Internal Corrosion in Dry Gas Pipelines During Upsets L52079e

Catalog No. L5XXXX

INTERNAL CORROSION IN DRY GAS PIPELINES DURING UPSETS

FINAL REPORT

Contract GRI - 8292

CASA project 1395

Prepared for theCorrosion Technical Committee

ofPipeline Research Council International, Inc.

Prepared by the company:CorrOcean ASA, Norway

Author:Per Olav Gartland

Publication Date:Rev. 04 March 2005

CorrOcean ASADOCUMENT TITLE:

DOCUMENT No.:

INTERNAL CORROSION IN DRY GAS PIPELINES DURING UPSETS – FINAL REPORT1395-002

PAGE : 2 of 54REV. : 04DATE : 17 March 05

“This report is furnished to Pipeline Research Council International, Inc. (PRCI) under the terms of GRI - 8292, between GRI and CorrOcean ASA, Trondheim, Norway. The contents of this report are published as received from CorrOcean ASA. The opinions, findings, and conclusions expressed in the report are those of the authors and not necessarily those of GRI or PRCI, its member companies, or their representatives. Publication and dissemination of this report by PRCI should not be considered an endorsement by PRCI or CorrOcean ASA, or the accuracy or validity of any opinions, findings, or conclusions expressed herein.

In publishing this report, PRCI makes no warranty or representation, expressed or implied, with respect to the accuracy, completeness, usefulness, or fitness for purpose of the information contained herein, or that the use of any information, method, process, or apparatus disclosed in this report may not infringe on privately owned rights. PRCI assumes no liability with respect to the use of , or for damages resulting from the use of, any information, method, process, or apparatus disclosed in this report.

The text of this publication, or any part thereof, may not be reproduced or transmitted in any form by any means, electronic or mechanical, including photocopying, recording, storage in an information retrieval system, or otherwise, without the prior, written approval of PRCI.”

Pipeline Research Council International Catalog No. L5XXXX

Copyright, 2005All Rights Reserved by Pipeline Research Council International, Inc.

PRCI Reports are Published by Technical Toolboxes, Inc.

3801 Kirby Drive, Suite 340

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ACKNOWLEDGEMENTThe author gratefully acknowledges the contributions and support from the CorrOcean employees Nguyen Bich and Tore Landmark in carrying out the activities of the project.

It is also a pleasure to acknowledge the Ad Hoc Committee Chairman Stein Olsen, Statoil, for the initiative and support that made the project possible.


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EXECUTIVE SUMMARY

The main objective of the present project has been to develop a computer program, named GasCor, that can be used to estimate the corrosion related risk of operating dry gas pipelines under conditions where upsets may occur. An upset is here considered as an event that may cause corrosive liquid water to be present in some part of the pipeline within a certain time period. The computer program is meant to be a screening tool that can assist in the evaluation of the severity of the corrosion rate as well as in the location of the positions where the most significant corrosion is to be expected. The latter may be of importance for the planning of an inspection program.

The project work has been organized in four activities:

1) Identification of critical parameters and corrosion mechanisms2) Selection and modification of corrosion models3) Selection of risk analysis methods4) Creation of software

As an introduction to activity 1 several pipeline operators were contacted and information about typical upset conditions and the results of cleaning operations were gathered. Based on this information three main types of upsets were defined, depending on the Water type: Water type 1: No free liquid water running in the pipe, but due to

increased water content in the gas some water may be absorbed in an absorbent being present in the pipe.

Water type 2: Water is condensing in the pipe. Water type 3: There is free liquid water at the inlet of the pipe.

For Water type 1 three different absorbents were considered: Glycol (absorb water at any humidity) Sand (absorb water at relative humidity > 60 %) Salt (absorb water at relative humidity > 30 %)

For Water type 2 & 3 the presence or not of solids (sand or salt) was considered.

For all upset types the wetting time is the most important parameter for the corrosivity, and formulas for the wetting time were established. These formulas were obtained from:

Calculation of the rate of water absorption/condensation and the rate of evaporation after the upset

Using the flow simulation program OLGAS 2000 to study the transport of liquid water as a thin film and water holdup at large inclination angles.

The wetting time was observed to be a function of such parameters as the actual temperature, the actual pressure, the dew point temperature of the gas, the gas flow rate and the diameter of the pipe. The critical inclination angle for massive water holdup was found to be a complex function of the water flow rate, the actual pressure, the diameter of the pipe and the gas flow velocity.


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The corrosion model chosen was the one known as the Shell 95 model. This model is described by a set of equations depending on the following parameters:

The actual temperature The CO2 partial pressure The flow velocity of the liquid water phase The hydraulic diameter of the liquid water phase The actual pH

The actual pH was assumed to be the value calculated from the CO2 value given and the water being saturated with Fe2+, except for a distance 100 m downstream of a condensation point where the pH was assumed to be free of any ions.

For the risk analysis two different options were selected: Based on the ASME B-31G code Based on the DnV RP-F101 code

The computer program was designed and implemented using Windows Visual Basic Developer Studio 6.0. The program system consists of two main components: A user interface and a calculation engine. Through the user interface parameters are fed to the engine. The engine checks the validity of the parameters and then calculates the profiles on the following parameters: The temperature, the pressure, the wetting time and the corrosion rate. These calculated profiles are returned to the interface and may be displayed graphically or in a table. There is a print option for the results as well as for the input parameters. An established model with a complete set of input parameters may be saved on file.

The computer program can handle a single pipe as well as a system of pipes. This makes it possible to study the effect of upsets in a single pipe branch on the corrosion conditions downstream of the upset pipe branch when there are other branching pipes downstream being operated under normal conditions.

The detailed elevation profile of the pipe or pipe system is not a part of the required input. The pipes are assumed to be horizontal except for one defined location per pipe where a critical uphill section is allowed to be present. The critical angle is calculated by the program based on the set of input data. If the user verifies that the pipe or pipe system considered has a local inclination angle larger than the critical one at the location considered, the calculation engine will assume a massive holdup of water at the location. Massive holdup areas are observed to be locations with particularly long wetting times and hence maxima in the corrosion rate profiles.

In addition to the corrosion rate aspect there is an option in the program for risk analysis, where the corrosion risk is analyzed at selected locations of the pipeline system. The output from the risk analysis is the critical corrosion depth and the maximum number of years of safe operation with the actual upset conditions.


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With the present report and the associated computer program the main objectives of the project have been fulfilled. It can thus be stated that the project has been completed with success.


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Table of contents:

ACKNOWLEDGEMENT 3

1 INTRODUCTION 9

2 GENERAL REQUIREMENTS TO A CORROSION MODEL 10

3 WETTING CONDITIONS IN A SINGLE GAS PIPELINE 113.1 Water conditions 113.2 Absorbent 113.3 Combined water and absorbent upsets 133.4 Wetting time 13

4 FREE WATER BEHAVIOUR IN A SINGLE PIPELINE 154.1 Water flow rates 15

4.1.1 Condensing water 154.1.2 Free water at the inlet 16

4.2 Water flow and holdup 164.3 The dynamics of a massive holdup situation 194.4 Water film properties without massive holdup 21

5 REMOVAL OF FREE WATER AFTER UPSET 235.1 Thin water film only 23

5.1.1 No solids in the pipeline 235.1.2 Free water and solids present 28

5.2 Massive holdups and no solids 315.3 Massive holdups and solids 32

6 WATER ABSORPTION AND REMOVAL WITHOUT FREE WATER 336.1 Glycol 336.2 Sand or salt without glycol 356.3 Sand or salt with glycol 37

7 TEMPERATURE AND PRESSURE PROFILES 38

8 THE CHOSEN POINT CORROSION MODEL 398.1 The Shell95 corrosion model 398.2 Flow effects and mass transport limitations 40

8.2.1 Thin water films 408.2.2 Massive water holdup 408.2.3 Water absorbed in solids 40

8.3 Effects of glycol 418.4 The pH of the water film 41

9 CORROSION MODEL INPUT VARIABLES 43

10 MODEL APPLICATION 44


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10.1 Water upset type 1 4410.2 Water upset type 2 & 3 44

11 REQUIRED MODIFICATIONS FOR A PIPELINE SYSTEM 45

12 LIST OF SYMBOLS USED IN THE CORROSION MODEL 47

13 RISK ANALYSIS 5013.1 General 5013.2 Definitions 5013.3 ASME B31G 5013.4 DnV RP-F101 52

14 references 54


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1 INTRODUCTION

CorrOcean ASA is running the GRI-supported project: ”Internal Corrosion in Dry Gas Systems During Upsets”. The project has been initiated by the PRCI Committee on Corrosion and Inspection, and the plan for the project was presented at the PRCI Committee meeting in Toronto on May 8, 2001.

