us50099_1

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 two sections.

The first section introduces a new prediction spreadsheet called Cassandra 98*which is BP's implementation of the CO2 prediction models published by deWaard et al. It builds on these models to include BP's experience of such systems.The pocket inside the front cover of this report contains a floppy disc whichcontains the necessary programs and spreadsheets to run it together with a setof installation instructions.

The second section discusses how the prediction model may be used for designpurposes and it introduces several improvements from previous guidelines.These include the use of the probabilistic approach to corrosion prediction andthe use of corrosion inhibitor availabilities instead of efficiencies. It also discussesthe use of "corrosion risk categories" as a way of quantifying the corrosion riskat the design stage. The floppy disc also contains a spreadsheet for calculatingthe risk category.

To illustrate the points made examples have been obtained from many BP assetsworldwide. 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 suggestions regardingeither the content or appearance of them would be very welcome.

*In Greek mythology Cassandra was the daughter of Priam and Hecuba. She was endowed withthe gift of prophecy but fated never to be believed. She is generally regarded as the prophet ofdisaster........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 more common.Unfortunately, the engineering solutions to eradicating the CO2 corrosion riskrequire high capital investments in corrosion resistant materials. As Figure 1shows, providing a corrosion allowance of 8 mm to carbon steel flowlinescosts a significant sum at circa US$1 million per 5 km but even this isinsignificant in terms of the costs of the various corrosion resistant flowlineoptions.

Similar relative costs are incurred when specifying corrosion resistantmaterials downhole or in facilities. This is rarely justified. For this reason, CO2corrosion of carbon steel will always be a problem that BPX has to deal with.Managing CO2 corrosion therefore becomes a priority and it can becomeexpensive. The replacement of the original Forties MOL and the severedamage to the Beatrice MOL are two examples of high costs that BPX haveincurred in recent years due to unpredicted corrosion rates. Successfulmanagement of CO2 corrosion starts off with the identification of risks andcontinues with the provision of suitable controls and the review of thesuccess of the controls via monitoring - as illustrated in Figure 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

2

INTRODUCTION

This document sets out BP’s approach to the quantification of CO2 corrosionrisk through the use of predictive models. In doing so, it also discusses thereliance that can be placed on corrosion inhibition as the only viable controlmeasure for carbon steel and the importance of suitable corrosionmonitoring. To put the importance of this into context, corrosion costs BPX8.3% of its capex budget and increases lifting costs by 14%, an average ofover 8 cents per barrel. Figure 3 shows that the costs are distributed acrossthe entire range of facilities.

Apply ControlsMonitor Effectiveness

Quantify Risk

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

3

INTRODUCTION

The quantification of corrosion risk is required at several stages during an assetslife. The most obvious period is during the project phase when the originalmaterials of construction are being selected. This process must be repeatedduring the life of the asset if failures or expansions require the procurement ofadditional facilities. Quantifying the corrosion risk is also important in tailoringinspection strategies. Risk based inspection is now widely adopted and, as CO2corrosion represents one of the most important factors governing the probabilityof failure for much equipment, a reasoned approach should be taken. It isimportant that this approach is theoretically sound but also reflects pastexperience.

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 the semi-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 flow velocitieson uninhibited corrosion rates.

Downhole13%

Subsea59%

Chemicals4%

Topsides23%

Personnel1%

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

4

INTRODUCTION

The new guidelines also consider the probabilistic approach to predicting CO2corrosion. Probabilistic approach to design in general is becoming morewidespread and offers several advantages over the traditional deterministicapproach. The probabilistic approach is neither endorsed nor disallowed but isdiscussed as, in some cases, it may be more appropriate than a deterministicapproach.

The approach to designing for the use of corrosion inhibitors has been changedsignificantly. The previous approach described the affects of an inhibitorthrough the use of an efficiency factor, such as 90%. This does not reflect BPX’srecent field data generated under severe conditions which showed inhibitorscan be more effective than predicted. "Inhibitor efficiencies" have thereforebeen replaced with "inhibitor availabilities" that more closely reflect fieldexperience. There is a general move in the industry towards this methodologyand it offers several advantages.

However, it has become clear that for inhibitors to work effectively thecorrosion management system must be highly organised. Recommendations aretherefore 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 inside thefront cover of this report contains a floppy disc with the programme togetherwith 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 the 1993De Waard model, incorporates some equations from the 1991 model, and usesthe 1995 model to assess velocity effects. The spreadsheet is intended to captureall the best features of the 1991, 1993 and 1995 models [1,2,3]. Certain extrafeatures from outside the De Waard papers, based on standard physicalchemistry, have also been included. The source, background and limitations ofall the assumptions and equations in the spreadsheet are fully documented inthese guidance notes.

The Cassandra 98 spreadsheet is written in a simple and accessible format withinMicrosoft Excel (version 7.0). It avoids the use of macros or special techniquesso that the logic and the calculations are as transparent as possible. Thisapproach also ensures that the spreadsheet is immediately compatible with newversions of Excel.

The Excel add-in module "CRYSTAL BALL" (from Decisioneering Ltd, 1380Lawrence Street, Suite 520, Denver, Colorado 80204, USA. Tel: +1 303 292 2291.Cost ~£100) enables probability distributions to be set for each input cell and itthen uses Monte-Carlo simulation to combine these into a probability distributionfor the resulting corrosion rate. You must buy "CRYSTAL BALL" separately foryour Excel environment. It can't be bundled with this spreadsheet. The detaileduse of CRYSTAL BALL is well covered in the manufacturer's handbook andtherefore is not repeated in these guidelines.

Care is required when comparing the output of any existing in-house version ofthe De Waard models against this new Cassandra 98 spreadsheet. It is very easyfor errors and untested assumptions to be entered into a spreadsheet whichmight then perhaps be passed on from user to user and often compounded withother assumptions. Cassandra 98 has been written from scratch with a detailedre-evaluation of all assumptions, all of which are presented. Cassandra 98 isintended to be a standard, reference version of the De Waard approach for usewithin BP and its partners, until such time that a more consistent approach tocorrosion modelling becomes established within the oil industry. The activities ofthe NORSOK industry forum in Norway are making helpful moves in thisdirection.

INTRODUCTION

6

This section gives enough information to allow experienced modellers to makea start. The subsequent section gives a more detailed description of all the inputand output parameters. The spreadsheets themselves also carry frequent "cellnotes". These are marked by a red dot in the top right hand corner of thosecells. Just double click on the cell to read the contents.

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

Only the inputs in the preceding Table are needed for a straightforwardnumeric calculation. Some further information is required in order to carry outa probabilistic calculation using CRYSTAL BALL. The spreadsheet can easily becustomised by individual users to permit more extensive handling ofprobabilities:

"CASSANDRA 98" CORROSION PREDICTION SPREADSHEET

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. The1995 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 spreadsheet environmentcan lead one to think that the De Waard corrosion models are equally precise.However, this is not the case. The models are only valid over a certain range ofconditions, and even within this range a certain amount of data has beenignored if it doesn't fit the main trends. Each model appears to be constructedby obtaining a large number of corrosion rates over a range of conditions andthen finding an equation which draws a line passing close to the majority of thiscloud of points. The equations appear to be freely adjusted in order to give thebest fit to the data. The primary concern is to obtain a good fit to the data, ratherthan obtaining mechanistically rigorous equations. These are empiricalengineering models rather than scientific theories.

Neither the 1991 or 1993 De Waard papers give many precise details about therange of validity of the models. The 1995 paper does give a more thorough setof figures (see below) but still omits important features such as the type of brineused in the tests, and the elapsed time when the corrosion rates were measured.De Waard's very early work used a 0.1% NaCl solution [4] and this may wellhave been used in all the subsequent studies because his main focus has alwaysbeen low salinity water in gas lines. Table 4 shows the approximate ranges ofvalidity for the different parameters in the Cassandra 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. Whenthe input value is outside the approximate range of the 1991 and 1993 De Waardmodels then the text will turn RED in the cell as a warning. The predictedcorrosion rate may still be useful but the user must accept the additional risk ofgoing 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 about thecorrosion rate profile over this time or when the final data point was taken. Datawere obtained for the following conditions.

- St-52 DIN 17100 steel (Cr 0.08%, C 0.18%) which is similar to ASTM A537Gr1

- 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 equations obtainedfor St-52 showed a complete lack of correlation for the other steels". The 15other steels were normalised steels and quench-and-tempered (Q&T) low alloysteels. These were examined over the following conditions to produce somemodified 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 and onlythe "Cr correction" is relevant. The Cassandra 98 spreadsheet does not includethe steel composition equations due to the poor correlations obtained whenfitted to the model.

Errors in matching equations to data points are defined in the 1995 paper by"coefficients of determination". This is a complicated statistical function rangingfrom 0 (poor correlation) to 1 (perfect correlation). It is not the same as the"correlation co-efficient" in regression analysis which scales from -1 to 1. The"co-efficients of determination" in the paper are 0.91 for the main St-52equations (after excluding the data that doesn't fit), 0.83 for the normalisedsteels, and 0.80 for the Q&T steels. For the main St-52 correlation thiscorresponds to a standard deviation of 25% on the predicted corrosion rate. Thisis the error given in this spreadsheet. Because of this error the predictedcorrosion rates are only shown to one decimal place. A "CRYSTAL BALL"probabilistic analysis gives a more realistic impression of the error on eachprediction.

The De Waard models were all developed using water-only systems in thelaboratory. The 1993 model is intended for nearly static, aqueous conditions andso for all but the lowest velocities (see page 77) it can be regarded as theminimum corrosion rate of a water wet region in a gas/water, water/oil, or awater/oil/gas system. Due to the different hydrodynamics in these field casessome assumptions are required in order to apply the 1995 model effectively.These assumptions will only affect the diameter and velocity values used asinputs in the model. The other inputs will be unaffected. Table 5 gives somesuggested assumptions. However, users are free to develop their ownapproaches to meet the demands of their own particular circumstances. Someof the issues involved in extrapolating the models to the field are discussed inmore 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 units areassumed in all the equations given below and throughout the Cassandra 98spreadsheet. The spreadsheet has a "units conversion box" at cell P5. The UNITSspreadsheet allows conversions between a wider range of units. The SALTSspreadsheet enables conversion between an ionic analysis of brine and the saltsrequired to prepare a synthetic analogue. The FUGACITY spreadsheet is a data-base used to calculate fugacity corrections at high total pressures.

