Pipeline Integrity Management
Content
Paper No.
622
Computer Modelling of Offshore CP systems for 15 years: ”What
have we learned ?
A PIPELINE INTEGRITY MANAGEMENT STRATEGY BASED ON
MULTIPHASE FLUID FLOW
AND CORROSION MODELLING
by
Per Olav Gartland, Frode Bjoernaas and Harald Osvoll
CorrOcean ASA
Trondheim,
Norway
Per Olav
Gartland
and Jan Erik Salomonsen
CorrOcean ASA
Teglgaarden, Trondheim, Norway
ABSTRACT
The paper outlines the basic features of a computer program used to model CP systems of
offshore structures over a 15 year period. The ABSTRACT
program is based on the Boundary Element
Method (BEM) and utilises time dependent electrochemical boundary conditions obtained
from extensive field tests and inspection data from real structures. A large variety of case
studies are reviewed, covering such aspects as local protection in complex areas, effects of
uneven anode distribution, ohmic potential drop in the metal structures, effects of various
integrityhybrid
management
strategy
has drain
been todeveloped
forAn
pipelines
gas,
coating An
philosophies,
CP systems
and current
subsea wells.
extract ofcarrying
the
experience gained
the modelling
studies
formulated.
condensate/oil
andfrom
water.
The strategy
is isbased
on identification of corrosion related failure
modes, risk assessment, and application of risk reducing methods in terms of corrosion control,
monitoring and inspection. Modeling of multiphase flow, CO2 corrosion and associated
INTRODUCTION
probability distributions along the pipeline play key roles in the risk assessment. Examples of
applications
are presented.
Since the beginning of the 1980’ies computer modelling of CP system performance has been
a key service activity at CorrOcean’s materials department. In co-operation with Conoco, a
Key
words:program
C-Mn was
steel,
oil andwith
gasthe
production,
pipelines,the
CO
corrosion model,
computer
designed
purpose of simulating
CP
of real, limit state
2, performance
large offshore
with realistic boundary conditions, i.e. the variation of the current
design,
integritystructures
management.
density and potential with time at the steel and the anode surfaces. Over a time period of
about 15 years a large number of studies have been carried out, reflecting the continuous
development in the offshore structures used for oil and gas production. The purpose of the
INTRODUCTION
present paper is to summarise some of the experience gained in the field of CP modelling of
offshore structures. This experience is related to the type of problems attacked, the program
itself, and also to the requirements for human resources related to ruining and maintaining
New
pipelines
increasingly being designed to limit state criteria1. The
computer
programs
of thisare
kind.
driving force in
this process is the potential cost savings obtained from reduced wall thickness. The reduction in
wall thickness, however, offer no latitude for deviations beyond the design corrosion expectations.
MODELLING
This increases the requirements
to efficientAPPROACH
corrosion management. For old pipelines, based on
traditional design methods, the excess wall thickness may offer some additional safety within the
design lifetime. The advances within the oil and gas technology often favour continued production
The computer
beyond
the designprogram
lifetime, and extension of the pipeline life may become relevant. Again,
efficient
corrosion
management may become an important issue.
The CP computer modelling program used at our company since the early 80’s is known as
the SEACORIUCP program. It is based on the Boundary Element Method (BEM) and the
order to meet
these challenges
a strategy
forcarried
pipeline
integrity
is
BEASYIntechnology,
but considerable
development
had to be
out to
be able tomanagement
handle
the non-linear
and time isdependent
conditions of
experienced
withtool
CP for
systems
in
proposed.
The strategy
based onboundary
the development
an efficient
establishing
a pipeline
corrosion model. This model then forms
the basis for evaluations related to the need for corrosion
Copyright
control, monitoring and inspection. An essential tool in these evaluations is risk analysis. The
present paper describes the ideas and the methods applied to develop the pipeline integrity
management strategy based on internal corrosion as the dominant failure mode.
Examples of applications are presented.
