Lecture 3_23Apr SW0[1]

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Slide 1

PIPELINES AND SOIL MECHANICS

Pipeline Ancillary Equipment

Presented by: Scott Wright PhD BEng (Hons) [email protected]

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Slide 2

Q: What is pipeline ancillary equipment?

A: Components of the pipeline system other than the physical pipeline.

The list of components is wide ranging but we will take a look at:

Flanges, end fittings and connectors

Bulkheads

Coatings

Insulation

Anodes

Protection

Manifolds

Valves

Flow meters

Controls equipment

Tie-in spools

PIPELINE ANCILLARY EQUIPMENT

When asked to do this lecture I wasnt sure what we should be looking at for pipeline

ancillary equipment.

In the end I decided that it should be all components of the pipeline system other than simply

the physical pipe. In reality there is a wide range of components that make up the pipeline

system, each of which performs an important role. We will take a look at the most significant

of these components, including:

Flanges, end fittings and connectors.

Bulkheads.

Coatings.

Insulation.

Anodes.

Protection.

Manifolds.

- Valves.

- Flow meters.

- Controls equipment.

Tie-in spools.

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Slide 3

FLANGES

Flanges provide a pressure containing connection between two parts of the pipeline

system.

Flanges are traditionally made by hand either onshore or by diver on the seabed.

Principally 2 types of flanges:

API

ANSI / ASME

Flanges provide a pressure containing connection between two parts of the pipeline system.

Flanges are normally made by hand either onshore or by diver on the seabed.

Principally 2 types of flanges:

API - provides face to face seal between the flange faces.

ANSI / ASME Flange faces are separated and interface is provided through the

gasket.

In general, API flanges are smaller than ANSI flanges.

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Slide 4

FLANGE ASSEMBLY

Weld Neck to Weld Neck Connection Weld Neck to Swivel Ring Connection

Weld Neck StudboltsGasket

Weld Neck

Swivel Ring

Subsea flange connections are normally made using weld neck to weld neck flanges or, where

the flange connection needs to be made-up Subsea, using weld neck to swivel ring flanges.

Weld neck flanges consist of a single component comprising a flange with a tapered hub

section to which the pipe is welded.

Swivel ring flanges are made up of two components, an inner part and a outer swivel ring.

The inner part is similar to weld neck flange and is welded to the pipe at the rear of the

tapered hub. The swivel ring freely rotates around the hub for easy alignment of bolt holes

during make up. The flange is bolted together through the swivel ring which bears on the

inner hub.

Between the flanges there is a metal gasket which provides the pressure retaining seal.

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Slide 5

SMALL FLANGE ALTERNATIVES

Compact Flanges SPO, Destec

Hub Clamp Connectors Grayloc, Techlok

Often size and weight is of particular concern in subsea design. There are a number of

alternatives to the traditional ANSI and API flanges, the most common being:

Compact flanges, such as the vector SPO flange and the Destec Compact flange.

Hub connectors, such as the vector Techlok and the Grayloc connectors.

Compact flanges are a smaller and lighter proven alternative to conventional ANSI or API

flanges. Compact flanges are increasingly used in the subsea industry because of their

smaller sizes, lower weight and guaranteed seal integrity.

Hub connectors again provide significant size and weight savings. They also provide reduced

bolting requirements and therefore reduce the time required to make the connection. They are

often the preferred solution where space, weight and joint integrity are critical and can often

be found on flexible riser systems.

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Slide 6

FLANGE RATING

Flanges, indeed many pipeline and piping components, are c lassified by pressure

rating.

425.4

2,500

255.4153.110268.25119.6ANSI Pressure @ LowTemperature (bar)

1,500900600400300150ANSI Class

32

164

G

M

G

FPP deff

++=

G = Mean Gasket Diameter

Pd = System Design Pressure

F = Tensile Load

M = Bending Moment

Peff = Equivalent Flange Pressure Loading

Kellogs Equation

20,00015,00010,0005,0003,0002,000API Pressure (psi)

Flanges are classified by pressure rating. If the flange was subject to no other loads it would

be capable of retaining this pressure. However, tensile loading and bending moments acts to

open the flange pair and this reduced the pressure it can withhold.

The Kellogs equation can be used as a first pass to assess flange loading. In this equation the

flanges pressure capacity is apportioned into pressure, tensile and bending moment capacity.

