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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
Rignol, Krepa, Hogan, den Besten 1 SPE / ICoTA Aberdeen, November 2003
Abstract
The cost of remedial work on marginal gas
wells suffering from water unloadingproblems can be prohibitive, especially in
an offshore environment. The expected
financial return often does not justify the
rig costs associated with pulling and
running a new completion, while the
formation damage caused by many well-
killing methods can reduce the production
potential of already marginal wells.
A Coiled Tubing velocity string can often
prove a quick and cost-effective method ofassisting in water unloading. The ability to
work in live well conditions avoids
damaging the formation, making it an ideal
solution in many cases. However, the
limited lifespan of carbon steel strings in
corrosive environments calls for a different
solution. The next option is often to run
and hang off a chrome tubing string with a
snubbing unit, which makes running
corrosion-resistant tubing in live well
conditions possible. However, the highercosts and increased time associated with
a snubbing unit reduce its attractiveness.
The unconventional operational procedure
of running corrosion-resistant jointed
tubing with Coiled Tubing equipment has
been used on few occasions to combine
the benefits of Coiled Tubing and snubbing
interventions. Although generally
restricted to relatively short tailpipes, this
method has on occasion been extended torunning full velocity strings. The limited
Using Coiled Tubing Equipment to run complex Jointed
Tubing velocity strings
Joel RIGNOL, Total E&P Nederland
Jean Marc KREPA, Total E&P Nederland
Edward HOGAN, SPE, Schlumberger Oilfield Services
Hendri DEN BESTEN, Weatherford
Presented at the SPE/ICoTA 9th European Coiled Tubing and Well Intervention Round
Table 19 & 20 November 2003 - Aberdeen, Scotland
tensile load capacity of the externally
flush threads has limited the length of the
string in some cases.
A solution to this problem where a
complex string is run in two independent
sections has been applied in the field to
increase the total velocity string length to
4115m.
The paper discusses the design and
execution of the operation where Coiled
Tubing and jointed tubing were used as a
complex velocity string in order to restore
production on a gas well, while retaining the full functionality of the downhole safety
valve. Particular attention will be paid to
the design of the string, which had to be
tailored to remain within the operating
envelope of the externally flush thread.
Introduction
The gas well K6-DN2 was originally
completed with a tapered (5” x 4-½” x3-½”) 13% chrome production string in
1992 (Figure 1). The well produces from a
133 m perforated interval and a 400 m
horizontal 4-½” slotted liner. In latter
years, the well has commenced water
slugging and continuous gas production
has not been possible.
Using nodal analysis software, it had been
determined that stable production could be
regained by replacing the currentcompletion with a 2-3/8” production string.
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
Because the K6-DN satellite platform is
incapable of handling any operations other
than slickline and wireline, due to crane
and deck space limitations, the workover
operation had to wait until a drilling-rig
(jack up) was mobilized for a conventionalslot recovery/side track operation on the
offset well K6-DN4.
Design Criteria
In preliminary discussions between Total
E&P Nederland and Coiled Tubing Service
provider, Schlumberger Oilfield Services,
the following design parameters were
decided upon:
• The 2-3/8” tubing string must be
composed from a corrosion resistant
alloy to withstand the corrosive
wellbore environment encountered in
the K6 field (4% CO2
in gas composition
and bi-carbonates & chlorides in fluid
composition).
• The bottom of the CRA velocity string
must be located at approximately 4215
m (within the perforated interval 4168
m to 4301 m) which is 326 m below the
bottom of the existing 3-½” tailpipe.
• The 2-3/8” tubing string must be
suspended below the two existing SV-
LNs in order to maintain full integrity of
both the WRSV & TRSV devices.
• A lower section of 2” tubing would be
required to pass the 2.31” landing
nipple at the bottom of the existing
tailpipe• The re-completion with 2.3/8” tubing
had to be executed as a live well
intervention, to avoid unnecessary
formation damage of the depleted gas-
bearing formation.
