Corrosion Monitoring

CCORROSIONORROSION MMONITORINGONITORINGININ OOILIL & G& GASAS IINDUSTRYNDUSTRYININ OOILIL & G& GASAS IINDUSTRYNDUSTRY

SEONYEOB LI

GS ENGINEERING & CONSTRUCTION, CO., LTD.

PLANT PROCESS ENGINEERING TEAMPLANT PROCESS ENGINEERING TEAM21 JUNE 2012

CAUSES OF FAILURE IN REFINING & PETROCHEMICAL PLANTS IN JAPAN (2004)PETROCHEMICAL PLANTS IN JAPAN (2004)

“Comparing the 2004 survey results with data from a similar 1984 survey Source: R.D. Kane, Chemical Engineering, June 2007

Comparing the 2004 survey results with data from a similar 1984 survey shows the situation appears unchanged over the past 20 years.”

MATERIAL SELECTION - REALITY

Compromise between expensive CRA’s and less expensive, more available metal susceptible to corrosionsusceptible to corrosion.

Corrosion of CRA’s during upset conditions A more proactive (realtime) approach to corrosion mitigation is needed, e.g.,

corrosion monitoring

WHAT IS “CORROSION MONITORING”?

The practice carried out to assess and predict the The practice carried out to assess and predict the corrosion behavior in operating plant and equipment

DEVELOPMENT OF MONITORING PLAN

1. It shall be included in the detailed design stage of plant and facilities.

2. Corrosion Risk Assessment (system by system base)1) Process stream parameters1) Process stream parameters2) Specific corrosion mechanisms or modes of attack likely to occur3) Corrosion rate estimation4) Consequences of system failures

3 Development of corrosion monitoring plan3. Development of corrosion monitoring plan1) Monitoring system design including types, locations and orientation2) Prescribed monitoring frequency3) Monitoring procedures4) Allocation of responsibility

OBJECTIVES OF CORROSION

MONITORINGMONITORING

Diagnosis of corrosion problem Monitoring corrosion control methods Advanced warning of system upsets leading to corrosion damage Invoking process control Invoking process control Determination of inspection and/or maintenance schedules Estimating service life of equipmentg q p

CORROSION MONITORING SYSTEM DESIGN

Design process included the establishment of the type, location and orientation of devices and sampling ports in the facility.

PROBE LOCATION – GENERAL RULES

Positions where water will condense, pool or impinge. For long horizontal pipe runs, e.g., at the bottom of a pipeline In fluid streams with suspended solids, there is a risk of solids accumulating in the

access fitting located in positions between 3 and 9 O’clock, which cause probe sealing problemsproblems.

Positions of special sensitivity where turbulence, velocity mixing, temperature of H b f pH etc. may be of concern. Access fitting should be located a minimum distance of seven pipe diameters

downstream and a minimum of three pipe diameters upstream of any changes in flow caused by bends reducers valves orifice plates thermowells etccaused by bends, reducers, valves, orifice plates, thermowells, etc.

If access fittings are installed in pairs there should be a minimum distance of 1 m (3 ft) between each fitting.

If the monitoring devices are intrusive and comprise a probe and a coupon holder the If the monitoring devices are intrusive and comprise a probe and a coupon holder, the probe should be located in the upstream fitting to minimize turbulence around the second monitoring device.

PROBE LOCATION – GENERAL RULES

Positions where upsets may occur, i.e., after chemical injection, acid concentration or separation concentration or separation. Production chemicals, corrosion inhibitors, scale inhibitors, oxygen scavengers, etc. “Corrosion monitoring devices should be placed at a minimum of five pipe diameters

downstream of treatment chemical injection points ”downstream of treatment chemical injection points.

Positions where there are concentrations of corrosive species. Positions where abrupt changes occur such as plant metallurgy, process fluids, etc.

Positions where process stream change such as pressure, temperature, flow rate, etc.are prevalent.

Positions where from experience the highest corrosion rates would be expected.

LOCATIONS - GUIDELINES

NACE RP 0775“In lines handling wet gas water can accumulate at changes in the line elevation as depicted in Figure 8In lines handling wet gas, water can accumulate at changes in the line elevation as depicted in Figure 8.Corrosion may be accelerated where water has accumulated. Coupons in such systems must be locatedwhere they will be water‐wet to correlate with corroding areas. Coupons located in the vapor phasecould indicate only slight corrosion when water‐wet areas are corroding severely.”

