03 corrosion monitoring guidelines

Main CDContents

CorrosionMonitoringGuidelinesA summary of practicalsteps for successfulcorrosion monitoring inoil and gastransportation facilities

S Webster, R Woollam

Sunbury Report No. ESR.95.055dated November 1996

Summary 1

Acknowledgements 3

Introduction to Corrosion Monitoring 5

Background 5Elements of a Corrosion Control Strategy 6What are Corrosion Monitoring Methods? 6The Economics of Corrosion Monitoring 8

General Guidelines 11

Selection of a Corrosion Monitoring Location and Technique 11Design of Corrosion Monitoring Location 17Process Monitoring 20Data Handling 21Side-stream Monitoring 25

Corrosion Monitoring: A System by System Approach 27

Background 27Sea Water Injection Systems 27Flow Lines (oil, water and gas) 29Oil Export Lines 31

References 35

Appendix 1: Monitoring Technique Definitions 37

Appendix 2: Conversion of Units 39

Contents

1

Lower cost materials are the natural economic choice for oil and gasproduction and transportation facilities. Unfortunately these materials(e.g. carbon steel, low alloy steels) in general have a low resistance tocorrosion. Therefore, the corrosion risks of these materials have to beproactively managed. To this end BPX have developed andimplemented corrosion control strategies which integrate corrosionmonitoring and inspection with risk assessment and corrosion control.

The application of corrosion monitoring as part of a corrosion controlstrategy is complex and often becomes the responsibility of engineerswho are not experts in the field. These guidelines are a synopsis ofthe more thorough Corrosion Monitoring Manual* that has beendeveloped as an aide to those designing and operating a corrosionmonitoring system. The guidelines supplement the BP recommendedpractice RP 6-1 and give a broad overview of corrosion monitoringrequirements by providing practical information and advice based onrecent operational experience which will aid any operator concernedwith corrosion monitoring. The guidelines address:

❍ Choice of monitoring location/orientation

❍ Choice of monitoring methods

❍ Application of the various methods

Other complementary procedures such as inspection or intelligencepigging are outside the scope of these documents but are covered inthe BP standard RP32-4

Many of the principles and concepts given here are also relevant toprocessing facilities such as glycol and amine gas treatment systems,although these cases are not dealt with specifically.

* S Webster, R. Woollam, “Corrosion Monitoring Manual: AComprehensive Guide to Corrosion Monitoring in Oil and GasProduction and Transportation Systems”, Sunbury. Report No.ESR.95.ER053. Dated November 1996.

Summary

The authors would like to thank,

❍ BP staff who helped in useful discussions

❍ suppliers who provided information and photographs

❍ Drew McMahon (ESS Sunbury) for editorial assistance

Acknowledgements

3

A 1988 survey revealed that BP transports 80% of its cash flowthrough facilities that are over 15 years old [1]. The integrity of suchfacilities is vital to the successful and profitable operation of theCompany and the prevention of environmentally sensitive incidents.Although BP has a first class record in environmental protection,major pipeline repairs and replacements alone have cost BP around$250 million over the past 5 years. A recent survey [2] of BPX’scorrosion costs in the North Sea estimated that corrosion accounts forover 10% of the lifting costs per barrel of oil.

Lower cost materials are the natural economic choice for oil and gasproduction and transportation facilities. Unfortunately these materials(e.g. carbon steel, low alloy steels) in general have a low resistance tocorrosion. Therefore, the corrosion risks of these materials have to bemanaged proactively. To this end BPX have developed andimplemented corrosion control strategies which integrate corrosionmonitoring and inspection with risk assessment and corrosion control.

The aim of corrosion monitoring is primarily to ensure that the designlife is not being adversely affected or compromised and also toincrease the safe and economic operational life of a facility (Figure 1).

Introduction to Corrosion Monitoring

5

Background

Figure 1: The Aims ofCorrosion Monitoring

CorrosionMonitoring

Inspection

On-lineMonitoring

ProcessStream

Analysis

PredictiveModels

OperationalHistory

Health&

Safety

PlantIntegrity

& Operation

LifeExtension

LifeAssurance

FutureOperationalConditions

INTRODUCTION TO CORROSION MONITORING

6

These guidelines give practical advice on the essential steps requiredto achieve effective corrosion monitoring and details of practicalexperience are given in the highlighted boxes.

There are three main components in the development andimplementation of the BPX corrosion control strategies (Figure 2).

All of the above activities (risk assessment[3,4], corrosion control,inspection and monitoring) are interdependent . Results fromcorrosion monitoring and inspection must be used to re-evaluate andmodify, where necessary, the risk and criticality assessment and anycontrol procedures.

This report focuses on the corrosion monitoring elements in acorrosion control strategy.

When undertaking corrosion monitoring it is important not to rely onjust one method. The best results are obtained by using a range ofmethods. Corrosion monitoring in this context can be defined as:

Elements of a Corrosion Control Strategy

Figure 2: A Schematic of theInter-Relationships in aCorrosion Control Strategy.

Risk / CriticalityAssessment

ControlProcedures

Inspection andMonitoring

What are Corrosion Monitoring Methods?

The main methods fall into the following categories:

❍ Inspection

❍ On-line corrosion monitoring

❍ Analysis of process streams

❍ Operational history assessment

Historically, corrosion monitoring and process data analyses wereperceived as quite separate from inspection activities. Althoughinspection has been historically concerned with mechanical integrity,many inspection methods can be used as corrosion monitoring toolsand supplement corrosion monitoring methods. The complementarynature of these approaches is summarised in Figure 3.


7

\

The use of any method that enables an operator toestimate or measure the corrosion rate occurring in anitem of plant, or the corrosivity of a process stream.

