Uprating The Dolphin Gas Pipeline

Risk Based & Limit State Design & Operation of Pipelines Page 1 of 24 Oslo, Norway, 4 – 5 October 1999

UPRATING THE DOLPHIN GAS PIPELINE USING

STRUCTURAL RELIABILITY BASED METHODS

Richard Espiner, Alan Edwards & Andrew Francis

BG Technology

Gas Research & Technology Centre, Loughborough, U.K.

ABSTRACT

The Dolphin field off the coast of Trinidad is operated by BG International. The field

delivers natural gas to Trinidad through a 67 km, 24” subsea pipeline that currently

operates at a maximum allowable operating pressure (MAOP) of 118 barg.

This paper describes a structural reliability based approach to assess the feasibility of

uprating the pipeline in order to increase throughput.

The approach involves the probabilistic treatment of limit state functions for each

credible failure mode of the pipeline. Initially the credible failure modes that will be

affected by the proposed uprating are identified together with the appropriate limit state

functions. The variation in the governing parameters is established and the probability of

failure calculated for the current and proposed uprated pressures for each failure mode.

The acceptability of the uprating is assessed according to the relative values of the

failure probabilities at the current and uprated pressures.

INTRODUCTION

Gas produced from the Dolphin field is exported through a 64 km, 609 mm (24”)

diameter pipeline from the Dolphin ‘A’ platform to the third party operated Poui platform.

The export pipeline has a maximum allowable operating pressure (MAOP) of 118 barg.


The pipeline was commissioned in 1996. The water depth ranges from 109 m at the

Dolphin ‘A’ platform to 55 m at the Poui platform. The first 3.56 km of the pipeline has a

nominal wall thickness of 14.27 mm and the remainder has a nominal wall thickness of

12.7 mm. The risers at the Dolphin and Poui platforms have a nominal wall thickness of

17.48 mm.

This report describes an assessment of the feasibility of uprating the 24” export pipeline

to a pressure above the present MAOP in order to increase throughput. The

assessment was carried out using a structural reliability based methodology that was

used to justify uprating sections of the Transco National Transmission System to a

pressure of 85 barg, equivalent to a design factor of 0.78 [1-6].

Scope of Study

A full structural reliability assessment is carried out for the main pipeline section of 12.7

mm nominal wall thickness. The design parameters of this section of the pipeline are

listed in Table 1. For the purposes of this study, the external hydrostatic pressure is

calculated at the minimum water depth of 55 m. For simplicity the value of the external

pressure is rounded to 5 barg.

A structural reliability assessment is also carried out for the risers at the Dolphin and

Poui platforms, which may be subject to different failure modes. The design parameters

of the risers are listed in Table 1.

STRUCTURAL RELIABILITY BASED METHODOLOGY

Structural Reliability Based Design is a technique that has been referred to elsewhere

as Reliability Based Limit State Design, Probabilistic Limit State Design and Limit

State Design. The overall aim of the methodology is to assess the fitness for purpose of

a structure based on a calculated failure probability. The techniques can be used to

determine the theoretical probability of failure associated with the design and operation

of a pipeline.


The six basic elements of the approach are:

• Establishment of the limit states to be considered.

• Identification of failure modes that could lead to the limit states.

• Construction of limit state functions.

• Data analysis and the construction of appropriate probability density functions.

• Evaluation of failure probabilities.

• Assessment of the results.

These elements are discussed in detail in [1 – 11].

LIMIT STATES AND FAILURE MODES

A limit state is defined as the state of a structure in which it no longer satisfies a

particular design requirement.

The Ultimate Limit State (ULS) is the state at which the pipeline cannot contain the fluid

it is carrying. This limit state has safety implications.

The Serviceability Limit State (SLS) is the state at which the pipeline no longer meets

the full design requirements but is still able to contain the fluid, e.g. can no longer pass

sufficient fluid and / or maintenance tools. This limit state has no direct safety

implications.

The limit states of an in-service subsea pipeline and riser are excessive plastic

deformation (SLS) and loss of containment (ULS).

The credible failure modes are discussed below.

Pipe Wall Yielding


A net operating pressure causing a hoop stress greater than the pipeline steel yield

strength will lead to yielding of the pipe wall with resulting plastic deformation (SLS).

