle pressure cantrol now possible with the small
electro-fiber-optic cable provides significant
operational flexibility while logging. Capability to
log with high surface pressures or while pumpingat
high injectionrates now makesDHV loggingfeasible
for determinationof a variety of prtiuction problems.
The lens surfactant also makes DHV feasible for
productionlogging.
~!
Future developmentsin loggingwith theDHVcamera
155
“,
.
8 Diagnosing Production Probiems With Downhoie Video Logging at Prudhoe Bay SPE 26043
include
q
q
q
Improvement in the lighthead configuration to
allow a clearer view downhole.
Increased operating temperature range.
Combined operation of the DHV camera with
other production logging tools to provide
quantitativedata with the DHV.
ACKNOWLEDGMF~
The authors of this paper wish to thank the Otis and
Westech field persomcl for their contributionsto the
success of the DHV logging of the case studies
presented in the paper. The authors also thank Otis
Engineering Corporation, Westech Geophysical,
ARCOAlaskainc., and the PrudhoeBayUnit owners
for their encouragement and permission to publish
this paper. The opinions and results within this
dcxmmentdo not necessarily represent the views of
the other Prudhoe Bay Unit operating companies.
FERENCE~
1.
2,
Cobb, C. C. and Schultz, P. K.; “ReTime
Electro-Fiber-Optic Downhole Video System,”
OTC paper 7046 presented at the 24th Annual
Offshore Technology Conference, Houston,
Texas, May 4-7, 1992,
Rademaker, R. A., Ohwewski,W, K., Goiffon,
J. J., and Maddox, S. D.; ‘coiled Tubing
Deployed Downhole Video System,” SPE paper
24794 presented at the 1992 Annual SPE
Technical Conference, Washington, D. C.,
October 4-7, 1992.
156
8“*
iSFE26043
F
FIBER OPTIC CABLE
FISHING NECK
CASLE HEAD
—
WEIGHT BAR
BOW SPRING
TRANSMITTER ANO
ELECTRONICS SECTION
BOW SPRINGS
CAMERA SARREL ASSEMBLY
LIC?HTHEAO SUPPORT ROOS CAMERA LENS
QUAR?Z LAMPS
LIGHT OOME PRESSURE HOUSING
o’-’- BULL NOSE PLUG
Figure 1
Downhole Video Camera
OH CiR PERFS FO SPINNER TEMP
11,300
ZONE 4
11,400
11,500
11,000
ZONE 2B
11,700
ZONE 1
11,s00
o aR lW 20 ; W4btl h!AiOR i MliOR M.
185F TEMPERATURE 195CF
VIOEO ANALYSIS REPERFS
m - -
- -
..—--- .- --
n -
-
-
-
-
-
- -- . .- ---
m Ill
Figure 2
Past-Video P;oductlon Profile
and Video Analysia
157
sPti26043
GAS QUIDE TUBES -
LOCATl!iL? SLOT -
GLV POCKET -
POGLM BARREL –
‘,
‘. .
,.
,’
,
,’
,’
,’
,
,’
Expended Wew of Fish
d
Figure 3
Rlagnoslng Annular Communication
from Eroded POGLMS
_ ERODED TOP POGLM
@ 4,075’ MD
— FISH@’6,S40’ MD
— SLIDING SLEEVE
— PACKER
_ :A3~l#TERMElllATE
OPEN PERFORATIONS
S40E POCKET MANORELS
95m” Production CASING
6 1/2” PRODUCTION TUBING
TUBJN#oL=~P
TUBING LEAKS
@ 9,112-9,118’ MO
PACKER
OTHER LEAKS
IN TUBING TAIL
CASINC4 LEAK@ %55T .9,588’ MD
CASING AND CEMENT GONE
CASINC4 LEAK@ S 6S5’ - 9,S18’ MO
SEVE/4E CORROSION *
J?*WI
TOP OF PERFORATIONS
@ S,62W ml)
FILL
3 ..