@1999 by NACE international. Requests for permission to publish this manuscript in any form, in parl or in whole must be made in writing to NACE
International, Conferences Divieion, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in this
paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in the U.S.A.
THE PIPELINE CORROSION MODEL
The approach for establishing a corrosion model for the entire pipeline is illustrated
schematically in figure 1. The model consists of multiphase flow module, a water property
module, a pH module and a point corrosion model.
Multiphase flow
Estimation of flow characteristics in three phase flow (gas, oil and water) is today
routinely simulated by the use of computer based simulation programs like OLGA2. The output
from such calculations contains information of great value for corrosion evaluations such as the
total pressure profile, the temperature profile, the condensation rates of water and hydrocarbons,
the flow regime, and the velocity and holdup of each of the phases. The flow regime and the phase
velocities may change considerably with the pipeline inclination angle and it is therefore very
important to have a geometric model of the pipeline reflecting the true variation of the pipeline
inclination angle.
The water phase
In a three phase system of gas, liquid hydrocarbons and water, the water may mix with
the liquid hydrocarbon to form a dispersed phase or it may exist as a separate phase at the bottom
of the pipe. A figure for the probability of water being separated can be obtained by analysing the
results from the three phase numerical flow simulations, or from a two phase flow calculation in
combination with the method of Wicks & Fraser3.
pH
The pH is a complex function of several parameters, like the CO2 partial pressure, the
temperature and the content of ions in the water phase. The Fe2+ content, which is a result of the
corrosion process itself, has a particular strong influence on the pH in condensed water. The pH
can be calculated from the ion concentrations using equations describing the chemical equilibria
involved4, but empirical relations between the pH and the Fe2+ content are also used when
appropriate. Since the pH may change as a result of the corrosion process, the corrosion rate has to
be calculated in a forward stepping approach down the pipeline.
The point corrosion model
Two corrosion models have been included in the corrosion analysis program. The first
one is the model as it has been presented in its latest revision of 1995, jointly by Shell and the
Norwegian Institute of Energy Technology (IFE)5. The second one is the model recommended by
NORSOK.4 Both models are so-called point corrosion models, in the sense that they provide a
single value for the corrosion rate based on a set of values for the input data such as the
temperature, the CO2 partial pressure, the pH, the flow rate or wall shear stress, the glycol content
and the inhibitor performance. The corrosion profiles are obtained by applying a point corrosion
model to the various positions along the pipeline. In this process a particular problem arises
related to the flow conditions. Both models are largely based on one-phase laboratory data, such
that there is no obvious relation between the model flow parameter and the multiphase flow data.
Special routines have been designed to handle this problem.
A STRATEGY FOR PIPELINE INTEGRITY MANAGEMENT
Design phase
A strategy for pipeline integrity management to be considered in the design phase may
include the following items:
•
•
•
•
•
•
Identification of the failure modes for internal corrosion
Deterministic corrosion model for a pipeline, identification of critical locations
Establish a probability model for the different corrosion forms
Risk analysis related to the different failure modes
Evaluation of different means to reduce the risk, based on corrosion control, monitoring and
inspection
Recommended plan for corrosion control, monitoring and inspection
Identification of the failure modes for internal corrosion. Corrosion related failure modes
have to be identified based on the most likely corrosion forms that can occur in the pipeline. Such
corrosion forms comprise general corrosion, longitudinal grooving, pitting, weld corrosion and
mesa corrosion. For each corrosion form one may define a critical depth or critical wall thickness
reduction. Such critical depths are given in guidelines like the ASME B31G6. Here, one may find
equations relating the critical depth, the typical length of the attack and the maximum allowable
hoop stress.
Deterministic corrosion model for a pipeline, identification of critical locations.
Corrosion models are established for the entire pipeline, using the calculation approach as
described above, and shown in Figure 1. Based on the actual conditions, different models may
have to be established for the various corrosion forms. The result provides two important pieces of
information: The maximum deterministic corrosion rates, and the positions were they occurs. The
first information is taken further into the risk analysis, while the critical position identification is
important for corrosion monitoring evaluation.
