Corrosion Monitoring Guidelines A summary of practical steps for successful corrosion monitoring in oil and gas transportation fac facilities ilities S Webster, R Wooll Woollam am Sunbury Report No. ESR.95.055 dated November 1996
Main CD Contents
Contents Summary
1
Acknowledgements
3
Introduction to Corrosion Monitoring
5
Background Elements of a Corrosion Control Strategy What are Corrosion Monitoring Methods? The Economics of Corrosion Monitoring
General Guidelines
5 6 6 8
11
Selection of a Corrosion Monitoring Location and Technique Design of Corrosion Monitoring Location Process Monitoring Data Handling Side-stream Monitoring
11 17 20 21 25
Corrosion Monit ito orin ing g: A System by System Approach
27
Background Sea Water Injection Systems Flow Lines (oil, water and gas) Oil Export Lines
27 27 29 31
References
35
Appendix 1: Monitoring Technique Definitions
37
Appendix 2: Conversion of Units
39
Summary
Lower cost materials are the natural economic choice for oil and gas production and transportation facilities. facilities. Unfortunately these materials (e.g. carbon steel, low alloy steels) in general have a low resistance to corrosion. Therefore, the corrosion risks of these materials have to be proactively managed. To this end BPX have developed and implemented corrosion control strategies which integrate corrosion monitoring and inspection with risk assessment and corrosion control. The application of corrosion monitoring as part of a corrosion control strategy is complex and often becomes the responsibility of engineers who are not experts experts in the field. field. These guidelines are a synopsis of the more thorough Corrosion Monitoring Manual* that has been developed as an aide to those designing and operating a corrosion monitoring system. The guidelines supplement the BP recommended practice RP 6-1 and give a broad overview of corrosion monitoring requirements by providing practical information and advice based on recent operational experience which will aid any operator concerned with corrosion corrosion monitoring. monitoring. The guidelines guidelines address: address: r
Choice of monitoring location/orientation
r
Choice of monitoring methods
r
Application of the various methods
Other complementary procedures such as inspection or intelligence pigging are outside the scope of these documents but are covered in the BP standard RP32-4 Many of the principles and concepts given here are also relevant to processing facilities such as glycol and amine gas treatment systems, although these cases are not dealt with specifically.
*
S Webste Webster, r, R. Woo Woolla llam, m, “Corr “Corrosi osion on Monit Monitori oring ng Manua Manual: l: A Comprehensive Guide to Corrosion Monitoring Monitoring in Oil and Gas Production and Transportation Systems”, Systems”, Sunbury. Sunbury. Report No. ESR.95.ER053. Dated November 1996. 1
Acknowledgements
The authors would like to thank, r
BP staff who helped in useful discussions
r
suppliers who provided information and photographs
r
Drew McMahon (ESS Sunbury) for editorial assistance
3
Introduction to Corrosion Monitoring
Background
A 1988 survey revealed that BP transports 80% of its cash flow through facilities that are over 15 years old [1]. The integrity of such facilities is vital to the successful and profitable operation of the Company 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’s corrosion costs in the North Sea estimated that corrosion accounts for over 10% of the lifting costs per barrel of oil. Lower cost materials are the natural economic choice for oil and gas production and transportation facilities. facilities. Unfortunately these materials (e.g. carbon steel, low alloy steels) in general have a low resistance to corrosion. Therefore, the corrosion risks of these materials have to be managed proactively. To this end BPX have developed and implemented corrosion control strategies which integrate corrosion monitoring and inspection with risk assessment and corrosion control. The aim of corrosion monitoring is primarily to ensure that the design life is not being adversely affected or compromised and also to increase the safe and economic operational life of a facility (Figure 1). Figure 1: The Aims of Corrosion Monitoring Health & Safety
Inspection
Plant Integrity & Operation
Life Assurance Life Extension
Corrosion Monitoring
Predictive Models
Process Stream Analysis
On-line Monitoring Operational History
Future Operational Conditions
5
INTRODUCTION TO CORROSION MONITORING
These guidelines give practical advice on the essential steps required to achieve effective corrosion monitoring and details of practical experience are given in the highlighted boxes. Elements of a Corrosion Control Control Strategy
There are three main components in the development and implementation of the BPX corrosion control strategies (Figure 2). Figure 2: A Schematic of the Inter-Relationships Inter-Rela tionships in a Corrosion Control Strategy.
Risk / Criticality Assessment
Control Procedures
Inspection and Monitoring
All of the above activities (risk assessment [3,4], corrosion control, inspection and monitoring) are interdependent . Results from corrosion monitoring and inspection must be used to re-evaluate and modify, where necessary, the risk and criticality assessment and any control procedures. This report focuses on the corrosion monitoring elements in a corrosion control strategy. What are Corrosion Cor rosion Monitoring Methods? Methods?
When undertaking corrosion monitoring it is important not to rely on just one method. The best results are obtained by using a range of methods. Corrosion monitoring monitoring in this context can be defined as:
6
INTRODUCTION TO CORROSION MONITORING
The use of any method that enables an operator to estimate or measure the corrosion rate occurring in an item of plant, or the corrosivity of a process stream.
