Paper 43 - Deep Water Pipeline CT 9_2_15

OPT 2015 09 February 2015John Grover Page 1

Deepwater Pipelines – the latest developments using coiled

tubing down-lines for pre-commissioning and contingency

dewatering

ABSTRACT AND INTRODUCTION1

As submarine gas pipelines get deeper, the challenge of pre-commissioning becomes

greater. For all deep water pipelines technology exists today to perform parts of the pre-

commissioning entirely subsea utilizing autonomous or ROV power equipment to flood,

gauge and test the pipeline entirely subsea. However there remain many situations

where it is necessary to connect from the surface to the deep water pipeline thus forming

a reliable conduit to the pipeline that facilitates the injection of water, air, nitrogen, MEG

etc., or even to be used for subsea depressurization.

Part 1 of this paper will discuss the recent advances made in the use of large bore coiled

tubing as a “down-line”, focusing on:

A comparison between coiled tubing and other down-line options

An overview of the latest custom coiled tubing equipment being deployed today

on deep water pipeline projects

A discussion on the challenges around the use of coiled tubing in a blue-water

marine environment

Part 2 of this paper will then explore how such a coiled tubing system can be used to

provide an innovative contingency-dewatering solution for any deep water pipeline, even

those where a hydrostatic test waiver is in place. This will focus on:

A brief introduction to “wet buckle” contingency techniques

A detailed introduction on how a coiled-tubing based system can be deployed to

partially dewater and depressurize a deep water pipeline, minimizing cost and

schedule impact should a wet buckle occur

Our aim with the above is to demonstrate to future major subsea pipeline projects what

can be achieved through the selection of the best equipment and techniques.


PART 1 – RECENT ADVANCES USING LARGE-BORE COILED TUBING AS A2“DOWN LINE”

2.1 INTRODUCTION

A down-line is best described as a conduit between a marine vessel at surface and a

subsea pipeline connection. For the purpose of this paper we will consider only the use

of down-lines for pipeline pre-commissioning.

The following flow chart illustrates the pre-commissioning process as typically applied to

oil pipelines. The process for gas lines is similar but involved additional steps prior to

handover such as removal of hydrotest water (dewatering), drying, MEG swabbing and

nitrogen packing.

Cleaning & gauging ofPipeline Section

Flooding & testing ofPipeline Section

Depressurise line andhandover to client filled

with treated water

Displace Hydrotestwater with oil

Dewater usingcompressed air

BHI ActivityClient Activity

Commission thePipeline

Perform Caliper Survey,possibly c/w dewatering

Nitrogen purge andpack the line

Treat the line with batchof corrosion inhibitor

Optional Services / Gas

Figure 2-1 Pre-Commissioning Flow Chart for Typical Oil Pipelines


Where the pipeline has one or both terminations subsea then a down-line may be

required to perform the pre-commissioning service.

Figure 2-2 Schematic of Dewatering using Coiled Tubing System

The following key attributes are desired from a down-line system:

1. 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

2. Be space efficient both for transporting to / from the mobilization point and for

installation on the pre-commissioning support vessel

3. Be cost effective

4. Be robust and reliable

5. Include contingency for critical items

6. Be self-supporting during deployment and recovery

7. Fast deployment and recovery rates

8. In many applications, be able to withstand the external hydrostatic pressure at the

deepest point.


2.2 A COMPARISON BETWEEN COILED TUBING AND OTHER DOWN-LINEOPTIONS

The two down-line techniques commonly used for subsea pipeline pre-commissioning

are:

Flexible down lines

Coiled tubing down lines

Flexible Down Lines:2.2.1

Figure 2-3 Transport of 4” ID Flexible Downline Figure 2-4 3” ID. CT Downline on Vessel

Flexible down-lines can be as simple as a short length of lay-flat or hydraulic hose. For

the purposes of this paper we shall consider only large bore (2” plus i.d.), deep water

(500m WD or deeper) and self-supporting (not deployed with an attached wire) flexible

down-lines. Today there are a number of manufacturers of composite and flexible risers

that can also be used as down-lines. They can be either of a steel reinforced design or a

layered composite design. For pre-commissioning applications to date the layered

composite bonded and un-bonded design has proved to be more popular.

Some attributes of large-bore, self-supporting flexible down-lines include:

High cost when compared to coiled tubing. This generally precludes the provision

of a contingency down-line

Weight and size preclude movement by road and conventional freight

Long fabrication time – 12 months plus is typical

Large deck space required for flexible down-line and reel, tensioner, winch &

chute

Restrictions in operating temperatures – a limit of 60°C presents a challenge

when injection high-pressure compressed air.