The objectives of the project are as follows:

“To establish a methodology and a computer program that can be used to assess the corrosion related risk of pipeline failure due to internal upsets in dry gas pipelines”.

The project action plan includes four main tasks:

1. Identification of critical parameters and corrosion mechanisms2. Selection and modification of corrosion models3. Selection of risk analysis methods4. Creation of software

This document is the final and only report of the project.

In the first task information has been gathered through questionnaires, visits to operators, analysis of failures and upset conditions. This information is confidential and is not presented in this report. However, the information gathered has been of value for the planning of the other tasks. The present report gives a systematic description of the conditions that may lead to corrosion and a description of methods that allow modelling of these conditions, through the chapters 2 to 11. The risk aspect is covered in chapter 12.

The result of task four is the computer program GasCor. It is not explained or discussed in this report since it is considered self-explaining through its user interface and user guidance.


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2 GENERAL REQUIREMENTS TO A CORROSION MODEL

Based on the knowledge of operation of dry gas pipelines, including some direct input from operators, it was concluded that a corrosion model for dry gas pipeline upsets must satisfy the following:

1. The corrosion model shall only include effects that can be modeled quantitatively.

2. The modeling program must be capable of handling a system of pipelines with different conditions of the gas transported (several suppliers/sources into a main transport pipeline).

3. The modeling program shall be restricted to a gas concentration ratio CO2/H2S > 20, i.e. pure H2S model situations shall not be included.

4. The model must be able to handle a water content ranging from dry gas to free water at the inlet. Free water may be present when the gas is retrieved from underground storage.

5. The model must be able to included effects of solids remaining in the pipeline. These solids can be sand, mud and corrosion products, and for storage gas also salt coming with the water.

6. The model shall be able to handle temperature and pressure variations along the pipeline or system of pipelines.

7. The model shall be able to quantify the time dependent water wetting situation, in the presence of massive water hold-up, sand and salt.

8. It shall be possible to run the model with limited input data. a. For pre-storage pipelines such data will typically be:

i. Frequency of upsetii. Typical duration of each upsetiii. Flow rate of gasiv. Geometry of pipe or pipe systemv. Temperature at inletvi. Pressure at inletvii. Dew point temperature of the gas at inletviii. Presence of solids in the pipelineix. Maximum uphill inclination of the pipeline

b. For storage pipelines some additional information may be required:i. Quantity of free water at inletii. Salt content of the free water at inlet

The model to be developed must satisfy these general requirements. We shall now go more deeply into some of these requirements, and see if there is sufficient knowledge for a model description satisfying the general requirements. Even though the model shall be able to handle a system of pipelines, we shall start with some considerations for a single pipeline. Later on we shall see how the single pipeline model can be modified to serve a system of pipelines.


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3 WETTING CONDITIONS IN A SINGLE GAS PIPELINE

3.1 Water conditions

A corrosive situation in a single gas pipeline requires the presence of liquid water. We may distinguish between three types of upsets with respect to the source and quantity of water.

Water type 1

In this type of upset the dew point temperature of the gas is higher than specified, but not so high that free water will condense. Water may, however, be absorbed by a glycol phase or by solids/salts and thereby creating a corrosive phase. The upset type is defined through the following:

Tamb > Tdew > Tspec

Water type 2

In this type of upset the dew point temperature of the gas is higher than the ambient temperature but lower than the inlet temperature of the pipeline. This has the effect that free water will start condensing at some position downstream of the inlet, where the dew point temperature equals the pipe temperature:

Tinlet > Tdew > Tamb

Water type 3

In this type of upset the gas is saturated with water at the inlet (no drying). In addition there is free water entering the pipe at the inlet. This type of upset is not expected where the gas leaves the gas processing plant, but may occur when the gas leaves an underground storage reservoir. In this type of upset one may have large amounts of free water at the inlet that may also contain salts from the storage. Depending on the temperature gradient one may also get some free water condensing downstream of the inlet:

Free water from storage reservoir + (Tdew = Tinlet )

3.2 Absorbent

The corrosivity created under the various water types also depends on the presence of solids and/or glycol. We may call these absorbent types.

Absorbent type A

This is glycol carried over from the process system. The glycol will exist as a highly viscous film at the bottom of the pipe gliding along the pipe at low speed. This glycol


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arises from condensation of glycol present in the vapor phase, or from accumulation of small droplets of glycol due to liquid carry-over from the contactors. Since this liquid glycol will absorb some water from the dried gas, the glycol/water phase will have 0.5 - 5 % water even at non-upset conditions, depending on the temperature.

In case of upsets of the dehydration process, the water content in the gas may rise above the specifications for short periods. With a dew point temperature lower than the minimum temperature of the pipe there will be no condensation of free water. The glycol film at the bottom of the pipe will, however, absorb more water and become more corrosive. The water content in the glycol film can be calculated from the following formulas /1/:

(3.1)

Absorbent type B

Here we have solids in the form of sand, soil and possibly corrosion products. With solid particle settlement in the pipe there can be a corrosive phase independent of the type of drying system. The solids may absorb water from the gas in the same way as the glycol film, but the dew point temperature must be substantially higher to absorb water by solids than by a glycol film. Experience from atmospheric corrosion in relation to corrosion products shows that corrosion may start at about 60 % relative humidity (RH) and accelerate at 75-80 % humidity /2/. The corrosion below 100% humidity is due to capillary condensation of moisture in the pores of the corrosion products. A similar model of water condensation will be applied with solids settled in the pipeline, but simplified as follows:

RH < 60% No water condensedRH > 60 % 100 % free water condensed in the solids

The limit of 60 % in RH corresponds roughly to a dew point temperature 7 – 8 C lower than the gas temperature for a gas temperature of 20 – 30 C /2/.

Absorbent type C

This is the salt type absorbent. If the solids in the pipe has a large fraction of salts, the solids may be a more efficient absorbent than if there is no salt. Certain salts are quite hygroscopic, and may absorb water from quite dry gas. It is here assumed water absorption equal to 100 % water wetting down to RH = 30 %


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3.3 Combined water and absorbent upsets

When the different water type upsets are combined with the different absorbent types, one gets the combinations shown in Table 3.1.

Table 3.1 Upset combinations Water

Absorbent

1 (no condensation)

2 (condensing downstream inlet)

3 (free water)

A (glycol) 1A 2A 3AB (sand) 1B 2B 3BC (salt) 1C 2C 3C

Table 3.2. Wetting Factor (WF) for the various combinationsUpset combination

Dominant water wetting conditions

1A WF calculated from eq. 3.11B WF = 100 % where RH > 60 %, else WF = 01C WF = 100 % where RH > 30 %, else WF = 02A WF = 100 % downstream of condensation point, else WF = 02B WF = 100 % downstream of condensation point else WF = 02C WF = 100 % downstream of condensation point else WF = 03A WF = 100 % in all positions3B WF = 100 % in all positions3C WF = 100 % in all positions

3.4 Wetting time

From table 3.2 we see that the absorbent type has an influence on the possibility of getting 100 % water wetting or not when we have water upset type 1. With the other water upset types, there will be 100 % water wetting somewhere independent of the absorbent type. The absorbent type may, however, have an influence also on the wetting time, and this influence may be present for all water upset types. Here, the wetting time will be defined as the time with WF = 100 %. The wetting time will depend on the upset time and the time to dry out the water afterwards.

We also see from table 3.2 that for water type 2 we assume water wetting only when water is present as a liquid. This means that we do not consider wetting due to absorption when we have liquid water in the system. This is done in order to simplify the algoritm, and it may be justified because the corrosion rate for water type 1 is in general much less than for water types 2 and 3.