Bursting

A pipeline free of any defects will fail if the hoop stress due to the operating pressure is

greater than the ultimate tensile strength of the pipeline steel causing the wall of the pipe

to burst (ULS).

External Corrosion

Corrosion defects may occur on the outside surface of the pipe wall, resulting in a loss

of wall thickness and failure under the action of internal pressure loading (ULS). The

risers are particularly susceptible to external corrosion in the splash zone.

Internal Corrosion

Corrosion defects may occur on the inside surface of the pipe wall, resulting in a loss of

wall thickness and failure under the action of internal pressure loading (ULS).

Stress Corrosion Cracking (SCC), Sulphide Stress Corrosion Cracking (SSCC)

and Hydrogen Induced Cracking (HIC)

SCC, SSCC and HIC may cause cracks to form in the wall of the pipe, leading to

fracture under the action of internal pressure loading (ULS).

Buckling

Large compressive axial stresses, including stresses due to thermal expansion, may

lead to global buckling of the pipeline (SLS).


Fatigue Crack Growth of Construction Defects

Defects introduced into the pipeline during construction, particularly in girth and seam

welds, may grow through fatigue and eventually lead to fracture under the action of

internal pressure loading (ULS). Fatigue crack growth may occur as a result of internal

pressure cycling or cyclic external loading, for example through vortex induced vibration

(VIV) of risers.

External Impact

Impacts on the pipeline may cause denting (SLS) or gouging (ULS). Impacts occur as a

result of external interference, including

• Dropped Anchors

• Dragged Anchors

• Dropped Cargo

• Sinking Ships

• Trawl Gear Interference

• Ship Impact (on risers)

The probability of failure due to these external impact modes is the product of the

probability of impact and the probability of pipeline failure given that an impact has

occurred.

STRUCTURAL RELIABILITY ASSESSMENT OF PIPELINE

Knowledge of the design and operation of the subject pipeline may be used at this

stage to identify failure modes that are unlikely and need not be assessed using

structural reliability based techniques.

Bursting occurs when the hoop stress in the pipe wall exceeds the ultimate tensile

strength of the pipe material. Ultimate tensile strength is significantly above yield


strength for the material used to construct the pipeline and thus bursting will occur at a

higher pressure than that at which the SLS is reached by yielding. Therefore bursting is

not explicitly considered in this study.

SCC is associated with pipelines with poor external coatings and poor cathodic

protection. The Dolphin export pipeline has a high quality coating in good condition and

has good cathodic protection, and therefore SCC is not addressed in this study.

SSCC and HIC occur when water and H2S are present in the fluid transported by the

pipeline. There is no evidence of H2S in the Dolphin field and therefore SSCC and HIC

are not addressed in this study.

The pipeline operates, and will continue to operate, under steady state conditions with

no significant pressure cycling. Therefore fatigue crack growth of weld defects is not a

credible failure mode and is not addressed in this study.

The pipeline is not in an area where trawling is carried out and therefore trawl gear

impact is not a credible failure mode. The pipeline has a nominal concrete coating

thickness of 75 mm and it is assumed that this coating will prevent gouging of the

pipeline from any impacts that do occur. Therefore external impact is not a credible

failure mode and is not addressed in this study.

The remaining credible failure modes that may lead to the pipeline reaching the

Serviceability Limit State are

• Yielding due to internal pressure loading

• Buckling due to thermal expansion

The credible failure modes that may lead to the pipeline reaching the Ultimate Limit

State are

• External Corrosion


• Internal Corrosion

Serviceability Limit State

Yielding

The pipeline has been hydrostatically tested to 147 barg which eliminates the possibility

of failures at pressures below this value if no defects are present. However, the onset of

gross yielding in the pipe wall sets the theoretical upper limit on the possible operating

pressure and therefore the probability of yielding due to internal pressure has been

investigated.

The limit state function for this failure mode is given by

( )

ye

w2DPP

σ=−

(1)

where P is the internal pressure, Pe is the external hydrostatic pressure, D is the pipeline

diameter, w is the actual wall thickness at any point in the pipe and σy is the actual value

of yield strength at the same point.