Detailed flange capacity calculations can be performed using the method in ASME VIII and

PD5500. Alternatively finite element analysis can be performed with linearised stress checks

in accordance API 6A or PD5500.

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Slide 7

MECHANICAL CONNECTORS

Mechanical connectors are typically used in flanged-spool repair applications.

They can be fitted to pipe ends to provide a flange connection.

They are proprietary equipment and as a result are more expensive than a traditional welded

flange solution.

The pipe end needs to be cleaned and prepared to the connector manufacturers requirements.

The connector is then slid over the pipe end and tightened. The action of tightening the

connector activates the gripping and sealing mechanism.

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Slide 8

MERLIN CONNECTOR

There are some advanced connectors out there like the Merlin connector. Either side of the

connector is welded to the pipe ends. The pipe ends are then brought together. The annulus of

the connector is pressurised and the two components are displaced together. The annulus is

then depressurised and the connection is complete.

It provides a connection with a high integrity metal to metal seal.

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Slide 9

DIVERLESS CONNECTORS - When is Diverless Technology Required?

Requirement Set by either

Water depth

Safety

Local Legislation

Existing kit

Implication of Water Depth

Increase in Hydrostatic pressure with depth.

Toxicity and impact of respiratory gases under pressure on human tissue.

Fatigue, insomnia, memory loss occur as depth increases >> 300m

Time to decompress increases

e.g. For a dive to 530m, takes 8 day to compress, 18 Day to decompress

Before delving into diverless system requirements, it is worth considering why we would

adopt a diverless system strategy.

In general pipelay can be conducted in a variety of water depths up to 2000m without divers

being required. The primary area that require diver intervention is for the make up of

connections on tie-in spools or for maintenance (intervention) when something needs to be

changed out.

1. Water depth poses a natural limit set by human physiology. Typically saturation divers can

operate safety to about 300m (1000ft). With increasing depth, the gases and in particular

oxygen (in air diving) can become toxic which necessitates differing respiratory gas

combinations depending on depth. At deeper depths, experience has shown that fatigue,

insomnia and memory loss can occur, although divers have achieved 530m in water and over

700m in dry decompression chambers. An additional consideration is the time for

decompression which is limited to approximately 15 meters per day, and this controls the time

required for decompression.

2. A second consideration is safety. Intuitively, placing a diver in the water poses a risk.

Adopting an alternative diverless technique has to be fundamentally safer, although this will

incur a cost delta which may be significant

3. There may be local legislative requirement for the work to be done diverless. This is the

preference in Norway where divers are used only as a last resort for safety reasons.

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This can cause some interesting cases where projects straddle the UK-Norway boundary

where the portion in UK waters has been diver assisted and that in Norwegian waters is

diverless.

4. Finally, if tie-in into existing subsea kit there may be little option but to adopt a similar

philosophy.

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Slide 10

DIVERLESS CONNECTORS - When is Diverless Technology Required?

Diving Options

Air Diving: Breathing gas : Normal atmospheric mixture of oxygen and Nitrogen

Limited to a depth of about 58m (190 ft)

More commonly being used for

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Slide 11

DIVERLESS CONNECTORS

Many different Diverless Connection system on Market

Fundamentals of each are similar, but differ locall y in design Vetco (GE) : Icarus, HCCS or VCCS system

Cameron : CVC or CHC system Kvaerner : RTS and BBRTS system FMC : FLYCON, ROVCON, UTIS system

Diverless Lacks benefit of diver dexterity: Bolted clamp no longer possible

=> Adopt either a clamp or collettype solution Clamp must be deployable by ROV

Dedicated structure to enable primary location => An alignment structure is required with guide posts

Method of pulling in either connection required => A dedicated pulling tool required

Method of inserting seal and cleaning sealing faces if dirty

All functions must be conductable by ROVThese compromises / enhancements increase the size, weight, complexity and cost of the connection.

Diverless connection systems are typically classified by the orientation of the connection, i.e.HORIZONTAL OR VERTICAL

The intention with diverless system is to provide exactly the same level of functionality and

flexibility as a diver assisted system. However, divers have a major benefit; that being their

freedom to move and rotate. Any mechanical system trying to provide similar flexibility

needs to be quite complex and is ultimately expensive. The approach taken is to make the

seabed installed sections as cheap and simple as possible (essentially just steelwork), with all

the control and pulling systems located within multi use tying tools.