The time to dry out the water will depend on the wetting situation. Drying of a thin water film may take just an hour or so, while a massive hold-up of water can take days to dry out. Drying out water in an absorbent like sand and salt may also be a slow process.


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In the sections to follow we shall look at some models that allow us to estimate the wetting time twet for the various upset types. But first we need to look at some modelling results of the water behaviour in a single pipeline.


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4 FREE WATER BEHAVIOUR IN A SINGLE PIPELINE

4.1 Water flow rates

The amount of water flowing in a pipe during upset may have two origins:

Condensing water Free water at the inlet

4.1.1 Condensing water

With condensing water the amount of water is a function of the dew point temperature, the amount of gas flowing in the pipe and the ambient temperature. The amount of condensing water can then be calculated from the following formula:

Wcond (kg/s) = (C(Tdew,P) – C(Tamb,P))* Ugas (MSm3/s) (4.1)

The function C(T,P) is given by the following formula /1/:

(4.2)

Equations 4.1 and 4.2 have been combined to establish a single equation for the amount of condensed water:

Wcond (kg/s)= 1.6E-4*Ug*D2*(Tdew – Tamb)1.7 (4.3)

The dependency on the diameter and the dewpoint temperature is illustrated in Figure 4.1.


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Figure 4.1. Rate of water condensation as a function of the dewpoint temperature for three pipeline diameters. The ambient temperature is 10 C.

4.1.2 Free water at the inlet

With free water at the inlet the total amount of water in the pipeline will be:

Wtotal = Wfree + Wcond (4.4)

where the free water at inlet, Wfree, must be given as an input to the model.

4.2 Water flow and holdup

The flow of water can be calculated by computer programs designed for multiphase flow modelling. The model program we have available is based on OLGAS 2000. Since this is an advanced program with a high licence fee, it is not relevant to integrate this program in the present corrosion model. Instead we have used OLGAS 2000 to model a number of different situations with different values of the variables. From this study we have been able to extract some simple relations that can be used in the corrosion model to estimate the water flow conditions and especially the critical conditions for massive hold-up of water. The latter is of particular importance since a massive hold-up of water may lead to much longer wetting times than without massive hold-up. The term massive hold-up is used with purpose because, under certain conditions, the water may accumulate and give hold-up of 20 – 50 % of the pipe cross sectional area. Outside the area of this massive hold-up, there may be minor variations in the hold-up which then is of the order of typically 1 %.

The modelling study with OLGAS 2000 covered a parameter combination as shown in Table 4.1. The temperature was kept constant at 10 C in all the runs. A total of 46 runs were carried out.

Water condensation

0

0.1

0.2

0.3

0 10 20 30 40 50 60

Dewpoint temperature (C)

Co

nd

en

sa

tio

n r

ate

(k

g/s

) D = 0.2 m

D = 0.5 m

D = 1.0 m


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Table 4.1 Parameters varied in the flow modelling study with OLGAS 2000

PARAMETER PARAMETER VALUE UNIT

Diameter 8, 20 and 40 inches

Water flow rate 0.005, 0.02 and 0.1 kg/s

Gas velocity 2, 4, 6 and 8 m/s

Pressure 30, 45 and 60 bar bar

Inclination angle 0 – 13 in steps of 0.2 degrees

The model pipe was divided into sections with increasing inclination, in steps of 0.2 degrees. The maximum inclination was about 13 degrees. For each model run one used a certain combination of diameter, water flow rate, gas velocity and pressure. From the model results one could then in most cases see that the water flow situation changed dramatically at a certain inclination angle. Figure 4.2 shows an example of such a change at an angle of 3.8 degrees. Below this critical angle the water was transported as a thin layer with a hold-up of less that 0.03 %, and with a speed of about 0.4 m/s. Above the critical angle the hold-up increases to about 22 % and the speed is correspondingly low. The flow regime is also changing from stratified to slug flow at the critical angle.

It is obvious that the change of the water flow at the critical angle will be important for the wetting time. The more water the longer time to dry out the water after the upset. It is therefore of importance to be able to identify if a massive holdup will take place in the pipeline considered. This will take place if:

umax > ucrit

whereumax = maximum uphill angle of the pipelineucrit = critical angle for massive water holdup

Since we cannot make OLGAS 2000 a part of the model, we have combined all the information from the model studies and used that to establish a simple analytical expression for the critical angle ucrit in dependence of the other parameters:

(4.5)

As seen from figure 4.3 this analytical expression gives a fair fit to the critical angle predictions obtained in the OLGAS2000 runs. The critical angle dependencies of gas velocity, pressure and pipe diameter is illustrated in Figure 4.4.


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Figure 4.2. OLGAS 2000 model run with 40 “ pipe diameter, 0.1 kg/s water flow, 6 m/s gas velocity and a pressure of 30 bar.

Figure 4.3. Correlation between the analytical expression for ucrit and the critical angle obtained from the OLGAS 2000 run.

Figure 4.3. Correlation between the analytical expression for ucrit and the the critical angle obtained from the OLGAS 2000 run.

OLGAS2000 modelling

0.000

0.001

0.010

0.100

1.000

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0

Pipe inclination (degrees)

Wat

er h

old

up

(-)

0

2

4

6

8

10

12

14

0 2 4 6 8 10 12 14

Critical angle from OLGAS2000

An

aly

tic

al e

xp

res

sio

n f

or

the

cri

tic

a a

ng

le


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Figure 4.4. Critical angle dependencies of gas velocity, pressure and pipe diameter.

4.3 The dynamics of a massive holdup situation

The model simulations with OLGAS 2000 are based on a steady state situation (OLGAS 2000 is the static and not the dynamic version of OLGA). The massive water holdups predicted above the critical angle will take some time to develop. As an example we may consider a 20 “ pipeline with an uphill slope larger than the critical angle over a length of 100 m. In this pipeline the massive water holdup in the steady state will be 0.25. The total volume of water is then about 5 m3. With W=0.1 kg/s one can easily calculate that it then takes about 14 hours before the steady state situation is reached, neglecting any transport of water downstream of the uphill section before steady state is reached. In practice, some water will be transported during the build-up period (e.g. as droplets) so that the build-up period will be larger than 14 hours for this case.

When steady state is reached for the section considered, the water transport through the uphill section must be the same as just before it and just after it, i.e. given by the value of W. Steady state just means that the holdup is constant, i.e. there must be the same quantity of water leaving and entering the section. Thus, after the build-up period, the pipe sections downstream of the first critical uphill section will also become water wetted. If there is another critical uphill section downstream of the first one, this second critical section may also accumulate a massive holdup of water, but at a time later given by the build-up time of the first critical section.

Critical angle prediction model

02468

101214161820

0 5 10 15

Gas velocity (m/s)

Cri

tic

al a

ng

le (

de

gre

es

)

P=30 bar D=0.2 m

P=60 bar D=0.2 m

P=30 bar D=0.5 m

P=60 bar D=0.5 m


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What happens when the upset is over? Then the massive water holdups must be reduced. To begin with the holdup will be reduced at the same rate as it was build up, simply because it was a steady state situation with a balance between the water entering and leaving the section. When the upset is over the water entry to the section will soon disappear, while the water leaving the section will be the same. This will result in a decrease of the holdup in the section. Since we do not have a dynamic version of OLGA we cannot study in detail what happens when the water is removed from the critical uphill section. What is likely, however, is that the water removal rate will be reduced when the holdup is reduced. Since we cannot calculate this influence we must be satisfied with a rough estimate, e.g. to assume a time for removal of the massive holdup that is a certain factor larger than the calculated build-up time. In the model we shall use a factor of 2. If we for simplicity assume that also the build-up time is extended by a similar factor such that the build-up and the removal times become equal, we find that two following critical uphill sections will experience a similar wetting cycle, but only shifted in time. The situation is depicted in figures 4.5 and 4.6. For simplicity, the build-up and the reduction of the massive holdup is assume to proceed at a constant rate in the figure.

Figure 4.5 Schematic pipe profile with two uphill sections with an inclination larger than the critical angle.

Figure 4.6. Schematic development of the holdup of water in the two critical uphill sections shown in figure 4.5.