sr9001
Waa
9.100
9.200
9.300
9,400
I
4
I
I
[~
-- ----- -
I
I
--- ----
I
/
b
Figure 4
TublnQand Production Leaka
15s

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SPE26043 (Fluid Entry)

  • 1. societyof Petroleum En@reers SPE 26043 Diagnosing Production Problems With Dovvnhole Video Logging at Prudhoe Bay T.T. Allen and S.L, Ward, ARCO Alaska Inc.; R,D. Chavers and T.N. Robertson, Otis Engineering Corp.; and P.K, Schultz, Westech (%ophysical Inc. SPE Members Copy?lght 1993, Society of Petroleum Engineers, Inc. Tltls paper waa prepared for praserrlatlorr a! the Wesiern Regional Meeting held In Anchorage, Alaska, U.S.A., 2&28 May 1993. This permr waa ealected for presentation by an SPE Pregram Committee followlng ravlew of information containad In an abstract eubmrtted by tko aulhor(s). Contents of the Paper, ae preeerrted, have not been reviewed by the Soclaly of Petroleum Engineem and are eubJect to corretticrr by the au!hor(e). The material, as presented, does not necessarily reflect any ~sttion of the Sotiety of Petroleum Englnears, lte officere, or members. Papara presented at SpE meetlnss are eublacl to Publfcalion review by Efltorlal Commllfee$ of tho SOc~eW of Pelrc-fmrm Engineers. Permlaekm 10copy Is reelricfed to an abstract of not more than 3C0 words. IIlu$lralions may not be wpled. The abstract should contain conspicuous acknowledgment of where and by whom the paper Is preeerrted. Write Librarian, SPE, P,O. Sox S33836, Rlchardeon, TX 7E4M3-3WS, U.S.A. Telex, 163245 SPEUT. A8sT~K,I Thispaper describesareal time, fiber-opticdownhole video (DIN) system and its use as a diagnostic tool in solvingproductionproblemsin PrudhoeBaywells. Recent developments in lens preparation technology and advancementsin the applicationof electro-fiber- optic cable have proven the viability of DEN logging in oilfield applications. The case histories of three field applications in which oownhole visual inspections of tubulars and casing were used successfully are presented. These opxations determined fluid entry under flowing conditions, verified tubing and casing integrity, and facilitated wireline fishing operations. UCTKM( Until recently, real-time downhole video systems relied on specialized large-diameter 9/16-inch [14.3 mm] coaxial cable to transmit the high data rates required for real-time video to surface when loggingin wells of significantdepth.”2 These coaxial systemshave been primarily used in wells with little or no surface pressure because of the operational Itsferencea snd illuctrstions st end of psper. difficulty in maintaining pressure control with the large-diameter cables. Using an electro-fiber-optic cable instead of the coaxial cable improved the picture, and more importantly, reduced the cable diameter required for data transmission. The 7/32- inch [5.6 mm]diameter electro-fiber-opticcable now makes dealing with high surface pressure a routine procedure. A unique, highly-specializedsurfactantthat repels oil and inhibits condensationwhen properly applied has recently been developed. The surfactant has been field testedand is now being used on the camera lens and light domes to make viewing of wells while on production possible. Before the developmentof the new surfactant, many other products including detergents, phosphates, petroleum-based coatings, acid&d ethanol/isopropanolpolish, and a myriad of other wetting agents had ken tried; however, these products proved to be only marginally successful. The new surfactant, which is polished into the glass surface to prohibit oil adherence to the camem lens, has permitted viewing for more than eight hours in wells with high oil concentration without the oil adhering to the camera lens and obstructingthe video picture. Even after tmversing thousands of feet through a column of oil, visual clarity returned when 149
