Summary Evaluation methods have been developed to detect cases of tubing annulus communication. Temperature, spinner and noise logs, as well as fluid level detection equipment, are used under a variety of flow conditions. Stepwise procedures are provided. Introduction Production in the Prudhoe Bay Unit Western Operating Area (WOA) began in June 1977. Wells now flow naturally or with the aid ofgas lift. Rates vary from 100 to 10,000 BOPD or more and gas oil ratios (GOR) from 60010,000 scfSTB. Water cuts have in creased mainly in the waterflood areas and can approach 100%. The combination of water and 12 % carbon dioxide in the dissolved solu tion gas forms carbonic acid, corroding tubulars despite corrosion inhibition treatments. A typical completion is shown in Fig. 1. Tub ing sizes range from 312 to 7. In the early years offield life few workovers were required. Most of these were to replace defective packers and thermocase tubing. An increasing number of mechanical failures of tubular components as well as worsening corrosivity of produced fluids has significantly increased the occurrences of tubing annulus communication and corresponding workover requirements. In 19881989, 50 cases of tubing annulus communication were found in the WOA. Of these, 5 were permanently repaired with wireline techniques and 3 were temporarily repaired until a workover could be implemented. The remaining 42 wells were shut in and worked over without attempt ing remedial measures. This paper discusses methods used at Prudhoe Bay for identifying problem wells and determining the exact location of the leak in natu rally flowing, gas lifted, and injection wells.
Trang 1Methods of Detecting and Locating
Tubing and Packer Leaks in the Western Operating Area of the Prudhoe Bay Field
C.M Michel, SPE, BP Exploration
Summary
Evaluation methods have been developed to detect cases of tubing/
annulus communication Temperature, spinner and noise logs, as
well as fluid level detection equipment, are used under a variety of
flow conditions Step-wise procedures are provided
Introduction
Production in the Prudhoe Bay Unit Western Operating Area
(WOA) began in June 1977 Wells now flow naturally or with the
aid of gas lift Rates vary from 100 to 10,000 BOPD or more and gas/
oil ratios (GOR) from 600-10,000 scf/STB Water cuts have
in-creased mainly in the waterflood areas and can approach 100% The
combination of water and 12 % carbon dioxide in the dissolved
solu-tion gas forms carbonic acid, corroding tubulars despite corrosion
inhibition treatments A typical completion is shown in Fig 1
Tub-ing sizes range from 3-1/2" to 7"
In the early years offield life few workovers were required Most
of these were to replace defective packers and thermocase tubing
An increasing number of mechanical failures of tubular components
as well as worsening corrosivity of produced fluids has significantly
increased the occurrences of tubing - annulus communication and
corresponding workover requirements In 1988-1989, 50 cases of
tubing - annulus communication were found in the WOA Of these,
5 were permanently repaired with wireline techniques and 3 were
temporarily repaired until a workover could be implemented The
remaining 42 wells were shut in and worked over without
attempt-ing remedial measures
This paper discusses methods used at Prudhoe Bay for identifying
problem wells and determining the exact location of the leak in
natu-rally flowing, gas lifted, and injection wells
Traditional Methods for Leak Detection
Numerous articles are available related to temperature logging for
production logging purposes.l·2 Noise logging articles have
fo-cused on production logging or finding leaks behind casing.3 ,4 This
work is useful to the extent that the basic concepts of tool response
still apply in tubing-annulus communication troubleshooting
The technical literature on identifying tubing leaks consists
most-ly of mechanical devices run on wireline The devices form a seal
to the tubing wall and are pumped down to the leak Two such
exam-ples are provided in the references.5,6 It is unlikely these devices
would work in North Slope wells due to the restriction at the sub
sur-face safety valve
Leak Detection Methods at Prudhoe Bay
Leak determination techniques for Prudhoe Bay wells have been
de-veloped which primarily employ electric line logging The strategy
used depends on the condition of the well and whether the well is
naturally flowing, on gas lift, or is an injector Each case is discussed
individually The underlying strategy in almost all cases is to obtain
baseline results with the well in near static thermal equilibrium, then
alter conditions to induce temperature and time transients
Copyright 1995 Society of Petroleum Engineers
Original SPE manuscript received for review April7, 1991 Revised manuscript received Nov,
13 1992 Paper accepted for publication Dec 6, 1994 Paper (SPE 21727) first presented
