05. offshore pipelines design-curs5-8ore

8/20/2019 05. Offshore Pipelines Design-Curs5-8ORE

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C A D O F OF F S H O R E S T R U C T U R E SC A D O F OF F S H O R E S T R U C T U R E S -- C O U R S E 4C O U R S E 4

C M UC M U --8 H8 H

OFFSHORE PIPELINESOFFSHORE PIPELINES

DESIGNDESIGN


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Constanta Maritime UniversityIoan Calimanescu PhD 2

5.1 Routing

There are a number of important stages in the life cycle of an oil or gas transmissionpipeline: design, construction, operation and maintenance and finally repair. Thischapter will look at the initial stage of pipeline design for oil and gas pipelines. Withinthe planning phase, and before any work commences on constructing a newpipeline, factors that affect the design process include:the effect on the environment;the pipeline routing process;approval and legal considerations.There are currently numerous standards available that provide guidance on thedesign of pipelines. Some operators may use their own national standard, but many

others use foreign standards that are widely used throughout the pipelineindustry. In particular, for oil and gas pipelines worldwide, the API (AmericanPetroleum Institute), ANSI (American National Standards Institute) and BS (BritishStandards) are widely used. Within the UK, oil and gas pipelines are based onguidance provided by PD 8010 [1]. In addition, the IGE/TD/1 standard [2] is a pipelinecode developed by the Institution of Gas Engineers and Managers within the UK for thedesign, construction and operation of pipelines operating at pressures exceeding 16

bar. In addition, IGE/TD/1 takes into account extensive research into the causesand consequences of pipeline failure. It is appropriate, therefore, that IGE/TD/1 bereferenced for developments in international pipeline standards and current bestpractice throughout the pipeline industry. A summary of the main standards usedworldwide includes those shown in Tables 5.1.


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Consideration must be given to the likely impact a newly constructed pipeline willhave on the environment.It is important to identify the likely environmental effects of a planned pipeline and satisfyappropriate legislation. Obviously there will be different requirements around theworld, but a typical example used within the UK includes the ‘Public Gas Transporter Pipeline Works Regulations’. This legislation requires an environmental impactassessment (EIA) in sensitive areas. Consequently, before the operator can constructa new pipeline, an EIA should be conducted at the design stage.

.

Table 5.1 Overview of standards that

provide guidance on design,

construction and maintenance


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Having considered the environmental impact and routing selection, the nextimportant stage is to notify the relevant authorities of the intention to construct a newpipeline. In the UK, authorization would be provided by the Department of Trade andIndustry (DTI), who must be notified of any new construction projects and updatedon the likely environmental effects. For cross-country pipelines, farmers should beconsulted, since compensation payments are likely, in order to allow a pipeline tocross private land. In addition, permission will be required in areas where theproposed pipeline route will cross roads, railways or river crossings. Finally, toprevent any disruption to the project at the construction stage, appropriatemeasures should be taken to ensure that the proposed route does not affectprotected wildlife species, preventing costly delays later in the project. Once all these

considerations have been addressed and the route options for the pipeline havebeen selected, detailed design of the pipeline system can be done. What does thedetailed design involve?The starting point for the best route is a straight line from where you found the reservesto where you want them delivered. However, very few pipelines go in a straight line andthere are numerous factors which lead us away from the straight route. The issuessurrounding the route selection for the pipeline are considered in this section.


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In open sea, platforms, wellheads, wrecks and anchors should be passed with aminimum clearance of 500 m (1640 ft).Where possible, existing infrastructure should be avoided. This cannot always be thecase as often you will actually be bringing your pipeline to tie into the existinginfrastructure. The basic rules are that the number of pipeline and cable crossingsshould be minimised, pipelines should be corridored where possible, and anchoring

areas and dropped object zones should be avoided.FPSO and semi-submersible drilling rigs have anchor spreads which may have a radiusof 2 km (1.2 miles). The area within the spread will be dead to any passing pipelines.Pipelines to and from the FPSO or subsea development must route in between anchors.

Fig.5.3-Choosing the best route


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Fig.5.4-Seabed obstructions


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Where a route runs parallel with an existing pipeline, the DTI is likely to specify that youmust corridor your route with the existing line. Pipelines may be crossed, but youshould endeavour to minimise the number of crossings as these introduce additionalconstruction costs.Existing pipelines are preferably crossed perpendicularly with the minimum angle being

30°. The reason for this is that any shallower angle of approach would lead to a longand extensive volume of rockdump to make up the elongated crossing.The oil industry shares the seabed with the telecommunications industry (amongstothers). With the advent of subsea fibre optics for international phone calls and internettraffic, there are many cables currently being installed. Whilst crossing an existing cablewould probably not require a pipeline route deviation, it would be important to knowwhere the crossing would occur and to take measures to protect the cable againstdamage.

Fig.5.5-Pipelines and cables


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Many other users have a claim on the seabed and can influence the seabed route.Crossing international boundaries increases the design and operational reportingrequirements.Exclusion zones and dredging areas will need to be routed around.It is often necessary with trunk lines to cross the license blocks of other companies.

Normally this is done by way of negotiation - company A crossing company B’s licenseblock in return for company B crossing company A’s license block somewhere else. Incase of difficulties, the DTI has the authority to impose a solution.There may be environmental pressure to avoid fishing grounds, sites of special scientificinterest and special areas of conservation. However, given that virtuallyall the UK coast and coastal waters fall under some such classification, the approach isgenerally to evaluate the sensitive areas and select the route of minimum environmentalimpact.Where there are busy shipping lanes, the route should go perpendicular so that theconstruction vessels spend the minimum amount of time obstructing those lanes. Areas of rock outcrops are avoided where possible.Similarly, areas of sandwaves are avoided where possible. As a fallback the pipelinemay be routed through the valleys if they have a suitable orientation. As a last resort,

and if it is necessary to cross mobile sandwaves, the sandwave may be dredged downto the level of the valleys.


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Pockmarks are craters typically up to 50 to 60 m (164 - 196 ft) across and 2 to 4 m (7 -13 ft) deep, thought to originate from shallow gas pockets. The pipeline would be routedaround, rather than across, these.Mudslides sometimes occur on steep slopes particularly near river estuaries. If these

slopes cannot be avoided, then the route should run down the slope rather than acrossit.Subsea mud volcanoes and volcanic eruptions simply have to be circumnavigated.Iceberg scars can be very steep-sided deep valleys, which are best crossed at an angle.5.2 Sizing the pipeline-The Diameter

Having defined the pipeline route, taking into consideration factors described inChapter 1, the next stage is to start the detailed design of the pipeline, includingparameters such as volume throughout, length of the pipeline and acceptablepressure loss. Note that the length of transmission pipelines varies considerably andcan range from less than 1 km to thousands of kilometres.When deciding the form of product to transport, it is important to consider theadvantages and disadvantages of using liquid or gas. The main advantages of liquidtransmis- sion pipelines include the following:

During inspection using intelligent pigs, the speed is easier to control.The pipelines are easier to inspect using ultrasonics.It is possible to transport products in batches.Liquid is incompressible, and so the consequence of failure is less critical (i.e. flow canquickly be stopped).Flow is more controllable.


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Disadvantages of liquid pipelines are as follows:There is a greater risk of pollution when leaks occur, i.e. hydrocarbons are heavier than air.

Pipelines can easily become clogged with waxy deposits.There is a greater risk of corrosion from ‘sour’ operating conditions.The main advantages of operating gas transmission pipelines include the following:Pollution is less critical since gases such as methane are lighter than air and diffuseinto the atmosphere.Gases can easily be ventedGenerally, gas pipelines suffer less from deposits than liquid pipelines.‘Sour’ corrosion is not as big a problem as on liquid pipelines.Disadvantages of gas pipelines are as follows:The consequence of failure is higher since the gas is compressible and flow is notas easily controlled.Inspection using ultrasonic tools is more complicated and specialist tools are required.Gas pipelines are usually operated as a single product.