High investment for tensioner and chute

High top tensions expected at the launching system


Coil Tubing Down-Lines:2.2.2

Figure 2-5 – Coil Tubing Deployed through Moonpool

Coiled Tubing has been used in down-hole applications for over 50 years. The

technology has continuously developed with pipe size increasing from 1” in 1970’s up to

3 ½” today. It is believed there are over 1,000 coiled tubing units in use globally today.

At the heart of the unit is the pipe, or coiled tubing itself. For the purpose of this paper

the limiting factors for the size and depth of coiled tubing are:

1. The maximum length of large bore coiled tubing that can be installed on the reel

2. Using an industry standard design, the largest pipe handling capacity available.

Currently Baker Hughes has deployed 2,300m of 3 ½” OD coiled tubing for marine

operations. Some attributes of coiled tubing down-lines include:

Entire unit can be moved by road and using conventional freight. This means

mobilization costs can be far lower than for a comparative flexible down-line

High-strength means far thinner wall thicknesses than for flexible down-lines. This

equates to a far smaller deck space requirement.

No potential collapse issues due to external hydrostatic pressures

Tolerant of high temperatures generated by high pressure air compressors

The coiled tubing pipe itself costs less than 20% of the equivalent flexible down-

line. Thus it is common to mobilise a spare reel of pipe either to the work vessel or

marine base, providing 100% contingency for this critical item.

Coiled tubing pipe is often available ex-stock or on delivery times less than 3

months.


Comparison Table2.2.3

The merits of coiled tubing vs. a composite down line are set out in the table below:

Attribute Coiled Tubing Composite Down Line

Delivery Time Better – 8 to 9 months Worse – 12 to 18 months

Cost Better Worse – approx.. 2 x CT price

Deck Space Much Better Much Worse

Mobilisation Better – can move by roadMuch Worse – at 150 tonnes

for reel alone only by sea

Reliability

Better – over 100 subsea

deployments and millions of

well deployments

Worse – some history of

composite down lines failing

during test and deployment

Contingency

Much Better – a spare coiled

tubing string and reel can be

supplied quickly and at low cost

Much Worse – cost of spare

line and reel approx.. 20 x that

of CT with 12 month + delivery

Vessel InstallationBetter – heaviest lift approx.

41,000 KG

Worse – heaviest lift approx..

150 tonnes

Vessel PlacementBetter – can be deployed over

back, side or via moon pool

Worse – needs to be deployed

over the back or the side of the

vessel

Maximum Internal

Temperature

Better – can withstand 90°C

typical of air booster discharge

Worse – limited to 60°C hence

additional air cooling required

Size AvailabilityWorse – current design limited

to 3 ½” OD CT pipe

Better – we believe up to 6” ID

availableTable 2-1 Coiled Tubing and Composite Comparison


2.3 AN OVERVIEW OF THE LATEST CUSTOM COILED TUBING EQUIPMENTBEING DEPLOYED TODAY ON DEEP WATER PIPELINE PROJECTS

Introduction2.3.1

Traditional oilfield coiled tubing units have been used to connect between surface

spreads and subsea pipelines for many years. Typically such units used coiled tubing of

2” NPS and below with the oilfield design generally necessitating deployment via a

moon-pool equipped marine vessel.

Figure 2-6 – 2” Coil Tubing Deployed Via Moon pool

In 2012 Baker Hughes designed and built coiled tubing systems specifically designed for

deep water down-line applications.

The design brief for the customized system was as follows:

Capable of operating in water depths up to 3000m

Designed for large diameter pipe of 2 7/8” or 3 ½”

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 moon

pool 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 pipelines. This also typically requires that

MEG or another pipeline hydrate inhibiting fluid be pumped as part of a conditioning pig

train. To date coiled tubing has been used in water depths of around 2200m, but with

exploration already taking place in water depths up to 3000m, this was selected as the

target water depth.


What Governs Required Flows and Pressures?2.3.2

The flow-rate of the water, air, nitrogen or MEG within the coiled tubing is dictated by the

desired pig speed in the pipeline. As an example we take the following pipeline as an

example and consider water as the pumping medium:

Line NPS 16”

Wall Thickness 12.5mm

Line Length 8KM

Water Depth at launcher 1000m

Water Depth at receiver 1000m

Water Temp at surface 28°C

Water Temp at Seabed 4°C

Average Flooding pig velocity required 0.5 m/sec

Flooding Rate Required 3,420 lpmTable 2-2 Typical Pipeline Parameters

The important data from the above is that we need to inject 3,420 lpm of water into a

pipeline at a water depth of 1000m. Of course this operation could be performed using a

subsea flooding unit, however for the purpose of this paper we assume a down-line must

be used.