at the 1991 SPE Production Operations Symposium held in Oklahoma City, April 7-9
Tool Selection The optimal tool string depends in part on the magnitude of the leak
At the lower range of leak rates (or leaks behind another string of pipe) the noise log is often the most sensitive and the best tool for pinpointing a leak The temperature log works over a broad range
of leak rates, butis usually not as sensitive as the noise log A spinner can be used for rates above the detection limit of the tool (usually about 6 feet/minute velocity) A philosophical approach to tool selection is provided in Fig 2
Naturally Flowing Well Leak Detection Annulus pressure readings are taken on a daily basis Any unex-plained increase in annulus pressure is cause for investigation An attempt is made to bleed off the pressure The initial and final pres-sures along with the amount and type of fluid bled is documented
If the pressure returns, then troubleshooting efforts begin Leak Detection Method An acoustic sounding of the liquid level
in the annulus is the first step in leak detection After non-gas lift wells are completed they are left with a full liquid column in the an-nulus Assuming no wireline work has been subsequently done to allow wellbore gas to enter the annulus since the completion, a liq-uid level significantly below the wellhead is further confirmation of
a leak Further, because the leak must be at or below the liquid level, the level may provide an indication of the location of the leak In one case the entire annular fluid volume to the packer was voided Determination of the Leak Rate by the Non-Ideal Gas Law The rate of increase in the annulus pressure alone is not sufficient in de-termining the severity of the leak as it is a function of the leak rate and the compressibilty of the annular fluids For example, even a very slow transfer of wellbore fluids into a liquid-packed annulus results in a dramatic increase in annulus pressure On the other hand, the pressure of an annulus having a deep liquid level responds de-ceptively slow to a significant influx of wellbore fluids,
With the well shut-in, the annulus pressure is bled after noting the initial fluid level For low GOR wells: the fluid entering the well is mostly liquid The rise in annulus fluid level with time can be con-verted to barrels per minute (BPM) For high GOR wells: mostly gas enters the annulus and the liquid level remains fairly constant The system can be modeled as a concentric cylinder of constant volume
V bounded by the wellhead at the top, the liquid level at the bottom, the tubing on the inner radius, and the casing on the outer radius The influx of gas into the inner annulus from initial to final condi-tions can be quantified by using the non-ideal gas law:
Q leak -_ 188 (460 (P/zr- P/zi)V + T) ~t
with P expressed in psi, V in barrels, ~t in minutes, T in OF, and Qleak
in standard cubic feet per minute (SCFM)
Annular flow leak determination method Gas flashing across the leak provides Joule-Thompson effect cooling easily detectable on the temperature log This process has the advantage of being consis-tent with the conditions under which the leak is known to occur: that
is, hydrocarbons flowing from the tubing to annulus side Based on experience to date, approximately 10 SCFM is considered the mini-mum rate detectable by electric line logging methods Leaks near surface where higher differential pressure can be established, are more pronounced
Trang 2INDICATED OTHERWISE
13-3/8", 72#/FT
2701
TOP OF 7"
LINER 10557
9-5/8" 4 7#/FT
10843
7", 26#/FT
11700
J-24
SUBSURFACE SAFETY VALVE
2087 FEET
MANDRELS 4-1/2" SLIDING SLEEVE
10420 FT PBR 9-5/8" PACKER 10516 4-1/2" "X" NIPPLE 4-1/2" "XN" NIPPLE
PERFORATIONS 11325-11355 (8890-8913 TVD)
Fig 1-Typical Prudhoe Bay WOA well completion
Prior to electric-line logging, tubing and annulus are both shut in
for at least eight hours This allows the wellbore to approach static
thermal equilibrium for baseline conditions Electric line is rigged
up and a continuous temperature log made from surface to a point
at least 200 feet below the tubing tail Baseline data may also be
ac-quired with the noise tool, which is included on the tool string if the
leakage rate is low and ambiguity anticipated with the temperature
logging alone.* The tool is then positioned at a point at least 200 feet
below the suspected leak while monitoring temperature
The annulus is bled off in 400 psi stages, interspersed with
tem-perature passes After the initial bleed off, one expects to see
in-creasing temperature at the stationary positioning point below the
leak This is due to warmer (deeper) wellbore liquids gradually
flowing upwards past the tool and toward the leak Thus, when the
"dynamic" (after bleed off) temperature passes are made they show
progressively warmer temperatures below the leak This is usually
on the order of a 0.25 - 2°F
The dynamic passes diverge from being warmer than the static
pass below the leak, to being colder near the leak where