LOCATIONS – NACE RP0497

EXAMPLE OF PROBE INSTALLATION

(FOR COLUMN TRAY MONITORING)(FOR COLUMN TRAY MONITORING)

PROBE LOCATION

MONITORING DEVICE ACCESS

The probe and coupon monitoring devices should be available without th d t h t d th f ilitthe need to shut down the facility. For systems of less than 10 bar(g) (150 psig), low pressure DN 25 (NPS 1)

access fittings can be employed. For high pressure systems, 10‐137 bar(g) (150‐2 000 psig) this shall be

achieved by the use of proprietary DN 50 (NPS 2) access fittings.

Selected location shall have adequate clearance for the operation of the Selected location shall have adequate clearance for the operation of the retrieval tool; otherwise, the access fitting is unusable.

CORROSION DATA QUALITY

Generally, the information from a single type of corrosion monitoring method should not be relied upon to provide a full understanding of the method should not be relied upon to provide a full understanding of the corrosion environment of interest.

For any monitoring program, control checks should be included to ensure reliability of the datareliability of the data. Duplicate devices Correlation with inspection results Comparison between direct and indirect monitoring data Correlating data with visual inspection results taken out of service

Validation If important damage mechanisms are transient, does the monitoring device

identify and/or record them? If timely awareness of excessive corrosion rates or excessive metal loss is

needed, is the monitoring device providing information in the right time scale? Is the monitoring system identifying the morphology of interest?

GENERAL GUIDE ON APPLICATION OF

CORROSION MONITORINGTECHNIQUES

eigh

tlos

s up

on

pro

bes

R pr

obes

ld Signa

ture

etho

d (FSM

)

ndMon

itorin

g vice

s

lvan

icpr

obes

drog

en pro

bes

tch

6 solved gas

ses

solved so

lids

cteria

onito

ring

We

cou

ER

LPR

Fie

Me

San

Dev

Gal

Hyd

pat

pH Dis

Dis

Bac

mo

Seawater injection and cooling system ○ ○5 ○4 ○ ○ ○ X ○ O2 ○ ○

Produced water treatment and injection systems ○ ○ ○ ○ ○ X ○ ○ O2, CO2, H2S ○ ○

Aquifer water ○ ○ ○1 ○ ○ X X ○ CO2, H2S ○ ○q ○ ○ ○1 ○ ○ ○ O2, 2 ○ ○

Effluent water ○ ○ ○ ○ X ○2 X ○ O2 ○ ○

Boiler feedwater and stream condensate ○ ○ ○ ○ X ○2 X ○ O2 ○ X

Multiphase flow with water ○ ○ ○3 ○ ○ ○2 ○ ○ X ○ ○

Unstabilized crude oil ○ ○ X ○ X X ○ X CO2, H2S X X

Hydrocarbon gas ○ ○ X ○ X X ○ X X X X

Fractionation units, CDU, and pipework ○ ○ X ○ X X ○ X O2 X X

FCCU reactor col mns ○ ○ X ○ X X ○ X X X XFCCU, reactor columns ○ ○ X ○ X X ○ X X X X

Solvent extraction units, amine/caustic treaters and piping ○ ○ X ○ X X X ○ O2 X X

Vacuum towers, regenerators, process units, and pipework ○ ○ X ○ X X X ○ O2 X Xp p

Storage vessels/tanks with separated water bottoms ○ ○ X ○ X X X ○ CO2, H2S X ○

○ : possible application, X: Not applicable, 1: Depends on water quality. Unsuitable if there is low ion content, strong scaling tendency, or other forms of electrode contamination are possible2: may be used if oxygen content are high, 3: only in water cuts above ca. 10%‐20%, 4: Depends on water quality. Unsuitable if there is biofliming tendency5: Intrusive probe preferred. Flush mounted probe unsuitable if there is biofilming tendency, 6: only in aqueous phase is present

Source: BP GP 06-70

TYPES OF MONITORING METHODS

Direct*1 Indirect*1

Intrusive*3Corrosion couponsElectrical resistance (ER)Linear polarization resistance (LPR)

On‐line pH or water analysisInternal hydrogen flux probes

Non‐intrusive

Ultrasonic testingRadiographyExternal hydrogen flux probesAnalysis of water samples obtained y pthrough an existing valveSurface patch hydrogen probes

*1To measure a direct result of corrosion.*2To measure an outcome of the corrosion process*3To require entry into the process stream

Of th t h i li t d b i ER d LPR f th f i d t i l i Of the techniques listed above, corrosion coupons, ER and LPR form the core of industrial corrosion monitoring systems.

