a438243_1.pdf bp corrosion modelling

CorrosionPredictionModellingA guide to the use ofcorrosion predictionmodels for risk assessmentin oil and gas productionand transportationfacilities

A J McMahon, D M E Paisley

Sunbury Report No. ESR.96.ER.066dated November 1997

Main CDContents

Contents

Summary

Acknowledgements

Introduction 1

"Cassandra 98" Corrosion Prediction Spreadsheetby A J McMahon

Introduction 5Quick Start 6Limitations of Corrosion Prediction Models 8Detailed Description of the Spreadsheet 11Comparing Output from the "Cassandra 98" Model with Field Data 27Appendix 1: Henry's Law Constans for CO2 Dissolved in Brine 29

The Use of Corrosion Prediction Models During Designby D E Paisley

Introduction 31Important Factors not Covered by the Corrosion Model 35Effect of Corrosion Inhibitors 42Predicting the Effectiveness of Corrosion Inhibitors - 48'The Inhibitor Availability Model'Recommended Values for use in the Inhibitor Availability Model 51Comparisons of the Inhibitor Availability Model with BP's Previous Model 62Corrosion Rates of Low Alloy Steels 64Preferential Weld Corrosion 65Effects of Pitting 66Choosing an Optimum Corrosion Allowance 67Applying Models to Different Flow Regimes 69Applying Models to Transportation Equipment 72Applying Models to Process Equipment 86Flow Velocities in Process Pipework 89Economic Tools to Use During Materials Selection 92

References 95

Installation of the Cassandra 98 Excel Workbook 97

Page

Summary

This document decribes BP's current approach to Corrosion Prediction and itsuse during the design of pipelines and facilities. It is divided into twosections.

The first section introduces a new prediction spreadsheet called Cassandra98* which is BP's implementation of the CO2 prediction models published byde Waard et al. It builds on these models to include BP's experience of suchsystems. The pocket inside the front cover of this report contains a floppydisc which contains the necessary programs and spreadsheets to run ittogether with a set of installation instructions.

The second section discusses how the prediction model may be used fordesign purposes and it introduces several improvements from previousguidelines. These include the use of the probabilistic approach to corrosionprediction and the use of corrosion inhibitor availabilities instead ofefficiencies. It also discusses the use of "corrosion risk categories" as a wayof quantifying the corrosion risk at the design stage. The floppy disc alsocontains a spreadsheet for calculating the risk category.

To illustrate the points made examples have been obtained from many BPassets worldwide. Where financial data are shown it is from 1997.

Since this subject is continually changing it is anticipated that these guidelineswill be updated in future years and so any comments or suggestionsregarding either the content or appearance of them would be very welcome.

*In Greek mythology Cassandra was the daughter of Priam and Hecuba. She was endowedwith the gift of prophecy but fated never to be believed. She is generally regarded as theprophet of disaster........especially when disregarded.

Acknowledgements

The authors would like to thank the following BP staff for theircontributions to these guidelines.

Jim CorballyLaurence CowieMike FielderDon HarropBill HedgesWill McDonaldTracy SmithSimon WebsterRichard Woollam

1

Introduction

Carbon dioxide corrosion represents the greatest risk to the integrity ofcarbon steel equipment in a production environment. Compared with theincidences of fatigue, erosion, stress corrosion cracking or over-pressurisation, the incidences of CO2 related damage are far morecommon. Unfortunately, the engineering solutions to eradicating the CO2corrosion risk require high capital investments in corrosion resistantmaterials. As Figure 1 shows, providing a corrosion allowance of 8 mm tocarbon steel flowlines costs a significant sum at circa US$1 million per 5km but even this is insignificant in terms of the costs of the variouscorrosion resistant flowline options.

Similar relative costs are incurred when specifying corrosion resistantmaterials downhole or in facilities. This is rarely justified. For this reason,CO2 corrosion of carbon steel will always be a problem that BPX has todeal with. Managing CO2 corrosion therefore becomes a priority and it canbecome expensive. The replacement of the original Forties MOL and thesevere damage to the Beatrice MOL are two examples of high costs thatBPX have incurred in recent years due to unpredicted corrosion rates.Successful management of CO2 corrosion starts off with the identificationof risks and continues with the provision of suitable controls and thereview of the success of the controls via monitoring - as illustrated inFigure 2.

Figure 1: FullyInstalled Costs forVarious FlowlineMaterials Options inColombia (1997)

0

5

10

15

20

25

30

35

6 8 10 12 14 16 18 20 22 24 26 28 30

Nominal Flowline Diameter - Inches

Cost per

5 Km ($mil l)

Carbon steel 8mm ca

Duplex SS

13%Cr

Bi-metal 13Cr liner

Carbon steel, no ca

INTRODUCTION

2

This document sets out BP’s approach to the quantification of CO2corrosion risk through the use of predictive models. In doing so, it alsodiscusses the reliance that can be placed on corrosion inhibition as theonly viable control measure for carbon steel and the importance ofsuitable corrosion monitoring. To put the importance of this into context,corrosion costs BPX 8.3% of its capex budget and increases lifting costsby 14%, an average of over 8 cents per barrel. Figure 3 shows that thecosts are distributed across the entire range of facilities.

Apply ControlsMonitor Effectiveness

Quantify Risk

Figure 2: The FeedbackLoop that is Required forSuccessful Managementof CO2 Corrosion

INTRODUCTION

3

The quantification of corrosion risk is required at several stages during anassets life. The most obvious period is during the project phase when theoriginal materials of construction are being selected. This process must berepeated during the life of the asset if failures or expansions require theprocurement of additional facilities. Quantifying the corrosion risk is alsoimportant in tailoring inspection strategies. Risk based inspection is nowwidely adopted and, as CO2 corrosion represents one of the most importantfactors governing the probability of failure for much equipment, a reasonedapproach should be taken. It is important that this approach is theoreticallysound but also reflects past experience.

This version of the BP CO2 prediction model is the first to be published since1993/4 when the guidelines on multiphase and wet gas transport respectivelywere issued. The new guidelines incorporate changes by the authors to thesemi-empirical model used in the original guideline as well as comprehensiveguidance on how to use the spreadsheet included with this version. The newmodel also includes the ability to predict the affects of changing flowvelocities on uninhibited corrosion rates.

Downhole13%

Subsea59%

Chemicals4%

Topsides23%

Personnel1%

Figure 3: TheDistribution of Costs ofCorrosion Across TenBPX North Sea Assets,1990 to 1994.

INTRODUCTION

4

The new guidelines also consider the probabilistic approach to predictingCO2 corrosion. Probabilistic approach to design in general is becomingmore widespread and offers several advantages over the traditionaldeterministic approach. The probabilistic approach is neither endorsed nordisallowed but is discussed as, in some cases, it may be more appropriatethan a deterministic approach.

The approach to designing for the use of corrosion inhibitors has beenchanged significantly. The previous approach described the affects of aninhibitor through the use of an efficiency factor, such as 90%. This does notreflect BPX’s recent field data generated under severe conditions whichshowed inhibitors can be more effective than predicted. "Inhibitorefficiencies" have therefore been replaced with "inhibitor availabilities" thatmore closely reflect field experience. There is a general move in the industrytowards this methodology and it offers several advantages.

However, it has become clear that for inhibitors to work effectively thecorrosion management system must be highly organised. Recommendationsare therefore included on methods to ensure that the inhibitor availabilitiesassumed at the design stage occur during the operational stage.

5

"Cassandra 98" Corrosion Prediction Spreadsheetby A J McMahon

"Cassandra 98” is BP's new implementation of the 1991, 1993 and 1995 CO2corrosion prediction models published by De Waard et al. The pocket insidethe front cover of this report contains a floppy disc with the programmetogether with a set of installation instructions.

The 1991 and 1993 De Waard models are already widely used within BP andelsewhere in a variety of customised forms. This report describes the newCassandra 98 spreadsheet for Microsoft Excel. It is based primarily on the1993 De Waard model, incorporates some equations from the 1991 model,and uses the 1995 model to assess velocity effects. The spreadsheet isintended to capture all the best features of the 1991, 1993 and 1995 models[1,2,3]. Certain extra features from outside the De Waard papers, based onstandard physical chemistry, have also been included. The sourc e ,background and limitations of all the assumptions and equations in thespreadsheet are fully documented in these guidance notes.

The Cassandra 98 spreadsheet is written in a simple and accessible formatwithin Microsoft Excel (version 7.0). It avoids the use of macros or specialtechniques so that the logic and the calculations are as transparent aspossible. This approach also ensures that the spreadsheet is immediatelycompatible with new versions of Excel.

The Excel add-in module "CRYSTAL BALL" (from Decisioneering Ltd, 1380Lawrence Street, Suite 520, Denver, Colorado 80204, USA. Tel: +1 303 2922291. Cost ~£100) enables probability distributions to be set for each inputcell and it then uses Monte-Carlo simulation to combine these into aprobability distribution for the resulting corrosion rate. You must buy"CRYSTAL BALL" separately for your Excel environment. It can't be bundledwith this spreadsheet. The detailed use of CRYSTAL BALL is well covered inthe manufacturer's handbook and therefore is not repeated in theseguidelines.

Care is required when comparing the output of any existing in-house versionof the De Waard models against this new Cassandra 98 spreadsheet. It is veryeasy for errors and untested assumptions to be entered into a spreadsheetwhich might then perhaps be passed on from user to user and oftencompounded with other assumptions. Cassandra 98 has been written fromscratch with a detailed re-evaluation of all assumptions, all of which arepresented. Cassandra 98 is intended to be a standard, reference version of theDe Waard approach for use within BP and its partners, until such time that amore consistent approach to corrosion modelling becomes established withinthe oil industry. The activities of the NORSOK industry forum in Norway aremaking helpful moves in this direction.

INTRODUCTION

This section gives enough information to allow experienced modellers tomake a start. The subsequent section gives a more detailed description ofall the input and output parameters. The spreadsheets themselves also carryfrequent "cell notes". These are marked by a red dot in the top right handcorner of those cells. Just double click on the cell to read the contents.

To carry out a basic calculation enter the following input values into thecells with a white background:

Only the inputs in the preceding Table are needed for a straightforwardnumeric calculation. Some further information is required in order to carryout a probabilistic calculation using CRYSTAL BALL. The spreadsheet caneasily be customised by individual users to permit more extensive handlingof probabilities:

"CASSANDRA 98" CORROSION PREDICTION SPREADSHEET

6

QUICK START

Input Parameters

Probabilistsic Inputs

P total gas pressure bar F7%CO2 CO2 in gas mole % (NB = v/v%) F8%H2S H2S in gas mole % (NB = v/v%) M8water composition ion ppm values ppm (NB = mg/ltr) A15-L15brine pH enter known value, F17

or enter "d", "o", or "x" to accept one of the calculated values shown in F18-F20(see Page 17)

T System temperature oC F24Ts Scaling temperature, enter oC F25

the calculated scalingtemperature, given in cellF26, or another known orpreferred value

d hydraulic diameter m M24U velocity m/s M25

Parameter Comments Units CellTable 1: Inputparameters for anumeric calculation


7

P F7 use a uniform distribution; set F7 as the maximum; set G7 as the minimum

%CO2 F8 use a normal distribution; adjust standard deviation as necessary

brine pH F17 must enter a known or a calculated value; use a normal distribution; adjust standard deviation as necessary

T F24 use a uniform distribution; set F24 asthe maximum; set G24 as the minimum

d M24 use a uniform distribution; set M24 as the maximum; set N24 as the minimum

U M25 use a uniform distribution; set M25 as the maximum; set N25 as the minimum

Output Parameters

1993 basic Vcor E32 the uncorrected corrosion rate for static conditions

1993 correction factors G32-K32 correction factors for pH, fugacity,scaling, and glycol

1993 corrosion rate G34 the corrosion rate for static conditions corrected for pH

1995 corrosion rate G39 the corrosion rate for dynamic conditions calculated from the components Vr and Vm in G37 and G38

93/95 merged corrosion G41 the average of the 93 and 95 rate corrosion rates; this cell enables

"CRYSTAL BALL" to combine the93 and 95 probability distributions

Parameter Cell Comment

Parameter Cell Comments

The resulting output parameters are described in Table 3. See p23 for a moredetailed description of how to interpret and use these values. Briefly, the 1993rate should be regarded as the minimum. Velocity effects may increase thisminimum rate as shown by the 1995 rate. Hence, the 1993 and 1995 rates willnormally give the lower and upper bounds on the expected corrosion rate.The 1995 model is not accurate at low velocities and so it should be ignoredwhenever it falls below the 1993 value.

Table 2: AdditionalInput Parameters for aProbabilisticCalculation

Table 3: OutputParameters


8

The use of simple equations and the precision of the spreadsheetenvironment can lead one to think that the De Waard corrosion models areequally precise. However, this is not the case. The models are only validover a certain range of conditions, and even within this range a certainamount of data has been ignored if it doesn't fit the main trends. Each modelappears to be constructed by obtaining a large number of corrosion ratesover a range of conditions and then finding an equation which draws a linepassing close to the majority of this cloud of points. The equations appearto be freely adjusted in order to give the best fit to the data. The primaryconcern is to obtain a good fit to the data, rather than obtainingmechanistically rigorous equations. These are empirical engineering modelsrather than scientific theories.

Neither the 1991 or 1993 De Waard papers give many precise details aboutthe range of validity of the models. The 1995 paper does give a morethorough set of figures (see below) but still omits important features such asthe type of brine used in the tests, and the elapsed time when the corrosionrates were measured. De Waard's very early work used a 0.1% NaCl solution[4] and this may well have been used in all the subsequent studies becausehis main focus has always been low salinity water in gas lines. Table 4shows the approximate ranges of validity for the different parameters in theCassandra 98 spreadsheet.

LIMITATIONS OF CORROSION PREDICTION MODELS

Table 4 : Range ofValidity of De WaardModels

P <200 bar not definedfCO2 <10 bar 0.3-6.5 barOddo & Tomson pH -- -- <200oC, <1000 barXLpH -- -- <120oCT <140oC 20-80oCU 0 m/s 1.5 -13 m/s

Parameter Range of 1991 Range of 1995 Comments& 1993 ModelModels


9

The spreadsheet gives freedom to enter any value for most parameters.When the input value is outside the approximate range of the 1991 and 1993De Waard models then the text will turn RED in the cell as a warning. Thepredicted corrosion rate may still be useful but the user must accept theadditional risk of going beyond the known limits of the correlations.

To develop the 1995 model [3] corrosion rates were obtained on the IFE flowloop (Kjeller, Norway) using a radiochemical technique to measure corrosionrates. Tests were carried out over 2-3 days but there is no information aboutthe corrosion rate profile over this time or when the final data point wastaken. Data were obtained for the following conditions.

- St-52 DIN 17100 steel (Cr 0.08%, C 0.18%) which is similar to ASTMA537 Gr1

- 0.1, 3.1, 8.5, 13 m/s flow velocity- 20 - 90oC- 0.3 - 20 bara CO2

Certain inconsistencies in the data set were eliminated prior to developing themodel. These included:

- 0.1 m/s excluded- 13 m/s excluded when corrosion rate less than at 8.5 m/s- 90oC excluded- CO2 >6.5 bar excluded

Eventually 221 data points were used in the main correlation (Figure 2 ref 3).The main equations are specific to St-52 steel because, "The equationsobtained for St-52 showed a complete lack of correlation for the other steels".The 15 other steels were normalised steels and quench-and-tempered (Q&T)low alloy steels. These were examined over the following conditions toproduce some modified equations which take account of steel composition.

- 3.1, 8.5, 13 m/s flow velocity- 60oC- ca 2 bar CO2- pH 4,5,6

Limits of the 1995Model


10

For normalised steels a "Cr correction" and a "C correction" can be calculatedseparately and together. For Q&T steels the "C correction" has no effect andonly the "Cr correction" is relevant. The Cassandra 98 spreadsheet does notinclude the steel composition equations due to the poor correlationsobtained when fitted to the model.

Errors in matching equations to data points are defined in the 1995 paperby "coefficients of determination". This is a complicated statistical functionranging from 0 (poor correlation) to 1 (perfect correlation). It is not the sameas the "correlation co-efficient" in regression analysis which scales from -1to 1. The "co-efficients of determination" in the paper are 0.91 for the mainSt-52 equations (after excluding the data that doesn't fit), 0.83 for thenormalised steels, and 0.80 for the Q&T steels. For the main St-52 correlationthis corresponds to a standard deviation of 25% on the predicted corrosionrate. This is the error given in this spreadsheet. Because of this error thepredicted corrosion rates are only shown to one decimal place. A "CRYSTALBALL" probabilistic analysis gives a more realistic impression of the error oneach prediction.

The De Waard models were all developed using water-only systems in thelaboratory. The 1993 model is intended for nearly static, aqueous conditionsand so for all but the lowest velocities (see page 77) it can be regarded asthe minimum corrosion rate of a water wet region in a gas/water, water/oil,or a water/oil/gas system. Due to the different hydrodynamics in these fieldcases some assumptions are required in order to apply the 1995 modeleffectively. These assumptions will only affect the diameter and velocityvalues used as inputs in the model. The other inputs will be unaffected.Table 5 gives some suggested assumptions. However, users are free todevelop their own approaches to meet the demands of their own particularcircumstances. Some of the issues involved in extrapolating the models tothe field are discussed in more detail on pages 27-28.

Errors on CorrosionRates

APPLYING THE MODEL TO DIFFERENT FIELD SITUATIONS

Units are specified for each parameter listed in this section. The same unitsare assumed in all the equations given below and throughout the Cassandra98 spreadsheet. The spreadsheet has a "units conversion box" at cell P5. TheUNITS spreadsheet allows conversions between a wider range of units. TheSALTS spreadsheet enables conversion between an ionic analysis of brine andthe salts re q u i red to pre p a re a synthetic analogue. The FUGACITYspreadsheet is a data-base used to calculate fugacity corrections at high totalpressures.

P...total gas pressure (bara, i.e. bar absolute) INPUT cells F7 and G7

For a multiphase system this is simply the prevailing local P in the gas. Fora liquid only system it is the P in the last gas phase which was in equilibriumwith the liquid, e.g. the separator gas in the case of a crude oil export line.For a downhole liquid pressurised above the bubble point then use thebubble point pressure (Figure 4).

For a simple numeric calculation, enter the P value into cell F7. Cell G7 isthen unused. For a probabilistic calculation using "CRYSTAL BALL", set up auniform distribution for P with F7 set as the maximum and G7 as theminimum.


11

DETAILED DESCRIPTION OF THE SPREADSHEET

Total Pressure

Water only use pipe diameter and water velocity

Liquid/Gas use hydraulic diameter (see p 21)use true liquid velocity rather than nominal velocity(see p 22)

Water/Oil use pipe diameter and total liquid velocity(n.b. this ignores the possibility of water drop out orstratification which could lead to the water phase moving more slowly than the oil phase)

Water/Oil/Gas use a specialist multiphase program to calculate the wall shear stress or the "C factor" for the pipe system,then choose diameter and velocity inputs whichreproduce this hydrodynamic value.

