Offshore Pipeline Hydraulic and Mechanical Analyses

Part I – Pipeline Alternative Hydraulic and Mechanical Analysis

1

CHAPTER 1

Pipeline Hydraulic and

Mechanical Design


2

1 Pipeline Hydraulic and Mechanical Design

1.1 Overview

he target of the hydraulic design is to get the

range of suitable diameters for the pipeline to

satisfy the outlet pressure and flow capacity

requirements, while the mechanical design defines

the minimum acceptable thickness for the pipeline.

This chapter discusses some of the important

concepts of gas flow study. It shows the equations

governing the compressible flow in pipes with brief

explanations for the different terms of each equation

and its physical meaning. We will go through the

diameter selection criteria for gas pipelines. The

mechanical design is based on the DNV 2000 rules

for submarine pipeline systems. Also we will discuss

the Enby Excel sheet which is a professional

mechanical design program based on the DNV 2000.

We are going to show the solution algorithm for both

hydraulic and mechanical design and the flow chart

of V.B.Net program for hydraulic and mechanical

design of gas pipelines. The chapter is concluded

with the results of V.B.Net program for the Egypt-

Cyprus pipeline. The analyses are obtained using

Imperial units.

1.2 Hydraulic Design:

As we mentioned before the target of the hydraulic

analyses is to select a suitable standard diameter that

satisfies the pipeline requirements. The major tool

used in the analysis is the energy equation which

relates the pressures at the start and end of a pipe

with the flow rate passing through the pipe and other

pipe and flow parameters.

1.2.1 The continuity equation:

Consider pipeline that transports a compressible

fluid (e.g. natural gas). For any two sections 1 and 2

along a gas flow pipe;

P = gas pressure

u = gas velocity

A = pipeline cross sectional area

ρ = gas density

The continuity equation for steady state is:

0dt

dm

ρAu2

u2

A2

ρ1

u1

A1ρconstant

.

m

For a constant diameter pipe:

CρuA

.

m

Where C is a constant

1.2.2 The energy equation

The energy equation applied on gas flow between

sections 1 and 2 is in the form:

LD

2Cf22

aveZ2aveT2R

2H

1H2

aveP2M

22

P21

PaveTaveZR2

M

2u

1u

ln2C

This equation is a general equation that can be used

in Imperial or S.I. units, for any size or length of

pipe, for laminar, partially turbulent or fully

turbulent flow and for low, medium or high pressure

systems.

Definition of parameters:

psia 2, and 1 sectionsbetween pressure average Pave

psia ly,respective 2 and 1 sectionsat pressures P2 & P1

ft/sec ly,respective 2 and 1 sectionsat s velocitieflow u2 & u1

2P1P

2P

1P

2P1P3

2aveP

R 2, and 1 sectionsbetween re temperatuaverage Tave

R ly,respective 2 and 1 sectionsat res temperatu T2 & T1

2

2T1T

aveT

constant C

factorility compressib Zave

moles) lb / (lbm weight,molecular gas M

R) moles lb / ft3 (psia ,

10.73constant gas universal R

T

1 2

P1, u1

T1, H1

Z1, A1

ρ1

P2, u2

T2, H2

Z2, A2

ρ2


3

2D

bZ

bTRπ

bPM

bQ4

A

.

mC

Qb = standard flow rate, MMSCFD or MCF/HR

The standard volume is the gas volume at the

standard or base conditions (Tb, Pb and Zb) that have

the same mass of the actual gas volume. That is;

TRZ

PQ

bTR

bZ

bP

bQ

ρQb

ρb

Q.

m

gravity gas G

inch pipe, theofdiameter inside D

1˜ Tb, and Pbat factor ility compressib Zb

R 520 condition, baseat re temperatu Tb

psia 14.7 condition, baseat pressure Pb

The gas gravity is the ratio between the gas

molecular weight and the air molecular weight = M /

Mair, Mair ≈ 29 lbm / lb moles

Z = compressibility factor at Pave and Tave

H1-H2 = the elevation change, ft

L = pipe length, ft or mile

1.2.3 Determination of the compressibility

factor:

There are two main methods for the determination of

the compressibility factor; compressibility factor

chart and the equations of state

1.2.3.1 Compressibility factor chart:

As we can see, to get the compressibility factor from

the chart we have to get the pseudo reduced pressure,

Pr and the pseudo reduced temperature, Tr.