  • 2. 2 Diagnosing Production Problems With Downhole Video Logging at Prudhoe Bay SPE 26043 a clear mediumwas encountered. Recmt advancesin lens preparationand electro-fiber- optic technology have eliminated the two most persistent operational problems associated with obtaining quality DHV logs: 1) controlling high surface pressures and 2) logging through opaque fluids. The capability to log or pump into a well underhigh pressure provides operationalflexibilityin attemptingto achievea clear mediumfor viewing. It is no longer necessary to bad or kill a well before running a DHV log. Wells with high shut-in surfaoe pressures can often be logged in gaseous environments. New surfiwtantsfor the DHV camera lens have eliminated the need (and associated expense) to completely sweep the wellbore of oil. Wells can be logged while on production without fouling the camera lens and obstructing the DHV picture. DHV technologyhas progressed to the point that DHV logging is now viable for a variety of downholeapplications. POWN~OLK!QQL CONFl~URATl~M A schematicof the DHV cameras wed in the logging is shownin Figure 1. The 1-1l/16-inch- [42.9 mm] diameter cameras are Comprised of four subassemblies; the cablehead, electronic chassis, housing or pressure barrel, and the lighthead. The l-3/8-inch [34.9 mm] cableheadincludes an external fishing neck on top of a cable packoff and ekdrical and fiber-optic connectors. The electronic chassis includes an electronics package and a fiber-optic transmitter. The housinghas internal supportsfor the electronic chassis. The lighthead attaches to the lower end of the housing and typically consists of a set of three rods that supports two opposing lamps, which are psitioned in front of the lens. The lights are powered by direct current (DC) through the conductors in the cable, and their intensity is adjusted from the surfkceby varying the voltage. For optimal viewing, the distancesbetween the camera lens and the light sourcxware adjusted prior to thejob for the dueter of the tubulars. It is often desirable to view smalldiarneter production tubingwith the upper lamp and large-diametercasing with the lower lamp in the same logging run. Switchingbetween the upper and lower lamp during logging is performed by varying the voltage at the surface. ~~SIDE~ATIO~S The DHV system still presents several operational challenges that must be considered in job design to obtain a successful DHV log. These challenges includ% 1. 2. C@en@ngternpmaturesfor the DHV cameras - Current DHV cameras are rated to a maximum working temperature of 175‘F [79°CJ, although a few have been able to operate up to 195*F [91°CJ, As the temperature increases above 175*F[79”C], the picture will gradually degrade and fimlly disappear completely. However, the picturewill return once the temperatureis reduced to within the camera’s operating range. With bottomholetemperaturesranging from 180-235°F [82”-113”C.]at Prudhoe Bay, cold fiuids often have to be pumpeddownholeprior to loggingthe wells. High-temperature DHV cameras are currently under development. ~fectiw Ulumindbn area of the Eghthewis- Current lightheads typically used for DHV logging illuminate only a relatively small section of the pipe wall. For a standard two-lamp lighthead, approximately 4 inches [102 mm] of the pipe wall can be seenwith the upper lampand 10-16 inches [254 -406 mm] of the pipe wall with the lower lamp, depending on the tubing or casing size. While this allows close inspectionof the casing and tubulars, the close perspective makesit difficult to discern subtle changes in the internal diameters of the tubulars. Uniform wall loss from corrosion or scale buildup is often diflicult to differentiateon pipe wails on DHVlog remds (i.e. video tape). 150
  • 3. q SPE 26043 Thomas T. Men, Ste@hrn L. Ward, Raymond D. Chavera, Thomas N. Robertson, Philip K. Schultz 3 3. New lighting systems are being devebped that will project the light further down the hole. The narrow field of view of the present system makes it difficult to log dynamic fluid changes. Meeting tubing kdrs while tubing and annulus fluids equab is typically a “hit or miss” proposition. Swapping of fluids will often obscure the DHV in the areas of mostinterest. In addition, the narrow viewing area also dictates slow traveling and logging speeds. Traveling SpeOdS of 10150 fthnin [0.51-0.76 III/S] and logging speeds of 10-30 ft/min [0.05-0.15 lrds] are typical fos a DHV log. The new lighting systems shouIdincrease viewingarea and cIarity, allow faster movement,and reduce actual logging time and expse. Mhxhuns won@ine tensiim of the elec$n7- jtboptic cdk - The electro-fibmoptic cable has a maximumworking strength of 