During inspection using intelligent pigs, the speed is more difficult to control owing tothe compressible nature of gas.The methods for sizing pipeline diameters are presented, focusing on the considerationsof fluid property effects and required flowrates. The basic equations for analysis of fluidflow are given along with a description of the different flow regimes within a pipeline.Experience of design of pipeline diameter is gained by completing an exercise.


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The methods for sizing pipeline diameters are presented, focusing on the considerationsof fluid property effects and required flow rates. The basic equations for analysis of fluidflow are given along with a description of the different flow regimes within a pipeline.Experience of design of pipeline diameter is gained by completing an exercise

Fig.5.8-Sizing for flow


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This flow chart illustrates the process of pipeline sizing. We consider all of theseaspects in the followings.The principal factor in diameter sizing is the peak flowrate through the line for anacceptable pressure drop. There are, however, secondary implications that need

consideration in the design process:Check for low flow conditionsCheck for secondary criteriaFlow regimeTemperature profileErosional velocityNaturally occurring oil and gas may contain a range of components, as below.

HydrocarbonsWater Acid gasesSolidsSulphur, nitrogen and oxygen compoundsHeavy metalsWhilst not all of these components are of interest from the viewpoint of flow and pipelinesizing, they do influence corrosion (addressed later in the course). We will, forcompleteness, briefly overview all of these components here.3 main hydrocarbon series found naturally: Alkanes (Paraffins)Cyclo-alkanes (Naphthenes) Aromatics


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Viscosity for each series increases with carbon number. Boiling temperature for eachseries increases with carbon number Alkanes are straight and branched saturated hydrocarbon chains, the simplest of whichis methane (CH4).Cyclo-alkanes have ring structures and are again saturated. The simplest cyclo- alkane

is cyclo-pentane (C5H10). Aromatics are hydrocarbons which are based upon the benzene ring structure. Benzeneis the simplest member of the aromatic group, being composed of a ring of six carbonatoms and six associated hydrogen atoms, leaving three pairs of unsaturated carbonbonds between members of the ring. A constituent worthy of note is Asphaltenes. This is a heavy fraction; a tar-like stickydeposit often seen as a residue when gas is removed in a separator Oil and gas sit above water within the reservoir. Water will be produced together with oilor gas. The quantity of water produced will increase with production rates, and alsolater in life as the water level rises within the formation.

Fig.5.9-Produced water


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Fluid properties are of relevance to the pipeline designer. They are:Phase fractionsDensityViscosity

CompressibilityHeat capacityThermal conductivity

The phase diagram illustrates how the flow properties change with pressure andtemperature. The point marked C is the critical point. The corresponding pressure andtemperature are termed critical pressure and critical temperature.The fluid phase above the cricondenbar is termed dense phase. In the dense phase the

fluid remains as a single phase fluid provided the pressure does not fall below thecricondenbar. In this state, changes in temperature alone will not change the phase.The fluid in dense phase is neither liquid nor gas but the density of the dense phase fluidcan vary between the two. Both liquid and gas flow equations may be used for densephase. In a dense phase line, the drop in pressure along the line can cause the flow tobecome two-phase.Flow characteristics of fluids are dependent on density and viscosity. Density of oil issometimes defined by API gravity.The definition of API gravity is shown above: S (60/60) is the specific gravity of the oil at600F compared to water at 600F. Oils with low densities, and hence low specificgravities, have high API gravities.


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Fig.5.10-Phase diagram


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Behaviour depends on density and viscosity. Density will sometimes be defined byspecific gravity or API gravity.

5.1315.141

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S

API gravity

Viscosity is the ratio of shearing stress (force per unit area) to shearing rate (strain rateor velocity gradient of flow). Viscosity may be defined by dynamic (absolute) viscosity or kinematic viscosity. Kinematic viscosity is used for convenience and is simply dynamicviscosity divided by density.Fluids where viscosity is constant at a given temperature are called Newtonian Fluids.

Water and liquid hydrocarbons are Newtonian. Fluids for which viscosity is a function of shear rate are called Non-Newtonian Fluids. A fluid where the viscosity decreases withincreased shear rate is known as shear thinning. Similarly, if viscosity increases withincreased shear rate, it is known as shear thickening.Oil/water emulsions are usually very viscous and usually more viscous than the originaloil. The appearance is often referred to as “chocolate mousse”.The specification of pipe diameter should be based on normal conditions although upsetconditions should be considered; e.g. start-up.

For gas flow, gas compressibility also needs to be known as this controls therelationship between pressure, temperature and density.

mzRT PV


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Where P is the pressure; V is the volume; T is the temperature; R is the universal gasconstantm is the number of moles of the gas z is the average gas compressibilityThere are many references that provide generalised compressibility graphs such as onthe followings.The reduced pressure and temperature are the ratio of actual pressure and temperatureto the critical pressure and temperature.In the following diagram TR = T/Tcritical and PR= P/Pcritical

Fig.5.12-Generalized compressibility chart


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The composition of the fluid being pumped through the pipeline needs to be analysed sothat the properties of the fluid can be predicted. The pipeline design is dependant onthe fluid properties in three respects:1. Density and viscosity of the fluid affect the flowrate and so influence the diameter sizing2. The thermal properties affect the heat loss and so influence the thermal design3. The chemicals within the fluid composition react with the steel pipe wall causingcorrosion and so influence the required corrosion protection on the internal pipe wall. An additional property is required if considering the flow behaviour of gases. Gases arecompressible and therefore a compressibility factor of the fluid needs to be determinedFlow may be single phase (i.e. just liquid or just gas) or multi-phase (i.e. both liquid and

gas flowing in the same pipeline).

Fig.5.13-Flow regimes


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The diagram above shows a schematic of a typical subsea development. Following theoil from the reservoir, where it is single phase, it passes up the well. As the pressure

reduces on the way up, the lighter hydrocarbons vaporise to give multi- phase flow. Thispasses through the wellhead and Xmas tree (which is essentially a block of valves) andpasses into the horizontal flowline. It passes through the flowline in two phase flow backto the production facility. It then passes up the riser and into the separator.The prime function of the production facility is to separate the oil and gas into singlephases, and put these into export pipelines where they can be pumped to shore or to atanker.

The following pages show how pipeline diameter is determined for the different flowregimes.The change in phase composition within the well and flowline can be illustrated by theline of pressure and temperature on the phase diagram above. As the temperature andpressure drop as the fluids flow along the flowline, so the phase composition changes.There are two types of flow regime relevant to the movement of hydrocarbons, these

being single and two phase flow.Hydrocarbons located in the field will be under high pressures which keep thehydrocarbon in the liquid form. However, as the hydrocarbons are drawn to the surface,the reduction in pressure may cause the lighter hydrocarbons to vaporise, resulting intwo-phase flow.


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Hydrocarbons located in the field will be under high pressures which keep thehydrocarbon in the liquid form. However, as the hydrocarbons are drawn to the surface,the reduction in pressure may cause the lighter hydrocarbons to vaporise, resulting intwo-phase flow.

Phase diagrams are used to illustrate the relationship between the phase composition,the pressure and the temperature of the fluidThe flow in pipelines are characterised by:Bernoull’s equation

constant2

2

H g

V

g

p

Bernoulli’s equation defines the energy balance for flow problems.Where p is the fluid pressure; ρ is the density; g is the gravity constant; V is the flowvelocity; H is the head.In practice energy is dissipated through friction losses.Modified Bernoulli equation

constant2

2

f h H g V

g p

(5.4)


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Where hf is head loss due to friction.For pipelines, energy can be added by pumps or compressors and is dissipated byfriction and heat flow. In flow analyses, the heat loss is ignored and the Bernoulliequation can be modified to include the frictional energy loss.Pressure drop in the pipeline is given by the Darcy equation. This equation works for

any combinations of compatible units:

D

L

2

vf P

2

Where f - friction factor related to internal roughness and Reynolds Number. ρ is density;v is flow velocity; L is pipeline length; D is pipeline internal diameter.