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. For aliquid only system it is the P in the last gas phase which was in equilibrium withthe liquid, e.g. the separator gas in the case of a crude oil export line. For adownhole liquid pressurised above the bubble point then use the bubble pointpressure (Figure 4).

For a simple numeric calculation, enter the P value into cell F7. Cell G7 is thenunused. For a probabilistic calculation using "CRYSTAL BALL", set up a uniformdistribution for P with F7 set as the maximum and G7 as the minimum.


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. Fora 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 dissolved inthe brine, the Henry's constant, and the bubble point pressure to back-calculatethe "effective %CO2" which would be required in the bubble point gas in orderto sustain the known level of dissolved CO2 (see box at cell P19). Indeed, thisprocedure can be followed for any region where the CO2 dissolved in the brineis 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 pHp redictions). 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 component andnot 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 partial pressureis not an accurate description of the activity of a gas component. The fugacity

is the true activity of the gas component. The 1991 and 1993 models use pCO2in the main corrosion prediction equations and then at the end apply a fugacitycorrection factor (Ffug) to account for fugacity effects. In Cassandra 98 theequations from the 1991 and 1993 models use fCO2 directly, therefore there isno need to use a fugacity correction factor (Ffug). The equations from the 1995model in Cassandra 98 also use fCO2 directly - instead of pCO2. Hence, inCassandra 98, it is fCO2 which is used as the primary parameter for all theequations 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 "reducedpressure",

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 difficulty arisesin deciding whether it is the Tc and Pc for methane or for CO2 that one shoulduse. In the Cassandra 98 spreadsheet, empirical values of Tc and Pc are assumedwhich allow the Newton model to agree with the CO2/methane mixed gasfugacity data in Figure 5 of the 1993 De Waard paper to ± 10%. In other wordsthe De Waard data are used to calibrate the Newton model.

The De Waard calibration data are valid up to 140oC and 250 bar. The Newtondata extends beyond these levels up to 300oC and 400 bar. The general trendsin the data will be accurate under these extreme conditions, however, theabsolute values are unchecked. For accurate work it will be necessary tocalculate or obtain the correct value of fugacity from elsewhere and thenmanipulate %CO2 in cell F8 by trial and error in order to obtain the correctfugacity 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 the corrosionrate, often in synergy with CO2. In practise, H2S tends to promote FeS surfacefilms which reduce the observed general corrosion rate but which increase thelikelihood of localised corrosion whenever the film fails. The CO2 generalcorrosion rate is often assumed as the worst-case localised corrosion rate for theregions 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). Enter ppmvalues 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/v value for glycolin cell L15. Use the SALTS spreadsheet to check that the total positive andnegative charges of the ions are roughly balanced. Any significant misbalance(e.g. >10%) may invalidate the pH calculation. Note that ion charges are handledin general chemistry by using the term "equivalents": 1 mole of positive chargesis equal to one equivalent; in other words 0.7 mole of Ca2+ ions is equal to 1.4equivalents of positive charge. Some further aspects of the acetate entry arediscussed 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 used toestimate the "salting-out" of CO2 as salinity increases. This will tend to reducethe concentration of dissolved CO2 and thereby reduce the corrosion rate [8].The box at X19 shows how to apply the salting-out correction. The procedureuses "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 low salinitybrine (ca 0.1% NaCl). Therefore, by calculating the true Henry's constant for aspecific brine it is possible to apply a salinity correction to the De Waardcorrosion rate.

The salt-correction procedure first calculates the Henry's constant used by theDe 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 sometimes awkwardrange of units which can be used to express the parameter. For consistency inthis report the De Waard equation for an aqueous solution can be rewritten inorder 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 CO2 fugacity".This "effective fCO2" will give the correct dissolved CO2 concentration whenused with the other equations in the Cassandra 98 model. The salt correctioneffect 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 the calculatedpH 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 to coverappropriate 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 values of[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 brine pHswith no restrictions on salinities or component concentrations. It was developedby XTP, Sunbury using well documented code published by the US GeologicalSurvey (the "PHREEQ" model). The original version of XLpH [10] has since beenupdated to include pH2S as an input parameter. XLpH has been validated againstother pH models such as in CORMED and also against literature and recentlaboratory values.

XLpH uses the individual ion concentrations in cells A15-L15. The positive andnegative charges must be approximately balanced (see "water chemistry", p15,above). XLpH will automatically compensate for any small misbalances by addingNa+ 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 the form of sodiumacetate 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, becausethis is the worst case. If one wishes to assume Na acetate then zero should beentered for Ac and the molar equivalent of Na acetate should be added to the Naand Cl entries. Unfortunately a field water analysis will not directly revealwhether Na acetate or acetic acid should be used to simulate the water chemistry.This can only be established by making laboratory pH measurements under CO2saturation and comparing the results with the XLpH model.

Inclusion of the organic acid concentration will always improve the reliability ofa prediction. However, when organic acid data is not available it is possible tomake some rule-of-thumb approximations in order to aid progress. Organic acidsare typically present in formation water at <30ppm. Therefore, for bicarbonate>150ppm, the presence of organic acids is likely to make little difference to thecalculated pH and therefore corrosion rate. In such cases, an API water analysis(which omits organic acids) will often suffice. If the formation water is low inbicarbonate (<150ppm), then there is more chance that organic acids could makea significant contribution to the in situ pH and calculated corrosion rate and soan acetate entry should be added to the water 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 the corrosionprediction equations.

T...temperature (oC) INPUT cell F24

The prevailing local temperature. When doing a probabilistic calculation usingCRYSTAL BALL then use a uniform distribution for the temperature : set F24 asthe 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") to acceptthe calculated value shown in cell F26.

Researchers are still actively investigating the issue of what happens tocorrosion rates at temperatures above the scaling temperature. Previous workhas shown that sometimes the scale films are protective and can reduce thecorrosion rate, whereas sometimes the films are non-protective so that thecorrosion rate continues to increase. Choosing one or other of these optionscould on the one hand lead to significant under-design, and on the other handto significant over-design. Therefore, until the matter is fully resolved BPprefers to choose a middle course for design purposes. BP assumes that thecorrosion rate reaches a peak at the scaling temperature and remains on aplateau at the same value for higher temperatures. The Cassandra 98spreadsheet follows this approach. In order to achieve this outcome both fCO2and 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) in the1995 paper. Note that the equation above is expressed in oC and uses fCO2 ratherthan the oF and pCO2 used in the paper. The 1993 paper gives a similar equationto the 1995 paper but uses a factor of 0.67 in front of the log term 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 be pipelinediameter, 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/liquid lines.The ratio of the liquid and gas cross-sectional areas, or the ratio of the liquiddepth to the pipe radius, is required as an input parameter. Calculation of thisparameter is outside the scope of the Cassandra 98 spreadsheet.

When doing a probabilistic calculation using CRYSTAL BALL then use a uniformdistribution for the hydraulic diameter : set M24 as the maximum and N24 asthe 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 P5 whichenables calculation of flow velocity from pipe diameter and flow in liquid onlylines. The calculation is more complicated for the liquid phase in gas/liquidlines, therefore, the box at cell P39 should be used.

When doing a probabilistic calculation using CRYSTAL BALL then use a uniformdistribution for the flow velocity : set M25 as the maximum and N25 as theminimum.

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 and occasionallythe glycol correction factors (FpH and Fglyc respectively). The application of eachof these is discussed below.

For the basic corrosion rate and the correction factors, the values reached at thescaling temperature are set to remain the same at higher temperatures. This isto ensure that the corrosion rate reaches a peak at the scaling temperature andthen remains on a plateau at the same value for higher temperatures (see Ts

section above). Hence, the BP approach does take account of scaling at hightemperatures but doesn't use the De Waard scaling factor, 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

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

Outputs : 1993 De Waard Model

Vcor...BasicCorrosion Rate

log10 Vcor = 7.96 − 1710T

− 0.67 log10 (fCO2)

pH CorrectionFactor

24


These equations use pHCO2 instead of the "pHsat" used in the De Waard paper.pHsat is the pH at which a brine first becomes saturated with either FeCO3 orFe3O4 as a result of the steel corroding and building up dissolved Fe2+ in thesolution. The problem with pHsat is that it is difficult to define. Even the DeWaard paper only gives some approximate expressions for one particular brinecomposition (10% NaCl). Furthermore, there is serious doubt over the wholeconcept of a fixed saturation pH due to the observation of massivesupersaturation effects by IFE (Norway) and also within BP. Dissolved Fe2+

concentrations can often reach hundreds of ppm and can exceed the theoreticalsaturation values by orders of magnitude. Hence, pHsat is not a reliableconcept.

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 over awide range of conditions. Therefore, a pure water system will give pHact =pHCO2 and so FpH = 1 in the BP approach. Certain conditions can make pHact< pHCO2 (e.g. high salinity, zero bicarbonate) and so FpH > 1. The presence ofbicarbonate will tend to make pHact > pHCO2 and so FpH < 1.

One way of reconciling these divergent approaches is to say that the direct DeWaard approach uses Fph to derive the initial corrosion rate in a brine beforecorrosion products build up and gradually reduce the corrosion rate until itreaches a steady state. This is the issue discussed in the 1993 De Waard paper.The BP approach on the other hand does not deal with initial corrosion ratesat all. It deals only with steady state corrosion rates and uses Fph to express theeffect of water composition on the steady state rate. This effect is not coveredin the direct De Waard approach. In essence BP have taken an equation fromthe direct De Waard approach and then adapted it for another purpose. Hence,overall, the two approaches are different but consistent.

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 preference topCO2 throughout the calculation and so fugacity has already been accounted 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 a corrosioninhibitor chemical is used or is planned then BP assume that any effect of glycolis included within the corrosion inhibitor efficiency (normally 90%, but seediscussion 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 to ensurethat the corrosion rate reaches a peak at the scaling temperature and thenremains on a plateau at the same value for higher temperatures (see T(s) sectionabove). Hence, the BP approach does take account of scaling effects at hightemperatures 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 1993 model,in particular it does not use the idea of correction factors applied to a basecorrosion rate. Instead, the overall corrosion rate is calculated from twocomponents : 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 1993 and1995 rates so that one can see the lower and upper bounds on the expectedcorrosion 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 at lowvelocities so it is ignored whenever it falls below the 1993 value, and then themerged rate is the same as the 1993 rate.