Pipeprofile

L1 L2

Distance

Holdup

t5 t2 t3 t4 t6 t7 t8

t1Section 1 Section 2

Time


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Section 1 = first critical uphill sectionSection 2 = second critical uphill sectionL1 = distance from water entry to section 1L2 = distance from section1 to section 2m1 = total mass accumulated in section 1m2 = total mass accumulated in section 2Wnet = net water transport rate into a section in the accumulation period W/2t1 = time for the upset conditions to reach section 1 = L1/Uw

t2 = time to establish steady state holdup in section 1 = m1/Wnet

t3 = steady state period of section 1 = tupset – t2t4 = time to empty the holdup in section 1 =m1/Wnet

t5 = time for the upset water film to travel from section 1 to section 2 = L2/Uw

t6 = time to establish steady state holdup in section 2 = m2/Wnet

t7 = steady state period of section 1 = tupset – t6t8 = time to empty the holdup in section 2 =m2/Wnet

In the example shown in figures 4.5 and 4.6, the holdup is smaller in section 2 than in section 1. In practice, there can be several critical holdup sections, and the holdup values in terms of water mass can vary randomly. The example shown has been included to demonstrate that there may not be just one critical uphill section.

Massive water holdup and reduction has so far been considered only as a transport phenomenon along the pipeline. During an upset that creates a free water phase, the gas must be saturated with water. When the upset is over, the gas will again become dry and will start absorbing water from the liquid phase. This situation will be looked into in section 5.

4.4 Water film properties without massive holdup

Below the critical angle, the water will flow as a thin film. The thickness of the film, h, its velocity, Uw, depends on the same four parameters as the critical angle: W, P, D and Ug. In addition there is a weak dependence on the pipe inclination. We shall neglect this last effect here and consider the data for a horizontal pipe. The data obtained in the OLGAS 2000 modelling study were correlated to give a basis for a simple relation that could be used to calculated h and Uw, without using OLGAS 2000. The best fit equation for h is:

(4.6)

Figure 4.7 demonstrates the good correlation between equation 4.6 and the actual flow modelling data with OLGAS 2000.

0

2

4

6

8

10

12

0 2 4 6 8 10 12

h(OLGAS2000)

h(m

od

el)


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Figure 4.6. Correlation between the simple analytical model (equation 4.6) and the OLGAS 2000 flow predictions. The solid line represents the ideal correlation.

When h is known, the flow velocity of the water film can be obtained from the general expression:

(4.7)

where the cross sectional holdup of water is calculated from:

(4.8)


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5 REMOVAL OF FREE WATER AFTER UPSET

5.1 Thin water film only

5.1.1 No solids in the pipeline

When the upset is over, the water will disappear. A thin water film will move at a velocity of about 0.5 m/s or less, and may be “flushed” out of the pipeline after some time. However, when dry gas starts to flow after the upset, some water may also be transported from the liquid water phase by diffusion of water vapour.

The diffusion rate of water vapour is given by:

Jm = km(csat – cdry) (5.1)

The mass transfer coefficient, kw, is a function of the Sherwood number:

Sh = kmD/Ddiff (5.2)

For turbulent gas flow in a pipe we use the Dittus-Boelter relation /3/:

Sh = 0.027*Re0.8*Sc0.33 (5.3)

Combining this equation with equation 5.2 we get the following equation for the mass transfer coefficient:

(5.4)

Because of the high pressure we must identify the parameters that vary with the pressure. These are:

Diffusion constant Ddiff = Ddiff,0/PKinematic viscosity =0/P

Separating out the pressure effect we get:

(5.5)

where km0 is the mass transfer coefficient at atmospheric pressure (1 bar).

Since the saturated water vapour concentration csat is independent of the pressure, we have now full control of the pressure dependence of the water mass transfer rate Jm.

Numerical example:


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csat - cdry = 17.3 g/m3

0 = 1.6*E-5 m2/sDdiff,0 = 2.3*E-5 m2/sUg = 5 m/sD = 0.5 mP = 1 bar

This gives

km = 0.01456 m/s and

Jm = 0.25 g/m2s = 21.6 kg/m2d

Since 1 mm of a 1m2 water film weighs 1 kg, the evaporation rate in terms of water film thickness reduction rate is:

E(mm/d) = 21.6 kg/m2d /1kg/mm*m2 = 21.6 mm/d

This value corresponds well with empirical relations for evaporation from open lakes and rivers /4/. A check on four different such relations gave evaporation rates in the range 10 – 14 mm/d for a wind speed of 5 m/s. Taking into account the different geometries of a pipe an open lake, the agreement is quite good.

In order to take into account the higher pressure in a gas pipe, we must divide the evaporation by the factor P0.2. Even for 60 bar this factor is no larger than 2.3,and

km = 0.01456/2.3 = 0.0063.

Thus, the evaporation rate of a water film in a pipe at a gas pressure of 30 –60 bar will be about the same as from a lake at the same “wind speed”, i.e. about 10 mm/d (roughly 0.5 mm/h) at 5 m/s.

When dry gas starts to flow over the liquid water film, water will evaporate to the gas at this rate. However, the gas will soon be saturated with water and the evaporation stops. It is thus only a limited length of the water film that can evaporate at a given time. The length of this film is obtained as follows:

When the gas is saturated with water, the water mass transport rate in the gas is:

Wgas = (csat – cdry)*Qg (5.6)

The water mass transport rate from diffusion in the length Ldiff of the water film:

Wdiff =Jm*Si*Ldiff (5.7)

Setting these rates equal yields for Ldiff:

(5.8)


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Numerical example:

csat - cdry = 0.01 kg/m3

D = 0.5 mUg = 4 m/sQg =0.25*3.14*0.5*0.5*4 = 0.78 m3/sSi D/2 = 0.25 mJm = 10 kg/m2d= 1.16E-4 kg/m2s

Ldiff = 0.01 kg/m3 * 0.78 m3/s / (1.16E-4 kg/m2s * 0.5 m) = 270 m

Thus, the evaporation of the liquid film takes place over a length of the order a few hundred meters. It means that the removal of the water is limited by the transport in the gas and not by the evaporation rate.

The water mass in a length L of the liquid film is:

mw = AwwL (5.9)

The time required to transport this mass with the gas is obtained by dividing the mass in equation 5.9 by the transport rate in equation 5.6:

(5.10)

or we can alternatively define a velocity at which the upstream end of the liquid water train is consumed:

(5.11)

In relation to a given position x the end of the water train moves with the composite velocity Udry + Uw, because the end of the train will move with the velocity Uw even if there is no drying. The situation is depicted in figure 5.1.

Waterholdup

WaterWater saturated

Dry gas evaporation gas

Uw

Uw + Udry Distance


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Figure 5.1. Illustration of the water removal process when dry gas starts flowing after the upset.

On a time diagram this will lead to the situation shown in figure 5.2.

Figure 5.2. Illustration of the various time periods related to water wetting and water removal after upset, at an arbitrary position x from where the free water is entering/condensed.

tstart = time before water train reaches position x = x/Uw

tgas = time for the gas to arrive position x in dry condition = x/(Udry + Uw)

The total wetting time at position x is therefore:

twet = tupset + tgas - tstart (5.12)

or

(5.13)

This equation shows that the wetting time will decrease linearly with the distance x. Thus, the corrosive effect of the free water will be strongest near the inlet or the point of condensation. The equation also shows that there will be a maximum distance

Waterholdup

tupset

tstart tgas

Time


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beyond which the free water will not exist. This maximum distance is obtained by setting twet = 0:

(5.14)

Numerical example:

Pipe length = 100 kmtupset = 12 hUw = 0.3 m/sD = 0.5 mUg = 4 m/sAw =1.6E-4 m2

Qg =0.25*3.14*0.5*0.5*4 = 0.78 m3/scsat – cdry = 0.01 kgUdry = 0.01 kg*0.78 m3/s /1.6E-4 * 1000 kg/m3 = 0.05 m/s

This gives a value Lmax = 91 km.

The wetting time for this case is shown in figure 5.3.

Figure 5.3 Wetting time with distance from inlet assuming free water and no solids. Parameters according to the example above.

12 hour upset

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0 20 40 60 80 100

Distance from free water inlet (km)

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We see from this example that the wetting time will be reduced with the distance and it becomes zero at 91 km, which is the Lmax value of the case. Even if the pipeline is 100 km, there will be no water wetting in the last 9 km.