MONITORING METHODS

Corrosion coupon

LPR probe

Bioprobe for monitoring bacteria

17Electrical resistance probe

Source: Alabama Specialty Products, www.metalsamples.com

FLUSH TYPE VS. INTRUSIVE TYPE

18

DIRECT INTRUSIVE TECHNIQUES

Flush mounted monitoring device Simulation of processes that occur at the wall surface. Corrosion in low water cut situations (wet oil), water dropout (wet gas),

under‐deposit corrosion, and areas where water condenses. Susceptible to fouling (can be ignored in turbulence locations)

Intrusive probes Intrusive probes Overall corrosivity of streams rather than more specific environments Process upsets in a single phase, high wall shear stresses, “

worst case” situations For clean water steams Cannot be used in lines that are pigged, or must be drawn before pigging.p gg , p gg g

CORROSION (WEIGHT LOSS) COUPONS( )

The method involves exposing a specimen of material of interest (the coupon) to a process environment for a given duration, then removing the specimen for analysis. process environment for a given duration, then removing the specimen for analysis.

The basic measurement is weight loss; the weight loss taking place over the period of exposure being expressed as corrosion rate.

The simplicity of the measurement is such that the coupon technique forms the baseline method of measurement in many corrosion monitoring programs.

Typically, a 90‐day duration test (for pressure retrieval coupons), which gives basic corrosion rate measurements as a frequency of four times per year. NACE RP0497: a minimum exposure duration (h) = 50/[expected corrosion rate (mm/y)] Shutdowns or process interruption Shutdowns or process interruption

ASTM G58“C” Ring – ASTM G38C Ring ASTM G38

INHIBITOR COMPARISON

USING COUPONS (OIL WELL)USING COUPONS (OIL WELL)

FLOW

35 ppm 25 ppm

Oil Soluble Chemical

35 ppm

Water Soluble Chemical

CORROSION RATE

FROM COUPON DATAFROM COUPON DATA

Simplest and most reliable technique for corrosion rate determination is th W i ht L T h ithe Weight Loss Technique.

Corrosion Rate = [mass loss]/[(exposed surface area] ∙ [time])por

= Average corrosion penetration depth/time= (mass/density/surface area/time) (mass/density/surface area/time)

Common Corrosion Rate Units gmd: grams of metal loss per square meter per day (mdd) mm/y: average millimeters penetration per year mpy: average mils penetration per year 1 mil = 0 001 inch) mpy: average mils penetration per year, 1 mil 0.001 inch)

NACE RP 0775 -CORROSION RATES GUIDELINESCORROSION RATES GUIDELINES

lGeneral(mm/y)

Max. Pitting(mm/y)

CorrosionRating

< 0.025 < 0.13 Low

0.025 – 0.12 0.13 – 0.20 Moderate

0.13 – 0.25 0.21 – 0.38 High

> 0.25 > 0.38 Severe

CORROSION COUPONS

Advantages Disadvantages

Inexpensive, easily applied Corrosion rate averaged over exposure time

Coupon made of materials similar to pipe or vessel Corrosion rate calculation assumes uniform corrosion

Visual inspection identifies mode of corrosion attack Data generation slow (long exposure times)

Samples available for scale or surface deposit analysis

Requires insertion and retrieval under pressure or at a turnaround

Sources of microbiological data

Applicable to all environments

TYPICAL CORROSION MORPHOLOGY (SOIL)

Stray current corrosion

Corrosion in oxygen‐rich (aerobic) soil

Microbiologically influenced corrosion In anaerobic soil

25

EDS ANALYSIS OF CORROSION COUPON

3000

MIC2000

3000

O 부식생성물

Si

1000

FeCa

SAl

Inorganic corrosion

3000 0 1 2 30

일반부식생성물

Ca

Inorganic corrosion2000

Fe

O

0

1000Ca

SSi

0 1 2 3keV

AVERAGE CORROSION RATE VS. INSTANTANEOUS CORROSION RATEINSTANTANEOUS CORROSION RATE

TYPES OF PITTING (ASTM G46)( )

Ratio of maximum localized corrosion rate to general corrosion rate determined by mass g yloss (pitting factor) Pitting of SS Velocity‐accelerated corrosion

Percent of corrosion‐affected area on the coupon

ELECTRICAL RESISTANCE (ER) PROBE( )

Measures the change in electrical resistance of a corroding metal l t l ti t f di l t l d ithi th elements relative to a reference non‐corroding element sealed within the

probe body.