Considering a comparison with a typical bolted flange assembly, the following applies:

1.

Firstly, bolting a flange is quite a complex operation for a machine. It is easier to

use a clamp with tapered faces, or a collet type connector (see next slide) which

simplifies make up.

2. Ends need to be located within a certain range to enable clamping of both halves.

This requirement dictates the need to positively locate the spools relative to one

another which is done using retrievable guideposts.

3. Generally, the guidepost provides only course initial alignment. A tie-in tool is then

used to clean the connecting faces. To facilitate pull-in, pull-in forces need to be

transferred between each side of the connection and this requires a dedicated pull in

structure. As the forces involved can be large, the tie-in structure itself can be huge.

Once in position the tie-in tool inserts a seal ring, pulls both halves of the connectors

together and makes up the clamp. All these functions are controlled by a work class

ROV operated form the surface.

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A large range of diverless connection system current exist essentially each sub sea

equipment supplier has their own unique system which are all unique. However, ultimately

they may be broken down into the orientation of the connector : either Horizontal or Vertical

and the type of connector used : Collet or clamp type connector.

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Slide 12

DIVERLESS CONNECTORS - Collet And Clamp Connectors

Collet Clamp

Collet (Left) and Clamp (Right) Connectors

The collet connectors has a number of latching fingers (shown in black) and a movable

securing ring (shown in yellow) which is positioned around the pipe hub (gray). In this

diagram the connector is closed with the yellow securing ring engaged.

When the yellow hub is retracted, the fingers open and this allow a mating hub to mate

against the hub within the clamp. The yellow locking ring is then engaged causing the latches

to close and secure the mating hub together. To reverse the operation, the locking ring is

retracted and the fingers open.

The clamp connector operates by means of a 3 piece clamp assembly attached to an ROV

operable trunnion which opens and closes the clamp assembly. The inner surface of the

clamps and the external profile of the hubs are profiled that once the hubs are located with a

certain capture tolerance, the clamp forces both hubs together to form a seal. The yellow disk

is the sealing gasket.

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Slide 13

DIVERLESS CONNECTORS - Horizontal Tie-in System

Make up: Metrology conducted and spool fabricated on

shore to fit. Landing bucket and inboard connector pre-

attached to structure

Spool lowered from Vessel and ROV used toensure stab-in pins lands within Landingbucket (primary alignment)

Tie-in tool lowered from Vessel and slidesdown V shaped receptacles over bothconnectors.

ROV controls stroking operation from top Both halves pulled together, ROV engages

Collet clamp and conducts back seal test. Tie-in tool removed.

Considerations Low connection height required, typically 1.5m

minimum Low height allows protection from Fishing and

dropped objects However, larger probably of stirring seabed

with ROV di rt in connector Spool needs to be made short to allow fit-up

=> Spool prestressed during pull-in

Landing bucketattached to structure(Primary alignment)

In board Connector onStructure

Outboard hub withcolletconnector

Tie-in Tool (lands overeither half and strokes

halves together andmake up collet)

Tie in spool withStabinpin in Funnel

A Cameron Horizontal Connector tie-in system is shown above. The Landing bucket and

inboard connectors are preinstalled on the structure during the structure fabrication.

Once the structure and pipeline is installed metrology is conducted to determine the

finalised length of the tie-in spool, within a permissible tolerrance. Metrology is required as

all subsea structures can only be installed to a certain level of accuracy typically within +/-

2m.

One the metrology measure is known, the spool is fabricated with the outboard half of the

connector attached, pressure tested, rigged for lifting and shipped offshore for installation.

Each outboard connection has a vertical stab-in pin which is used for primary location of the

connector. In the figure above, this is located within the landing bucket and is not visible.

Both sets of hubs are separated by a known distance which is large enough to allow any

protection covers to be removed and to facilitate seal ring insertion / cleaning of the mating

surfaces.

The tie-in tool is then deployed and lands over both hubs. The yellow ring around the hub is

the reaction structure onto which the Tie-in tool lands and reacts against to pull both halves

together.

In the present case, a collet type connector is shown. The orange ring is pulled down over the

fingers to secure both halves of the clamp together and complete the tie-in procedure.

A fundamental consideration with a horizontal system is that as a gap is required, the spool

must be made short to ensure fit. During the stroking operation the spool is prestressed into

position and stresses must be assessed to ensure these are within permissible limits.