\ The main methods fall into the following categories: Inspection On-line corrosion monitoring Analysis of process streams Operational history assessment
r r r r
Historically, corrosion monitoring and process data analyses were perceived as quite separate from inspection activities. Although inspection has been historically concerned with mechanical integrity, many inspection methods can be used as corrosion monitoring tools and supplement corrosion monitoring methods. The complementary nature of these approaches is summarised in Figure 3. Figure 3: Classification of Currently Available Inspection and Monitoring Techniques
À À À À À À
Large time interval between readings Non-destructive Direct measure of material loss Low sensitivity High accuracy / reliability Lagging indicator
n o l t a i c u e s i p V s n I
y h p a r g o i d a R
s c i n o s a r t l U
T U s e t l a b i M x e l F
#
À À À À À À
Small time interval between reading Destructive (probes / consumables) Indirect measure of material loss High sensitivity Lower accuracy / reliability Leading indicator
T U o t u A
s n o p u o C
e r ) u M t a S F n ( g d i S o h d l t e e i F M
s e b o l r a P c i r e t c c n e l t a E s i s e R
s i s y l a n A l a c i m e h C
n o i t a e s c i r n a t a l o i s P s r e a R e n i L
l a c i m e e s h i c o o r N t c e l E
#
#
#
#
Uniform Corrosion Localised Corrosion
Notes: Note s: (a) the posi positio tion n of a techni technique que in in the the tab table le does does not relate to its exact position along the arrows (b) Flexib Flexible le UT mats maximu maximum m temperatu temperature re is 120 C °
7
INTRODUCTION TO CORROSION MONITORING
For any corrosion monitoring/inspection programme to be fully effective it is vital that all of the above information can be accessed centrally and compared with each other. This can be be achieved by ensuring full access to all databases which hold the relevant information and having the right software to conduct the relevant correlational analysis. The Economics of Corrosion Monitoring
In general the purpose of corrosion monitoring is to optimise corrosion mitigation/repair/replacement activities such that an optimum between corrosion control and replacement costs is achieved. It should be noted that there may be additional cost considerations related to safety, environmental and production impacts which are NOT considered in the following. A given corrosion monitoring method or technique has only a limited accuracy and therefore, each corrosion rate determination has a random error associated with it. This random error can only be reduced by increasing the amount of corrosion monitoring undertaken but this increase in corrosion monitoring activity will increase the cost of the activity. For an optimal corrosion monitoring programme the benefit obtained should be greater than the cost incurred. For corrosion inhibitor optimisation there is a trade-off between replacement costs and corrosion inhibition cost (Figure 4a) which results in an operational minimum of the sum of the corrosion inhibition costs and the pipeline replacement costs. In order to determine the optimum corrosion inhibitor injection rate, the corrosion rate for the system needs to be determined. The corrosion rate will determine if the corrosion inhibitor injection rate is effective, if it needs adjustment (up or down), or if some alternative means of control is required (e.g. corrosion resistant alloys, CRAs). Figure 4b shows the increasing confidence and reduction in error in determining the corrosion rate as the number of corrosion rate measurements is increased. Figure 4c shows the increasing cost of corrosion monitoring as the number of measurements increases versus the incremental benefit from corrosion inhibitor optimisation.
8
INTRODUCTION TO CORROSION MONITORING
Figure 4c clearly shows the point at which no additional corrosion monitoring is warranted as the incremental savings from corrosion inhibitor optimisation are less than the cost of the monitoring program. The cross-over of the two curves indicates the level of corrosion monitoring required to optimise the overall cost structure. This approach can be generalised to other corrosion mitigation methodologies and the monitoring of these systems. systems. In general there is an optimum amount of corrosion monitoring in a system above which the costs of monitoring exceed any savings generated.
the e Figure 4a Shows th Trade-off Between Replacement Costs and Inhibition Costs.
Total Cost: CI and Replacement
Total Cost Replacement cost Inhibition cost
0
5
10
15
20
25
30
35
40
45
50
Corrosion Rate, mpy
Figure 4b Shows the Increasing Confidence and Reduction in Error, in Determining the Corrosion Rate as the Number of Corrosion Rate Measurements is Increased.
Corrosion Rate Spread with # Locations
2
5 10 20 50 100
Total Pv ∆ CR with #
0
5
10
15
20
25
30
35
40
45
50
Corrosion Rate, mpy
9
INTRODUCTION TO CORROSION MONITORING
Figure 4c The Increasing Cost of Corrosion Monitoring as the Number of Measurements Increases.
Cost/Benefit of Monitoring
Cost/Benefit of Monitoring Cost of Monitoring Program per Year
) $ ( e u l a V t n e s e r P
0
0.5
1
1.5
2
2 .5
3
3.5
4
Log (Number of Locations)
Costs
Table 1: Outline Costs for Various Corrosion Monitoring Techniques based on 1995 information (£1=$1.6).
Table 1 gives outline costs for various corrosion monitoring techniques. This table is a guide to the relative costs of each technique (hardware) and any operational costs associated with installation and data analysis. The costs will vary depending upon asset location and number of monitoring monitoring locations. However However,, these figures will aid the costing of monitoring/inspection activities. Monitoring Method
Hardware
Probe
Weight Loss Coupons
None
£300
Coupon insertion and retrieval. Coupon analysis
Electrical Resistance Probes
£1500
£500
Probe insertion and retrieval. Data analysis
Electrical Resistance Sand Monitor
£25000
£1000
Probe insertion and retrieval. Data analysis
FSM (Topsides)
£30000
-
Data analysis
£250000
-
Data analysis
L PR
£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
FSM (subsea)
10
Man-hour costs
Data analysis
General Guidelines
Selection of a Corrosion Monitoring Location and Method
Introduction
The selection of the monitoring location and method are critical tasks for successful corrosion monitoring. monitoring. It cannot be stressed enough that selection of the wrong location or method will result in a large amount of effort and expense only to generate inappropriate or even misleading information. In many cases incorrect selection is worse than no selection as the quality of data are often not questioned once they have been collected. Physical access is important but should not dictate monitoring location. However, when a monitoring point is identified the position should allow routine access for probe maintenance, retrieval etc. Incorrect selection of location or method is worse than no selection.
All corrosion monitoring (and inspection) locations and methods should be recorded recorded on the relevant relevant technical drawings. This should include process flow diagrams, process and instrumentation diagrams (P&ID’s) and the isometric isometric diagrams. On new facilities they should be included in the Computer Aided Design (CAD) system as this aids data analysis and the development of control procedures. The records should include not only details on the system, item and location, but also the method and probe orientation. There are no fixed rules on how to select a corrosion monitoring location or method but the first step must be to decide what corrosion mechanisms need to be monitored. monitored. Experience has shown that the following approaches are of value. r
Best practice
Experience at other assets utilising similar facilities or in the current asset can provide valuable information not only on the locations likely to experience corrosion but on the choice of suitable method.
11
GENERAL GUIDELINES
r
Networking
A wide range of engineering disciplines should be contacted to obtain a full picture of current and potential future problems. Two examples from recent BP operations are given here and highlight where inappropriate selection of the monitoring location or method caused problems. Corrosion monitoring in a main oil export line with water cut below 1%. Corrosion monitoring was undertaken using an intrusive electrical resistance probe via a top of the the line access fitting. fitting. Low corrosion rates were observed which appeared to be insensitive to process changes. In this case the the probe response was most likely reflecting the corrosivity of the continuous hydrocarbon phase and not that of the aqueous phase which constituted the corrosion hazard. A more reliable approach may well have been to have used a flush mounted electrical resistance probe via an access fitting located at the bottom of line where water separates.