In order to calculate the probability of failure the wall thickness, w, and yield strength, σy,

are represented by probability density functions p(w) and p(σy) respectively. The set of

combinations of w and σy that lead to a failure is known as the failure space. The two

dimensional failure space is expressed in the form

( )

w2DPP

0,w0 ey

−≤σ≤∞≤≤

The failure space is modified to take account of the successful hydrostatic test, which

rules out combinations of wall thickness and yield strength that would have resulted in

failure at the hydrostatic test pressure Ph. The modified failure space is given by


( ) ( )w2

DPPw2

DPP,w0 e

yeh −

≤σ≤−

∞≤≤

The limit state function defines a critical value of yield strength as a function of wall

thickness and the probability of failure, conditional on the pipeline surviving the

hydrostatic test at a pressure Ph, is found by integration of the probability density

functions over the failure space

( ) ( )( )

( )

( ) ( )( )

dwdpwp1

dwdpwp

p

yw2

DPP

0y

0

y

w2DPP

w2DPP

y0

feh

e

eh

σσ−

σσ

=

∫∫

∫∫

−∞

−

−

∞

(2)

where the denominator denotes the probability of the pipeline surviving the hydrostatic

test at pressure Ph.

The probability density function for yield strength, p(σy), was found from a statistical

analysis of measured values from pipe mill certificates. The most appropriate

distribution was found to be a lognormal probability density function with mean value

478.6 MPa and standard deviation 10.36 MPa. The yield strength distribution is shown

in Figure 1.

The probability density function for wall thickness, p(w), was found from pipe delivery

records and inspection sheets. The most appropriate distribution was found to be a

Normal pdf with mean value 12.7 mm and standard deviation 0.18 mm. This distribution

is illustrated in Figure 2. The parameters of the probability density functions are listed in

Table 2.

The external hydrostatic pressure is assumed to be a fixed value of 5 barg.


The probability of failure by yielding is calculated for a range of internal pressures by

repeated application of Equation (2). The calculated probability of yielding is zero for

internal pressures below 163 barg and increases rapidly at pressures above this value.

Therefore the maximum allowable pressure in the pipeline, assuming that no defects are

present, is 163 barg. In order to achieve this the operating pressure must be restricted

to a lower value to allow an overpressure margin. A 4% margin as required by the

ASME B31.8 design code dictates a maximum possible operating pressure of 156

barg.

The assumption that there are no defects in the pipeline is not realistic and therefore the

Ultimate Limit State must be taken into consideration, which may make operation at this

maximum possible operating pressure unacceptable.

Buckling

Buckling of the pipeline may occur when thermal expansion results in large compressive

axial stresses.

For generalised plain strain conditions the axial stress in the pipeline is given by

TEw2

PDwD

Flaya ∆α−ν+

π=σ (3)

where Flay is the residual pipe lay tension, w is the mean wall thickness, D is the

pipeline diameter, P is the operating pressure of the pipeline, ν is the Poisson’s ratio, E

the Young’s modulus and α the thermal expansion coefficient of the pipe material, and

∆T is the change in operating temperature relative to the temperature during laying.

The residual lay tension, operating temperature and the material properties ν, E and α

are assumed to be constants as given in Table 1.


The axial stress in the pipeline, calculated using Equation (3), is compressive at the

current MAOP and becomes tensile at higher pressures. Therefore buckling due to

thermal expansion is not a credible mode of failure for the pipeline at higher pressures.

Ultimate Limit State

External Corrosion

Guidelines for predicting the failure pressure of part wall corrosion defects in pipelines

were developed by the Linepipe Corrosion Group Sponsored Project [12] through a

combination of analysis and full scale testing. These guidelines, which are based on

plastic collapse, are central to the derivation of the limit state function that is used in this

study.

The limit state function for corrosion defects relates the defect depth at failure to defect

length and hoop stress and is given by

σσ

−

σσ

−

=−1

u

h

u

h

c

Q1

1

wa

(4)

where ac is the depth of the corrosion defect at failure, w is the wall thickness of the

pipeline, σh is the hoop stress given by

( )

w2DPP e

h−

=σ , (5)

σu is the ultimate tensile strength (UTS) of the pipe material, P is the internal pressure,

Pe is the external hydrostatic pressure, Q is a length correction factor given by


21

2

Dw

L31.01Q

+= , (6)

L is the length of the defect in the axial direction and D is the diameter of the pipeline.

