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A PIPELINE INTEGRITY MANAGEMENT STRATEGY BASED ON MULTIPHASE FLUID FLOW & CORROSION MODELLING

Per Olav Gartland and Jan Erik Salomonsen CorrOcean ASA

Teglgaarden, Trondheim, Norway

ABSTRACT 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. Modeling of multiphase flow, CO2 corrosion and associated probability distributions along the pipeline play key roles in the risk assessment. Examples of applications are presented.

Key words: C-Mn steel, oil and gas production, pipelines, CO2 corrosion model, limit state design, integrity management.

INTRODUCTION

New pipelines are increasingly being designed to limit state criteria 1. The 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. This increases the requirements to efficient 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 beyond the design lifetime, and extension of the pipeline life may become relevant. Again, efficient corrosion management may become an important issue.

In order to meet these challenges a strategy for pipeline integrity management is

proposed. The strategy is based on the development of an efficient tool for establishing a pipeline corrosion model. This model then forms the basis for evaluations related to the need for corrosion 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.

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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 Shell 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.

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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:

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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 stabilisers. 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 cost-benefit 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

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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.

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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 III, Arranged by Norwegian Petroleum Society, Rrros 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 CO2 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. Voermans, 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.

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1. x

Input Parameters

T(x), P(x)and

pCO2(x)

MultiphaseFluidFlow

Water Phase pH

Corrosion Model

Corrosion RateCR(x)

CORPOS Flowchart

Distance m Figure 1. Flowchart showing the process of establishing a pipeline corrosion model

log-Normal probability

0

0,1

0,2

0,3

0,4

0,5

0,6

0,7

0,8

0,9

1

0 0,5 1 1,5 2 2,5 3 3,5 4

x

Pro

babi

lity

dens

ity o

r pr

obab

ility

Probability densityCumulative probability

Figure 2. The lognormal probability distribution with a mean at x=1, and standard deviation of 0.3.

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Wet gas study - horisontal pipe

0,0

0,5

1,0

30 40 50 60 70 80 90 100

Distance along pipeline

Co

rro

sio

n r

ate(

mm

/yea

r) pHinit = 5.7pHinit = 3.6

Film inhibitor efficiency = 85 %

Figure 3. Corrosion rate profile of the wet gas study without a multiphase flow calculation

Wet gas study

0

0,05

0,1

0,15

0,2

0,25

0,3

0,35

-6 -4 -2 0 2 4 6 8 10

Inclination (Degrees)

Hol

dup

(-)

HOLHLHOLWT

Figure 4. Multiphase flow calculations of the wet gas study showing water holdup (HOLWT) and hydrocarbon liquid holdup (HOLHL) as a function of the pipeline inclination angle.

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Wet gas studyTrue pipeline profile

0,0

0,1

0,2

0,3

0,4

0,5

30 30,1 30,2 30,3 30,4 30,5 30,6 30,7 30,8 30,9 31

Position (km)

Co

rr. r

ate

(mm

/yea

r) o

r an

gle

(d

egre

es)

Inhibitor efficiency = 85 %

100 % water wetting at all pipe positions

Figure 5. Corrosion rate profiles for the wet gas study. Upper curve asssumes 100 % water wetting while lower curve assumes 100 % water wetting only for inclination angles larger than 0.5 degrees and 10 % otherwise.

Wet gas studypH = 3.5 and 85 % inhibitor efficiency

0

0,5

1

1,5

2

2,5

3

3,5

4

0 0,5 1 1,5 2 2,5 3

Corrosion rate (mm/year)

Pro

babi

lity

dens

ity

Pits

Longitudinal grooves

Figure 6. Probability distributions for the wet gas case.

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Wet gas study30 - 31 km

0,000

0,050

0,100

0,150

0,200

0,250

0,300

0 5 10 15 20 25

Time (years)

Pro

bab

ility

low pH 85%inhibhigh pH 85%inhibhigh pH 70%inhib

Figure 7. Probability of failure for the wet gas case.