CT

aveTrT

CP

avePrP

Where,

PC = pseudo critical pressure

TC = pseudo critical temperature

The pseudocritical values for a gas mixture such as

the natural gas can be obtained with Kay's rule as

follows:

T'C = TCA . yA + TCB . yB + TCC . yC + …

P'C = PCA . yA + PCB . yB + PCC . yC + …

T'C = average pseudocritical temperature of the gas

P'C = average pseudocritical pressure of the gas

TCA, TCB, TCC,. = critical temperature of each

component

PCA, PCB, PCC,. = critical pressure of each component

yA, yB, yC,. = mole fraction of each component

The pseudo critical properties for the different gases

forming the natural gas mixture are listed in the

following table.


4


5

Compound Molecular Weight Critical Temperature(R) Critical Pressure (psia)

C1 16.043 343 666

C2 30.07 550 707

C3 44.097 666 617

iC4 58.124 734 528

nC4 58.124 765 551

iC5 72.151 829 491

nC5 72.151 845 489

nC6 86.178 913 437

nC7 100.205 972 397

nC8 114.232 1024 361

nC9 128.259 1070 332

nC10 142.286 1112 305

nC11 156.302 1150 285

nC12 170.338 1185 264

N2 28.016 227 493

CO2 44.01 548 1071

H2S 34.076 672 1300

O2 32 278 731

H2 2.016 60 188

H2O 18.015 1165 3199

Air 28.96 238 547

He 4 9 33

Where, C1 is the single carbon atom alkane, methane

CH4, C2 is the double carbon atom alkane, ethane,

C2H6…etc. Also "i" refers to the ISO structure while

n refers to the normal structure.

1.2.3.2 Equations of state

Several equations can be used to determine the

compressibility factor like the CNGA equation and

the Van-der Waals equation.

CNGA equation:

3.825T

G1.78510344400

aveP

1

1Z

The CNGA equation is used to determine the

compressibility factor for natural gas with 90%

methane by volume. The equation is valid when the

average gas pressure Pave is greater than 100 psig.

For pressures less than 100 psig, the compressibility

factor can be taken as 1.00. Note that the pressure

used in the CNGA equation is the gage pressure not

the absolute pressure.

Van-der waals equation

C8P

CRTb &

C64P

2CT

227R

a

RTbv2

v

aP


6

This equation was the first attempt to correct the

ideal gas law, but its accuracy is law.

1.2.4 Flow regimes

There are two main types of flow; laminar and

turbulent flow. The regime of flow is defined by the

Reynolds number, which is a dimensionless

expression:

μ

uDρeR

lbm/ft.sec , viscosityfluidμ

ft/sec velocity,average fluidu

ft diameter, internal pipelineD

3lbm/ft density, fluidρ Where

For Reynolds numbers less than 2,000 the flow is

normally laminar or stable. When the Reynolds

number exceeds 2,000, the flow is turbulent or

unstable. In high-pressure gas transmission lines

with moderate to high flow rates, only two regimes

of flow exist: partially turbulent flow (rough pipe

flow) and fully turbulent flow (smooth pipe flow).

The transmission factor for fully turbulent flow can

be calculated from the Nikuradse equation as

follows:

eK

3.7D

10log4f

1

Ke = effective roughness, inch which is

comprised of the following terms:

Ke = Ks + Ki + Kd

Where Ks = surface roughness

Ki = interfacial roughness

Kd = roughness due to bends, welds, fittings, etc.

Usually in high-pressure gas transmission lines with

high flow rates where the flow regime is fully

turbulent and the natural gas is almost dry, the values

of Ki and Kd are negligible. The values of Ks or Ke is

important in fully turbulent flow because the laminar

sublayer, the surface roughness of the pipe plays an

important role in determining the flow and pressure

drop in the pipe.

For internally uncoated commercial pipes, the value

of Ke is normally measured in the range of 650-750

μ inches. Erosion, corrosion, contamination and

other factors cause a yearly increase in Ke by 30-50

μ inches. Internal coating of pipes with a material

such as epoxy/polyamide reduces the surface

roughness to within a range of 200-300 micro inches

so the pressure drop decreases and correspondingly

the compressor power. The deterioration also

decreases the rate of deterioration per year by 50-75

micro-inches for every five years.

Getting Reynolds number:

42

πDμ

bQD

bρ

42

πDμ

QDρeR

42

πD

Qu

μ

uDρeR

29GM 1,b

Z

bTR

bZ

Mb

P

bρ

bTRDπμ

bP29G

b4Q

eR

Once the actual Reynolds number is determined, the

flow regime can be determined from Prandtl- Von

Karman equation which defines border line between

partially and fully turbulent flow:

0.6

f

1

eR

104logf

1

Laminar

sublayer

Partially

turbulent flow

Fully turbulent

flow

10000 100000 1000000

Re (in Log Scale)

Border Line

Prandtl- Von

Karman Equation

Fully Turbulent

Zone

Partially Turbulent

Zone


7

If the actual Reynolds number is greater than the

Reynolds number obtained from Prandtl- Von

Karman Equation, the flow is fully turbulent.