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Horizontal connectors can be positioned approximately 1.5m above seabed. However, the

lower the connector, the larger the possibility that ROV will sir up dirt that may foul the

sealing surface, which may require the connection to be remade. A back seal test facility is

typically provided to give an indication that the seal is good.

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Slide 14

DIVERLESS CONNECTORS - Vertical Tie-in System

Make up: Metrology conducted and spool fabricated on

shore to fit. Spool configured in W or M configuration to

allow expansion Inboard connector pre-attached to structure

Spool with pull-in tool preinstalled droppedfrom vessel and landed over Inboard Hubs.

Tie-in tool secured and pull-in operationbegun

Both halves pulled together, ROV engagesCollet clamp and conducts back seal test.

Tie-in tool removed.

Considerations Spool generally span between connection

points Height of connection typically>3m

Reduces potential for dirt in connection fromROV operations.

Height causes a concern where Fishing anddropped objects are a problem. More difficultto protect.

Spool made of exact length => Spool doesnot become pre-stressed during tie-in

Inboard Hub onStructure

M-shaped Spools

Combined alignmentand tie-in tool

The vertical system is similar to the horizontal system except orientated in the vertical plane

which causes the assembly to be much taller and more snagable where fishing interaction is

likely.

The tie-in spool is usually orientated vertically and configured in a U or W shape to allow

expansion. Metrology is conducted and the spool is fabricated and shipped to site for

installation. One key difference from the horizontal system, is that as both end are landed at

the same time, there is no need for the spool to be fabricated short. Additionally, gravity helps

to locate either end. The pulling and latching of the collet connector is conducted similar to

the process described for the vertical connector.

Vertically connectors are typically used where fishing interaction is not likely. The assistance

of gravity in make up means they can be more lightweight (primarily as friction loads do not

apply).

As such they can be positioned at a higher elevations relative to the seabed and are less likely

to be subject to fouling from dirt stirred up by the ROV fans.

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Slide 15

DIVERLESS CONNECTORS - Horizontal vs Vertical Connectors?

Considerations

Seabed Conditions

No defined seabed in some deeper water developments

Gradual change in density from water to soil

Concern to ensure connecting surfaces are clean

Vertical connector position 5-6m above seabed provide an advantage.

Fishing interaction

Where fishing interaction is a threat, 5 to 6m high spools are not practical.

Typically adopt horizontal connection where fishing interaction is likely

Typically horizontal connections used < 500m, vertical > 500m

The decision to use horizontal or vertical connectors depends primarily on the seabed

conditions and the level of fishing interaction.

In many West African developments, there is no defined hard seabed, but rather a gradual

change from water to soil. Additionally many of these area are not fished. Thus vertical

connectors are extensively used. In Norway, seabed tend to be either sand or gravel and are in

regions / water depths where fishing interaction remains a possibility. Horizontal connectors

are favoured as they are more squat and thereby easier to protect.

In general, vertical connectors are typicially, but not exclusively, used for very deep water

applications water depths in excess of 500m. Horizontal connectors are used for depth less

than this.

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Slide 16

BULKHEADS

Pipe-in-Pipe End Bulkhead

Where number of pipes terminate at the ends of pipeline bundles, pipe-in-pipe pipelines or

caissons, a bulkhead will be provided to provide mechanical connection between the inner

pipes and the carrier pipe. A bulkhead normally comprises a large steel connection that ties all

of the pipes to the carrier pipe. This connection needs to be designed to accommodate the

different axial loads within each inner pipe and the carrier pipe. The analysis is normally

performed using finite element solid modelling with the results assessed in accordance with

PD5500, API 6A or ASME VIII.

This slide shows a solid finite element model of a pipe-in-pipe bulkhead. Only half of the

assembly is modelled as it takes advantage of a symmetrical boundary along the pipe centre

line. On the left the entire model is shown with the flange, bulkhead and adjoining sections of

pipe. On the right only the bulkhead is shown. The colours indicate the level of stress within

the bulkhead.

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Slide 17

BULKHEADS

Bundle and Caisson Riser Bulkheads

Unlike a pipe-in-pipe system, bundles or caisson riser systems may have a number of internal

pipes. Examples of such cases are illustrated here. The bulkhead generally comprise a thick

connecting plate with nibs that increase in wall thickness as the bulkhead approaches. This

assists in reducing high stresses caused by a the stiffness discontinuity between the pipe and

the bulkhead.