LAL

R

ER PROBE TYPES (CORROSOMETER®)( )

Velocity shield

ER PROBE

TRADEOFF BETWEEN SENSITIVITY AND

SENSOR LIFE IN COMMERCIAL ER PROBESENSOR LIFE IN COMMERCIAL ER PROBE

Wire type: loss of a quarter of thickness

Other types: loss of a half of thickness

ER PROBE

Recommended measurement interval

ER PROBE


Direct measurement of metal loss Sensitive to thermal change

Will work in most environments: does not require continuous aqueous phase(suitable for multiphase non aqueous environments)

Corrosion rate calculated as uniform corrosion. No information on localized corrosion

(suitable for multiphase, non‐aqueous environments)

Quicker response than corrosion coupons Manual readings subject to signal noise (probe connections)

Continuously logged probes give high quality data Crevice corrosion can occur on poorly constructed Continuously logged probes give high quality data (logging rate as low as 5 min)(trends and changes in corrosion activity)

Crevice corrosion can occur on poorly constructed flush‐type probes

Meter output is in cumulative metal loss. Slope of Requires insertion and retrieval under pressure data needed to calculated corrosion rate which can have safety implications

High sensitivity type probe is available.(Takreer RRE #2)

Requires several days to determine a reliable corrosion rate trend

N di l t b d Ad l ff t d b d ti lfid fil Non‐corroding elements can be used as pure erosion monitor.

Adversely affected by conductive sulfide film corrosion products where H2S is present

APPLICATIONS OF ER PROBE

Oil and gas production Gas sweetening, storage, and transportation systems Refineries and petrochemical plants Inhibitor evaluation/optimization programs Inhibitor evaluation/optimization programs Power plants—for cooling water, feedwater, and scrubber systems. In

bag houses and stacks for special function such as dew point alarming in flue gas systems

Chemical processes Cathodically protected systems Cathodically protected systems Air‐cleaning systems in control rooms Paper mills or other plants with a volatile inherently corrosive process p p y p

stream

SAND PROBE

ELECTROCHEMICAL CORROSION MONITORING

Linear polarization resistance (LPR) –선형분극(저항)법 Potential monitoring Zero‐resistance ammetry (ZRA); galvanic current measurements Electrochemical impedance spectroscopy (EIS) Electrochemical impedance spectroscopy (EIS) Electrochemical noise (EN)

ELECTROCHEMICAL CORROSION

MONITORINGMONITORING

Corrosion in an electrochemical process that can be monitored by i t ti l & t th t h t i th i measuring potential & current that characterize the corrosion process.

CORROSION RATES AND POLARIZATION

POTENTIODYNAMIC POLARIZATION CURVE

LINEAR POLARIZATION RESISTANCE (LPR) METHOD

Within ~10mV more noble or active than the Ecorr,, i is a linear function of the electrode potential.

iapp = |ia‐ic| = f(E)E

E

pp

E = Eapp ‐ Ecorr

= alog ia/io,M ‐ alog icorr/io,M= a log ia/icorr l

Ecorr

Eappic ia

= a/2.303 ln ia/icorr

ia = icorr e2.303E/a

io,a log i

Similarly, ic = icorr e‐2.303E/c

o,a g

iapp = ia ‐ ic = icorr (e2.303E/a – e‐2.303E/c )= icorr (2.303E/a + 2.303E/c)

= 2.303icorrE(a + c)/ac = icorrE/BS G i Stern Geary equation

assuming that a = c = 0.12R = E/i = B/i = 0.026/iRp E/iapp B/icorr 0.026/icorr

Rp: polarization resistance.

TYPICAL POLARIZATION RESISTANCE PLOT

FARADAY’S LAW AND CORROSION RATES

MF

Qm

WhereQ = charge (C) = I∙t

nF

g ( )F = Faraday’s constant (96,500 C/eq.)n = number of equivalents (moles of electrons) transferred per mol of metalm = mass of metal corroded (g)m = mass of metal corroded (g)M = molecular (atomic) weight of metal (g/mole)

C i R ( / ) (8 6 4 ) / (A D T)Corrosion Rate (mm/y) = (8.76104 ∙ m) / (A ∙ D ∙ T)

WhereA = Coupon surface area (cm2)D = Material density (g/cm3)T = Time of exposure (hours)p ( )

LPR PROBE

• Gives instantaneous corrosion ratesrates

• Only used in conductive, aqueous solutionsaqueous solutions

• Based on the current flow between two or more electrodesbetween two or more electrodes

• Requires the surface to become polarized and current resistance polarized and current resistance is measured.

• Sometimes probe has a • Sometimes probe has a reference electrode as well.

LPR PROBE – OPERATING RANGE

Close Spaced 3 electrode probes

APPLICATION OF LPR PROBE

Water systems Condensing water systems Oil systems with high water contents

LPR PROBE WITH REMOTE MONITORING

Honeywell’s SmartCET® uses a sensor for background l h l d l helectrochemical noise (EN) to detect pitting along with

LPR probe.