In order to calculate the probability of failure, wall thickness, w, ultimate tensile strength,

σu, and defect length, L, are represented by probability density functions p(w), p(σu),

and p(L) respectively.

The defect depth, a, will increase with time due to corrosion and is represented by a

time dependent probability density function, p(a,t), where time zero is the time of

commissioning of the pipeline.

The limit state function, Equation (4), defines a critical defect depth ac and the four

dimensional failure space is therefore given by

∞≤≤∞≤≤∞≤≤∞≤σ≤ aa,L0,w0,0 cu

The time dependent cumulative probability of failure, pf’(t), given that a defect exists is

calculated by integration of the probability density functions over the failure space.

( ) ( ) ( ) ( ) ( ) ua000

uf ddwdLdat,apLpwpptpc

σσ=′ ∫∫∫∫∞∞∞∞

(7)

In order to calculate the probability of failure for the pipeline, the defect failure probability

must be multiplied by the probability of a corrosion defect occurring, pcorr.

( ) ( )[ ]tpptp fcorrf ′= (8)

The probability density function for ultimate tensile strength, p(σu), was found from a

statistical analysis of measured values from pipe mill certificates. The most appropriate


distribution was found to be a lognormal probability density function with mean value

606.2 MPa and standard deviation 8.67 MPa. The UTS distribution is shown in Figure

4.

No data is available for actual external corrosion incidents on the pipeline and therefore

assumptions have been made in line with conditions found on similar pipelines.

The defect length is assumed to be uniformly distributed between 0 and 1000 mm and

pcorr is estimated as 0.1 defects per km.

The corrosion defect depth is estimated by assuming a distribution for the depth growth

rate. The defect depth is assumed to have a Normal probability density function with

mean value equal to ( )tac& and coefficient of variation equal to 0.33, where ca& is the

mean depth growth rate for external corrosion. Previous studies [14] have used a value

of 0.005 mm/yr for ca& for subsea pipelines with good cathodic protection. The cathodic

protection system for the Dolphin export pipeline is assumed to be in good condition.

As before the external hydrostatic pressure is taken as 5 barg.

Calculated probabilities of failure due to external corrosion over a 40 year period are

negligible for operating pressures up to 160 barg.


Internal Corrosion

The pipeline is treated as thin-walled and therefore the limit state function for internal

corrosion is identical to that for external corrosion, Equation (4). The probability of

pipeline failure due to internal corrosion is found from Equation (8).

The growth rate of internal corrosion defects is governed by the fluid composition and

the operating pressure and temperature of the pipeline. The fluid composition is given in

Table 1.

No information is available on the internal corrosion behaviour of the Dolphin export

pipeline. However, a conservative assessment of the corrosivity of the fluid at the

pipeline operating pressure and temperature indicates that the maximum growth rate of

internal corrosion will be of the order of 0.1 mm/year. The defect depth is therefore

assumed to have a Normal probability density function with maximum value equal to 0.1t

and mean value equal to 0.05t, giving a coefficient of variation of 0.33. The defect length

is assumed to be uniformly distributed between 0 and 1000 mm. It is assumed that the

probability of occurrence of internal corrosion defects is equal to that for external

corrosion and therefore pcorr is assumed to be 0.1 defects per km.

Calculated probabilities of failure over a 40 year period are shown in Table 3 for a range

of operating pressures from 100 barg to 160 barg. The results are illustrated graphically

in Figure 4.

These results assume that no in-line inspection takes place over the life of the pipeline.

In-line inspection can significantly reduce the probability of failure due to corrosion by

identifying large defects for subsequent remedial action.


STRUCTURAL RELIABILITY ASSESSMENT OF RISERS

The arguments presented in section 4 with respect to SCC, SSCC, HIC and fatigue

crack growth on the main pipeline are equally applicable to the risers and therefore

these failure modes are not considered further.

It is assumed that the probability of failure due to ship impact is independent of

operating pressure and depends only on the probability of an impact occurring.

Therefore the probability is unaffected by uprating and is not considered further in this

study.