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Slide 18

COATINGS

The pipeline may be coated for a number of reasons, typically:

Submerged weight and stability

External corrosion protection

Insulation

Corrosionprotection

coating

Concreteweight coating

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Slide 19

COATINGS EXTERNAL CORROSION

External corrosion is controlled by a combination of:

Corrosion resistant coating

Cathodic protection (sacrificial anodes)

Typical corrosion resistant coatings include:

Fusion Bonded Epoxy

Thermoplastics polypropylene and polyethelene

Elastomers Neoprene rubber (polychloroprene)

Thermally Sprayed Aluminium

Asphalt Enamel

Wraps

Each coating has an associated breakdown factor

3 layer PP

External corrosion protection is controlled via a combination of:


Cathodic protection

Both are necessary as coating systems are not 100% reliable and it is not practical to provide

anodes to protect the entire bare steel pipeline over its design life.

Typical corrosion resistant coatings include:

Fusion Bonded Epoxy(FBE) is an epoxy based powder coating that is sprayed onto

a rotating pipe. The name 'fusion-bond epoxy' is due to resin cross-linking and the

application method, which is different from a conventional paint. The resin and

hardener components in the dry powder FBE stock remain unreacted at normal

storage conditions. At typical coating application temperatures, usually in the range

of 180 to 250 C, the contents of the powder melt and transform to a liquid form. The

liquid FBE film wets and flows onto the steel surface on which it is applied, and soon

becomes a solid coating by chemical cross-linking, assisted by heat. This process is

known as fusion bonding.

Thermoplastics, typicallypolypropylene and polyethelene which are extruded onto a

rotating pipe

Elastomers Polychloroprene is normally hot-bonded to the steel using a

vulcanization process in a steam autoclave. This process both cures the rubber and

bonds it to the steel. Polychloroprene provides tough, durable protection for pipelines

and risers with excellent resistance to water take-up, hydrocarbons and ozone.

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Polychloroprene can also be applied as a field joint coating on site being cured using

heated electrical tapes.

Thermally Sprayed Aluminium (TSA). A sprayed coating that is suitable for

relatively high temperatures. It has high thermal conductivity which makes it useful

for cooling and heating spools.

Asphalt Enamelis a plant applied durable coating based on modified bitumen

(asphalt).

Wraps. These are not commonly used but may be suitable for field joints.

Selection of coating type will be based on:

Cost

Operating temperature each coating system is only suitable for a certain

temperature range

Installation method

Thermal requirements (U-value)

Other coatings insulation or concrete weight coating.

Location of coating plant

Etc

Coating layers may be combined. The picture in this slide shows a 3 layer polypropylene

coating which is a very common pipeline coating. It is a multilayer coating composed of three

functional components, a high performance fusion bonded epoxy (FBE) followed by a

copolymer adhesive and an outer layer of polypropylene which provides one of the toughest,

most durable pipe coating solutions available.

Each coating system has an associated breakdown factor. This provides a measure of

protection offered to the pipeline by the coating and is thus used when assessing the cathodic

protection requirements. The coating breakdown factor accounts for coating damage and

water ingress. A break down factor of 0 means 100% electrically insulating whereas a break

down factor of 1 indicates that the coating has no protective properties.

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Slide 20

INSULATION

Pipeline may require insulation for flow assurance requirements.

Pipeline insulation may be provided by:

External wet insulating coating

Soil

Dry insulation, pipe-in-pipe system

Wet insulation systems

Solid polypropylene or polyurethane

Syntactic coatings

In oil production pipelines, wax deposition on the pipe wall may occur if the fluid

temperature becomes too low, leading to a local constriction of the bore. Also, the viscosity of

oil rises as the temperature falls, resulting in reduced flowrate. In gas production pipelines,

hydrates (ice-like material) may form under high pressure conditions if the temperature falls

too low and water is present in the product. Hydrates can block a pipeline and are difficult

and costly to remove. Insulating a gas pipeline prolongs the period between shut-in and the

fluids reaching the hydrate formation temperature and this can help to avoid the requirement

to de-pressurise the system. An alternative to insulating a pipeline transporting wet gas is to

continuously inject a hydrate inhibitor such as MEG into the product. Normally hydrate or

wax survival times of 24 hours are targeted following a shutdown event.