While both Operator and Contractor had
experience in running and hanging off
Coiled Tubing velocity strings below the
DHSV in live interventions, the requirementfor a corrosion resistant alloy (CRA)
necessitated a different approach. While
previously, Total E&P Nederland had
turned to a hydraulic workover solution to
run jointed pipe recompletions, the use of
the hybrid Coiled Tubing unit was
preferable in this case for the followingreasons:
• difficulty in erecting HWO unit on
small rig floor
• longer rig up/rig down time for
HWO unit
• CTU on site after stimulation work
on newly drilled sidetrack
• lower overall cost
Design Proposal
Although the authors of this article have
significant experience in similar live well
velocity string re-completion projects
using both Coiled Tubing and hydraulic
work-over systems, the velocity string
project for well K6-DN2 was a more
challenging task than initially expected.
When the project was initiated, it wasconsidered by all parties involved to be a
relatively straightforward operation. The
objective was to recomplete a 5” Cr tubing
completion with a 2-3/8” CRA tubing
velocity string, which had to be suspended
in the first joint of 5”-15#/ft tubing (ID =
4.283”) below the existing SV-LN profiles
(minimum ID = 3.813”) (Figure 1). A Vam
FJL connection would be used, as it was
the only connection available on short
notice. Such re-completions are relatively
commonplace and thus no major
difficulties were expected.
However, when the K6-DN2 velocity string
concept was subjected to a closer look
several critical design limitations became
apparent. The following paragraphs will
describe the engineering solutions, which
were offered to complete the K6-DN2
velocity string design.
Rignol, Krepa, Hogan, den Besten 2 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
Completion Design & Hardware
Conventional downhole suspension
systems were not available as ‘off-the-
shelf’ equipment for the particular case of
the K6-DN2 recompletion. Conventionalmechanical slip type packers (Figure 2) or
hydro-mechanical packers (Figure 3),
which are able to pass through a 3.813” ID
seal bore, are designed for compatibility
with a 4-½” tubing joint. If these packer
sizes are used to set inside a 5” tubing
joint they will not provide enough positive
grip to support the velocity string weight
and the slips may be damaged due to over-
expansion.
When this became apparent, the idea of
suspending the velocity string inside the 5”
tubing was temporarily abandoned and the
existing well completion was reviewed to
identify an alternative suitable suspension
point.
From the existing 5” completion schematic
it could be seen that several restrictions
are present below the SV-LN that could
act as an alternative suspension point.However to maximize the internal diameter
of the 2.3/8” FJT velocity string, either the
5” x 4.1/2” cross-over @ 3162 m or the
3.125” QN LN @ 3177 m were identified to
provide a suitable landing collar spot. After
closer consideration, the selection was
made to design the velocity string around a
suspension in the QN-LN using an RNG
lock mandrel (Figure 4). This would offer
both a no-go type landing collar feature in
combination with an annular pack off.
However, after reviewing the 2-3/8” Vam
FJL connection strengths, it became
apparent that the compressive forces
exerted by the free-standing upper section
of the string would exceed the
compressive load capabilities for the
connections positioned just above the RNG
lock, if the tubing extended above 2500 m.
It was now clear that our working windowwas much more restricted than initially
thought. In fact, if a suitable hang off
system could not be designed to pass the
3.813” SV-LN and set inside the 5” tubing
joint below it, most likely only a tailpipe
extension with a short section of free
standing 2-3/8” FJT mounted above theRNG lock could be installed.
Nodal analysis was performed again at
this stage to evaluate if a 2-3/8” FJT
tailpipe extension with a short section of 2-
3/8” FJT positioned on top of the RNG lock
mandrel would enhance well production to
ensure that the re-completion project
remained a valuable project. This analysis
confirmed that if the top of the 2-3/8” FJT
tailpipe extension could be positioned atapproximately 2500 m, the installation of
only the 2-3/8” FJT tailpipe would be
beneficial for the well production
performance.
At the same time a supplier of thru-tubing
packers was requested to review the
possibility to design a custom build
retrievable packer (Cr13) to pass the 3.813”
SV-LN and set inside the 5” – 15 #/ft tubing
with a tensile load (>45000 lbs) & pressurerating (>100 bar) to suit this application.
