1. P I P E L I N E S & F L O W L I N E S
Coiled tubing offers pre-commissioning
tool for deepwater pipelines
System can be applied for contingency dewatering
A
s submarine gas pipelines are installed in ever-deeper waters,
the challenge of pre-commissioning becomes more complex.
For all deepwater pipelines, technology exists today to per-
form parts of the pre-commissioning entirely subsea using
autonomous or remotely operated vehicle (ROV) powered
equipment to flood, gauge, and test the pipeline.
However, there remain many situations where it is necessary to
connect from the surface to the deepwater pipeline, thus forming a
reliable conduit to the pipeline that facilitates the injection of water,
air, nitrogen, and mono-ethylene glycol (MEG); or even to be used
for subsea depressurization.
The goal here is to demonstrate what can be achieved on major
subsea pipeline pre-commissioning projects through the selection of
the best equipment and techniques.
Employing a “down-line”
A down-line is best described as a conduit between a marine ves-
sel at the surface and a subsea pipeline connection. For our pur-
poses here, we will consider only the use of down-lines for pipeline
pre-commissioning.
The pre-commissioning process flow chart illustrates the pre-
commissioning process as typically applied to oil pipelines. The
process for gas lines is similar, but involves additional steps prior to
handover such as removal of hydrotest water (dewatering), drying,
MEG swabbing, and nitrogen packing.
Where the pipeline has one or both terminations subsea, then a
down-line may be required to perform the pre-commissioning service.
The following key attributes are desired from a down-line system:
• Be able to convey the pre-commissioning fluids (water, air,
glycol, nitrogen) from the surface to the subsea injection point
at the highest possible rate to achieve the pigging parameters
agreed for the project
• Be space efficient both for transporting to/from the mobilization
point and for installation on the pre-commissioning support vessel
• Be cost effective
• Be robust and reliable
• Include contingency for critical items
• Be self-supporting during deployment and recovery
• Have fast deployment and recovery rates
• In many applications, be able to withstand the external hydro-
static pressure at the deepest point.
Deepwater deployment
Traditional oilfield coiled tubing units have been used to make a
connection between the surface spreads and subsea pipelines for
many years. Typically, such units used coiled tubing of 2-in. outer
diameter (OD) and below, with the oilfield design generally neces-
sitating deployment via a moonpool equipped marine vessel.
In 2012, Baker Hughes designed and built coiled tubing systems
specifically designed for deepwater down-line applications.
The design brief for the customized system was as follows:
• Capable of operating in water depths up to 3,000 m (9,842 ft)
• Designed for large diameter pipe of 27
⁄8 in. or 3½ in.
• DNV-certified to allow offshore lifting
• Road transportable in two loads
• Standard basic components giving easy access to spare parts
and trained mechanics/operators
• Flexible frame to allow use on a wide variety of vessels, either
through a moonpool or over the side.
Historically, the main use of the coiled tubing down-line has been
as a conduit for supplying air or nitrogen to dewater the subsea pipe-
lines. This also typically requires that MEG or another pipeline hy-
drate-inhibiting fluid be pumped as part of a conditioning pig train.
To date, coiled tubing has been used in water depths of around 2,200
m (7,217 ft), but with exploration already taking place in water depths
down to 3,000 m (9,842 ft), this was selected as the target water depth.
John Grover • Andy Barden
Baker Hughes
Pre-commissioning flow chart for typical oil pipelines.
(All images courtesy Baker Hughes.)

2. P I P E L I N E S F L O W L I N E S
Coiled tubing system design
Initial evaluation of a number of deepwater pipeline projects in-
dicated that compressed air injection rates in excess of 10,000 cf/
min (283 cm/day) would be required, injected on to a down-line up
to 3,000 m long.
Engineering for such scenarios showed that the 2-in. coiled tub-
ing used to date is not large enough for these flow rates, with the
high-pressure drop equating to surface pressures greater than
could be achieved. Thus engineering focused on the two largest pipe
sizes available:
• 27
⁄8-in. pipe is readily available and there is considerable experi-
ence with this pipe in downhole applications.
• 3½-in. pipe is not widely used in downhole applications, as high
flow rates are not typically required, but it is manufactured, and
readily available. These larger pipe sizes have much lower pres-
sure drop, and are better suited for these applications.