Pipeline may require insulation to maintain the required flow rate and prevent wax and

hydrates forming. Flow assurance predicts the thermal insulation requirement and a coating

system is selected to achieve this.

Pipeline insulation may be provided by:

External wet insulating coating.

Soil. If the pipeline is buried the surrounding soil provides thermal insulation.

Dry insulation, pipe-in-pipe system.

External wet insulations generally comprise of:

Solid polypropylene or polyurethane

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Syntactic coatings. Plastic or glass microspheres are mixed with the polymer to

enhance its thermal insulation properties. Syntactic polyurethane (SPU

polyurethane mixed with plastic or glass microspheres).

Overall heat transfer coefficients or U-values as low as 2.5 W/m2K can be achieved using an

external wet insulation system.

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Slide 21

DRY INSULATION - PIP

Pipe-in-pipe systems comprise of two pipes with dry insulation in the annulus:

The insulation may be:

Polyurethane foam

Rockwool

More sophisticated material, such as:

- Aerogel

- Izoflex

- Wacker

Centralisers required to maintain pipe concentricity

As a contingency water stops may be provided.

A pipe in pipe system consists of 2 pipes one inside the other. The outer or carrier pipe

provides a dry annulus around the inner pipe. This enables the use of dry insulation which is

far more effective than wet insulation. Sometimes a vacuum can be provided in the annulus to

improve the thermal insulation. Overall heat transfer coefficients or U-values as low as 0.5

W/m2K can be achieved with pipe-in-pipe systems.

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Slide 22

ANODES EXTERNAL CORROSION




Cathodic protection involves the use of galvanic sacrificial bracelet anodes attachedto the pipeline at intervals along its length.

Anodes are electrically connected to the stee l pipeline.

Typical galvanic anode materials include:

Aluminium

Zinc

Magnesium




External corrosion is covered within the materials module of the course and is therefore not

covered herein.

Corrosion is an electro-chemical process that involves the passage of electrical currents.

Cathodic protection involves the use of galvanic sacrificial bracelet anodes attached to the

pipeline at intervals along its length.

Galvanic anode systems employ reactive metals as anodes that are directly electrically

connected to the steel being protected. The difference in natural potentials between the anode

and the steel, as indicated by their relative positions in the electro-chemical series, causes a

positive current to flow in the electrolyte solution (surrounding water) from the anode to the

steel. Thus, the whole surface of the steel becomes more negatively charged and becomes the

cathode. The anode (anodic reaction) corrodes as it passes electrons to the cathode (steel

cathodic reaction) which does not corrode.

The metals commonly used, as sacrificial anodes are aluminium, zinc and magnesium.

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Slide 23

PROTECTION

Pipelines and spools require protection from f ishing gear and dropped objects.

Untrenched pipeline sections and spools are often provided with additional protection.This typically takes the form of:

Concrete mats

Concrete tunnels Protection frames

Rockdump

Pipelines exposed to a significant possibility of impact from dropped objects, fishing gear or

any other type of harmful interface, must be shown to be capable of retaining their integrity

and operability should such an event occur.

A dropped object assessment is normally performed to assess the potential, based on the

frequency of offshore lifts, of various dropped objects and the probability of these objects

impacting the subsea facilities. Tie-in spools are not normally buried and are often located

adjacent to offshore facilities, where there is an increased risk of dropped object impact.

Surface laid pipelines and spools that are located in areas of frequent fishing activity must be

shown to be capable of surviving interference from the various types of trawl gear that they

are likely to encounter. DNV RP F111 gives guidance on these calculations for trawl gear

pull-over, impact and hooking.

Pipelines smaller than 16 inch diameter are usually trenched and buried for mechanical

protection in the UKCS (united Kingdom Continental Shelf).

Concrete weight coatings, applied primarily for stability, are considered to offer some impact

protection to pipelines.

Untrenched pipeline sections and spools are often provided with additional protection. This

typically takes the form of:

Flexible concrete mattresses

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Concrete protection tunnels

Protection frames

Rockdump

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Slide 24

CONCRETE MATTRESSES

Concrete mattresses typically dont absorb a great deal of energy but rather spreads the

energy so that it doesnt act as a knife edge impact.

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Slide 25

PROTECTION STRUCTURES

Concrete Tunnels

Tie-in spools are typically protected using flexible concrete mattresses. Where this provides

insufficient protection or the spool cannot have mattresses protection, for instance elevated

free draining spools, protection structures may be adopted.