Otherwise, the flow is partially turbulent.

1.2.5 Widely used steady-state flow equations

A more simplified form of the general energy

equation in Imperial units can be written as follows:

2.5D

21

aveZaveGLT

E2

2P2

1P

f

1

bP

bT

38.744b

Q

E = potential energy term

aveave

2

ave

ZT

PΔH0.0375GE

psia 14.7 condition, baseat pressure = Pb

R 520 condition, baseat re temperatu= Tb

SCF/D ,conditions baseat rate flow gas Qb

psia pressure,exit gas = P2

psia pressure,inlet gas = P1

essdimensionl factor,ion transmiss=1

f

inch diameter, inside pipeline = D

miles length, pipeline = L

essdimensionl Tave, Paveat factor,ility compressib average = Zave

R re, temperatuaverage = Tave

psia pressure, average = Pave

ft change,elevation = H

essdimensionl gravity, gas =G

The different flow equations differ in the value of the

transmission factor. The general form of all the

equations is:

eD

d

aveZaveLTc

G

E2

2P2

1Pb

bP

bT

ab

Q

Where a, b, c, d, e are constants that have different

values in each equation. The values of a, b, c, d, e for

some of the most common steady-state flow

equations are listed in the table below.

These equations are especially suitable for the design

of gas transmission lines having large diameters and

high pressures. Only Colebrook-White can be used

for both partially and fully turbulent flow regimes,

Panhandle A and AGA partially turbulent equations

are used in the partially turbulent flow regime while

the remainders are used in the fully turbulent flow

regime. For AGA partially turbulent equation, Df is

the drag force that compensates for the inefficiencies

due to bends, welds, fittings, etc., and has a

numerical value in the range of 0.92 to 0.97. The

Panhandle B equation is normally suitable for large-

diameter (i.e., pipes larger than NPS 24). The

Weymouth equation tends to overestimate the

pressure drop predictions, and contains a lower

degree of accuracy relative to the other equations.

Weymouth is commonly used in distribution

networks for the sake of safety in predicting pressure

drop. Both the AGA fully turbulent and the

Colebrook-White introduce the effect of the pipe

effective roughness, Ke.


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Equation Transmission factor, f

1 a b c d e

Panhandle

A 0.07305

eR 6.872 435.83 1.078

8

0.853

9

0.539

4

2.618

2

AGA

Partially

Turbulent

F 1.4126

eR

10logf

4D

f

11.4126

eR

10logf

4D38.774 1 1 0.5 2.5

Panhandle

B

01961.0

bQ

16.70

D

G 737.02 1.02 0.961 0.51 2.53

Weymout

h 61

D 11.19 432.7 1 1 0.5 2.667

AGA

Fully

Turbulent

eK

3.7D

10log4

eK

3.7D

10log438.774 1 1 0.5 2.5

Colebrook

-White

eR

f

11.4126

D3.7

eK

10log4

eR

f

11.4126

D3.7

eK

10log438.774

1 1 0.5 2.5

1.2.6 Temperature profile:

Temperature is very important parameter in the

design of pipelines and related facilities.

The temperature has major effect on gas properties

and hence gas transportation in pipeline. Many gas

properties depend on temperature, such as gas

viscosity, density and specific heat. As gas

temperature increases, its viscosity increases which

results in the increase in pressure drop and hence

power loss. The temperature change in a pipeline has

three main reasons; heat transfer between gas and

surrounding, isenthalpic gas expansion due to

friction which is expressed by the Joule-Thompson

effect and isentropic gas expansion caused by

elevation change.

1.2.6.1 Heat Transfer in gas pipelines

Heat is transferred between gas and surrounding

among three stages; heat transfer by convection

between gas and pipe wall, heat transfer by

conduction through pipe wall, insulation and

concrete and heat transfer by convection and

radiation between pipe wall and surroundings.

1.2.6.1.1 Heat transfer between gas and pipe

wall:

This is held by convection, the heat transfer

coefficient can be calculated from Dittus-Boelter

equation:

0.2

D

0.8f

Vf

ρ0.4

fμ

pfC

0.6f

0.023kf

h

Where

hf = heat transfer coefficient, Btu/hr-f2-R

kf = gas thermal conductivity, Btu/hr-ft-R

Cpf = gas specific heat, Btu/lbm-R

μf = gas dynamic viscosity, lbm/ft-hr

ρf = gas density, lbm/ft3

Concrete

coating

Conduction

Plastic

coating

Conduction

Pipe

thickness

Conduction

Gas flow

Convection

Surrounding

Convection

and

Radiation


9

Vf = flow velocity, ft/hr

D = internal pipe diameter, ft

This equation is suitable for turbulent flow in pipes

where, Re > 10,000 and Prandtl number between 0.7

and 160.