Corrosion monitoring in a sulphide-conta sulphide-containing ining produced water line. Corrosion monitoring was undertaken using a flush mounted linear polarisation resistance resistance (LPR) probe via a bottom of line access fitting. The monitoring programme yielded an exponentially increasing corrosion corrosion rate with time. Most likely the probe response reflected the shorting out of the probe elements due to the formation of a conducting sulphide film. A more reliable approach may have been to substitute the LPR probe with a flush mounted electrical resistance (ER) probe in the same location.
Selection of a Corrosion Monitoring Location
12
This section outlines the main points that should be considered when identifying a corrosion monitoring location, and are summarised in Figure 5.
GENERAL GUIDELINES
Figure 5: A Check List for Identifying a Corrosion Monitoring Location
Single or multiphase flow
What is the major corrosion mechanism and mode of attack ?
Corrosion rate of each phase Mechanism/mode of attack
Prior elevation changes
Orientation of pipework?
Water drop out Other pipeline entrants Position of other pieces of equipment
Location of chemical injection points
Upstream/downstream effects Localised effects Corrosivity of injected chemical
Environment indicative of corrosion elsewhere
Process changes
Low alloy probe in CRA line
Identify process changes in system Location reflect most corrosive situation
Physical access
Should not dictate locations
Record locations
Flow diagram process and instrument diagrams etc.
Full details of each factor are given in the Corrosion Monitoring Manual. Corrosion Monitoring Method Selection
The inspection or monitoring method must be chosen to provide rate information appropriate to the particular corrosion process(es). Consideration of the corrosion environment is important as this will often preclude many methods (e.g. electrochemical methods are not suitable in low water cut or low conductivity situations). Consideration of the corrosion mechanism (general, pitting, cracking etc.) is also important as this will give an insight into the monitoring method most suitable (e.g. pitting most easily detected using weight loss coupons) and eliminate many unsuitable methods. The Corrosion
13
GENERAL GUIDELINES
Monitoring Manual gives a detailed critique of each method covering instrumentation, data analysis and the relative advantages and disadvantages. The economics of applying any of the methods must be considered because the economic benefit must exceed the cost of the activity. A schematic for selecting the most appropriate corrosion monitoring method(s) is presented presented in Figure 6. A simple definition definition of each technique is given in Appendix 1. There are no fixed rules on which methods are most suited for a given system (i.e. water injection system, crude oil flow lines etc.) as the conditions conditions in each will will vary. However, Table 2 gives a general guide to the possible application of the various monitoring methods on a system by system approach. When selecting a monitoring method it must be realised that each method gives only only a limited amount of information. It is good practice to use a selection of methods to give confidence in the results. The first choice must always be inspection-based methods as they are very reliable for integrity assurance. This can then be supported by probe-based methods. If only one probe based method can be used then the first choice should be weight loss coupons as this method gives both general and localised information. The utility of inspection based methods is tempered by the fact that they are “lagging” indicators of corrosion. corrosion. If inspection data says the situation is bad then it may be too late to do anything about it because the damage damage has already been done. Monitoring methods are are “leading” indicators of corrosion. They show the corrosivity at a particular moment, potentially before any significant damage has occurred. Hence, monitoring monitoring methods are always a valuable complement to inspection methods.
14
GENERAL GUIDELINES
Figure 6: Schematic for Selecting a Corrosion Monitoring Method
15
GENERAL GUIDELINES
Table 2: A General Guide to the Application of Corrosion Monitoring Techniques
t a n i S d o h t e M g e r u d l e i F
.
) e l b i s s s t a m T U e l b i x e l F o 6 p s i n o i t a h c t a P / s e b o r P n e g o r d y H n # # # # i m a t n o 7 c e p H # # d o r t c e 2 S S S l S I 2 2 2 e 2 S s e s a G d e v l o s s i D C H f , , H , H H 2 o , 2 2 # , 2 2 2 H O O O m O r O C C C o f r e h s d i l o S d e v l o s s i D t # # # o r o ( y c n s d i l o S d e d n e p s u S e # # # # d n e t g n i l g n i r o t i n o M l a i r e t c a B c # # # a s g n o r t s s e b o r P c i n a v l a G 2 a # # # # # r o t n e s e b o r P 4 3 t n 1 l a c i m e h c o r t c e l E # # # # o c n o i w s e b o r P 5 o l e c n a t s i s e R l a c i r t c e l E a i s e r e s i s y l a n A h t t c u d o r P n o i s o r r o C r e e h w e s e c e i P l o o p S l b / s n o p u o C s s o L t h g i e W a t i u s n u R P L . y ) t i s l a m a l g o i u t , t q r O h o t e r i B t e e n a t w d s r o w a i u a s t e r l , w c l r e t r C G e e i s a n j o t e d n t ( s W o n o a e I s a e b s r e W i s r W V d e d e i i a t n r l t e t n c a b n a L f g r e e a o p r e w w i t r a u a e a o u s d l o p e l q n y f f t e D S F A U H E S S
1
16
. h g i h s i t n e t n o c n e g y x o e r e h w d e s u e b y a M
. % 0 2 % 0 1 . a c e v o b a s t u c r e t a w n i y l n O
2
3
. y c n e d n e t g n i m l i f o i b e r e h w e l b a t i u s n u R P L . y t i l a u q r e t a w n o s d n e p e D
. y c n e d n e t g n i m l i f o i b e r e h w e l b a t i u s n u d e t n u o m h s u l F . d e r e f e r p e b o r p e v i s u r t n I
C 0 2 1 e r u t a r e p m e t m u m i x a M
4
6 5 7
°
e n i l t r o p x e s a g t e w n i r e t a w d e s n e d n o c r o f l u f e s u e b y a M
GENERAL GUIDELINES
Design of Corrosion Monitoring Location
Access Fittings
For operating pressures 10-137 bar(g) (i.e. 150-2000 psig) the insertion of probes and coupons into pipework and facilities without the need for plant shutdown relies on the use of proprietary 2 inch access fittings. Access fittings are usually installed at the construction phase or during plant shutdown. Therefore, itit is important important that the corrosion monitoring requirements are well thought out at the design stage otherwise subsequent installation will be difficult and costly. Access fittings can be installed during plant operations using a hot tap but in many circumstances safety requirements will preclude such activity. The BP recommended practice RP6-1 gives a thorough overview of access fittings and retrieval tools [5]. However However,, the following points should also be considered. r
Orientation of access fitting
The anticipated location of the corrosion attack should dictate location of the fitting. If corrosion is occurring at the bottom of line (e.g. wet oil, wet gas) then the access fitting should be located in this position. position. This will also minimise probe length and so reduce the possibility of probe fatigue failure and make the line easier to pig. The bottom of line line location can cause cause problems with accumulation of debris and the possible galling of the threads. However However,, modern access fittings or improved retrieval procedures procedures can minimise these effects. The access orientation is less critical for a single phase water stream since all parts of the pipewall will experience the same environment. BPX Norway have developed a procedure to minimise the effect of debris build up on bottom of line location using standard access fittings [6] . This involves back pressurising the retrieval tool so that any debris is pushed back into the line. This procedure has been used used on Ula since 1986 without any problems.