Establish a probability model for the different corrosion forms. The deterministic
corrosion models form the basis for establishing a probabilistic description of the maximum
corrosion rates. Such a probabilistic description is illustrated in figure 2. In the probabilistic
approach the deterministic value corresponds to the mean value. The scatter around this value is
reflecting the model uncertainty as evident in the experimental data to which the corrosion models
have been fitted5. The probability distribution shown in figure 2 is the log-normal distribution.
Risk analysis related to the different failure modes. Risk is defined from the formula:
Risk = probability of occurrence x consequence
Here, the probability of occurrence is defined as the probability related to corrosion
induced failure modes. This probability can be calculated from the probability models for the
various corrosion forms, as illustrated in figure 2. The approach is as follows. Assume that we
have a cumulative probability distribution F(CR) of the maximum corrosion rate CR The critical
corrosion depth for a corrosion form is dcrit . Over a lifetime L we may then define a critical
corrosion rate CRcrit from the following expression:
CRcrit = dcrit/L
(1)
The probability of occurrence is defined as follows:
P(CR > CRcrit) = 1 - F(CRcrit)
(2)
The consequence can be expressed in terms of cost figures, personal hazard or
environmental impact.
The presentation of probability distributions for the corrosion attacks allows the
application of limit state approaches, as presented in the following example:
For pipelines where hoop stress together with corrosion allowance are the dimensioning
criteria determining the necessary wall thickness, the hoop stress equation can be combined with
the formulae of ASME B31G 6, the modified ASME B31G or the Shell-92 model 7, to give a
presentation of the hoop stress capacity as a function of; corrosion attack depth, corrosion attack
length, inhibitor efficiency, yield- or tensile strength, wall thickness, and outer diameter.
The parameters are then treated as variables within their known probability distributions,
and by applying a probability simulation model e.g. MonteCarlo simulation, this will give an
expression of the probability distribution for the risk of exceeding the hoop stress capacity of the
pipeline. By applying this approach, the known conservatism in the traditional pipeline design is
avoided and a potential reduction in wall thickness results.
Evaluation of different means to reduce the risk based on corrosion control, monitoring
and inspection. This activity describes the various methods available for corrosion control by use
of chemicals, like film forming inhibitors and pH stabilizers. The sensitivity to variations in e.g.
the inhibitor performance can be obtained from a sensitivity study in the risk analysis, and a
minimum performance requirements to the inhibitor can be defined. Methods or combinations of
methods for corrosion monitoring are evaluated. Monitoring can be based on weight loss, ER- and
LPR-probes, FSM8, ultrasonic equipment, Fe-counts, inhibitor residual analysis etc. Inspection
methods comprise intelligent pigging and spot NDT. Case studies can be carried out using costbenefit analysis to obtain combinations of corrosion control, monitoring and inspection that
reduces the risk to an acceptable level at the lowest possible costs.
A recommended plan for corrosion control. monitoring and inspection. Based on the
case studies a recommended plan for corrosion control, monitoring and inspection can be
established. The elements of such a plan can be:
•
•
•
•
•
•
Requirements to inhibitor application
Requirements to field testing of inhibitors
The need for cleaning pigs
Monitoring equipment, types, numbers, locations
Frequency of intelligent pigging
Frequency and locations for spot NDT
Operational phase
The working strategy in the operational phase may to some extent resemble the strategy
in the design phase, but the practical performance has to be influenced by the presence of actual
operational experience, actual process data, monitoring data and eventually inspection data.