Figure 3: Classificationof Currently AvailableInspection andMonitoring Techniques

Ultr

ason

ics

✓✓

✓✓

✓✓

✓✓

✓ ✓ ✓ ✓ ✓ ✓ ✓✗ ✓ ✓ ✗ ✗ ✗ ✗

Vis

ual

Insp

ectio

n

Rad

iogr

aphy

Fle

xibl

e U

TM

ats

Cou

pons

Fie

ld S

igna

ture

Met

hod

(FS

M)

Aut

o U

T

Ele

ctric

alR

esis

tanc

e P

robe

s

Che

mic

al A

naly

sis

Line

ar P

olar

isat

ion

Res

ista

nce

Ele

ctro

chem

ical

Noi

seLarge time interval between readingsNon-destructiveDirect measure of material lossLow sensitivityHigh accuracy / reliabilityLagging indicator

➚

➚

➚

➚

➚

➚

Small time interval between readingDestructive (probes / consumables)Indirect measure of material lossHigh sensitivityLower accuracy / reliabilityLeading indicator

➚

➚

➚

➚

➚

➚

UniformCorrosionLocalisedCorrosion

Notes: (a) the position of a technique in the table does not relateto its exact position along the arrows

(b) Flexible UT mats maximum temperature is 120°C

For any corrosion monitoring/inspection programme to be fullyeffective it is vital that all of the above information can be accessedcentrally and compared with each other. This can be achieved byensuring full access to all databases which hold the relevantinformation and having the right software to conduct the relevantcorrelational analysis.

In general the purpose of corrosion monitoring is to optimisecorrosion mitigation/repair/replacement activities such that anoptimum between corrosion control and replacement costs isachieved. It should be noted that there may be additional costconsiderations related to safety, environmental and productionimpacts which are NOT considered in the following.

A given corrosion monitoring method or technique has only a limitedaccuracy and therefore, each corrosion rate determination has arandom error associated with it. This random error can only bereduced by increasing the amount of corrosion monitoring undertakenbut this increase in corrosion monitoring activity will increase the costof the activity. For an optimal corrosion monitoring programme thebenefit obtained should be greater than the cost incurred.

For corrosion inhibitor optimisation there is a trade-off betweenreplacement costs and corrosion inhibition cost (Figure 4a) whichresults in an operational minimum of the sum of the corrosioninhibition costs and the pipeline replacement costs. In order todetermine the optimum corrosion inhibitor injection rate, thecorrosion rate for the system needs to be determined. The corrosionrate will determine if the corrosion inhibitor injection rate is effective,if it needs adjustment (up or down), or if some alternative means ofcontrol is required (e.g. corrosion resistant alloys, CRAs).

Figure 4b shows the increasing confidence and reduction in error indetermining the corrosion rate as the number of corrosion ratemeasurements is increased.

Figure 4c shows the increasing cost of corrosion monitoring as thenumber of measurements increases versus the incremental benefitfrom corrosion inhibitor optimisation.


8

The Economics of Corrosion Monitoring

Figure 4c clearly shows the point at which no additional corrosionmonitoring is warranted as the incremental savings from corrosioninhibitor optimisation are less than the cost of the monitoringprogram. The cross-over of the two curves indicates the level ofcorrosion monitoring required to optimise the overall cost structure.

This approach can be generalised to other corrosion mitigationmethodologies and the monitoring of these systems. In general thereis an optimum amount of corrosion monitoring in a system abovewhich the costs of monitoring exceed any savings generated.

9


Corrosion Rate Spread with # Locations

Corrosion Rate, mpy

0 5 10 15 20 25 30 35 40 45 50

50

10

5

2

Total Pv

∆ CR with #

100

20

Total Cost: CI and Replacement

Corrosion Rate, mpy

0 5 10 15 20 25 30 35 40 45 50

Replacement cost

Inhibition cost

Total Cost

Figure 4a Shows theTrade-off BetweenReplacement Costs andInhibition Costs.

Figure 4b Shows theIncreasing Confidenceand Reduction in Error,in Determining theCorrosion Rate as theNumber of CorrosionRate Measurements isIncreased.

10

Monitoring Method Hardware Probe Man-hour costs

Weight Loss Coupons None £300 Coupon insertion and retrieval. Coupon analysis

Electrical Resistance £1500 £500 Probe insertion and Probes retrieval. Data analysis

Electrical Resistance £25000 £1000 Probe insertion and Sand Monitor retrieval. Data analysis

FSM (Topsides) £30000 - Data analysis

FSM (subsea) £250000 - Data analysis

LPR £1500 £300 Probe insertion and retrieval. Data analysis

Electrochemical Noise >£2500 £300 Probe insertion and retrieval. Detailed data analysis. Very time consuming

Flexible UT mats >£2500 £300-600 Data analysis

Table 1: Outline Costs forVarious Corrosion MonitoringTechniques based on 1995information (£1=$1.6).

Table 1 gives outline costs for various corrosion monitoringtechniques. This table is a guide to the relative costs of eachtechnique (hardware) and any operational costs associated withinstallation and data analysis. The costs will vary depending uponasset location and number of monitoring locations. However, thesefigures will aid the costing of monitoring/inspection activities.


Cost/Benefit of Monitoring

Log (Number of Locations)0 0.5 1 1.5 2 2.5 3 3.5 4

Cost/Benefit of Monitoring

Cost of Monitoring Program per Year

Pre

sent

Val

ue ($

)

Figure 4c The Increasing Costof Corrosion Monitoring as theNumber of MeasurementsIncreases.

Costs

11

The selection of the monitoring location and method are critical tasksfor successful corrosion monitoring. It cannot be stressed enough thatselection of the wrong location or method will result in a largeamount of effort and expense only to generate inappropriate or evenmisleading information.

In many cases incorrect selection is worse than no selection as thequality of data are often not questioned once they have beencollected.

Physical access is important but should not dictate monitoringlocation. However, when a monitoring point is identified the positionshould allow routine access for probe maintenance, retrieval etc.

General Guidelines

Selection of a Corrosion Monitoring Location and Method

Introduction

Incorrect selection of location or method is worse than noselection.

All corrosion monitoring (and inspection) locations and methodsshould be recorded on the relevant technical drawings. This shouldinclude process flow diagrams, process and instrumentation diagrams(P&ID’s) and the isometric diagrams. On new facilities they should beincluded in the Computer Aided Design (CAD) system as this aidsdata analysis and the development of control procedures. The recordsshould include not only details on the system, item and location, butalso the method and probe orientation.

There are no fixed rules on how to select a corrosion monitoringlocation or method but the first step must be to decide what corrosionmechanisms need to be monitored. Experience has shown that thefollowing approaches are of value.

❍ Best practice

Experience at other assets utilising similar facilities or in thecurrent asset can provide valuable information not only on thelocations likely to experience corrosion but on the choice ofsuitable method.