Retaining adequate clearance for the retrieval tool is important when locating an access fitting. RP 6-1 gives full details on the clearance required for different different retrieval tools. However However,, clearance alone should not dictate location or orientation. The position must also be be capable of providing useful corrosion information.
17
GENERAL GUIDELINES
r
Access fitting and sampling point design
All access fittings should be fitted with heavy duty covers to protect the fitting threads and electrical connections from damage. The cover should be fitted with bleed bleed plugs (or possibly a pressure gauge) so that leaks between the access fitting body and the monitoring device can be easily identified. The design should not allow the probe to be inserted back-tofront. Sample points for the collection of process fluids should include two isolating valves in series, one of which should be a needle valve. Details are are given in RP 42-1 [7]. r
Material selection
Access fitting material should conform to the requirements of the piping specification. specification. Austenitic stainless stainless steels are usually specified and are suitable for most duties. Recent experience at a refinery has highlighted the importance of material material selection. A 316 stainless steel probe holder on a Crude Distillation Unit top pump around-circuit suffered chloride stress corrosion cracking in service leading to a hydrocarbon leak and a serious “near miss”. The incident report recommended that all future fittings should be constructed from Hastelloy for this application in which chloride ion concentration and low pH put conventional conventional austenitic stainless stainless steels at risk .
It is also important that any seals associated with the probe assembly should have satisfactory performance under the operating conditions[8]. r
Trap-type monitoring point
In low water cut situations some operators have adopted the use of water traps. These traps act as a sink for water water drop-out and allow allow conventional monitoring monitoring methods to be employed. employed. The trap can also promote bacterial bacterial action. The design of the trap should include include appropriate isolation to allow accumulated water to be drawn off (full details are given in the Corrosion Corrosion Monitoring Monitoring Manual). Traps can become potential corrosion sites by acting as a dead leg and their use is not recommended. Probe Configuration
18
Probes and coupons fall into two main categories:
GENERAL GUIDELINES
r
Flush mounted
These are designed to be positioned so that the probe element is flush with the inside pipe wall. r
Intrusive
These probes protrude well into the process stream and are suited for measuring the overall corrosivity of a process stream. There is no generalisation as to which of these probe configurations is most appropriate appropriate for corrosion corrosion monitoring. The choice will depend on the information required and whether the line is pigged. Validation of Monitoring Method Response
Before embarking on a detailed corrosion monitoring programme it is important to ensure that the type of monitoring method is reliable and has 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 data can actually be misleading. This can lead to complacency in corrosion control, unnecessary modification of control methods, or changes to operational parameters being made. Increasing probe corrosion rate is usually a warning of increasing corrosivity but a low probe corrosion rate is not a guarantee that a system is under control. A lack of probe response has often been interpreted as a sign of good control rather than a sign of poor positioning/choice of the monitoring methods
For any monitoring programme, control checks must be included to ensure the reliability of the data. Changing the corrosivity corrosivity of the system, to validate the monitoring method should only be undertaken once the full risks of the operation have been identified. A recent corrosion survey [9] of a sea water injection system showed good oxygen and free chlorine control according to the on-line dissolved dissolved gas monitors. monitors. However, when the responses of the on-line monitors were checked against proprietary chemical kits the levels of dissolved gases were found to be an order of magnitude higher than expected. Also the probes took hours to respond to instantaneous changes changes in dissolved dissolved gas levels. levels. It was found that the probes were fouled and needed more frequent maintenance.
19
GENERAL GUIDELINES
Process Monitoring
Background
Process monitoring is a key aspect of any corrosion monitoring programme and covers a wide range of activities including but not limited to the following: r
Measurements of standard process data (temperature, pressure, flow rates, water cuts etc.)
r
Chemical analysis of the process streams (dissolved ions, bacterial levels, suspended solids, dissolved gases etc.)
r
Chemical analysis of corrosion products.
r
Details of production engineering activities (workovers, acidisations etc.)
r
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 and in the interpretation of corrosion monitoring data in order to indicate if the inspection/monitoring programme is still relevant to current operating conditions. Process monitoring measurements can be made either on-line or by samples taken at regular intervals. There are standard standard procedures available available for most most of the methods, the details of which are outside the scope of this document and are listed below. Full details of these activities activities are also given in the complementary Corrosion Monitoring Manual. API RP 38
Recommended Practice for Biological Analysis of Subsurface Injection Waters.
API RP 45
Recommended Practice for Analysis of Oilfield Waters
NACE RP 0173 Recommended Practice: Collection and Identification of Corrosion Products NACE RP 0192 Recommended Practice: Monitoring Corrosion in Oil and Gas Production with Iron Counts
20
GENERAL GUIDELINES
Application of Process Monitoring Data
The application of process monitoring data is important if the full value of the data is to be realised. realised. Typically the data will be used to assess corrosion rates indirectly (iron counts or laboratory corrosivity measurements of field samples) or be used to predict potential corrosivity from a detailed knowledge of the corrosion processes. The latter approach is extremely valuable as it enables an operator to predict changes in worst case corrosion rates and modify any monitoring/inspection activities or control procedures before significant damage has occurred. Figure 7 gives a broad summary of the use of process monitoring data. The Figure below is from the BP Magnus platform in the North Sea. A number of production vessels vessels on the installation are sandwashed sandwashed every day. day. It was assumed that all the water was routed out from the vessels via the drains. The fluid corrosivity corrosivity graphs for for the main-oil-line main-oil-line (MOL) generally showed a low value, however, high corrosion “spikes” were were appearing appearing every day. day. Comparing the times of these “spikes” with process conditions revealed that some of the sandwash water was in fact going down the the MOL and and increasing the the corrosion. By doubling the corrosion inhibitor injection rate into the MOL during sandwashing, the “spikes” on the probe output disappeared and the normal low corrosion rate could be maintained.