The following issues have to be addressed:
•
•
•
•
Analysis of process, monitoring and inspection data
Calculation of a pipeline corrosion model based on actual process data
Revision of risk analysis
Revision of plan for corrosion control, monitoring and inspection
EXAMPLES OF APPLICATION
Pipeline corrosion models have been worked out for quite a number of submarine
pipelines, covering a wide variety of operational conditions. The pipelines may be grouped in
three categories: Dry gas pipelines, wet gas pipelines and pipelines carrying a well fluid composed
of gas, oil and produced water. Dry gas pipelines do not carry a corrosive fluid, but a corrosive
fluid may form due to glycol condensing in the pipeline. The glycol absorbs some water from the
dry gas and then becomes a weakly corrosive fluid. Upsets in the drying process may lead to
temporary enhancements in the water content. For wet gas systems one will normally have a
variable pH down the pipeline due to condensation of water with low pH. The water wetting is a
second important factor. For gas/oil/water well fluids the water wetting is the all important factor.
The example shown here is from a wet gas study of a long pipeline. Figure 3 shows the
corrosion profile of the C-Mn pipeline without a multiphase flow calculation. The pipeline route is
very uneven, and the pipeline inclination angle varies typically between -5 and +5 degrees.
The multiphase flow calculations, figure 4, show clearly that water is separating out at
upward angles larger than about 0.5 degrees. With the information from the multiphase flow
calculations the pipeline corrosion model becomes much more complex than shown in figure 3.
Figure 5 shows a typical result for the 30 - 31 Km section of the pipeline. The upper
curve is the corrosion rate profile including flow rate variations due to the pipeline profile, but
assuming 100 % water wetting at all locations. The lower curve shows the effect of assuming 100
% water wetting only for upward inclinations larger than 0.5 degrees and 10 % for other
inclinations. This has two major implications. Firstly, the maximum corrosion rates are reduced by
about a factor of two. Secondly, the critical locations are rather narrow, which is important for a
proper location of monitoring equipment.
The probability distributions for the case are shown in figure 6. The pit/weld distribution
is shifted to larger corrosion rates because it has been observed that such localised attacks can
grow faster than predicted by the corrosion models by a factor of 2-3. This may be due to galvanic
effects in the system or a more continuous water wetting in areas with geometric disturbances.
Based on these probability distributions the probability of failure related to longitudinal grooving
is shown as a function of the time in figure 7. With a corrosion inhibitor performance of minimum
85 % the probability of failure is very low, but with a reduced inhibitor performance (70 %) or no
pH- adjusting chemicals, the probability of failure may become significant.
CONCLUSIONS
An integrity management strategy has been developed for pipelines carrying gas,
condensate/oil and water.
The strategy is based on identification of corrosion related failure modes, risk assessment,
and application of risk reducing methods in terms of corrosion control, monitoring and inspection.
Modelling of multiphase flow, CO2 corrosion and associated probability distributions
along the pipeline plays a key role in the risk assessment, and may be applied in limit state design
approaches.
Examples of application show that a pipeline corrosion model that includes multiphase
flow calculations and a true pipeline profile offer much better insight into the corrosivity of the
pipeline than a simple point corrosion model.
REFERENCES
1. DNV (1996) "Rules for Submarine Pipeline Systems" Det Norske Veritas 1996
2. Fuchs, P. and Nuland, S.: "Three Phase Modelling is a Must", Multiphase Transportation IIL
Arranged by Norwegian Petroleum Society, Rpros 20-22 September, 1992,
3. Wicks, M. and Fraser, J. P.: "Entrainment of Water by Flowing Oil", Materials Performance,
May 1975, pp 9-12.
4. NORSOK Standard M-506, Jan. 98.
5. de Waard, C., Lotz, U. and Dugstad, A.: "Influence of Liquid Flow Velocity on C02
Corrosion: A Semi-empirical Model", Paper no. 128 at NACE CORROSION '95.
6. ASME B31G (1993) "Manual for Determining the Remaining Strength of Corroded
Pipes" American Society of Mechanical Engineers, 1993.
7. D Richie, C.W.M. Voerrnans, M.H. Larsen, W.R. Vranckx, "Planning repair and
inspection of ageing corroded lines using probabilistic methods" Risk Based & Limit State
Design ~ Operation of Pipelines 20th & 21th October 1998, Aberdeen
8. Strommen, R. D., Horn, H. and Wold, K.R: Paper no 7, NACE Corrosion/92.
622
Computer Modelling of Offshore CP systems for 15 years: ”What
have we learned ?