12

This section outlines the main points that should be considered whenidentifying a corrosion monitoring location, and are summarised inFigure 5.

Corrosion monitoring in a sulphide-containing producedwater line.

Corrosion monitoring was undertaken using a flush mountedlinear polarisation resistance (LPR) probe via a bottom of lineaccess fitting. The monitoring programme yielded anexponentially increasing corrosion rate with time. Most likely theprobe response reflected the shorting out of the probe elements dueto the formation of a conducting sulphide film. A more reliableapproach may have been to substitute the LPR probe with a flushmounted electrical resistance (ER) probe in the same location.

Selection of a CorrosionMonitoring Location

❍ Networking

A wide range of engineering disciplines should be contacted toobtain a full picture of current and potential future problems.

Two examples from recent BP operations are given here and highlightwhere inappropriate selection of the monitoring location or methodcaused problems.

GENERAL GUIDELINES

Corrosion monitoring in a main oil export line with watercut below 1%.

Corrosion monitoring was undertaken using an intrusiveelectrical resistance probe via a top of the line access fitting. Lowcorrosion rates were observed which appeared to be insensitive toprocess changes. In this case the probe response was most likelyreflecting the corrosivity of the continuous hydrocarbon phaseand not that of the aqueous phase which constituted thecorrosion hazard. A more reliable approach may well have beento have used a flush mounted electrical resistance probe via anaccess fitting located at the bottom of line where water separates.

13

Full details of each factor are given in the Corrosion MonitoringManual.

The inspection or monitoring method must be chosen to provide rateinformation appropriate to the particular corrosion process(es).Consideration of the corrosion environment is important as this willoften preclude many methods (e.g. electrochemical methods are notsuitable in low water cut or low conductivity situations).Consideration of the corrosion mechanism (general, pitting, crackingetc.) is also important as this will give an insight into the monitoringmethod most suitable (e.g. pitting most easily detected using weightloss coupons) and eliminate many unsuitable methods. The Corrosion

GENERAL GUIDELINES

Figure 5: A Check Listfor Identifying aCorrosion MonitoringLocation

Single or multiphase flow

Corrosion rate of each phase

Mechanism/mode of attack

Upstream/downstream effects

Localised effects

Low alloy probe in CRA line

Identify process changes in system

Location reflect most corrosive situation

Should not dictate locations

Flow diagram processand instrument diagrams etc.

Orientationof pipework?

Location of chemicalinjection points

Environment indicativeof corrosion elsewhere

Process changes

Physical access

Record locations

What is the majorcorrosion mechanismand mode of attack ?

Prior elevation changes

Water drop out

Other pipeline entrants

Position of other pieces of equipment

Corrosivity of injected chemical

Corrosion MonitoringMethod Selection

14

Monitoring Manual gives a detailed critique of each method coveringinstrumentation, data analysis and the relative advantages anddisadvantages. The economics of applying any of the methods mustbe considered because the economic benefit must exceed the cost ofthe activity.

A schematic for selecting the most appropriate corrosion monitoringmethod(s) is presented in Figure 6. A simple definition of eachtechnique is given in Appendix 1.

There are no fixed rules on which methods are most suited for agiven system (i.e. water injection system, crude oil flow lines etc.) asthe conditions in each will vary. However, Table 2 gives a generalguide to the possible application of the various monitoring methodson a system by system approach.

When selecting a monitoring method it must be realised that eachmethod gives only a limited amount of information. It is goodpractice to use a selection of methods to give confidence in theresults. The first choice must always be inspection-based methods asthey are very reliable for integrity assurance. This can then besupported by probe-based methods. If only one probe based methodcan be used then the first choice should be weight loss coupons asthis method gives both general and localised information.

The utility of inspection based methods is tempered by the fact thatthey are “lagging” indicators of corrosion. If inspection data says thesituation is bad then it may be too late to do anything about itbecause the damage has already been done. Monitoring methods are“leading” indicators of corrosion. They show the corrosivity at aparticular moment, potentially before any significant damage hasoccurred. Hence, monitoring methods are always a valuablecomplement to inspection methods.

GENERAL GUIDELINES

15

GENERAL GUIDELINES

Figure 6: Schematic forSelecting a CorrosionMonitoring Method

16

GENERAL GUIDELINES

Dep

ends

on

wat

er q

ualit

y. L

PR

uns

uita

ble

whe

re th

ere

is a

low

ion

cont

ent o

r a

stro

ng s

calin

g te

nden

cy (

or o

ther

form

of e

lect

rode

con

tam

inat

ion

is p

ossi

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.

May

be

used

whe

re o

xyge

n co

nten

t is

high

.

Onl

y in

wat

er c

uts

abov

e ca

. 10%

-20%

.

Dep

ends

on

wat

er q

ualit

y. L

PR

uns

uita

ble

whe

re b

iofil

min

g te

nden

cy.

Intr

usiv

e pr

obe

pref

ered

. Flu

sh m

ount

ed u

nsui

tabl

e w

here

bio

film

ing

tend

ency

.

Max

imum

tem

pera

ture

120

°C

May

be

usef

ul fo

r co

nden

sed

wat

er in

wet

gas

exp

ort l

ine

✓ ✓✓ ✓

✓ ✓✓

✓✓

✓✓

✓✗

✗

✗

Bacterial Monitoring✗✗✗

✗✗✓

✗✓

✓✗

✓

✗✓

✗✓

✗

✓

✗✓

✗

✓✗ ✓

✗✓

✗

✓✗

✓✗

✓

✗

✓

✗✓ ✓ ✓ ✓

✓ ✓ ✓ ✓ ✓

✓ ✓ ✓ ✓ ✓✗✗

✗✓ ✗

1

2

O2,

CI 2

CO

2,H

2S

H2S

CO

2,H

2S

O2,

H2S

✓3

Electrical ResistanceProbes

Weight Loss Coupons /Spool Pieces

Corrosion ProductAnalysis

Galvanic Probes

ElectrochemicalProbes

Suspended Solids

Dissolved Solids

Dissolved Gases

pH

Hydrogen Probes / Patch

Sea

wat

er In

ject

ion

Flo

w L

ines

(oi

l, w

ater

, gas

)