The credible failure modes that may lead to the riser reaching the Serviceability Limit

State are

• Yielding due to internal pressure loading

• Buckling due to thermal expansion

The credible failure modes that may lead to the riser reaching the Ultimate Limit State

are

• External Corrosion

• Internal Corrosion

• Fatigue Crack Growth due to vortex induced vibration

Serviceability Limit State

Yielding

The risers have been hydrostatically tested to 176 barg, which eliminates the possibility

of failures at pressures below this value if no defects are present. This is above the

maximum possible operating pressure of the pipeline as determined earlier and

therefore yielding of the risers does not limit uprating.


The assumption that there are no defects in the riser is not realistic and therefore the

Ultimate Limit State must be taken into consideration.

Buckling

Buckling of the riser may occur when thermal expansion results in large compressive

axial stresses.

As for the pipeline, an increase in operating pressure results in a tensile axial stress in

the riser. Therefore buckling is not a credible mode of failure for the riser at higher

pressures.

Ultimate Limit State

External Corrosion

The limit state function for external corrosion of the riser is identical to that for the

pipeline, Equation (4). The probability of riser failure due to external corrosion is found

from Equation (8).

The risers are constructed from the same X65 material as the main pipeline and

therefore the UTS distribution is the same as for the pipeline.

The probability density function for riser wall thickness, p(w), was found from pipe

delivery records and inspection sheets. The most appropriate distribution was found to

be a Normal pdf with mean value 17.46 mm and standard deviation 0.25 mm. The

parameters of the probability density functions are listed in Table 2.

No information is available on the external corrosion behaviour of the risers at the

Dolphin and Poui platforms. However, it is expected that the growth rate will be higher

for the risers than for the main pipeline. The defect depth is assumed to have a Normal


probability density function with mean value equal to ( )tac& and coefficient of variation

equal to 0.33, where ca& is the mean depth growth rate for external corrosion. An

assumed growth rate of 0.1 mm/yr is used for the purposes of this feasibility study. The

defect length is assumed to be uniformly distributed between 0 and 1000 mm.

It is conservatively assumed that the probability of occurrence of an external corrosion

defect on each riser is 1, i.e. that each riser contains a defect.

The area of concern is in the splash zone around the mean waterline. Therefore the

external hydrostatic pressure in this case is zero.

Calculated probabilities of failure over a 40 year period are shown in Table 3 for a range

of operating pressures from 100 barg to 160 barg. The results are illustrated graphically

in Figure 5.

These results assume that no inspection takes place over the life of the riser. Inspection

can significantly reduce the probability of failure due to corrosion by identifying defects

for subsequent repair.

Internal Corrosion

As the riser contains the same fluid as the pipeline the growth rate and probability of

occurrence of internal corrosion defects on the riser will be the same as for the pipeline.

The limit state function for internal corrosion is given by Equation (4) and the probability

of riser failure due to internal corrosion is found from Equation (8).

The riser extends above the water level and therefore the external hydrostatic pressure

is assumed to be zero.

Calculations show that the probability of failure of the riser due to internal corrosion is

negligible at pressures up to 160 barg, as expected given the increased wall thickness.


Fatigue Crack Growth due to Vortex Induced Vibration

Vortex induced vibration (VIV) can occur when the frequency of vortex shedding,

dependent on the current velocity, is close to a natural frequency of vibration of the riser.

This can result in large bending stresses leading to fatigue crack growth.

The riser is held by clamps that were designed to be sufficiently closely spaced to

eliminate VIV at the current operating pressure. This is achieved by ensuring that the

natural frequency of the riser span is significantly higher than the maximum vortex

shedding frequency that would result from the highest credible current velocity.

An increase in operating pressure will increase the axial tension in the riser, resulting in

an increase in the natural frequency of the span. Therefore uprating will not adversely

affect this failure mode.

ASSESSMENT OF RESULTS

The above analysis demonstrates that the most significant failure mode is internal

corrosion for the pipeline and external corrosion for the two risers, based on the

information available and the assumptions made.

The overall probability of failure of the system, consisting of the pipeline and the two

risers, in a 40 year period is given in Table 3 for a range of operating pressures. The

results are illustrated graphically in Figure 6. It can be seen that the probability of failure

increases gradually for operating pressures up to 140 barg and more rapidly for

pressures above this value. The results assume that no in-line inspection takes place

over the life of the pipeline. In-line inspection can significantly reduce the probability of

failure due to corrosion by identifying defects for subsequent repair or other remedial

action.