Joule-Thompson and/or latent heat of vaporization effects are occurring
For deep leaks where low tubing - annulus ilp was induced, this
cooling effect may be only 0.5 to 3 oF For shallow leaks with greater
ilp the effect will be far greater
Above the leak, the dynamic temperature passes remain
progres-sively cooler than the static pass as the cooled liquids travel up the
annulus At some distance above the leak, typically 200-300 feet,
the dynamic passes usually approach the static pass temperatures as
thermal exchange with the surrounding formation dominates
The intermediate temperature passes while bleeding offthe
annu-lus in stages help pinpoint and confirm the leak
• A discussion of noise logging techniques as it relates to leak determination is given in the
appendix
SPE Production & Facilities, May 1995
II)
UJ
Z
UJ
>
i=
u
UJ
LL
J
a
Fig 2-Philosophical view of tool selection
An example of the temperature log while flowing the annulus is shown in Fig 3
Annular injection leak determination method For wells that leak
at high liquid rates (greater than 0.25 BPM), an alternative method
is to pump a liquid down the annulus and through the leak A plug
is set first in the tubing tail If pumping can be sustained down the annulus with barrel for barrel returns up the tubing, then the packer
is ruled out as the communication problem Compared to the base-line pass, the dynamic passes will exhibit the following behavior: 1) Identical temperature below the leak (static fluid)
2) A temperature spike at the leak due to friction heating (unless
no restriction exists)
3) Either cooler or warmer temperature above the leak, depend-ing on the amount of friction heatdepend-ing, the pump rate, and tempera-ture of fluid pumped (relative to original temperatempera-ture of fluids downhole)
A temperature log from troubleshooting a large leak by pumping down the annulus is shown in Fig 4_
For wells with packer failures, there will be no returns up the tub-ing Progressively cooler temperatures will be measured from sur-face to the plug depth
The troubleshooting can be done without initially setting a plug
in the tailpipe, but can be more difficult If sufficient annular injec-tion rate is obtained such that a high pressure drop is developed across the leak, then friction heating is detected Alternatively, if the leak rate is sufficient such that the velocity in the pipe exceeds approximately 6 feet/minute, a spinner tool can aid in detection The annular flow method is preferred to the annular injection method, since it duplicates conditions under which the well is known to leak No plug is necessary, and plugs are best avoided due
to evaluation complications if they leak and due to potential removal problems if they become stuck ARCO Alaska, Inc (the operator of the Eastern Operating Area at Prudhoe Bay), however, has reported successes using the annular injection method at rates down to 0.25 gallons per minute'?
Leak Detection in Gas Lifted Wells Gas lift wells are the easiest cases to troubleshoot The investigation
is normally completed with the well flowing at steady-state condi-tions on gas lift
As a tubing leak develops, lift gas will pass through the leak A decrease in casing pressure is usually experienced This is due to 1)
an increase in the total annulus-to-tubing flow area and 2) the shal-lower "lifting point" if the leak develops above the normal lifting point For the latter locations, a decrease in gross fluid production associated with inefficient gas lift operation is also common Table
1 provides an example
An acoustic fluid level measurement in the annulus with the well
on lift is an important first step in troubleshooting Various scenarios with the corresponding acoustic sounding results are as follows: 1) Large hole, shallow leak: The liquid level can be just below the leak, since little or no differential pressure can be developed across the leak to unload annular fluids (which can accumulate after a
shut-in period) The actual distance below the leak of the annulus fluid level will be equal to the pressure drop across the leak divided by the
Trang 39200 210 215 220 225
9300
9400
-,
9500 - , ,
,
IN Ff
9600
9700
-\
9800
-BASELINE PASS
LEAKIt\G GAS UFT MANDREL
DYNAMIC PASS
t
t
t
t
Fig 3-ldentification of tubing leak using the annular flow
meth-od
difference in the casing gas gradient and the flowing tubing gradient
below the leak
If the leak is higher than the shut-in tubing liquid level, then the
annulus may stay dry, even to the bottom operating gas lift valve
2) Small hole, shallow leak: The annular fluid level can still be at
the normal lifting point (There must be significant pressure drop
across the leak for this situation to occur)
3) Leak below the normal lifting point, small operating gas lift
valve port size: The annulus will have unloaded below the normal
lifting point all the way to the leak
4) Leak below the normal lifting point, large operating gas lift