0.10 ) r 0.08 y / m m0.06 ( y t i v i s 0.04 o r r o C 0.02
Corrosion Peaks Related to Sand Washing
0.00
Days
Data Handling
The methods used to analyse corrosion monitoring data will depend upon the number, location and variation in monitoring methods employed. For effective corrosion corrosion monitoring and control it is vital vital that all of the relevant data can be accessed easily, cross referenced and analysed. Typically in any production operation operation the data will will be held on different databases and in a variety of formats (database or paper files). Therefore, it is important to set up the relevant relevant 21
GENERAL GUIDELINES
Figure 7: The Use of Process Monitoring Data to Predict Corrosion
Risk
CO2
H2S
O2
O2
MIC
1 2 3 4 5 6 7 8 9 10 11
22
System
Oil & Gas Systems
Oil & Gas Systems
Sea Water
Injection Water
Oil & Gas Systems
Process Parameter Temperature Pressure Flow Regime Flow Rate CO2 mol % H2S mol % Water Chemistry pH Solids Corrosion Inhibitor - dose rate - deployment Temperature Pressure CO2 mol % H2S mol % Water Chemistry pH
Temperature Pressure Flow Rate O2 Free CI2 Biocide Oxygen Scavenger pH Water Chemistry Temperature Pressure Sessile Bacteria Count Planktonic Bacteria Counts pH Water Chemistry
Model
de Waard & Milliams (1) Cormed (2) pH Calc (3) Design Guidelines - Wet Gas (4) - Wet Oil (5) - Erosion (6)
NACE MR-0175 (7) Cormed (2) Design Guidelines - Material Selection (8)
Oldfield &Todd (9) Design Guidelines - Sea Water Injection (10) - Material Selection (8)
Microbiologically Influenced Corrosion Review (11)
C de Waard et. al., Prediction of CO2 Corrosion of Carbon Steel, NACE 93, Paper 69 1993 J L Crolet, "Cormed Lotus 123 Spread Sheet for Calculating pH of Produced Waters" Elf Aquitane-SNEA (P) Copyright 1988, 1990 pH prediction J Pattinson et. al., A Corrosion Philosophy for the Transport of Wet Hydrocarbon Gas Containing CO2, ESR. 93. ER016 J Pattinson et.al., A Corrosion Philosophy for the Transport of Wet Oil and Multiphase Fluids Containing CO 2, ESR. 93.ER013 J Pattinson, Erosion Guidelines, ESR.94. ER070 NACE MR-0175 J Martin, Guidelines for Selecting Downhole Tubular Materials with Particular Reference to Sour Conditions, ESR. 94.ER043 Oldfield et.al., Corrosion of Metals in Dearated Seawater, BSE-NACE Corrosion Conference, Bahrain, Jan 19-21 81 J T A Smith, Minimising Corrosion of Carbon Steel in Sea Water Injection Systems - Guidelines for Water Quality, ESR. 94.005 I Vance, Microbiologically Influenced Corrosion (MIC) in Oil Production Operations, Topical report No 8615 1993
GENERAL GUIDELINES
communication networks to ensure the data are readily accessible. For example, BP Alaska have usefully integrated their corrosion and production databases. BPX Alaska are now using a Corrosion Analysis Tracking System (CATS). This computer system system can store multi-giga bytes of data from literally thousands of corrosion measurements and inspections in the field. The database database is helping Inspectors, Corrosion Engineers and others to develop a systematic, comprehensive approach to locating corrosion, analysing the best treatment strategies, and monitoring corrosion chemical treatments to verify their effectiveness.
There are several proprietary packages which can be used to assist with this type of activity. These packages are essentially databases which store, manipulate and analyse the data to: r r r
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 to input the data into the system and the lack of flexibility. However, such systems have the capability to become the main corrosion database for all the monitoring data e.g. CORTRAN (CORrosion TRend ANalysis). CORTRAN is currently currently used by two inspection inspection contractors involved in the integrity management of the BP offshore assets in the UK sector of the North Sea [10]. Another approach is to access all the databases and extract the relevant information needed. needed. This can be a time consuming task if undertaken manually and impacts on the effectiveness of any monitoring programme. Wytch Farm has developed a user friendly front end to their distributed control system [11] . This system forms the management information system which archives and displays all site data for unlimited periods periods of time. It also has its own programming language which allows the user to develop high level applications e.g. energy monitoring or corrosion monitoring. monitoring. The system also allows manual manual input of data such as the addition of laboratory reports or production engineering reports.
23
GENERAL GUIDELINES
Another proprietary data handling and analysis package available is Mentor [12]. This system has been developed for for condition monitoring and has now been expanded to include corrosion monitoring information. The system can interrogate data from the distributed control system as well as allow data input manually. manually. The software is such that the data can easily be compared from different databases and alarm levels set to alert an operator to potential changes in corrosivity. A “Mentor” system was installed on the Magnus asset in in 1995. For effective analysis the following information is required: 1.
Process data: Usually available from a central database. This
information involves involves both on-line on-line and off-line data. These data should be supplemented by: r r
Laboratory analysis Production engineering reports detailing - well shut-ins - acid stimulations - wireline activities - sand production - well workovers
2.
Should include all the on-line data as well as the data collected manually (coupons etc.). These data should be stored in a format which enables comparison with the process data.
3.
Should include the routine inspection reports and data from specialised surveys. surveys. Again, the data should should be in a format which is comparable with the process and monitoring data.
Corrosion monitoring data:
Inspection data:
The presentation of data is also important. The type of of report is dependent upon the activity and the scope of the work. work. Recently some operators have started to use the CAD drawings as an aid to presenting the corrosion and integrity data. This approach approach is very very effective in identifying areas of concern and predicting potential locations of corrosion.
24
GENERAL GUIDELINES
Side-stream Monitoring
Side-stream monitoring is considered as a supplement to on-line corrosion monitoring. In this approach some of the process process fluids are diverted from the facility into a temporary section of pipework containing the corrosion corrosion monitoring probes. The fluids then re-enter the main process fluids or are collected for disposal disposal later. later. This approach allows the flow rates to be modified and chemical treatments to be investigated without any major changes in production. Side-streams have been used extensively to study inhibitor performance. Although the use of side-streams side-streams appears appears to be useful there are several several inherent problems problems associated with with their use. These are: r
The sampled fluids may not be representative of the process fluids.
r
The side-stream may not simulate the correct flow regime for a given flow rate.
r
Side-streams tend to form well mixed fluids in low water cut situations therefore forming emulsions and preventing water separation.
r
Temperature and pressure in the side-stream may not be representative of process stream.