As a packer setting mechanism, which is
not influenced by the carried tail pipe load,
is required, the proven PB packer design
was considered to provide a suitable
solution. Based on the design of a 3.67” OD
PB Packer, a proto-type 3.78” OD PB
packer for 5” – 15 #/ft and the associated
EH hydraulic setting tool were designed,
built and tested at the beginning of 2003.
The main feature for the prototype 3.78”
OD PB Packer was to overcome the
required extended slip reach. This was
achieved by designing a special slip
carrier in combination with an extended
stroke hydraulic setting tool.
After the proto type 3.78” OD PB Packer
system was build, it was subjected to the
following test procedure prior to allowingfield release :
Rignol, Krepa, Hogan, den Besten 3 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
• Set 3.78” OD PB Packer inside a 5” –
15#/ft casing joint using the custom
build 3.78” EH Setting Tool (Extended
Hydraulic setting tool).
• Heated up the system to 55 degC tosimulate well bore environment at
setting depth in well K6-DN2
(approximately 120 m).
• Apply 45000 lbs of tensile force on
3.78” OD PB Packer to simulate
tailpipe load (upper part of velocity
string).
• Apply 170 bar in the bottom annulus
along with the tail pipe load of 45000
lbs applied.• Release the 3.78” OD PB Packer using
the Retrieving Tool with 10000 lbs
straight pull.
• Allowed element to relax for 30
minutes.
• Retrieve the 3.78” OD PB Packer
through a 3.813” ID restriction with
approximately 1500 lbs overpull
During the initial test a few minor problemswere encountered. However these issues
were resolved and did not re-occur when
the actual 3.87” OD PB Packer (Cr13) was
tested at the end of February 2003.
The PB packer could not be used to
suspend the entire string as the weight of
the string would exceed the to the tensile
load capacity of the 2-3/8” VAM FJL
connection. However, now suspension
systems for both the lower string (RNGlock mandrel) and the upper string (3.78”
OD PB Packer) were available, a solution
to run a full 2-3/8” FJT velocity string was
available (Figure 5).
A conventional seal stinger & polished
bore receptacle (PBR) were selected, to
tie back the upper velocity string with the
lower velocity string to create a
continuous flow conduit.
Base Pipe Material
All tubing used for the velocity string
should be made from a CRA type material
(i.e. Cr13) to maximize the lifetimeexpectancy of the velocity string in the
corrosive well environment.
However 2” OD CRA Coiled Tubing was not
commercially available at the time of the
operation and 1.9” OD FJT Cr13 could not
be handled with conventional CT surface
equipment.
Therefore, it had to be accepted that a
short section of conventional 2” OD CT
(HS80CM) was made up to the bottom of a2.3/8” – Cr13 FJT velocity string using a
common type external CT connector in
order to extend the velocity string till the
middle of the perforations @ 4215 m.
Well Control Barriers
To allow the proposed two-stage velocity
string design to be deployed into a live
well, dual barrier systems needed to beavailable to allow each velocity string
section to be deployed against a positive
wellhead pressure.
The lower tailpipe, which was deployed
against full wellbore pressure, was
equipped with a commonly used double
barrier pump out plug (Figure 6).
After the lower tailpipe had been landed in
the QN-LN, the pressure above the doublepump out plug would be bled off, which
would allow the top string to be run into a
zero-pressure well.
However, in case the RNG lock packing did
not seal completely in the QN-LN seal
bore, a dual barrier system for the top
string was also required for contingency
purposes. It was requested to offer a
“non-debris” system to reduce operational
costs and avoid any risk of plugging the
lower tailpipe with expelled debris. The
Rignol, Krepa, Hogan, den Besten 4 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
most simple and reliable solution that
could be found was a “glass disk” sub
(Figure 7).
CT Running & Deployment Equipment
In rigless operations, the use of a CTU
injector head to run jointed tubing often
employs a basket constructed above the
injector head for making up the threaded
connection. In this basket, operators make
up the connections with the pipe tongs and
operate a gin pole winch assembly to raise
the next pipe.