Taking into account the small magnitude of the calculated failure probability, it is

considered that the increase in failure probability at 140 barg is insignificant.


The calculated failure probability at the current MAOP of 118 barg is considered

acceptable on the basis of code compliance and therefore the failure probability at a

pressure of 140 barg is also considered acceptable.

CONCLUSIONS

The feasibility of uprating the Dolphin 24” export pipeline has been investigated using a

structural reliability based methodology developed by BG Technology.

A detailed study of the credible failure modes has been undertaken to evaluate the

associated probabilities of failure.

The probability of reaching the Serviceability Limit State by yielding is zero for internal

pressures up to 163 barg and increases rapidly at higher pressures. The maximum

possible operating pressure of the pipeline if no defects were present would therefore

be 156 barg, if a 4% overpressure margin is required.

The most significant failure mode of the pipeline, based on the information available and

the assumptions made, is internal corrosion.

The most significant failure mode of the risers, based on the information available and

the assumptions made, is external corrosion.

It is considered that the increase in the total failure probability of the pipeline and risers

due to an increase in pressure to 140 barg is insignificant.

The calculated failure probability at the current MAOP of 118 barg is considered

acceptable on the basis of code compliance and therefore the failure probability at a

pressure of 140 barg is also considered acceptable.


REFERENCES

1. Francis, A., Batte, A.D. & Haswell, J.V., “Probabilistic Analysis to Assess the Safety and Integrity of Uprated High Pressure Gas Transmission Pipelines”, Institution of Gas Engineers Annual Conference, Birmingham, UK, April 1997

2. Francis, A., Espiner, R.J., Edwards, A.M., Cosham, A. & Lamb, M., “Uprating an In-

service Pipeline Using Reliability-based Limit State Methods”, 2nd International Conference on Risk Based & Limit State Design & Operation of Pipelines, Aberdeen, UK, May 1997

3. Francis, A. & Senior, G., “The Applicability of a Reliability-based Methodology to

the Uprating of High Pressure Pipelines”, Institution of Gas Engineers Midlands Section Meeting, Hinckley, UK, March 1998

4. Francis, A., Espiner, R.J., Edwards, A.M., & Senior, G., “The Use of Reliability-

based Limit State Methods in Uprating High Pressure Pipelines”, International Pipeline Conference, Calgary, Canada, June 1998

5. Senior, G., Francis, A. & Hopkins, P., “Uprating the Design Pressure of In-service

Pipelines Using Limit State Design and Quantitative Risk Analysis”, 2nd International Pipelines Conference, Istanbul, Turkey, December 1998

6. Espiner, R.J., “Uprating of In-service Transmission Pipelines Using Structural Reliability Based Methods”, Institution of Gas Engineers North of England Section Meeting, Chester-le-Street, UK, 12 January 1999

7. Francis, A., Edwards, A.M. & Espiner, R.J., “Reliability Based Approach to the

Operation of Gas Transmission Pipelines at Design Factors Greater Than 0.72”, 17th International Conference on Offshore Mechanics and Arctic Engineering, Lisbon, Portugal, July 1998

8. Espiner, R.J. & Edwards, A.M., “An Investigation of the Effectiveness of Hydrostatic

Testing in Improving Pipeline Reliability”, 3rd International Conference on Risk Based & Limit State Design & Operation of Pipelines, Aberdeen, UK, October 1998

9. Lamb, M., Francis, A. & Hopkins, P., “How do you Assess the Results of a Limit

State Based Pipeline Design”, 3rd International Conference on Risk Based & Limit State Design & Operation of Pipelines, Aberdeen, UK, October 1998

10. Batte, A.D., Francis, A. & Fu, B., “Extending the Operational Performance of

Pipelines”, International Gas Research Conference, San Diego, USA, November 1998

11. Espiner, R.J., Edwards, A.M. & Francis, A., “Structural Reliability Based Approach

to Uprating a Subsea High Pressure Gas Pipeline”, 18th International Conference


on Offshore Mechanics and Arctic Engineering, St. Johns, Newfoundland, Canada, July 1999