In summary, side-streams should be used with caution and should never be used as a primary corrosion monitoring tool. Experience has shown them to be most effective on single phase systems (e.g. water injection flow lines). Any results obtained should be compared to field experience before reliance is placed on them.
BP Alaska used a side stream device to assess the performance of biocide in the sea water injection system. Biocide was terminated, based in part on the side stream data. Corrosion rates rates subsequently subsequently increased by approximately approximate ly two orders of magnitude. magnitude. Biocide was then then restarted but even after 2 years it had not reduced the corrosion rates back to their previous levels
25
Corrosion Monitoring: A System by System Approach
Background
This section serves to give examples of how the various monitoring methods and approaches can be applied to give comprehensive cover within an oil and gas production facility. These are only examples and in practice the monitoring system required may be quite different depending on the site specific conditions. Sea Water Injection System
Corrosion monitoring in sea water injection systems should be very simple (i.e. aqueous and single phase) but is quite complex in practice. Guidelines have been issued on corrosion control methods [12] . Figure 8 summarises summarises the basic corrosion monitoring required for a sea water system. Figure 8 Corrosion Monitoring Monitori ng Req ui uirements rements for a Sea Water Injection System.
System
Monitoring
Corrosion Monitoring - Weight Weight loss loss coupons coupons - Electrica Electricall resistance resistance methods methods - intrusive intrusive probe probe type - Flexib Flexible le UT mats matsa /auto UT - Electroch Electrochemica emicall metho methods ds b - intrusive intrusive probe type
Sea Water Injection systems
Process stream Monitoring - Flow Flow rate rate - Temper Temperatu ature re - Pres Pressu sure re - Iron Iron coun counts ts - Dissolved Dissolved oxygen oxygen (<50ppb (<50ppb)) - on-line, on-line, colorimetr colorimetric ic - Free chlori chlorine ne (<0.2pp (<0.2ppm) m) - on-line, on-line, colorimetr colorimetric ic - Oxygen Oxygen scavenge scavengerr - dose rate, rate, residual residual conc. conc. (Hach) - Particula Particulate te productio production n - Bacter Bacterial ial level level - biocide biocide treatment treatment - sessile sessile & plankton planktonic ic counts
a) Flexible UT mats: Maximum operating temperature 120°C b) Depends on water quality. quality. LPR unsuitable where where biofilming tendency
The main corrosion mechanism mechanism is oxygen induced corrosion. This depends on the dissolved oxygen concentration, flow rate and temperature. Microbially induced induced corrosion (MIC) is also possible. The activity of aerobic bacteria will be reduced by effective oxygen control. However, sulphate sulphate reducing bacteria bacteria (SRB) are anaerobic and will require an efficient biociding biociding regime. Other production chemicals added to the sea water also contribute to the overall corrosivity, r
Oxygen scavenger: This chemical is added to remove residual residual oxygen but can itself be corrosive if over-dosed.
27
CORROSION METHODS: A SYSTEM BY SYSTEM APPROACH
r
r
Free chlorine: Chlorine is added (as the hypochlorite ion, OCl -) to control bacteria in raw sea water. A free residual residual chlorine concentration between 0.5 to 1 ppm is needed to give adequate “kill”. Free chlorine will react with the oxygen scavenger so affecting oxygen control. High concentrations concentrations of free chlorine chlorine (>1 ppm) can increase corrosivity. Organic biocide treatment: A lack of bacterial control due to infrequent biocide treatments can lead to increases in corrosivity. Organic biocides are deployed in systems where little or no residual free chlorine exists (e.g. downstream of deaerators) to control the build up of biofilms, corrosion and H 2S generation.
Corrosion monitoring in sea water injection systems should include: r
Raw Sea Water/Upstream of Deaeration Towers:
Process monitoring: Flow rate, temperature, pressure, free residual chlorine, solids loading, bacteria measurements (sessile and planktonic) etc. r
Downstream of Deaeration Towers:
Process monitoring: The following parameters should be monitored. Flow rate, temperature, pressure, pressure, oxygen content, free residual chlorine, residual bisulphite (if oxygen scavenger used), bacteria bacteria counts (sessile and planktonic). The measurements of oxygen and free chlorine can be made on-line. However, these measurements can be unreliable if the sensors are not well maintained and regular cross checks with other meters or proprietary kits should be made. Corrosion monitoring: It is recommended that in sea water systems intrusive type probes are are used. The choice of methods will depend on the system but should always include weight loss coupons (to provide valuable information on general and localised attack) which can be supported by other on-line monitoring methods. The choice of method will depend upon system quality. quality. Electrochemical methods have have proved proved satisfactory for on-line monitoring in many systems [9]. However, if probe fouling is a problem then ER probes have proved equally equally satisfactory. The corrosion monitoring probes should be interrogated on a regular basis. On-line interrogators interrogators are preferred for this duty as they allow frequent (hourly) data collection over long periods (2-3 months). The reason for this
28
CORROSION METHODS: A SYSTEM BY SYSTEM APPROACH
approach is that corrosivity in sea water systems is quite often due to short lived lived transients. The on-line probe data can also be supported by inspection type methods such as automated ultrasonics etc. This type of monitoring should be concentrated in areas of high turbulence such as downstream of bends, valves, pumps, and also in regions of low flow such as drains, sumps etc. r
Downstream of Booster Pumps:
Oxygen ingress is possible downstream of the booster pumps and may lead lead to corrosion. All of the methods methods described in in the section above apply but in practice the inspection type methods should be sufficient to give confidence for integrity assurance. Flowlines (oil, water and gas)
Flowlines in this context are pipelines carrying unprocessed fluids, often 3 phases, from the wellhead to the processing facilities. The main corrosion mechanism in these flow lines is flow-induced CO 2 corrosion. Figure 9 summarises the basic monitoring required. Figure 9 Corrosion Monitoring Monitori ng Req ui uirements rements for Flowlines Flowlines..