The friction factor is dependent on Reynolds number. Reynolds number is defined as(velocity x diameter)/(kinematic viscosity):

DV

D

V

V

2

Re

The friction factor, f, can be derived from the Moody diagram shown. This plots frictionfactor against Reynolds number for a range of surface roughnesses. It should be notedthat f is nearly constant in the turbulent region.


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Fig.5.14-Moody’s diagram


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Alternatively, there is a range of formulae available for the calculation of friction factor,such as the Colebrook-White equation given above. Equations for laminar and turbulentflow are shown.Laminar flow Re2000

f D

k

f Re

7.182log274.1

110

Re = Reynolds number (defined previously); k = roughness (mm) (in) D = diameter (mm) (in) A note of caution on Moody diagrams and friction factors: there are two differentsystems in use. The above is the US system which is used throughout the oil and gasindustry. The other system has a friction factor of f’ = 0.25f, and is shown in sometextbooks.Typical roughness values are defined. The clean steel value shown is conservative andactual values could be as low as 0.02mm (0.787mil). As pipe manufacturing processesimprove, k drops. Sometimes roughness is defined as relative roughness, which issimply the ratio k/D.


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Alternatively, there is a range of formulae available for the calculation of friction factor,For gas transmission lines - e.g. NTS and CATS, the pipe is shot-blasted which givestypical roughness values of 0.045mm (1.77mil). If a pipe is internally coated with FBEthe surface roughness improves dramatically, with the value for k dropping down to0.005mm (0.197mil)

Fig.5.15-Pipe roughness


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Consider the liquid flow governed by equation (5.4) and characterised by the fact thatvelocity does not change along line -therefore ignore and the head due to elevation isimportant due to higher densityThe velocity term does not change and can therefore be ignored in single phase liquidflow. The changes in elevation can have a significant effect and therefore input pressure

may be governed by elevation of the terrain over which the pipeline passes, and notnecessarily by the required delivery pressure.

Fig.5.16-Conservation of energy


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Having sized the pipeline for maximum flowrate, we need to consider the secondaryissues, and if necessary adjust our design. We need to consider the flow velocity. Athigh flowrates, solids or water droplets can start to cause erosion of the pipeline walls,particularly at bends. API RP 14E gives the above formula for the velocity at whicherosion may start to occur. Normal practice would be to ensure that this velocity is not

exceeded.The units are metric, with velocity in m/s (ft/s) and density in kg/m3 (lb/ft3).Erosional velocity is :

122eV

Crudes containing large chain paraffins are called waxy crudes. They:Contains paraffins with carbon number > 30

Dissolved at higher temperaturesCrystallisation occurs as temperature dropsCloud point - wax crystals first formPour point - wax matrix formedNon-Newtonian viscosity behaviour Care when mixing - mixture of two cool waxy crudes can raise the pour point

Wax deposition can significantly reduce oil throughput in a pipeline. Options to considerare:Oversizing the line to allow for a build-up of waxInsulating the line to keep the temperature upSpecifying a pigging regime to control wax build-upInjection of a wax suppressant


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In shut-down conditions, the wax can deposit in a gel like matrix across the pipe boreentrapping the liquid oil within it. Under these conditions, a significant pressuredifferential may be necessary across the wax gel plug in order to shear and break-up thematrix.The most significant difference between liquids and gas pipelines is the compressibility

of the gas. Whilst this introduces certain operational problems, it also adds additionaloperational flexibility. The pipeline will store gas and supply and demand rates cantherefore differ to some extent.The analysis of gas flow is complicated by the changing properties of the gas. Velocityand density change as the gas flows down the line. If we again consider the energyconservation equation, no terms within the equation remain constant for gas flow.The energy balance is illustrated above. The effects of terrain are much less significantfor gas flow because of the relatively low density.The frictional head loss (hf ) can be calculated using the same approach as for oil.However, empirical formulae, incorporating the velocity component and compressibility,have been derived and are often used.Empirical Equations for Gas Flow are:Weymouth (high Reynolds numbers

667.2

5.02

2

2

15.433 DGTLZ

P P

P

T Q

stp

stp


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Fig.5.17-Gas flow

Fig.5.18-Conservation of energy

in gas flow


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Panhandle (longer lines)

6182.2

5392.0

8539.0

2

2

2

1

0788.1

7.4335 DTLZ G

P P

P

T Q

stp

stp

The Weymouth equation assumes that the friction factor only depends on the pipelinediameter. It is used extensively for short lines within a plant where gas velocities will behigher. For longer gas pipelines with slower flow, the friction factor depends on bothdiameter and flow rate, and in these cases the Panhandle equation is better.Because of the empirical nature of these formulae it is necessary to ensure correct unitsare used, i.e. Imperial:Q is the flowrate (standard cubic feet per day) ; Tstp is standard temperature (0R); Pstp is

standard pressure (psia)P1 is inlet pressure (psia) ; P2 is outlet pressure (psia); G is gas specific gravity (air = 1)T is average gas temperature; L is line length (miles); Z is average gas compressibility;D is inside diameter (in).Compressibility Z is selected for average pressure

21

21

213

2

P P

P P

P P P avg


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As mentioned previously, the compressibility Z is derived from published tables or charts.Compressibility charts reference critical pressure and temperature. These are publishedfor individual components. The main gas constituents are shown in the following.Combined Tc and Pc for a mixture can be determined by summation of molar

proportions of components.

Fig.5.19-Compressibility factor


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Critical pressure and temperature can be determined for mixes by summing themolecular proportions multiplied by the individual component properties

Fig.5.20- Critical pressure and temperature

Wellstream fluids are usually two-phase or multi-phase. This type of flow is thereforemost commonly experienced in in-field flowlines.Wellstream fluids are typically a mixture of gas, oil and water. Flowlines and pipelinesfrom minimum facility installations will typically be multiphase flow. They are:Mixture of oil, gas and water Typically wellstreamTie-backs of subsea wells or minimum facility platformsThe wellstream fluids are a mixture of different hydrocarbons, each having different

boiling temperatures. Therefore, there will be a mixture of gaseous and liquidhydrocarbons in the flow. As temperature and pressure change, the gas and liquidcontent will change.Two-phase flow characteristics are dependent on the flow rate and the proportions of gas and oil.


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Stratified flow is characterised by slow moving liquid in the lower part of the pipe withfaster moving gas flowing above. Water drop out at the bottom of the pipe can causetram-line corrosion.Slug flow is characterised by individual slugs of liquid separated by gas. The slugs willtend to cause vibrations at any change in the flow direction.

In faster, predominantly liquid flow, the gas is carried as bubbles within the liquid. At veryhigh flows, the liquid is displaced out to the pipe wall and carried as mist droplets in thegas.

Fig.5.21-Types of two phase flow


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The localised gas and liquid velocities are dependent on the overall flowrate, thepressure and the temperature.The seabed terrain affects the flow regime in a number of ways.In stratified flow, liquid may tend to hold up at low points in the line. This build up willcontinue until it creates sufficient pressure drop for it to begin moving as a slug. The

seabed terrain will therefore contribute to the onset of slug flow. The terrain will alsoaffect the pressure drop along the line. At the bottom of a depression or a hill, the liquidcomponent will collect. It will be carried up the side of the hill as liquid slugs and willtherefore experience a loss of pressure as the head increases. The liquid flows downthe other side of the hill in stratified flow, and therefore reduction in head is notconverted back to pressure, but to velocity instead.