Field Situation Recommended ApproachTable 5: Applying the1995 De Waard Modelto Field Situation


12

Figure 4: SchematicDiagram of an OilProduction System(downhole, separator,export)

%CO2...CO2 in gas (mole%, which is same as v/v%) INPUT cell F8

For a multiphase system this is simply the prevailing local %CO2 in the gas.For a liquid only system it is the %CO2 in the last gas phase which was inequilibrium with the liquid, e.g. the separator gas in the case of a crude oilexport line. For a downhole liquid use the %CO2 in the gas formed at thebubble point. If this gas analysis is not available then use the CO2 dissolvedin the brine, the Henry's constant, and the bubble point pressure to back-calculate the "effective %CO2" which would be required in the bubble pointgas in order to sustain the known level of dissolved CO2 (see box at cellP19). Indeed, this procedure can be followed for any region where the CO2dissolved in the brine is known, but the gas analysis is unknown.

There may be occasions when it is helpful to apply parts of the Cassandramodel to a water which is in equilibrium with ambient air (e.g. for pHpredictions). The appropriate atmospheric inputs are P = 1 bara and%CO2=0.035 mole%. Remember that under these conditions the corrosionprediction from the model will only relate to the dissolved CO2 componentand not the dissolved O2.

For a probabilistic calculation using "CRYSTAL BALL", set up a normaldistribution for %CO2 using an appropriate standard deviation.

%CO2


13

pCO2...partial pressure of CO2 (bara) OUTPUT cell F9

fCO2...fugacity of CO2 (bar) OUTPUT cell F10

The non-ideality of gases means that at high total pressures the partialpressure is not an accurate description of the activity of a gas component.The fugacity is the true activity of the gas component. The 1991 and 1993models use pCO2 in the main corrosion prediction equations and then at theend apply a fugacity correction factor (Ffug) to account for fugacity effects.In Cassandra 98 the equations from the 1991 and 1993 models use fCO2directly, therefore there is no need to use a fugacity correction factor (Ffug).The equations from the 1995 model in Cassandra 98 also use fCO2 directly -instead of pCO2. Hence, in Cassandra 98, it is fCO2 which is used as theprimary parameter for all the equations which consider CO2 as an input.

Fugacity data from the work of R H Newton [5] are tabulated in theFUGACITY.XLS spreadsheet in the workbook. The Cassandra 98 spreadsheetuses the input values of temperature and total pressure to look-up the correctvalue of the fugacity co-efficient (γ) in the FUGACITY spreadsheet,

fCO2 = pCO2 γ

The R H Newton data are generally applicable to many pure gases. The datashow fugacity co-efficients as a function of "reduced temperature" and"reduced pressure",

where Tr is reduced temperature (dimensionless)T is the prevailing local temperature (oC)Tc is the critical temperature for the gas (from tables) (oC)

pCO2

fCO2

Tr = TTc

pCO2 = P.%CO 2100


14

where Pr is reduced pressure (dimensionless)P is the total pressure (bar)Pc is the critical pressure for the gas (bar)

Oilfields produce gas mixtures rather than pure gases. Hence, a difficultyarises in deciding whether it is the Tc and Pc for methane or for CO2 thatone should use. In the Cassandra 98 spreadsheet, empirical values of Tc andPc are assumed which allow the Newton model to agree with theCO2/methane mixed gas fugacity data in Figure 5 of the 1993 De Waardpaper to ± 10%. In other words the De Waard data are used to calibrate theNewton model.

The De Waard calibration data are valid up to 140oC and 250 bar. TheNewton data extends beyond these levels up to 300oC and 400 bar. Thegeneral trends in the data will be accurate under these extreme conditions,however, the absolute values are unchecked. For accurate work it will be necessary to calculate or obtain the correct value of fugacity from elsewhereand then manipulate %CO2 in cell F8 by trial and error in order to obtainthe correct fugacity in cell F10.

%H2S...H2S in gas (mole%, which is same as v/v%) INPUT cell M8

H2S is not included in any of the De Waard models. It is only used in theCassandra 98 spreadsheet in the calculation of solution pH by XLpH (seebelow). It can be ignored completely simply by entering zero.

Pr = PPc

CO2 31 73methane -82 45.8

empirical values used to correlate with De Waard data -37 56.7

%H2S

Tc Pc(oC) (bar)

Table 6: ReducedTemperature andReduced PressureValues for CO2 andMethane


15

It is by lowering the solution pH that H2S can potentially increase thecorrosion rate, often in synergy with CO2. In practise, H2S tends to promoteFeS surface films which reduce the observed general corrosion rate but whichincrease the likelihood of localised corrosion whenever the film fails. TheCO2 general corrosion rate is often assumed as the worst-case localisedcorrosion rate for the regions with no FeS film.

An alternative approximate approach for handling the presence of H2S is toassume that every 1 mole% H2S has the same corrosivity as 0.01 mole% CO2.This rule of thumb assumes that 1 ppm dissolved CO2 and 200 ppm dissolvedH2S give roughly equal corrosion rates [6], and that H2S is roughly twice assoluble in water as CO2 for a given partial pressure [7].

pH2S ...partial pressure of H2S (bar) OUTPUT cell M9

pH2S = P . %H2S

water chemistry ..ion concentrations (ppm, same as mg/ltr) INPUT cells A15-L15

The water chemistry is used to calculate the solution pH (see below). Enterppm values for Na+, K+, Ca2+, Mg2+, Ba2+, Sr2+, Cl-, HCO3-, SO42-, Fe2+,acetate. (NB enter the sum of all organic acids as acetate). Enter the %v/vvalue for glycol in cell L15. Use the SALTS spreadsheet to check that the totalpositive and negative charges of the ions are roughly balanced. Anysignificant misbalance (e.g. >10%) may invalidate the pH calculation. Notethat ion charges are handled in general chemistry by using the term"equivalents": 1 mole of positive charges is equal to one equivalent; in otherwords 0.7 mole of Ca2+ ions is equal to 1.4 equivalents of positive charge.Some further aspects of the acetate entry are discussed on p.19.

T D S...total dissolved solids in water phase (ppm, same as mg/ltr) OUTPUT cell M17

pH2S

LIQUID PARAMETERS

Water Chemistry

Total DissolvedSolids


16

This is the sum of all the individual dissolved ions concentrations. TDS and[HCO3-] are used in the Oddo & Tomson pH calculation. TDS is also usedto estimate the "salting-out" of CO2 as salinity increases. This will tend toreduce the concentration of dissolved CO2 and thereby reduce the corrosionrate [8]. The box at X19 shows how to apply the salting-out correction. Theprocedure uses "Henry's Law" to calculate the solubility of a gas in a liquid.

pCO2 = KH XCO2

where KH is Henry's constant (bar/mole fraction)XCO2

is mole fraction of CO2 dissolved in brine.

The Henry's constant from the De Waard paper is only valid for a lowsalinity brine (ca 0.1% NaCl). Therefore, by calculating the true Henry'sconstant for a specific brine it is possible to apply a salinity correction to theDe Waard corrosion rate.

The salt-correction procedure first calculates the Henry's constant used bythe De Waard model (equation 28 from the 1993 paper- which is used in thederivation of equation 13 in the 1993 paper),

where KH is Henry's constant (mole/ltr bar)

Note that this KH equation from the De Waard paper has different units(mole/ltr bar) from those given earlier (bar/mole fraction). Much of theconfusion over Henry's constants arises from the wide and sometimesawkward range of units which can be used to express the parameter. Forconsistency in this report the De Waard equation for an aqueous solutioncan be rewritten in order to maintain KH in units of (bar/mole fraction)..

where KH is Henry's constant (bar/mole fraction)

log10 KH = 1088.76T + 273

− 5.113

log10 KH = − 1088.76T + 273

− 5.113

181000


17

The true Henry's constant is a function of both salinity and temperature(Appendix 1) so that,

Therefore, the salt-correction factor, Fsalt, is,

The best way to use Fsalt is to apply it to fCO2 to give an "effective CO2fugacity". This "effective fCO2" will give the correct dissolved CO2concentration when used with the other equations in the Cassandra 98model. The salt correction effect only becomes significant for TDS > 10% w/v.

pH ...brine pH control parameter INPUT cell F17

Enter the known pH value, or else enter a letter to accept one of thecalculated pH values given in cells F18, F19, or F20

❍ "d" or "D" will accept the De Waard distilled water pH

❍ "o" or "O" will accept the Oddo & Tomson brine pH

❍ "x" or "X" will accept the BP XLpH calculated value.

The accepted value is displayed in cell F21 for confirmation.

KHtrue (for 0−125°C) = (1.77 T + 47.1)

TDS10000

+ (45.2 T+ 559)

KHtrue (for 125 −200°C) = 250

TDS10000

+ 6500

Fsalt =KH

De Waard

KHtrue

Brine pH


18

When doing a probabilistic calculation using CRYSTAL BALL then a numericvalue of pH (either known or calculated) must be entered. Use a normaldistribution for the probability adjusting the standard deviation so as tocover appropriate minima and maxima.

pH(CO 2)...pH of distilled water containing CO2 OUTPUT cell F18

Equation (8) from the 1995 paper...

pH(CO2) = 3.82 + 0.000384 T - 0.5 log10 (fCO2)

fCO2 is used here rather than the pCO2 quoted in the original paper. Theequation is valid over 10-80oC. It gives the pH for pure water containingdissolved CO2 at the prevailing temperature and fCO2.

pH(act, Oddo) ..Oddo & Tomson calculated pH in brine OUTPUT cell F19

An empirical equation from reference 9...

+0.000000458 (T * 9/5 * 32)2 - 0.0000307 (P * 14.5)...

fCO2 is used here rather than the pCO2 quoted in the original paper. Theequation is valid up to 200oC and 1200 bar, but is inaccurate for low valuesof [HCO3

-]. The Cassandra 98 spreadsheet is set to give an error for pH(act,Oddo) if [HCO3

-] < 50 ppm.

pH(CO2)

pH(act)

−0.477TDS

58500

1 / 2

+ 0.193TDS

58500

pH = log10

HCO3−[ ]

fCO2 *14.5 *61000

+ 8.68 + 0.00405(T * 9 / 5 * 32)...


19

pH(act, XLpH) ...XLpH calculated pH in brine OUTPUT cell F20

XLpH is an Excel add-in function for calculating both pure water and brinepHs with no restrictions on salinities or component concentrations. It wasdeveloped by XTP, Sunbury using well documented code published by theUS Geological Survey (the "PHREEQ" model). The original version of XLpH[10] has since been updated to include pH2S as an input parameter. XLpH hasbeen validated against other pH models such as in CORMED and also againstliterature and recent laboratory values.

XLpH uses the individual ion concentrations in cells A15-L15. The positiveand negative charges must be approximately balanced (see "water chemistry",p15, above). XLpH will automatically compensate for any small misbalancesby adding Na+ or Cl- ions.

Enter the sum of all organic acids as acetate. Note that the pH of CO2-containing-brine will differ depending on whether the acetate is added in theform of sodium acetate salt or acetic acid...

pH of 0.5 M NaCl / 300 ppm NaHCO3, 1 bar CO2, 25oC plus...

no acetate 6.8 mM Na acetate 6.8 mM acetic acid(i.e. 571 ppm) (i.e. 422 ppm)

5.53 5.41 4.17

XLpH assumes that the acetate value entered in cell K15 is acetic acid,because this is the worst case. If one wishes to assume Na acetate then zeroshould be entered for Ac and the molar equivalent of Na acetate should beadded to the Na and Cl entries. Unfortunately a field water analysis will notdirectly reveal whether Na acetate or acetic acid should be used to simulatethe water chemistry. This can only be established by making laboratory pHmeasurements under CO2 saturation and comparing the results with theXLpH model.

Inclusion of the organic acid concentration will always improve the reliabilityof a prediction. However, when organic acid data is not available it is possibleto make some rule-of-thumb approximations in order to aid progress.Organic acids are typically present in formation water at <30ppm. Therefore,for bicarbonate >150ppm, the presence of organic acids is likely to make littledifference to the calculated pH and therefore corrosion rate. In such cases,an API water analysis (which omits organic acids) will often suffice. If theformation water is low in bicarbonate (<150ppm), then there is more chancethat organic acids could make a significant contribution to the in situ pH andcalculated corrosion rate and so an acetate entry should be added to thewater analysis.

pH(act, XLpH)


20

accepted pH ...confirmation of selected pH OUTPUT cell F21

This is confirmation of the pH value which has been accepted for thecorrosion prediction equations.

T...temperature (oC) INPUT cell F24

The prevailing local temperature. When doing a probabilistic calculationusing CRYSTAL BALL then use a uniform distribution for the temperature :set F24 as the maximum and G24 as the minimum.

Ts...selected scaling T (oC) INPUT cell F25

Enter a preferred value for the scaling temperature or enter "a" (or "A") toaccept the calculated value shown in cell F26.

Researchers are still actively investigating the issue of what happens tocorrosion rates at temperatures above the scaling temperature. Previouswork has shown that sometimes the scale films are protective and canreduce the corrosion rate, whereas sometimes the films are non-protectiveso that the corrosion rate continues to increase. Choosing one or other ofthese options could on the one hand lead to significant under-design, andon the other hand to significant over-design. Therefore, until the matter isfully resolved BP prefers to choose a middle course for design purposes. BPassumes that the corrosion rate reaches a peak at the scaling temperatureand remains on a plateau at the same value for higher temperatures. TheCassandra 98 spreadsheet follows this approach. In order to achieve thisoutcome both fCO2 and pH are set to a plateau for T > Ts.

T

Scaling T

IFE, Norwaydata

BP approach

De Waardapproach

Ts

Corrosion Rate

Temperature

Accepted pH

Figure 5: The PossibleEffects of HighTemperature Scaling onthe Corrosion Rate


21

Ts...De Waard calculated scaling T (oC) OUTPUT cell F26

Equation (13) from the 1995 paper,

This is obtained by setting log10 Fscale = 0 (i.e. Fscale = 1) in equation (13) inthe 1995 paper. Note that the equation above is expressed in oC and usesfCO2 rather than the oF and pCO2 used in the paper. The 1993 paper gives asimilar equation to the 1995 paper but uses a factor of 0.67 in front of the logterm instead of 0.44.

d...hydraulic diameter (m) INPUT cell M24

A diameter input value is only required for the velocity equations in the 1995model. It is not needed for the 1993 model. The 1995 paper actually uses"hydraulic diameter" rather than a simple pipeline diameter. Let Dp bepipeline diameter, and let Dh be hydraulic diameter, then,

..for gas/liquid pipelines, Dh < Dp

Dh = 4 A / S

..where A is the cross-sectional area of the liquid in the pipeS is the cross-sectional perimeter length of the liquid region (i.e. liquid/pipe + liquid/gas interfaces, see Figure 6)

..therefore for a pipeline full of liquid, Dh = Dp

De Waard CalculatedScaling Temperature

Ts = 24006.7 − 0.44log10fCO2

− 273

Diameter


22

There is a box at cell P39 for calculating hydraulic diameters in gas/liquidlines. The ratio of the liquid and gas cross-sectional areas, or the ratio of theliquid depth to the pipe radius, is required as an input parameter.Calculation of this parameter is outside the scope of the Cassandra 98spreadsheet.

When doing a probabilistic calculation using CRYSTAL BALL then use auniform distribution for the hydraulic diameter : set M24 as the maximumand N24 as the minimum.

U...flow velocity (m/s) INPUT cell M25

A flow velocity input value is only required for the velocity equations in the1995 model. It is not needed for the 1993 model. There is a box at cell P5which enables calculation of flow velocity from pipe diameter and flow inliquid only lines. The calculation is more complicated for the liquid phasein gas/liquid lines, therefore, the box at cell P39 should be used.

When doing a probabilistic calculation using CRYSTAL BALL then use auniform distribution for the flow velocity : set M25 as the maximum and N25as the minimum.

cross-sectional perimeter lengthof the liquid region

Flow Velocity

Figure 6: Explanationof Parameter "S" in aGas/Liquid System


23

Vcor ...basic corrosion rate (mm/yr.) OUTPUT cell E32


The basic corrosion rate is adjusted by multiplying with the pH andoccasionally the glycol correction factors (FpH and Fglyc respectively). Theapplication of each of these is discussed below.

For the basic corrosion rate and the correction factors, the values reached atthe scaling temperature are set to remain the same at higher temperatures.This is to ensure that the corrosion rate reaches a peak at the scalingtemperature and then remains on a plateau at the same value for highertemperatures (see Ts section above). Hence, the BP approach does takeaccount of scaling at high temperatures but doesn't use the De Waard scalingfactor, Fscale, directly.

FpH ...pH correction factor OUTPUT cell G32

Equations (9) and (10) from the 1991 paper,

log10 FpH = 0.32 (pHCO2 - pHact)

for pHCO2 > pHact

where ...pHact is the actual pH of the brine which wets the pipewall...pHCO2 is the pH under the same conditions but in pure,

salt-free water

log10 FpH = - 0.13 (pHact - pHCO2)1.6

for pHCO2 < pHact

Outputs : 1993 De Waard Model

Vcor...BasicCorrosion Rate

log10 Vcor = 7.96 − 1710T

− 0.67 log10 (fCO2)

pH CorrectionFactor


24

These equations show that as pHact rises, FpH will get smaller and so thecorrosion rate will fall.

These equations use pHCO2 instead of the "pHsat" used in the De Waardpaper. pHsat is the pH at which a brine first becomes saturated with eitherFeCO3 or Fe3O4 as a result of the steel corroding and building up dissolvedFe2+ in the solution. The problem with pHsat is that it is difficult to define.Even the De Waard paper only gives some approximate expressions for oneparticular brine composition (10% NaCl). Furthermore, there is serious doubtover the whole concept of a fixed saturation pH due to the observation ofmassive supersaturation effects by IFE (Norway) and also within BP.Dissolved Fe2+ concentrations can often reach hundreds of ppm and canexceed the theoretical saturation values by orders of magnitude. Hence,pHsat is not a reliable concept.

Until the pHsat issue is resolved BP prefer to use pHCO2 as an alternativereference point. It has the advantage that it is well defined and is valid overa wide range of conditions. Therefore, a pure water system will give pHact= pHCO2 and so FpH = 1 in the BP approach. Certain conditions can makepHact < pHCO2 (e.g. high salinity, zero bicarbonate) and so FpH > 1. Thepresence of bicarbonate will tend to make pHact > pHCO2 and so FpH < 1.

One way of reconciling these divergent approaches is to say that the directDe Waard approach uses Fph to derive the initial corrosion rate in a brinebefore corrosion products build up and gradually reduce the corrosion rateuntil it reaches a steady state. This is the issue discussed in the 1993 DeWaard paper. The BP approach on the other hand does not deal with initialcorrosion rates at all. It deals only with steady state corrosion rates and usesFph to express the effect of water composition on the steady state rate. Thiseffect is not covered in the direct De Waard approach. In essence BP havetaken an equation from the direct De Waard approach and then adapted itfor another purpose. Hence, overall, the two approaches are different butconsistent.