A PIPELINE INTEGRITY MANAGEMENT STRATEGY BASED ON
MULTIPHASE FLUID FLOW
AND CORROSION MODELLING
by
Per Olav Gartland, Frode Bjoernaas and Harald Osvoll
CorrOcean ASA
Trondheim,
Norway
Per Olav
Gartland
and Jan Erik Salomonsen
CorrOcean ASA
Teglgaarden, Trondheim, Norway
ABSTRACT
The paper outlines the basic features of a computer program used to model CP systems of
offshore structures over a 15 year period. The ABSTRACT
program is based on the Boundary Element
Method (BEM) and utilises time dependent electrochemical boundary conditions obtained
from extensive field tests and inspection data from real structures. A large variety of case
studies are reviewed, covering such aspects as local protection in complex areas, effects of
uneven anode distribution, ohmic potential drop in the metal structures, effects of various
integrityhybrid
management
strategy
has drain
been todeveloped
forAn
pipelines
gas,
coating An
philosophies,
CP systems
and current
subsea wells.
extract ofcarrying
the
experience gained
the modelling
studies
formulated.
condensate/oil
andfrom
water.
The strategy
is isbased
on identification of corrosion related failure
modes, risk assessment, and application of risk reducing methods in terms of corrosion control,
monitoring and inspection. Modeling of multiphase flow, CO2 corrosion and associated
INTRODUCTION
probability distributions along the pipeline play key roles in the risk assessment. Examples of
applications
are presented.
Since the beginning of the 1980’ies computer modelling of CP system performance has been
a key service activity at CorrOcean’s materials department. In co-operation with Conoco, a
Key
words:program
C-Mn was
steel,
oil andwith
gasthe
production,
pipelines,the
CO
corrosion model,
computer
designed
purpose of simulating
CP
of real, limit state
2, performance
large offshore
with realistic boundary conditions, i.e. the variation of the current
design,
integritystructures
management.
density and potential with time at the steel and the anode surfaces. Over a time period of
about 15 years a large number of studies have been carried out, reflecting the continuous
development in the offshore structures used for oil and gas production. The purpose of the
INTRODUCTION
present paper is to summarise some of the experience gained in the field of CP modelling of
offshore structures. This experience is related to the type of problems attacked, the program
itself, and also to the requirements for human resources related to ruining and maintaining
New
pipelines
increasingly being designed to limit state criteria1. The
computer
programs
of thisare
kind.
driving force in
this process is the potential cost savings obtained from reduced wall thickness. The reduction in
wall thickness, however, offer no latitude for deviations beyond the design corrosion expectations.
MODELLING
This increases the requirements
to efficientAPPROACH
corrosion management. For old pipelines, based on
traditional design methods, the excess wall thickness may offer some additional safety within the
design lifetime. The advances within the oil and gas technology often favour continued production
The computer
beyond
the designprogram
lifetime, and extension of the pipeline life may become relevant. Again,
efficient
corrosion
management may become an important issue.
The CP computer modelling program used at our company since the early 80’s is known as
the SEACORIUCP program. It is based on the Boundary Element Method (BEM) and the
order to meet
these challenges
a strategy
forcarried
pipeline
integrity
is
BEASYIntechnology,
but considerable
development
had to be
out to
be able tomanagement
handle
the non-linear
and time isdependent
conditions of
experienced
withtool
CP for
systems
in
proposed.
The strategy
based onboundary
the development
an efficient
establishing
a pipeline
corrosion model. This model then forms
the basis for evaluations related to the need for corrosion
Copyright
control, monitoring and inspection. An essential tool in these evaluations is risk analysis. The
present paper describes the ideas and the methods applied to develop the pipeline integrity
management strategy based on internal corrosion as the dominant failure mode.
Examples of applications are presented.
@1999 by NACE international. Requests for permission to publish this manuscript in any form, in parl or in whole must be made in writing to NACE
International, Conferences Divieion, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in this
paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in the U.S.A.