5.1.2 Free water and solids present

With solids present the wetting time will be longer due to the slower water vapour diffusion through the solid. We may write the mass transfer equation in a somewhat different form to understand this better:

(5.15)

With this form we identify the diffusion length , as the hydrodynamic layer over which the diffusion must take place. This diffusion length is related to km:

(5.16)

When diffusion of water takes place from some depth z in a layer of solids, this depth comes in addition to the hydrodynamic diffusion layer, and the diffusion equation must be modified:

(5.17)

Will this make a large difference? It depends on the size of z compared to If we go back to our numerical example we find a value for

Ddiff/km = Ddiff,0/(Pkm) = 2.3 E-5/(60 *0.0063) =6.1E-5 m = 0.061 mm

This is a very small value and will be negligible compared to the thickness of a solid layer that will be of the order mm. This also has the effect that the evaporation rate will be strongly reduced. If the total thickness of the solid layer is 3 mm, then the average diffusion length will be 1.5 mm. Compared to the hydraulic layer thickness this is a factor of 25.

A slow diffusion process will have an influence on the water removal process. If we use the numerical example that gave Ldiff = 270 m in the case of no solids, this value will be increased to Ldiff = 270 m * 25 = 6.8 km with a 25 times slower diffusion. But the water transport will still be limited by the water transport in the gas as long as the pipeline section considered has a length > 6.8 km. There are, however, also other effects of solids that will influence the wetting time and these may be difficult to quantify. When an upset starts creating free water, the water may be partly absorbed by the solids. It is therefore difficult to set up equations for the water flow in the presence of solids. It is accordingly difficult to have a clear picture of the extension of the water phase when the upset is over. To be able to get quantitative results we shall make some assumptions:


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When the upset starts, the free water will get soaked in the solid until it is saturated. After that the water will ride on top of the solid as if the solid did not exist or represent the stagnant wall instead of the pipe wall.

We assume for simplicity that the thickness of the solid layer is such that there will be a similar amount of water stagnant here as the amount in free water layer on top.

This has the following implications:

In the upset period we will have a water film that is twice as thick as without solids.

o The lower half of the film is stagnant and the upper half is moving at a velocity of Uw, as without solids.

o The front of water film, however, is moving forward with a velocity that is 50 % of the free water film velocity.

When the upset is over, the moving film will continue to move and soak in the solid until it is all soaked or caught up with the drying gas.

The soaked water will be evaporated and transported away from the solid layer by the dry gas. For a water train of length > 3 km the transport process is limited by the gas transport, as without solids. For shorter water trains the transport is limited by the diffusion from the stagnant water film, and the assumption of gas transport limitation will be conservative. This conservatism will be present for upset time lower than about 3 hours, using the equations below for all upset times.

Based on these assumptions it may be shown that we may use the same formulas as before, with some modifications:

tstart = time before water train reaches position x = 2x/Uw

tgas = time for the gas to arrive position x in dry condition = x/(Udry)

For tstart the velocity of the moving water front is Uw/2 because the solid layer has to be filled up as well. For tgas the velocity of the ”drying edge” in the back of the train is assumed to be Udry for all cases although it is more like Udry/2 when Udry > Uw. Equation 5.19 is therefore most “true” when Udry < Uw, i.e. when the wetting time and the corrosion rate is largest. Udry is still the drying velocity of a water film without solids, as given by equation 5.11.

The total wetting time at position x is therefore:

twet = tupset + tgas - tstart (5.18)

or

(5.19)

In equation 5.19 it is assumed that we use the same values for Uw and Udry as we used without solids present (eq. 5.13). With solids, the expression for Lmax in equation 5.14 has to be modified. Since the water film will stop moving when all the water is soaked, it may happen that this takes


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place at a shorter distance than the Lmax value given by twet = 0. We then get the following equation for Lmax:

(5.20)

This equation is based on the assumption that the amount of water per unit length in the solid layer is the same as in a free flowing film.

We must therefore put the following limitations on the twet expression in equation 5.19:

twet = according to equation 5.19 for L < Lmax

= 0 for L > Lmax

One consequence of the modifications in the presence of solids, is that the wetting time may get a different dependence on the position x. If we consider the same numerical example as without solids (figure 5.3), we get the result shown in figure 5.4.

Figure 5.4. Illustration of the effect of solids on the wetting time during upset.

5.2 Massive holdups and no solids

If we have a massive holdup situation, the equations for the wetting time must be modified. If we consider a point x at the bottom of the critical uphill section, we will have the same values of tstart and tdry, because they are related to the film section of

12 hour upset

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150

0 20 40 60 80 100


We

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No solids

Solids


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the pipe before we reach the critical uphill section. When the end of the thin film water train reaches the point x, the pipe may not become dry immediately as we assumed for a thin film section. The reason is that the water mass in the critical uphill section is very large, and the drying process will have a negligible influence on the water removal process. We therefore assume that the water here will be removed by fluid transport only. To be conservative, we shall assume that the point x is not dry until the entire massive water holdup has been transported out of the uphill section. Thus, we get for the wetting time:

twet = tupset + tgas - tstart +tempty (5.21)

We have therefore the same expression as before, except for the extra term:

tempty = mw/Wnet (5.22)

giving

(5.23)

One should note that the above equation is based on the assumption that the entire holdup area is considered wetted from the time the water train arrives at the bottom of the hill and until all the water has been removed from the holdup area.

The influence of the last term is illustrated by a modification of the previous example (without solids):

Pipe length = 100 kmtupset = 12 hUw = 0.3 m/sD = 0.5 mUg = 4 m/sAw =1.6E-4 m2

Qg =0.25*3.14*0.5*0.5*4 = 0.78 m3/scsat – cdry = 0.01 kgUdry = 0.01 kg*0.78 m3/s /1.6E-4 * 1000 kg/m3 = 0.05 m/sLength of uphill section = 50 mHoldup = 0.25mw =0.25 * 3.14*0.5m 0.5m*50m*1000 kg/m3 = 9812 kgWnet = 0.05 kg/s

Giving:tempty = 54 hours

If we assume that the first critical uphill section is 20 km from the inlet, we get the situation as depicted in figure 5.5.

12 hour upset

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20

30

40

50

60

70

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Figure 5.5. Wetting time profile with a 50 m long critical uphill pipe section at 20 km

5.3 Massive holdups and solids

If we have both massive holdups and solids present, we may have the most significant water wetting, if the critical uphill section is within reach of the water train. As we have seen there may be a relatively short maximum length in the presence of solids.

We will then first have to remove all the water, mainly from fluid transport, and then dry out the water from the soaked solid by evaporation and transport with the gas. The result is that the wetting time in the holdup area can be written as

(5.24)


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6 WATER ABSORPTION AND REMOVAL WITHOUT FREE WATER

When the dewpoint temperature of the gas is lower than the ambient temperature, there will be no free water in the pipeline. Some water may still be present if we have an absorbent in the system, and conditions for absorption. This is water type 1, as described in section 3. The amount of water absorbed will depend on the amount and type of absorbent. Quantification of the amount of glycol, sand and salt is difficult, and therefore we have to make some assumptions. It is possible that the final computer program will have options for a qualitative description of the assumed amount (small, medium, large), but for the present we shall consider a certain default quantity. In the description below we shall consider the water absorption process and the water removal process for each type of absorbent individually.

6.1 Glycol

Glycol absorbs water at all values of the dewpoint temperatures. The percentage of water in the glycol is given by equation 3.1.

For the volume of glycol present in the pipe we shall use some typical values obtained from studies in another project /5/:

The amount of glycol entering the pipeline is assumed to be Xglycol = 8 l/MSm3 gas.

It is assumed that all this glycol is condensing to become a thin liquid film at the bottom of the pipe.

The flow is stratified at horizontal flow and the small inclination angles of the seabed pipeline. The liquid flow velocity is of the order Uglycol= 0.001 m/s.