The vessel based spread must be designed to deliver 3,420 lpm in to the pipeline –

hence the first consideration is the size of the down-line required. Having looked at the

various pressure drops across the down-line, we then need to evaluate the pump power

(HHP / BHP) required to overcome the system pressure losses and deliver the flow to

the system.

Down-line

Diameter

Down-line

Length

Pressure Drop

in barg *

HHP required

for 1m/sec

BHP required

for 1m/sec**

2” 1,200m 210 barg 1,600 HHP 2,560 BHP***

3” 1,200m 78 barg 594 HHP 1,014 BHP

4” 1,200m 24 barg 183 HHP 382 BHPTable 2-3 Flooding Pressures – Typical Pipeline

* Using Mears pipe flow calculator

** Based on 65% efficiency (centrifugal pump) plus 100bhp for engine ancillaries

*** Maximum power from portable, marinised diesel engines approx. 1,800 BHP


Hence the down-line surface injection pressure increases as the down-line ID decreases.

Such changes can be accommodated by using higher pressure surface equipment up to

the point where the pressure reaches the limit of commercially available equipment, or

the down-line itself.

In the following example we look at a scenario to dewater a deep water flow-line using

high pressure compressed air.

Line NPS 16”

Wall Thickness 20mm

Line Length 8KM

Water Depth at launcher 1500m

Water Depth at receiver 1500m

Water Temp at surface 28°C

Water Temp at Seabed 4°C

Average dewatering velocity required 0.3 m/sec Average

Free air delivery flow / pressure at

pipeline injection point to achieve

0.5m/sec

11,000 cfm @ 152 barg plus friction loss

through hose. See below

The important data from the above is that we need to inject 11,000 cfm of air into a

pipeline at a water depth of 1,500m

The vessel based spread must be designed to deliver 11,000 cfm in to the pipeline –

hence the first consideration is the size of the down-line required. Having looked at the

various pressure drops across the down-line, we then need to evaluate the air

compression capacity required to overcome the down-line and pipeline system pressure

losses and deliver the flow to the system.

Down-line

Internal Diameter

Down-line

Length

Pressure Top of

Downline (barg)

Pressure Drop

(barg)

2” 2,200m 277barg 125barg

3” 2,200m 173barg 21barg

4” 2,200m 157barg 5bargTable 2-4 Dewatering Pressures – Typical Pipeline

Commercially available air boosters have a MAWP of around 200barg hence a 2” down-

line cannot be considered in this example. Equally the pressure drops in the 3” and 4”

lines are similar and hence the 4” offers no real advantage.


Coiled Tubing System Design2.3.3

Initial evaluation of a number of deep water pipeline projects indicated that compressed

air injection rates in excess of 10,000cfm would be required, injected on to a down-line

up to 3,000m long.

Engineering for such scenarios showed that the 2” coiled tubing 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:

2 7/8” pipe is readily available and there is considerable experience with this pipe

in down hole applications.

3 ½” is not widely used in down hole applications, but it is manufactured, and

readily available. These larger pipe sizes have much lower pressure drop, and so

are better suited for these applications

In looking at reel dimensions it was decided to opt for a reel that would handle 3000m of

2 7/8” and around 2300m of 3 1/2” pipe. This gives reel dimensions of 96” (2.43m)

between flanges, with a core diameter of 120” (3.05m) and flange diameter of 180”

(4.57m), and reel skid dimensions of 223” (5.66m) long, 144” (3.65m) wide and 182” high

(4.66m). The weight of the skid with pipe is 90,000 lbs (41,000kg).

It was decided to mount the rest of the equipment on a single skid for ease of

transportation and lifting. This skid also provides the basis of the overboard deployment

system. A trolley system is used, which allows 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 moon pool deployment. The skid accommodates the control cabin, the

power pack, the gooseneck and all ancillary equipment in its transport mode. In use the

control cabin is lifted off the skid and is replaced by the tubing reel, which partially

balances 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 radius of the power pack,

giving flexibility depending on vessel layout. The main transport skid if 40ft (12.2m) long

by 12ft (3.65m) wide, weighing approximately 80,000lbs, so although it is a permit load it

can be transported by conventional truck. The use of a spreader beam gives a single

point DNV certified lift for offshore lifting.