THE PIPELINE CORROSION MODEL
The approach for establishing a corrosion model for the entire pipeline is illustrated
schematically in figure 1. The model consists of multiphase flow module, a water property
module, a pH module and a point corrosion model.
Multiphase flow
Estimation of flow characteristics in three phase flow (gas, oil and water) is today
routinely simulated by the use of computer based simulation programs like OLGA2. The output
from such calculations contains information of great value for corrosion evaluations such as the
total pressure profile, the temperature profile, the condensation rates of water and hydrocarbons,
the flow regime, and the velocity and holdup of each of the phases. The flow regime and the phase
velocities may change considerably with the pipeline inclination angle and it is therefore very
important to have a geometric model of the pipeline reflecting the true variation of the pipeline
inclination angle.
The water phase
In a three phase system of gas, liquid hydrocarbons and water, the water may mix with
the liquid hydrocarbon to form a dispersed phase or it may exist as a separate phase at the bottom
of the pipe. A figure for the probability of water being separated can be obtained by analysing the
results from the three phase numerical flow simulations, or from a two phase flow calculation in
combination with the method of Wicks & Fraser3.
pH
The pH is a complex function of several parameters, like the CO2 partial pressure, the
temperature and the content of ions in the water phase. The Fe2+ content, which is a result of the
corrosion process itself, has a particular strong influence on the pH in condensed water. The pH
can be calculated from the ion concentrations using equations describing the chemical equilibria
involved4, but empirical relations between the pH and the Fe2+ content are also used when
appropriate. Since the pH may change as a result of the corrosion process, the corrosion rate has to
be calculated in a forward stepping approach down the pipeline.
The point corrosion model
Two corrosion models have been included in the corrosion analysis program. The first
one is the model as it has been presented in its latest revision of 1995, jointly by Shell and the
Norwegian Institute of Energy Technology (IFE)5. The second one is the model recommended by
NORSOK.4 Both models are so-called point corrosion models, in the sense that they provide a
single value for the corrosion rate based on a set of values for the input data such as the
temperature, the CO2 partial pressure, the pH, the flow rate or wall shear stress, the glycol content
and the inhibitor performance. The corrosion profiles are obtained by applying a point corrosion
model to the various positions along the pipeline. In this process a particular problem arises
related to the flow conditions. Both models are largely based on one-phase laboratory data, such
that there is no obvious relation between the model flow parameter and the multiphase flow data.
Special routines have been designed to handle this problem.
A STRATEGY FOR PIPELINE INTEGRITY MANAGEMENT
Design phase
A strategy for pipeline integrity management to be considered in the design phase may
include the following items:
•
•
•
•
•
•
Identification of the failure modes for internal corrosion
Deterministic corrosion model for a pipeline, identification of critical locations
Establish a probability model for the different corrosion forms
Risk analysis related to the different failure modes
Evaluation of different means to reduce the risk, based on corrosion control, monitoring and
inspection
Recommended plan for corrosion control, monitoring and inspection
Identification of the failure modes for internal corrosion. Corrosion related failure modes
have to be identified based on the most likely corrosion forms that can occur in the pipeline. Such
corrosion forms comprise general corrosion, longitudinal grooving, pitting, weld corrosion and
mesa corrosion. For each corrosion form one may define a critical depth or critical wall thickness
reduction. Such critical depths are given in guidelines like the ASME B31G6. Here, one may find
equations relating the critical depth, the typical length of the attack and the maximum allowable
hoop stress.
Deterministic corrosion model for a pipeline, identification of critical locations.
Corrosion models are established for the entire pipeline, using the calculation approach as
described above, and shown in Figure 1. Based on the actual conditions, different models may
have to be established for the various corrosion forms. The result provides two important pieces of
information: The maximum deterministic corrosion rates, and the positions were they occurs. The
first information is taken further into the risk analysis, while the critical position identification is
important for corrosion monitoring evaluation.