With these assumptions we easily find an equation for the glycol holdup Aglycol:

(6.1)

When the upset starts, the dewpoint temperature increases. Then, the glycol will start absorbing more water from the gas according to equation 3.1. It will take some time before the glycol is at the new equilibrium, and the process may also proceed more slowly down the pipe than the gas flow. Since the glycol is an efficient absorbent, we assume that the distance a certain volume of gas is travelling before it has given away the water it can to the “hungry” glycol, is short compared to the distance of the pipe influenced by the upset. In this simplified picture, the glycol in the pipe will attain the new water equilibrium at a velocity that is limited by the water content in the gas. It may be shown that the formula for this velocity Ueq is given by:

(6.2)


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In equation 6.2 Cupset is the water content in the gas during upset and Cdry the water content in the dry gas.

The understanding of the velocity in equation 6.2 is as follows: In the picture above, the glycol that is first met by the upset train (gas with increased Tdew) will absorb all the water there is in the gas until it has reached the new water content equilibrium. Then, the glycol downstream of this equilibrium glycol will start absorbing. This border between “hungry” and equilibrium glycol will move at the velocity Ueq.

When the upset is over, the process will be reversed, and the glycol film at the inlet will start releasing water to the dry gas as fast as the gas can absorb it. It is not difficult to understand that the new equilibrium will be established at the same velocity.

By the same arguments as in section 3.1 for the wetting time we then get:

(6.3)

We here see that the terms dependent on the distance x, drop out because the equilibrium velocity is assumed to be the same for water absorption and water removal. Because of the simplifying assumptions, there may be some differences in practice that introduces a slight dependence on x, but this will be neglected in the model.

A consequence of equation 6.3 is that there will be no maximum length of the influence of the upset. The train of high water-in-glycol will have a fixed length equal to Ltrain, which depends on tupset and Ueq as indicated in Figure 6.1. This train will move all the way through the pipe. It may seem strange that this upset train will exist long time after the upset is finished, but this is due to the assumed strong affinity of the glycol to absorb water. The dry gas hitting the train will absorb water and dry out the glycol film. It then becomes saturated, and when the saturated gas reaches the downstream end of the train the water will again be absorbed by the glycol film with a low water content. Thus, the dry gas only acts as a medium to transport the excess water in the glycol from the upstream end of the train to the downstream end of the train.


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Figure 6.1. Illustration of the water-in-glycol profile moving downstream with velocity Ueq.

Since the wetting time will be the same at all locations, the corrosion rate profile will be rather flat for this case.

6.2 Sand or salt without glycol

If there is sand or salt in the pipeline, we shall make the following assumptions:

The sand or salt layer has a constant thickness = zsolid

The width of the layer = 0.5*D The volume to be filled with water = 50 % of total volume.

Water will start to absorb at the position where the pipe temperature is such that the water content in the gas corresponds to a critical relative humidity (RHcrit) which is 0.6 (60 %) in sand and 0.3 (30 %) in salt at that temperature. We may call this temperature Tstart. Its value is found from:

Cw (Tdew,P) = RHcrit*Cw(Tstart, P) (6.4)

At this position the water absorption rate is very low because if a large quantity is absorbed the water content in the gas will drop below 60% (30%) RH and the absorption will stop. Further down the pipe the temperature will drop, and more water can be absorbed. The maximum absorption rate occurs when T = Tamb. We shall neglect this variation in absorption rate and assume that the absorption rate is maximum at all locations where absorption can occur according to the RHcrit criterium. The maximum absorption rate is:

Wabs = (Cw(Tdew,P) – RHcrit*Cw(Tamb,P))*Qg (6.5)

With the assumptions made the mass of water absorbed per meter length is:

Waterin glycol Ltrain = tupset *Ueq

Ueq Ueq

Distance


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(6.6)

And the velocity at which the absorption travels downstream the pipe is:

(6.7)

In contrast to the glycol absorption, the absorption and drying velocities in the solid layer are different. This is due to the fact that the amount of water that can be absorbed by the gas is different from the amount that can be absorbed from the gas, per unit volume. The drying rate expression is similar to eq. 6.5, but with other values of the temperatures:

Wdry = (C(Tamb,P) – C(Tdry,P))*Qg (6.8)

The speed of the drying process is:

The wetting time is then:

(6.9)

As for the case with free water we may define a maximum distance of wetting:

(6.10)

When the upset is over, the absorption velocity can never be larger than the drying velocity. Therefore, Lmax cannot be negative, in the limit it may approach infinity as for glycol.

6.3 Sand or salt with glycol

If there is glycol in the pipe, it is assumed that the glycol will control all the exchange of water between the vapour phase and the film at the pipe bottom. It means that we have the same situation as with glycol only, described in section 6.1, i.e.:


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(6.11)


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7 TEMPERATURE AND PRESSURE PROFILES

For a single pipe the temperature profile can be calculated from:

T(x) = (Tinlet – Tamb)* exp(-x/) + Tamb (7.1)

where the decay length is given by:

(7.2)

Most of these parameters are relatively well defined, but the overall heat transfer coefficient Uheat depends on the burial depth and the heat conduction properties of the soil, in addition to the heat transfer properties of the pipe coatings. Thus, unless the heat transfer coefficient has been obtained from field measurements of the temperature profile, Uheat will normally be known only with a large uncertainty.

The pressure is normally known at certain locations like the inlet and outlet of a pipe. For the present modelling it is accurate enough to assume a linear pressure drop between two points of known pressure.


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8 THE CHOSEN POINT CORROSION MODEL

8.1 The Shell95 corrosion model

Models describing corrosion of carbon steel in the presence of a water phase saturated with CO2 from the gas phase has been the subject of many publications. Some of the models are based on very fundamental principles of electrochemistry, chemical equilibria and transport processes. Others are of a more empirical nature. The most well known CO2 corrosion model has been the empirical model of de Waard and Milliams. The original model was a rather simple model relating the corrosion rate to the CO2 partial pressure and the temperature only /6/. Over the last decade the model has been improved to include effects of the total pressure, protective films, Fe2+

concentration, glycol, actual pH and flow rate. These improved models are often referred to as Shell91, Shell93 and Shell95, where the number denotes the year of the published improvement of the model /1,7,8/.

The Shell95 model showed reasonable predictions in a project comparing 15 different CO2 corrosion models with field data /9/, and is the model to be used here.

Following de Waard, Lotz and Dugstad the overall corrosion rate, Vcor, can be written as:

Vr

is the

highest possible corrosion rate determined by the reaction rate, i.e. when the mass transfer rate Vm is infinitely large.

The best fit equation describing Vr in dependence of the environmental parameters is:

For Vm a best fit equation is given by:

The equations 8.1 – 8.3 are assumed valid for temperatures up to about 80 C, which is higher than the temperatures of the present problem.

(8.1)

(8.2)

(8.3)


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8.2 Flow effects and mass transport limitations

8.2.1 Thin water films

When dealing with thin water films, it is not obvious that equation 8.3 gives a good description of the mass transport limited corrosion rate. The definition of a hydraulic diameter d is introduced to take into account variations in the liquid holdup, but the experimental data on which Shell95 is based, does not include very thin films. We have therefore run some OLGAS 2000 models with a water holdup from 1 mm to completely water filled pipe. The flow conditions were adjusted to give identical shear forces. With different water holdups the water film flow velocities became different. However, the ratio U0.8/d0.2 remained constant within 10 %. This shows that equation 8.3 is valid also for very thin water films.

8.2.2 Massive water holdup

If we get a massive water holdup, the OLGAS 2000 modeling shows an extremely low water flow velocity. This is the average transport velocity of the water phase, and it must be low when the holdup is large. The flow situation in the massive holdup area is, however, rather complex. The flow regime can be stratified or slugging. With a stratified flow it is obvious that there must be a strong variation in the water velocity from the wall to the gas/water interface. Actually, the water will flow downhill near the wall and uphill at the gas/water interface, with a profile such that the average is just slightly positive. OLGAS 2000 does not provide such a profile, but provides the shear stress between the wall and the water phase. The value of this shear stress attains values of the same order as with a water filled horizontal pipe with a flow velocity of about 1 m/s.

In massive holdup areas we will therefore use the value Uw = 1.0 m/s in equation 8.3.