In looking at reel dimensions, it was decided to opt for a reel that
would handle 3,000 m of 27
⁄8-in. and around 2,300 m (7,545 ft) of
3½-in. pipe. This gives reel dimensions of 96 in. (2.43 m) between
flanges, with a core diameter of 120 in. (3.05 m) and flange diameter
of 180 in. (4.57 m), and reel skid dimensions of 223 in. (5.66 m) long,
144 in. (3.65 m) wide and 182 in. (4.66 m) high. The weight of the
skid with pipe is 90,000 lb (41,000 kg).
The rest of the equipment was mounted on a single skid for ease
of transportation and lifting. This skid also provides the basis of the
overboard deployment system. A trolley system was used, which al-
lowed the pipe and ancillary equipment to be rigged up in-board of
the vessel and then jacked out over the side of the vessel.
The primary driver for this was an “over-the-side” deployment
scenario, but this would work just as well for a moonpool deploy-
ment. The skid accommodates the control cabin, the power pack,
the gooseneck and all ancillary equipment in its transport mode.
Prior to use, the control cabin was lifted off the skid and replaced
by the tubing reel, which partially balanced the weight of the tubing
when deployed over the side. The cabin can be located in a number
of places around the skid within a 30-ft (9-m) radius of the power
pack, giving flexibility depending on vessel layout. The main trans-
port skid was 40-ft (12.2-m) long by 12-ft (3.65-m) wide, weighing ap-
proximately 80,000 lb; so although it is a permit load, it can be trans-
ported by conventional truck. The use of a spreader beam gives a
single point DNV-certified lift for offshore lifting.
The power pack, injector, gooseneck, and control cabin were all
effectively standard components. The reel was also standard in the
way it functions, but the dimensions are unique to meet the criteria
outlined above.
Deployment challenges
The main issue associated with deploying the coiled
tubing as a down-line in deepwater environment is the
impact of current on the coiled tubing string and the
vessel movement. This impact results from wave ac-
tion, which can cause fatigue in the pipe string. In
downhole applications, high-cycle fatigue is not an is-
sue, since the tubing is constrained by the well, but in
open water this is not the case.
Historically, several projects have been carried out in
the relatively benign environment of the Gulf of Mex-
ico. The calm sea state and relatively weak currents
have not caused any major issues with the coiled tub-
ing, even in deployments lasting several weeks. Howev-
er, in more aggressive sea states, this has the potential
to impact the coiled tubing and limit its working life.
The first project in which these more extreme con-
ditions were encountered required the project team
to look at this in more detail. In order to assess this
potential impact, extensive modeling was carried out to determine
the effect of different conditions on the coiled tubing string and the
entire jumper system across to the pipeline end termination.
Modeling was undertaken using OrcaFlex to look at deployment
analysis, in-place analysis, and high-cycle fatigue. This software re-
quires the following inputs in order to model the behavior of the
coiled tubing:
• Detailed physical parameters of the coiled tubing and all the
equipment attached to the end of the string in the various de-
ployed conditions
• Metocean data
• Vessel data and details of the hang-off point for the coiled tubing
• Response amplitude operator data for the vessel.
Specific issues to be addressed as part of the analysis:
• Assess the allowable yield stress utilization in the coil tubing
across the range of conditions that could be encountered dur-
ing operations
• Assess the need for a bend stiffener for the coiled tubing based
on the above
• Examine vortex-induced vibration and whether lock-in would
occur
• Evaluate the movement of the hose bundle during the operation
and assess the need for buoyancy and a bend restrictor to pre-
vent the minimum bending radius from being exceeded
• Evaluate potential clashing of the coiled tubing and/or hose
bundle with the vessel’s hull during deployment
• Look at the likely tension and bending moments in the hose
bundle and the breakaway coupling during the operation.
The initial static analysis of the system revealed that a bend stiff-
ener was required. Without one, the current acting on the coiled
tubing would cause an overbend in the string at the vessel interface.
Various types of bend stiffeners were evaluated, and a steel tube
of reducing wall thickness was agreed upon, which would limit the
radius of curvature of the coil and allow progressively more bending
of the coil over its length. With this in place, the bend of the coiled
tubing is limited to a level below the allowable limits of stress utiliza-
tion based on curvature and tension.