Aqu

ifer W

ater

Uns

tabi

lised

Cru

de O

il

Hyd

roca

rbon

Gas

Effl

uent

Wat

er

Sto

rage

Ves

sels

with

Sep

arat

ed W

ater

Bot

tom

1 2 3

Flexible UT mats

✓✓ ✓ ✓ ✓ ✓ ✓

4 5

54

6

6

7

7

CO

2,H

2S

✓✓ ✓ ✓ ✓ ✓ ✓

Field Signature Method

Table 2: A GeneralGuide to the Applicationof Corrosion MonitoringTechniques

17

GENERAL GUIDELINES

For operating pressures 10-137 bar(g) (i.e. 150-2000 psig) the insertionof probes and coupons into pipework and facilities without the needfor plant shutdown relies on the use of proprietary 2 inch accessfittings. Access fittings are usually installed at the construction phaseor during plant shutdown. Therefore, it is important that thecorrosion monitoring requirements are well thought out at the designstage otherwise subsequent installation will be difficult and costly.Access fittings can be installed during plant operations using a hot tapbut in many circumstances safety requirements will preclude suchactivity.

The BP recommended practice RP6-1 gives a thorough overview ofaccess fittings and retrieval tools[5]. However, the following pointsshould also be considered.

❍ Orientation of access fitting

The anticipated location of the corrosion attack should dictatelocation of the fitting. If corrosion is occurring at the bottom ofline (e.g. wet oil, wet gas) then the access fitting should belocated in this position. This will also minimise probe lengthand so reduce the possibility of probe fatigue failure and makethe line easier to pig. The bottom of line location can causeproblems with accumulation of debris and the possible galling ofthe threads. However, modern access fittings or improvedretrieval procedures can minimise these effects. The accessorientation is less critical for a single phase water stream sinceall parts of the pipewall will experience the same environment.

BPX Norway have developed a procedure to minimise theeffect of debris build up on bottom of line location usingstandard access fittings [6]. This involves backpressurising the retrieval tool so that any debris ispushed back into the line. This procedure has been usedon Ula since 1986 without any problems.

Retaining adequate clearance for the retrieval tool is important whenlocating an access fitting. RP 6-1 gives full details on the clearancerequired for different retrieval tools. However, clearance alone shouldnot dictate location or orientation. The position must also be capableof providing useful corrosion information.

Design of Corrosion Monitoring Location

Access Fittings

18

GENERAL GUIDELINES

❍ Access fitting and sampling point design

All access fittings should be fitted with heavy duty covers toprotect the fitting threads and electrical connections fromdamage. The cover should be fitted with bleed plugs (orpossibly a pressure gauge) so that leaks between the accessfitting body and the monitoring device can be easily identified.The design should not allow the probe to be inserted back-to-front.

Sample points for the collection of process fluids should includetwo isolating valves in series, one of which should be a needlevalve. Details are given in RP 42-1 [7].

❍ Material selection

Access fitting material should conform to the requirements of thepiping specification. Austenitic stainless steels are usuallyspecified and are suitable for most duties.

Recent experience at a refinery has highlighted theimportance of material selection. A 316 stainless steelprobe holder on a Crude Distillation Unit top pump-around-circuit suffered chloride stress corrosion crackingin service leading to a hydrocarbon leak and a serious“near miss”. The incident report recommended that allfuture fittings should be constructed from Hastelloy forthis application in which chloride ion concentration andlow pH put conventional austenitic stainless steels at risk .

It is also important that any seals associated with the probeassembly should have satisfactory performance under theoperating conditions[8].

❍ Trap-type monitoring point

In low water cut situations some operators have adopted the use ofwater traps. These traps act as a sink for water drop-out and allowconventional monitoring methods to be employed. The trap canalso promote bacterial action. The design of the trap should includeappropriate isolation to allow accumulated water to be drawn off(full details are given in the Corrosion Monitoring Manual). Trapscan become potential corrosion sites by acting as a dead leg andtheir use is not recommended.

Probes and coupons fall into two main categories:Probe Configuration

19

GENERAL GUIDELINES

❍ Flush mounted

These are designed to be positioned so that the probe elementis flush with the inside pipe wall.

❍ Intrusive

These probes protrude well into the process stream and aresuited for measuring the overall corrosivity of a process stream.

There is no generalisation as to which of these probe configurations ismost appropriate for corrosion monitoring. The choice will dependon the information required and whether the line is pigged.

Before embarking on a detailed corrosion monitoring programme it isimportant to ensure that the type of monitoring method is reliable andhas adequate response to changes in the conditions being monitored.

This aspect is often overlooked when undertaking routine monitoring.If data validation has not been undertaken, corrosion monitoring datacan actually be misleading. This can lead to complacency in corrosioncontrol, unnecessary modification of control methods, or changes tooperational parameters being made. Increasing probe corrosion rate isusually a warning of increasing corrosivity but a low probe corrosionrate is not a guarantee that a system is under control.

Validation of MonitoringMethod Response

A lack of probe response has often been interpreted as asign of good control rather than a sign of poorpositioning/choice of the monitoring methods

A recent corrosion survey [9] of a sea water injectionsystem showed good oxygen and free chlorine controlaccording to the on-line dissolved gas monitors. However,when the responses of the on-line monitors were checkedagainst proprietary chemical kits the levels of dissolvedgases were found to be an order of magnitude higher thanexpected. Also the probes took hours to respond toinstantaneous changes in dissolved gas levels. It wasfound that the probes were fouled and needed morefrequent maintenance.

For any monitoring programme, control checks must be included toensure the reliability of the data. Changing the corrosivity of thesystem, to validate the monitoring method should only be undertakenonce the full risks of the operation have been identified.

20

GENERAL GUIDELINES

API RP 38 Recommended Practice for Biological Analysisof Subsurface Injection Waters.

API RP 45 Recommended Practice for Analysis of OilfieldWaters

NACE RP 0173 Recommended Practice: Collection andIdentification of Corrosion Products

NACE RP 0192 Recommended Practice: Monitoring Corrosionin Oil and Gas Production with Iron Counts

Process Monitoring

Background Process monitoring is a key aspect of any corrosion monitoringprogramme and covers a wide range of activities including but notlimited to the following:

❍ Measurements of standard process data (temperature, pressure,flow rates, water cuts etc.)

❍ Chemical analysis of the process streams (dissolved ions,bacterial levels, suspended solids, dissolved gases etc.)