Ffug ...fugacity correction factor OUTPUT cell J32


Fugacity CorrectionFactor

log10 Ffug = 0.67 0.0031− 1.4T + 273

P


25

Ffug is not required in the BP approach because fCO2 is used in preferenceto pCO2 throughout the calculation and so fugacity has already beenaccounted for.

Fscale ...scaling correction factor OUTPUT cell K32


where ... T > Ts otherwise Fscale = 1... Tscale is scaling temperature (defined above)

This factor is not used directly in the BP approach. It is included in thespreadsheet only for completeness.

Fglyc ...glycol correction factor OUTPUT CELL H32


log10 Fglyc = A (log10 W - 2)

where ... A is a constant = 1.6 to a first approximation... W is water content (%) of water/glycol mixture

BP only use this factor for cases without corrosion inhibitor. When acorrosion inhibitor chemical is used or is planned then BP assume that anyeffect of glycol is included within the corrosion inhibitor efficiency (normally90%, but see discussion on pages 42-48).

V'cor ...corrected corrosion rate (mm/yr.) OUTPUT cell G34

This is BP's preferred output from the 1993 DeWaard model. It is the basecorrosion rate multiplied by the FpH correction factor. Note that for the basiccorrosion rate and the correction factor, the values reached at the scalingtemperature are set to remain the same at higher temperatures. This is toensure that the corrosion rate reaches a peak at the scaling temperature andthen remains on a plateau at the same value for higher temperatures (seeT(s) section above). Hence, the BP approach does take account of scalingeffects at high temperatures but doesn't use the De Waard scaling factor,Fscale, directly.

log10 Fscale = 24001

T + 273− 1

Tscale + 273

Glycol CorrectionFactor

CorrectedCorrosion Rate

Scaling CorrectionFactor


26

The 1995 De Waard model is derived in a different fashion from the 1993model, in particular it does not use the idea of correction factors applied toa base corrosion rate. Instead, the overall corrosion rate is calculated fromtwo components : the reaction rate Vr and the mass transfer rate Vm.

Vr ...reaction rate (mm/yr.) OUTPUT cell G37


Vm ...mass transfer rate (mm/yr.) OUTPUT cell G38

Equation (10b) from the 1995 paper,

Vcor ...corrosion rate (mm/yr.) OUTPUT cell G39


where Vcor is overall corrosion rateVr is reaction rateVm is mass transfer rate

Outputs : 1995 De Waard Model

Reaction Rate

log10 Vr = 6.23 − 1119T+ 273

+ 0.0013 T+ 0.41log10 (fCO2 ) − 0.34pH act

Mass Transfer Rate

Vm = 2.45U0.8

d0.2fCO2

Overall CorrosionRate

1Vcor

= 1Vr

+ 1Vm


27

Vcor ...merged corrosion rate (mm/yr.) OUTPUT G41

The merged rate simply takes the average of the 1993 and 1995 values. Thisallows CRYSTAL BALL to combine the probability distributions for the 1993and 1995 rates so that one can see the lower and upper bounds on theexpected corrosion rate.

The 1993 rate is regarded as the minimum. Velocity effects may increase thisminimum rate as given by the 1995 value. The 1995 model is not accurate atlow velocities so it is ignored whenever it falls below the 1993 value, andthen the merged rate is the same as the 1993 rate.

The validity of any corrosion prediction model depends on how well itagrees with the measured corrosion rates in the field. However, thecomparison is not always straightforward. This is because the models aredeveloped from well characterised, clean and stable systems in thelaboratory, and they are being applied to partially characterised, dirty, andvariable systems in the field where the full operating history is not alwaysknown. This is no criticism of field activities. It is simply a fact of life ofoperations where the aim is to produce hydrocarbons, not to generatecompletely rigorous corrosion data.

The discrepancies between the models and r eal field corrosion data whichdo exist arise because there are parameters in the field which the model cannot take account of effectively, or at all, e.g. surface coatings (scales,corrosion products, biomass), crude oil wetting, local hydrodynamics, weldmetallurgy.

The industry generally regards the De Waard model as conservativecompared to the field, i.e. it over-estimates the field corrosion rate. Much ofthis opinion is based on anecdotal and semi-quantitative evidence - often notpublished in the open literature - but it is confirmed by the occasional formalpresentation [12]. BP is currently compiling a database of field corrosion data

1993 & 1995Merged CorrosionRate

Vcormerged = Vcor

1993 + Vcor1995

2

COMPARING OUTPUT FROM THE “Cassandra 98” MODEL WITH FIELD DATA


28

from a variety of sources which will be used to assess the Cassandra 98spreadsheet presented here.

In the meantime Table 7 gives a comparison of the Cassandra 98spreadsheet against new laboratory data; data which were not used incompiling the model. The final column shows whether the observedcorrosion rate falls within 15% of the range encompassed by the 1993 and1995 models and there is some agreement. However, the discrepanciesshow the pitfalls in trying to push the accuracy of the model too far. It isbest used to gain order of magnitude estimates of corrosive situations ratherthan absolute corrosion rates to several decimal places.

Table 7: Comparisonof Model Predictionswith Laboratory Data

BP 1993 0.1% NaCl, 3 litre flow loop (15 mm ID)25 1.9 1 5 1.1 5.8 yes25 1.9 0.27 2.2 0.5 1.9 yes35 1.9 0.27 3.4 0.7 2 noBP 1992 Forties brine, beaker test and 5 litre flow loop (15 mm ID)50 0 0.88 2.5 1.5 0.1 no50 1.2 0.88 2.5 1.5 3.2 yesCAPCIS Flow Project Forties brine, flow loop (10 mm ID)25 3.2 1 1.8 0.6 3.3 yes50 1.1 0.88 3.8 1.5 3.2 yes50 1.7 0.88 4.1 1.5 3.9 yes50 2.5 0.88 2.5 1.5 4.4 yes50 3.2 0.88 4 1.5 4.7 yesCAPCIS Flow Project 3% NaCl, flow loop (10 mm ID)25 3.2 1 6 1.2 7.7 yes50 3.2 0.88 12.1 3.1 9.2 no70 3.2 0.88 17.4 5.3 8.4 no50 1.1 0.88 6.8 3.1 4.8 no50 1.7 0.88 7.3 3.1 6.4 yes50 2.5 0.88 8.6 3.1 8.1 yes

corrosion rate (mm/yr.)T U fCO2 observed 93 95 correct?(oC) (m/s) (bar) model model


29

"Henry's Law" describes the solubility of a gas in a liquid,

pCO2 = KH XCO2

where KH is Henry's constant (bar/mole fraction)XCO2

is mole fraction of CO2 dissolved in liquid

Henry's constants are dependant on both temperature and salinity and theyare easily found for CO2 dissolved in pure water [e.g. 13]. The data for brinesis less extensive [14-16]. Figure 7 is compiled using data from all thesesources. The reduced number of points at higher salinity are still sufficient toshow that the data in the 0-10% region can be reliably extrapolated up to ca30% NaCl. Note that the 16 and 31% data at 75 and 100oC are actually forMgCl2 in the original paper but have been plotted in Figure 7 at theequivalent ionic strength of NaCl.

APPENDIX 1 : "Henry's Law" Constants for CO2 Dissolved in Brine

0

2000

4000

6000

8000

10000

12000

14000

0 5 10 15 20 25 30 35

[NaCl] %w/w

Kh (

bar/

mol fr

ac)

20017515012510075503010

T (oC)

The lines in this figure can be represented by the following equations (towithin ±15%),

Figure 7: Henry'sLaw Constants as aFunction of Salinity


30

where KH is Henry's constant (bar/mole fraction)

Cell AD31 in the spreadsheet uses these equations to calculate the trueHenry's constant for the input values of T and TDS.

KH (for 0 −125°C) =(1.77 T + 47.1)TDS

10000+ (45.2T +559 )

KH (for 125− 200°C)250TDS

10000+ 6500

31

The Use of Corrosion PredictionModels During Design by D M E Paisley

The value and purpose of predictive corrosion rate models should be neitheroverlooked nor exaggerated. The models (of which CO2 models are oneexample) are tools for the Materials Engineer to use during materials selectionstudies. The models help to quantify the corrosion risk and to help assessthe impact of various process or production scenarios. However, corrosionrate prediction models should always be used in conjunction with other toolssuch as life cycle costing as well as previous operational experience if thefinal materials selection is to offer the optimal balance between cost andreliability. As each project will have unique economic factors, materialsselection should reflect these and the economic assessment will be asimportant as the corrosion modelling in the selection of the final materials.In-depth coverage of techniques such as life cycle costing and estimatingvalues are beyond the scope of this document but both techniques are brieflycovered in a previous publication [17].

Over the past few years, several design guidelines have been issued by BPfor dealing with CO2 corrosion risks. Each document deals with a specificapplication. This more general document summarises all previous guidelinesbut can not deal with the specific issues to the level of detail possible in theindividual guidelines. The previously issued guidelines are listed in Table 8.

Introduction

THE USE OF PREDICTIVE MODELS DURING DESIGN

32

Table 8: PreviouslyIssued DesignGuidelines

A corrosion philosophy for the transport of wet oil and multiphasefluids containing CO2

This was the first undertaking in recent years to document a BP approachto defining internal corrosion risks and the basic approach is still followed.It recommended the use of the de Waard and Milliams model to predict in-situ corrosion rates along with a 90% corrosion inhibitor efficiency. Muchof the work is still valid but it is in the areas of high temperature scaling,corrosion inhibitor efficiencies and impact of various flow regimes that the

Report Title Authors Report Number Issue Date

A corrosion philosophy for the I D Parker ESR.93.ER.013 1/3/93transport of wet oil and J Pattinsonmultiphase fluids containing A S Green.CO2

A corrosion philosophy for I D Parker ESR.94.ER.016 28/8/94the transport of wet J Pattinsonhydrocarbon gas containing A S Green.CO2

Assessment of a top of line D Paisley Branch Report 5/10/92versus bottom of line corrosion J Pattinson No 124 421ratio for use in the design of S Websterwet natural gas pipelines

The application of pH D Paisley ESR.95.ER.042 10/4/95moderation as a means of corrosion control for wet gas pipelines

The effects of low levels of D Paisley ESR.95.ER.073 22/6/95hydrogen sulphide on carbon R Gourdindioxide corrosion: A review of industry practice and a guideto predicting corrosion rates


33

new guidelines differ. Most of the recommendations made in theseguidelines have been reproduced or superseded in the present document andtherefore the original guidelines are redundant.

A corrosion philosophy for the transport of wet hydrocarbon gascontaining CO2

This was a companion document to the guidelines on wet oil and multiphasesystems. The basic approach was similar but this document dealt with thespecific wet gas application. Most of the recommendations made in theseguidelines have been reproduced or superseded in the present document andtherefore the original guidelines are redundant.

Assessment of a top of line versus bottom of line corrosion ratio foruse in the design of wet natural gas pipelines

Wet natural gas pipelines operating under stratified flow have two distinctcorrosion environments : (a) the bottom of line which is continually wettedby condensed water, hydrate inhibitor and hydrocarbons, and (b) the top ofline which is wetted intermittently by condensing liquids. The corrosion rateat the top of the line is lower than that at the bottom due to the more limitedexposure to corrosive species. Predicting this rate is done by predicting thebottom of line rate using models in the normal way and applying amoderating factor for the top of line rate. Up to 1992, BP used a factor of0.3, i.e. the top of line corrosion rate was predicted to be 30% of the bottomof line rate. When inhibitors are used to control the bottom of line rate, thetop of line corrosion rate becomes the limiting rate as inhibitors are assumednot to protect against condensing corrosion. This report reviewed the top ofline factor and recommended the adoption of a moderating factor of 0.1. Forinhibitor efficiencies up to 90%, the top of line corrosion rate is therefore notthe limiting rate. This approach is no longer valid since BP have moved awayfrom the direct use of inhibitor efficiencies, as described later in this report.However, the assumption that top of line rates are 1/10th of the predicteduninhibited bottom of line rates can still be used. For applications were the'top of line' corrosion rate is the faster rate (using the 0.1 moderating factor)then a more detailed evaluation should be carried out. Such a scenario doesnot lend itself to the use of simplified guidelines.


34

The application of pH moderation as a means of corrosion controlfor wet gas pipelines

This technique is not widely applicable but may find niche applications inhighly corrosive wet gas lines utilising recycled glycol for hydrate control.It is covered in more detail on p75 but if this technique is of interest the fullguideline document should be reviewed.

The effects of low levels of hydrogen sulphide on carbon dioxidecorrosion: A review of industry practice and a guide to predictingcorrosion rates

This document summarised how low levels of H2S influence corrosion ratesdominated by CO2. The conclusion was that H2S at levels below the NACEcriteria for sulphide stress corrosion cracking (ref MR0175, NACEPublications) reduces general metal loss rates but can promote pitting. Thepitting proceeds at a rate determined by the CO2 partial pressure andtherefore CO2-based models are still applicable at low levels of H2S. Wherethe H2S concentration is greater or equal to the CO2 value, or greater than1 mole%, the corrosion mechanism may not be controlled by the CO2 andtherefore CO2 based models may not be appropriate.

Summary of Previous Guidelines

In summary, the old guidelines are generally still applicable. What haschanged is BP’s views on the reliability and performance of corrosioninhibitors as well as the availability of updated models incorporating flowaffects. The old guidelines defined a corrosion inhibitor efficiency of 90%with no scope for variation. There were also stringent velocity restrictionsfor use under multiphase conditions which restricted the energy of slug flowto below 20 Pa, later raised to 100 Pa. In light of favourable field data, thisapproach is now seen as too pedantic and inhibitor availabilities are seen asa better way of describing the role of inhibitors. These differences inapproach are covered in more detail in the following sections. Furthermore,the corrosion rate prediction model (p5-30) does not cover some aspectsthat are important during design and these are covered in the next section.


35

The modelling approach outlined in this document deals with all the inputs(mole% CO2, temperature etc.) on a deterministic basis. However, each inputwill have a level of uncertainty associated with it and this can have importanteffects on the outcome. One way to deal with this it to calculate a range ofoutput values, (in this case the predicted corrosion rate) across the wholerange of input values. Where the model is dealing with several inputs(temperature, pressure, CO2 mole %, pH, scaling factor), this can be timeconsuming. Also, the value of these inputs will not all vary in a uniformmanner. Some will behave uniformly while others may behave in a normalor log-normal manner.

Calculating the impact of all these variables is time consuming, unless aprogramme such as Crystal Ball is used. This is an add-in to Excel andhandles the variability by performing a Monte Carlo analysis. Any number ofiterations can be performed and the output is displayed in terms of aprobability, rather than as a discreet value. In general, a minimum of 1,000iterations, involving tens of thousands of individual calculations are requiredto show the effects of the variability in input data. A modern PC can performsuch a task in a minute or two.

The important factors to consider are the range and type of distributionassumed for each variable. If process data are available, this will form anideal basis for determining the range and type of distribution but if this islacking, some assumptions will have to be made.

Using distributions to define variables in a predictive model can havesignificant effects on the outcome.

Engineering design traditionally uses worst case inputs so that the final designwill be safe under all foreseeable combinations of events. This approach hasalso been adopted when predicting corrosion rates, where pressure andtemperature etc. are used as inputs to the models. In the past this approachwas the only viable one as predicting the enormous range of possibleoutcomes for all variables would have been too time consuming but it canresult in substantial over-design. Metal loss corrosion processes do not leadto sudden failure due to a combination of variables over short time periods

Worst Case Design

Important Factors not Covered by the Corrosion Model

The ProbabilisticApproach toPredictive Modelling


36

(unlike high pressure which can lead to an instantaneous failure) but ratherreflect a combination of varying conditions over a longer time period. Usingthe worst case values is therefore not a sensible approach, if a range of morerealistic values can be handled.

In defining a range of likely operating variables such as temperatures andpressures, the design values will form the maximum for the respectivedistributions but lower values should be included. Defining this range willrequire inputs from the Process and Reservoir Engineers. Due to the natureof the uncertainty, such that all values within the range are as likely as eachother, Uniform distributions are probably the most appropriate for thesevariables.

The yield strength and wall thickness of linepipe are other examples of thetype of variables that can be treated in this manner. The linepipe propertiesare important if using corrosion models to calculate mean time to failure.Rather than using the minimum values for each, based on the specifiedmaterial and the variation allowed within the specification, typicaldistributions can be defined for each value. Such variables tend to bedistributed normally around a mean with the specified minimum propertiesdefining a lower bound.

Many variables in corrosion rate predictions, such as the level of CO2 in thegas phase, are based on “best guess” or on limited well test data. Noattempt is made to define the uncertainty in these data and this is a majorlimitation of deterministic modelling. In defining the distributions of suchvariables, the mean value should be based on the best guess or well testdata in a similar way to the deterministic approach. However, a range ofpossible values should be considered. In the absence of any otherinformation, the distribution of values is likely to be symmetrical around themean with the greatest probability associated with values close to the mean.The Normal distribution is a familiar example of this type and should beused.

It should be noted that using a symmetrical distribution, such as a Normaldistibution, does not correspond to using a single value equal to the meanif the variable under consideration has a non-linear relationship with theoutcome. For example, the corrosion rate prediction model used by BPstates that:

Non-LinearRelationships


37

Therefore, the corrosion rates associated with the CO2 partial pressure valuesin the Normal distribution that are greater than the mean value are closer tothe mean corrosion rate than those associated with the values below themean CO2 partial pre s s u re. In other words, defining symmetricaldistributions for variables whose influence is described by a power < 1produces a non-symmetrical distribution of outcomes (predicted corrosionrates). The mean value of this distribution will be lower than the single valuecalculated using the mean of the input variable.

The same applies to all symmetrical distributions, including Uniformdistributions. In the previous section on 'worst case design', the uncertaintiesregarding operating temperature and pressure were discussed. In both cases,Uniform Distributions were used to define the range of possible values. Incorrosion rate modelling, both these inputs have non-linear relationships withthe outcome (predicted corrosion rate). The effect of pressure is moderatedby a fugacity coefficient related to the non-ideality of CO2. Therefore,considering a range of pressures distributed symmetrically around a meanvalue will tend to reduce the predicted corrosion rate.

The effect of temperature on predicted corrosion rates is strongly non-linear.At higher temperatures, the role of protective corrosion products or scales canbe important. There is a great deal of uncertainty in the effects of these scalesbut the bounds of the expected values can be defined using existing models.One approach would be to use a log normal distribution, defined as follows:

1. The de Waard & Milliams unscaled rate (upper bound), 2. The de Waard & Milliams fully scaled rate (lower bound), 3. A modal value equivalent to the standard BP approach that uses the

scaling temperature to calculate the corrosion rate for all temperaturesabove this.