1,200 lbs [544kg]. Pulling the line above this point begins to break the optic fibers inside the cable even thoughthe breaking strengthof the armor is 4,700 lbs ~,132 kg]. The potential for becoming caught on a fish downhole and not being able to pull free without damaging the line bemmes an operational concern when performing DHV logging for fishing operations. The limited surfhce pull also places an effective limit on the logging depth of the DHV camera system. With a line weight of 85 lbs/1000 ft [0.126 kg/m], a maximum logging depth of 14,000 ft [4,267 m] MD is possible, and North Slope wells have been SUCC4Wfid 10~ed to thiS depth. PHV C~~l=OR@ _ her inspectionand I%oductionFrof~e A DHV log was run in a high-rate waterflood producer to help determine the appropriate remedkai wellwork needed to improve oil production. Two alternatives under considenition were w 1) cement squeeze for water shut off or 2) sidetrack the well. The cement squeezewould be more economical, but there was concern about the integrity of the productioncasingand achievinga successfulsqueeze. If production tubing or casing integrity had been compromised, sidetracking the well would be more cost effwtive. The well unum considerationwas completed in 1978 with 9-5/8-inch [244 mm]production casing and a 7- inch [178 mm] by 5-1/2-inch [140 mm] tapered production tubing string with side-pocket gas-lift mandrels (GLMs). Directionallydrilled, the well had an average deviation of 50° across the !ladlerochit formation. TIMreservoir consists of five hydraulic- flow units in the area of the waterflood where the well was drilled. At the time of the DHV,logging, the well was producing from all five flow units at 2,000 BOI?D, [318 m3/d oil] 8’7% watercut, and 2,950 scf/STB [525 std m3/stock-tankm3]. Previous surveillance work on the well consisted primarily of two productionprot51es,which were run in 1988 and 1989. Neither profile was effective in interpretation of production splits and oil entry sources. Each profile was run immediately prior to adding additional perforation interwds. The mom recent profde indicatedsignificantliquid fallbackthat prevented determinationof representativeproduction rates from the lower perforation intervals. A proposal was made to investigate the feasibilityof visually logging the perforations to determine phase entry while the well was on production. lMs would be an alternative to a conventional productional profile, which typically consists of a combinationof flowmeter, fluid density, fluid capacitance, temperate, pressure, or gamma-ray logging tools, Basedon the results from the previous work, another production profile was not expected to provide conclusive information. The high watercut of the well wasexpectedto render inconclusivefluiddensity and capacitanceresponses. A production profile was also expectedto showconsiderablewater fallback. A flowingattemptwas to be made since a DHVlog was already planned to inspect the production tubing and casing for damage. 151
  • 4. 4 q Diagnosing Production Problems With Downhola Video Logging at Prudhoe Bay SPE 26043 1 TM well was shut in 12 hours prior to logging with the DHVcamera to allow wellborefluidsto segregate into their respective phases. A fluid hwel, determined with an echo meter, was found to be at 11,550 ft [3,520 m] MD with 2,700 psi [18.62 mPa] shut-in tubing pressure (!UTP). The tubing was logged in gas at 60-120 fthnin [0.30-0.61 rnh], and the casing was loggedin gas at 25 fthnin [0.127tis] from the tubingtail at 11,262ft [3,433 m] MD to the liquid Ievel. Filtered sea water was then pumped down the tubing at 1.5 bblhnin [0.238 m’hnin] to depress the liquid level. The casing was logged in gas to 11,802 ft [3,597 m] MD where fill that covered the bottom two sets of perforations was encountered. The staticDHV log results showedthe tubing was in relatively gocxl cundition with only minor pitting above and below the bottom GLM. The casing was also in relatively good condition with only moderate pitting observed near the tubing tail. Across the perforations, the DHV log showed seven isolated perforations ercxled to nearly l-inch [25.4 mm] diameters,doublethetypica10.4-O.5-inch[10-13mm] entrance hole diameter. The well was slowly brought on production