❍ Chemical analysis of corrosion products.

❍ Details of production engineering activities (workovers,acidisations etc.)

❍ Monitoring the addition of production chemicals.

All of the above activities can have a major impact on corrosivity.Process monitoring is essential in predicting potential corrosivity andin the interpretation of corrosion monitoring data in order to indicateif the inspection/monitoring programme is still relevant to currentoperating conditions.

Process monitoring measurements can be made either on-line or bysamples taken at regular intervals.

There are standard procedures available for most of the methods, thedetails of which are outside the scope of this document and are listedbelow. Full details of these activities are also given in thecomplementary Corrosion Monitoring Manual.

21

GENERAL GUIDELINES

The application of process monitoring data is important if the fullvalue of the data is to be realised. Typically the data will be used toassess corrosion rates indirectly (iron counts or laboratory corrosivitymeasurements of field samples) or be used to predict potentialcorrosivity from a detailed knowledge of the corrosion processes. Thelatter approach is extremely valuable as it enables an operator topredict changes in worst case corrosion rates and modify anymonitoring/inspection activities or control procedures beforesignificant damage has occurred. Figure 7 gives a broad summary ofthe use of process monitoring data.

Application of ProcessMonitoring Data

Data Handling

The Figure below is from the BP Magnus platform in theNorth Sea. A number of production vessels on theinstallation are sandwashed every day. It was assumedthat all the water was routed out from the vessels via thedrains. The fluid corrosivity graphs for the main-oil-line(MOL) generally showed a low value, however, highcorrosion “spikes” were appearing every day. Comparingthe times of these “spikes” with process conditionsrevealed that some of the sandwash water was in factgoing down the MOL and increasing the corrosion. Bydoubling the corrosion inhibitor injection rate into theMOL during sandwashing, the “spikes” on the probeoutput disappeared and the normal low corrosion ratecould be maintained.

The methods used to analyse corrosion monitoring data will dependupon the number, location and variation in monitoring methodsemployed. For effective corrosion monitoring and control it is vitalthat all of the relevant data can be accessed easily, cross referencedand analysed. Typically in any production operation the data will beheld on different databases and in a variety of formats (database orpaper files). Therefore, it is important to set up the relevant

0.00

0.02

0.04

0.06

0.08

0.10

Corrosion Peaks Related to Sand Washing

Days

Cor

rosi

vity

(m

m/y

r)

22

GENERAL GUIDELINES

Figure 7: The Use ofProcess Monitoring Datato Predict Corrosion

Risk

MIC

O2

O2

H2S

CO2

System

Oil & Gas Systems

Injection Water

Sea Water

Oil & Gas Systems

Oil & Gas Systems

Process Parameter Model

12

34

5

678

9

10

11

C de Waard et. al., Prediction of CO2 Corrosion of Carbon Steel, NACE 93, Paper 69 1993J L Crolet, "Cormed Lotus 123 Spread Sheet for Calculating pH of Produced Waters" Elf Aquitane-SNEA (P)Copyright 1988, 1990pH predictionJ Pattinson et. al., A Corrosion Philosophy for the Transport of Wet Hydrocarbon Gas Containing CO2,ESR. 93. ER016J Pattinson et.al., A Corrosion Philosophy for the Transport of Wet Oil and Multiphase Fluids Containing CO2,ESR. 93.ER013J Pattinson, Erosion Guidelines, ESR.94. ER070NACE MR-0175J Martin, Guidelines for Selecting Downhole Tubular Materials with Particular Reference to Sour Conditions,ESR. 94.ER043Oldfield et.al., Corrosion of Metals in Dearated Seawater, BSE-NACE Corrosion Conference, Bahrain,Jan 19-21 81J T A Smith, Minimising Corrosion of Carbon Steel in Sea Water Injection Systems - Guidelines for Water Quality,ESR. 94.005I Vance, Microbiologically Influenced Corrosion (MIC) in Oil Production Operations, Topical report No 8615 1993

Microbiologically InfluencedCorrosion Review (11)

Oldfield &Todd (9)

Design Guidelines - Sea Water Injection (10) - Material Selection (8)

NACE MR-0175 (7)

Cormed (2)

Design Guidelines - Material Selection (8)

de Waard & Milliams (1)Cormed (2)pH Calc (3)Design Guidelines - Wet Gas (4) - Wet Oil (5) - Erosion (6)

TemperaturePressureFlow RegimeFlow RateCO2 mol %H2S mol %Water ChemistrypHSolidsCorrosionInhibitor - dose rate - deployment

TemperaturePressureCO2 mol %H2S mol %Water ChemistrypH

TemperaturePressureFlow RateO2Free CI2BiocideOxygen ScavengerpHWater Chemistry

TemperaturePressureSessile Bacteria CountPlanktonic Bacteria CountspHWater Chemistry

23

GENERAL GUIDELINES

communication networks to ensure the data are readily accessible.For example, BP Alaska have usefully integrated their corrosion andproduction databases.

BPX Alaska are now using a Corrosion Analysis TrackingSystem (CATS). This computer system can store multi-giga-bytes of data from literally thousands of corrosionmeasurements and inspections in the field. The databaseis helping Inspectors, Corrosion Engineers and others todevelop a systematic, comprehensive approach to locatingcorrosion, analysing the best treatment strategies, andmonitoring corrosion chemical treatments to verify theireffectiveness.

There are several proprietary packages which can be used to assistwith this type of activity. These packages are essentially databaseswhich store, manipulate and analyse the data to:

❍ generate monitoring and inspection reports❍ generate inspection schemes, workscopes and plans❍ demonstrate integrity status for certification purposes.

The main limitation with this type of package is the time taken toinput the data into the system and the lack of flexibility. However,such systems have the capability to become the main corrosiondatabase for all the monitoring data e.g. CORTRAN (CORrosion TRendANalysis). CORTRAN is currently used by two inspection contractorsinvolved in the integrity management of the BP offshore assets in theUK sector of the North Sea [10].

Another approach is to access all the databases and extract therelevant information needed. This can be a time consuming task ifundertaken manually and impacts on the effectiveness of anymonitoring programme.