Establish a probability model for the different corrosion forms. The deterministic
corrosion models form the basis for establishing a probabilistic description of the maximum
corrosion rates. Such a probabilistic description is illustrated in figure 2. In the probabilistic
approach the deterministic value corresponds to the mean value. The scatter around this value is
reflecting the model uncertainty as evident in the experimental data to which the corrosion models
have been fitted5. The probability distribution shown in figure 2 is the log-normal distribution.
Risk analysis related to the different failure modes. Risk is defined from the formula:
Risk = probability of occurrence x consequence
Here, the probability of occurrence is defined as the probability related to corrosion
induced failure modes. This probability can be calculated from the probability models for the
various corrosion forms, as illustrated in figure 2. The approach is as follows. Assume that we
have a cumulative probability distribution F(CR) of the maximum corrosion rate CR The critical
corrosion depth for a corrosion form is dcrit . Over a lifetime L we may then define a critical
corrosion rate CRcrit from the following expression:
CRcrit = dcrit/L
(1)
The probability of occurrence is defined as follows:
P(CR > CRcrit) = 1 - F(CRcrit)
(2)
The consequence can be expressed in terms of cost figures, personal hazard or
environmental impact.
The presentation of probability distributions for the corrosion attacks allows the
application of limit state approaches, as presented in the following example:
For pipelines where hoop stress together with corrosion allowance are the dimensioning
criteria determining the necessary wall thickness, the hoop stress equation can be combined with
the formulae of ASME B31G 6, the modified ASME B31G or the Shell-92 model 7, to give a
presentation of the hoop stress capacity as a function of; corrosion attack depth, corrosion attack
length, inhibitor efficiency, yield- or tensile strength, wall thickness, and outer diameter.
The parameters are then treated as variables within their known probability distributions,
and by applying a probability simulation model e.g. MonteCarlo simulation, this will give an
expression of the probability distribution for the risk of exceeding the hoop stress capacity of the
pipeline. By applying this approach, the known conservatism in the traditional pipeline design is
avoided and a potential reduction in wall thickness results.
Evaluation of different means to reduce the risk based on corrosion control, monitoring
and inspection. This activity describes the various methods available for corrosion control by use
of chemicals, like film forming inhibitors and pH stabilizers. The sensitivity to variations in e.g.
the inhibitor performance can be obtained from a sensitivity study in the risk analysis, and a
minimum performance requirements to the inhibitor can be defined. Methods or combinations of
methods for corrosion monitoring are evaluated. Monitoring can be based on weight loss, ER- and
LPR-probes, FSM8, ultrasonic equipment, Fe-counts, inhibitor residual analysis etc. Inspection
methods comprise intelligent pigging and spot NDT. Case studies can be carried out using costbenefit analysis to obtain combinations of corrosion control, monitoring and inspection that
reduces the risk to an acceptable level at the lowest possible costs.
A recommended plan for corrosion control. monitoring and inspection. Based on the
case studies a recommended plan for corrosion control, monitoring and inspection can be
established. The elements of such a plan can be:
•
•
•
•
•
•
Requirements to inhibitor application
Requirements to field testing of inhibitors
The need for cleaning pigs
Monitoring equipment, types, numbers, locations
Frequency of intelligent pigging
Frequency and locations for spot NDT
Operational phase
The working strategy in the operational phase may to some extent resemble the strategy
in the design phase, but the practical performance has to be influenced by the presence of actual
operational experience, actual process data, monitoring data and eventually inspection data.