The internal heat transfer resistance, Ri, can then be

calculated from the equation:

hr/BtuR,

iDLπ

fh

1

iR

1.2.6.1.2 Heat transfer through pipe wall,

insulation and concrete:

The heat transfer through solids occurs by

conduction, the total thermal resistance can be

calculated from the equation:

c

kL2π

ins/D

cDln

inskL2π

p/D

insDln

pkL2π

i/D

pDln

sR

Where Di, Dp, Dins, Dc are the internal and external

diameters of pipe, external diameter of insulation

and external diameter of concrete respectively.

While kp, kins and kc are the thermal conductivities of

pipe, insulation and concrete respectively.

1.2.6.1.3 Heat transfer between pipe and

surrounding:

Heat may be transferred between pipe wall and the

surrounding by conduction, convection and

radiation; this depends on what kind of environment

surrounds the pipe. For an above-ground or offshore

pipeline placed in a blowing fluid environment, the

heat transfer coefficient can be calculated from the

equation:

nPr

msurre,RC

outD

surrksurrh

Where

ksurr = thermal conductivity of the surrounding

fluid, Btu/hr-ft-R

Dout = outer diameter of the pipeline, e.g.

concrete outer diameter, ft

Re,surr = Reynolds number of the surrounding fluid

C, m and n are constant that are given in the

following table. The corresponding heat resistance

can be given as follows:

hr/BtuR,

cπLDsurrh

1surrR

Re number range C m n

< 4 0.989 0.33 1/3

< 40 0.911 0.385 1/3

< 4,000 0.683 0.466 1/3

< 40,000 0.193 0.618 1/3

> 40,000 0.027 0.805 1/3

Then, the overall heat transfer coefficient is

determined from the equation:

surrRsRi

RUA

1

1.2.6.2 Joule-Thompson Effect

The Joule-Thompson effect describes the

temperature loss due to the pressure drop that occurs

when gas expands in a pipeline. The Joule-

Thompson factor can either be related to the pressure

drop or pipe length as following:

L

jΔT

orΔP

jΔT

j

dLjpCmsurround

TTdAUdTpCm

By integration we yield:

j/asurround

TLa

e

j/asurround

T1T

2T

T1 = inlet gas temperature, R

T2 = exit gas temperature, R

Tsurround = surrounding temperature, R

j = Joule-Thompson coefficient, R/ft

(sometimes R/psi)

a = constant

=

pCm

πDU

, ft

-1

L = pipe length, ft

Notes:

1. For an underground pipeline, heat transfers

by conduction through the soil. The amount

of heat transfer through soil is calculated

using the following equation:

gTTSsoil

kq

Where

q = heat transfer rate, Btu/h

ksoil = soil thermal conductivity, Btu/h-ft-R

S = conduction shape factor for buried

pipelines, ft


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T = pipe wall temperature, R

Tg = soil (ground) temperature, R

The conduction shape factor for buried pipelines is

given as:

/2D

h1cosh

L2S

out

Where L = pipe length, ft

h = distance from center of pipe to the ground

surface, ft

Dout = pipeline outer diameter, ft

2. Heat transfer by radiation from pipe to the

surroundings can be given as:

4surround

T4

surfaceT

surfaceAσεq

Where ε = surface emissivity of the pipe

σ = Boltzman constant

= 5.67×10-8

Btu/hr-ft2-R

4

Asurface = pipe surface area, ft2

Tsurface = pipe surface temperature, R

Tsurround =surrounding temperature, R

1.2.7 Diameter selection criteria:

The diameter selection in fluid transmission

pipelines is usually based on the fluid velocity. For

liquid transmission pipelines, the pipeline diameter is

selected such that the liquid velocity in the pipeline

ranges between 1 and 3 m/s. If the liquid velocity

exceeds 3 m/s, the pressure drop in the pipeline will

be very large, while a low velocity flow allows

precipitation of solids carried with fluid.

In gas pipelines, the gas velocity is limited by the

erosional velocity. If a fluid flows in a pipeline with

a high velocity it can cause both erosion and

vibration in the pipeline. This will reduce the life of

the pipeline. So it is always necessary to control gas

velocity in gas transmission pipelines to prevent it

from rising above the erosional velocity.