Figure 2-7 Coiled Tubing unit in transit mode, showing main deployment skid and reel

The power pack, injector, gooseneck and control cabin are all effectively standard

components. The reel is also standard in the way it functions, but the dimensions are

unique to meet the criteria outlined above.

Beyond that there are several unique components to meet the specific needs of the

application. As we are not using the coil in a well, there is no need for a traditional

blowout preventer (BOP). However there are several functions that the BOP provides

that were deemed necessary in this application. Although a subsea quick disconnect

coupling can be used with the system it was deemed necessary to have a tubing cutter

built into the system, as a means of last resort in the case of extreme weather. This is

mounted directly underneath the injector, and is hydraulically actuated from the control

cabin.

In the event of injector failure with the pipe deployed it was advisable to have a

mechanism to hold the pipe in place while repairs were affected on the injector. A tubing

clamp above the injector, rated for the full weight of pipe deployed is built into the stack.

For these large pipe sizes it was decided to include a tubing straightener into the system.

With no well to constrain the pipe it was deemed a necessity, as no residual curvature in

the pipe is desired in this application.

The tower on which the trolley is mounted has a storage well in which to transport the

clump weight which is attached to the bottom of the coil during deployment. A spacer

frame is mounted on the trolley underneath the injector. This allows the clump weight

and bottom hole assembly to be attached to the bottom of the coiled tubing string and

retracted into the spacer frame to facilitate deployment over the side of the vessel.


Figure 2-8 Complete spread in deployed configuration

The bottom hole assembly consists of a tubing connector, a swivel to allow the jumper

hose to orient itself in the direction of the connection, and the clump weight hanger.

Several different options can be considered for the jumper hose, depending on the

application. In situations where the hose will remain at pressures above that of the static

head a standard hydraulic hose can be used. Working pressures of 5000 psi and higher

are readily available and a surplusing valve can be used on the end of the hose to

ensure that minimum pressure is retained to prevent collapse. In a scenario where the

pipeline has to be depressurized it is necessary to use a non-collapsible hose. A typical

high-pressure hose that might be used as a pipeline jumper (Coflexip or similar) was felt

to be very difficult to handle, not very flexible, very expensive, long lead time and difficult

to repair in the field. The alternative was to use a bundle of 1” hoses, manifolded

together. This is a much cheaper solution, is very flexible and individual hoses can be

replaced in the field in the event of damage.


Figure 2-9 Bottom hole assembly and jumper hose ready for connection to PLET


2.4 CHALLENGES OF USE OF COILED TUBING IN A BLUE-WATER MARINEENVIRONMENT

In this section the challenges of deploying coiled tubing in a blue-water marine

environment are explored.

Figure 2-10 Coiled Tubing Entering Sea

The main issue associated with deploying the coiled tubing as a down-line in a blue

water marine environment is the impact of current on the coiled tubing string and the

vessel movement, resulting from wave action, which can cause fatigue in the pipe string.

In down hole applications high-cycle fatigue is not an issue, as 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 Mexico. The calm sea state and relatively weak currents have not caused any

major issues with the coiled tubing, even in deployments lasting several weeks. However

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 conditions were encountered required us

to look at this in more detail. In order to assess this potential impact, extensive modelling

was carried out to determine the effect of different conditions on the Coiled Tubing string

and the entire jumper system across to the PLET. Modelling was undertaken using

OrcaFlex™ to look at deployment analysis, in-place analysis and high cycle fatigue.


Orcaflex™ requires 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 deployed conditions

MetOcean data

Vessel data and details of the hang-off point for the coiled tubing

RAO data for the vessel

Specific issues to be addressed as part of the analysis:

Allowable yield stress utilization in the coil tubing across the range of conditions

that could be encountered during operations

Assess the need for a bend stiffener for the coiled tubing based on the above

Look at vortex induced vibration (VIV) 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 prevent the MBR being exceeded

Evaluate potential clashing of the coiled tubing and/or hose bundle with 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 stiffener 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 stiffener 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 in all cases of Hs less than 3m

to below the allowable limits of stress utilization based on curvature and tension.

Figure 2-11 Sketch of proposed bend stiffener


In many instances with the vessel in a fixed position it is possible for the hose and BHA

to be tensioned beyond their design limit, so 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.