valve port size: Because virtually no pressure drop is taken across
the gas lift valve, the fluid will not unload significantly below this
point Ifthis is suspected a smaller port size or dummy gas lift valve
should be installed
In most cases a suspected leak is easily verified by temperature
logging The tool string used consists of a temperature tool and
cas-ing collar log A lift gas rate of over 3 MMscflD, or enough to ensure
a significant pressure drop across the leak, is preferred
Leak determination method A log of the entire tubing string to a
point 200 feet below the tailpipe is made Where the leak is
encoun-tered, a general shift in the temperature gradient is noted The gas
entry results in a flowing tubing temperature decrease above the
leak anywhere from 0.25 to 6 degrees, depending on lift gas rate,
fluid rates and composition, and hole size Logging out through the
tailpipe is done to investigate any leaks at the packer, which then
show up as a cooling at the tubing tail However, logging much
be-low the annular liquid level is unnecessary since no lift gas could be
encountered Any suspicious anomalies are repeated The lift gas
can also be shut-in and a "baseline" pass made without gas lift if any
126
8300
8400
8500
8600
-DEJYfH
1:-': Ff
8700
8800
8900
-TEMPERATURF DEG F
140 145 150 15S
, , , GEOTHERMAL
GRADIENT
LEAKING GAS LIFT MA:-.JDREL
GEOTHERMAL GRADIENT
t
t
Fig 4-ldentification of tubing leak using the annular injection method
uncertainty remains Examples of tubing and packer leaks are shown as Figs 5 and 6, respectively
A screening procedure similar to the above has been adopted as part of production logging work The well bore temperature is con-tinually recorded while running in the hole This information is also useful for gas lift valve redesign and troubleshooting
Injection Well Leak Detection Injection well leaks usually present a particular challenge
Typical-ly, the leak rate is low Because of the higher bottomhole pressure (compared to producing wells) even a small leak can over time, cause an annulus pressure approaching the wellhead injection pres-sure The leaks can sometimes be temperature sensitive, leaking only while the well is on injection with warm fluids
TABLE 1-EFFECT ON CASING PRESSURE AND PRODUCTION RATE OF A HOLE DEVELOPING
IN A TUBING STRING
Test Gross Fluid Watercut Lift Gas Rate Pressure Date Rate (BLPD) (%) (MMscf/D) (psi)
Trang 410100-
10150-
10250-DEPTH
I~ IT
10350-
10400-TEMPFRATURE DEG F
t
(f)
0
Z
0
r
0
c;")
~
n
0
C (f)
R
r
~
GAS LIFT
0
MANDREL
r
m
<
m
r
tn
Fig 5-E-line and acoustic fluid level response for a gas lift well
with tubing leak
Injection wells at Prudhoe Bay are either water,
water-alternat-ing-miscible gas (WAG), or gas Many injection wells are converted
producers Wells experiencing little or no communication problems
on water injection can have a much greater communication problem
on gas injection Thus, troubleshooting of these wells is done while
on the gas injection cycle if possible
Monitoring, problem detection, and leak quantification processes
for injection wells is analogous to those described for naturally
flowing production wells
Gas Injection Well Leak Detection
For wells with significant leaks an identical strategy to that used for
naturally flowing producing wells is used: a baseline temperature
pass under near static conditions is made, followed by bleeding the
annulus in stages interspersed with dynamic temperature passes In
one (extreme) example, a well with a leak at 1,021 feet exhibited 56
degrees of cooling compared to the baseline pass Most other wells
have not been as easy to identify because the leaks were deeper and
slower For troubleshooting these wells a noise tool is usually
in-cluded in the tool string
If the above method is unsuccessful, a plug is set in the tubing tail
The annulus is allowed to reach an equilibrium pressure The tubing
is pressurized with gas, and the annulus pressure is bled off If the
annulus pressure returns to its original value and the tubing pressure
does not change, a packer leak is indicated If tubing pressure drops
as annulus pressure increases, then the leak is somewhere in the
tub-ing strtub-ing If the leak is in the tubtub-ing strtub-ing, then a slug of liquid is
pumped into the tubing and allowed to fall Once in place, its top can
be verified with an acoustic liquid level device The tubing is
pres-surized with gas and then shut in If technique is successful, the
liq-uid level will slowly move to the location of the leak and stop The
exact location of the liquid top can be verified by using a fluid
identi-fication device such as a density or capacitance type electric line
tool
Water Injection Well Leak Detection
A plug can be set in the tail pipe and pumping done down the tubing
or annulus, similar to the method described for naturally flowing
producing wells
In one 7" completion with no nipple profiles that leaked at a very
slow rate, a modified Baker-Lynes inflatable packer set with coiled