12. Batte, A.D., Fu, B., Kirkwood, M.G. & Vu, D., “New Methods for Determining the

Remaining Strength of Corroded Pipelines”, 16th International Conference on Offshore Mechanics and Arctic Engineering, Yokohama, Japan, April 1997

13. Det Norske Veritas, “Corroded Pipelines”, Recommended Practice RP-F101, 1999 14. Hameed, S.A., Ismail, M., Fassina, P., Hoxha, G. & Lazzari, L., “Corrosion Risk

Assessment and Planned Maintenance for Corrosion Control: An Application to an Oilfield in Egypt”, 17th International Conference on Offshore Mechanics and Arctic Engineering, Lisbon, Portugal, July 1998


Table 1: Pipeline and Riser Design Parameters

Parameter Symbol Value

Outer Diameter D 609.6 mm

Pipeline Nominal Wall Thickness wnom 12.7 mm

Riser Nominal Wall Thickness wnom,r 17.48 mm

Specified Minimum Yield Strength SMYS 448 MPa

Specified Minimum Tensile Strength SMTS 530 MPa

Young’s Modulus E 210 GPa

Poisson’s Ratio ν 0.3

Thermal Expansion Coefficient α 1.2 x10-5 K-1

Seabed Temperature To 289 K

Pipeline Operating Temperature Top 327 K

Residual Pipelay Tension Flay 328.7 kN

Maximum Allowable Operating Pressure MAOP 118 barg

Pipeline Hydrostatic Test Pressure Ph 147 barg

Riser Hydrostatic Test Pressure Ph,r 176 barg

Fluid Composition: %CO2 %H2S %H2O

0.1 nil saturated


Table 2: Stochastic Parameters

Parameter Symbol Distribution Distribution Parameters

Pipeline Wall Thickness

w Normal mean = 12.74 mm sd = 0.18 mm

Riser Wall Thickness

wr Normal mean = 17.46 mm sd = 0.25 mm

Yield Strength sy Lognormal mean = 478.6 MPa sd = 10.36 MPa

Ultimate Tensile Strength

su Lognormal mean = 606.2 MPa sd = 8.67 MPa

Corrosion defect depth

a Normal mean = tac& mm sd = tac& /3 mm

Corrosion defect length

L Uniform max = 1000 mm min = 0

Table 3: Calculated Probabilities of Failure Over a 40-year Period

Operating Pressure

(barg)

Probability of Failure of Pipeline (per km)

Probability of Failure of Riser

(per riser)

Probability of failure of System

(Pipeline and Two Risers)

100 0 2.0 x10-7 3.9 x10-7

120 0 4.8 x10-6 9.6 x10-6

140 2.7 x10-8 9.1 x10-5 1.8 x10-4

145 8.0 x10-8 1.8 x10-4 3.7 x10-4

150 4.5 x10-7 3.6 x10-4 7.7 x10-4

155 2.3 x10-6 6.9 x10-4 1.7 x10-3

160 1.1 x10-5 1.3 x10-3 4.0 x10-3


440 460 480 500 520

Yield Strength (MPa)

0

0.01

0.02

0.03

0.04

0.05

p(yield strength)

Figure 1Yield Strength Probability Density Function

12 12.5 13 13.5

Wall Thickness (mm)

0

0.5

1

1.5

2

2.5

p(w)

Figure 2Wall Thickness Probability Density Function

580 590 600 610 620 630

UTS (MPa)

0

0.01

0.02

0.03

0.04

0.05

p(UTS)

Figure 3UTS Probability Density Function


100 110 120 130 140 150 160 170

Operating Pressure (bar)

0.0E+0

5.0E-6

1.0E-5

1.5E-5

2.0E-5

2.5E-5

pf ( /km)

Figure 4Probability of Failure of Pipeline due to Internal Corrosion in a 40 Year Period

100 110 120 130 140 150 160 170


0.0E+0

5.0E-4

1.0E-3

1.5E-3

pf (per riser)

Figure 5Probability of Failure of Riser due to External Corrosion in a 40 Year Period

100 110 120 130 140 150 160 170


0.0E+0

1.0E-3

2.0E-3

3.0E-3

4.0E-3

5.0E-3

Probability of Failure

Figure 6Overall Probability of Failure of Pipeline and Risers in a 40 Year Period

Documents

Uprating The Dolphin Gas Pipeline