Fig.5.22-Flow maps


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Multi-phase flow analysis requires the use of specialised software.

Steady state methods using correlations to predict pipeline pressure drop, liquid hold upand thermal response provide a simple, and often effective, tool for pipeline design.There are a large number of alternative flow correlations that can be used. e.g. for pressure drop/hold-up in vertical and horizontal flow, PIPESIM uses a default correlationby Beggs and Brill.Transient simulations bring an improved understanding of the behaviour of multiphaseflow in pipelines. Many of the problems associated with the design and operation of

multiphase pipelines are transient in nature:SluggingStart-up / shutdownProduction rate changes

Fig.5.23-Two phase flow regime


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In the absence of transient simulation, these issues are addressed throughassumptions, often conservative by necessity, based on the results of the steady statemodelling. This often leads to over-specification and increased cost.

The steady state example above shows a temperature profile along a pipeline. At 6km(3.7 miles) and 20km(12.4 miles) there are pipeline tees where new wells are tied-in. The analysis is run for four different wellhead temperatures. At 6km (3.7 miles), the incoming flow is hotter than the pipeline flow. This results in thecommingled flow downstream of the tee being hotter. At 20km (12.4 miles), the incoming flow from the well is cooler than the pipeline (longer

step out). This results in the commingled flow being cooler downstream of the tee.The flow regime may change through the pipeline life as the flow rates and compositionschange. In particular, slugging flow may develop. There are a number of ways of dealing with turn-down:The installation of multiple flowlines designed for the high start of life flow rates, meanthat fewer lines can be used later in life to maintain sufficient velocities.Gas lift can be used both downhole and at the base of risers to increase the flowvelocity and to reduce the overall density so that slug size is reduced.Downhole pumps will maintain a high flow rate.The liquid and gas can be separated subsea and transported through separate single-phase lines.Gas or water injection to maintain the well pressure


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Ihe flow regime can introduce a range of problems to pipeline operation.Slug flow is particularly problematic and can induce vibrations and fatigue at bends. Slugcatchers are often installed in the process system to remove slugs of liquidfrom the pipeline before the separator, otherwise the separator and other process plantcan become flooded. A typical slug catcher is shown above.It is essential to control the size of slugs within the pipeline. As corrosion inhibitor is carried in the liquid phase, we may not get adequate protectionin stratified flow. Water drop out in stratified flow can cause localised corrosion. Thewater can be highly acidic, leading to rapid corrosion.Hydrates are a particular problem in multi-phase flow and wet gas flow where water ispresent. They are formed under conditions of low temperature and high pressure.

A hydrate plug can block the line. This presents both an operational and a safetyproblem. The pressure differential across that plug will increase. It may then shift athigh pressure and travel along the line at high velocity. It can therefore cause damagewhen it reaches a bend or some equipment.Control of hydrate formation is by control of the operating pressure and temperature of the pipeline, and by injection of a hydrate inhibitor.


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Fig.5.24-Implications for thermal design


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5.4 Thermal design

Having calculated the required pressure and diameter based on the above flowequations, it is important that the pipeline is thick enough to contain this designpressure. The basic formula shown in many pipeline codes, relating nominal wallthickness to design pressure for a straight section of steel pipe, is given in Fig.

2.2, where t is the nominal wall thickness, P is the design pressure (N/mm2Þ, D is the diameter (mm), S is the specified minimum yield strength (SMYS),(N/mm2 , F is the design factor, E is the joint factor and T is the temperature deratingfactor.Codes such as IGE/TD/1, PD 8010 , B31.4 and B31.8 for transmission pipelines usethis approach in calculating nominal wall thickness. When considering wall thickness

for offshore pipelines, the pipe must be thick enough to prevent hydrostaticcollapse under external pressure but also contain the internal pressure.There are several reasons why the pipeline temperature can be important.The flow can be heavily dependent on the contents temperature and there are threemain effects. In oil lines wax may start to form if the temperature drops below a criticalpoint. The wax will deposit on the pipe walls and restrict the flow. In gas lines, hydratesmay start to form, with a similar effect. Finally, the fluid viscosity will change with

temperature, and this will have an effect on the pressure drop in the line. For liquids,viscosity will decrease with increasing temperature while for gases the reverse is true.High temperatures can give problems for the pipeline. The pipe will want to expand andthis can give rise to upheaval or lateral buckling. At elevated temperatures, the strengthof the pipeline may be reduced. Finally, polymer coating systems have temperaturelimitations.


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The two main conditions that need consideration are given above. The producttemperature will fall as it flows along the pipeline due to conduction of heat through thepipe to the surroundings. The temperature profile of the pipeline can be calculated for the steady-state flow conditions, and so the arrival temperature of the contents at the far end of the line may be determined.If the steady flow conditions are interrupted, for example to do maintenance work, thenthe contents will cool down. The temperature of the contents as a function of time mustbe determined, with the aim of keeping the temperature at an acceptable level.

Fig.5.24-Need for thermal analysis


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The image above shows the effect of severe wax deposition in a pipe section.Wax or hydrate formations can be dealt with in different ways:Regularly sweep the line with pigs to prevent build-ups Avoid shut-in conditions where plugs may form (e.g. flush the line before shut-in)

Either batch or continuously inject chemicals into the line that suppress the tendency of the fluid to form waxes or hydrates.Design the pipeline to meet the thermal requirements that avoid the conditions that willform wax or hydrates. Combinations of these techniques are often used.Hydrates are compounds of gas and water that look very much like water ice. The gasmolecules are trapped within a cage of water molecules. Hydrates form under

conditions of low temperature and high pressure, so they can be broken down byreducing the pressure in the pipeline.Pipeline design needs to account for influence of thermal effects on the flow of productthrough the pipeline. With low temperatures there are implications on the product flow. At high temperatures there are implications for the pipe integrity.There are also requirements imposed on the pipeline system, where minimum arrivaltemperatures and maximum pipe wall temperatures may be specified during steady-

state flow. During a shut-in situation, a maximum cool-down rate may be specified toprevent the product reaching a temperature where wax or hydrates may form during theshut-in situation.The thermal behavior equations below assume steady state conditions:-Heat conduction in 1D


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Total heat flow

dx

dT kAQ x

•Per unit area

12

12

12 T T h x x

T T k

A

Qq

x x

x

x

x

Where Qx is the total heat flow; A is the area of the body perpendicular to the heat flowdirection; k is the thermal conductivity of the material; T is the temperature; x is the

linear distance through the material in the direction of heat flow h is the heat transfer coefficient.For most thermal analyses of pipelines, axial conduction of heat along the pipeline canbe ignored and therefore the analysis becomes one of simple radial heat flow.The below equations show the radial heat flow and the heat transfer coefficient. Inthese equations r 1 and r 2 represent the inner and outer radii of the layer being

considered.Pipelines are often multi-layer systems, which include the steel pipe wall, anti- corrosioncoatings, insulation coating layers and concrete weight coating. With multi-layer systems, an overall heat transfer coefficient needs to be calculated as shown in thenext.Radial heat conduction


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Total heat flow per unit length of pipeline

1

2

12

ln

2

r

r

T T k Qr

•Heat transfer coefficient

1

2ln

2

r

r

k h r r

Overall Heat Transfer Coefficient (OHTC)•Requires reference diameter

ref

tot

rnr r

tot

D

hOHTC U

hhhh

1

21

1...