The validity of any corrosion prediction model depends on how well it agreeswith the measured corrosion rates in the field. However, the comparison is notalways straightforward. This is because the models are developed from wellcharacterised, clean and stable systems in the laboratory, and they are beingapplied to partially characterised, dirty, and variable systems in the field wherethe full operating history is not always known. This is no criticism of fieldactivities. It is simply a fact of life of operations where the aim is to producehydrocarbons, not to generate completely rigorous corrosion data.

The discrepancies between the models and r eal field corrosion data which doexist arise because there are parameters in the field which the model can not takeaccount of effectively, or at all, e.g. surface coatings (scales, corrosion products,biomass), crude oil wetting, local hydrodynamics, weld metallurgy.

The industry generally regards the De Waard model as conservative compared tothe field, i.e. it over-estimates the field corrosion rate. Much of this opinion isbased on anecdotal and semi-quantitative evidence - often not published in theopen literature - but it is confirmed by the occasional formal presentation [12].

1993 & 1995Merged CorrosionRate

Vcormerged = Vcor

1993 + Vcor1995

2

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

28


BP is currently compiling a database of field corrosion data from a variety ofsources which will be used to assess the Cassandra 98 spreadsheet presentedhere.

In the meantime Table 7 gives a comparison of the Cassandra 98 spreadsheetagainst new laboratory data; data which were not used in compiling themodel. The final column shows whether the observed corrosion rate falls within15% of the range encompassed by the 1993 and 1995 models and there is someagreement. However, the discrepancies show the pitfalls in trying to push theaccuracy of the model too far. It is best used to gain order of magnitudeestimates of corrosive situations rather than absolute corrosion rates to severaldecimal 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 they areeasily found for CO2 dissolved in pure water [e.g. 13]. The data for brines is lessextensive [14-16]. Figure 7 is compiled using data from all these sources. Thereduced number of points at higher salinity are still sufficient to show that thedata in the 0-10% region can be reliably extrapolated up to ca 30% NaCl. Notethat the 16 and 31% data at 75 and 100oC are actually for MgCl2 in the originalpaper but have been plotted in Figure 7 at the equivalent 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 (to within±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 true Henry'sconstant 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 assess theimpact of various process or production scenarios. However, corrosion rateprediction models should always be used in conjunction with other tools such aslife cycle costing as well as previous operational experience if the final materialsselection is to offer the optimal balance between cost and reliability. As eachproject will have unique economic factors, materials selection should reflect theseand the economic assessment will be as important as the corrosion modelling inthe selection of the final materials. In-depth coverage of techniques such as lifecycle costing and estimating values are beyond the scope of this document butboth techniques are briefly covered in a previous publication [17].

Over the past few years, several design guidelines have been issued by BP fordealing with CO2 corrosion risks. Each document deals with a specificapplication. This more general document summarises all previous guidelines butcan 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 approach todefining internal corrosion risks and the basic approach is still followed. Itrecommended the use of the de Waard and Milliams model to predict in-situcorrosion rates along with a 90% corrosion inhibitor efficiency. Much of thework is still valid but it is in the areas of high temperature scaling, corrosioninhibitor efficiencies and impact of various flow regimes that the new guidelines

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

differ. Most of the recommendations made in these guidelines have beenreproduced or superseded in the present document and therefore the originalguidelines 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 for usein 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 wetted bycondensed water, hydrate inhibitor and hydrocarbons, and (b) the top of linewhich is wetted intermittently by condensing liquids. The corrosion rate at thetop of the line is lower than that at the bottom due to the more limited exposureto corrosive species. Predicting this rate is done by predicting the bottom of linerate using models in the normal way and applying a moderating factor for thetop of line rate. Up to 1992, BP used a factor of 0.3, i.e. the top of line corrosionrate was predicted to be 30% of the bottom of line rate. When inhibitors areused to control the bottom of line rate, the top of line corrosion rate becomesthe limiting rate as inhibitors are assumed not to protect against condensingcorrosion. This report reviewed the top of line factor and recommended theadoption of a moderating factor of 0.1. For inhibitor efficiencies up to 90%, thetop of line corrosion rate is therefore not the limiting rate. This approach is nolonger valid since BP have moved away from the direct use of inhibitorefficiencies, as described later in this report. However, the assumption that topof line rates are 1/10th of the predicted uninhibited bottom of line rates can stillbe 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 becarried out. Such a scenario does not lend itself to the use of simplifiedguidelines.


34

The application of pH moderation as a means of corrosion control forwet 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 iscovered 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, NACE Publications)reduces general metal loss rates but can promote pitting. The pitting proceedsat a rate determined by the CO2 partial pressure and therefore CO2-basedmodels are still applicable at low levels of H2S. Where the H2S concentration isgreater or equal to the CO2 value, or greater than 1 mole%, the corrosionmechanism may not be controlled by the CO2 and therefore CO2 based modelsmay not be appropriate.

Summary of Previous Guidelines

In summary, the old guidelines are generally still applicable. What has changedis BP’s views on the reliability and performance of corrosion inhibitors as wellas the availability of updated models incorporating flow affects. The oldguidelines defined a corrosion inhibitor efficiency of 90% with no scope forvariation. There were also stringent velocity restrictions for use undermultiphase conditions which restricted the energy of slug flow to below 20 Pa,later raised to 100 Pa. In light of favourable field data, this approach is nowseen as too pedantic and inhibitor availabilities are seen as a better way ofdescribing the role of inhibitors. These differences in approach are covered inmore detail in the following sections. Furthermore, the corrosion rateprediction model (p5-30) does not cover some aspects that are important duringdesign 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 whole rangeof input values. Where the model is dealing with several inputs (temperature,pressure, CO2 mole %, pH, scaling factor), this can be time consuming. Also, thevalue of these inputs will not all vary in a uniform manner. Some will behaveuniformly while others may behave in a normal or 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 and handlesthe variability by performing a Monte Carlo analysis. Any number of iterationscan be performed and the output is displayed in terms of a probability, ratherthan as a discreet value. In general, a minimum of 1,000 iterations, involving tensof thousands of individual calculations are required to show the effects of thevariability in input data. A modern PC can perform such a task in a minute ortwo.

The important factors to consider are the range and type of distribution assumedfor each variable. If process data are available, this will form an ideal basis fordetermining the range and type of distribution but if this is lacking, someassumptions will have to be made.

Using distributions to define variables in a predictive model can have significanteffects 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 approach wasthe only viable one as predicting the enormous range of possible outcomes forall variables would have been too time consuming but it can result in substantialover-design. Metal loss corrosion processes do not lead to sudden failure due toa combination of variables over short time periods (unlike high pressure whichcan lead to an instantaneous failure) but rather reflect a combination of varying

Worst Case Design

Important Factors not Covered by the Corrosion Model

The ProbabilisticApproach toPredictive Modelling


36

conditions over a longer time period. Using the worst case values is thereforenot a sensible approach, if a range of more realistic 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 nature ofthe uncertainty, such that all values within the range are as likely as each other,Uniform distributions are probably the most appropriate for these variables.

The yield strength and wall thickness of linepipe are other examples of the typeof variables that can be treated in this manner. The linepipe properties areimportant if using corrosion models to calculate mean time to failure. Ratherthan using the minimum values for each, based on the specified material andthe variation allowed within the specification, typical distributions can bedefined for each value. Such variables tend to be distributed normally arounda mean with the specified minimum properties defining a lower bound.

Many variables in corrosion rate predictions, such as the level of CO2 in the gasphase, are based on “best guess” or on limited well test data. No attempt ismade to define the uncertainty in these data and this is a major limitation ofdeterministic modelling. In defining the distributions of such variables, themean value should be based on the best guess or well test data in a similar wayto the deterministic approach. However, a range of possible values should beconsidered. In the absence of any other information, the distribution of valuesis likely to be symmetrical around the mean with the greatest probabilityassociated with values close to the mean. The Normal distribution is a familiarexample of this type and should be used.

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

Non-LinearRelationships


37

Therefore, the corrosion rates associated with the CO2 partial pressure values inthe Normal distribution that are greater than the mean value are closer to themean corrosion rate than those associated with the values below the mean CO2partial pressure. In other words, defining symmetrical distributions for variableswhose influence is described by a power < 1 produces a non-symmetricaldistribution of outcomes (predicted corrosion rates). The mean value of thisdistribution will be lower than the single value calculated using the mean of theinput 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 moderated bya fugacity coefficient related to the non-ideality of CO2. Therefore, consideringa range of pressures distributed symmetrically around a mean value will tend toreduce the predicted corrosion rate.

The effect of temperature on predicted corrosion rates is strongly non-linear. Athigher temperatures, the role of protective corrosion products or scales can beimportant. There is a great deal of uncertainty in the effects of these scales butthe bounds of the expected values can be defined using existing models. Oneapproach 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 temperatures above this.

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

Each input into a corrosion rate prediction should be considered and a range ofpossible outcomes defined. By consideration of the way in which the value mayvary in practice, a distribution function can also be defined. This may have tobe done subjectively but the following basic rules offer some guidance. In thefollowing examples, distributions are shown that have been used in the CrystalBall 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 in CO2levels around the field, a Normal Distribution should be used with a meanequivalent to the best guess. Figure 7 shows an example of a NormalDistribution describing the expected variation in CO2 levels, centredaround 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 to beskewed 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 at whichinhibitors fail to control corrosion. Figure 8 shows the Log NormalDistribution used to describe the critical pit depth with a modal value of 8mm 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 range offlowline operating pressures can be described. In this case the range of1,000 to 1,200 psi has been used.

Table 9 summarises the assumptions used in a recent probabilistic study intomean time to failure, based on CO2 corrosion risks. As the study looked atfailure mechanisms as well as corrosion rates, some of the factors apply to thelinepipe steel while others apply to the CO2 prediction model. The 'StandardValue' corresponds to the value that would be used in a deterministic study.The Table does not attempt to fully define the distributions in a statistical sensebut more information is available from the authors 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 pH values ofoilfield brines.

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


42

This section represents a significant shift from previous BP recommendationsand therefore is covered in some detail.

The guidelines on the reliance to be placed on corrosion inhibitors presentedhere have been based on experience gained with continuous injection systems.The success of batch treatments with corrosion inhibitor is less welldocumented and generally this approach to corrosion control is less reliable.These guidelines should therefore not be used when designing systems that willbe protected with batch treatments - this effectively rules out their use for

the majority of downhole applications. Instead, it is recommended thatrelevant operational experience with batch treatments is sought beforedesigning on the basis of batch inhibition. The authors will be able to assist insourcing relevant operational experience.