Again, the outcome of considering a range of temperatures symmetricallydistributed around a mean will tend to be a lower corrosion rate estimationthan found by calculating a single value at the mean temperature.

Each input into a corrosion rate prediction should be considered and a rangeof possible outcomes defined. By consideration of the way in which thevalue may vary in practice, a distribution function can also be defined. Thismay have to be done subjectively but the following basic rules offer someguidance. In the following examples, distributions are shown that have beenused in the Crystal Ball software.

Summary of Inputsto a Monte CarloAnalysis

Corrosion Rate ∞ CO2 partialpressure( )0.67


38

1. Where variations would be due to nature, such as the difference inCO2 levels around the field, a Normal Distribution should be usedwith a mean equivalent to the best guess. Figure 7 shows an exampleof a Normal Distribution describing the expected variation in CO2levels, centred around a mean of 5%.

Figure 7: An Exampleof a NormalDistribution for theconcentration of CO2in a gas. The MeanValue is 5 mole% with arange of 3 to 7 mole%.


39

2. Where an input may vary over a wide range but would be expected tobe skewed around the 'best guess' or predicted value, a Log NormalDistribution should be used. The effects of high temperature scalingwould be an example of this type of distribution, or the pit depth atwhich inhibitors fail to control corrosion. Figure 8 shows the LogNormal Distribution used to describe the critical pit depth with a modalvalue of 8 mm and a range of 5 to 12mm.

Figure 8: An Exampleof a Log NormalDistribution describingthe critical pit depth.


40

Figure 9: An Exampleof a UniformDistribution Describingthe Flowline OperatingPressure

3. Where a value may occur equally often within the defined range e.gflowline operating pressure, a Uniform Distribution should be used,i.e. all values are equally likely to occur. Figure 9 shows how a rangeof flowline operating pressures can be described. In this case therange of 1,000 to 1,200 psi has been used.

Table 9 summarises the assumptions used in a recent probabilistic studyinto mean time to failure, based on CO2 corrosion risks. As the studylooked at failure mechanisms as well as corrosion rates, some of the factorsapply to the linepipe steel while others apply to the CO2 prediction model.The 'Standard Value' corresponds to the value that would be used in adeterministic study. The Table does not attempt to fully define thedistributions in a statistical sense but more information is available from theauthors if required.


41

Linepipe Wall thickness e.g. 0.75" Mean = 0.75" NormalSD = 0.01

Linepipe Yield Stress SMYS Mean = 70 ksi Normale.g. 65 ksi SD = 2.5 ksi

Linepipe Flow Stress - - - - 1.15 x Yield Stress Normal

Fluids CO2 Content 5 mole% Mean = 5% NormalSD = 0.72

Fluids Temperature 110oC 85 - 110oC UniformFluids Pressure 1,200 psi 1,000 - 1,200 psi Uniform

Corrosion Water pH Cormed * Cormed * Normalmodel prediction ± 0.25 unitsCorrosion Corrosion rate >Rate at scaling Unscaled to Log Normalmodel scaling ToC temperature fully scaled

Inhibitor Inhibitor 90% 65 - 95% Log Normalefficiency availabilityInhibitor Critical pit depth 8 mm 5 - 12 mm Log NormalefficiencyInhibitor Inhib. effic. > 0% 0 - 90% Uniformefficiency critical pit depth

Table 9: Summary ofVariables Modelled,the Values that wouldbe Assigned Using aStandard Approach,and the Range ofValues Used in theExample Study

Component Variable 'Standard Range Used Distributionin study Value'

Note * Cormed is a software programme which can predict in-situ pHvalues of oilfield brines.

Figure 10 shows the output from a Monte Carlo simulation, using 20,000iterations to determine the distribution in outcomes (predicted corrosionrate) due to the variation in inputs detailed above. The most likely corrosionrate is circa 1 mm/yr. While there is a possibility that higher or lower ratesoccur, the probability of such rates decreases the further they are from themost likely outcome.


42

This section re p resents a significant shift from previous BPrecommendations and therefore is covered in some detail.

The guidelines on the reliance to be placed on corrosion inhibitorspresented here have been based on experience gained with continuousinjection systems. The success of batch treatments with corrosion inhibitoris less well documented and generally this approach to corrosion control isless reliable. These guidelines should therefore not be used when designingsystems that will be protected with batch treatments - this effectively rules

out their use for the majority of downhole applications. Instead, it isrecommended that relevant operational experience with batch treatments issought before designing on the basis of batch inhibition. The authors willbe able to assist in sourcing relevant operational experience.

Previous BP guidelines have dealt with the affect of corrosion inhibitors onCO2 corrosion by assigning a “corrosion inhibitor efficiency”. Thisdescribed the extent to which an inhibitor reduced the predicted rate and afigure of 85% was originally used, later raised to 90%. This was despitelaboratory observations that showed inhibitors could reduce corrosion ratesby 95% or more. However, it was accepted that in the field, inhibitor is notdelivered at the recommended dose rate for 100% of the time and thereforea degree of conservatism is necessary when estimating the benefits ofinhibitors.

Frequency Chart

mm/yr

.000

.028

.057

.085

.113

0

565

2260

0.00 1.13 2.25 3.38 4.50

20,000 Trials 313 Outliers

Forecast: Predicted Corrosion RatesFigure 10: TypicalOutcome of the BPCorrosion Rate ModelRun Using aProbabilistic Approach

Effect of Corrosion Inhibitors

Inhibited CorrosionRates

Applicability of theGuidelines


43

One major limitation with inhibitor efficiencies is that it allows noconsideration of the effects due to increased dose rates or the developmentof better chemicals. It is well known that increasing the dose rates ofcorrosion inhibitors up to a certain level reduces the corrosion rate. Figure11 shows the relationship between dose rate of inhibitor and corrosion rateon corrosion coupons at Prudhoe Bay. Clearly, the inhibitor efficiency is nota constant value and increasing the inhibitor concentration (or changing thechemical for a more efficient one) enables lower corrosion rates to beachieved.

A second major limitation with using a single value for corrosion inhibitorefficiencies is that they are unlikely to be constant across the whole range offield conditions. CO2 corrosion models can handle input values across awide range and moderation factors have been developed over the years toreduce the conservatism due to the extrapolation of the data set used todevelop the model. However, no such moderation factors have beendeveloped for corrosion inhibitor efficiencies and by applying a blanketefficiency, it is assumed they are constant across the range of applications.

BP is ‘fortunate’ in having one of the more corrosive fields in Prudhoe Bay.This field also lends itself to effective corrosion monitoring due to the use ofabove-ground flowlines and there is a great deal of data on inhibitedcorrosion rates. There is a good relationship between observed corrosionrate and inhibitor concentration, as shown in Figure 12. In this Figure, theeffect of the increased dose rate of chemical between January 1994 andSeptember 1996 can be seen in the increased ‘efficiency’ of the chemical,based on the predicted corrosion rates using BP’s CO2 corrosion rateprediction model.

1

10

100

40 50 60 70 80 90 100 110 120 130 140

Corrosion Inhibitor Concentration - ppm

1/co

rros

ion

rat

e (y

ears

per

mm

)

Figure 11: TheImprovement inPerformance of aCorrosion Inhibitorwith IncreasingConcentration


44

In Figure 12 all efficiency values lie within the range 98.6% and 99.7%,apparently extremely good performance but in January 1994 only 40% of theflowlines at PBU had ‘acceptable’ rates of corrosion, defined as corrosionrates under 2 mpy (0.05 mm/yr.) based on corrosion probes - see Figure 13.The improvement in performance from January 1994 onwards correlateswith the increase in average dose rates shown in Figure 12.

0

20

40

60

80

100

120

140

Jan-94 May-94 Sep-94 Jan-95 May-95 Sep-95 Jan-96 May-96 Sep-96

Date

Ave

rage

Cor

rosi

on I

nh

ibit

or C

once

ntr

atio

n -

pp

m

98.20%

98.40%

98.60%

98.80%

99.00%

99.20%

99.40%

99.60%

99.80%

'Ave

rage

' C

orro

sion

In

hib

itor

Eff

icie

ncy

Corrosion inhibitor concentration

Corrosion inhibitor efficiency,defined using BP's model

Figure 12: TheRelationship BetweenCorrosion Inhibitor DoseRate and ObservedEfficiency at PrudhoeBay


45

Prudhoe Bay was constructed before the development of the earlier BPguidelines on CO2 corrosion, but if their flowlines were to be constructedtoday using the same materials and corrosion allowances, it would infer acorrosion inhibitor efficiency of approximately 98%. As PBU have nowdemonstrated that corrosion control of their system is possible it is clear thatinhibitors can be effective under highly corrosive conditions. This in turnindicates that either:

❍ Higher inhibitor efficiencies can be assumed in more aggressiveconditions, or

❍ Corrosion inhibitor efficiencies are not the correct way to describe therole of inhibitors in corrosive service.

The former premise does not lend itself to design as it would require a slidingscale of inhibitor efficiencies and the field data is not available to allow thisto be produced. The latter is the belief of several oil companies who do notuse inhibitor efficiencies, preferring to use a design corrosion rate forinhibited systems in the range 0.1 to 0.3 mm/year. For mildly corrosiveconditions (~1.0mm/year) the use of an efficiency of 90% generally workswell. However, for highly corrosive conditions (~10mm/year) it would resultin a conservative estimate of the inhibited corrosion rate. This adds weight tothe argument that the role of corrosion inhibitors can not be described byefficiencies.

Percentage of Production Lines with Corrosion Under Control

-100%

-80%

-60%

-40%

-20%

0%

20%

40%

60%

80%

100%

Jan-90 Jan-91 Jan-92 Jan-93 Jan-94 Jan-95 Jan-96

2 < CR < 5 CR >5 mpy1 < CR < 2 CR < 1 mpy< 2 mpy by Qtr

Note

Covers 3 phase productionlines >6" in diameter with WLCsincluding LDFs, LP, HP andGHX.

Figure 13: HistoricalRecord of CorrosionRates in PBU FlowlinesShowing ImprovingPerformance SinceJanuary 1994


46

BP’s data indicate that inhibited corrosion rates of 0.1 mm/year are possibleunder optimum conditions of high inhibitor dose rates and optimisedchemicals. This is confirmed with inspection data from PBU whereflowlines which have been effectively inhibited have pipewall corrosionrates of less than 0.1 mm/yr.

In general, inhibitors require free and regular access to the steel surface tobe effective. Anything that interferes with this will reduce their effectivenessto low or negligible levels. Examples of low or stagnant flow situations arevessels, instrument and drain piping and tanks. Historically, inhibitors havenot been assumed to work well in these environments and other corrosioncontrol measures are used, such as coatings and/or cathodic protection.

Inhibitors also perform poorly in low velocity pipework and pipelines,particularly if the fluids contain solids such as wax, scale or sand. Undersuch circumstances, deposits inevitably form at the 6 o’clock position,preventing transportation of the inhibitor to the metal surface. Flowvelocities below approximately 1.0 m/s should be avoided if inhibitors areto provide satisfactory protection and this will be critical in lines containingsolids.

The figure of 1.0 m/s is a rule-of-thumb which has been used in the industryfor many years. However, it is now possible to calculate the velocity moreaccurately, using an approach developed by the 'Corrosion in MultiphaseSystems Centre' at Ohio University [18]. The work agrees with the rule ofthumb for most black oil systems but allows more accurate quantification ifthe minimum velocity is restrictive.

The costs associated with corrosion inhibition are driven by the volume ofchemical used per annum and the chemical cost. There may be someincidental costs associated with the provision and maintenance of injectionequipment but increasingly this is being handled by the chemical suppliersand is therefore covered by the chemical cost.

In general, inhibitors are most attractive when protecting long lengths ofpipeline while they are rarely cost effective when protecting short runs ofprocess piping. The dose rates required are dependent on factors such asliquid throughput, CO2 partial pressure, pH and flow regime. Dose rates arenot dependent on the length of pipeline or pipework being treated and

Operating CostsAssociated WithCorrosion Inhibition

Applications WhereInhibitors Are LessThan Fully Effective

47


Beatrice 40Brae 10Bruce * 46Forties Pipeline * 26Magnus 20Miller * 35Nelson Enterprise * 17Scott Amerada Hess * 9AVERAGE 25

Table 10: Dose Ratesof Corrosion Inhibitorsinto Several North SeaExport Pipelines,Based on Total FluidVolumes

Field Dose Rate (ppm)

Note * - These fields deploy concentrated corrosion inhibitors to improvelogistics offshore. The quoted dose rates correspond to the standardproduct, manufactured by the same supplier.

At Prudhoe Bay the field-wide average corrosion inhibitor injection rate is110 ppm, with maximum rates of 250 ppm in certain flowlines, based onwater production (typical water cuts are 50%). These rates reflect the rapidcorrosion experienced in some PBU flowlines in recent years.

The determination of dosage rates in gas systems is not as straightforward asfor liquid filled lines. The three methods which are commonly used to dothis are:

1. Based on Gas Flow. This is the most commonly used method and acommon rule of thumb is to apply 1 pint of inhibitor to every 1 millionstandard cubic feet of gas (1 pint/MMscf). Actual values are found to varyenormously in the range of 2 and 0.05 pints/MMscf of gas.

2. Based on the Water Content in the Pipe Line. This is the methodfavoured by corrosion engineers as it usually indicates a very lowrequirement for inhibitor. It is common to assume a dosage of 200 ppm

therefore the same operating cost is incurred in protecting 10 metres ofpipework as is required to protect 20 km of flowline. Corrosion resistantmaterials are likely to offer lower life cycle costs for pipework while carbonsteel plus inhibition tends to be the cheapest method of constructing andoperating flowlines [19].


48

of chemical in the water. This method will often give erroneously lowvalues, especially when the water content is very low and/or the pipelineis very long. This is because the volume predicted will be too low to allowa film to be build up over the entire surface of the pipe.

3. Based on the Formation of a Protective Film. This is probably theleast used method but one whch provides a good check on the valuesobtained from the first two methods. Typically it is the volume requiredto form a 0.05mil (1 micron) film over the entire internal surface of thepipe. This volume is then applied continuously on a daily basis. If theproduct is to be applied as a batch treatment the volume is increased bya factor of ten (x10).

In practice it is sensible to do all three calculations and to use the greatestvolume as the starting point. This should hopefully be the most conservativevolume required. Again, highly corrosive duties associated with hightemperatures or CO2 partial pressures will tend to require dose ratestowards the upper end of this scale.

Chemical costs vary from supplier to supplier and may be tied in with theprovision of other services such as corrosion monitoring. However, for thepurposes of life cycle costing a chemical cost of US$8 per US gallon isreasonable. On this basis, corrosion inhibitor costs 0.84 cents to 8.4 centsper barrel at inhibitor dose rates of 25 to 250 ppm. There will also be costsassociated with monitoring and inspection. These aspects are beyond thescope of this document but are covered in detail in ‘SELECTING MATERIALSFOR WEALTH CREATION: A Material Selection Philosophy Based On LifeCycle Costs [17].

Due to the limitations of corrosion inhibitor efficiencies as a design tool, theinhibitor availability model has been adopted. This approach can be usedto define a corrosion allowance as follows:

C At o t a l = CAi n h i b i t e d (x years @ 0.1 mm/yr.) + CAu n i n h i b i t e d (y years @ uninhibited rate)

This approach assumes that the inhibited corrosion rate is unrelated to theuninhibited corrosivity of the system and all systems can be inhibited to 0.1mm/year. The approach also acknowledges that corrosion inhibitor is notavailable 100% of the time and therefore corrosion will proceed at theuninhibited rate for some periods.

Predicting the Effectiveness of Corrosion Inhibitors - ‘The InhibitorAvailability Model’


49

In the context of this model, corrosion inhibitor availability infers thepresence of a suitable corrosion inhibitor at sufficient concentration to reducethe corrosion rate to 0.1 mm/yr. The factors that lead to inhibitor availabilitybelow 100% are:

❍ Inhibitor injection equipment is not available on Day 1 of operations.❍ Injection equipment requires maintenance and repairs.❍ Operators set the dose rate incorrectly.❍ Chemical is not available when required.❍ Chemical dose rate is less than optimum. This can be due to a variety of

reasons including lack of response to increases in throughput, or watercut or sand rate.

❍ Well stimulation fluids such as hydrochloric acid are produced alongwith the crude oil and reduce corrosion inhibitor effectiveness.

❍ The corrosion inhibitor injection facilities are used for delivery of otheroilfield chemicals such as demulsifiers or combined products such asscale and corrosion inhibitors.

❍ Inhibitors are deployed via large bore pipework (instead of via injectionquills) and are not dispersed in the flow stream for some distance,providing poor protection.

All of these factors and others not listed have lead to less than optimaldelivery of corrosion inhibitor into production equipment in BPX. No assetis immune to such problems and therefore the maximum inhibitor availabilitythat should be assumed is 95%. In many instances, a lower availability shouldbe assumed; see, 'Recommended Values For Use in the Inhibitor AvailabilityModel, pp 51.'

Words of Caution

Production data from Cusiana shows that their 12 inhibitor injection skidsaveraged 99.2 % availability over the second half of 1996, an identical figureto that generated at a new gas treatment plant in the Middle East. This isprobably close to the maximum that inhibitor injection units can be available,bearing in mind the requirements for chemical feedstock, power and thereliability of the pumps. However, this should not be used as a basis forassuming an inhibitor availability of greater than 95%. Figure 14 shows thedelivery of corrosion inhibitor against the target rate for a North Sea platform.There was only one instance when the inhibitor injection system was notdelivering chemical - during March 1993 - but there were also only 3 shortperiods where the chemical was fully available with respect to the target doserate.


50

At the project stage, it is difficult to determine the availability of inhibitorin future years but relatively easy to ensure inhibitor is available on dayone. The provision of chemical injection equipment is often outside thescope of EPIC contracts and therefore assets are brought on-stream withoutthe necessary facilities to inhibit valuable equipment. In previous projects,this has taken up to 2 years to correct and therefore the best inhibitoravailability that can be achieved will be 90%, assuming a 20 year designlife. If the provision of chemical injection equipment is brought inside thescope of the EPIC contract, measures can be taken to ensure inhibitor isavailable on day 1 of operations.

Achieving good inhibitor availability during operations is partly down tosystem design and partly due to management of the changing corrosionrisk. Inhibitor injection systems are simple systems and lend themselves tohigh levels of mechanical availability. This can be improved furtherthrough the use of low level warning devices on the storage tanks and doserate gauges such as the sight glass or more complicated dose ratemonitoring systems. Together, these two simple measures will help toensure that the target dose rate is achieved for a high proportion of thetime.

Ensuring the target dose rate is correct is more difficult and requires thatconstant changes to the target are made to reflect changes in productionrate, water cut etc In extreme cases, this may require weekly tailoring ofthe target dose rate. This is where corrosion control programmes can failand therefore it is important that the materials or corrosion engineerconcentrates on this aspect.