11


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The plot shows a sample radial thermal profile through the pipe and insulation. Note thatas steel is an effective conductor, pipe temperature is equal to content temperature.The overall heat transfer is determined by combining the individual layer heat transfer coefficients as shown.OHTC stands for Overall Heat Transfer Coefficient. It gives a measure of theperformance of the overall coating system and allows comparison between different

systems. Units of OHTC are W m-2 K-1 (BTU/hr/ft2/°F), hence OHTC requires areference surface. Most common is to reference the OHTC to the ID or OD of the steelpipe.For transient conduction problems, the rate of change of temperature depends not onlyon the thermal conductivity of the material, but its density and specific heat capacity.The differential equations can be solved numerically.

Fig.5.25-Radial thermal profile

through the pipeand insulation


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Transient conduction in 1D:

2

2

x

T

c

k

t

T

p

Transient conduction in cylindrical system:

t

T

r x

T

c

k

t

T

p

12

2

In order to calculate the thermal properties of the system, then, three physical propertiesare needed for each material. The conductivity is needed for any thermal analysis,

either steady-state or transient. For transient analyses, the density and specific heatcapacity are also needed. The product of density and heat capacity is sometimesknown as the thermal inertia. Remember that these properties are themselvestemperature-dependent, and so must be measured in the temperature range of interest.The fundamental assumption in the thermal analysis of pipelines is that the heat lossoccurs primarily in a radial direction. In order to assess the performance of any multi-layer insulation coating system, we need to estimate the Overall Heat Transfer

Coefficient (OHTC) for the combined coating system.The thermal analysis of pipeline systems can be undertaken in two ways: Steady-stateanalysis, which requires only the material property of the thermal conductivity.Transient analysis, which requires the thermal conductivity property and also the densityand specific heat capacity properties of the system materials.


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Thermal profile analysis is the determination of the temperature profile along the pipelineas the contents are cooled by conduction of heat through the pipe to the surroundings. A pipeline resting on the seabed is normally assumed to be fully exposed. Whereoperational pipelines are inadequately insulated, trenching and back-filling may improveor solve the problem. It is necessary to take into account changes in burial levels over

field life, and hence changes in insulation values.The increase in insulation for the pipeline under partial burial conditions is not great.Heat will flow circumferentially through the steel to the section of exposure. Evenexposure of just the crown of the pipeline results in efficient heat transfer to thesurroundings, due to the high thermal conductivity of the steel.

Fig.5.26-External heal loss


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Buried pipe heat transfer:

D

ba

k h soil soil

2cosh

2

Pipeline burial occurs due to:Deliberate placement of rock, grit or seabed material on the pipe for stability or protection requirementsCollapse of sides or gradual infill due to sediment mobility of a trenched pipelinePropagation of sandwaves across the pipelineGeneral embedment of the pipeline into the seabed due to mobility of the seabed or movement of the pipelineSediment flow at river mouths/deltasWhilst seabed soil can be a good insulator, porous burial media, such as rock dump,may give little in the way of additional insulation since water can flow through the spacesbetween the rocks and transfer heat to the surroundings.Where a pipeline design has assumed that it will be exposed on the seabed, then burialmay cause problems. The lower heat loss can give rise to upheaval buckling, increased

corrosion and overheating of the coating.The density, thermal conductivity and specific heat of the fluid are pressure andtemperature dependent. Later in field life, the water cut tends to increase. Water has a higher density and specific heat, hence the temperature drop along the pipelinetends to decrease (although this effect tends to be partly offset by lower flow rates dueto dropping reservoir pressure) (GOR = Gas Oil Ratio).


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Exponential decay along pipeline is:

Fig.5.27-Thermal profile

pcont mass

tot

ambinambc flow

xhT T T xT exp)(

Thermal profile analysis is the determination of the temperature profile along the pipelineas the contents are cooled by conduction of heat through the pipe to thesea/surroundings.

The basic equation of temperature along a section of pipeline is shown above. Thisassumes steady state flow conditions, constant fluid properties, uniform insulation anduniform ambient temperature along the pipeline section.


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In this equation,T(x) is the contents temperature at distance x along the pipeline; Tamb is the ambientseawater temperature; Tin is the flowing inlet temperature flowmass is the contents massflow rate; Cpcont is the contents specific heat capacity

The key parameter that determines the onset of wax and hydrate problems is thetemperature of the fluid, and it is the requirement to avoid their formations thatdetermines the fluid arrival temperature.Most pipelines require thermal profile analysis in a number of sections, due to changesin the conditions:riser sections with different insulation systems or seawater temperaturesspoolpiecessections of the line which are buried or may become buriedintermediate facilities such as valves or teeschanges in contents thermal properties due to flow conditions, pressure, temperature or density effects(all of which are inter-related)The analysis should consider each section sequentially, with inlet properties determined

by the outlet conditions from the preceding section.Process simulation software such as PIPESIM accepts heat transfer coefficientsdetermined for each insulation system, enabling the concurrent modelling of the effectsof content changes and external condition changes on contents temperature.


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Simple pipeline configurations can readily be analysed using spreadsheets. Morecomplex systems, such as multi-core umbilicals or service lines are better suited toanalysis with FE. Operational considerations often result in some cores operating withothers shut-in. Complexity can also arise due to fluid-filled interstitial cavities, that arepotentially susceptible to convective heat transfer. Analytical approximations for

convection are available for flat plates or tubes, which provide qualified estimates. Thehighest integrity solution is to model the cavities using Computational Fluid Dynamics(CFD).Options to assist or avoid thermal insulation include electric heating or circulating a hotfluid through spare cores. These may also need to be modelled.

Fig.5.28-FEA/CFD numeric analysis


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Analysis techniques are required to determine the thermal profile along the length of the

pipeline. The radial heat loss by convection to the surrounding water will result in anexponential decrease in temperature along the pipeline length. The insulation systemneeds to be designed to ensure that the minimum required arrival temperature is met.For complex problems, such as umbilicals and bundles, it may be necessary to utilisecomputerised approximation techniques such as Finite Element (FE) analysis toestimate the radial heat loss.We should note that when determining the thermal profile we need to consider the

change in the thermal properties of the contents over time as the Gas Oil Ratio andwater cut of the field changes through its life.Thermal cooldown analysis is the evaluation of the contents temperature as a functionof time, following the shut-in of the line. Cooldown analysis tends to be either:to find the final temperature of the contents after a defined shut-in duration (typically 4 to20 hours)

to find the time taken for the contents to reach the temperature when wax or hydratesmay start to formto find the OHTC required to meet a given minimum contents temperature following agiven shut-in durationCooldown analysis is normally performed at the outlet from the pipeline, as this gives thecoolest contents from the thermal profile analysis.


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Temperature after time t given approximately by:

Fig.5.29-Cooldown during shut-in

pii

i

tot

ambinitial ambcmass

t hT T T t T exp)(

The basic equation of temperature at a point in a shut-in pipeline versus time is shownabove. This assumes constant fluid properties, uniform initial system temperature,constant ambient temperature and also that the contents and steel pipe are the onlylayers that contribute to the thermal inertia (i.e. thin coatings), while other layers

contribute to the insulation.In this equation:T(t) is the contents temperature after time t ; Tamb is the ambient seawater temperature;Tinitial is the contents initial temperature; massi is the mass (per unit length) of the pipecontents, steel etcCpi is the specific heat capacity of the pipe contents, steel etc


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For complex umbilicals, interstitial cavities may be flooded with seawater, which has ahigh heat capacity. This increases the thermal inertia and may usefully contribute tomaintaining the contents temperature during shut-in. For complex systems such as thatillustrated, finite element analysis provides the simplest method of analysis.The simplified method described on the previous slide becomes inaccurate when thepipeline is coated with a thick high density coating. The method assumes that thethermal inertia is concentrated at the centre of the system at constant temperature andthat the coating simply provides insulation. With thick coatings, the coating will alsocontribute to the thermal inertia, although it is not at constant temperature. Again, FEA isthe simplest method for analysis of thick coating systems.