Previous BP guidelines have dealt with the affect of corrosion inhibitors on CO2corrosion by assigning a “corrosion inhibitor efficiency”. This described theextent to which an inhibitor reduced the predicted rate and a figure of 85% wasoriginally used, later raised to 90%. This was despite laboratory observationsthat showed inhibitors could reduce corrosion rates by 95% or more. However,it was accepted that in the field, inhibitor is not delivered at the recommendeddose rate for 100% of the time and therefore a degree of conservatism isnecessary when estimating the benefits of inhibitors.

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 no considerationof the effects due to increased dose rates or the development of better chemicals.It is well known that increasing the dose rates of corrosion inhibitors up to acertain level reduces the corrosion rate. Figure 11 shows the relationshipbetween dose rate of inhibitor and corrosion rate on corrosion coupons atPrudhoe Bay. Clearly, the inhibitor efficiency is not a constant value andincreasing the inhibitor concentration (or changing the chemical for a moreefficient one) enables lower corrosion rates to be achieved.

A second major limitation with using a single value for corrosion inhibitorefficiencies is that they are unlikely to be constant across the whole range of fieldconditions. CO2 corrosion models can handle input values across a wide rangeand moderation factors have been developed over the years to reduce theconservatism due to the extrapolation of the data set used to develop the model.However, no such moderation factors have been developed for corrosioninhibitor efficiencies and by applying a blanket efficiency, it is assumed they areconstant across the range of applications.

BP is ‘fortunate’ in having one of the more corrosive fields in Prudhoe Bay. Thisfield also lends itself to effective corrosion monitoring due to the use of above-ground flowlines and there is a great deal of data on inhibited corrosion rates.There is a good relationship between observed corrosion rate and inhibitorconcentration, as shown in Figure 12. In this Figure, the effect of the increaseddose rate of chemical between January 1994 and September 1996 can be seen inthe increased ‘efficiency’ of the chemical, based on the predicted corrosion ratesusing BP’s CO2 corrosion rate prediction 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 corrosion ratesunder 2 mpy (0.05 mm/yr.) based on corrosion probes - see Figure 13. Theimprovement in performance from January 1994 onwards correlates with theincrease 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 constructed todayusing the same materials and corrosion allowances, it would infer a corrosioninhibitor efficiency of approximately 98%. As PBU have now demonstrated thatcorrosion control of their system is possible it is clear that inhibitors can beeffective under highly corrosive conditions. This in turn indicates that either:

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

❍ Corrosion inhibitor efficiencies are not the correct way to describe the roleof 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 this to beproduced. The latter is the belief of several oil companies who do not useinhibitor efficiencies, preferring to use a design corrosion rate for inhibitedsystems in the range 0.1 to 0.3 mm/year. For mildly corrosive conditions(~1.0mm/year) the use of an efficiency of 90% generally works well. However,for highly corrosive conditions (~10mm/year) it would result in a conservativeestimate of the inhibited corrosion rate. This adds weight to the argument thatthe role of corrosion inhibitors can not be described by efficiencies.

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 optimised chemicals.This is confirmed with inspection data from PBU where flowlines which havebeen effectively inhibited have pipewall corrosion rates of less than 0.1 mm/yr.

In general, inhibitors require free and regular access to the steel surface to beeffective. Anything that interferes with this will reduce their effectiveness to lowor negligible levels. Examples of low or stagnant flow situations are vessels,instrument and drain piping and tanks. Historically, inhibitors have not beenassumed to work well in these environments and other corrosion controlmeasures 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. Under suchcircumstances, deposits inevitably form at the 6 o’clock position, preventingtransportation of the inhibitor to the metal surface. Flow velocities belowapproximately 1.0 m/s should be avoided if inhibitors are to provide satisfactoryprotection and this will be critical in lines containing solids.

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 of thumbfor most black oil systems but allows more accurate quantification if theminimum 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 some incidentalcosts associated with the provision and maintenance of injection equipment butincreasingly this is being handled by the chemical suppliers and is thereforecovered 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 as liquidthroughput, CO2 partial pressure, pH and flow regime. Dose rates are notdependent 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 standard product,manufactured by the same supplier.

At Prudhoe Bay the field-wide average corrosion inhibitor injection rate is 110ppm, with maximum rates of 250 ppm in certain flowlines, based on waterproduction (typical water cuts are 50%). These rates reflect the rapid corrosionexperienced in some PBU flowlines in recent years.

The determination of dosage rates in gas systems is not as straightforward as forliquid filled lines. The three methods which are commonly used to do this are:

1. Based on Gas Flow. This is the most commonly used method and a commonrule of thumb is to apply 1 pint of inhibitor to every 1 million standard cubicfeet of gas (1 pint/MMscf). Actual values are found to vary enormously in therange of 2 and 0.05 pints/MMscf of gas.

2. Based on the Water Content in the Pipe Line. This is the method favouredby corrosion engineers as it usually indicates a very low requirement forinhibitor. It is common to assume a dosage of 200 ppm of chemical in thewater. This method will often give erroneously low values, especially when the

therefore the same operating cost is incurred in protecting 10 metres of pipeworkas is required to protect 20 km of flowline. Corrosion resistant materials arelikely to offer lower life cycle costs for pipework while carbon steel plusinhibition tends to be the cheapest method of constructing and operatingflowlines [19].


48

water content is very low and/or the pipeline is very long. This is becausethe volume predicted will be too low to allow a film to be build up over theentire surface of the pipe.

3. Based on the Formation of a Protective Film. This is probably the leastused method but one whch provides a good check on the values obtainedfrom the first two methods. Typically it is the volume required to form a0.05mil (1 micron) film over the entire internal surface of the pipe. Thisvolume is then applied continuously on a daily basis. If the product is to beapplied as a batch treatment the volume is increased by a 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 re q u i red. Again, highly corrosive duties associated with hightemperatures or CO2 partial pressures will tend to require dose rates towardsthe 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 cents perbarrel at inhibitor dose rates of 25 to 250 ppm. There will also be costsassociated with monitoring and inspection. These aspects are beyond the scopeof this document but are covered in detail in ‘SELECTING MATERIALS FORWEALTH CREATION: A Material Selection Philosophy Based On Life CycleCosts [17].

Due to the limitations of corrosion inhibitor efficiencies as a design tool, theinhibitor availability model has been adopted. This approach can be used todefine 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 Inhibitor AvailabilityModel’


49

In the context of this model, corrosion inhibitor availability infers the presenceof a suitable corrosion inhibitor at sufficient concentration to reduce thecorrosion rate to 0.1 mm/yr. The factors that lead to inhibitor availability below100% 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 water cutor sand rate.

❍ Well stimulation fluids such as hydrochloric acid are produced along withthe 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 as scaleand corrosion inhibitors.

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

All of these factors and others not listed have lead to less than optimal deliveryof corrosion inhibitor into production equipment in BPX. No asset is immune tosuch problems and therefore the maximum inhibitor availability that should beassumed is 95%. In many instances, a lower availability should be assumed; see,'Recommended Values For Use in the Inhibitor Availability Model, 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 figure tothat generated at a new gas treatment plant in the Middle East. This is probablyclose to the maximum that inhibitor injection units can be available, bearing inmind the requirements for chemical feedstock, power and the reliability of thepumps. However, this should not be used as a basis for assuming an inhibitoravailability of greater than 95%. Figure 14 shows the delivery of corrosioninhibitor against the target rate for a North Sea platform. There was only oneinstance when the inhibitor injection system was not delivering chemical - duringMarch 1993 - but there were also only 3 short periods where the chemical wasfully available with respect to the target dose rate.


50

At the project stage, it is difficult to determine the availability of inhibitor infuture years but relatively easy to ensure inhibitor is available on day one. Theprovision of chemical injection equipment is often outside the scope of EPICcontracts and therefore assets are brought on-stream without the necessaryfacilities to inhibit valuable equipment. In previous projects, this has taken upto 2 years to correct and therefore the best inhibitor availability that can beachieved will be 90%, assuming a 20 year design life. If the provision ofchemical injection equipment is brought inside the scope of the EPIC contract,measures can be taken to ensure inhibitor is available on day 1 of operations.

Achieving good inhibitor availability during operations is partly down to systemdesign and partly due to management of the changing corrosion risk. Inhibitorinjection systems are simple systems and lend themselves to high levels ofmechanical availability. This can be improved further through the use of lowlevel warning devices on the storage tanks and dose rate gauges such as thesight glass or more complicated dose rate monitoring systems. Together, thesetwo simple measures will help to ensure that the target dose rate is achievedfor a high proportion of the time.

Ensuring the target dose rate is correct is more difficult and requires thatconstant changes to the target are made to reflect changes in production rate,water cut etc In extreme cases, this may require weekly tailoring of the targetdose rate. This is where corrosion control programmes can fail and thereforeit is important that the materials or corrosion engineer concentrates on thisaspect.

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 management ofcorrosion using chemicals. As chemical inhibition is the only viable method forcontrolling internal corrosion, it is important that the deployment of chemicalreceives 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 of thefeedback loop in Figure 15. The different approaches to managing this feedbackloop enable five categories to be defined which in turn allow recommendationsto be made on the values used for inhibitor availability.

In all cases, it is recommended that the inhibited corrosion rate is assumed to be0.1 mm/yr. The inhibitor availability value will reflect the approach of an assetto corrosion inhibition. The following categories have been defined to cover theentire range, based on predicted corrosion rates. Each asset or project may haveequipment corresponding to two or more categories, as the modelled corrosionrate will vary throughout the facilities. The categories are summarised below anddiscussed in detail in the following sections, starting with the lowest corrosionrisk.


52

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

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

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

❍ Category 4 - Corrosion inhibition is relied on heavily and will be requiredfor the entire period of operation. Inhibitor must be available on Day 1 toe n s u re maximum probability of success for the corrosion contro lprogramme.

❍ 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 last resort.