8.2.3 Water absorbed in solids

When there is no free water flowing and the only water present is the water absorbed in solids settled at the bottom of the pipe, the water flow velocity along the pipe is zero. A zero velocity would imply complete mass limitation, and the corrosion rate would be zero. Practical experience tells us that this is not true. Even if there is no net flow of water along the pipe, there will be natural convection within the solid/water phase that secures a certain minimum mass transfer. CO2 corrosion studies with solids are scarce, but we have a parallel situation with oxygen corrosion on steel in seawater/soil. For this system the corrosion rate obeys similar equations with respect to mass transfer. The corrosion rate in flowing seawater at high velocity (several m/s) is about 1 mm/y. The typical corrosion rate in seawater saturated soil is 0.15 – 0.2 mm/y. This is also the typical corrosion rate for steel in slowly flowing seawater, when the steel specimen has got a stable layer of corrosion products. Thus, both in soil and for steel with a corrosion product layer, there is a certain natural convection that allows oxygen to reach the surface and allow corrosion to proceed at a rate that is a factor of 0.15-0.2 smaller than the corrosion rate under activation control.We shall assume that the mass transfer within a solid layer at the bottom of a pipe is subject to a similar behavior with respect to the mass transfer limitations in CO2

corrosion. In practice, we shall assume a certain equivalent water velocity to be used in equation 7.3. If we assume that mass transfer is negligible at 1.0 m/s, which is reasonable with the pH-values expected, we may estimate the value of Uw for solids


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by the requirement that the mass transfer shall be a factor 0.15 - 0.2 of the high flow corrosion rate, as we have seen for oxygen corrosion on steels in seawater:

(Uw(solids)/Uw(high flow))0.8 = 0.15 - 0.2

This gives the following value of Uw(solids) = 0.08 - 0.13 m/s. In the modeling we use the value 0.1 m/s.

8.3 Effects of glycol

In the presence of glycol in the water phase it has been shown that the corrosion rate decreases with increasing glycol concentration. This has been introduced as a multiplication factor Fglyc, to be multiplied with the overall corrosion rate. Following de Waard, Lotz and Milliams /10/ the glycol factor Fglyc is given by:

where W% is the weight percent of water in the glycol/water phase. For pure water log(W%) equals 2 and the glycol factor equals 1.

8.4 The pH of the water film

According to eq.8.2 the reaction rate depends on the actual pH. For condensing water the water will have a rather low concentration of Fe2+ ions. If the iron content is zero the pH is given by the following equation /10/:

where T is the temperature in degrees C and pCO2 the partial pressure in bar.

As Fe2+ -ions accumulate in the liquid due to corrosion the pH will shift to higher values. According to de Waard et al /11/ a new stable pH -value will be attained when the liquid becomes saturated with FeCO3:

While the pH at low iron content may be typically in the range 4-5, the saturation pH is 1-2 units higher. The length over which this pH increase takes place will depend on parameters like the thickness of the liquid layer, its average flow rate and the average corrosion rate.

The following equation describes the increment d[Fe2+] over an incremental distance dx:

log log( F )= 1.6( (W%)- 2)glyc (8.4)

(8.5)

sat 2pH = 5.4 - 0.66 ( pCO )log (8.6)


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whereVcorr = corrosion rate (mm/year)SL = wetted periphery (m)Aw = cross sectional area of liquid film (m2)Uw = water film velocity (m/s)k= fractional area uncoated

With dx given in meters d[Fe2+] is obtained in ppm units.

For the present modeling we do not aim at a very detailed description of the change in pH along the pipeline. The use of eq.8.7 is therefore limited to an estimate of the typical length Lsat, over which this pH change takes place. This value can be estimated, using some typical values of the parameters:

Vcorr = 1 mm/ySL = 1 mAL = 3E-5 m2

Uw = 0.3 m/sk = 1.0 (no internal coating)

With these parameters, eq. 8.7 is integrated to saturation (of the order 100 ppm) over the length Lsat = 4 m. Saturation is therefore a very rapid process under these conditions. Condensation will occur over quite some distance as long as there is a thermal gradient. The actual change of the iron content and the pH will therefore take place over a distance longer than Lsat. For the present modeling we will use this as follows:

At the beginning of the condensation (Tdew = Tamb ) we assume [Fe2+]=0, and a pH given by eq. 8.5.

When condensation is stopped (Tgas = Tamb), saturation is assumed, and a pH given by eq. 8.6.

If it is required to consider a pipe section between these positions, a linear variation of [Fe2+] is assumed.

The pH may also be influenced by other constituents than CO2 and the iron content. In the presence of salts, the pH will normally decrease, but the effect is not quite large. A stronger effect is expected if the gas contains acetic acid (Ac), which may lower the pH by 0.5 – 1.0 pH units.

(8.7)


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9 CORROSION MODEL INPUT VARIABLES

Table 9.1 Input variables of the corrosion modelVariable Typical value/range of valuesFrequency of upset Any figureDuration of upset Any figureGas flow rate Figures giving gas flow velocities up to 10 m/sPipe diameter 8 – 40 ”Pipe length Any figureTemperature at inlet 10 – 50 CPressure at inlet 30 – 60 barDew point temperature of gas

-20 C to 50 C

Free water at inlet Up to 0.3 kg/sWater type Absorption/Condensation/Liquid water at inletSolids Yes/noSalt Yes/NoGlycol Yes/NoGlycol quality Low/Medium/HighAc in gas Yes/NoMaximum uphill inclination

Up to 15 degrees

CO2 content of the gas Any figureAmbient temperature Any figureHeat transfer coefficient Any figure


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10 MODEL APPLICATION

10.1 Water upset type 1

1. Calculate amount of water absorbed in glycol, solids or salts2. Calculate maximum length of water wetting 3. Calculate wetting time twet for relevant sections

4. Set velocity to U=0.1 m/s5. Calculate pH =pHsat6. Calculate average corrosion rate at relevant sections: CRave = Vcor

(U,d,pCO2,T,pH)*twet* fwhere f = upset frequency.Water upset type 2 & 3

1. Calculate water mass flow in pipe 2. Calculate water film velocity and thickness3. Identify if massive holdup areas will exist4. Solids ?5. Calculate wetting time twet for relevant sections

6. Calculate pH7. Calculate average corrosion rate at important locations:

CRave = Vcor (U,d,pCO2,T,pH)*twet* f

From the above we see that the final formula for calculating the average

corrosion rate is the same for all water upset types. It is also quite simple. The

complexity of the modelling work is more or less confined to the parameter twet.

As we have seen in the previous sections, the calculation of twet can be relatively

complex, and will require different formulas for different types of upsets.


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11 REQUIRED MODIFICATIONS FOR A PIPELINE SYSTEM

Figure 11.1 Schematics of a pipeline system with an underground storage facility.

With a system of pipe sections from different producers upsets may not occur at the same time in all parts of the system. A corrosive condition in one branch of the pipeline may thus be modified by the conditions met in another branching section that has no upsets. The situation immediate downstream of the connection point can thus be corrosive or non-corrosive depending on the actual situation. It is therefore important to be able to model the changing conditions at the connection points.

The approach used for the present modelling will be as follows:

Only single-upset situations will be considered, i.e. it is assumed that during an upset in one of the single pipe sections there will be no upsets in other parts of the pipe system.

The model will handle only single pipe sections at the time. A single pipe section may have two types of input definitions:

o A single pipe inputo An input described by two pipes that are connected at the inlet

This approach will have a number of consequences for the way the program/model is used:

A system of pipes must be broken down into a number of single pipe calculations, e.g. the system in Figure 11.1 will consist of six different single pipe sections.

For a single pipe section with a “double pipe input” there will be some common data (e.g. input pressure) and some data that require separate input values for the two branches (e.g. gas flow rate, Tdew, temperature, amount of free water etc.). The model must therefore be able to convert a double input to a single input, e.g. converting two temperatures to a single average temperature, two different dewpoint temperatures to a single average temperature, two gas flow rates to a single gas flow rate etc. This process

Producer 3

Producer 1

Producer 2 Storage


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does not require any other basic equations than those already discussed for the single pipe case.

Once the double input data are converted to single input data the analysis of the particular single pipe section will be straight forward as for any single pipe. It should be noticed, however, that the order of calculation must be so that if the output of a single pipe section A is to be used as input to another pipe section B, the pipe section A must be analysed before pipe section B.