Fig.5.30-Cool down-complex systems


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Insulation design is primarily determining the pipeline coating system required to meetcompromises of:coating costsmaterial performance under thermal and environmental loading during service

the effectiveness of the system in meeting required insulation performanceThe primary insulation materials used are polymeric coatings. The strength of thepolymers varies inversely with temperature. These polymers are frequently mixed withplastic or glass microspheres (small spherical beads filled with gas) to enhanceinsulation properties. Plastic beads are more common and lower cost. Glass beadshave greater strength and therefore depth capability, but have a potential problem of breakage during mixing with the polymer and pumping.

Foams are made by blowing the polymers with CO2, N2 or water. The density of thefoam can be controlled and this determines the “wall thickness” of the foam bubbles.The thermal conductivity of foams is proportional to the density:high density = high conductivity, low insulation performanceThe higher the foam density, the greater the strength:high density = higher temperature or depthOther materials include Fly ash and EPDM rubber.The cavities in pipe-in-pipe systems may be filled with microspheres, inert gas (N2) or evacuated. All these materials have an upper service temperature limit.The extrusion process involves a continuous wrapping process of an extruded strip of the polymeric material onto a rotating pipe joint. This process is typically used for solid,syntactic or foamed polypropylene


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This process can apply both thin and thick layers by using multiple extrusion heads.Casting is typically used for polyurethane coatings and field joints.Pouring is a continuous process that applies a bead of liquid polymer to the rotating pipe joint. The process can be used for foams and syntactics as well as solids. The polymer cures rapidly and by use of multiple heads, a multi-layer coating system can be rapidly

applied.

Fig.5.31-Pipe coating

The foams have lower strength and greater elasticity than steel. Analysis of insulation


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g g y ysystems can be undertaken by breaking the coating down into concentric virtual sub-layers, over which approximately constant material properties are evaluated. The radialcompression by hydrostatic pressure results in a reduced diameter, which causescircumferential compression of the foam. The radial strain on inner layers enhances thiseffect. The radial strain and circumferential compression propagate in through thecoating. Inner layers are less compressedthan outer layers, and therefore have lower thermal conductivity. Accurate analysis canbe done using FEA or programs such as Mathcad.Polymer strengths are reduced at higher temperatures, which means that the depthlimits will be correspondingly lower.Thermoplastic materials are susceptible to creep, which manifests itself as a time

dependent strain, even under a constant load condition. Creep of pipeline insulationsystems results in thinner, more dense coatings. Therefore, the coatings have higher thermal conductivities and reduce the performance of the insulation system.In foam systems, creep is caused by the gradual deformation and collapse of the gas-filled cells or cavities. Flattening of the cells results in a loss of the mechanical strengthof the cell, hence the creep successively causes the crushing of most of the cells.Beyond a certain level, sufficient strength is lost and the creep rate increases rapidly as

a Phase 2 creep. Insulation systems should be designed to avoid entering this phase of creep. As a rule of thumb, strain should be limited to not more than 5%.The plots above show an example of the change on OHTC due to creep over the life of the coating, and a typical three stage creep rate for an insulation coating.

Almost all polymers allow the diffusion of fluids at variable often very low rates Most


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Almost all polymers allow the diffusion of fluids at variable, often very low, rates. Mostcoating systems are therefore susceptible to water ingress or permeation.Pipe-in-pipe systems are normally designed to avoid water ingress, and may includescavengers to “mop-up” any residual moisture.Ingress is time dependent and may take a significant proportion of the design life to

reach equilibrium. The water can permeate along cell boundaries in syntactics andfoams. It can also fill foam cavities or syntactic microspheres.The water has a much higher thermal conductivity than the polymer insulation or gasfilled cavities. Hence 5% water content (a high value) significantly affects the materialperformance. The resulting thermal conductivity of the material is analysed by addingthe thermal conductivity of water, multiplied by the absorption fraction. It is not just asimple weighted balance between the basic material and water content, since theabsorption of water does not reduce the mass of parent material present, hence doesnot reduce its conductivity.

Fig.5.32-Creep


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Fig.5.33-Water absorbtion

Fick’s law for water absorbtion is:


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Fick s law for water absorbtion is:

x

c D J

Water diffuses through polymers, and the rate of diffusion increases with bothtemperature and pressure. Higher temperatures also cause an increase in solubility, ie

more water will be absorbed at higher temperatures. Diffusion is modelled using Fick’slaw, as above, where:J = flux of water concentration; D = diffusion coefficient; c = mass concentration of water; x = distanceThe example above shows the results of a comparison between a predictive numericalanalysis (e.g. FEA) with experimental testing. The results show that only very low

absorption takes place in the inner layers of the insulation. The analysis shows thesteady state water content after many years.The competing effects are the diffusion of the water in the direction of the partialpressure (concentration) gradient versus the diffusion of the water in the direction of thetemperature gradient. The net effect, as shown above, is that little water is absorbedinto the coating except in the outer layer. A vicious cycle exists in the performance of insulation coatings:

with creep and hydrostatic compression causing increased thermal conductivitywhich increases the temperature of the coating, resulting in increased creep andcompression


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This consideration makes the evaluation of insulation coating systems complex.However, analytical approximations with Mathcad or Excel are possible alternatives toFEA. Coating system suppliers are worth consulting for recommending the correctsystem.

Most insulation requirements tend to be in the range between 2 and 5 W/m²K (0.35 and0.88 BTU/hr/ft²/0F). Typical pipe coating systems for this insulation duty are shownabove. These would be applied over a corrosion protection coating comprising: A 0.5 mm (0.02in) layer of fusion bonded epoxy (FBE), which gives the anti- corrosionprotection An adhesive layer to give bonding between FBE and insulation layer Note that the above depth and temperature limitations may not both be attainable

together. For example it may be possible to get a polyurethane foam to either 150 m or 1000C, but not both at the same time.Some of the limitations in the above can be overcome by using composite systems. For example, by applying a layer of solid polypropylene between the pipe and a layer of polypropylene foam, the temperature in the foam is reduced and the system can beused up to temperatures of 1400C, the upper limit for solid PP.

A typical pipe coating system for this insulation duty is a pipe-in-pipe system using PUFor loose packed microspheres.


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Fig.5.34-Rules of thumb for medium insulation

A typical pipe coating system for this insulation duty is a pipe in pipe system using PUF


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A typical pipe coating system for this insulation duty is a pipe-in-pipe system using PUFor loose packed microspheres.For the lowest U values in deep water, it is currently necessary to use pipe-in-pipesystems. Developments in syntactic coatings are likely to produce coatings capable of U values down to less than 1 W/m2K.

Fig.5.35-Thermal insulation capability guide


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Field joints are areas where greater heat loss may occur. If the field joint insulation isnot as good as that on the main pipe body then additional heat loss will occur by heatflowing axially towards the field joint and then radially through the poorer insulation. Theassumption made previously that the heat flow was only radial is therefore not valid anda more sophisticated analysis is needed. Accurate analysis can be done using FEA of acomplete pipe joint.Field joints are therefore a potential location where axial heat conduction may result in:lowering of the OHTC of the pipe systemunder-prediction of the OHTC using 2D analytical or FE evaluationField joint design involves a compromise:

ideally as good an OHTC as the main coating systemas rapid a field jointing operation as possibleThe design of thermal insulation coating systems requires a compromise between the

cost of the materials, the performance of the materials under the applied environmentalloads during the design life and the effectiveness of the coating system at meeting therequirements.The majority of the pipe length can have the thermal coating applied onshore in a

controlled environment. However, the ends of the pipe must remain uncoated so thatthe pipe joints can be welded together on the lay vessel. Therefore, specialist field jointcoatings must be designed that can be applied on the vessel after the joint make-up.The integrity of these field joints must be ensured prior to pipe installation.