Categories 2 and 4 are illustrated schematically in Figure 16. Categories 1, 3 and5 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 a sufficientdegree and de-rating or replacement will be required at Year 10. In this case, 18years of inhibition (equivalent to 90% availability) is not sufficient due to the highrates of uninhibited corrosion in Years 1 and 2. The availability of inhibitor mustbe improved to 95% if carbon steel and corrosion inhibition is to worksatisfactorily and therefore the system should be designated as a Category 4 anddesigned and operated accordingly.

Category 2 - blue example:

Uninhibited corrosion proceeds at a moderate rate for 10 years, when inhibitionis started. The inhibited rate is low enough to enable full field life to be reachedwith corrosion allowance to spare. In this case 10 years of inhibition, equivalentto 50% availability is satisfactory. This would place this example in Category 2as there is ample time to detect corrosion prior to the implementation of acorrosion 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 remaining periodi.e. 100% availability for the remaining period. In practice, this will not be thecase and inhibitor availability will be less than 100% due to the reasonsdescribed pp 49. This would see the lines representing the loss of corrosionallowance becoming step shaped, corresponding to the periods of inhibitoravailability 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, monitoringand 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 allowance requiredfor a Category 3 system compared with the additional costs of the control,monitoring and inspection incurred with a Category 4 system.

In general, long pipelines will be more cost effective when designed to a highercategory while shorter pipelines or process piping will be more cost effective as alower 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 corrosion allowance.In practice, this means a maximum predicted corrosion rate of 0.4 mm/yr.,assuming a design life of 20 years and a maximum corrosion allowance of 8mm. Longer or shorter design lives will change this rate accordingly. Corrosioninhibition provides a fallback measure in case the actual corrosion rate arehigher than predicted due to changes in field conditions or unforeseencircumstances.

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-situcorrosion rates may be higher than predicted. However, rates are unlikely toexceed the predicted rate by more than a factor of 2 (i.e. 0.8 mm/yr. maximum)and therefore the inspection programme will be capable of detecting suchattack. This can provide an early warning system, allowing time forimplementation of a corrosion control programme if required. The usualrequirements of an inspection programme apply. In particular, it shouldanticipate localised corrosion at areas such as welds and the 6 o’clock positionof low flow rate lines.

Category 1 - Corrosion Control System Requirements

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


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 corrosion rateis too high to be accommodated by corrosion allowance alone but wherecorrosion inhibition should not be required for the full field life.

In practice, this approach is only valid for predicted corrosion rates of up to 0.7mm/yr., again assuming an 8 mm corrosion allowance and 20 design life. Usinga corrosion inhibitor efficiency of 50% infers that approximately 9 years ofuninhibited corrosion can be accommodated before 95% reliance on inhibitionmust be assumed for the remaining 11 years of a 20 year field life. This providestime for corrosion to be detected via inspection programmes.


A design of this type relies heavily on monitoring systems to detect the onset ofcorrosion at a rate requiring inhibition. This will require monitoring of processchanges such as temperature, flow velocity and water cut. Direct corrosion ratemonitoring will also be required. However, due to the relatively low corrosivityof fluids, response from corrosion probes and coupons may be poor.

Due to the relatively low corrosivities of the fluids, inspection programmes willalso play a vital role in detecting the onset of corrosion. Uninhibited corrosionlosses of half the corrosion allowance over a 3 to 5 year period will be detectableby inspection techniques and will still enable corrosion inhibition to reduce ratesto acceptable levels over the remaining field life. Selecting corrosion allowancesusing the BP model will ensure several years of corrosion can be accommodatedprior to inhibition being required.


The corrosion control system must be capable of being commissioned and tobegin injection as soon as changes in the corrosion rate are detected. This meansthat the plant should be designed for inhibitor injection without recourse to ashutdown. In practice, this will mean that access fittings should be installed toallow fitment of corrosion inhibitor injection quills at system pressure. Provisionof equipment upstream of the quill such as the pipework, dosing pumps andstorage tanks can be delayed until monitoring or inspection data show thatcorrosion 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 inhibition foralmost the full life of the field but do not include the specification and provisionof corrosion control and monitoring facilities into the overall project scope foruse on Day 1 of operations. In practice, this may mean that corrosion controlequipment is not on site and commissioned for 12 months or more andtherefore the reliance that can be placed on inhibition is less than 95%. A delayof 12 months means that corrosion inhibitor availability must average 95% overthe remaining 19 years to achieve an overall availability of 90%. This limits themaximum predicted corrosion rate that can be successfully accommodated to3.1 mm/yr., assuming a corrosion allowance 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 in under3 years if the corrosion allowance is selected in accordance with the guidelines.Reliance on the corrosion control programme is therefore high, particularly asit will not be present on Day 1 of operations. The corrosion monitoring systemmust be capable of detecting changes in corrosion rates within weeks if thetarget rate of inhibitor injection is to be constantly revised to ensure the overallavailability of 90% is achieved. The recommended techniques that are capableof providing such resolution are ultrasonic mats and the CorrOcean FSM.


It is recognised that the corrosion control system will not be available on Day1 of operations. However, it must be capable of being commissioned withoutrecourse to a shutdown. In practice, this will mean that access fittings shouldbe installed to allow fitment of corrosion inhibitor injection quills at systempressure. The corrosion inhibitor should have been pre-selected and the initialdose rate should be based on either laboratory trials or similar operatingexperience elsewhere.

Provision of equipment upstream of the quill such as the pipework, dosingpumps and storage tanks should also be planned during the design phase to



59

unsure there is adequate deck space and power supplies to enable the system tobe commissioned quickly once it arrives. The system should incorporate doserate meters and low level warning devices on the storage tank.


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

This category applies to equipment that require corrosion inhibition to be presentfor the full design life of the field to ensure satisfactory integrity from carbon steelequipment. The reliance on corrosion inhibition is high and a failure could occurin a little over 1 year if the corrosion control programme fails. To achieveinhibitor availability of 95%, the corrosion control system must be operational onDay 1. To ensure this happens, it is recommended that the provision of thecontrol system is brought within the scope of the overall 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 dose ratesof chemicals to be checked on a weekly basis and the sensitivity of corrosionmonitoring devices must reflect this. The recommended techniques that arecapable of providing such resolution are ultrasonic mats and the CorrOcean FSM.


The corrosion control system must be commissioned and working on Day 1 ofproduction. The corrosion inhibitor should have been pre-selected and theinitial dose rate should be based on either laboratory trials or similar operatingexperience elsewhere. The system should incorporate dose rate meters and lowlevel 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. Predictedcorrosion rates beyond 6 mm/yr should not generally be handled through a




60

combination of carbon steel with corrosion allowance and corrosion inhibition.Instead, corrosion resistant materials should be considered.

There will always be specific cases where corrosion resistant materials are notfeasible or where previous operating experience indicates that carbon steel willcorrode at a lower rate than indicated by the model. However, the risksinvolved in operating such a system are high and repairs or replacement ofequipment should be expected during the field life. This is unlikely to be costeffective when lost production costs and potential environmental damage areconsidered and these areas must be addressed if such highly corrosive fluids areto be handled or transported using carbon steel.


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 a Category4 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 each category.Table 12 also classifies when an intelligent pig inspection should be carried outfor the various corrosion risk categories. These classifications are described onpage 52. These can be scheduled by a variety of means, depending on theamount of information available for the system. If there is extensive processand corrosion monitoring data together with extensive operational experienceof the system, it may be possible to schedule inspections based on gathereddata i.e. using ER probe data as a trigger. However, until experience andconfidence are gathered corrosion modelling offers the best method. Thereliance on monitoring and inspection is greater for Categories 5, 4 and 3 thanfor Categories 2 and 1 and therefore inspection should occur earlier in the field’slife.


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 monitoring

Standard 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 plus

capable of requirement weight loss coupon weight loss coupon weight loss coupon

commissioning ER probes ER probes ER probes

w/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 plus

included 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 system

commissioned as flow monitor in Continual data Continual data Continual data

soon 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 plus

scope of overall low level device increased inspection increased inspection increased inspection

project and and flow monitor frequency frequency frequency

available 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 4

scope of overall low level device plus leak plus leak

project and and flow monitor detection detection

available 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 but toremove some of its conservatism in more corrosive systems. The two inputs tothe model are the inhibited corrosion rate and the inhibitor availability andusing different values for these can produce a whole array of outputs.

Figure 18 shows the corrosion allowance that would be recommended using thetwo approaches for a 20 year design life. A range of uninhibited corrosion ratesare considered, from 0.5 to 10 mm/yr. which covers the range from mildly tohighly corrosive fluids (less corrosive fluids would probably be handled withoutrecourse to inhibition). In the inhibitor efficiency example, an efficiency of 90%has been assumed, in line with BP’s previous practice. The inhibitor availabilitymodel uses an inhibited corrosion rate of 0.1 mm/yr. and an inhibitoravailability of 95%. During the remaining 5% of the time, the uninhibitedcorrosion rate is used (0.5 to 10.0 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 as externalcorrosion may require a corrosion allowance of up to 2 mm and would 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 lower corrosionallowances than the efficiency model. This agrees well with the observed ‘highefficiencies’ of corrosion inhibitor under highly corrosive conditions. This willincrease the use of carbon steel as the standard practice is to specify carbon steelwith corrosion allowances up to 8mm and to use corrosion resistant steels formore corrosive fluids.

Figure 19 shows the relationship between predicted corrosion rate and therecommended corrosion allowance using the inhibitor availability method. Theexample shown is the same as in Figure 18 with predicted corrosion rates in therange 0.5 to 10 mm/yr. In each case, the corrosion allowance for inhibitedcorrosion is constant at 1.9 mm due to the assumption of an inhibited corrosionrate of 0.1 mm/yr. and the required field life of 20 years. The variation inrecommended corrosion allowances is due entirely to the 5% of the time whereinhibition is assumed to not occur.

Figure 19 helps to illustrate how important the period of uninhibited corrosioncan be. In a severe case of a predicted corrosion rate of 10 mm/yr., theuninhibited period of 5% of the time accounts for 83% of the corrosionallowance. In this case, each 1% increase in the assumed availability of corrosionwould reduce the total corrosion allowance by 16.6%. Table 13 gives some moredetails 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 Inhibitedand UninhibitedPortions of theInhibitor 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 value forthe 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 strength ortoughness. Such elements are commonly found in corrosion resistant materialsand chromium in particular can increase the corrosion resistance of carbonsteels, if present in sufficient concentration. 13% of chromium turns a carbonsteel into a stainless steel, with excellent resistance to CO2 corrosion.