100

80

60

40

20

0

January1993

March1993

May1993

July1993

September1993

November1993

January1994

March1994

May1994

Target = 50ppm

Figure 14: TheAvailability ofCorrosion Inhibitorinto a Main-Oil-Lineover an 18 MonthPeriod


51

Figure 15 shows the feedback loop that is required for effective managementof corrosion using chemicals. As chemical inhibition is the only viablemethod for controlling internal corrosion, it is important that the deploymentof chemical receives attention.

Apply Controls Monitor Effectiveness

CorrOcean FSM

UT mats

Corrosionprobes

Intelligent piginspections

Chemicalinhibition

CorrosionModels

Experience from other assets

Field experience

Quantify Risk

Figure 15: TheFeedback Loop thatMust be in Place forCorrosion Control toWork Effectively

Recommended Values for Use in the Inhibitor Availability Model

The degree to which a project or asset can rely on corrosion inhibition willdepend heavily on the investment made to ensure satisfactory operation ofthe feedback loop in Figure 15. The different approaches to managing thisfeedback loop enable five categories to be defined which in turn allowrecommendations to be made on the values used for inhibitor availability.

In all cases, it is recommended that the inhibited corrosion rate is assumedto be 0.1 mm/yr. The inhibitor availability value will reflect the approachof an asset to corrosion inhibition. The following categories have beendefined to cover the entire range, based on predicted corrosion rates. Eachasset or project may have equipment corresponding to two or morecategories, as the modelled corrosion rate will vary throughout the facilities.The categories are summarised below and discussed in detail in thefollowing sections, starting with the lowest corrosion risk.


52

❍ Category 1 - Benign fluids where corrosion inhibitor usage is notanticipated. Predicted metal losses should be accommodated bycorrosion allowance alone.

❍ Category 2 - Corrosion inhibitor will probably be required but at thepredicted corrosion rates there will be sufficient time to review theneed for inhibition based on inspection data.

❍ Category 3 - Corrosion inhibition will be required for the majority offield life but the facilities will not be available from Day 1, limiting themaximum effectiveness of a corrosion control programme.

❍ Category 4 - Corrosion inhibition is relied on heavily and will berequired for the entire period of operation. Inhibitor must be availableon Day 1 to ensure maximum probability of success for the corrosioncontrol programme.

❍ Category 5 - Carbon steel and corrosion allowance with corrosioninhibition is unlikely to provide integrity for the full field life, therebyrequiring repairs or replacements. Should only be considered onceenvironmental and economic analyses have shown this to be more costeffective than using corrosion resistant materials - an option of lastresort.

Categories 2 and 4 are illustrated schematically in Figure 16. Categories 1,3 and 5 can be considered in a similar manner.


53

Category 4 - red example:

Uninhibited corrosion continues at high rate for 2 years, when inhibition isstarted. However, the inhibitor is incapable reducing the corrosion to asufficient degree and de-rating or replacement will be required at Year 10. Inthis case, 18 years of inhibition (equivalent to 90% availability) is notsufficient due to the high rates of uninhibited corrosion in Years 1 and 2. Theavailability of inhibitor must be improved to 95% if carbon steel and corrosioninhibition is to work satisfactorily and therefore the system should bedesignated as a Category 4 and designed and operated accordingly.

Category 2 - blue example:

Uninhibited corrosion proceeds at a moderate rate for 10 years, wheninhibition is started. The inhibited rate is low enough to enable full field lifeto be reached with corrosion allowance to spare. In this case 10 years ofinhibition, equivalent to 50% availability is satisfactory. This would place thisexample in Category 2 as there is ample time to detect corrosion prior to theimplementation of a corrosion control programme.

0 20Field Life (years)

SAFE

UNSAFE

‘Spare CA’

Cross section ofpipe or vessel on

Day 1

Derating, repair orreplacement required in

Year 10

Figure 16: TheConcept of InhibitorAvailability in Relationto Consumption ofCorrosion Allowances


54

In these examples, once inhibition is initiated in Year 2 or 10, it is shown asbeing effective at controlling corrosion at 0.1 mm/yr. for the remainingperiod i.e. 100% availability for the remaining period. In practice, this willnot be the case and inhibitor availability will be less than 100% due to thereasons described pp 49. This would see the lines representing the loss ofcorrosion allowance becoming step shaped, corresponding to the periods ofinhibitor availability and non-availability.

Figure 17 provides a pictorial representation of these relationships.

Table 11 shows some examples of how the corrosion risk category isdetermined.

Figure 17: A PictorialRepresentation of theRelationship betweenCorrosion Rates, DesignLife, InhibitorAvailability andCorrosion Allowance.

KnownsUninhibited corrosion rate - from model

Inhibited corrosion rate = 0.1 mm/yr.

Design life e.g. 20 years

Variables

Inhibitor Availability

Corrosion Allowance

Outcome

Corrosion Risk Category 1 to 5

Options:

Increase CA, decrease availabilityDecrease CA, increase availability

In general, decreasing CA:Reduces CAPEX

Increases monitoringIncreases OPEX

Risk category determinesrequirements for:• Corrosion control• Monitoring• Inspection

Fluid VelocityC-factor < 100, no change

C-factor 100-135, + 1 category

Velocity limitations relateto inhibited fluids

•••


55

Knowns: Variables:

Uninhibited corrosion rate = 2.0 mm/yr. Inhibitor availability = 0 to 95%Inhibited corrosion rate = 0.1 mm/yr Corrosion allowance = 0 to 8.0 mmDesign life = 20 years

Design as Category 1 System

Inhibitor availability = zeroCorrosion allowance required: (20 x 2.0) + (0 x 0.1) = 40 mmNot a practical option: corrosion allowance > 8.0 mm


Inhibitor availability = 49%Corrosion allowance required: (10 x 2.0) + (10 x 0.1) = 21 mmNot a practical option: corrosion allowance > 8.0 mm


Inhibitor availability = 90%Corrosion allowance required: (2 x 2.0) + (18 x 0.1) = 5.8 mmPractical option: moderate corrosion allowance and corrosion control,monitoring and inspection requirements


Inhibitor availability = 95%Corrosion allowance required: (1 x 2.0) + (19 x 0.1) = 3.9 mmPractical option: minimal corrosion allowance with requirements for elaboratecorrosion control, monitoring and inspection requirements

In this example, the choice is between designing as a Category 3 or 4 system.Both are practical solutions and the optimum balance for a project will bedetermined by the relative cost of the extra 1.9 mm corrosion allowancerequired for a Category 3 system compared with the additional costs of thecontrol, monitoring and inspection incurred with a Category 4 system.

In general, long pipelines will be more cost effective when designed to ahigher category while shorter pipelines or process piping will be more costeffective as a lower category system.

Table 11: SomeExamples of how theCorrosion Risk Categoryis Determined.

Worked example for determining optimum corrosion risk category

The workbook provided on the disc with these guidelines contains aspreadsheet for determining the corrosion risk category of a given system.


56

Category 1 - Basis of Design

Assumed inhibitor availability = 0%Maximum tolerable uninhibited corrosion rate = 0.4 mm/yr.

This approach will be valid for applications where the predicted cumulativecorrosion rate over field life can be accommodated by a corrosionallowance. In practice, this means a maximum predicted corrosion rate of0.4 mm/yr., assuming a design life of 20 years and a maximum corrosionallowance of 8 mm. Longer or shorter design lives will change this rateaccordingly. Corrosion inhibition provides a fallback measure in case theactual corrosion rate are higher than predicted due to changes in fieldconditions or unforeseen circumstances.

Category 1 - Corrosion Monitoring and Inspection Requirements

The fluids must by definition be benign and corrosion rates low. Corrosionmonitoring equipment such as corrosion probes and coupons will respondslowly to changes in corrosion rates and will be of little practical benefit.

Detection of unexpectedly high corrosion rates remains important as the in-situ corrosion rates may be higher than predicted. However, rates areunlikely to exceed the predicted rate by more than a factor of 2 (i.e. 0.8mm/yr. maximum) and therefore the inspection programme will be capableof detecting such attack. This can provide an early warning system,allowing time for implementation of a corrosion control programme ifrequired. The usual requirements of an inspection programme apply. Inparticular, it should anticipate localised corrosion at areas such as welds andthe 6 o’clock position of low flow rate lines.

Category 1 - Corrosion Control System Requirements

As the design of the facilities does not rely on the use of corrosioninhibition, there is no requirement to incorporate corrosion injectionfacilities into the design.


Assumed inhibitor availability = 50%Maximum tolerable uninhibited corrosion rate = 0.7 mm/yr.

Designing andOperating aCategory 1Corrosion ControlSystem

Designing andOperating a Category2 Corrosion ControlSystem


57

Category 2 equates to mildly corrosive fluids where the predicted corrosionrate is too high to be accommodated by corrosion allowance alone butwhere corrosion inhibition should not be required for the full field life.

In practice, this approach is only valid for predicted corrosion rates of up to0.7 mm/yr., again assuming an 8 mm corrosion allowance and 20 design life.Using a corrosion inhibitor efficiency of 50% infers that approximately 9years of uninhibited corrosion can be accommodated before 95% relianceon inhibition must be assumed for the remaining 11 years of a 20 year fieldlife. This provides time for corrosion to be detected via inspectionprogrammes.


A design of this type relies heavily on monitoring systems to detect the onsetof corrosion at a rate requiring inhibition. This will require monitoring ofprocess changes such as temperature, flow velocity and water cut. Directcorrosion rate monitoring will also be required. However, due to therelatively low corrosivity of fluids, response from corrosion probes andcoupons may be poor.

Due to the relatively low corrosivities of the fluids, inspection programmeswill also play a vital role in detecting the onset of corrosion. Uninhibitedcorrosion losses of half the corrosion allowance over a 3 to 5 year periodwill be detectable by inspection techniques and will still enable corrosioninhibition to reduce rates to acceptable levels over the remaining field life.Selecting corrosion allowances using the BP model will ensure several yearsof corrosion can be accommodated prior to inhibition being required.


The corrosion control system must be capable of being commissioned andto begin injection as soon as changes in the corrosion rate are detected.This means that the plant should be designed for inhibitor injection withoutrecourse to a shutdown. In practice, this will mean that access fittingsshould be installed to allow fitment of corrosion inhibitor injection quills atsystem pressure. Provision of equipment upstream of the quill such as thepipework, dosing pumps and storage tanks can be delayed until monitoringor inspection data show that corrosion inhibition is required.


58

Category 3 - Basis of DesignAssumed inhibitor availability = 90%Maximum tolerable uninhibited corrosion rate = 3 mm/yr.

This category equates to projects or assets that require corrosion inhibitionfor almost the full life of the field but do not include the specification andprovision of corrosion control and monitoring facilities into the overallproject scope for use on Day 1 of operations. In practice, this may meanthat corrosion control equipment is not on site and commissioned for 12months or more and therefore the reliance that can be placed on inhibitionis less than 95%. A delay of 12 months means that corrosion inhibitoravailability must average 95% over the remaining 19 years to achieve anoverall availability of 90%. This limits the maximum predicted corrosion ratethat can be successfully accommodated to 3.1 mm/yr., assuming a corrosionallowance of 8 mm and a 20 year design life.


A facility in this category will have a predicted corrosion rate of 0.7 to 3.1mm/yr. Failure of the corrosion control programme can lead to failure inunder 3 years if the corrosion allowance is selected in accordance with theguidelines. Reliance on the corrosion control programme is therefore high,particularly as it will not be present on Day 1 of operations. The corrosionmonitoring system must be capable of detecting changes in corrosion rateswithin weeks if the target rate of inhibitor injection is to be constantlyrevised to ensure the overall availability of 90% is achieved. Therecommended techniques that are capable of providing such resolution areultrasonic mats and the CorrOcean FSM.


It is recognised that the corrosion control system will not be available onDay 1 of operations. However, it must be capable of being commissionedwithout recourse to a shutdown. In practice, this will mean that accessfittings should be installed to allow fitment of corrosion inhibitor injectionquills at system pressure. The corrosion inhibitor should have been pre-selected and the initial dose rate should be based on either laboratory trialsor similar operating experience elsewhere.

Provision of equipment upstream of the quill such as the pipework, dosingpumps and storage tanks should also be planned during the design phaseto unsure there is adequate deck space and power supplies to enable the



59

system to be commissioned quickly once it arrives. The system shouldincorporate dose rate meters and low level warning devices on the storagetank.


Assumed inhibitor availability = 95%Maximum tolerable uninhibited corrosion rate = 6 mm/yr.

This category applies to equipment that require corrosion inhibition to bepresent for the full design life of the field to ensure satisfactory integrity fromcarbon steel equipment. The reliance on corrosion inhibition is high and afailure could occur in a little over 1 year if the corrosion control programmefails. To achieve inhibitor availability of 95%, the corrosion control systemmust be operational on Day 1. To ensure this happens, it is recommendedthat the provision of the control system is brought within the scope of theoverall project.


A facility in this category will be handling highly corrosive fluids and thecorrosion control programme will require constant optimisation to ensure thecorrosion allowance is not consumed prematurely. This may require doserates of chemicals to be checked on a weekly basis and the sensitivity ofcorrosion monitoring devices must reflect this. The recommended techniquesthat are capable of providing such resolution are ultrasonic mats and theCorrOcean FSM.


The corrosion control system must be commissioned and working on Day 1of production. The corrosion inhibitor should have been pre-selected andthe initial dose rate should be based on either laboratory trials or similaroperating experience elsewhere. The system should incorporate dose ratemeters and low level warning devices on the storage tank.


Assumed inhibitor availability > 95%Uninhibited corrosion rate > 6.0 mm/yr.

This category of corrosion risk is beyond BP’s recommended practice.Predicted corrosion rates beyond 6 mm/yr should not generally be handled




60

through a combination of carbon steel with corrosion allowance andcorrosion inhibition. Instead, corrosion resistant materials should beconsidered.

There will always be specific cases where corrosion resistant materials arenot feasible or where previous operating experience indicates that carbonsteel will corrode at a lower rate than indicated by the model. However, therisks involved in operating such a system are high and repairs orreplacement of equipment should be expected during the field life. This isunlikely to be cost effective when lost production costs and potentialenvironmental damage are considered and these areas must be addressed ifsuch highly corrosive fluids are to be handled or transported using carbonsteel.


Assuming the technical, environmental and financial factors of operating acarbon steel facility of this type have been considered and answeredsatisfactorily, the monitoring requirements will be similar to those for aCategory 4 system.


Assuming the technical, environmental and financial factors of operating acarbon steel facility of this type have been considered and answeredsatisfactorily, the control system requirements will be similar to those for aCategory 4 system.

Table 12 summarises the recommendations made in respect of eachcategory. Table 12 also classifies when an intelligent pig inspection shouldbe carried out for the various corrosion risk categories. These classificationsare described on page 52. These can be scheduled by a variety of means,depending on the amount of information available for the system. If thereis extensive process and corrosion monitoring data together with extensiveoperational experience of the system, it may be possible to scheduleinspections based on gathered data i.e. using ER probe data as a trigger.However, until experience and confidence are gathered corrosion modellingoffers the best method. The reliance on monitoring and inspection is greaterfor Categories 5, 4 and 3 than for Categories 2 and 1 and thereforeinspection should occur earlier in the field’s life.


61

Table 12: Summaryof Criteria andRequirements forCorrosion RiskCategories 0 to 4

Category 1 Zero 0.4 mm/yr. 0 ppm None required No requirement Routine inspection Process monitoring Process monitoring Process monitoringStandard inspection Standard inspection Standard inspection

techniques techniques techniques

Category 2 50% 0.7 mm/yr. 20 ppm Should be No special Routine inspection As Category 1 plus As Category 1 plus As Category 1 pluscapable of requirement weight loss coupon weight loss coupon weight loss coupon

commissioning ER probes ER probes ER probesw/o plant shut- Intelligent pig run Intelligent pig run Intelligen pig run

Category 3 90% 3 mm/yr. 50 ppm Should be Should Early inspection As Category 2 plus As Category 2 plus As Category 2 plusincluded in basis incorporate low regular inspection of FSM or UT mat FSM or UT mat

of design and level device and bends, welds etc system systemcommissioned as flow monitor in Continual data Continual data Continual datasoon as practical injection package logging for probes logging for all logging for all

monitoring devices monitoring devices

Category 4 95% 6 mm/yr. 100 ppm Should be within Should include Early inspection As Category 3 plus As Category 3 plus As Category 3 plusscope of overall low level device increased inspection increased inspection increased inspection

project and and flow monitor frequency frequency frequencyavailable from in injection

Day 1 package

Category 5 > 95% >6 mm/yr. 300 ppm Should be within Should include Early inspection As Category 4 As Category 4 As Category 4scope of overall low level device plus leak plus leak

project and and flow monitor detection detectionavailable from in injection

Day 1 package

Corrosion control system Monitoring requirements,

requirements based on location

Corrosion Inhibitor Corrosion Assumed System System Scheduling 1st On land, On land, SubseaRisk availability rate (max) dose rate availability sophistication inspection above Ground buried


62

- The aim of the inhibitor availability model is to encompass the good trackrecord of the inhibitor efficiency model at low to moderate corrosivities butto remove some of its conservatism in more corrosive systems. The twoinputs to the model are the inhibited corrosion rate and the inhibitoravailability and using different values for these can produce a whole arrayof outputs.

Figure 18 shows the corrosion allowance that would be recommendedusing the two approaches for a 20 year design life. A range of uninhibitedcorrosion rates are considered, from 0.5 to 10 mm/yr. which covers therange from mildly to highly corrosive fluids (less corrosive fluids wouldprobably be handled without recourse to inhibition). In the inhibitorefficiency example, an efficiency of 90% has been assumed, in line withBP’s previous practice. The inhibitor availability model uses an inhibitedcorrosion rate of 0.1 mm/yr. and an inhibitor availability of 95%. Duringthe remaining 5% of the time, the uninhibited corrosion rate is used (0.5 to10.0 mm/yr. as appropriate).

Both models agree well for moderately corrosive fluids, while for mildlycorrosive fluids (0.5 to 1.0 mm/yr.) the availability approach recommends agreater corrosion allowance. In practice, this may not be important asexternal corrosion may require a corrosion allowance of up to 2 mm andwould over-ride the allowance recommended for internal corrosion.

Comparisons of theInhibitor AvailabilityModel with BP’sPrevious Model

0.5 1 2 3 5 10

1.0 2.4 2.0 2.94.0 3.9

6.0 4.910.0 6.9

20.011.9

0

2

4

6

8

10

12

14

16

18

20

Reco

mm

en

ded

Co

rro

sio

n A

llo

wa

nce

for 2

0 y

ea

r d

esi

gn

lif

e -

mm

0.5 1 2 3 5 10

Predicted Corrosion Rate - mm/yr.