The current trend is to exploit reservoirs with harsher production characteristics


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The current trend is to exploit reservoirs with harsher production characteristics,including high temperature, high pressure fields. These fields also have a tendency tocontain aggressive fluids, which can be highly corrosive. They may also have severewax or hydrate problems. There are also trends towards using a larger number of pipelines over longer distances in order to minimise topsides processing. Hence

unprocessed well fluids are being transported greater distances. The performancerequirements and use of insulation systems on subsea pipelines is therefore increasing.5.8 Stability

If a pipeline is not stable then it will move under the actions of waves and currents. Thisis a problem since the movement will cause bending stresses in the pipeline, which maythen cause the pipe to fatigue and fail. Alternatively, it may cause damage to pipelinecoatings, such as cracking of concrete.Submarine pipeline stability is governed by the fundamental balance of forces betweenloads and resistances.This approach to stability design of pipelines was incorporated into DNV’s Rules for Submarine Pipeline Systems issued in 1976 and was the basis of design for manypipelines around the world.It was known from experimental research that the hydrodynamic loads on a pipeline

could be very much higher than in the DNV ’76 model. In 1981, DNV’s revised rulesincorporated a much more realistic hydrodynamic model.

This created an anomaly - the new approach suggested many of the existing pipelines


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This created an anomaly the new approach suggested many of the existing pipelinesdesigned to DNV ’76 were unstable. However, annual surveys showed no evidence of awide-spread problem. The explanation lay in the lateral resistance of a pipeline tomovement also being very much higher than predicted by the simple model. It wasshown experimentally that during a storm a pipeline undergoes small displacements

under the action of wave forces, gradually digging itself into the seabed. The pipelinetherefore had small soil berms either side, providing increased resistance to movementand greater hydrodynamic shielding. The results of this research were incorporated into AGA’s suite of stability design software, providing a state of the art approach.

Fig.5.59-Pipeline instability

The first pass approach to pipeline stability is a simple force balance model in 2


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p pp p p y pdimensions. It is the basis of the design methodology used in:DNV ’76 + ’81 AGA Level 1 stability software

Fig.5.60-Stability fundamentals


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Vertical forces are:Hydrodynamic liftPipe and contents submerged weight (weight - buoyancy)The pipeline is vertically stable if the submerged weight exceeds the maximum lift force.

Horizontal forces are:Hydrodynamic drag and inertiaLateral resistance to movement due to seabed frictionThe pipeline is horizontally stable if the lateral resistance exceeds the combined dragand lift loads throughout the wave cycle.In this simple approach seabed friction is modelled using coulomb friction.We will look at how information is gained for determining the hydrodynamic forces,

which are dependent on local particle velocities.The field of oceanography plays a large role in subsea pipeline design. Althoughpipeline engineers are not often directly involved in the derivation of environmentaldesign criteria, an appreciation of the issues involved is required to ensure a goodpipeline stability design.Environmental data is recorded using a large variety of instruments:

Global wind data / synoptic chartsSatellite imagery (SAR)Wave rider buoysShip observationsPlatform-mounted measurementsHindcast numerical modelling


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Fig.5.61-Data sources

R d d d t l t t b i li i l d


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Recorded data relevant to subsea pipelines includes:Wave heights and directions: cause hydrodynamic loads on pipesWind speeds: drive sea currentsCurrents: cause hydrodynamic loads on pipesTide heights: affect water depth A large variation exists in the quality and quantity of this data between mature offshoreoil and gas areas (e.g. the North Sea and Gulf of Mexico), and much younger greenfieldareas (e.g. West of Ireland). Outside major oil & gas areas it is common not to have 100years of recorded data. It is also unusual to have data recorded in the exact area of interest.Inherently, pipelines differ from platforms and similar structures in that they traverse the

seabed. Major trunk lines can be hundreds of kilometres long and therefore havechanges in data along the route. Pipelines can therefore be subjected to a considerablerange of oceanographic conditions. Numerical models are used to hindcast or extrapolate conditions from known storms to a sufficient number of locations along thepipeline.-Significant wave height (Hs)Hs= 4.0 √mo (where mo is the variance in the water surface elevation)

Hs≅the average of the highest 1/3 of the waves-Maximum wave height (Hmax)Hmax≅1.86 x HsHmaxis limited by water depth ≅0.78 x d


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Significant Wave Height

Hs has its origins in the analysis of results from plotter data recorders, where a physicalline could be drawn below the highest 1/3 of the waves, then the average of the wave

heights determined. It corresponded to what a trained ship-bourne wave heightobserver would report as the wave height when watching these same waves. Significantwave is the most commonly provided measure of wave height in pipeline engineering.Hs is a fundamental seastate parameter, which is indicative of the energy of a given seastate.Maximum Wave Height

The probability of exceedence for a single wave out of a group is given by the Rayleighdistribution. The typical duration of a design return event or ‘storm’ is normally taken tobe 3 hours. Assuming a typical wave period of 10 s means that about 1000 waves willpass the design location in that time, which by applying a Rayleigh distribution to theexpected extreme value results in the highest wave being about 1.86 times the height of the significant wave.The theoretical limit of wave height for a given water depth is 0.78 times the depth.

When the breaking wave limit is reached, the wave spectra become truncated at thebreaking wave limit. This alters the meaning of Hs and validity of the aboverelationships. This is important when doing stability design using Hs.

This illustrates how significant wave height is determined from the statistical data of


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g gwave height. It shows the probability of a particular wave height occurring. Thecoloured portion of the graph shows the highest third of the waves. Hs is the mean of this area.The other main parameter important in determining wave properties is the period.

Ts and Tmax are the time periods of the significant and maximum waves respectively. Themost commonly recorded data is Tz, the mean zero crossing interval as shown in theplot below

Fig.5.62-Wave height


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Fig.5.63-Wave period

The spectral peak period, Tp, is determined from spectral analysis and is commonly


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used in design. For different JONSWAP peakedness values, conversion curves areprovided in DNV RP E305. As a default RP E305 provides an upper limit of the peak period according to thefollowing relationship:

Tp = √(250 Hs/g)In practice the peak period will depend on fetch and depth limitations as well as durationof the sea-states.

Fig.5.64-Wave kinematics


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Wave Kinematics

Wave kinematics are used to describe the velocities and accelerations of water particlesthat make up the wave. Airy and Stokes wave theories are the simplest, describing the shape of the water/air

interface as a function of time. They both treat waves as a continuous series. Airy wavetheory uses a simple sine function while Stokes extended the description of the seasurface using a 5th order sine series. In the above image, it means that Stokes wavetheory can provide a better approximation to the steeper waves typically encountered inshallower water.Stream function wave theories are better approximations in shallow water. They aremore complex and require numerical solutions.Breaking Waves

Theoretically, waves break when their tips (or crests) move forwards at a higher velocitythan the wave celerity. Breaking waves can be spilling, plunging or surging. Thehydrodynamic loads produced by breaking waves are not well defined, especially lower down in the water column.Water depth classification as ‘deep’, ‘intermediate’ or ‘shallow’ is a relative measure and

depends on the wave period. The ordinate H/g T2 is a measure of wave steepness,which is related to the angle of the face of the wave.The above diagram refers to the conditions at the surface and not the seabed


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Wave particles move in an approximately elliptical path. In deep water, the paths arenearly circular and decay exponentially with depth, so that at a depth of about one half of the wave length there is very little effect due to surface waves. Because of thiscurrents tend to dominate over waves for deepwater developments.In shallow water the paths are elliptical, as shown above. At the seabed, the particlemotion is purely horizontal, with the results that wave induced seabed currents are high,with no bottom boundary layer. More pronounced asymmetry occurs with a netdisplacement of particles in the direction of wave propagation.