and flowed to a test separator, once the static DHV logging passes of the tubing and casing were completed. Productionwas restricted to 6,600 BLPD [1.049 m3/d]and 8000 Msef/D [227 Mm’/d] at 1100 psi [7.58 mPa]FTP. The rate was restricted because of operationalconcerns about potentially flowing the DHV camera uphole and damagingthe electro-fiber- optic cable. As the well was brought on production, several flowing DHV camera passes were made across the entire perforated interval to investigate phase entry points. While the production rate was stabilizing, the downhole flow regime changed significantly. Production was observed from the upper perforations only on thf ffist pass and from progressively lower perforums on subsequent passes. An analysis of the flowing DHV log is shown in Figure 2 with results horn a conventionalproduction profile. The analysisis a quaMativeevaluationof the oil and gas entry observed horn the DHV log. A three-tier scale was used to quanti~ the magnitudeof the oil and gas entry obsemxi on the DHV log. The three levels of the scale represenfi 1) no fluid entry, 2) minor fluid entry, and 3) major fluid entry. Any perforations without oil or gas entry were either nonproductiveor producing only water. The DHV analysis showed oil and gas production from only about 10% of the open perforations. The oil and gas production was distributed across the length of the open perforations with only isolated perforations producing in each inteml. A major casing leak was found in a casing collsr at 11,458ft [3,492 m] MD. No analysis of the top two perforationintervalswas done becauseof an oil/water interface, logged at 11,400 ft [3,475 m] MD. The interfaceobscuredany video results above tlds depth. Had the oillwater interface occurred at a greater depth, the amount of DEW production information would have been significantlyreduced. Two weeks after the DHV log had been run, a productionprofde was run with conventionallogging tools for oornparativepurposes, The comparisonwas to determine if the DHV results would provide information that was not readily available from conventional logging tools. Since conventional production profiles am already available fo~most of the producers, the comparison would ako aid in evaluating future candidates for DHV production logging. Theconventionalprofile response, as shownin Figure 2, generally correlated with the DHV results. The flowmeter (or spinner) confirmed that approximately 8% of the prw!uction was coming from the casing leak at 11,458 ft [3,492 m] MD. The fluid density response indicated 100% water flow from 11,802- 11,400 ft [3,597-3,475 m] MD, an oil/water transition layer between 11,400-11,360 ft [3,475- 3,463 m] 11,300 ft ~, and a gas/oil layer from 11,360- [3,463-3,444 m] MD. The DHV log I 152
  • 5. . q SPE 26043 Thomas~. Mm, Stephrn L. Ward. Raymond D. Chav@rs.Thomas N. Roba@son, ~illP K- S*U~Z 5 results showed water as the primary phase between 11,802-11,400 ft [3,597-3,475 m] MD and oil as a continuous phase above the oil/water interface at 11,400 ft [3,475 m] MD. The gradient temperature response also correlated well with the DHV gas analysis. The temperatureresponse shows major gas entry at 11,400 ft [3,475 m], 11,458 ft [3,492 m], 11,572ft [3,527 m], 11,656ft [3,553 m], and 11,767 ft [3,587 m] MD that matched with the gas entry observed on the DHV log. The primary lfference between the conventional profile results and the DHV log results is the identificationof oil producingperforations below the oil/water interface. The fluid density indicates only water production fkomthe perforations below 11,400 ft [3,475 m] MD. Oil production shownon the DHV log from the lower perforation intervals was not detected by conventional logging tools. The fluid density results suggest only the top two intervals produce oil and gas. Based on the DHV results and other collaborating surveillance information, it was decided to squeeze the well and reperforate two of the lower perforation intervals. J?irst, zone 1 was to be perforated from 11,720-11,740ft [3,572-3,578 m] MD. After flow testing this zone, zone 3 was to be reperforated from 11,418-11,460ft [3,480-3,493 m] MD. Withoutthe data providedby the IX-IVlog, the lower oil-producingintervals mightnot have been identified and reperforated, which would have resulted in a reduction of oil production and less chance for ultimaterecovery. The productioncharacteristicsnecessaryto define the range of applicability for DHV logging require further investigation. Until W range is better defined,judicious selectionof candidatesand careful job design is recommended if DHV production logging is to be successful. Some of the primary factors contributing to the successfidlogging of this well were 1. High watercut. Provides a clear viewingmedium. 