The following issues have to be addressed:
•
•
•
•
Analysis of process, monitoring and inspection data
Calculation of a pipeline corrosion model based on actual process data
Revision of risk analysis
Revision of plan for corrosion control, monitoring and inspection
EXAMPLES OF APPLICATION
Pipeline corrosion models have been worked out for quite a number of submarine
pipelines, covering a wide variety of operational conditions. The pipelines may be grouped in
three categories: Dry gas pipelines, wet gas pipelines and pipelines carrying a well fluid composed
of gas, oil and produced water. Dry gas pipelines do not carry a corrosive fluid, but a corrosive
fluid may form due to glycol condensing in the pipeline. The glycol absorbs some water from the
dry gas and then becomes a weakly corrosive fluid. Upsets in the drying process may lead to
temporary enhancements in the water content. For wet gas systems one will normally have a
variable pH down the pipeline due to condensation of water with low pH. The water wetting is a
second important factor. For gas/oil/water well fluids the water wetting is the all important factor.
The example shown here is from a wet gas study of a long pipeline. Figure 3 shows the
corrosion profile of the C-Mn pipeline without a multiphase flow calculation. The pipeline route is
very uneven, and the pipeline inclination angle varies typically between -5 and +5 degrees.
The multiphase flow calculations, figure 4, show clearly that water is separating out at
upward angles larger than about 0.5 degrees. With the information from the multiphase flow
calculations the pipeline corrosion model becomes much more complex than shown in figure 3.
Figure 5 shows a typical result for the 30 - 31 Km section of the pipeline. The upper
curve is the corrosion rate profile including flow rate variations due to the pipeline profile, but
assuming 100 % water wetting at all locations. The lower curve shows the effect of assuming 100
% water wetting only for upward inclinations larger than 0.5 degrees and 10 % for other
inclinations. This has two major implications. Firstly, the maximum corrosion rates are reduced by
about a factor of two. Secondly, the critical locations are rather narrow, which is important for a
proper location of monitoring equipment.
The probability distributions for the case are shown in figure 6. The pit/weld distribution
is shifted to larger corrosion rates because it has been observed that such localised attacks can
grow faster than predicted by the corrosion models by a factor of 2-3. This may be due to galvanic
effects in the system or a more continuous water wetting in areas with geometric disturbances.
Based on these probability distributions the probability of failure related to longitudinal grooving
is shown as a function of the time in figure 7. With a corrosion inhibitor performance of minimum
85 % the probability of failure is very low, but with a reduced inhibitor performance (70 %) or no
pH- adjusting chemicals, the probability of failure may become significant.
CONCLUSIONS
An integrity management strategy has been developed for pipelines carrying gas,
condensate/oil and water.
The strategy is based on identification of corrosion related failure modes, risk assessment,
and application of risk reducing methods in terms of corrosion control, monitoring and inspection.
Modelling of multiphase flow, CO2 corrosion and associated probability distributions
along the pipeline plays a key role in the risk assessment, and may be applied in limit state design
approaches.
Examples of application show that a pipeline corrosion model that includes multiphase
flow calculations and a true pipeline profile offer much better insight into the corrosivity of the
pipeline than a simple point corrosion model.
REFERENCES
1. DNV (1996) "Rules for Submarine Pipeline Systems" Det Norske Veritas 1996
2. Fuchs, P. and Nuland, S.: "Three Phase Modelling is a Must", Multiphase Transportation IIL
Arranged by Norwegian Petroleum Society, Rpros 20-22 September, 1992,
3. Wicks, M. and Fraser, J. P.: "Entrainment of Water by Flowing Oil", Materials Performance,
May 1975, pp 9-12.
4. NORSOK Standard M-506, Jan. 98.
5. de Waard, C., Lotz, U. and Dugstad, A.: "Influence of Liquid Flow Velocity on C02
Corrosion: A Semi-empirical Model", Paper no. 128 at NACE CORROSION '95.
6. ASME B31G (1993) "Manual for Determining the Remaining Strength of Corroded
Pipes" American Society of Mechanical Engineers, 1993.
7. D Richie, C.W.M. Voerrnans, M.H. Larsen, W.R. Vranckx, "Planning repair and
inspection of ageing corroded lines using probabilistic methods" Risk Based & Limit State
Design ~ Operation of Pipelines 20th & 21th October 1998, Aberdeen
8. Strommen, R. D., Horn, H. and Wold, K.R: Paper no 7, NACE Corrosion/92.