In many instances with the vessel in a fixed position, it is possible
for the hose and bottom hole assembly (BHA) to be tensioned beyond
their design limit. In order to prevent this, it is necessary to move the
vessel such that the BHA remains within a given target area, so that
the hose and breakaway connector are not overly stressed. Buoyancy
and weights are attached to the hose bundle so that it remains in a
lazy S shape during the operation, without undue tension or bending
moments being applied to any of the components.
Schematic of dewatering
using coiled tubing system.

3. P I P E L I N E S F L O W L I N E S
Eprinted and posted with permission to Baker Hughes Inc. from Offshore
June © 2015 PennWell Corporation
Vortex-induced vibration was found to be present in the initial analy-
sis without the bend stiffener, but the use of the bend stiffener reduced
this to the point where it was no longer an issue. Contact between the
tubing and the side of the vessel is possible in high current scenarios;
therefore, the vessel may have to be oriented accordingly to avoid this.
With the bend stiffener designed as described, the coil was ana-
lyzed for fatigue. As indicated earlier, high-cycle fatigue is a major con-
cern in this application, given the constant movement of the vessel.
In this particular instance, the coil was anticipated to be deployed for
about 32 days continuously. For a single deployment, fatigue was not
determined to be an issue in this case. However, it should be noted
that in the case of multiple deployments, the coil is also subjected to
low cycle fatigue each time it goes over the gooseneck. The combi-
nation of these two fatigue regimes requires further investigation to
determine a probable ultimate fatigue life of the coil.
Wet buckle contingency
Many subsea pipelines employ some type of wet buckle contin-
gency (WBC) dewatering system, however for large-bore, deep-
water pipelines, the compressed air spread required to dewater
the line is huge and the dewatering time very slow. For example,
a major Black Sea pipeline project would have required a standby
dewatering spread to be located in the vicinity of the subsea initia-
tion head. To mitigate this contingency requirement, Baker Hughes
developed a solution to partially dewater, isolate, and depressurize a
short deepwater section using a large-bore coiled tubing down-line.
This technique is summarized as follows:
1. An unplanned flooding event occurs. WBC flooding spread is
commissioned.
2. A wet buckle contingency flooding pig receiver/catching head
is installed. The head is fitted with a large bore discharge port
for air/water outlet during the WBC flooding operation.
3. The line is then flooded with filtered, treated seawater from the
WBC flooding spread and the free-flood, untreated seawater is
displaced with treated seawater within 20 days. Water treated
for a pre-agreed wet park period.
4. The WBC flooding pig receiver is then recovered to the sur-
face and a pipeline recovery tool is installed with a pre-loaded
smart plug
5. Concurrently, a coiled tubing (CT) dewatering system is in-
stalled on a dynamically positioned vessel
6. Once function tested, the CT dewatering system is deployed to
the recovery head
7. The smart plug is propelled about 3 km to 5 km (1.86 mi to 3.10
mi) into the line and treated water is discharged at the WBC
pumping location. This can be conducted at a lower velocity
than conventional dewatering.
8. The smart plug is set and the air pressure is bled down at the
surface.
9. Lay barge recovers line to surface and pipelay can recommence.
10. The smart plug is left in place until dewatering operations
commence after completion of pipelay.
With this technique, a project crew can then use the dewatering
air pressure to equalize across the smart plug and then push it to the
receiver as part of the dewatering train.
Conclusions
With this article, the authors have endeavored to demonstrate the
following:
1. Down-lines play an important role in the pre-commissioning of
deepwater pipelines
2. Coiled tubing should be considered as the preferred down-line
system except where very large bore down-lines are required.
Even then, multiple coiled tubing down-lines can be considered
as an alternative.
3. Custom marine coiled tubing systems provide the flexibility
for moonpool or over-the-side deployment and are largely self-
supporting once installed.
4. Engineering and modeling is required prior to deploying coiled
tubing in a blue-water environment.
5. A partial dewatering system offers a faster, lower cost alternative
to a full wet buckle contingency dewatering system, especially
for pipelines not intended for hydrostatic pressure testing. •
Acknowledgment
Based on a paper presented at the OPT conference in Amsterdam, The Netherlands,
Feb. 25-26, 2015.
Left:Two-inch coiled tubing being deployed via moonpool. Right: Coiled tubing unit in transit mode, showing main deployment skid and reel.
Complete spread in deployed configuration.