Wytch Farm has developed a user friendly front end totheir distributed control system [11]. This system forms themanagement information system which archives anddisplays all site data for unlimited periods of time. It alsohas its own programming language which allows the userto develop high level applications e.g. energy monitoringor corrosion monitoring. The system also allows manualinput of data such as the addition of laboratory reportsor production engineering reports.

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GENERAL GUIDELINES

Another proprietary data handling and analysis package available isMentor [12]. This system has been developed for condition monitoringand has now been expanded to include corrosion monitoringinformation. The system can interrogate data from the distributedcontrol system as well as allow data input manually. The software issuch that the data can easily be compared from different databasesand alarm levels set to alert an operator to potential changes incorrosivity. A “Mentor” system was installed on the Magnus asset in1995.

For effective analysis the following information is required:

1. Process data: Usually available from a central database. Thisinformation involves both on-line and off-line data. These datashould be supplemented by:

❍ Laboratory analysis❍ Production engineering reports detailing

- well shut-ins- acid stimulations- wireline activities- sand production - well workovers

2. Corrosion monitoring data: Should include all the on-linedata as well as the data collected manually (coupons etc.).These data should be stored in a format which enablescomparison with the process data.

3. Inspection data: Should include the routine inspection reportsand data from specialised surveys. Again, the data should be ina format which is comparable with the process and monitoringdata.

The presentation of data is also important. The type of report isdependent upon the activity and the scope of the work. Recentlysome operators have started to use the CAD drawings as an aid topresenting the corrosion and integrity data. This approach is veryeffective in identifying areas of concern and predicting potentiallocations of corrosion.

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Side-stream monitoring is considered as a supplement to on-linecorrosion monitoring. In this approach some of the process fluids arediverted from the facility into a temporary section of pipeworkcontaining the corrosion monitoring probes. The fluids then re-enterthe main process fluids or are collected for disposal later. Thisapproach allows the flow rates to be modified and chemicaltreatments to be investigated without any major changes inproduction. Side-streams have been used extensively to study inhibitorperformance. Although the use of side-streams appears to be usefulthere are several inherent problems associated with their use. Theseare:

❍ The sampled fluids may not be representative of the processfluids.

❍ The side-stream may not simulate the correct flow regime for agiven flow rate.

❍ Side-streams tend to form well mixed fluids in low water cutsituations therefore forming emulsions and preventing waterseparation.

❍ Temperature and pressure in the side-stream may not berepresentative of process stream.

In summary, side-streams should be used with caution and shouldnever be used as a primary corrosion monitoring tool. Experience hasshown them to be most effective on single phase systems (e.g. waterinjection flow lines). Any results obtained should be compared tofield experience before reliance is placed on them.

GENERAL GUIDELINES

BP Alaska used a side stream device to assess theperformance of biocide in the sea water injection system.Biocide was terminated, based in part on the side streamdata. Corrosion rates subsequently increased byapproximately two orders of magnitude. Biocide was thenrestarted but even after 2 years it had not reduced thecorrosion rates back to their previous levels

Side-stream Monitoring

27

This section serves to give examples of how the various monitoringmethods and approaches can be applied to give comprehensive coverwithin an oil and gas production facility. These are only examplesand in practice the monitoring system required may be quite differentdepending on the site specific conditions.

Corrosion monitoring in sea water injection systems should be verysimple (i.e. aqueous and single phase) but is quite complex inpractice. Guidelines have been issued on corrosion control methods[12]. Figure 8 summarises the basic corrosion monitoring required fora sea water system.

The main corrosion mechanism is oxygen induced corrosion. Thisdepends on the dissolved oxygen concentration, flow rate andtemperature. Microbially induced corrosion (MIC) is also possible.The activity of aerobic bacteria will be reduced by effective oxygencontrol. However, sulphate reducing bacteria (SRB) are anaerobic andwill require an efficient biociding regime. Other production chemicalsadded to the sea water also contribute to the overall corrosivity,

❍ Oxygen scavenger: This chemical is added to remove residualoxygen but can itself be corrosive if over-dosed.

Corrosion Monitoring: A System by System Approach

Background

Sea Water Injection System

Figure 8 CorrosionMonitoring Requirementsfor a Sea Water InjectionSystem.

System Monitoring

a) Flexible UT mats: Maximum operating temperature 120°Cb) Depends on water quality. LPR unsuitable where biofilming tendency

Sea WaterInjection systems

Corrosion Monitoring- Weight loss coupons- Electrical resistance methods

- intrusive probe type- Flexible UT matsa/auto UT- Electrochemical methodsb

- intrusive probe type

Process stream Monitoring- Flow rate- Temperature- Pressure- Iron counts- Dissolved oxygen (<50ppb)

- on-line, colorimetric- Free chlorine (<0.2ppm)

- on-line, colorimetric- Oxygen scavenger

- dose rate, residual conc. (Hach)- Particulate production- Bacterial level

- biocide treatment- sessile & planktonic

counts

28

❍ Free chlorine: Chlorine is added (as the hypochlorite ion, OCl-)to control bacteria in raw sea water. A free residual chlorineconcentration between 0.5 to 1 ppm is needed to give adequate“kill”. Free chlorine will react with the oxygen scavenger soaffecting oxygen control. High concentrations of free chlorine(>1 ppm) can increase corrosivity.

❍ Organic biocide treatment: A lack of bacterial control due toinfrequent biocide treatments can lead to increases in corrosivity.Organic biocides are deployed in systems where little or noresidual free chlorine exists (e.g. downstream of deaerators) tocontrol the build up of biofilms, corrosion and H2S generation.

Corrosion monitoring in sea water injection systems should include:

❍ Raw Sea Water/Upstream of Deaeration Towers:

Process monitoring: Flow rate, temperature, pressure, freeresidual chlorine, solids loading, bacteria measurements (sessileand planktonic) etc.

❍ Downstream of Deaeration Towers:

Process monitoring: The following parameters should bemonitored. Flow rate, temperature, pressure, oxygen content,free residual chlorine, residual bisulphite (if oxygen scavengerused), bacteria counts (sessile and planktonic). Themeasurements of oxygen and free chlorine can be made on-line.However, these measurements can be unreliable if the sensorsare not well maintained and regular cross checks with othermeters or proprietary kits should be made.