tubing was used to confirm a leak at the PBR (The poppet valve was
removed allowing multiple sets with the same packer.) During the
SPE Production & Facilities, May 1995
9850 _ 222 114 12<> 228
9900
9950
-
lOCOO-DFPTH
!NIT
10050-
10100-
10150-GAS LIFT MANDREL
SLIDING
SLEEVE
LEAKING PACKER
8
z
o
§
~
(")
o
c
~
R
r
~ o
r
m
<
m
r (f)
I
o
Fig 6-Temperature log and acoustic fluid level sounding on a gas lift well with a packer failure
multiple sets made while running the tool into the hole injectivity was zero and no annular returns were apparent After setting the tool below the PBR, slow but definitive leak injectivity was apparent Recommendations
I) Do not rely heavily on hydrostatic head calculations to deter-mine the leak location If anything, annulus pressure tends to be higher than what would be calculated for a given depth of tubing/an-nulus communication
2) Prior to investigating with electric-line logging, attempt to du-plicate the conditions under which the logging will be done For ex-ample, shut the well in first for 6-8 hours Then bleed off some annu-lus pressure and note the rate of annular pressure/liquid level build-up Some leaks are thermally related and cease after the well
is shut in (necessary for a baseline pass)
3) There are numerous individual ways to pinpoint the leak loca-tion, many of which involve combinations of the aforementioned techniques It is important to determine ahead of time what type of log response is anticipated This can impact the tools to be selected and the sequence of actions planned
4) In most cases it is best to use the reservoir as the pressure source (annular flow method) rather than pumping liquid down the annulus (annular injection method)
5) When possible, get baseline measurements prior to inducing tubing/annulus communication This will provide a greater degree
of confidence in the results
Nomenclature
Pi = initial annulus pressure, psi Pf= final annulus pressure, psi
Zi = Z factor, initial conditions Zf= Z factor, final conditions
T = annulus temperature, OF
V = volume of annulus from wellhead to liquid level, bbls L'l.t = elapsed time in minutes
Qleak = leak rate in standard cubic feet per minute (SCFM) Acknowledgments
The contribution of the members of the BP Exploration (Alaska) North Slope Production Engineering department are gratefully ac-knowledged Julie Heusser and David Smith of ARCO Alaska, Inc provided me with further insights and examples
Trang 5(WG S(JIJ.t:)
HICH 't~ NOISJ:: ~IUQUI::J"l:Y IY\"'DWIUlH ~ (SCHI.UMII~R(;t:I(1
Fig 7-Noise log for a well with a packer failure
The techniques and/or conclusions are those of the authoring
company and may not be shared by the other Prudhoe Bay Unit
Working Interest Owners
References
2 Curtis, M R and Witterholt, E J., "Useofthe Temperature Log for
Inter-pretation, and Operational Procedures," July 1976
4 McKinley, R M., Bower, FM, Rumble, R.C.: "The Structure and
Inter-pretation of Noise From Flow Behind Cemented Casing," 1 Pet Te ch P
329-338 March 1973
6 Hubbard Glen O Locating Holes in Tubing US Patent No 3,696,660
conversa-tion
Appendix-Noise Logging
Noise logging can provide additional information on the location of
the leak
128
R M McKinley (Exxon Production and Research Company) has published much of the research on noise logging, much of which has been oriented toward its uses as a production logging tool and
iden-tifying channels behind casing He reports that single phase fluids produce higher noise levels in the 1000-2000 Hz range (4) Gas ex-panding into a water-filled channel produces increased noise in the 200-600 Hz range
Typical noise logging equipment filters the signal into various frequency windows (Fig 7 from Schlumberger (8» Field results to
date have found increases in noise levels in all windows in the vicin-ity of the leak An example from a packer leak is provided (Fig 7) Noise logging is a slow process Discrete stops must be made, each requiring nearly one minute Noise attenuation in liquid is low,
so stops can be widely spaced (10 - 500 feet) Attenuation in gas filled tubing, however, is high and stops should be made only two feet apart
The noise tool is typically run on the same string as the tempera-ture tool When in the noise data acquisition mode, no temperature
or casing collar log data is available All possible extraneous surface noise should be eliminated when noise logging
51 Metric Conversion Factors
bbl x 1589 873 E-OI = m3
ft3 x 2.831 685 E -02= m3
C M Michel is a Senior Production Engineer for BP Exploration (Alaska) He is currently involved in hydraulic fracturing He re-ceived a BS degree in chemical engineering 1978 and MBA in
1982 both from Oregon State U., and worked as a process engi-neer in the pulp and paper industry between degrees He joined Sohio Petroleum (later BP Exploration) in 1982 and has as-sumed various production engineering assignments Michel is a registered petroleum engineer in Alaska