Corrosion allowance - efficiency methodCorrosion allowance - availability method

Inhibitor availability model based on inhibited rate of 0.1 mm/yr

and availability of 95%

Efficiency method based on efficiency of 90%

Figure 18: AComparison Betweenthe Inhibitor Efficiencyand InhibitorAvailability Methods ofDeterminingCorrosion Allowances


63

For highly corrosive fluids, the availability model recommends lowercorrosion allowances than the efficiency model. This agrees well with theobserved ‘high efficiencies’ of corrosion inhibitor under highly corrosiveconditions. This will increase the use of carbon steel as the standardpractice is to specify carbon steel with corrosion allowances up to 8mm andto use corrosion resistant steels for more corrosive fluids.

Figure 19 shows the relationship between predicted corrosion rate and therecommended corrosion allowance using the inhibitor availability method.The example shown is the same as in Figure 18 with predicted corrosionrates in the range 0.5 to 10 mm/yr. In each case, the corrosion allowancefor inhibited corrosion is constant at 1.9 mm due to the assumption of aninhibited corrosion rate of 0.1 mm/yr. and the required field life of 20 years.The variation in recommended corrosion allowances is due entirely to the5% of the time where inhibition is assumed to not occur.

Figure 19 helps to illustrate how important the period of uninhibitedcorrosion can be. In a severe case of a predicted corrosion rate of 10mm/yr., the uninhibited period of 5% of the time accounts for 83% of thecorrosion allowance. In this case, each 1% increase in the assumedavailability of corrosion would reduce the total corrosion allowance by16.6%. Table 13 gives some more details on this point.

1.9 1.9 1.9 1.9 1.9 1.9

0.5 12

35

10

0

2

4

6

8

10

12

0.5 1 2 3 5 10

Predicted Corrosion Rate - mm/yr

Rec

om

men

ded

Co

rro

sio

n

All

owan

ce f

or 2

0 Y

ear

des

ign

li

fe -

mm

Corrosion allowance for uninhibited corrosion

Corrosion allowance for inhibited corrosion (95%availability)

Figure 19: TheContribution to theTotal RecommendedCorrosion Allowancefrom the Inhibited andUninhibited Portions ofthe Inhibitor AvailabilityModel


64

0.5 2.4 2.3 3.3 %1 2.9 2.7 6.2 %2 3.9 3.5 9.7 %3 4.9 4.3 11.8 %5 6.9 5.9 14.2 %10 11.9 9.9 16.6 %

Table 13: The Effectof the AssumedCorrosion InhibitorAvailability on theRecommendedCorrosion Allowancefor a 20 year DesignLife

Predicted CA assuming CA assuming % reduction inCorrosion 95% inhibitor 96% inhibitor corrosion allowance

Rate availability availability per 1% increase inmm/yr.. mm mm inhibitor availability

It can be seen that highly corrosive systems must assume a high valuefor the inhibitor availability if carbon steel is to be used with a practicalcorrosion allowance.

The corrosion rate prediction model presented here is for use with carbonsteels, i.e. predominantly iron with low levels of carbon. However, someengineering materials contain a wider range of alloying elements such aschromium and nickel to improve the mechanical properties, such as strengthor toughness. Such elements are commonly found in corrosion resistantmaterials and chromium in particular can increase the corrosion resistanceof carbon steels, if present in sufficient concentration. 13% of chromiumturns a carbon steel into a stainless steel, with excellent resistance to CO2corrosion.

Many claims have been made over the past 5 years of the affect of addinglow levels of chromium (0.5 to 1.0%) to carbon steel. Some steel suppliersclaim that 0.5%Cr can halve the CO2 corrosion rate and certainly in sometests there does appear to be a benefit. The most consistent benefit seemsto be an improved resistance to ‘mesa’ corrosion where large, square edgedand flat bottomed pits can form. However, in other tests no benefits havebeen observed and it seems that the benefits may be related tom i c ro s t r u c t u re rather than composition. Other re s e a rchers and oilcompanies have reported that inhibitors perform worse on low alloy steelsthan on carbon steel and therefore, in inhibited systems, there is no benefitfrom the addition of low levels of chromium.

Corrosion Rates of Low Alloy Steels


65

On balance, BP believe there are no proven advantages or disadvantages interms of CO2 corrosion resistance from the presence of chromium atconcentrations up to 1% in steels. It is therefore recommended that noaccount is taken of the presence of alloying elements at low levels and nopremium should be paid for such steels. However, if the steel supplier useslow levels of chromium in the standard product, that is acceptable.

Preferential weld corrosion is a problem in most systems and productionsystems containing CO2 are no exception. Efforts have been made toeliminate preferential weld corrosion by alloying welding consumables withvarious elements such as chromium, nickel and copper at low levels (circa1%). No universal solution has been found and there are examples of eitherweld metal or heat affected zone (HAZ) suffering preferential attack withmost welding consumables and welding procedures. The problem is notmade easier by the fact that the mechanism for preferential weld corrosionis not fully understood in CO2 service. The speed of such corrosionsuggests there could be a galvanic driving force.

Even in ‘benign’ systems where predicted rates of general corrosion are low,rates of attack at welds can be unacceptably high. This causes a problemwhen deciding whether a corrosion inhibitor is required for a particularapplication. The traditional approach has been to calculate cumulative walllosses over the life of the field using corrosion models and if the predictedwall loss is less than the available corrosion allowance, inhibitors have notbeen specified. However, preferential weld corrosion can proceed at ratesfar higher than predicted and inhibitors offer the only proven method ofimproving the reliability of carbon steel in such cases. There have recentlybeen cases of preferential weld corrosion causing rapid failures in systemsbelieved to be only mildly corrosive.

Unfortunately, there can be no clear guidance for such systems butinspection programmes should recognise the risk of preferential weld attackand, if detected, corrosion inhibition should be initiated immediately.

Preferential Weld Corrosion


66

CO2 models are basically ‘bare surface’ models with moderation factorsapplied to anything that affects this, such as surface scales and corrosioninhibitors. Moderation factors are used to reduce the predicted corrosion ratedue to the presence of protective or semi-protective species at the surface.In other words, all such factors predict that the surface will corrode at a lowerrate than would be expected if it was fully exposed to the bulk solution.

Pits are one case where local corrosion rates may be higher than if the surfacewas exposed to the bulk solution. The environment at a corroding steelsurface is different from that in the bulk due to the continual transport ofreactants to the surface and products from the surface and this is reflected inthe CO2 models and associated factors. These effects are generally beneficialwhere the corrosion process is transport controlled but can be detrimentalwhere it is the transport of inhibitor that is limited. This can be the case in acorrosion pit where galvanic affects also play an important role. The resultis that the growth rate of deep pits may accelerate. This can be seen as aloss of control by the inhibitor and may place a practical limit on the size ofthe corrosion allowance. For example, if an inhibitor is incapable ofprotecting pits deeper than 8mm, once pitting has reached this depth thecorrosion rate in the pit will proceed at the uninhibited rate, i.e. 10 or 20times faster than the bare surface rate. The increase in life due to theprovision of corrosion allowance beyond 8 mm would therefore be minor.

In practice, the relationship between pit depth and inhibitor efficiency is notfully understood. Field experience indicates that pits below 5 mm behavenormally while pits deeper than this may corrode at a higher rate. Pittingrates up to 3 times faster than predicted have been quoted in a variety ofsystems. Certainly, if corrosion has reached 8 mm it is likely that the localenvironment within a pit will be significantly divorced from the bulkenvironment and hence transportation of inhibitor may be unreliable.Moreover, if corrosion has caused such metal loss, the corrosion control ofthe system must be poor and providing extra steel is unlikely to provide asatisfactory answer.

As corrosion allowance is often consumed via pitting or localised corrosionthe importance of pits should be considered when selecting the optimumcorrosion allowance.

Effect of Pitting


67

The term corrosion allowance creates the impression of a uniform wastageover time leading to the gradual and controlled reduction in wall thickness.In practice, this is unlikely to be the case and the role of the corrosionallowance is to provide protection against the periods when corrosioncontrol is poor and short term corrosion rates are high, i.e. poor inhibitoravailability in the case of inhibited systems. As there is always uncertaintyin the rate of corrosion (and therefore time to failure), specifying a corrosionallowance is a compromise between capital costs and reliability. Greatercorrosion allowances incur greater costs but confer greater reliability. Formildly corrosive systems, low corrosion allowances of 1.5 to 3 mm arejustified as they are protecting against the possibility of internal and externalcorrosion. In highly corrosive systems, active corrosion is almost certain tooccur and therefore greater corrosion allowances should be specified toincrease the mean time to failure.

Some Operators specify maximum corrosion allowances and BP has tendedto use the figure of 8 mm for some years. The reasons for this are:

1. Corrosion tends to be localised pitting attack and corrosion inhibitorsperform poorly in deep pits. Therefore, extra corrosion allowanceprovides little benefit beyond approximately 8mm.

2. Carbon steel will not provide a long term solution for highly corrosivesystems and if several millimetres of corrosion allowance have beenlost, corrosion control of the system has not been achieved.

3. Intelligent pigs are sensitive to corrosion damage of circa 10% of wallthickness. This makes it difficult to detect the onset of corrosion inthick walled pipe which in turn means that corrosion may continue forsome time before detection. It is preferable to detect corrosion earlyand remedy the situation and therefore thin walled pipe is preferablefor detection of corrosion.

4. Welding and handling thick walled pipe is difficult and thick sectionsmay require post weld heat treatment. Cost increases are thereforegreater than the incremental increase in wall thickness.

The figure of 8mm should not be seen as fixed. Each project may havedifferent drivers in terms of the optimum balance between opex and capexcosts and in certain cases, replacement of flowlines may be more

Choosing an Optimum Corrosion Allowance


68

economically attractive than high capital costs in Year 1. For one recent BPXproject it was decided that localised corrosion was the main concern for theflowlines and therefore the definition of corrosion allowance should reflectthis. BP’s first pass defect assessment criterion for pipelines allows 20% ofthe pressure containing wall to be lost due to localised corrosion and thedesign of the corrosion allowance took this into account. This approachreduced the corrosion allowance by circa 1.5 mm and saved US$1.16 millionfrom the cost of the flowline network. In effect, the ‘traditional’ corrosionallowance was reduced from 8 mm to 6.5 mm but as the corrosion wasexpected to be localised, there would be 8mm of pipewall available forlocalised corrosion before raising any concern over integrity.

In other cases, a corrosion allowance greater than 8mm may be justifiedbut it should be recognised that the additional costs may not be reflectedin the incremental increase in reliability.

Use of Common Sense

In specifying a corrosion allowance, the Materials Engineer should not betoo pedantic. Projects often define three or more nominal corrosionallowances such as 1.5 mm, 3 mm and 8 mm. Process streams arecategorised as mildly corrosive, corrosive or highly corrosive using modelsor experience and the appropriate corrosion allowance added to thepressure containing wall thickness defined using the appropriate code. Thetotal required wall thickness is then reviewed against the available wallthicknesses with the next greater thickness being selected. It may be thecase that the corrosion allowance just takes the total wall thickness out ofone wall thickness range and into another, increasing significantly the wallthickness and the effective corrosion allowance.

Example

The linepipe specification API 5L lists wall thicknesses (WT) in 1.6 mmincrements for 16” linepipe in the range 12.7mm to 14.3mm. If the totalrequired WT including 6 mm corrosion allowance is 12.8mm, standardpractice would be to select the 14.3 mm size. The ‘excess’ 1.5 mm wouldadd circaUS$11,500/km to the cost of the 16” flowline i.e. in excess of US$1million for a 100km line. As the selection of the nominal corrosion


69

allowance is based on imprecise models, the Materials and PipelineEngineers should use their judgement in the selection of the final wallthickness. They may decide that a corrosion allowance of 5.9 mm isacceptable, allowing the 12.7 mm WT linepipe to be specified.

CO2 predictive models - such as the one in this report - are based onlaboratory studies, typically developed in water only systems. Variousmoderation factors have been applied over the years, reducing the predictedrates as experience showed them to be too conservative in their basic forms.In the approach covered here, the water cut is ignored thereby treating thepipeline or process equipment as if it was transporting 100% water. It mayappear a large step to apply a model developed using laboratory data inwater only systems to the field where hydrocarbons account for the majorityof the throughput.

However, this is not the vast over-simplification it may seem. Water wettingof the pipewall can occur at both high and low water cuts. This is despitethe widely shown plot, reproduced in Figure 21 in which a relationship isproposed between water cut and corrosion rate based on water wetting.This relationship is not reliable in practise because water cuts below 1%have been known to cause rapid failures. This simply reflects the fact that

Applying Models to Different Flow Regimes

Effect of Water Cut

Water only...

Gas / Water

Oil / Water

Multiphase

0.1 - 13 m/s20 - 90oC0.3 - 20 bara CO2

(0.1 m/s, 90oC, >6.5 bara CO2excluded!!)

Figure 20: TheApplication of a ModelDeveloped in Water-Only Systems to OtherWater-ContainingSystems


70

the average corrosion rate in a system is rarely of interest: it is the maximumrate that determines time to failure. If at a water cut of 1%, 1% of theequipment is water wet 100% of the time then clearly there will be no effectof water cut on the maximum potential corrosion rate and hence time tofailure.

Hilly terrain, changes in elevation or changes in flow direction can inducewater hold-up in wells, flowlines and process equipment. Local water cutscan exceed 50% despite input water cuts of 1% or less. The water in dipsmay remain for weeks or months until an increase in throughput sweepssome of it out and a temporary increase in water production is seen at theoutlet of the system. It is therefore unwise to rely on the formation ofemulsions or similar dispersions to provide fully oil wet surfaces. It is forthis reason that BP ignores the water cut in determining system corrosivity.

CO2 corrosion rates are dependent on flow regime and flow velocity, hencethe attempt to incorporate the effects of flow into the 1995 de Waard andMilliams model. In uninhibited corrosion, flow effects are of secondaryimportance, after the important controlling factors such as temperature,pressure, CO2 concentration and pH and for this reason BP have retainedthe earlier de Waard and Milliams model as the basis for their CO2modelling. The 1995 model is included if the sensitivity to flow velocitychanges are considered important.

0

1

0 100

Water Cut, %

Co

rro

sio

n R

ate

I

II

III

Figure 21: An OftenPresented RelationshipBetween Water Cutand Corrosion Rate

Effect of FlowRegime


71

Each flow regime will cause different rates of corrosion under otherwiseidentical conditions and the 1995 de Waard and Milliams model offers thebest method of assessing this.

When considering inhibited corrosion rates under multiphase flow, theapproach proposed on pp76 should be followed. In summary, velocitiescorresponding to C factors below 100 require no special consideration.Velocities corresponding to C factors between 100 and 135 raise theCategory of the corrosion risk, e.g. from 3 to 4. Velocities corresponding toC factors greater than 135 should not be considered unless there issignificant operating experience to justify this.

Liquid Flowrate

Bubble

Stratified Stratified Wavy

Slug Annular

Gas Flowrate

Figure 22: DifferentFlow RegimesExperienced at VariousCombinations of GasFlowrate and LiquidFlowrate


72

Crude oil transport pipelines or main oil lines (MOL) fall into two categories:

1. The fully stabilised type such as the Trans Alaskan Pipeline Systemand OCENSA in Colombia.

2. The partially stabilised type, such as Forties and Beatrice MOLs.

The corrosivity of the fluids is different in each case and pipelines shouldbe designed and operated accordingly.

In the case of fully stabilised lines, the crude oil is processed down toatmospheric pressure and may remain in tanks for some period prior toshipping. This allows water cuts to reach levels of 0.1 to 1.0%. It alsoallows the acid gases present in the reservoir to vent and reach very lowconcentrations. For example, the effective partial pressure of CO2 in anassociated gas containing 2 mole% CO2 is only 0.3 psia at atmosphericpressure. The low levels of acid gases mean the potential corrosivity of thewater phase will be low.

Fully stabilised crude oil can therefore be considered as a non-corrosiveproduct and typically such pipelines are constructed with minimal or zerocorrosion allowance. When a corrosion allowance is specified, it is oftendue to concerns over external corrosion rather than internal attack.Corrosion inhibitor is not normally deployed into fully stabilised crude oillines.

In the partially stabilised case, the crude oil is partially stabilised (typicallyoffshore) and exported for final processing at a remote location (typicallyonshore). The crude oil in the export pipeline therefore remains corrosiveas the acid gases are not vented down to negligible levels and anyassociated water will be corrosive. The partial pressure of gases will dependon the pressure of final processing. For example, at 7 bara the partialpressure of CO2 in an associated gas containing 2 mole% would be 0.14bara, or 2 psia.

Applying Models to Transportation Equipment

Crude Oil Export Pipelines

Fully StabilisedCrude Oil ExportPipelines

Partially StabilisedCrude Oil ExportPipelines


73

Final processing pressures vary. Forties fluids are processed down to 4.5 barawhile the value on Bruce is 12 bara and Brae is 16 bara. The ‘typical’ rangeis from 1.4 bara to 20 bara and the corrosivity of the fluids will varyaccordingly, along with the CO2 concentrations, temperatures etc.

As the crude oil does not pass through tankage offshore, water cuts inpartially stabilised lines are typically higher than in fully stabilised lines.Water cuts can reach 15% or even higher if water handling is a constraint butmore typical levels are around 1%.

With the removal of the majority of the CO2 and water, partially stabilisedcrude oil is significantly less corrosive than the non-stabilised multiphasefluids transported in flowlines, but it can not be considered as non-corrosive.The original Forties 30” and existing Beatrice export lines are adequate proofthat partially stabilised crude oil is corrosive. Such pipelines should thereforebe designed and operated to deal with internal corrosion. Typically acorrosion allowance of 2 to 3 mm may be specified and corrosion inhibitorshould be added on a continuous basis.

It is important to note that although the pressure of the oil is raiseddownstream of the crude oil shipping pumps, the partial pressure of CO2does not increase. The crude oil is single phase and any remainingassociated gas is in solution - see page 11.

Ideally, the velocity should be maintained above 1 m/s - see page 46.

To minimise or eliminate the risk of corrosion in gas pipelines it has been(and still is) common practice to dry it prior to transportation. The two mostcommon methods involve either contacting the wet gas with dry glycol orpassing it through molecular sieves.

The target water content of the 'dried' gas is usually 2lbs of water for everymillion standard cubic feed of gas (2lbs/MMscf).

However, both methods have their problems as shown by Figure 23 whichshows the water content of a dry gas downstream of the glycol contactors.

Natural Gas Pipelines

Dry Gas Pipelines

0.00

0.05

0.10

0.15

0.20

0.25

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Water Content - lbs/mmscf

Pro

bab

ilit

y

Specification2 lbs/mmscf


74

The data was gathered from a BP Asset over a two year period and it is clearthat the target value of 2lbs/MMscf was rarely achieved.

Thus some care should be taken when relying on the drying of gas forcorrosion control and each system should be considered on a case by casebasis.