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Slide 26

ROCKDUMP

Rock may be used for protection or to restrain the pipeline. As protection it may be used

along the entire pipeline length or more normally at crossings and trench transitions.

Rockdump may also be used for intermediate supports on uneven seabeds. Its use is typically

restricted to geographic regions where rock is readily available.

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Slide 27

SUBSEA STRUCTURES - MANIFOLDS

A manifold is a subsea structure housing:

Pipework

Valves

Controls Equipment

Chemical injection and distribution facilities

Metering

for the control and operation of the Subsea field.

A manifold is a subsea structure that houses:

Pipework

Valves

Controls equipment

Chemical injection and distribution facilities

Metering

for control and operation of the Subsea field.

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Slide 28

MANIFOLD DESIGN

Design Activities

Structural analysis

Transportation

Installation

Inplace

- Hydrodynamic Loading

- Foundations

- Impact / Fishing Gear Interaction

Pipe Stress Analysis

Controls Equipment DesignCodesandStandards

Designing a manifold for the system requirement involves:

Structural analysis.The principal purpose of the structure is to protect the

equipment within its envelope. As a result, the structure needs to be suitably designed

for all functional and accidental loads that it may be exposed to throughout its design

life.

Pipe stress analysis.The pipework within the structure should be suitable for the

design operating conditions as well as any functional and accidental loads that it may

be expose to during its design life.

Controls equipment.The controls equipment covers all electrical, hydraulic and

chemical systems that are required for operation of the subsea field. All control

signals are normally provided through a subsea umbilical which terminates within the

manifold. The controls may then be distributed around the manifold, to the trees, to

other developments, etc. through a subsea distribution unit (SDU), also housed within

the manifold.

Shown here is the 8 slot Callanish manifold from the Britannia Satellites development. The

top picture shows the integrated pipework and structure model used for the design and the

bottom picture shows the 3D model of the manifold.

The scale of the manifold is illustrated by the diver standing at the bottom corner. The

structure is the size of a reasonably large building approximately 15m long 6m wide

6.5m high.

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Slide 29

MANIFOLD INSTALLATION

This slide illustrates the Callanish manifold being installed it doesnt look the size of a

building

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Slide 30

TIE-IN SPOOLS

Tie-in spools connect one part of the subsea system to another.

Typically rigid single pipe and, if required, are designed in a configuration to

accommodate pipeline end expansion.

Commonly configured in a Z shape.

Expansion

Manifold

Tie-in Spool

Pipeline

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Slide 31

TIE-IN SPOOL DESIGN

Tie-in spools are typically designed using a non linear structural, piping or finite element

package.Involves non-linear analysis for the pipe to seabed friction modelling.

Design considerations:

Geometry

Pipe sizes, tolerances, corrosion allowance, etc.

Bends

Seabed restraint

Protection

Loading

Submerged weight

Mattresses

Pressures & temperatures

Environmental loading (waves and currents)

Tie-in spools are typically designed using a non linear structural, piping or finite element

package.

Involves non-linear analysis for the pipe to seabed friction modelling. Non linear models are

those which cannot be solved in a linear manner, in this instance the tie-in spool loading is

path dependant, i.e. the spool submerged weight needs to be applied to generate the frictional

resistance before any operational loading is applied.

The primary design considerations include:

Geometry The tie-in locations, self loading and pipeline expansion may all

influence and the size and layout of the spool.

Pipe sizes, tolerances, corrosion allowance, etc. the pipe will be modelled with

the correct diameter and wall thickness. It is normal to model the pipe nominal wall

thickness, however fabrication tolerances, corrosion allowances, erosion allowances

bend thinning etc. may need to be taken into account when code checking.

Bends spool bends may be of radius 1.5D (forged long radius elbows), 3D (pulled

induction bends) or 5D (pulled induction bends). If there is a pigging requirement the

bends will have to be 3D or 5D induction bends. The hot induction bending process

induces thinning of the bend wall which should be taken into account in the analysis.

Seabed restraint the interaction between the spool pipe and the seabed provides

resistance to spool movement. This resistance is difficult to accurately predict and a

conservative range is normally analysed.

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Protection the tie-in spools must be protected against dropped objects and fishing

gear interaction.