1.2.7.1 Pipeline gas velocity

bZ

bTsP

sZsTb

P

4

2πD

4

2πD

A

bZ

bTsP

sZsTb

P

sρ

bρ

bTR

bZ

Mb

P

bρ;

sTRsZ

MsPsρ

bρ

bQsρsQ

A

sQsu

bs

Qu

Substitute, Pb = 14.7 psia, Tb = 520 R, Zb = 1

sP2

D

sZsTb

Q3101.44su

Where us = gas velocity at any segment, ft/sec

Qb = gas flow rate at base condition, ft3/hr

P = pressure at any section, psia

Ts = temperature at any section, R

D = pipeline diameter, inches

1.2.7.2 Erosional velocity

The velocity that can cause erosion to the pipeline

can be calculated from the following equation:

0.5ρ

Ceu

Where, in Imperial Units,

ue = erosional velocity, ft/sec

ρ = gas density, lbm/ft3

C is a constant defined as 75 < C < 150. The

recommended value for C in gas transmission lines

is C = 100.

0.5

TRZ

29GP

100eu

In the above equation:

ue = erosional velocity, ft/sec

G = gas gravity, dimensionless

P = pipeline minimum pressure, psia

Z = compressibility factor at the specified

pressure and temperature, dimensionless

T = flowing gas temperature, R

R = 10.73 (ft3 × psia/lb moles × R)

The recommended value for the gas velocity in gas

transmission mainlines is normally 40% to 50% of

the erosional velocity; this means a flow velocity in


11

the range of 33-43 ft/sec (10-13 m/sec). This value

could be increased to 15-17 m/sec for nonmajor lines

or laterals. Note that a very low velocity ratio means

that the pipeline is very extremely large which

means a high capital cost.


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2 Mechanical Design

2.1 Objectives

The objectives of this standard are:-

Provide an international acceptable standard

of safety for submarine pipeline system by

defining minimum requirements for the

design, materials, fabrication installation,

testing, commissioning, operation & repair.

Serve as technical reference document in

contractual matters between purchaser and

contractor; and

Serve as guideline for designers, purchaser,

and contractors

2.2 Definitions

1. Erosion: Material loss due to repeated

impact of sand particles liquid droplets.

2. Fabrication: Activities related to the

assembly of objects with a defined

purpose. In relation to pipelines,

fabrication refers to e.g. risers, expansion

loops, bundles, reels, etc.

3. Fabrication factor: factor on the material

strength in order to compensate for

material strength reduction from cold

forming during manufacturing of line

pipe.

4. Failure: An event affecting a component or

system and causing one or both of the

following effects:

Loss of component or system function; or

Deterioration of functional capability to

such an extent that the safety of the

installation , personal or environmental is

significantly reduced

5. Fatigue: cyclic loading causing degradation

of material.

6. Limit state: A state beyond which the

structure no longer satisfies the

requirements. The following categories of

limit states are of relevance for pipeline

systems:

SLS= Serviceability L.S.

ULS=Ultimate L.S

FLS=Fatigue L.S

ALS= Accidental L.S

7. Ovalisation: the deviation of the perimeter from a

circle. This has the form of an elliptic section.

8. Buckling, global: Buckling mode which involves a

substantial length of the pipeline, usually several

pipe joints and deformations of the cross section;

upheaval buckling is an example thereof.

9. Buckling local: Buckling mode confined to a short

length of the pipeline causing gross changes of the

cross section; collapse, localized wall wrinkling and

kinking are examples thereof.

10. Safety class(SC): in relation to pipelines; a

concept adopted to classify the significance

of the pipe line system with respect to the

consequences of failure

11. safety class resistance factor: Partial safety

factor which transform the lower fractile

resistance to a design resistance reflecting

the safety class

12. Reliability: the probability that a component

or a system will perform its required

function without failure, under stated

conditions of operation and maintenance and

during a specified time interval

Pressure definitions

1. Pressure collapse: characteristic resistance

against external over pressure

2. Pressure design: In relation to pipelines this is

the maximum internal pressure during normal

operation, referred to a specified reference

height, to which the pipeline or pipeline section

shall be designed. The design pressure must

take account of steady flow conditions over the

full range of flow rates, as well as possible

packing and shut-in conditions, over the whole

length of the pipeline or pipeline section which

is to have a constant design pressure.

3. Pressure incidental: In relation to pipelines

this is the maximum internal pressure the pipeline

or pipeline section is designed to withstand

during any incidental operation situation, referred

to the same reference height as the design

pressure.

4. Pressure propagation: the lowest pressure

required for a propagating buckle to continue to

propagate.