As part of the drive to minimum offshore processing, gas transportation linesare increasingly being designed to operate wet i.e. the gas either enters thepipeline below its water dew-point or will drop below this temperature atsome location along the pipeline. Once free water is present, corrosionbecomes a concern and this must be taken into account during the designand operational phases of the pipeline’s life. The severity of corrosion andthe potential means for controlling it depend on the operating scenario andflow regimes.

If a wet gas pipeline is not going to be treated with a recycled hydrateinhibitor, corrosion inhibition is the only practical corrosion control method.The approach to design is identical to that for oil pipelines except that thereis no pH buffering capacity in the condensed water in wet gas lines. Thismust be taken into account when performing the corrosion rate predictions.

If the flow regime is stratified or wavy, there may be a concern thatcorrosion inhibitor deployed into the continuous phase at the bottom of thepipe does not get transported to the top of line location. The corrosionprocesses occurring at the two locations are different as the transportation

Corrosion InhibitorDeployment in WetGas Pipelines

Figure 23: The ActualWater Content of a 'DryGas' Downstream of theGlycol Contactors Overa 2 Year Period. TheDesign Specificationwas 2lbs/MMscf.

Wet Gas Pipelines


75

of water to, and subsequent removal of corrosion products from the top ofline location is limited by the quantities of condensing water. There is nocontinuous water phase at this location in stratified/wavy flow and water isonly present via condensation on to the pipewall. Under thesec i rcumstances, the water quickly becomes saturated with corro s i o nproducts, effectively stifling further corrosion and this can be used toadvantage in the design of wet gas pipelines.

The term top of line/bottom of line (TOL/BOL) ratio is used to describe therate at which the top of line corrodes relative to the bottom of line, with thebottom of line rate being calculated using a standard CO2 modellingapproach. A TOL/BOL ratio of 0.1 is used by BP. This does not rely oninhibitor availability and can therefore be assumed to occur 100% of thetime. The bottom of line location requires inhibition and the predicted rateestimated using the availability model. The higher of the two rates willdetermine the required corrosion allowance.

Glycol (or methanol) is often used as the hydrate preventer on a recycledbasis, although this traditional approach to hydrate control is increasinglybeing replaced by once through, low dose systems. However, recycledsystems will remain valid for older systems or those operating well withinthe hydrate envelope where low dose chemicals are not applicable. The useof glycol is beneficial as it is a corrosion inhibitor, albeit a relatively poorone. If glycol is used without the addition of corrosion inhibitor, there willbe some benefit from the glycol. This is hard to quantify but Shell’s workproduced a glycol correction factor which is described on page 25.

However, if glycol and inhibitor are both used there will be little additionalbenefit from the glycol and it should be ignored for design purposes. Onlythe inhibitor availability factor should be used.

The use of a glycol (or methanol) recycling system offers the opportunityfor an alternative form of corrosion control - pH moderation. This techniquehas been used by Elf since the 1970’s and works by artificially raising thepH of the water in the pipeline to high values (circa 6.0). This limits orarrests CO2 corrosion and therefore the pipeline can be constructed withreduced corrosion allowance. The system is economical to operate as thepH moderator, typically bicarbonate or MDEA is carried in the glycol andremains through the glycol drying process. However, the technique shouldonly be used along with corrosion inhibition as pH moderation is notentirely successful at preventing localised corrosion. In effect, pHmoderation expands the application of carbon steel to more aggressiveenvironments i.e. hotter and/or higher CO2 partial pressures.

Corrosion Inhibitorand GlycolDeployment in WetGas Pipelines


76

However, the technique has some drawbacks:

1. pH moderation relies on the existence of glycol recycling to providethe transport medium and to recycle the pH moderator. With themodern trend towards once-through, low dose hydrate inhibitorsmany new wet gas pipelines will not have glycol recycling facilities.Once-through dosing of pH moderator is unlikely to be economic as2,500 ppm bicarbonate or 500 ppm MDEA may be required in thewater phase to achieve the required pH shift. MDEA costs circa US$4per kg and therefore treating condensed water would cost circa 30cents per barrel on a once through basis.

2. If formation water is produced along with the gas then the artificiallyhigh pH will increase the scaling tendency of the water. This can haveserious consequences and may require the termination of the pHmoderation programme.

Multiphase flowlines are the most arduous application for corrosioninhibitors. This mode of transporting fluids is set to increase further in BPwith the development of long reach tie-backs to existing platforms and largedevelopments on land such as Colombia and Algeria. Flowlines are anarduous application for corrosion inhibitors for two main reasons:

1. The fluids are unstabilised and therefore contain acid gases such asCO2 at high partial pressures, along with water. In contrast, exportpipelines transport more benign fluids that have had the bulk of suchcorrodents removed.

2. The flow regimes in multiphase flowlines vary widely and thevelocities and attendant liquid forces can reach high levels. Thisincreases uninhibited corrosion rates and increases the concentrationof inhibitor required to achieve acceptably low corrosion rates.

Very low velocities are also a concern and the ‘optimum’ mean velocity forsuch flowlines is believed to lie between 1 and 10 m/s. Below this velocityrange, water drops out and deposits can accumulate at the 6 o’clockposition, preventing inhibitor reaching the pipewall - see page 46.

Multiphase Flowlines


77

Corrosion inhibitors are not effective under such circumstances, particularlyif there are solids or bacteria in the line and therefore corrosion rates areincreased.

Corrosion rates can be controlled above 10 m/s, but at higher operatingcosts. Figure 24 gives a graphical representation of the affects of flowvelocity on inhibited CO2 corrosion rates.

Figure 24 is only a qualitative representation and velocity is not the onlycriterion controlling the flow element of CO2 corrosion. Mixture density isalso important, with denser fluids giving rise to higher corrosion rates.Higher velocities can therefore be tolerated in systems with high GORs thanin similar systems with low GORs. It is often convenient to design using C-factors, defined in API RP 14E because the erosional velocity is often thelimiting velocity for flowlines. Although C-factors specifically relate toerosion and not corrosion they usefully represent the forces acting on thepipewall and therefore the forces causing enhanced corrosion rates. Forcarbon steel, BP use a C factor = 135.

..where maximum flow velocity is in ft/s and mixture density is in lb/ft3.

0

1

0 5 10 15 20

Flow Velocity - m/s

Co

rro

sio

n R

isk

High risk of water dropand under-deposit

corrosion

Effect ofincreasing [CI]

Figure 24: AGraphicalRepresentation of theEffect of Flow Velocityon Inhibited CO2corrosion.

MaximumFlow Velocity = C

Mixture density


78

The relationship between flow and corrosion rate will be unique for eachsystem and will be difficult to estimate at the design stage. However, thedesigner should accept that high velocities increase the risk of highcorrosion rates and should design accordingly. The level and sophisticationof corrosion control and monitoring systems must reflect the potential forcorrosion to occur and this in turn will depend heavily of the flow regime.This should be handled using the approach developed for InhibitorAvailability, based on categories 1 to 5. The impact of flow velocitiescorresponding the C factors > 100 can be considered as an increase in riskand the category defined on the bais of predicted corrosion rates changedaccordingly - see Table 14.

Note that operating at C factors > 135 should only be considered wherethere is sufficient operational experience in the asset to confidently state thaterosion or corrosion are not occurring at unacceptable rates at C=135. Cfactors > 135 should not be used during design but may be considered as ade-bottlenecking measure if successful experience has been gained.'Successful experience' is likely to require several years of operation with atleast one intelligent pig inspection of the flowline after operating at close toC = 135.

Design No change + 1 Category NoOperation Yes + 1 Category Possibly1

C Factor<100 100 to 135 >135

Table 14: The Impactof High Fluid Velocitieson the Categorisation ofCorrosion Risk


79

Within BP, there are no fixed policies on the frequency of intelligence pigsurveys (IPS) of pipelines and each individual case should be examined onmerit. It is important to note that intelligence pigging surveys are just oneelement of a toolbox for the management of pipeline integrity. They arecomplementary to the full range of other pipeline integrity and monitoringtechniques, for example, wall thickness checks, corrosion coupons andcorrosion inhibitor injection monitoring. It is recommended that pipelinesat risk of corrosion are designed to be “piggable”, with the requirement forpermanent pig traps being determined according to the required frequencyfor operational pigging and intelligence pigging.

For any pipeline, the need for, and frequency of inspection depends on anumber of factors:

❍ the known or anticipated corrosion risk (which this document dealswith);

❍ the sensitivity of the inspection tools available to detect theanticipated defect types;

❍ the corrosion allowance and whether the pipeline can be accessedfor repairs;

❍ the environmental risk;❍ local pipeline regulations;❍ the strategic importance of the pipeline and the associated political

environment;

There are three main types of pipeline inspections which may becategorised as follows:

❍ A Baseline Survey;❍ an Early Inspection; and❍ a Routine Survey.

A Baseline Survey is carried out prior to pipeline commissioning, with theprincipal objective of detecting material defects and construction anomalies.Baseline surveys are primarily intended to detect dents, or wrinkles, and sogeometry pigs are normally used (e.g. caliper device), these pigs are notnormally considered to be intelligence pigs.

Baseline Survey

Intelligence Pigging Guideline


80

BP would not generally recommend a baseline intelligence pig survey forpipelines. It is normally considered that the pipeline hydrotest is a sufficientdemonstration of the pipelines’ initial fitness for service. A true baselineintelligence pig survey may be required for pipelines transporting highlysour fluids, where there is some doubt over the steel’s ability to resist HIC.In these circumstances it may be justified to inspect for initial laminations inthe pipeline steel. Such laminations may grow or blister during operation,and so a baseline measurement of such features can prove useful inassessing the integrity of the pipeline in later life. BP has not found itnecessary to carry out a baseline IPS in any of its pipelines. However, thereis increasing pressure on the assets from regulators to carry out suchinspections. A normally satisfactory compromise is the Early Inspection.

An Early Inspection would be carried out 1 - 3 years after commissioning.The objective of this survey is to verify the absence of corrosion in apipeline where a new corrosion prevention strategy is being implemented,or when the operating conditions are particularly severe. In the context ofthis document, pipelines in corrosion categories 4 and 5 would certainlywarrant an early inspection. The case for a category 3 pipeline having anearly inspection should also be considered.

An early inspection is similar to a baseline inspection, but it is carried outafter some operating life has been accumulated. The objective of an earlyinspection is to confirm that the corrosion management philosophy isoperating satisfactorily before any significant damage occurs to the pipeline.For example, an early inspection of the Miller Gas System (sour with highCO2) was carried out after approximately 1 year of operation and thisconfirmed satisfactory corrosion management performance. The data froman early survey can be used later in the pipeline’s life to provide informationon when the damage was initiated.

A routine inspection is carried out to confirm the on-going integrity of apipeline which has a known corrosion risk. Clearly, the frequency of thisinspection will vary from pipeline to pipeline. This survey is used tomonitor known defects or confirm the absence of significant corrosion.Pipelines in corrosion categories 1 to 5 should all be considered for routinesurveys.

Early Inspection

Routine Survey


81

Where it is feasible, it is recommended that a caliper inspection is carriedout on each new pipeline during the commissioning procedure. This willconfirm the good workmanship of the pipeline and remove concern aboutdents in the pipeline. Dents can pass hydrotest, but fail by fatigue laterduring the life of the line.

Baseline intelligence pig surveys are not generally recommended.

To determine when to first inspect a new pipeline, it is necessary to considerthe corrosion risk and the uncertainty in prediction of the corrosion rate.Three simple principles can be used to determine when to carry out the firstpig inspection:

❍ It should not be before a time when one would expect to detectsome corrosion if the corrosion rate is in line with the pessimisticestimate;

❍ It should be before our pessimistic estimate of when the first failuremay occur;

❍ It should be before we expect widespread corrosion to occur, whichwould result in major repair programme.

To quantify this timing, the pipeline operator can apply a number ofmethods of increasing sophistication, reliability calculations are suited to thistype of assessment. However, as a first pass the following simple methodis recommended:

Make an estimate of the most likely and the pessimistic corrosion rates.These should be based on the corrosion model described here, taking in toaccount the influence of corrosion inhibitors (if applicable) and the likelyeffectiveness of the inhibitors. The probabilistic approach to corrosionmonitoring can be helpful here, taking the P50 and P90 (or P10) corrosionrates as the most likely and pessimistic rates.

The first inspection should not be before….Calculate the time taken for the pessimistic corrosion rate to reach 1mm indepth or the detection threshold of the inspection tool being used (typically10% of nominal wall thickness). Use the greater time period as the earliestrecommended inspection time.

When To Inspecta Pipeline

New Pipelines


82

The first inspection should not be after….Calculate the retiral thickness of the pipeline according to the ruling pipelinedesign code - the “code thickness”.

Calculate the tolerance of the pipeline to “long” corrosion defects. Forpipelines operating at 72% SMYS, the BP Guidelines for the assessment ofcorroded pipe allow a further 20% loss of the Code thickness (BP's"Transmission Pipelines to BS8010", 1st June 1992). The “BP 1st Pass”thickness is normally calculated as 0.8 * code thickness.

Calculate:

❍ the time that the pessimistic corrosion rate will reach the BP 1st PassThickness,

❍ half the time that the best guess corrosion rate will reach the BP 1stPass Thickness.

The earliest of these dates is the latest intelligence pig inspection date.

The procedure is shown pictorially in Figures 25 and 26.

Nominal

Code

BP 1st Pass“long”

Rupture

Wall ThicknessesCorrosion Levels

DesignAllowance

ActualAllowance

FailurePoint

time0

SAFE

SAFE

UNSAFE

FAILURE

Detection Level

bestestimate

pessimisticestimate

earliest inspection

date

latest inspection

date (1)

widespreadcorrosion expected(divide time by two)

Figure 25: A PictorialRepresentation of howto Determine theTiming of a PigInspection Run.


83

The actual inspection date chosen should fall between these limits. Thefinal selection of date will depend the factors outlined above i.e.

❍ the known or anticipated corrosion risk;❍ the sensitivity of the inspection tools available to detect the

anticipated defect types;❍ the corrosion allowance and whether the pipeline can be accessed

for repairs;❍ the environmental risk;❍ local pipeline regulations;❍ the strategic importance of the pipeline and the associated political

environment;

Calculate the most likely and worst case corrosion rates (P50 and P90 rates if using the probabilistic corrosion model)

Determine when the most likely rate leads

to wall losses > 10%

This is the earliest date for inspection

This is the latest date for inspection

Determine when the most likely rate leads

to wall losses of 1 mm

Take the greater of the times calculated in Steps 1 and 2

Determine the retiral wall thickness using BP’s 1st pass

method for long defects

Calculate when the worst case rate means the retiral

limit will be reached

Calculate when the most likely rate means half the

retiral limit will be reached

4

3

2

1

Take the lesser of the timescalculated in Steps 5 and 6

5

6

7

Figure 26: A FirstPass Method forDetermining theTiming of the FirstIntelligence PigInspection.


84

A similar method is used to determine the minimum inspection interval forpipelines without a severe corrosion problem. The relatively low accuracyof even the high resolution intelligence pigs compared with other NDTtechniques, means that pigs are not well suited to the measurement ofcorrosion rate. Statistical techniques have been applied to pig inspectionresults. However these will result in a high degree of uncertainty inmeasured corrosion rate unless there is a reasonable period of time betweeninspections.

For example, the time to the next intelligence pig inspection survey couldbe determined as follows. If the defects identified in the early survey areindeed corrosion defects, then one should carry out the next inspectionwhen the predicted growth exceeds the tool’s ability to confidently measuredifferences in wall thickness. If an inspection tool has an accuracy of 10%of pipewall thickness then the inspection should be carried out when theestimated total loss in wall thickness due to corrosion has exceeded:

√2 x 10%

i.e. 14.1%, which is equivalent to 1.8 mm on a 12.7 mm thick line.

The reason for this is that the error in the measurement of corrosion (adifferences in wall thickness) is approximately √2 times the error in eachwall thickness measurement.

For pipelines with significant corrosion, the timing of the next inspectiondepends on when it is anticipated that the corrosion depth will reach a"retiral" limit. For onshore pipelines, the owner has the opportunity to carryout local inspections and repairs at relatively low cost. In this instance, aninspection programme can be put in place to monitor a number of theseverest defects in order to judge when repair / replacement / derating isnecessary. This point monitoring may be used to reduce the requiredfrequency of IPS. For offshore pipelines with significant corrosion, whereinspection and repair is costly, there will be a tendency to carry out IPSmore frequently than outlined above. It should be understood thatinspections carried out more frequently than the minimum recommendedfrequency may not be able to generate reliable corrosion rate data. In theseinstances only with careful consideration, should forecasts of pipelineintegrity be made from pit depth changes from inspection to inspection. Inorder to avoid over-pessimism in forecasts it is important to consider othersources of information on possible corrosion rates (e.g. corrosion modelpredictions / experiments; topsides inspection results).

Repeat InspectionIntervals


85

For oil transmission pipelines, where fluid corrosivity is being monitored ona routine basis, the pipeline is in a reasonable condition and thought to beat low risk, a frequency of once every 5 years would be typical. Examplesof this are the new Forties MOL and the existing Ninian MOL, which are bothsubsea lines in the North Sea. When a good corrosion management trackrecord has been established, assets are tending to increase this interval. Forsignificantly corroded pipelines, where the pipeline is nearing the end of itslife, inspections may be carried out as often as annually.

For dry gas pipeline systems that are tightly controlled, inspections would becarried out after indications of potential problems from other sources:topsides corrosion, failure to meet dew point spec, water carry over into thepipeline etc. For example, BP has operated a dry gas pipeline (Gyda field inNorway) since 1986, without yet requiring an intelligence pig inspection,because of the low risk of internal corrosion in this pipeline.

For more information on this topic contact Will McDonald ( Sunbury x4014 )or Jim Corbally ( Sunbury x2774 ) of the SPR Transportation Team.

Typical InspectionIntervals


86

As stabilisation trains take fluids from the flowlines, they will naturallybenefit from the injection of any corrosion inhibitors upstream to protect theflowlines. However, there are locations within the stabilisation units whereinhibitors will not work well and alternative means of corrosion controlshould be employed. Inhibitors rarely work well under low velocity orstagnant conditions, such as at the base of separators, tanks or in instrumentbridles. Deposits can form in such locations preventing inhibitors getting tothe metal surface. This becomes relevant at velocities below 1 m/s andeither internal coatings and anodes (vessels, tanks) or stainless steel piping(instrument bridles) should be used. Carbon steel is suitable for drain lines,downstream of an isolation valve.

Gas compression systems fall into two categories; wet gas compression anddry gas compression. Some systems are wholly wet gas, such as Pedernales,Venezuela and the Long Term Test facility at Cusiana, Colombia. Themajority of systems are wet up to an intermediate stage of compression atwhich point the gas is dried, normally in glycol contactors at approximately500 psi. Once the gas is dried, corrosion is not a major concern and aminimal corrosion allowance is normally specified to account for periodswhen gas dryers operate off-specification or for external corrosion.