Corrosion monitoring: It is recommended that in sea watersystems intrusive type probes are used. The choice of methodswill depend on the system but should always include weightloss coupons (to provide valuable information on general andlocalised attack) which can be supported by other on-linemonitoring methods. The choice of method will depend uponsystem quality. Electrochemical methods have provedsatisfactory for on-line monitoring in many systems [9].However, if probe fouling is a problem then ER probes haveproved equally satisfactory. The corrosion monitoring probesshould be interrogated on a regular basis. On-line interrogatorsare preferred for this duty as they allow frequent (hourly) datacollection over long periods (2-3 months). The reason for this

CORROSION METHODS: A SYSTEM BY SYSTEM APPROACH

29

approach is that corrosivity in sea water systems is quite oftendue to short lived transients. The on-line probe data can alsobe supported by inspection type methods such as automatedultrasonics etc. This type of monitoring should be concentratedin areas of high turbulence such as downstream of bends,valves, pumps, and also in regions of low flow such as drains,sumps etc.

❍ Downstream of Booster Pumps:

Oxygen ingress is possible downstream of the booster pumpsand may lead to corrosion. All of the methods described in thesection above apply but in practice the inspection type methodsshould be sufficient to give confidence for integrity assurance.

Flowlines in this context are pipelines carrying unprocessed fluids,often 3 phases, from the wellhead to the processing facilities. Themain corrosion mechanism in these flow lines is flow-induced CO2corrosion. Figure 9 summarises the basic monitoring required.


Flowlines (oil, water and gas)

Figure 9 CorrosionMonitoring Requirementsfor Flowlines.

System Monitoring

c) Electrochemical methods require water wetting and conductivity. Can only be used reliably in water cutsabove ca. 10-20% or perhaps higher depending on the precise flow regime, e.g. stratified flow enablesmore reliable use of a bottom of line probe compared to turbulent flow. Each case has to be assessedindividually.

Flow Lines (oil,water, gas)

Corrosion Monitoring- Coupons- Electrical resistance methods

- flush / intrusive probe type- FSM

- Auto UT /Flexible UT mats- Electrochemical methodsc

- flush / intrusive probe type

Process stream Monitoring- Flow rate (oil, water, gas)- Flow regime- Water cut- Temperature- Pressure- Mol % CO2- Water chemistry- Iron counts- Production chemical addition

- de-emulsifier- scale inhibitor- corrosion inhibitor

- deployment method / rate- Well interventions

- scale squeezes,- acidisation etc.

- Particulate production- sand rates

- Bacterial level- biocide treatment- Sessile (<) & planktonic (<)

counts

30

The corrosion rate in a flowline will be dependent on many factorsincluding partial pressure of CO2, presence of H2S, water chemistry,temperature, water cut, production rates/regimes and inhibition. Thecorrosion monitoring requirements in flowlines will depend onlocation (land or sub-sea) but should include:

Process stream monitoring: Flow rate (oil, water, gas), water cut,temperature, pressure, dissolved gases (e.g. mole % CO2, H2S etc.),water chemistry, iron counts, production chemical additions (rate andtype) and solids production. Flow regime predictions should becarried out using these data. Well intervention programmes alsoshould be recorded (wireline operations, acid squeezes, reservoirfracturing etc.).

Corrosion monitoring:Subsea: The monitoring methods applicable sub-sea are very limited.At present only the Field Signature Method (FSM) (full details are givenin the Corrosion Monitoring Manual p. 53) is commercially available.The FSM method can be hard-wired back to the central facility or canbe installed as a stand alone device with satellite communications.However, the cost of a sub-sea FSM is high (>£250,000). A systembased on flexible UT mats is under development and may becommercially available in 1997.

Weight loss coupons, ER probes and electrochemical probes can befitted at the top of sub-sea risers. However, these will only giveinformation about corrosion in the riser itself. The riser conditions arenot likely to be representative of those in the flowline.

Land lines: Land lines fall into two categories, buried or raised. Forburied lines the methods for corrosion monitoring on the line arerestricted to FSM. Flexible UT mats may also be possible (UT mats areto be used in Colombia in 1996 on buried lines, using pipeline datatransmission). However, the monitoring at the wellhead will be similarfor both types (buried or raised). For raised lines it is recommendedthat a combination of flush and intrusive probes are used. The choiceof probe type and location will depend on the conditions. The choiceof methods will also depend upon the system but should alwaysinclude weight loss coupons (to provide information on general andlocalised attack). These can be sited both at the wellhead and at theprocessing facility to give information regarding changes in potentialcorrosivity through the flowline. At the wellhead, intrusive couponscan be used as the fluids will be well mixed. Further down the lineflush coupons may be preferred so as to reflect the corrosivity of anyseparated water.


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The coupon data can be supported by other on-line monitoringmethods. The primary choice would be ER probes but in high watercuts this could be supplemented by electrochemical methods for moredetailed studies. The ER probe type will depend upon location (asfor coupons). However, a flush probe mounted in a bottom of linelocation would be preferred for corrosion monitoring in low water cutflowlines. The on-line probe data can also be supported by inspectiontype methods such as automated ultrasonics. This type of monitoringshould concentrate on areas of high risk i.e. where water mayseparate: at bends, “Tees”, elevation or direction changes whereturbulence is at the highest or where erosion may be a problem. Ifsolids (sand) production is known to occur then data on erosion canbe obtained by using corrosion resistant ER probes (i.e. a probewhich will not corrode but which will erode at a similar rate as thepipe material).

Export lines fall into two categories, those carrying partially stabilisedcrude oil and those carrying fully stabilised crude oil. Partiallystabilised crude oil is where the offshore processing only goes downto an intermediate pressure and final separation is completed onshore.As some CO2/H2S remains, the fluids are still corrosive and thereforecareful corrosion control and monitoring are required. Most NorthSea lines fall into this category. Fully stabilised crude oil is where theoil has been processed down to atmospheric pressure and possiblystored in tanks. This type of line generally has a significantly lowerrisk of corrosion and so less exhaustive control and monitoring arenecessary.

In either case it is vital to maintain good control of export fluidquality and also to monitor any excursions in the water content. Withexport lines, access can be extremely restricted and so monitoring isoften limited to either end of the pipeline, although the FSM methodcan be used to monitor subsea or buried lines. Remember that riserconditions may not be representative of the main pipeline. Forexport lines reliance should always be placed on internal inspectionusing intelligent pigs.