5. Pressure containment : is the maximum

internal pressure causing failure

2.3 DESIGN PHILOSOPHY

2.3.1 Location class


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2.3.2 Safety classes

2.3.3 Categorization of fluids

According to previews classifications in our case:-

Fluid category is: - B

Location type:- 2

So safety class would be:- High

Loads:

Loads shall be classified as follows:-

1. Functional loads:

Loads arising from the physical existence of the

pipeline system and its intended use shall be

classified as functional loads

All functional loads which are essential for the

pipe line system, during both the construction

and the operational phase, shall be considered

Effects from the following phenomena are the

minimum to be considered when establishing

functional load:

Wight

External hydraulic pressure;

Temperature of continent

Reaction from component(flanges, clamps

etc)

Cover (soil, rock, mattresses);

Internal pressure during operation

Reaction from sea floor(friction &rotational

stiffness)

Pre-stressing

Permanent deformation of supporting

structure

Permanent deformations due to subsidence of

ground, both vertical and horizontal

Possible loads due to ice bulb growth around

buried pipelines near fixed points ( in line

valves tees, fixed plants etc)

Loads included by frequent pigging

operations

2. Environmental loads :

Are defined as ;those loads on a pipeline

system which are caused by the surrounding

environment, and that are not otherwise

classified as functional or accidental loads

Hydrodynamic loads:- are defined as flow

induced loads caused by the relative motion

between the pipe and the surrounding water.

When determining the hydrodynamic loads the

relative liquid particles velocities and

accelerations used in the calculations shall be

established, taking into account contributions

from waves, current and motions if significant.

The following hydrodynamic loads shall be

considered but not limited

Drag and lift forces which are in phase with

the absolute or relative water particles

velocity

Inertia forces which are in phase with the

absolute or relative water particle

acceleration

3. Accidental loads

Loads which are imposed on a pipeline

system under abnormal conditions shall be

classified as accidental loads.

Typical accidental load can be caused by:

Vessel impact or other drifting items

(collision , grounding, sinking);

Dropped objects;

Mud slides

Explosion

Fire and heat flux

Dragging anchors


14

2.4 Design Calculations

Limit states:

As minimum requirement, risers and pipelines

shall be designed against the following potential

modes of failure:

1. serviceability limit state

Ovalisation / Ratching limit state;

accumulated plastic strain limit state

damage due to , or loss of, weight coating.

2. Ultimate limit state

Bursting limit state;

Ovalisation / Ratching limit (if causing total

failure)

Local buckling limit state (pipe wall

buckling limit state);

Global buckling limit state (normally for

load-controlled conditions);

Unstable fracture and plastic collapse limit

state; and

Impact

3. Fatigue limit state

Fatigue due to cyclic loading.

4. Accidental limit state

All limit states shall be satisfied for all

specified load combinations; the limit

state may be different for the load

controlled condition and the displacement

controlled condition

All limit states shall be satisfied for all relevant phases

and conditions. Typical conditions to be covered in the

design are:

Installation

As laid

System pressure test

Operation and

Shut-down

THE DESIGN WILL BE ACCORDING TO [ULS]

The design load can generally be expressed in the

following:

1. Pressure containment

High safety class during normal operation:

Pe: External pressure

Z : water height

G : proportionality constant

Pi : internal pressure

: sea water denisity.

The pressure containment resistance, pb (t), is

given by:

The minimum between Yield limit-state & the

bursting limit-state.

Yield limit state is

The bursting limit-state is

t : Wall Thickness

D: outer Diameter

Fy: Yield Stress to be used in design

Fu: Tensile Strength to be used in Design

2. Collapse Pressure:-

Not to be taken < 0.005 (0.5%)

The external pressure along the pipeline shall with the

Following collapse check:

Pc : Collapse Pressure

Pe1 : Elastic Collapse Pressure

E : young’s modulus ( Pipe Material)