In wet systems, corrosion will occur whenever the gas falls below its waterdew-point. This can be predicted using flowsheet simulation packages suchas Genesis but there are some general guidelines which make the task morestraight forward.

The gas entering a compressor will have come from either a vessel or knockout pot. The gas will there f o re be in equilibrium with water and hydro c a r b o nliquids and there should be zero or negligible liquids present. The action ofc o m p ressing the gas will heat it, raising it above the dew-point and there b yremoving any traces of liquid water. The pipework downstream ofc o m p ressors is there f o re not at risk from internal corrosion and a moderatec o r rosion allowance (1 - 2mm) will suffice to account for external corro s i o n .The exception is small bore instrument tappings where the gas may cool tobelow its dew-point, causing corrosion. Greater corrosion allowances orstainless steels should be used in these locations.

Applying Models to Process Equipment

Crude OilStabilisation Trains

PipeworkDownstream ofCompressors

Gas CompressionSystems


87

Wet Gas Coolers

Table 15: OperatingConditions andCorrespondingCorrosion Rates forDischarge Coolers

Temperature - in 243oF 240oF 222oF 226oF

Temperature - out 110oF 110oF 110oF 110oF

Pressure 220 psig 567 psig 1334 psig 3310 psig

CO2 content 0.2 mole% 0.2 mole% 0.2 mole% 0.2 mole%

PCO2 0.44 psia 1.13 psia 2.68 psia 6.63 psia

pH range 4.65 - 4.95 4.47 to 4.75 4.32 to 4.55 4.21 to 4.38

Water dew point 147oF 144oF 136oF 132oF

Water content 737 lb./MMscf 299 lb./MMscf 124 lb./MMscf 64 lb./MMscf

Tube size 1" x 16g 5/8" x 16g 3/4" x 16g 5/8" x 16g

Wall thickness 1.5 mm 1.5 mm 1.5 mm 2.75 mm

Pred. Corr. Rate 0.5 mm/yr. 0.9 mm/yr. 1.16 mm/yr. 1.6 mm/yr.

Inhib. Corr. Rate 0.05 mm/yr. 0.09 mm/yr. 0.1 mm/yr. 0.2 mm/yr.

1st Stage 2nd Stage 3rd Stage 4th Stage

Discharge Discharge Discharge Discharge

Cooler Cooler C ooler Cooler

Gas is typically cooled between each stage of compression. Downstream ofcompressors, liquid water will not re-appear until the gas is cooled to belowits dew-point. This will occur some way into the cooler. If the cooler has carbon steel tubes it is worth calculating the temperature at which this willoccur as the site of water condensation can be the location of worst casecorrosion and will therefore determine the life of the coolers. As thefollowing example, in Table 15 from one BPX asset shows, the dew-pointtemperature can be closer to the gas exit temperature than the entrytemperature. If the entry temperature had been used for the corrosion ratepredictions, they would have been unnecessarily conservative.


88

Carbon steel is rarely a good choice for the tubes of coolers in wet gasservice for the following reasons:

1. The equipment is critical as it handles flammable gas at highpressure within the facilities.

2. The thermal requirements of the cooler exclude the use of significantcorrosion allowances and therefore coolers typically have thin walledtubes.

3. The high gas velocities and highly turbulent flow regimes meancorrosion inhibitors are unlikely to work well.

4. Inhibitor may need injecting downstream of each compressor as it maybe ‘lost’ with the liquids at each knock out pot, making inhibitorsuneconomic.

5. On-line inspection of the tubes of airfin coolers is difficult.

More suitable materials for the tubes include 316L, duplex or super duplexstainless steels. If necessary, carbon steel can be used for the tube sheetsto reduce costs with a suitable corrosion allowance incorporated.

Glycol contactors are an example of equipment that, on the face of it, maysuffer excessive internal corrosion due to the combination of gas below itsdew-point, high pressures and carbon steel construction. However,operating experience has shown this to not be the case as the large volumesof glycol effectively absorb the water and inhibit corrosion. Carbon steel istherefore a satisfactory material of construction although many projects goto the expense of internal coatings, such as epoxy phenolics, particularly forthe lower sections.

Although corrosion inhibitors are supplied to control corrosion in glycolcontactors, their benefit is not quantified or proven. However, the control ofthe pH of the water/glycol moisture is important and chemicals(neutralisers) are available for this. During operation the pH of the fluid isreduced by the build up of organic acids. These result from the degradationand hydrolysis of the glycol during the heated, regeneration stage.

Glycol Contactors


89

The 1995 de Waard & Milliams corrosion rate prediction model relies heavilyon the use of flow velocities to predict corrosion rates. If this model is used,guidance is required on typical velocities. The design guidelines used for theProject, or actual throughput rates and internal pipe sizes are the best sourcesof such information. If this information is not available then the followinginformation can be used as it details typical limiting velocities used during thedesign of process pipework.

This information is taken from two recent design guidelines used by ProcessEngineers for sizing of process pipework. They deal with maximumvelocities and can therefore be used as worst case. Pipe sizes are based onseveral criteria, including the requirements to avoid vibration, deposition ofsolids, excessive pressure drop and erosion.

‘Single phase liquid lines’ refers to pipework where system pressure is forcingliquid from higher pressure vessels to lower pressure vessels, drains ortankage. It does not refer to the suction or discharge of pumps.

Maximum velocity = 5.0 m/s, with excursions up to 9 m/s.

Flow should not exceed 5.0 m/s and should not be less than 1 m/s. Thelower limit is to avoid deposition of solids. More detailed guidelines aresummarised below. They are only to be applied to clean fluids - allowablevelocities shall be reduced if solids are present.

Process liquid general 5 9Hydrocarbon headers 5 9Hydrocarbon branches 5 9Water & water solutions 3.5 9Liquid to reboiler 1.25 -Side stream drawoff 1.25 3Gravity flow 1 2.5Refrigerant lines 0.6 1.25

Nominal line size Maximum Velocity (m/s)

Flow Velocities in Process Pipework

Flow Velocities inSingle Phase LiquidLines

Table 16: MaximumVelocities in SinglePhase Liquid Lines


90

The flow velocity in pumped liquid lines is strongly dependent on pumptype and line size. Centrifugal pumps and large line sizes can handle higherliquid velocities than reciprocating pumps and small line sizes. If the pumptype is unknown, it is safer to assume a centrifugal pump for the purposesof corrosion rate calculations.

If the line size is not known, the following velocity range can be used. Ifthe line size is known, Tables 17 and 18 give more information.

Centrifugal PumpsSuction 1 to 2.4 m/sDischarge 1.8 to 5.5 m/s, excursions up to 9 m/s.

Reciprocating PumpsSuction 0.3 to 0.6 m/sDischarge 1 to 1.8 m/s

Flow Velocities inPumped Liquid Lines

Service Max. Velocity m/s Max. Velocity m/sNormal Limit

Suction Dischargeup to 3" 1 1.8

4" 1.4 2.46" 1.5 38" 1.8 4.310" 2.1 4.912" 2.4 5.5

Suction Dischargeup to 250 0.6 1.8251-330 0.5 1.4over 330 0.3 1

Speed RPM Maximum Velocity (m/s)

Table 17: MaximumVelocities in Lines toand from CentrifugalPumps

Table 18: MaximumVelocities in Lines toand from ReciprocatingPumps


91

In multiphase lines, use the limiting velocity defined by API RP 14E. BP usea C factor of 135 for carbon steel - see p77. Velocities should not exceed 75%of the 'critical flow velocity'. Critical flow in multiphase systems is analogousto sonic flow in single phase systems.

A general limit of 18 m/s is applied to gas piping to avoid pipe vibrations.Compressor surge/recycle lines, relief valve inlets etc may operate atsubstantially higher velocities - see Table 19. However, pipework to and fromreciprocating compressors typically has a lower velocity limit of 12 m/s.

In general, vapour piping is sized in terms of pressure drop, rather thanmaximum velocities.

Service Velocity m/s

< 15 psia (vacuum) 61 to 1520 - 100 psig 46 to 61

100 to 500 psig 30 to 46500 to 2000 psig 30 to 38

Flare 0.5 to 0.8 Mach

Table 19: Vapour LineSizing Criteria

Flow Velocities inMultiphase Lines

Flow Velocities inVapour or Gas Lines


92

Corrosion modelling will give a good indication of the probability of failureof equipment in service due to internal conditions but will not help indetermining the economic consequences of such a failure or the operatingcosts involved with avoiding or managing such a failure. Even if corrosionmodels predict short times to failure, it may be economic to plan forreplacement or repair of carbon steel equipment late in field life rather thanto invest in a more robust solution on Day 1. Alternatively, inhibitors maybe a technically feasible solution for process pipework but economically andlogistically, protecting large numbers of short lengths of pipework may beimpractical and corrosion resistant materials may be a better choice.

The technique of life cycle costing (LCC, also known as whole life costing)helps in this assessment by converting future costs into current monetaryvalue and thereby allowing direct comparisons with capital costs. To carryout accurate, meaningful and useful LCC’s the Materials or Project Engineermust have:

1. An understanding of the economic factors driving the decision, suchas discount rates, rates of return on investment and net present values.

2. The design life and production profile of the development.3. An assessment of future costs based on similar developments over

several years.4. An understanding of the important economic drivers for the Project,

such as the balance between capital and operating costs. This in turnwill be determined by the economic terms under which the licencewas awarded.

Gathering the necessary data for accurate LCCs is a major task and aguideline document is available [17].

In some cases, the cost of materials are relatively minor and the costs ofinstallation far outweigh them. Expensive sub-sea wells are an obviousexample of where workovers are to be avoided due to a materials failure.In such cases it is common to select robust materials in order to protectagainst a repeat of the high installation costs but there are many exampleswhere the answer is less clear cut. The key question is, “when is investmentin corrosion resistant materials justified?”

Economic Tools To Use During Materials Selection


93

Location/Equipment Materials Cost MaterialType as % Selection

of Whole

Corrosion models clearly have an input to this but can not provide thecomplete answer. Corrosion models are normally used as a materialsselection tool and taking an extreme example, if there were no consequencesof a failure there would be no justification in investing in corrosion resistantmaterials. An investment in corrosion resistant alloys (CRAs) aims to protectagainst the consequences of a failure and therefore materials selection mustconsider the consequences in the decision making process. Consequencesmay include economic, health, safety or environmental impacts or all four butin most cases all consequences can be related to a financial impact.

Example:

A flowline is to transport corrosive fluids from a remote well-site to theprocessing facilities. The route includes a major river which provides localcommunities with water for consumption and agriculture. The river crossingrequires directional drilling and is therefore expensive. The material selectedfor the majority of the flowline is carbon steel with a suitable corrosionallowance but it is recognised that localised failures and repairs may berequired late in field life.

What material should be used for the river crossing? The decision can not bebased solely on the corrosivity of the fluids as the consequences of a failureunder the river crossing is clearly far greater than a similar failure on land. Amethod of evaluating the consequences of such a failure is required and fromthis a method for determining how much it is worth investing on Day 1 toprevent a failure several years later.

The Expected Value technique does this and is covered in detail in ref 17.The technique quantifies what has been done subjectively for many years:materials selection becomes more conservative as the consequences of afailure increase. This is the main reason corrosion resistant materials are usedmore extensively downhole and sub-sea than on land - it is not the fluidsthat are significantly different but the economic drivers.

Subsea wells < 3% Most conservativeLand wells / sub-sea flowlines ~ 10%Flowline road / river crossings ~25%Buried land lines ~ 30%Surface running land lines > 30% Least conservative

Table 20: Categoriesof Equipment,Classified by theProportion ofMaterials Cost toTotal Installation Cost


94

The expected value technique is represented graphically in Figure 27. Itassesses the economic costs and benefits of two or more choices. Inassessing each option, the technique allows for the possibility of failure anda probability is assigned to each outcome (failure or no failure ) .Probabilities of failure will be higher for a carbon steel system than for anequivalent CRA system and corrosion modelling helps to determine this.The costs of each outcome consist of :

❍ Capital costs (no failure case)

❍ A combination of capital and operating costs

❍ The above plus repair or replacement costs

For fair comparison, the costs are converted to present day values (NPVs).The costs associated with each outcome are multiplied by their probabilityto produce the estimated value.

Figure 27: ExpectedValue Technique

Which river crossing material ?

Failure

No Failure

No Failure

Failure

NPV Cost = $1.0+$0.48+$23.75 = $25.23

NPV Cost = $1.0

NPV Cost = $0.6+$0.29+$23.75 = $24.64

NPV Cost = $0.6

1%

99%

20%

80%

Install CRAriver crossing

Install C-Steelriver crossing

EV for C-steel$5.85 million

(0.8 x 0.6) + (0.2 x 24.64)

EV for CRA$1.31 million

(0.99 x 1) + (0.01 x 25.23)

Choose lowest EVi.e. CRA river crossing

95

References

1. C de Waard, U Lotz, D E Milliams, "Predictive Model for CO2Corrosion Engineering in Wet Natural Gas Pipelines", Corrosion, 47(1991) 976

2. C de Waard, U Lotz, "Prediction of CO2 Corrosion of Carbon Steel",NACE Corrosion 93, New Orleans, paper 69

3. C de Waard, U Lotz, A Dugstad, "Influence of Liquid Flow Velocity onCO2 Corrosion : A Semi-Empirical Model", NACE Corrosion 95,Orlando, paper 128

4. C de Waard, D E Milliams, "Carbonic Acid Corrosion of Steel",Corrosion, 31 (1975) 177

5. R H Newton, "Activity Co-efficients of Gases", Industrial andEngineering Chemistry, March 1935, 302-306

6. L W Jones, "Corrosion and Water Technology", OGCI Publications,Tulsa, USA, 1988, p14-15

7. J G Stark, H G Wallace, "Chemistry Data Book", J Murray Ltd,London, 1978, p 60-61

8. I R McCracken, C G Osborne, D Harrop, "Carbon Dioxide andCorrosion in Forties", Sunbury Report No PEB/122/89, datedDecember 1989

9. J E Oddo, M B Tomson, "Simplified Calculation of CaCO3 Saturationat High Temperatures and Pressures in Brine Solutions", J ofPetroleum Technology, 34 (1982) 1583

10. L A Rogers, M B Tomson, "Saturation Index Predicts Brine's Scale-Forming Tendency", Oil and Gas Journal, April 1 1985, p 97

11. R G Chapman, "pH Models for Corrosion Rate Predictions", SunburyReport No POB/025/96, dated June 1996

12. M J J Simon Thomas, P B Herbert, "CO2 Corrosion in Gas ProductionWells: Correlation of Prediction and Field Experience", NACECorrosion 95, Orlando, paper 121

REFERENCES

96

13. J J Carroll, J D Slupsky, A E Mather, "The Solubility of CarbonDioxide in Water at Low Pressure", J Phys Chem Ref Data, 20 (1991)1201 - 1209

14. A J Ellis, R M Golding, "The Solubility of Carbon Dioxide above100°C in Water and in Sodium Chloride Solutions", Amer J of Sci.,261 (1963) 47-60

15. S Takenouchi, G C Kennedy, "The Solubility of Carbon Dioxide inNaCl Solutions at High Temperatures and Pressures", Amer J of Sci,263 (1965) 445 - 454

16. S D Malinin, "Thermodynamics of the H2O - CO2 System",Geochemistry International, 10 (1974) 1060 - 1085

17. D M E Paisley, "Selecting Materials for Wealth Creation: A MaterialsSelection Philosophy based on Life Cycle Costs", BP Sunbury ReportNo. ESR.97.ER.005, 10th Jnauary 1997

18. D Vedapuri "Studies on Oil-Water Flow in Inclined Systems" April1997 Progress Report, Section 9. Ohio University Multiphase Flowand Corrosion Project.

19. A J McMahon and S Groves, "Corrosion Inhibitor Guidelines: APractical Guide to the Selection and Deployment of CorrosionInhibitors in Oil and Gas Production Facilities", BP Sunbury ReportNo. ESR.95.ER.050, April 1995

97

Installation of the Cassandra 98 ExcelWorkbook

The Cassandra 98 work book was written in Microsoft Excel for Windows95, version 7.0a. It may not run in earlier versions of Excel.

If for any reason this does not succeed, try the ‘Manual Installation’procedure described below.

1. Insert the disc into the disc drive2. Click on the ‘Start’ button3. Click on the ‘Run…’ option4. Using the ‘Browse’ feature select A:\Install.Exe5. In the ‘Run’ window click on ‘OK’6. Follow the Instructions.

Once complete the work book should be opened using the followingsequence:

1. Start2. Programs3. Cassandra4. Cassandra 98

The first time the work book is used the message ‘ This document containsLinks’ will appear. Click ‘No’ to this.

Continue at step 5 in the ‘Manual Installation’ procedure described below.

If not already present, the automatic installation will create the followingfolders with files in them:

1. C:\Xlph2. C:\Data\Cassandra3. C:\Windows\Start Menu\Programs\Cassandra

In addition it will place the file Xlph.ini in the root directory ( c:\ )

Description

Automatic Installation

INSTALLATION OF THE CASSANDRA 98 EXCEL WORKBOOK

98

In the root directory of the disc there is a folder called ‘Files’. This foldercontains two files ( Cassandra 98.xls and Xlph.ini ) and a folder( Xlph ) in the root directory. The Xlph folder contains seven folders:

1. Phreeqe.dat2. Readme.doc3. Xlph.inf4. Xlph.out5. Xlph.xla6. xlph.xla7. Xlphdemo.xls

It is suggested that these instructions are visible during loading so thatthey can be referred to easily during the loading process. The instructionsmust be followed precisely to ensure that the installation is successful. Itis suggested that ‘Windows Explorer’ or ‘File Manager’ be used for sections1 to 3 below.

1. Copy the Xlph folder into the root directory of the C: drive. Thisshould give the following structure:

1. C:\Xlph\Phreeqe.dat2. C:\Xlph\Readme.doc3. C:\Xlph\Xlph.inf4. C:\Xlph\Xlph.out5. C:\Xlph\Xlph.xla6. C:\Xlph\xlph.xla7. C:\Xlph\Xlphdemo.xls

2. Copy the Xlph.ini file into the root directory of the C: drive to giveC:\Xlph.ini

3. Copy the Cassandra 98 file to your preferred location such as theDesktop, the root directory or another folder. For example:C:\Cassandra 98.xls

4. Start Excel5. On the Menu bar click ‘Tools’.6. On the drop down menu click ‘Add-Ins…’.7. In the ‘Add-Ins’ box click on ‘Browse…’.8. In the ‘Look in’ box select (C:).9. Select the ‘xlph’ folder and click ‘Open’.10. Select the ‘Xlph.xla’ file and click ‘OK’.11. In the ‘Add-Ins’ box click on ‘OK’.12. If not already open, ‘Open’ the Cassandra 98.xls file.

Installation

Manual Installation

a438243_1.pdf bp corrosion modelling

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