Many claims have been made over the past 5 years of the affect of adding lowlevels of chromium (0.5 to 1.0%) to carbon steel. Some steel suppliers claimthat 0.5%Cr can halve the CO2 corrosion rate and certainly in some tests theredoes appear to be a benefit. The most consistent benefit seems to be animproved resistance to ‘mesa’ corrosion where large, square edged and flatbottomed pits can form. However, in other tests no benefits have beenobserved and it seems that the benefits may be related to microstructure ratherthan composition. Other researchers and oil companies have reported thatinhibitors perform worse on low alloy steels than on carbon steel and therefore,in inhibited systems, there is no benefit from the addition of low levels ofchromium.

Corrosion Rates of Low Alloy Steels


65

On balance, BP believe there are no proven advantages or disadvantages int e rms of CO2 c o r rosion resistance from the presence of chromium atconcentrations up to 1% in steels. It is therefore recommended that no accountis taken of the presence of alloying elements at low levels and no premiumshould be paid for such steels. However, if the steel supplier uses low levels ofchromium in the standard product, that is acceptable.

Preferential weld corrosion is a problem in most systems and production systemscontaining CO2 are no exception. Efforts have been made to eliminatepreferential weld corrosion by alloying welding consumables with variouselements such as chromium, nickel and copper at low levels (circa 1%). Nouniversal solution has been found and there are examples of either weld metalor heat affected zone (HAZ) suffering preferential attack with most weldingconsumables and welding procedures. The problem is not made easier by thefact that the mechanism for preferential weld corrosion is not fully understood inCO2 service. The speed of such corrosion suggests there could be a galvanicdriving 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 problem whendeciding whether a corrosion inhibitor is required for a particular application.The traditional approach has been to calculate cumulative wall losses over thelife of the field using corrosion models and if the predicted wall loss is less thanthe available corrosion allowance, inhibitors have not been specified. However,preferential weld corrosion can proceed at rates far higher than predicted andinhibitors offer the only proven method of improving the reliability of carbonsteel in such cases. There have recently been cases of preferential weldcorrosion causing rapid failures in systems believed to be only mildly corrosive.

Unfortunately, there can be no clear guidance for such systems but inspectionprogrammes should recognise the risk of preferential weld attack and, ifdetected, corrosion inhibition should be initiated immediately.

Preferential Weld Corrosion


66

CO2 models are basically ‘bare surface’ models with moderation factors appliedto anything that affects this, such as surface scales and corrosion inhibitors.Moderation factors are used to reduce the predicted corrosion rate due to thepresence of protective or semi-protective species at the surface. In other words,all such factors predict that the surface will corrode at a lower rate than wouldbe 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 steel surfaceis different from that in the bulk due to the continual transport of reactants tothe surface and products from the surface and this is reflected in the CO2models and associated factors. These effects are generally beneficial where thecorrosion process is transport controlled but can be detrimental where it is thetransport of inhibitor that is limited. This can be the case in a corrosion pitwhere galvanic affects also play an important role. The result is that the growthrate of deep pits may accelerate. This can be seen as a loss of control by theinhibitor and may place a practical limit on the size of the corrosion allowance.For example, if an inhibitor is incapable of protecting pits deeper than 8mm,once pitting has reached this depth the corrosion rate in the pit will proceed atthe uninhibited rate, i.e. 10 or 20 times faster than the bare surface rate. Theincrease in life due to the provision of corrosion allowance beyond 8 mmwould 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. Pitting ratesup to 3 times faster than predicted have been quoted in a variety of systems.Certainly, if corrosion has reached 8 mm it is likely that the local environmentwithin a pit will be significantly divorced from the bulk environment and hencetransportation of inhibitor may be unreliable. Moreover, if corrosion has causedsuch metal loss, the corrosion control of the system must be poor and providingextra steel is unlikely to provide a satisfactory answer.

As corrosion allowance is often consumed via pitting or localised corrosion theimportance of pits should be considered when selecting the optimum corrosionallowance.

Effect of Pitting


67

The term corrosion allowance creates the impression of a uniform wastage overtime leading to the gradual and controlled reduction in wall thickness. Inpractice, this is unlikely to be the case and the role of the corrosion allowanceis to provide protection against the periods when corrosion control is poor andshort term corrosion rates are high, i.e. poor inhibitor availability in the case ofinhibited systems. As there is always uncertainty in the rate of corrosion (andtherefore time to failure), specifying a corrosion allowance is a compromisebetween capital costs and reliability. Greater corrosion allowances incur greatercosts but confer greater reliability. For mildly corrosive systems, low corrosionallowances of 1.5 to 3 mm are justified as they are protecting against thepossibility of internal and external corrosion. In highly corrosive systems, activecorrosion is almost certain to occur and therefore greater corrosion allowancesshould be specified to increase the mean time to failure.

Some Operators specify maximum corrosion allowances and BP has tended touse 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 allowance provideslittle 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 been lost,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 in thickwalled pipe which in turn means that corrosion may continue for sometime before detection. It is preferable to detect corrosion early and remedythe situation and therefore thin walled pipe is preferable for detection ofcorrosion.

4. Welding and handling thick walled pipe is difficult and thick sections mayrequire post weld heat treatment. Cost increases are therefore greater thanthe incremental increase in wall thickness.

The figure of 8mm should not be seen as fixed. Each project may have differentdrivers in terms of the optimum balance between opex and capex costs and incertain cases, replacement of flowlines may be more economically attractive than

Choosing an Optimum Corrosion Allowance


68

high capital costs in Year 1. For one recent BPX project it was decided thatlocalised corrosion was the main concern for the flowlines and therefore thedefinition of corrosion allowance should reflect this. BP’s first pass defectassessment criterion for pipelines allows 20% of the pressure containing wall tobe lost due to localised corrosion and the design of the corrosion allowancetook this into account. This approach reduced the corrosion allowance by circa1.5 mm and saved US$1.16 million from the cost of the flowline network. Ineffect, the ‘traditional’ corrosion allowance was reduced from 8 mm to 6.5 mmbut as the corrosion was expected to be localised, there would be 8mm ofpipewall available for localised corrosion before raising any concern overintegrity.

In other cases, a corrosion allowance greater than 8mm may be justified but itshould be recognised that the additional costs may not be reflected in theincremental increase in reliability.

Use of Common Sense

In specifying a corrosion allowance, the Materials Engineer should not be toopedantic. Projects often define three or more nominal corrosion allowancessuch as 1.5 mm, 3 mm and 8 mm. Process streams are categorised as mildlycorrosive, corrosive or highly corrosive using models or experience and theappropriate corrosion allowance added to the pressure containing wallthickness defined using the appropriate code. The total required wall thicknessis then reviewed against the available wall thicknesses with the next greaterthickness being selected. It may be the case that the corrosion allowance justtakes the total wall thickness out of one wall thickness range and into another,increasing significantly the wall thickness 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, standard practicewould be to select the 14.3 mm size. The ‘excess’ 1.5 mm would addcircaUS$11,500/km to the cost of the 16” flowline i.e. in excess of US$1 millionfor a 100km line. As the selection of the nominal corrosion allowance is basedon imprecise models, the Materials and Pipeline Engineers should use their


69

judgement in the selection of the final wall thickness. They may decide that acorrosion allowance of 5.9 mm is acceptable, allowing the 12.7 mm WT linepipeto be specified.

CO2 predictive models - such as the one in this report - are based on laboratorystudies, typically developed in water only systems. Various moderation factorshave been applied over the years, reducing the predicted rates as experienceshowed them to be too conservative in their basic forms. In the approachcovered here, the water cut is ignored thereby treating the pipeline or processequipment as if it was transporting 100% water. It may appear a large step toapply a model developed using laboratory data in water only systems to the fieldwhere hydrocarbons account for the majority of the throughput.

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

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

in a system is rarely of interest: it is the maximum rate that determines time tofailure. If at a water cut of 1%, 1% of the equipment is water wet 100% of thetime then clearly there will be no effect of water cut on the maximum potentialcorrosion rate and hence time to failure.

Hilly terrain, changes in elevation or changes in flow direction can induce waterhold-up in wells, flowlines and process equipment. Local water cuts canexceed 50% despite input water cuts of 1% or less. The water in dips mayremain for weeks or months until an increase in throughput sweeps some of itout and a temporary increase in water production is seen at the outlet of thesystem. It is therefore unwise to rely on the formation of emulsions or similardispersions to provide fully oil wet surfaces. It is for this reason that BP ignoresthe water cut in determining system corrosivity.

CO2 corrosion rates are dependent on flow regime and flow velocity, hence theattempt to incorporate the effects of flow into the 1995 de Waard and Milliamsmodel. In uninhibited corrosion, flow effects are of secondary importance, afterthe important controlling factors such as temperature, pre s s u re, CO2concentration and pH and for this reason BP have retained the earlier de Waardand Milliams model as the basis for their CO2 modelling. The 1995 model isincluded if the sensitivity to flow velocity changes 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 the bestmethod 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 the Category ofthe corrosion risk, e.g. from 3 to 4. Velocities corresponding to C factors greaterthan 135 should not be considered unless there is significant operatingexperience 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 System andOCENSA 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 should bedesigned 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 also allowsthe 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 atmospheric pressure.The low levels of acid gases mean the potential corrosivity of the water phasewill be low.

Fully stabilised crude oil can therefore be considered as a non-corrosive productand typically such pipelines are constructed with minimal or zero corrosionallowance. When a corrosion allowance is specified, it is often due to concernsover external corrosion rather than internal attack. Corrosion inhibitor is notnormally deployed into fully stabilised crude oil lines.

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 corrosive asthe acid gases are not vented down to negligible levels and any associatedwater will be corrosive. The partial pressure of gases will depend on thepressure of final processing. For example, at 7 bara the partial pressure of CO2in an associated gas containing 2 mole% would be 0.14 bara, 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’ range isfrom 1.4 bara to 20 bara and the corrosivity of the fluids will vary accordingly,along with the CO2 concentrations, temperatures etc.

As the crude oil does not pass through tankage offshore, water cuts in partiallystabilised lines are typically higher than in fully stabilised lines. Water cuts canreach 15% or even higher if water handling is a constraint but more typical levelsare around 1%.