Vortex induced vibration was found to be present in the initial analysis 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, so the vessel may have to be oriented accordingly to avoid this.

With the bend stiffener designed as described the coil was analysed for fatigue. As

indicated earlier high-cycle fatigue is a major concern in this application given the

constant movement of the vessel. In this particular instance the coil was anticipated to be

deployed for around 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 combination of these two fatigue regimes requires further

investigation to come up with a probable ultimate fatigue life of the coil.

In summary there are multiple parameters than must be considered and modelled prior

to deploying coiled tubing in a blue-water environment. With projects ongoing in

Australia, Brazil, China and Norway data will be gathered and analysed against earlier

fatigue predictions. This will lead to the development of enhanced analysis techniques

for future projects.


Part 2 – Innovative Wet Buckle Contingency Solutions Using a Coiled Tubing3Down Line

3.1 A BRIEF INTRODUCTION TO WET BUCKLE CONTINGENCY TECHNIQUES

Many subsea pipeline installation projects employ some kind of system to mitigate

against the effects of a wet buckle, should such an event occur. In this section we

discuss the needs for such a system, the options available, and the limitations.

A wet buckle is best defined as an unplanned event where the pipeline has been

damaged and the integrity of the pipeline has been lost. The sea water enters the air

filled pipeline and displaces the air. Damage may be caused by excessive forces from

the lay vessel, effects from the sea bottom conditions or mechanical damage from

anchors.

The typical result of the wet buckle event is that the increased weight of the seawater in

the pipeline will overload the tensioners on the lay vessel and cause the pipeline to be

released from the lay vessel to the seabed further damaging the pipeline and exposing

the pipeline end to further ingress of sea water. The lay vessel typically will not be able to

recover the pipeline until the pipeline has been emptied of water and a suitable

connection point is installed on the pipeline.

In addition to the physical damage to the pipeline the untreated sea water and sea

bottom debris will start to corrode the internal surface of the pipeline.

There are many recorded cases of such events, many of which incurred significant

project costs usually recovered through project insurance. Today project insurers are

aware of such risks and often insist that a wet buckle contingency system be available at

short notice during the offshore pipe lay period.

The damaged sections of the pipeline need to be cut using ROV and diamond wire saw

to expose a clean cut section of pipeline. A Pipeline Recovery Tool (PRT) is then

inserted into the cut end and hydraulically engaged to grip and seal the pipeline.


Figure 3-1 Diagram of PRT

There are various designs of PRT, some of these can launch and receive pigs to assist

in the displacement of the untreated seawater and debris.

The actions required to manage the ingress of untreated sea water and debris from the

pipeline and ultimately recover the pipeline to the lay vessel are dependent on the

composition of the water, debris and time it will take to finish pipe lay and complete the

pre-commissioning.

For a deep water pipeline the usual actions required are:

Remove the untreated water

Inhibit any residual water to prevent further corrosion

Remove debris

Inhibit any residual debris including H2S treatment (if water contains H2S

Remove water either form the full pipeline section, or a partial section

Traditionally the flooding and dewatering spreads are located onshore or in the shallow

water location and the entire pipeline is flooded and dewatered using pigs to separate

the drive mediums. Pigs are launched from a temporary pig trap or startup head

preloaded with contingency pigs, the flooding pigs can be discharged subsea but the

dewatering pig must be caught in the PRT. Once the pipeline is dewatered the lay vessel

can recover the pipeline and continue the pipe lay operation.


In the case of long, large diameter and deep water pipelines the flooding and particularly

the dewatering spreads can become very large requiring significant investment to

recover the pipeline in an acceptable time frame.

Discharging a significant volume of chemically treated water to enable recovery of the

pipeline may also be restricted due to environmental concerns or discharge permit

restrictions if the entire pipeline volume must be displaced.

Figure 3-2 WBC Air Spread Stored Onshore


3.2 USING COILED TUBING TO PARTIALLY DEWATER AND DEPRESSURISE ADEEP WATER PIPELINE SECTION

In section 3.1 the applications and limitation of wet buckle contingency systems were

discussed.

However for large bore, deep water pipelines such as Galsi, Polarled and South Stream

the compressed air spread required to dewater the line is huge and the dewatering time

very slow.

As an example, to South Stream pipeline would require a standby dewatering spread to

be located in the vicinity of the subsea initiation head. This vessel based spread

requirements are shown in this table:

Air requirement

(scfm)

Av.