In the case of K6-DN2, it was decided touse the advantage of the presence of the
rig to allow safer and more efficient
operations. This was done by placing the
injector head and pressure control
equipment below the rig floor and using
the rig floor for conventional tubular
running (Figures 8-11).
The stackup design criteria were:
• Sufficient riser length to deploy all
subassemblies• Hydraulic jacking frame for safe
subassembly deployment
• Minimum change of pressure
control equipment during change
from 2” to 2-3/8”
• Double barrier philosophy at all
times
A support frame structure incorporating
hydraulic jacking frame, generally used for
safe deployment of long BHAs in CoiledTubing land operations, was adapted for
use on an offshore platform. The 9.5 m
structure was built up on the weather deck
of the platform extending up into the BOP
deck of the rig, where the injector head
was placed on top of it, approximately 5 m
directly below the slip bowl on the rig floor
(Figure 9). This stackup enabled sufficient
riser length between the stripper and the
BOPs, which were rigged up directly on
the wellhead on the wellhead deck.
All subassemblies would be deployed by
breaking the riser at the platform weather
deck level and lifting the injector head/
riser with the hydraulic jacks in the
support frame legs. The subassemblies
could then be easily pulled up from theplatform weather or wellhead deck into the
riser before reconnecting and running-in-
hole.
The six ram BOP stack allowed the double
pressure barrier philosophy be maintained
at all times during the operation, while
avoiding changing the stackup between
running the 2” CT tailpipe and running the
2-3/8” Vam FJL. The configuration was (top
to bottom):• 4-1/16” 10k gate valve
• 2-3/8” Blind / Shear
• 2” Shear
• 2-3/8” Pipe/Slip
• 2-3/8” Pipe
• 2” Pipe/Slip
• 2” Pipe
One stage of the velocity string installation
would involve running the lower section of
the velocity string into the well with CoiledTubing, to hang it off in the QN nipple. In
order to allow this be carried out with
minimum time lost in rigging up and down
the CT equipment, it was decided to work
out a solution to allow Coiled Tubing be run
from the cantilever deck, while leaving the
injector head in position below the rig floor
on the support frames.
A special frame was constructed to house
the Coiled Tubing pipe straightener, onwhich the Coiled Tubing gooseneck can be
mounted (Figure 10). This frame could be
positioned on top of the slip bowl in the rig
floor, which was directly above the
injector head. The Coiled Tubing string
could be run over the gooseneck and
through the injector head in this fashion,
without a long rig up / rig down time. This
would effectively be a standard Coiled
Tubing operation with a 5 m gap between
the gooseneck and injector head.
Rignol, Krepa, Hogan, den Besten 5 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
release. Drop ball back up release
feature failed as drop ball hung up in
surface equipment and thus false
pressure indications were observed.
Fortunately, the rotational back up
release functioned correctly and therunning tool was released from the
packer. A post job inspection of the
EH setting tool did confirm proper tool
function but that shear rating of
screws installed did exceed the
theoretical shear value. This was due
to a mistake being made in the
surface area value used in the
hydraulic calculations. This error has
been corrected so it should not re-
occur in future operations.• To shear out the glass disk and double
pump out plugs an additional run with
a sealing snap latch assembly was
used. By using this sealing snap latch
assembly the pressure was
maintained inside the PB packer body
which did significantly reduce the
compressive peak load on the anchor
slips and the packer elements.
Conclusion :
A rig (jack up) mobilization only to
recomplete well K6DN2 would not have
been economical, however by utilizing a
rig that was in place on the same platform,
the K6DN2 recompletion as executed
became justifiable.
Thorough pre-job engineering & planning
from all parties involved made thisrecompletion operation, using a 2-3/8” FJT
velocity string in combination with a
unique deployment method, become a
valuable alternative to a conventional
work-over rig or hydraulic work-over
operation.
By using this innovative live well
intervention technique, an existing gas
well was re-completed with a smaller size
production string without inducing any
formation damage to the depleted gas-
bearing reservoir during any stage the
work-over operation.