System
Monitoring
Corrosion Monitoring - Coup Coupon ons s - Electrical Electrical resistance resistance methods methods - flush / intrusive intrusive probe probe type type - FSM - Auto UT /Flexible /Flexible UT mats mats - Electrochemi Electrochemical cal method methods sc - flush / intrusi intrusive ve probe probe type
Flow Lines (oil, water, gas)
Process stream Monitoring - Flow rate rate (oil, (oil, water, water, gas) gas) - Flow Flow regi regime me - Wate Waterr cut cut - Temper Temperatu ature re - Pres Pressur sure e - Mol Mol % CO2 - Water Water chemi chemistry stry - Iron Iron coun counts ts - Production Production chemical chemical addition addition - de-emu de-emulsi lsifie fierr - scale scale inhibi inhibitor tor - corrosion corrosion inhibitor inhibitor - deployment deployment method method / rate rate - Well intervention interventions s - scale scale squeez squeezes, es, - acidis acidisati ation on etc. - Particulate Particulate production production - sand sand rat rates es - Bacter Bacterial ial leve levell - biocid biocide e treatm treatment ent - Sessile Sessile (<) & plankto planktonic nic (<) counts
c) Electrochemical Electrochemical methods require water wetting and conductivity conductivity.. Can only be used reliably in water cuts above ca. 10-20% or perhaps higher depending on the precise flow regime, e.g. stratified flow enables more reliable use of a bottom of line probe compared compared to turbulent flow. Each case has to be assessed individually.
29
CORROSION METHODS: A SYSTEM BY SYSTEM APPROACH
The corrosion rate in a flowline will be dependent on many factors including partial pressure of CO 2, presence of H 2S, water chemistry, temperature, water cut, production rates/regimes and inhibition. The corrosion monitoring requirements in flowlines will depend on location (land or sub-sea) but should include: Process stream monitoring: Flow rate (oil, water, gas), water cut, temperature, pressure, dissolved gases (e.g. mole % CO 2, H 2S etc.), water chemistry, iron counts, production chemical additions (rate and type) and solids production. Flow regime predictions should be carried out using these data. Well intervention programmes also also should be recorded (wireline operations, acid squeezes, reservoir fracturing etc.). Corrosion monitoring: Subsea: The monitoring methods applicable sub-sea are very limited. At present only the Field Signature Method (FSM) (full details are given in the Corrosion Monitoring Manual p. 53) is commercially available. The FSM method can be hard-wired back to the central facility or can be installed as a stand alone device with satellite communications. However, the cost of a sub-sea sub-sea FSM is high (>£250,000). (>£250,000). A system based on flexible UT mats is under development and may be commercially available in 1997.
Weight loss coupons, ER probes and electrochemical probes can be fitted at the top of sub-sea risers. risers. However, these will only give information about corrosion corrosion in the riser riser itself. The riser conditions are not likely to be representative of those in the flowline. Land lines: Land lines fall into two categories, buried or raised. For buried lines the methods for corrosion monitoring on the line are restricted to FSM. Flexible UT mats may also be possible (UT mats are to be used in Colombia in 1996 on buried lines, using pipeline data transmission). However, the monitoring at the wellhead will be similar for both types (buried or raised). For raised lines it is recommended that a combination of flush and intrusive probes are used. The choice of probe type and location will depend on the conditions. The choice of methods will also depend upon the system but should always include weight loss coupons (to provide information on general and localised attack). These can be sited both at the wellhead and at at the processing facility to give information regarding changes in potential corrosivity through the flowline. At the wellhead, wellhead, intrusive intrusive coupons can be used as the fluids will will be well mixed. Further down the line line flush coupons may be preferred so as to reflect the corrosivity of any separated water.
30
CORROSION METHODS: A SYSTEM BY SYSTEM APPROACH
The coupon data can be supported by other on-line monitoring methods. The primary choice would be ER probes but but in high water cuts this could be supplemented by electrochemical methods for more detailed studies. The ER probe probe type will depend upon location (as for coupons). However, a flush probe mounted in a bottom of line location would be preferred for corrosion monitoring in low water cut flowlines. The on-line probe data can also be supported by inspection type methods such as automated automated ultrasonics. This type of monitoring should concentrate on areas of high risk i.e. where water may separate: at bends, “Tees”, elevation or direction changes where turbulence is at the highest or where erosion may be a problem. If solids (sand) production is known to occur then data on erosion can be obtained by using corrosion resistant ER probes (i.e. a probe which will not corrode but which will erode at a similar rate as the pipe material). Oil Export Lines
Export lines fall into two categories, those carrying partially stabilised crude oil and those carrying fully stabilised crude oil. Partially stabilised crude oil is where the offshore processing only goes down to an intermediate pressure and final separation is completed onshore. As some CO 2/H2S remains, the fluids are still corrosive and therefore careful corrosion corrosion control and and monitoring are required. required. Most North Sea lines fall into this category. Fully stabilised crude crude oil is where the oil has been processed down to atmospheric pressure and possibly stored in tanks. This type of line generally has a significantly lower risk of corrosion and so less exhaustive control and monitoring are necessary. In either case it is vital to maintain good control of export fluid quality and also to monitor any excursions in the water content. With export lines, access can be extremely restricted and so monitoring is often limited to either end of the pipeline, although the FSM method can be used to monitor subsea or buried lines. lines. Remember that riser riser conditions may not not be representative of the main pipeline. For export lines reliance should always be placed on internal inspection using intelligent pigs. Figure 10 summarises the basic corrosion monitoring requirements.
31
CORROSION METHODS: A SYSTEM BY SYSTEM APPROACH
Figure 10 Corrosion Monitoring Requirements for Oil Export Lines.
System
Monitoring
Corrosion Monitoring - Co Coup upon ons s - Electr Electrical ical resistance resistance methods methods - flush / intrusiv intrusive e probe probe type - FSM - Auto UT /Flexible /Flexible UT mats - Electr Electrochem ochemical ical method methods sc - flush / intrusiv intrusive e probe probe type
Oil Export Lines
Process stream Monitoring - Flow rate rate (oil, water water,, gas) - Flo Flow w reg regime ime - Wa Wate terr cut cut - Temp empera eratur ture e - Pr Pres essu sure re - Mo Moll % CO2 - Wa Water ter chemis chemistry try - Iro Iron n cou counts nts - Produ Production ction chemical chemical addition addition - dede-emu emulsi lsifie fierr - scale inhib inhibitor itor - corro corrosion sion inhi inhibitor bitor - depl deploymen oymentt method / rate rate - Well inter interventio ventions ns - scale squee squeezes, zes, - acidi acidisation sation etc. - Par Particula ticulate te productio production n - san sand d rat rates es - Bac Bacter terial ial level level - bioci biocide de treat treatment ment - Sessi Sessile le (<) & plankton planktonic ic (<) counts
c) Electrochemical methods require water wetting and conductivity. Can only be used reliably in water cuts above ca. 10-20% or perhaps higher depending on the precise flow regime, e.g. stratified stratified flow enables more reliable reliable use of a bottom of line probe compared to turbulent flow. flow. Each case has to be assess ed individually.