2. Deviatedwellbore. Allows oil and gas production to rise to the high side of the pipe. 3. Large productioncasing. The larger the diameter of the casing, the smaller the area of view obscuredby opaque fluids. C3MQ2 Annular Conununication Troubleshooting and Fishing Operations A gravity-drainage producer bordering the Flow Station 2 ()?S-2)waterflood area was diagnosed as having annular communication. The well was completed in 1978 with 9-5/8-inch [244 mm] production casing and 5-1/2-inch [140 mm] tubing without GLM’s. Later, as the watercut increased, ‘ two retrievablepackoff gas-lift mandrels (POGLM’S) were run for artificial lift. At the time of the DHV log, the well was producing at 1,850 BOPD [294 mVd oil], 85% watercut, and 2,950 scf/STB GOR [525 std m%tock-tiankm3] at 350 psi [2.41 MPa] flowing tubing pressure @TP). During a routine mechanical integrity test, communication was discovered’between the tubing and the casing. The well would flow to surfaceIkom the tubingby casing annulus at 950 BLPD [151 m3/d liquid]. It was suspected that one of the two gas lift valves ((3LVS)was leaking or was out of the pocket. To eliminatethis communication,wireline operations were undertakento change out the two GLVS. Subsequentwireline operations were unsuccessfulin locating or latching the top GLV. When additional attempts were made to replace the bottom GLV, a restriction was discovered just above the bottom POGLM. It was suspectedthe bottom POGLM had collapsed. It was decided that a DHV log to determine the status of the POGLM’Sand the cause of the tubing restriction was needed. To ~repare the well for DHV logging, the tubingwas displaced with 1-1/2 wellbore volumes (400 bbls 153
  • 6. . . 6 tliegnosingProductionProbiems With Downhoie VideoLog@ng at Prudhoe Bay WE 26043 [64m3])of fiitered (2 microns)seawater. Produced gas,usedforartificialiift, wastheninjecteddownthe tubing to depress the liquid level. ‘NMinjection continueduntii the surface pressure of the tubing had equaiizedwith the iift-gas injectionpressure of 2,000 psi [13.79 MPa]. The DHV camera was then run in the weii at 150 fthin [0.76 rids]. The top POGLM at 4,075 ft [1,242 m] MD was logged in gas. The DHV log showed that the bottom three f~t of the POGLMwere gone. As shownin the expandedview of Figure 3, the missing section consisted of a locating slot, 2 gas guide tubes, and GLV pocket. With the integrity of the POGLM compromised, the cause of the annuiar communication between the tubing and annulus had been determined. The DEIVcamera was lowered further to fmd the missing part of the POGLM. The iiquid level was foundjust below the top POGJ.M at 4,100 h [1,250 m] MD. Rather than risk running into the fish while DHV logging through oii, sea water was injected down the tubing at 3 bbihnin [0.48 m3/min] and 2,200 psi [15.17 MPa] to pump the column of wellboregas to bottom. The DHV camera was then lowered while stayingjust above ftig iiquid level. As shown in figure 3, the fish was found stiii intact just above the bottom POGLM at 6,940 ft [2,115 m] MD. The gas guide tubes of the fish were located fwst, foiiowed by the locating slot. The DHV log showed that the locating slot was cracked. This would later become a problem in retrieving the fish. Xnitiaiattempts to log past the locating slot at 20-80 Mnin [0.10-0.41 mls] were not successful.. Eventually, the DHV camera went through the locating siot at 200 ft/min [1.0 m/s] and stoppedtwo feet below on top of the GLV pocket. Efforts to run deeper were not succe.ssfid. However, the DHV log showedthe top of the pocket with the GLV and both gas guide tubes in piace. Also shownwas the top of the three-foot barrel missing from the top POGLM. Based on the DHV log, subsequent