Length limitations on the smaller velocity
string, which can either be dictated by
connection strength or tubing body tensilestrength, become less restricted if a
modular velocity string design is used.
This type of operations can be executed
more economically by taking the potential
velocity string requirement into account at
the initial well completion design stage. If
dedicated down hole suspension subs are
build in the initial completion, significant
cost reductions can be achieved in the
future as i.e. only a no-go sub might berequired instead of a packer.
Acknowledgements
The authors would like to sincerely thank
Total E&P Nederland B.V., The Hague,
Schlumberger Oilfield Services, and
Weatherford for permission to publish this
paper.
We would also like to thank all field
personnel involved in the planning and
execution of the K6-DN2 operation. Their
experience and professionalism was the
key to making this a safe and successful
operation.
Abbreviations used
“ = inch
Cr13 = Chrome 13CRA = corrosion resistant alloy
CO2
= carbon dioxide
FJT = Flush Jointed Tubing
HWO = Hydraulic work-over
m = meter
Nm3/day = normal cubic meter per day
PBR = Polished bore receptacle
SV-LN = safety valve landing nipple
WRSV = wireline retrievable safety valve
TRSV = tubing retrievable safety valve
Rignol, Krepa, Hogan, den Besten 7 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
Figure 1 – Existing Completion of K6-DN2
Rignol, Krepa, Hogan, den Besten 8 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
Figure 2 - Mechanical slip type packer
The Mechanical Packer is ideal for use on coiled tubing or conventional tubing in straight hole
or deviated well applications, where the tubing rotation required to actuate the packer is not
possible.
The Mechanical Packer is set and released by reciprocal motion of the tubing.
Features:
• Set and released by reciprocal motion of the tubing
• Drag spring design offers substantial increase in drag and strength
• Dual high performance packing elements
• Sealed J-Slot housing
• Increased tensile strength to accommodate heavier tailpipe loads
• Large bore mandrels
• Ideal for use on coiled tubing or conventional tubing
• Designed for setting below most common tubing size related LN restrictions. Figure 3 - Hydro-mechanical packer
Figure 4 – RNG Lock Mandrel
The Hydromechanical PB-Packer is the largest bore Retrievable Packer available.
The Packer is coiled tubing, slickline or E-line set and straight pull release.
Applications:
The PB Packer can be used in monobore wells for screen hang-offs, tailpipe extensions, or
multiple packers can be used to temporarily or permanently isolate a section of tubing or
casing.
Features:
• Large bore
• Coiled tubing, E-line, or slickline set
• Straight pull release
• 5,000 psi @275°F rated
• Short overall length
• Low force for shear release
• Designed for setting below most common tubing size related LN restrictions.
a). No-Go engages
b). Set dogs by slackingoff 5000 lb
Rignol, Krepa, Hogan, den Besten 9 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
Figure 5 – Two-stage velocity string solution for K6-DN2
680 m
650 m
385 m
125 mRKB
2525 mRKB
3202 mRKB
3855 mRKB
4240 mRKB
Retrievable Packer
2 3/8” VamFJL 13%Cr tubing
Glass disks (shear 3Kpsi)PBR stinger w/ OR w/o seals
2 3/8” VamFJL 13%Cr tubing
RNG lock weight set
2 3/8” VamFJL 13%Cr tubing
Connection CT toVamFJL joint
2” Coiled Tubing cs2 pump out subs
2400 m
1715 m
Rignol, Krepa, Hogan, den Besten 10 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
Figure 6 - Double Barrier Pump-Out Plug
Figure 7 - Glass disk sub
Rignol, Krepa, Hogan, den Besten 11 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
Figure 8 – Equipment Rig Up
Gooseneck and frameremoved for running
tubulars
Rignol, Krepa, Hogan, den Besten 12 SPE / ICoTA Aberdeen, November 2003
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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings
Figure 9 – Support Frame Structure Figure 10 - Gooseneck
mounted on frame
Figure 11 – Running
Jointed Pipe on Rig Floor
Rignol, Krepa, Hogan, den Besten 13 SPE / ICoTA Aberdeen, November 2003