With the removal of the majority of the CO2 and water, partially stabilised crudeoil is significantly less corrosive than the non-stabilised multiphase fluidstransported in flowlines, but it can not be considered as non-corrosive. Theoriginal Forties 30” and existing Beatrice export lines are adequate proof thatpartially stabilised crude oil is corrosive. Such pipelines should therefore bedesigned and operated to deal with internal corrosion. Typically a corrosionallowance of 2 to 3 mm may be specified and corrosion inhibitor should beadded on a continuous basis.

It is important to note that although the pressure of the oil is raised downstreamof the crude oil shipping pumps, the partial pressure of CO2 does not increase.The crude oil is single phase and any remaining associated 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 (andstill is) common practice to dry it prior to transportation. The two most commonmethods involve either contacting the wet gas with dry glycol or passing itthrough 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 for corrosioncontrol and each system should be considered on a case by case basis.

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 at somelocation along the pipeline. Once free water is present, corrosion becomes aconcern and this must be taken into account during the design and operationalphases of the pipeline’s life. The severity of corrosion and the potential meansfor controlling it depend on the operating scenario and flow regimes.

If a wet gas pipeline is not going to be treated with a recycled hydrate inhibitor,corrosion inhibition is the only practical corrosion control method. Theapproach to design is identical to that for oil pipelines except that there is nopH buffering capacity in the condensed water in wet gas lines. This must betaken into account when performing the corrosion rate predictions.

If the flow regime is stratified or wavy, there may be a concern that corrosioninhibitor deployed into the continuous phase at the bottom of the pipe does notget transported to the top of line location. The corrosion processes occurringat the two locations are different as the transportation of water to, and

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

subsequent removal of corrosion products from the top of line location is limitedby the quantities of condensing water. There is no continuous water phase atthis location in stratified/wavy flow and water is only present via condensationon to the pipewall. Under these circumstances, the water quickly becomessaturated with corrosion products, effectively stifling further corrosion and thiscan be used to advantage in the design of wet gas pipelines.

The term top of line/bottom of line (TOL/BOL) ratio is used to describe the rateat which the top of line corrodes relative to the bottom of line, with the bottomof line rate being calculated using a standard CO2 modelling approach. ATOL/BOL ratio of 0.1 is used by BP. This does not rely on inhibitor availabilityand can therefore be assumed to occur 100% of the time. The bottom of linelocation requires inhibition and the predicted rate estimated using the availabilitymodel. The higher of the two rates will determine the required corrosionallowance.

Glycol (or methanol) is often used as the hydrate preventer on a recycled basis,although this traditional approach to hydrate control is increasingly beingreplaced by once through, low dose systems. However, recycled systems willremain valid for older systems or those operating well within the hydrateenvelope where low dose chemicals are not applicable. The use of glycol isbeneficial as it is a corrosion inhibitor, albeit a relatively poor one. If glycol isused without the addition of corrosion inhibitor, there will be some benefit fromthe glycol. This is hard to quantify but Shell’s work produced a glycol correctionfactor 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. Only theinhibitor availability factor should be used.

The use of a glycol (or methanol) recycling system offers the opportunity for analternative form of corrosion control - pH moderation. This technique has beenused by Elf since the 1970’s and works by artificially raising the pH of the waterin the pipeline to high values (circa 6.0). This limits or arrests CO2 corrosion andtherefore the pipeline can be constructed with reduced corrosion allowance.The system is economical to operate as the pH moderator, typically bicarbonateor MDEA is carried in the glycol and remains through the glycol drying process.However, the technique should only be used along with corrosion inhibition aspH moderation is not entirely successful at preventing localised corrosion. Ineffect, pH moderation 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 provide thetransport medium and to recycle the pH moderator. With the moderntrend towards once-through, low dose hydrate inhibitors many new wetgas pipelines will not have glycol recycling facilities. Once-throughdosing of pH moderator is unlikely to be economic as 2,500 ppmbicarbonate or 500 ppm MDEA may be required in the water phase toachieve the required pH shift. MDEA costs circa US$4 per kg andtherefore treating condensed water would cost circa 30 cents per barrel ona once through basis.

2. If formation water is produced along with the gas then the artificially highpH will increase the scaling tendency of the water. This can have seriousconsequences and may require the termination of the pH moderationprogramme.

Multiphase flowlines are the most arduous application for corrosion inhibitors.This mode of transporting fluids is set to increase further in BP with thedevelopment of long reach tie-backs to existing platforms and larg edevelopments on land such as Colombia and Algeria. Flowlines are an arduousapplication for corrosion inhibitors for two main reasons:

1. The fluids are unstabilised and therefore contain acid gases such as CO2at high partial pressures, along with water. In contrast, export pipelinestransport more benign fluids that have had the bulk of such corrodentsremoved.

2. The flow regimes in multiphase flowlines vary widely and the velocitiesand attendant liquid forces can reach high levels. This increasesuninhibited corrosion rates and increases the concentration of inhibitorrequired to achieve acceptably low corrosion rates.

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

Multiphase Flowlines


77

are not effective under such circumstances, particularly if there are solids orbacteria in the line and therefore corrosion rates are increased.

Corrosion rates can be controlled above 10 m/s, but at higher operating costs.Figure 24 gives a graphical representation of the affects of flow velocity oninhibited CO2 corrosion rates.

Figure 24 is only a qualitative representation and velocity is not the only criterioncontrolling the flow element of CO2 corrosion. Mixture density is also important,with denser fluids giving rise to higher corrosion rates. Higher velocities cantherefore be tolerated in systems with high GORs than in similar systems withlow GORs. It is often convenient to design using C-factors, defined in API RP14E because the erosional velocity is often the limiting velocity for flowlines.Although C-factors specifically relate to erosion and not corrosion they usefullyrepresent the forces acting on the pipewall and therefore the forces causingenhanced corrosion rates. For carbon 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 high corrosionrates and should design accordingly. The level and sophistication of corrosioncontrol and monitoring systems must reflect the potential for corrosion to occurand this in turn will depend heavily of the flow regime. This should be handledusing the approach developed for Inhibitor Availability, based on categories 1to 5. The impact of flow velocities corresponding the C factors > 100 can beconsidered as an increase in risk and the category defined on the bais ofpredicted corrosion rates changed accordingly - see Table 14.

Note that operating at C factors > 135 should only be considered where thereis sufficient operational experience in the asset to confidently state that erosionor corrosion are not occurring at unacceptable rates at C=135. C factors > 135should not be used during design but may be considered as a de-bottleneckingmeasure if successful experience has been gained. 'Successful experience' islikely to require several years of operation with at least one intelligent piginspection of the flowline after operating at close to C = 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 pig surveys(IPS) of pipelines and each individual case should be examined on merit. It isimportant to note that intelligence pigging surveys are just one element of atoolbox for the management of pipeline integrity. They are complementary tothe full range of other pipeline integrity and monitoring techniques, for example,wall thickness checks, corrosion coupons and corrosion inhibitor injectionmonitoring. It is recommended that pipelines at risk of corrosion are designedto be “piggable”, with the requirement for permanent pig traps being determinedaccording to the required frequency for operational pigging and intelligencepigging.

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

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

There are three main types of pipeline inspections which may be categorised asfollows:

❍ 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 highly sourfluids, where there is some doubt over the steel’s ability to resist HIC. In thesecircumstances it may be justified to inspect for initial laminations in the pipelinesteel. Such laminations may grow or blister during operation, and so a baselinemeasurement of such features can prove useful in assessing the integrity of thepipeline in later life. BP has not found it necessary to carry out a baseline IPSin any of its pipelines. However, there is increasing pressure on the assets fromregulators to carry out such inspections. A normally satisfactory compromise isthe Early Inspection.

An Early Inspection would be carried out 1 - 3 years after commissioning. Theobjective of this survey is to verify the absence of corrosion in a pipeline wherea new corrosion prevention strategy is being implemented, or when theoperating conditions are particularly severe. In the context of this document,pipelines in corrosion categories 4 and 5 would certainly warrant an earlyinspection. The case for a category 3 pipeline having an early inspectionshould also be considered.

An early inspection is similar to a baseline inspection, but it is carried out aftersome operating life has been accumulated. The objective of an early inspectionis to confirm that the corrosion management philosophy is operatingsatisfactorily before any significant damage occurs to the pipeline. For example,an early inspection of the Miller Gas System (sour with high CO2) was carriedout after approximately 1 year of operation and this confirmed satisfactorycorrosion management performance. The data from an early survey can be usedlater in the pipeline’s life to provide information on when the damage wasinitiated.

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 to monitorknown defects or confirm the absence of significant corrosion. Pipelines incorrosion categories 1 to 5 should all be considered for routine surveys.

Early Inspection

Routine Survey


81

Where it is feasible, it is recommended that a caliper inspection is carried out oneach new pipeline during the commissioning procedure. This will confirm thegood workmanship of the pipeline and remove concern about dents in thepipeline. Dents can pass hydrotest, but fail by fatigue later during the life of theline.

Baseline intelligence pig surveys are not generally recommended.

To determine when to first inspect a new pipeline, it is necessary to consider thecorrosion risk and the uncertainty in prediction of the corrosion rate. Threesimple principles can be used to determine when to carry out the first piginspection:

❍ It should not be before a time when one would expect to detect somecorrosion if the corrosion rate is in line with the pessimistic estimate;

❍ It should be before our pessimistic estimate of when the first failure mayoccur;

❍ 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 of methods ofincreasing sophistication, reliability calculations are suited to this type ofassessment. However, as a first pass the following simple method isrecommended:

Make an estimate of the most likely and the pessimistic corrosion rates. Theseshould be based on the corrosion model described here, taking in to account theinfluence of corrosion inhibitors (if applicable) and the likely effectiveness of theinhibitors. The probabilistic approach to corrosion monitoring can be helpfulhere, taking the P50 and P90 (or P10) corrosion rates as the most likely andpessimistic rates.

The first inspection should not be before….Calculate the time taken for the pessimistic corrosion rate to reach 1mm in depthor the detection threshold of the inspection tool being used (typically 10% ofnominal 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. For pipelinesoperating at 72% SMYS, the BP Guidelines for the assessment of corroded pipeallow a further 20% loss of the Code thickness (BP's "Transmission Pipelines toBS8010", 1st June 1992). The “BP 1st Pass” thickness is normally calculated as0.8 * 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 1st PassThickness.