Loading tie-in spool loading will be dependant on the actual tie-in spool

configuration, but will typically involve:

- Submerged weight of the tie-in spool and any attachments, e.g. coatings,

anodes, flanges, etc. and including contents.

-

Mattresses The application of mattress protection adds weight to the pipe

and introduces another interface between the pipe and the mattress, both of

which act to resist spool movement.

- Pressures & Temperatures (where applicable including pipeline

expansion)

-

Environmental loading from waves and currents

Spool design will be illustrated by a simple example.

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Slide 32

TIE_IN SPOOL EXAMPLE

Diameter = 12 (323.8mm OD)

Wall thickness = 17.5mm (Schedule 80)Material X65

s=7850kg/m3

SMYS=450MPa

E=207GPa

=0.3

=11.710-6 oC-1

Contents density =800kg/m3

Pressure = 300bar

Pipeline end expansion = 1m

Seabed frictional resistance = 0.4 to 0.9

Seawater Density = 1025kg/m3

For simplicity ignore temperature, coatings, protection, tolerances.

25m

10m

90o 5D Radius Bend

The wall thickness is sufficient for pressure containment, i.e. in accordance with PD 8010

t

PDSMYS

272.0 > thin walled theory 20>

t

D

Wall thickness requirement t=300e5323.8/(20.72450e6)=15mm (D/t=21.6 therefore thin

wall approximation is OK)

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Slide 33

TIE-IN SPOOL EXAMPLE

Spool

Pipeline

The basic steps to the analysisare:

Set up model with nodes and

elements.

Add section for pipeline.

Apply geometric and materialproperties.

Set up seabed frictionalresistance.

Apply loads.

Solve.

The basic steps to the tie-in spool analysis are:

Set up model with nodes and elements. The tie-in spool-to-seabed contact is modelled

using friction gap elements. These elements represent the spool-to-seabed interaction

by supporting the pipe on discrete vertical springs, with stiffness equal to the vertical

stiffness of the seabed. The pipe is free to rise off the seabed and, when in contact

with the seabed, is opposed from moving laterally and axially by frictional resistance.

As a result, the model is sub divided into a number of elements to gain an accurate

representation of seabed frictional resistance.

A section of the pipeline is added to remove any artificial end effects caused by over

restraint of the spool.

Apply geometric and material properties.

Set up seabed frictional resistance.

Apply loads.

Solve.

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Slide 34

TIE-IN SPOOL RESULTS

Deflected shape for the lowfriction case (=0.4)

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Slide 35

TIE-IN SPOOL RESULTS BENDING MOMENT

Low friction case (=0.4) High friction case (=0.9)

55kNm 311.2kNm185.1kNm

223.8kNm

The above slide shows the distribution of bending moment around the tie-in spool.

Greatest moment is generated in the tie-in spool bend for the high friction case, i.e. that which

provides greatest resistance to spool movement. However, because of the greater resistance,

bending moment drops off with distance from the bend. In the low friction case more moment

is transferred back to the restraint on the left hand side. This could be a flange connection to,

for example, a manifold which you wouldnt want subject to such a large bending moment.

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Slide 36

In the high friction case (=0.9) maximum loading occurs in the spool bend. This corresponds

to:

Effective axial force = -64 kN

Bending Moment = 311.2 kNm

Calculate the PD 8010 equivalent stress utilisation ratio

where fd=0.96 and

TIE-IN SPOOL RESULTS EXERCISE

SMYSfUR

d

equ

=

222 3 ++= lhlhequ

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Slide 37


0.824

Of course the good thing about computer programs is that it does it for you

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Slide 38


We will use an 11 API flange for our 12 tie-in spool. Use the Kellogs equation to determine

whether this flange should be rated 5k (5000psi=345bar) or 10k (10,000psi=690bar).

Note our design pressure is 300bar and a 11 API flange uses a SBX 158 gasket with a meangasket diameter of 328.9mm.

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Slide 39

TIE-IN SPOOL RESULTS - BEND ANGLE

60o

25m

1.06460o

0.94270o

0.87480o

0.82490o

PD 8010 URBend Angle

Someone in the last lecture asked why routing aimed at achieving 90obends on the tie-in

spools. I have re-analysed the tie-in spool with the same leg lengths but varied the angle

between 60oand 90

o. The table here shows increased PD8010 utilisation ratios, and thus

stress, at the spool bend.

Lecture 3_23Apr SW0[1]

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