ΰ : Poisson’s ratio

PP : Plastic Collapse Pressure

UO: Pipe Fabrication process for welded pipes

UOE: Pipe Fabrication process for welded pipes,

Expanded

TRB: Three roll bending

3. Local buckling

The check is:-

mSC

beli

γγ

(t)PPP

ili 1.05PP

we Z.g.ρP

w

3

2f

tD

2t(t)P ysb,

3

2

1.15

f

tD

2t(t)P u

ub,

t

DfPPP)P(P)P(P 0Pe1C

2

P

2

Ce1C

2

3

e1ν1

D

t2E

P

D

tαf2P fabyP

1D

DDovality,f minmax

0

mSC

Ce

γγ1.1

PP

1tPα

ΔP

tPα

ΔP1

Mα

Mγγ

Sα

Sγγ

2

bc

d

2

bc

d

Pc

dmSC

2

Pc

dmSC


15

For Pi>Pe

For Pe>Pi

P1d : Local design Pressure , The internal

pressure at any point in the pipeline system

for corresponding design pressure or

incidental pressure

Sd: Design Effective Axial Force

SF: Functional Axial Force= Residual lay

tension+

Thermal Expansion Force + Internal Pressure force

A: Pipe steel cross section Area

L: Residual lay tension

SE: Environmental Axial Force

Coefficient of thermal expansion

Md : Design bending moment

MF: Functional bending moment

ME: Environment bending moment

SP: Characteristic plastic axial force

resistance

MP: plastic Moment resistance

Design differential overpressure

4. Propagation buckling:-

The external pressure along the pipeline shall be

checked with the following Propagation check:-

Safety class resistance factor γsc

Safety class low Normal High

Pressure

containment

1.046 1.138 1.308

Other 1.04 1.14 1.26

Load effect factor and load combinations

Limit state

Functional

loads

Environ-

Mental

load

Accidental

loads

Pressure

loads

γf γE γA γp

SLS& 1.2 0.7 - 1.05

ULS 1.1 1.3 - 1.05

FLS 1.0 1.0 - 1.0

ALS 1.0 1.0 1.0 1.0

EECFFd γSγγSS

L2νν)(π/4)(1P2νν)(π/4)(1PEAsTαS 2

0e

2

iiF

EECFFd γMγγMM

tftDπS yP

tftDM y

2

P

)P(PγΔP eldPd

1]P

Pγ[γ]

Mα

Mγγ

Sα

Sγ[γ 2

c

emSC

2

Pc

dmSC

2

Pc

dmSC

dP

mSC

e

PP

Pr

5.2

Pr )(35D

tfP

SCm

faby


16

Conditions load effect factor γc

Condition γc

Pipe line resting on uneven seabed or in

a snaked condition

1.07

Continuously supported .82

System pressure test .93

Otherwise 1

Material resistance factor γm

Limit state

category

SLS/ULS/ALS FLS

γm 1.15 1

5. The Drag Force:

The Lift Force:

The Inertia Force:

ρ the density of sea water,

D is is the pipe diameter

UC is the steady state current velocity

averaged over the pipe diameter.

CD and CL are the non-dimensional

force coefficient for drag and lift.

CM : Inertia coefficient

cDD UDCF 25.0

c2

LL U0.5ρ.5F

M

2

I .Cρ.D4

πF


17

3 VB.NET Program algorithm

3.1 Inputs

3.2 Outputs

Input data Pipe Length, Flow Rate

Supply/Discharge Pressure & Temperature

Surrounding Temperature

Steel Grade

Number of Segments

Z-Factor Equation & Pressure Equation

Allowable Range for Velocity Ratio &

Allowable Pressure Drop

Gas Composition

Concrete/Insulation Thickness and

conductivity, Surface Emissivity

Load Data

Bases

Environmental Conditions; contours of: depth,

wave and current speed & direction

Properties of Gas components at the different

pressures and temperatures, ρ, Pr, μ, Cp, k,

Joule-Thompson

Molecular weight, critical pressures and

temperatures of different gas components

Standard diameters and thicknesses from the

API

Yield and tensile strengths of the different steel

grades

Tables

Acceptable diameters according to each equation

o Outlet/Inlet pressure and temperature

o Pressure drop

o Power lost in the line

o Velocity ratio

Required thicknesses in each contour according to the

pressure drop calculated by each equation

Graphs

Line chart

o Pressure plot

o Temperature plot

Bar chart

o Velocity ratios

o Powers

o Pressure drop


18

3.3 Processing

Loop all API diameters

Loop all solution equations

Loop all pipe segments

Find suitable thickness for this pipe segment according

to DNV code

Calculate compressibility factor

Calculate segment temperature according to heat

transfer (convection and radiation) and gas expansion

(Joule-Thompson) effect

Calculate pressure using the selected solution

equations

Calculate power loss in segment

End of loop

Calculate local to erosion velocity ratio at pipe end

Calculate total pressure drop along pipeline

Calculate total power lost in the pipeline

End of loop

End of loop

Defining the flow regime; partially turbulent or fully

turbulent flow

Equation Suits Flow regime

Yes

NO

Diameter satisfies requirements

Yes

NO


19

3.4 Program Interface


21

4 Egypt-Cyprus Pipeline

4.1 Pipeline requirements:

The proposed Egypt-Cyprus pipeline is 680 km

(422.6 mile) long. The demand is 4 MMSCM/Day.

The discharge pressure is 1,015 psi (70 bar). The

discharge temperature and the surrounding

temperature are equal and supposed to be 20 (C).

The gas consists mainly of methane (90%) and

ethane (10%).

4.2 Solution bases

Solve using both CNGA equation and Van-

der Waals equation

Solve using all the energy equations,

Panhandle A, AGA partially turbulent,

Panhandle B, AGA fully turbulent,

Weymouth and Colebrook-White

Divide the pipeline into 1000 segments.

Accept only diameters that give outlet local

velocity ranging between 30-50% of the

erosional velocity

Limit pressure drop to 1,500 psi

Ignore heat transfer

The selected pipe material is steel X-80.