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. The finalselection 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 accuracy ofeven the high resolution intelligence pigs compared with other NDT techniques,means that pigs are not well suited to the measurement of corrosion rate.Statistical techniques have been applied to pig inspection results. Howeverthese will result in a high degree of uncertainty in measured corrosion rateunless there is a reasonable period of time between inspections.

For example, the time to the next intelligence pig inspection survey could bedetermined as follows. If the defects identified in the early survey are indeedcorrosion defects, then one should carry out the next inspection when thepredicted growth exceeds the tool’s ability to confidently measure differencesin wall thickness. If an inspection tool has an accuracy of 10% of pipewallthickness then the inspection should be carried out when the estimated totalloss 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 each wallthickness 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 carry out localinspections and repairs at relatively low cost. In this instance, an inspectionprogramme can be put in place to monitor a number of the severest defects inorder to judge when repair / replacement / derating is necessary. This pointmonitoring may be used to reduce the required frequency of IPS. For offshorepipelines with significant corrosion, where inspection and repair is costly, therewill be a tendency to carry out IPS more frequently than outlined above. Itshould be understood that inspections carried out more frequently than theminimum recommended frequency may not be able to generate reliablecorrosion rate data. In these instances only with careful consideration, shouldforecasts of pipeline integrity be made from pit depth changes from inspectionto inspection. In order to avoid over-pessimism in forecasts it is important toconsider other sources of information on possible corrosion rates (e.g. corrosionmodel predictions / experiments; topsides inspection results).

Repeat InspectionIntervals


85

For oil transmission pipelines, where fluid corrosivity is being monitored on aroutine basis, the pipeline is in a reasonable condition and thought to be at lowrisk, a frequency of once every 5 years would be typical. Examples of this arethe new Forties MOL and the existing Ninian MOL, which are both subsea linesin the North Sea. When a good corrosion management track record has beenestablished, assets are tending to increase this interval. For significantly corrodedpipelines, where the pipeline is nearing the end of its life, inspections may becarried 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: topsidescorrosion, failure to meet dew point spec, water carry over into the pipeline etc.For example, BP has operated a dry gas pipeline (Gyda field in Norway) since1986, without yet requiring an intelligence pig inspection, because of the low riskof internal corrosion in this pipeline.

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

Typical InspectionIntervals


86

As stabilisation trains take fluids from the flowlines, they will naturally benefitfrom the injection of any corrosion inhibitors upstream to protect the flowlines.However, there are locations within the stabilisation units where inhibitors willnot work well and alternative means of corrosion control should be employed.Inhibitors rarely work well under low velocity or stagnant conditions, such asat the base of separators, tanks or in instrument bridles. Deposits can form insuch locations preventing inhibitors getting to the metal surface. This becomesrelevant at velocities below 1 m/s and either 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 and drygas compression. Some systems are wholly wet gas, such as Pedernales,Venezuela and the Long Term Test facility at Cusiana, Colombia. The majorityof systems are wet up to an intermediate stage of compression at which pointthe gas is dried, normally in glycol contactors at approximately 500 psi. Oncethe gas is dried, corrosion is not a major concern and a minimal corrosionallowance isnormally specified to account for periods when gas dryers operateoff-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 such asGenesis 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 knock outpot. The gas will there f o re be in equilibrium with water and hydrocarbon liquidsand there should be zero or negligible liquids present. The action of compre s s i n gthe gas will heat it, raising it above the dew-point and thereby removing anytraces of liquid water. The pipework downstream of compressors is there f o re notat risk from internal corrosion and a moderate corrosion allowance (1 - 2mm) wills u ffice to account for external corrosion. The exception is small bore instrumenttappings where the gas may cool to below its dew-point, causing corro s i o n .G reater corrosion allowances or stainless 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 below itsdew-point. This will occur some way into the cooler. If the cooler has carbonsteel tubes it is worth calculating the temperature at which this will occur as thesite of water condensation can be the location of worst case corrosion and willtherefore determine the life of the coolers. As the following example, in Table15 from one BPX asset shows, the dew-point temperature can be closer to thegas exit temperature than the entry temperature. If the entry temperature hadbeen used for the corrosion rate predictions, they would have beenunnecessarily conservative.


88

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

1. The equipment is critical as it handles flammable gas at high pressurewithin 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 mean corrosioninhibitors are unlikely to work well.

4. Inhibitor may need injecting downstream of each compressor as it may be‘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 sheets toreduce 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 its dew-point, high pressures and carbon steel construction. However, operatingexperience has shown this to not be the case as the large volumes of glycoleffectively absorb the water and inhibit corrosion. Carbon steel is therefore asatisfactory material of construction although many projects go to the expenseof internal coatings, such as epoxy phenolics, particularly for the lower sections.

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

Glycol Contactors


89

The 1995 de Waard & Milliams corrosion rate prediction model relies heavily onthe 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 sources ofsuch 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 maximum velocitiesand can therefore be used as worst case. Pipe sizes are based on several criteria,including the requirements to avoid vibration, deposition of solids, excessivepressure drop and erosion.

‘Single phase liquid lines’ refers to pipework where system pressure is forcingliquid from higher pressure vessels to lower pressure vessels, drains or tankage.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. The lowerlimit is to avoid deposition of solids. More detailed guidelines are summarisedbelow. They are only to be applied to clean fluids - allowable velocities shall bereduced 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 PhaseLiquid Lines

Table 16: MaximumVelocities in SinglePhase Liquid Lines


90

The flow velocity in pumped liquid lines is strongly dependent on pump typeand line size. Centrifugal pumps and large line sizes can handle higher liquidvelocities than reciprocating pumps and small line sizes. If the pump type isunknown, it is safer to assume a centrifugal pump for the purposes of corrosionrate calculations.

If the line size is not known, the following velocity range can be used. If theline 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 use a Cfactor of 135 for carbon steel - see p77. Velocities should not exceed 75% of the'critical flow velocity'. Critical flow in multiphase systems is analogous to sonicflow 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 at substantiallyhigher velocities - see Table 19. However, pipework to and from reciprocatingcompressors 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 GasLines


92

Corrosion modelling will give a good indication of the probability of failure ofequipment in service due to internal conditions but will not help in determiningthe economic consequences of such a failure or the operating costs involvedwith avoiding or managing such a failure. Even if corrosion models predictshort times to failure, it may be economic to plan for replacement or repair ofcarbon steel equipment late in field life rather than to invest in a more robustsolution on Day 1. Alternatively, inhibitors may be a technically feasiblesolution for process pipework but economically and logistically, protecting largenumbers of short lengths of pipework may be impractical and corrosionresistant 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 monetary valueand thereby allowing direct comparisons with capital costs. To carry outaccurate, meaningful and useful LCC’s the Materials or Project Engineer musthave:

1. An understanding of the economic factors driving the decision, such asdiscount 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 turn will bedetermined by the economic terms under which the licence was awarded.

Gathering the necessary data for accurate LCCs is a major task and a guidelinedocument 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. Insuch cases it is common to select robust materials in order to protect against arepeat of the high installation costs but there are many examples where theanswer is less clear cut. The key question is, “when is investment in corrosionresistant materials justified?”

Corrosion models clearly have an input to this but can not provide the completeanswer. Corrosion models are normally used as a materials selection tool and

Economic Tools To Use During Materials Selection


93

Location/Equipment Materials Cost MaterialType as % Selection

of Whole

taking an extreme example, if there were no consequences of a failure therewould be no justification in investing in corrosion resistant materials. Aninvestment in corrosion resistant alloys (CRAs) aims to protect against theconsequences of a failure and therefore materials selection must consider theconsequences in the decision making process. Consequences may includeeconomic, health, safety or environmental impacts or all four but in most casesall 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 selected forthe majority of the flowline is carbon steel with a suitable corrosion allowancebut it is recognised that localised failures and repairs may be required late in fieldlife.

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. Thetechnique quantifies what has been done subjectively for many years: materialsselection becomes more conservative as the consequences of a failure increase.This is the main reason corrosion resistant materials are used more extensivelydownhole and sub-sea than on land - it is not the fluids that are significantlydifferent 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. In assessingeach option, the technique allows for the possibility of failure and a probabilityis assigned to each outcome (failure or no failure). Probabilities of failure willbe higher for a carbon steel system than for an equivalent CRA system andcorrosion modelling helps to determine this. The costs of each outcome consistof :

❍ 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). Thecosts associated with each outcome are multiplied by their probability toproduce 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 CO2 CorrosionEngineering in Wet Natural Gas Pipelines", Corrosion, 47 (1991) 976

2. C de Waard, U Lotz, "Prediction of CO2 Corrosion of Carbon Steel", NACECorrosion 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 and EngineeringChemistry, 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 and Corrosionin Forties", Sunbury Report No PEB/122/89, dated December 1989

9. J E Oddo, M B Tomson, "Simplified Calculation of CaCO3 Saturation atHigh Temperatures and Pressures in Brine Solutions", J of PetroleumTechnology, 34 (1982) 1583

10. L A Rogers, M B Tomson, "Saturation Index Predicts Brine's Scale-FormingTendency", 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", NACE Corrosion95, Orlando, paper 121

REFERENCES

96

13. J J Carroll, J D Slupsky, A E Mather, "The Solubility of Carbon Dioxidein 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 above 100°Cin 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 in NaClSolutions 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 Report No.ESR.97.ER.005, 10th Jnauary 1997

18. D Vedapuri "Studies on Oil-Water Flow in Inclined Systems" April 1997Progress Report, Section 9. Ohio University Multiphase Flow andCorrosion Project.

19. A J McMahon and S Groves, "Corrosion Inhibitor Guidelines: A PracticalGuide to the Selection and Deployment of Corrosion Inhibitors in Oiland Gas Production Facilities", BP Sunbury Report No. ESR.95.ER.050,April 1995

97

Installation of the Cassandra 98 ExcelWorkbook

The Cassandra 98 work book was written in Microsoft Excel for Windows 95,version 7.0a. It may not run in earlier versions of Excel.

If for any reason this does not succeed, try the ‘Manual Installation’ proceduredescribed 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 that theycan be referred to easily during the loading process. The instructions must befollowed precisely to ensure that the installation is successful. It is suggestedthat ‘Windows Explorer’ or ‘File Manager’ be used for sections 1 to 3 below.

1. Copy the Xlph folder into the root directory of the C: drive. This shouldgive 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 the Desktop,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

us50099_1

Documents

api rp 14e

mass transfer

monte carlo

initial dose

preferential

life cycle

corrected

sectional