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12 LIST OF SYMBOLS USED IN THE CORROSION MODEL

a = fugacity coefficient

Aglycol = cross sectional area of glycol film

Aw = cross sectional area of water film during upset

C(T,P), csat = saturation water vapour concentration in the gas as function of T and P

cp = heat capacity of gas at constant pressure

cdry = water vapour concentration in the gas in dry condition

d = hydraulic diameter of the liquid phase

D = pipe diameter

Ddiff, Ddiff,0 = diffusion coefficient of water vapour

DEG% = percentage of glycol in the glycol/water film

F1 = function describing the maximum condensing water rate

F2 = function describing the sin(ucrit) dependencies

Fglyc = factor reducing the corrosivity in the presence of glycol

h = height of water film during upset

Jm = water vapour mass diffusion rate

k = coating factor

km, km0 = water mass transfer coefficient

L, L1, L2 = length of a given pipe section

Ldiff = length of water film involved in diffusion of water to the gas

Lmax = maximum length of pipe influenced by the upset

mw, m1, m2 = water mass (kg)

P = total pressure

pco2 = partial pressure of CO2

pHact = actual pH value of the water phase

pHCO2 = pH due to dissolved CO2 in the water

pHsat = pH when the water is saturated with FeCO3

Qg = gas volume flow rate (m3/s)

Re = Reynolds number

RH = relative humidity

RHcrit = critical relative humidity for absorption of water by sand or salt

Sc = Schmidt number

Sh =Sherwood number

Si = length of interface between liquid water and the gas

t, t1, t2 = time


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Tamb = ambient temperature (degrees Centigrade)

Tdew = actual dewpoint temperature of the gas (degrees Centigrade)

tempty = time to empty the massive holdup area for water

tgas (x) = time for gas to arrive position x in dry condition when the upset is over

Tinlet = actual gas temperature at the inlet of the pipe section (degrees Centigrade)

tsolid =

Tspec = specified dewpoint temperature in dry condition (degrees Centigrade)

tstart (x)= time before the upset water train reaches a certain position x

tupset = duration of upset

twet (x) = total wetting time at a position x

U = velocity parameter of the corrosion equation

ucrit = critical uphill inclination angle for massive water holdup

Udry = velocity of the ”drying edge”

Ug = gas velocity

Uglycol = glycol film velocity

Uheat = heat transfer coefficient of the pipe (W/m2 C)

umax = maximum uphill inclination of the pipe

Uw = velocity of the water film during upset

Vcor =total corrosion rate (mm/y)

Vm = mass transfer controlled corrosion rate (mm/y)

Vr = reaction rate controlled corrosion rate (mm/y)

W = water flux (kg/s)

W% = percentage of water in the glycol/water film

Wabs = flux of water absorbed by the gas (kg/s)

Wcond = flux of condensed water (kg/s)

Wdiff = flux of water due to diffusion from liquid water to the gas phase (kg/s)

Wfree = flux of free water at pipe inlet (kg/s)

Wgas = flux of water as vapour in the gas (kg/s)

Wnet = net water flux (kg/s)

Wtotal = total water flux (kg/s)

x = distance from pipe inlet or point of water condensation

Xglycol = amount of glycol in the gas (l/MSm3)

z, zsolid = thickness sand and salt layer

c = concentration difference of water content in wet and dry gas

= diffusion length

= temperature decay length


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= kinematic viscosity

g= density of gas

w = density of water


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13 RISK ANALYSIS

13.1 General

Risk analysis may be carried out in different ways. We have chosen to apply the method of calculating the pressure capacity of a corroded pipeline. For this purpose we have selected two different methods, the ASME B31G method /10/ and the more recent method of Det Norske Veritas, known as DnV RP-F101 /11/. Both methods are described below in some detail.

13.2 Definitions

L = longitudinal extent of corroded aread = maximum depth of corroded areadcrit = critical depth of corroded areat = nominal wall thickness of the pipeD = nominal outside diameter of the pipeSMYS = specified minimum yield strength of the pipeSMTS = specified minimum tensile strength of the pipeF = design factorPcorr = safe maximum pressure for the corroded areaPMAOP = maximum accepted operational pressureP = maximum allowable design pressureCR = corrosion rateY = number of yearsYcrit = critical number of years

13.3 ASME B31G

For corrosion attacks less than 10 % of the wall thickness no assessment is necessary, and corrosion attacks deeper than 80 % are not permitted.

For corrosion attacks between 10 and 80 % the following apply:

1. If L < Lallow then no further assessment is necessary, where

(13.1)

and

for d/t > 17.5 % (13.2)

B = 4 for d/t < 17.5 %

Bmax = 4


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2. If L > Lallow then the safe maximum pressure is given by:

a)

(13.3)

b) A > 4

(13.4)

where

(13.5)

(13.6)

(13.7)

When this method is applied with a corrosion feature depth d estimated from a model corrosion rate CR, we assume that the length of the corrosion feature L is infinite.

The critical depth dcrit and the critical time Ycrit is then obtained from the following equations combined with the ones above:

Pcorr = PMAOP (13.8)

(13.9)

13.4 DnV RP-F101


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The procedure is based on section 2.6 Relative Depth Measurements and section 3.2 Longitudinal Corrosion Defect, Internal Pressure Loading Only, in the DnV document /11/.

For defects of depth less than 85 % the following apply:

(13.10)

where

(13.11)

(13.12)

If then Pcorr = 0

Definition of specific parameters:

m = Partial safety factor for modeld = Partial safety factor for corrosion depthd = Factor for defining a fractile value for the corrosion depthStD[d/t] = Standard deviation of the ratio (d/t), based on tool accuracy

Figures for the specific parameters:

Safety class m d Range for d

Low 0.79 1.0 + 4.0 StD(d/t)1+5.5 StD(d/t)-37.5 StD(d/t)2

1.2

StD(d/t) < 0.040.04 < StD(d/t) < 0.080.08 < SrD(d/t) < 0.16

Normal 0.74 1+ 4.6StD(d/t) -13.9 StD(d/t)2 StD(d/t) < 0.016

High 0.70 1+ 4.3StD(d/t) – 4.1 StD(d/t)2 StD(d/t) < 0.016


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When this method is applied with a corrosion feature depth d estimated from a model corrosion rate CR, we assume that the length of the corrosion feature L is infinite.

The critical depth dcrit and the critical time Ycrit is then obtained from the following equations combined with the ones above:

Pcorr = PMAOP (13.13)

(13.14)

(13.15)

The latter equation is based on laboratory verification of the Shell95 corrosion model /8/.


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14 REFERENCES

1. de Waard, C. Lotz, U. and Milliams, D. E.: "Predictive Model for CO2 Corrosion Engineering in Wet Natural Gas Pipelines", Corrosion, Vol. 47, No. 12, Dec. 1991.

2. CORROSION, section 2.2, edited by L.L.Shreir, Newnes-Butterwords, second edition 1979.

3. F. M. White: “Heat and Mass Transfer”, Adison-Wesley, 1988.

4. http://www.eng.usf.edu/~mross/coursework/cwr4103/ notes4.pdf

5. P. O. Gartland: “ A Corrosion Model for the Åsgard Transport Gas Pipeline with Other Pipelines Connected to it”, CorrOcean Document E068-002, 1998.

6. de Waard, C. and Milliams, D. E.: "Prediction of Carbonic Acid Corrosion in Natural Gas Pipelines", First International Conference on the Internal and External Protection of Pipes, Paper F1, Durham, UK, University of Durham, 1975.

7. de Waard, C. and Lotz, U.: "Prediction of CO2 Corrosion of Carbon Steel", Paper 69 at NACE CORROCION '93.

8. 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.

9. “Kjeller Field Data Project”, run by Institute of Energy Technology, Kjeller, Norway.

10. ASME B31G-1991: “Manual for Determining the Remaining Strength of Corroded Pipelines”.

11. DnV RP-F101, “Corroded Pipelines”, 1999, DnV, Norway.

http://www.eng.usf.edu/~mross/coursework/cwr4103/notes4.pdf

http://www.eng.usf.edu/~mross/coursework/cwr4103/notes4.pdf

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Internal Corrosion in Dry Gas Pipelines During Upsets L52079e

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