wireline operations puiied the top POGLM and retrieved the fish. However, additicmaiattempts to change out the bottom GLV were still unsuccessful. The bottom POGLMhad not cdiapsed, but instead, had fded in a manner similar to the top one. Again, the results from the DHV log . were instrumental in troubleshooting this problem and diagnosing the second fishing situation. The bottom POGLM was pulled, and the second fish was retrieved. One gas tube was left in the bottom of the weii. New POGLM’S were later run, alleviating the annular communication, and the weii was returned to production. - ‘Ihbing and Liner inspection This was anotherwaterfloodproducer withan annular communication problem. Previous conductor iine operations had found two tubing leaks; one was just above the bottom GLM and the other wasjust above the polishedbore receptacleof the productionpacker, as illustrated in Figure 4. Becauseof multipleleaks, it was suspectedthat the tubingwas severelyemmded and required replacement. A DHV log was run to help determine whether the leaks could be successfully patched and the weii returned to production. The alternative was to leave the wei.i shut-in untii a rig could replace the tubing. The well was a producer in the FS-2 waterfloodam. It was completed with 9-5/8-inch [244 mm] production casing and 5-1/2-inch [140 mm] production tubing with conventionalGLM’s. At the time of logging, the well was producing at 4850 BOPD, ~71 m3/d oil] 50% watercut, and 2,950 scf/STB [525 std m3/stocktank m3]GOR at 300 psi [2.1 MPa] FI’P. The well was prepared for DHSl logging by displacingthe casing by tubingannulus with 450 bbls [72 m3]of fiitered sea water and then the tubingwith 300 bbls [48 m3](1.2 wellbore volumes) of filtered sea water. The fluids were allowed to segregatefor six hours. Because of the annular communication between the tubing and casing, it was necmary to sweepthe annulus with char fluid before Ioadiig the tubing. Any produced fluids behind the tubing wiii equaiizewith tubingfluidsduring the logging. Often, 154
  • 7. v *’ SPE26043 Thomas T. Allen, Stephen L. Ward, E?aymondD. Chavera, Thomas N. Robertson, Philip K. Schultz 7 this fluid swappingwill obscure the DHV in the areas of mostinterest unless a good sweepwith clear fluids is obtainedprior to logging. With the well shut-in, the tubing was loggedin gas to the liquid level at 6,428 [1,959 m] ft MD. The camerawasloweredthrough the oil untilthe oil/water interfhcewas encountered at 9400 ft ~,865 m] MD. Unable to view the tubing or the leaks at 9,030-9,150 ft [2,752-2,789 m] MD through the oil, the DHV camera was pulled back up above the liquid level. Sea water was then iqjected down the tubing at 1.5 bblhin [0.24 m%nin] to pump the wellbore gas columnto the perforations. The DHV cameralogged the tubing in gas by folIowingthe fidlingliquid level downhole. Just above tie packer, at 9,155 ft [2,790 m] MD, the water injection caught up with the DHV camera. lMperience has shown that being hit by a “wall of water” is a good indication of annular communication. With no annularcommunication,the gas columnor bubble can generallybe pumpedto the— perforations without significant water bypass. While the initial DHV logging provided good visual coverageof the tubing areas around the leaks, further investigationwas prevented becauseof the turbulence .resmltingfrom the injected sea water mixing with the gas. Parking the DHV camera 200ft [61 m] below the tubing tail, the sea water injection rate was increasedto 8 bblhnin [1.3 m3/min]at 2500psi [43.1 MI%]. After pumping 325 bbls [52 m3]down the tubing, the picture was sufficientlyclear to continue DHV logging. While maintaininga pumpmte of 3 bblhnin [.48 m3hnin], several passes wwe made aoross the tubing leaks ftom 9000-9250ft [2,743- 2,819m]MD. As the tubing and annulusequalized, five separate tubing leaks were observed. The leaks were on the bottom side of the tubing and originated ffom a narrow groove (possiblya wireline cut) in the tubing. The DHV log showed that the rest of the tubing was not severely corroded and could be ~y patohed. The produedoncasing was aIsologgedwith the IXIV camera. The camera showed significantwall 10ssin the casing from the tubing td to the top of the perforations. More