uprating the dolphin gas pipeline
DESCRIPTION
Richard Espiner, Alan Edwards & Andrew FrancisBG TechnologyGas Research & Technology Centre, Loughborough, U.K.TRANSCRIPT
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.
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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.
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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
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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).
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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
Risk Based & Limit State Design & Operation of Pipelines Page 6 of 24 Oslo, Norway, 4 – 5 October 1999
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
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• 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
Risk Based & Limit State Design & Operation of Pipelines Page 8 of 24 Oslo, Norway, 4 – 5 October 1999
( ) ( )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.
Risk Based & Limit State Design & Operation of Pipelines Page 9 of 24 Oslo, Norway, 4 – 5 October 1999
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.
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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
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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
Risk Based & Limit State Design & Operation of Pipelines Page 12 of 24 Oslo, Norway, 4 – 5 October 1999
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.
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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.
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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.
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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
Risk Based & Limit State Design & Operation of Pipelines Page 16 of 24 Oslo, Norway, 4 – 5 October 1999
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.
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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.
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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.
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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
Risk Based & Limit State Design & Operation of Pipelines Page 20 of 24 Oslo, Norway, 4 – 5 October 1999
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
Risk Based & Limit State Design & Operation of Pipelines Page 21 of 24 Oslo, Norway, 4 – 5 October 1999
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
Risk Based & Limit State Design & Operation of Pipelines Page 22 of 24 Oslo, Norway, 4 – 5 October 1999
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
Risk Based & Limit State Design & Operation of Pipelines Page 23 of 24 Oslo, Norway, 4 – 5 October 1999
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
Risk Based & Limit State Design & Operation of Pipelines Page 24 of 24 Oslo, Norway, 4 – 5 October 1999
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
Operating Pressure (bar)
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
Operating Pressure (bar)
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