Velocity

(m/sec)

Days for

800km

No. of

compressors

(1,050scfm)

No. of air

boosters

(2,070scfm)

Vessel Deck

Space

Required

Est. diesel

consumption

(litres/day)

53,000 0.3 31 51 26 2,700m2 236,000

40,000 0.23 40 38 20 2,400m2 179,000

Table 3-1Examples of Conventional WBC Dewatering Spreads

Furthermore with South Stream having a DNV hydro-test waiver, there is no post hydro-

test dewatering, and hence no other need for a full dewatering system other than to

support wet buckle contingency.

To mitigate this vast contingency requirement Baker Hughes developed a solution to

partially dewater, isolate, and depressurize a short deep water section using a large-bore

coiled tubing down-line.


This technique is summarised as follows:

1. An unplanned flooding event occurs. WBC flooding spread commissioned.

2. WBC flooding pig receiver / catching head installed. Head fitted with 12” discharge

port for air / water outlet during WBC flooding operation.

3. Line then flooded with filtered, treated sea water from WBC flooding spread and

free flood untreated seawater displaced with treated seawater within 20 days.

Water treated for a pre-agreed wet park period.

4. WBC flooding pig receiver then recovered to surface and a Pipeline Recovery

Tool (PRT) installed with a pre-loaded Smart Plug

5. Concurrently line Coiled Tubing (CT) dewatering system installed on a DP vessel

6. Once function tested the CT dewatering system is deployed to the recovery head

7. Smart Plug propelled about 3km to 5km in to the line and treated water

discharged at WBC pumping location. This can be conducted at a lower velocity

than conventional dewatering.

8. Smart Plug set and air pressure bled down at surface

Figure 3-3 Schematic of Partial Dewatering Spread

9. Lay barge recovers line to surface and pipelay can recommence.

10.Thus leaving the Smart Plug in place until dewatering operations commence after

completion of pipelay.


With this technique we can then use the dewatering air pressure to equalise across the

Smart Plug and then push it to receiver as part of the dewatering train. We also have the

option to relocate the dewatering system to either end of the line depending on Smart

Plug final location and manufacturer recommendation.

The benefits of this solution are clearly demonstrated in this table and in the bullet points

here:

Air requirement

(scfm)

Av.

Velocity

(m/sec)

Days for

5km

No. of

compressors

(1,050scfm)

No. of air

boosters

(2,070scfm)

Vessel Deck

Space

Required

Est. diesel

consumption

(litres/day)

10,200 0.1 0.5 11 5 900m2 25,600Table 3-2 Example of Partial Dewatering Spread

Lower cost related to WBC contingency equipment – which is rarely used!

Smaller vessel requirement on standby.

Reduced fuel requirements.

It the event that a Partial Wet Buckle Dewatering System is used; final dewatering

can be conducted after shore tie-in and during conventional pre-commissioning

period.

In summary (based on the South Stream example):

Key Issue Partial Dewatering Conventional Dewatering

Dewatering Time

Much Better – 2 days

including deployment &

recovery

Much Worse – 31days @

min of 0.3m/sec

Deck Space

Much Better – a spread

designed for 0.1m/sec

requires approx. 880 m2 of

deck space

Much Worse – a spread

designed for min 0.3m/sec

requires in excess of

3,300m2

Fuel UsageMuch Better – total of 25,600

litres

Much Worse – total of

7,300,000 litres

Equipment Cost

Significantly Better – even

excluding fuel 1/3 of the cost

of std. WBC.

Much Worse – excluding

fuel at least 3 x the cost of

partial dewatering.

Installation Vessel

Standby

Better – excluding flooding

vessel standby could be less

than 5 days

Worse – excluding flooding

standby could be 40 days

Table 3-3 Comparison of Partial and Conventional WBC Dewatering


SUMMARY AND CONCLUSIONS4With this paper the authors have endeavoured to demonstrate the following:

1. That down-lines play an important role in the pre-commissioning of deep waterpipelines

2. That coiled tubing should be considered as the preferred down-line system exceptwhere very large bore down-lines are required. Even then multiple coiled tubingdown-lines can be considered as an alternative.

3. That custom marine coiled tubing systems provide the flexibility for moon-pool orover-the-side deployment and are largely self-supporting once installed.

4. That engineering and modelling is required prior to deploying coiled tubing in ablue-water environment.

5. That a partial dewatering system offers a faster, lower cost alternative to a full wetbuckle contingency dewatering system, especially for pipelines not intended forhydrostatic pressure testing.

Documents

Paper 43 - Deep Water Pipeline CT 9_2_15