The main mechanism is usually CO 2 corrosion and the same factors that apply to flowlines will apply here. The biggest difference difference between the two is that the water cut is usually below 2% in oil export lines and therefore detection can be difficult as corrosion will only occur where water separates from the crude oil and contacts (i.e. water-wets) the pipe wall. The old 32” Forties subsea export line suffered significant corrosion which was not detected by conventional monitoring methods although it had generally been operating at water water cuts below 2%. It appears that the the monitoring points stayed oil-wet whilst the corroded areas became water-wet.
Process stream monitoring: Flowrate (oil, water), water cut, temperature, pressure, dissolved gases (e.g. mole % CO 2, H 2S etc.), water chemistry, iron counts, production chemistry additions, 3rd party entrants, and solids production. Flow regime predictions should be carried out using these data.
32
CORROSION METHODS: A SYSTEM BY SYSTEM APPROACH
Corrosion monitoring: It is recommended that for low water cut lines only flush flush mounted probes probes are used. The choice of method will depend upon the system but should always include weight loss coupons (to provide information on both general and localised attack). These should be situated at different different parts of the system so as to reflect changes in corrosivity throughout the system. The coupon data can be supported by other on-line monitoring methods. The primary choice would be ER probes located at the bottom of line, preferably flush mounted. The use of electrochemical methods would only be recommended at water cuts in excess of ca 10-20% which are unlikely to be found in an export line.
33
References
Main Webster, Webster, S and Woollam, R C, “Corrosion Monitoring Manual : A document Comprehensive Guide to Corrosion Monitoring in Oil and Gas
Production and Transportation Systems”, Sunbury Report No. ESR95ER053, dated November 1996. 1.
Trewh Trewhell ella, a, M, “An Assess Assessmen mentt of of the the Cost Costss of Corros Corrosion ion to the the BP Group”, 1989.
2.
Mari Marine ne Offs Offsho hore re Mana Manage geme ment nt Ltd. Ltd.,, Aberd Aberdee een n “BP Exp Explo lora rati tion on Costs of Corrosion 1990 to 1992”, 1993.
3.
LRIM, LRIM, “Criti “Critical cality ity Assess Assessmen ments” ts”,, King Kingss C Clos lose, e, 62 Huntly Huntly street street,, Aberdeen AB1 1RS.
4.
Tishuk Tishuk Ente Enterpr rprise isess [UK] [UK] Ltd, Ltd, “Opera “Operatio tional nal Critic Criticali ality ty Asse Assessm ssment ents”, s”, 52 Regent Quay, Aberdeen, AB1 2AQ.
5.
RP 6-1, 6-1, “Cor “Corro rosi sion on Moni Monito tori ring ng”, ”, Augu August st 1993 1993
6.
Ovstetu Ovstetun, n, I et.al. et.al. “Proce “Procedur dure e for Remova Removall and Instal Installat lation ion of Corrosion Monitoring Equipment”, Document No. 9.71.024 BPX Norway.
7.
RP 42-1, 42-1, “Pipin “Piping g Syste Systems” ms”,, (Issu (Issue e date date 1989) 1989) (rep (replac laces es BP CP 12). 12).
8.
Groves Groves,, S, “Elast “Elastome omerr Sele Selecti ction on Guidel Guideline ines”, s”, Sunbur Sunbury y Repo Report rt No. No. ESR.93.ER151, dated 16/12/9
9.
Webster ebster,, S and Smith, Smith, J T A, “A “A Compa Comparis rison on of of Corro Corrosiv sivity ity with with Operational Parameters for the Wytch Farm Sea Water Injection System 26-30 November 1994”, Report No. ESR.94.ER.120.
10.
LRIM, LRIM, “CORTR “CORTRAN AN (COrro (COrrosio sion n TRend TRend ANalys ANalysis) is)”” Kings Kings Close, Close, 62 Huntly Street, Aberdeen, AB1 1RS
11.
“PREMI “PREMISS (Proces (Processs Recordi Recording ng & Energy Energy Manage Managemen mentt Informa Informatio tion n System)”, MDC, Premier House, Startforth Road, Middlesborough, Cleveland TS2 1PT.
12.
Mentor Mentor,, CML, Real Real Time Time Corro Corrosio sion n Managem Management ent Ltd, Ltd, Ruther Rutherfor ford d House, Manchester Science Lab, Manchester M15 6SZ.
13(a)Smith, J T A, “Minimising Corrosion of Carbon Steel in Sea Water Injection 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 in Water Water Injection Systems”, Sunbury Report No. ESR.96.ER.074, Dated August 1996.
35
Appendix 1: Monitoring Technique Definitions
Abbreviation
Technique
Required Water Cut
Definition
LPR
Linear polarisation resistance
greater than ca 10-20%
ER
Electrical resistance
not a requirement
Direct measure of material loss from a probe by monitoring changes in resistance of probe element. Probe inserted into line through access fitting.
FSM
Field Signature Method
not a requirement
Commercial system which monitors changes in pipe wall thickness using the same principle as the ER probe but applied to a full pipe. No probe required. Uses a spool piece or external installation.
UT
Ultrasonic thickness measurement
not a requirement
Monitors thickness of pipe wall using an ultrasonic source.
FM
Flexible UT mats
not a requirement
Ultrasonic device which measures changes in pipe wall thickness. The device is fixed permanently to be area being monitored.
WL
Weight loss coupon
not a requirement
Direct measure of material loss by measuring changes in weight of a corrosion coupon. Coupons inserted into line through access fitting.
EN
Electrochemical noise
greater than ca 10-20%
Indirect measurement of corrosivity using a complex electrochemical technique. Data analysis very difficult, time consuming and uncertain.
Indirect measurement of corrosivity using electrochemical method. Probe inserted into line through access fitting.
37
Appendix 2: Conversion of Units
kilometre foot bar
= = =
0.621 mile 0.305 metr e 14 psi
pound mil per year (mpy) dollar
= = =
0.454 kilogram 0.0254 mm per year 0.625 pound sterling (Q2 1996)
39