Figure 10 summarises the basic corrosion monitoring requirements.


Oil Export Lines

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System Monitoring

c) Electrochemical methods require water wetting and conductivity. Can only be used reliably in water cutsabove ca. 10-20% or perhaps higher depending on the precise flow regime, e.g. stratified flow enablesmore reliable use of a bottom of line probe compared to turbulent flow. Each case has to be assessedindividually.

Oil Export Lines

Corrosion Monitoring- Coupons- Electrical resistance methods

- flush / intrusive probe type- FSM

- Auto UT /Flexible UT mats- Electrochemical methodsc

- flush / intrusive probe type

Process stream Monitoring- Flow rate (oil, water, gas)- Flow regime- Water cut- Temperature- Pressure- Mol % CO2- Water chemistry- Iron counts- Production chemical addition

- de-emulsifier- scale inhibitor- corrosion inhibitor

- deployment method / rate- Well interventions

- scale squeezes,- acidisation etc.

- Particulate production- sand rates

- Bacterial level- biocide treatment- Sessile (<) & planktonic (<)

counts

Figure 10 CorrosionMonitoring Requirementsfor Oil Export Lines.

The old 32” Forties subsea export line suffered significantcorrosion which was not detected by conventionalmonitoring methods although it had generally beenoperating at water cuts below 2%. It appears that themonitoring points stayed oil-wet whilst the corroded areasbecame water-wet.

Process stream monitoring: Flowrate (oil, water), water cut,temperature, pressure, dissolved gases (e.g. mole % CO2, H2S etc.),water chemistry, iron counts, production chemistry additions, 3rdparty entrants, and solids production. Flow regime predictions shouldbe carried out using these data.

The main mechanism is usually CO2 corrosion and the same factorsthat apply to flowlines will apply here. The biggest differencebetween the two is that the water cut is usually below 2% in oilexport lines and therefore detection can be difficult as corrosion willonly occur where water separates from the crude oil and contacts (i.e.water-wets) the pipe wall.

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Corrosion monitoring: It is recommended that for low water cutlines only flush mounted probes are used. The choice of method willdepend upon the system but should always include weight losscoupons (to provide information on both general and localisedattack). These should be situated at different parts of the system soas to reflect changes in corrosivity throughout the system. The coupondata can be supported by other on-line monitoring methods. Theprimary choice would be ER probes located at the bottom of line,preferably flush mounted. The use of electrochemical methods wouldonly be recommended at water cuts in excess of ca 10-20% which areunlikely to be found in an export line.


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1. Trewhella, M, “An Assessment of the Costs of Corrosion to the BPGroup”, 1989.

2. Marine Offshore Management Ltd., Aberdeen “BP ExplorationCosts of Corrosion 1990 to 1992”, 1993.

3. LRIM, “Criticality Assessments”, Kings Close, 62 Huntly street,Aberdeen AB1 1RS.

4. Tishuk Enterprises [UK] Ltd, “Operational Criticality Assessments”,52 Regent Quay, Aberdeen, AB1 2AQ.

5. RP 6-1, “Corrosion Monitoring”, August 1993

6. Ovstetun, I et.al. “Procedure for Removal and Installation ofCorrosion Monitoring Equipment”, Document No. 9.71.024 BPXNorway.

7. RP 42-1, “Piping Systems”, (Issue date 1989) (replaces BP CP 12).

8. Groves, S, “Elastomer Selection Guidelines”, Sunbury Report No.ESR.93.ER151, dated 16/12/9

9. Webster, S and Smith, J T A, “A Comparison of Corrosivity withOperational Parameters for the Wytch Farm Sea Water InjectionSystem 26-30 November 1994”, Report No. ESR.94.ER.120.

10. LRIM, “CORTRAN (COrrosion TRend ANalysis)” Kings Close, 62Huntly Street, Aberdeen, AB1 1RS

11. “PREMIS (Process Recording & Energy Management InformationSystem)”, MDC, Premier House, Startforth Road, Middlesborough,Cleveland TS2 1PT.

12. Mentor, CML, Real Time Corrosion Management Ltd, RutherfordHouse, Manchester Science Lab, Manchester M15 6SZ.

13(a)Smith, J T A, “Minimising Corrosion of Carbon Steel in Sea WaterInjection Systems - Guidelines for Water Quality”, ESR.94.ER.005,Dated Jan 1994.

13(b)Smith, J T A and Vance, I, “Corrosion and Materials Issues inWater Injection Systems”, Sunbury Report No. ESR.96.ER.074,Dated August 1996.

References

Maindocument

Webster, S and Woollam, R C, “Corrosion Monitoring Manual : AComprehensive Guide to Corrosion Monitoring in Oil and GasProduction and Transportation Systems”, Sunbury Report No.ESR95ER053, dated November 1996.

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Abbreviation Technique Required Water Cut Definition

LPR Linear polarisation greater than ca 10-20% Indirect measurement ofresistance corrosivity using

electrochemical method.Probe inserted into linethrough access fitting.

ER Electrical resistance not a requirement Direct measure of material lossfrom a probe by monitoringchanges in resistance of probeelement. Probe inserted intoline through access fitting.

FSM Field Signature Method not a requirement Commercial system whichmonitors changes in pipe wallthickness using the sameprinciple as the ER probe butapplied to a full pipe. Noprobe required. Uses a spoolpiece or external installation.

UT Ultrasonic thickness not a requirement Monitors thickness of pipe wallmeasurement using an ultrasonic source.

FM Flexible UT mats not a requirement Ultrasonic device whichmeasures changes in pipe wallthickness. The device is fixedpermanently to be area beingmonitored.

WL Weight loss coupon not a requirement Direct measure of material lossby measuring changes inweight of a corrosion coupon.Coupons inserted into linethrough access fitting.

EN Electrochemical greater than ca 10-20% Indirect measurement ofnoise corrosivity using a complex

electrochemical technique.Data analysis very difficult,time consuming and uncertain.

Appendix 1: Monitoring Technique Definitions

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Appendix 2: Conversion of Units

kilometre = 0.621 mile pound = 0.454 kilogramfoot = 0.305 metre mil per year (mpy) = 0.0254 mm per yearbar = 14 psi dollar = 0.625 pound sterling

(Q2 1996)

03 corrosion monitoring guidelines

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