significantly,severalcasingleaks were observedat 9,557-9,568 ft [2,913-2,916m]MD and at 9,598-9,618 ft [2,925-2,932 m] MD. Both setsof leaks were above the top of the perforationsat 9,630 fi [2,935 m] MD. The DHV log showedan exposedvoid behind the casing at 9,557 h [2,913 m] MD extendingdownwardfor approximatelyten feet. The bottom leak had several jagged holes over it’s entire length, with the casing appearing to sag on the bottom side of the hole. Continued DHV logging revealed that the bottom two perforation intervals were covered with fill. The casing damage was extensiveenough to preclude any attempts to cement squeeze the well. From the DHV log, the tubing was patched with two soft-setpatches. This allowed the well to be returned to production while waiting for a rig workover. Rather than replacingthe tubingnow, the well willbe sidetrackedin ‘enear future. A DHV camera was sucawdidly run in a producing well, and the results were used to determine oil-and gas-producing perforations. As a diagnostic tool, DHV logging is a viable alternative to conventional productionlogging for evaluatingpxforated intervals in high watercut wells. It is a credible tool for corrosion determination and for wireline fishing- operation determination. !lle pressure cantrol now possible with the small electro-fiber-optic cable provides significant operational flexibility while logging. Capability to log with high surface pressures or while pumpingat high injectionrates now makesDHV loggingfeasible for determinationof a variety of prtiuction problems. The lens surfactant also makes DHV feasible for productionlogging. ~! Future developmentsin loggingwith theDHVcamera 155
  • 8. “, . 8 Diagnosing Production Probiems With Downhoie Video Logging at Prudhoe Bay SPE 26043 include q q q Improvement in the lighthead configuration to allow a clearer view downhole. Increased operating temperature range. Combined operation of the DHV camera with other production logging tools to provide quantitativedata with the DHV. ACKNOWLEDGMF~ The authors of this paper wish to thank the Otis and Westech field persomcl for their contributionsto the success of the DHV logging of the case studies presented in the paper. The authors also thank Otis Engineering Corporation, Westech Geophysical, ARCOAlaskainc., and the PrudhoeBayUnit owners for their encouragement and permission to publish this paper. The opinions and results within this dcxmmentdo not necessarily represent the views of the other Prudhoe Bay Unit operating companies. FERENCE~ 1. 2, Cobb, C. C. and Schultz, P. K.; “ReTime Electro-Fiber-Optic Downhole Video System,” OTC paper 7046 presented at the 24th Annual Offshore Technology Conference, Houston, Texas, May 4-7, 1992, Rademaker, R. A., Ohwewski,W, K., Goiffon, J. J., and Maddox, S. D.; ‘coiled Tubing Deployed Downhole Video System,” SPE paper 24794 presented at the 1992 Annual SPE Technical Conference, Washington, D. C., October 4-7, 1992. 156
  • 9. 8“* iSFE26043 F FIBER OPTIC CABLE FISHING NECK CASLE HEAD — WEIGHT BAR BOW SPRING TRANSMITTER ANO ELECTRONICS SECTION BOW SPRINGS CAMERA SARREL ASSEMBLY LIC?HTHEAO SUPPORT ROOS CAMERA LENS QUAR?Z LAMPS LIGHT OOME PRESSURE HOUSING o’-’- BULL NOSE PLUG Figure 1 Downhole Video Camera OH CiR PERFS FO SPINNER TEMP 11,300 ZONE 4 11,400 11,500 11,000 ZONE 2B 11,700 ZONE 1 11,s00 o aR lW 20 ; W4btl h!AiOR i MliOR M. 185F TEMPERATURE 195CF VIOEO ANALYSIS REPERFS m - - - - ..—--- .- -- n - - - - - - - -- . .- --- m Ill Figure 2 Past-Video P;oductlon Profile and Video Analysia 157
  • 10. sPti26043 GAS QUIDE TUBES - LOCATl!iL? SLOT - GLV POCKET - POGLM BARREL – ‘, ‘. . ,. ,’ , ,’ ,’ ,’ , ,’ Expended Wew of Fish d Figure 3 Rlagnoslng Annular Communication from Eroded POGLMS _ ERODED TOP POGLM @ 4,075’ MD — FISH@’6,S40’ MD — SLIDING SLEEVE — PACKER _ :A3~l#TERMElllATE OPEN PERFORATIONS S40E POCKET MANORELS 95m” Production CASING 6 1/2” PRODUCTION TUBING TUBJN#oL=~P TUBING LEAKS @ 9,112-9,118’ MO PACKER OTHER LEAKS IN TUBING TAIL CASINC4 LEAK@ %55T .9,588’ MD CASING AND CEMENT GONE CASINC4 LEAK@ S 6S5’ - 9,S18’ MO SEVE/4E CORROSION * J?*WI TOP OF PERFORATIONS @ S,62W ml) FILL 3 .. sr9001 Waa 9.100 9.200 9.300 9,400 I 4 I I [~ -- ----- - I I --- ---- I / b Figure 4 TublnQand Production Leaka 15s