Concrete thickness = 15 cm

4.3 Results:

4.3.1 Solution using CNGA equation

Selected diameters

Panhandle B

D(in) P1(psi) T1(F) % us/ue Pressure Drop (psi) Power loss(HP)

14 2359.27 111.2475 35.25817 1344.27 3729.771

Weymouth


AGA fully turbulent


12.75 1709.595 93.16087 43.37388 694.5952 2269.894

14 1482.561 85.60558 36.26622 467.5608 1638.808

Colebrook-White


12.75 1746.229 94.33281 43.32061 731.2288 2364.554

14 1513.105 86.65953 36.22514 498.1049 1728.601

Selected thicknesses

12.75" 14"

Contour (mile) Thickness(in) Contour (mile) Thickness(in)

435.0528 427.6569 0.281 435.0528 399.8135 0.312

427.6569 263.642 0.312 399.8135 147.4829 0.344

263.642 147.4829 0.33 147.4829 0 0.375

147.4829 46.55065 0.344

46.55065 0 0.375


21

4.3.2 Solution using Van-der Waals equation

Selected diameters

Panhandle B


14 2386.581 111.8889 36.48789 1371.581 3782.823

Weymouth


AGA fully turbulent


12.75 1713.575 93.2877 43.77462 698.5751 2280.264

14 1483.859 85.65056 36.42109 468.8585 1642.656

Colebrook-White


12.75 1750.842 94.48033 43.76394 735.8423 2376.35

14 1514.654 86.71336 36.39981 499.6541 1733.113

Selected thicknesses

12.75" 14"

Contour (mile) Thickness(in) Contour (mile) Thickness(in)

435.0528 427.2219 0.281 435.0528 397.2032 0.312

427.2219 252.7657 0.312 397.2032 125.7303 0.344

252.7657 129.6457 0.33 125.7303 0 0.375

129.6457 23.0578 0.344

23.0578 0 0.375


22

4.3.3 Pressure plot vs. pipe length

Solution using CNGA equation Solution using Van-der Waals equation

AGA Fully

Turbulent

equation

Panhandle B

Colebrook-

White

Panhandle B

AGA Fully

Turbulent

equation

Colebrook-

White


23

4.3.4 Temperature plot vs. pipe length

Solution using CNGA equation Solution using Van-der Waals equation

Panhandle B

AGA Fully

Turbulent

Colebrook-

White

Panhandle B

AGA Fully

Turbulent

Colebrook-

White


24

Discussion of results:

As we can see the use of Van-der Waals

equation results in slightly higher pressure

drop

The in the selected diameters is fully

turbulent, so the solution is based on

equations: Panhandle B, AGA fully

turbulent, Weymouth and Colebrook-White.

The power lost is calculated by summation

of the power lost in each segment of the

pipe.

5503600

144

psiΔP

bT

bZP

TZb

PSCF/hr

bQhplossPower

The reason why we do not include the effect

of heat transfer can be interpreted as

following: due to heat transfer, the

temperature drops along the pipeline. For

long pipelines, such as our case the

temperature reduces till reaching the

temperature of the surrounding, then the pipe

become "thermally insulated" and the

temperature become constant for the

remainder of the pipeline. If we had to solve

the problem from the last segment to the first

one backward solution, there will be no way

to determine the point when the pipe become

isothermal so the backward solution is not

possible

The number of segments in the forward

solution should be selected in proportional to

the pipe length since a small number of

segments for a long pipeline may result in a

great error calculation of the heat transferred.

The program determines the minimum

required thickness in each pipe contour. For

liquid pipelines it is possible to use more

than one thickness which greatly reduces the

total cost of the pipeline. However, in gas

pipelines we can only use one thickness

which is certainly the largest one. But

studying the variation in thicknesses along

the pipeline, gives an indication to the

factors affecting the mechanical design of

the pipeline, which may be the pressure if

the thicknesses are descending along the

pipe or the water head if the largest depth is

associated with the largest thickness.

Selected diameter: Due to the proceeded

selection criteria there are two acceptable

diameters 12.75" and 14". We decide to use

the 14” diameter as most flow equations

decide this diameter. The specifications are

summarized in the table below:

Distance

Temperature

Surrounding

Temperature

Gas Temperature

Distance

Temperature


Gas Temperature

Large number

of segments

Moderate

number of

segments

Distance

Temperature

Surrounding

Temperature

Gas Temperature

Small number

of segments

Distance

Temperature


Gas Temperature


25

D(in) Thickness (in) P1(psi) T1(F) % us/ue Pressure

Drop (psi)

Power

loss(HP)

14 0.375 1482.561 85.60558 36.26622 467.5608 1638.808

Offshore Pipeline Hydraulic and Mechanical Analyses

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