Fig.5.64-Wave kinematics

Airy wave theory uses a sine function to represent the surface of the sea. It is thei l t th b t it i li bl i i t d it i id l d


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simplest wave theory, but it is applicable in many circumstances and it is widely used. Airy wave theory involves an iterative solution to find the wavelength. The equationsthen give the horizontal and vertical velocities and accelerations as sinusoidal functionsof horizontal distance x and time t. These sinusoidal variations with x and t are normally

replaced by a single parameter - wave phase angle θ.Because a typical velocity boundary layer does not develop for wave induced seabedcurrents, the normal approach is to determine the design parameters at the top of thepipe (e.g. peak velocity and acceleration) and apply these values to the current over theexposed area of pipe.

Fig.5.66-Airy wave theory

Airy theory transforms wave properties: surface →seabed


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y y p p

2

2 gT

Lo

Need to find: actual wavelength:

L

d L L o

22tanh

L = wavelength ; Lo= ‘deepwater’ wavelength (d/L ≥0.5); g = 9.81 m/s2; T = wave periodx = horizontal distance; t = time; d = water depth.The water particle velocities and acceleration are determined by applying the Airy waveequations. The second term in each of the above equation is the phase angle asdescribed in the followings..The maximum wave induced water particle velocity and water particle acceleration occur ¼ of a cycle out-of-phase.Design codes such as DNV RP E305 provide graphical means of determining velocityand acceleration directly from wave period, wave height and depth information.Note that z is referenced from the mean water level and will be negative when

measured downwards towards the seabed.Equations:

dz


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L = wavelength; H = wave height; T = wave period; z = vertical distance from mean levelx = horizontal distance from crest; t = time shift from crest; d = water depth.The normal area of interest in subsea pipeline engineering is in close proximity to theseabed. The applicability of Airy wave theory is generally better at the seabed thancloser to the surface, which enables it to be used with caution beyond the domaindescribed above. Having established the velocity contributions due to waves we nowneed to consider the effect of steady currents.

Steady currents develop a boundary layer due to the viscous forces in the water and theboundary flow condition of zero flow at the seabed.Seabed currents in design data are frequently given at 5 m above the seabed. Thelocation of the pipeline in the velocity boundary layer lowers the effective velocity seenby the pipe. The approach used is to integrate the velocity over the height of the pipe togive an effective steady current.

T

t

L

x

L

d

L

d z

T

H U W

2cos

2sinh

2cosh

T

t

L

x

L

d

L

d z

T

H

dt

dU a

2sin

2sinh

2cosh2

2

2


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Two approaches to finding the current at the pipe are shown above. The 1/7th power law predicts the current at a height z based on the readings from the current meter (areference velocity Ur at a height zr). Often this is fed into the stability calculation as thecurrent prediction at the level of the top of the pipe.The second formula is an average current over the height of the pipe and is modified totake account of the effect of the seabed roughness z0. The rougher the seabed, the

thicker the boundary layer and the lower the average velocity over the pipe height.

Fig.5.67-Other wave theories


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The loads due to the water particles can be classified into three types: drag, inertia andlift.

Fig.5.68-Currents in boundary layer

Fig.5.69-Hydrodynamic loads

Drag


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Drag is caused by the flow of a viscous fluid past a bluff body. The drag is mainly theresult of the high pressure in front of the pipe and the low pressure region in the wakebehind the pipe. The drag is influenced by the width of the wake and also by the waveaction. The effect of waves is that the wake from the previous 1/2 wave cycle is swept

back over the pipe again.Inertia

Waves produce cyclic loadings on the water particles in the water column. These cyclicloads accelerate and decelerate the water particles in both the horizontal and verticaldirections. Where a body sits within the water flow, it experiences the loads that wouldhave been exerted on the water that would have occupied the volume of the body.Lift

Lift is produced in the same way as flow over an airfoil. The presence of the seabedintroduces an asymmetry between the flow over the top of the pipe and the flowunderneath. This causes slower flow (or no flow) underneath the pipeline (highpressure) and higher velocities over the top (low pressure), resulting in lift.Loads by Morison’s equations:Drag:

2

5.0 DV C F D D •Inertia:

aC D

F M M

4

2

Lift: 25.0 DV C F LL


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L L

Typical pipe on seabed Drag CD= 0.7, Inertia CM = 3.29, Lift CL= 0.9.When the water particle velocities are known the loads on the pipe are calculated using

Morison’s equations, as shown above. The combined wave and current velocities andwave accelerations are input into the above equations where:CD = Drag coefficient of pipe; CM = Inertia coefficient of pipe; CL = Lift coefficient of pipe; ρ = Density of seawater; D = Overall diameter; V = Total current and wavevertical velocity; a = Wave particle acceleration.There is a phase difference of 90° between the maximum water particle velocity andacceleration. The maximum lift and drag occur when the inertia load is zero and the

maximum inertia load occurs when lift is at a minimum.The lift, drag and inertia coefficients are empirically determined, and vary depending onthe flow conditions. The selection of suitable coefficients is discussed in the followingslides.The magnitude of drag and lift forces depends on the flow boundary layer and the levelof turbulence.-Lift and drag coefficients are affected by:The Reynolds Number of the flow: Re = U OD/ν, where ν = kinematic viscosity and isapproximately 9.8 E-7 m2/s (1.06 E-5 ft2/s)The pipe roughness (Bare steel / concrete / marine growth shown above)The Keulegan-Carpenter Number of waves: Kc = Umax T/OD Any embedment of the pipe into the seabed


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Fig.5.70-Hydrodynamic coefficients


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The figure in the above slide illustrates the change in drag coefficient in steady flow for changing Reynolds number and pipe roughness.

The following slide shows changing drag in wave flow.Experimental research performed in the 1980s provides the best source of data isHydrodynamic Forces on Pipelines - Model Tests, Final Report DHI report to the AGAPR-170-185.-Inertia coefficients consists of two components1 + added mass coefficientCm= 1 + Ca

-Value of Ca determined experimentallydepends on height above seabedreduces with distance above the seabedCa ≈2.29 at the seabedCa≈1.1 more than 3 diameters above seabedCm≈3.29 at the seabedThe inertia load results from the differential pressures created by the wave. These

differential pressures accelerate the water particles as the wave passes. The inertialoads on the pipe are increased because the movement of water close to the pipe isrestricted by the presence of the pipe. Consequently additional load from this water istransmitted to the pipe.There are two components:

Consider a stationary cylinder of fluid in the middle of a volume of that fluid. If the


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volume of fluid is accelerated sideways, the cylinder of fluid experiences an accelerationforce in the same direction. This gives an inertia coefficient of 1. The secondcomponent is due to the additional acceleration of fluid particles in order to pass aroundthe cylinder, which results in a coefficient greater than 1. For a pipeline on the seabed, it

gives an inertia force roughly equal to 2.29. These inertia components add up to give3.29. Inertia coefficients vary depending on wave properties.-Seabed resistance - simple approachR = µ (WS-FL)-Submerged weightWS= Self weight - BuoyancySelf weight: (contents, steel, coating, concrete, marine growth)Buoyancy based on overall OD-Seabed frictionCoulomb frictionTypically µ= 0.2 - 0.4 clay, µ= 0.5 - 0.9 sandIn a simple analysis, the seabed frictional resistance can be represented by coulombfriction. The resistance is therefore the friction coefficient multiplied by the vertical

reaction between the pipeline and the seabed. As the lift force fluctuates through thewave cycle, the resistance will fluctuate.Normally pipelines will require some form of stabilisation. Reelable concrete- coatedpipelines are not currently

05. offshore pipelines design-curs5-8ore

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