LPR PROBE


Rapid measurement of corrosivity General corrosion rates indicative of trend rather than absolute

Sensitive to any process changes: flow,pressure, temperature, etc.

Continuous water phase requiredpressure, temperature, etc.

Probes are susceptible to fouling by deposits or hydrocarbon phase.

No localized corrosion information

ALGORITHM FOR SUITABILITY OF

ER AND LPR TECHNIQUESER AND LPR TECHNIQUES

OTHERTECHNIQUES

Electrochemical Impedance Spectroscopy (EIS) Electrochemical Noise (EN) Zero‐Resistance Ammetry (ZRA)

GALVANIC PROBE

Measures the current flowing between two dissimilar metal electrodes through a zero resistance ammeter (ZRA).

The magnitude of the current and its direction gives an indication of the corrosivity of the fluid and which material is anodic or cathodic.

Customarily, a pair of steel and brass Sensitive to DO

DO monitoring in East Texas Water Injection StationWater Injection Station

DIRECT NON-INTRUSIVE TECHNIQUES

Field signature method (FSM)

NDT methods NDT methods

RT IMAGE - EXAMPLE

54

INDIRECT ON-LINE TECHNIQUES

Hydrogen monitoring Acoustic solid particle detectors Water chemistry parameters Process parameters Process parameters

HYDROGEN FLUX MONITORING

Hydrogen‐related problems Blistering HIC SOHIC SSC

Hydrogen probe to monitor hydrogen absorption by steel I i (fi b ) P d i Intrusive (finger probes) – Pressure detection Non‐intrusive – electrochemical probe

Provision of a good measure of hydrogen activity

HYDROGEN PROBE

WATER & PROCESS PARAMETERS

Water chemistry parameters pH Oxidation‐reduction potential (ORP) Dissolved oxygen (DO) contentyg ( ) Conductivity

P t Process parameters Pressure temperature

INDIRECT OFF-LINE TECHNIQUES

Water chemistry parameters Dissolved solids analysis (API RP 45) Dissolved solids analysis (API RP 45) Metal ion corrosion analysis (NACE RP0192 – iron count analysis) Dissolved gas analysis

O2, CO2, H2S Test kits or laboratory analysis

Bacterial Monitoring Planktonic bacteria (API RP38 SRB) Planktonic bacteria (API RP38‐SRB) Sessile bacteria (NACE TM0194)

Chemical Analysis Chemical Analysis Sulfur content (ASTM D4294) TAN (ASTM D664, D974, UOP method 565, 587) Nitrogen content (ASTM D3228) Salt content in crude oil (ASTM D3230) Mercury (ASTM D6350)

CORROSION MONITORING IN

CRUDE UNIT OVERHEADSCRUDE UNIT OVERHEADS

Methods Water analysis (overhead) Water analysis (overhead)

pH Fe content Chlorides (water in overhead receiver) – base for optimization of caustic ( ) p

injection/blending of crudes Hardness – CW quality, precipitation at overhead (water washing)

Hydrocarbon analysisd l f f l h b Residual test of filming inhibitor (3‐5 ppm)

Metal analysis of oil (for NAC control) Corrosion rate measurements

ER probe ER probe LPR probe – overhead receiver water drum Corrosion coupon

NDT (on‐stream)( ) UT, RT When there is a confirmed or suspected problems

CORROSION MONITORING IN ADU

LPR

ER

Crude unit desalter Crude oil preheat exchangers & piping Tower

ER

Tower Tower overhead Overhead piping and condensers – water condensation + acid chlorides not neutralized and/or

inhibited.

CORROSION MONITORING

IN CRUDE UNIT OVERHEADSIN CRUDE UNIT OVERHEADS

Corrosion Probes Statistics (example) NACE Survey (1983) A breakdown of monitoring practices (129 CDU across 44 companies

worldwide)

ER Probes (CORROSOMETER) 59% LPR Probes (CORRATER) 1% LPR Probes (CORRATER) 1% Corrosion Coupons (COSASCO type) 17% None of above (?) 23%

CORROSION MONITORING IN ADU/VDU

At sites of condensation of acidic chloride in the distillate drum boot and the ejector inter‐condenser collector drum.

Areas susceptible to naphthenic acid corrosion (NAC, 500‐700F) such as VDU preheater, shell and trays of tower transfer line column side stripper gas oil circuitstower, transfer line, column side stripper, gas oil circuits.

In regions of condensation found inside of the column. High sulfur corrosion (bottom)

High temperature cylindrical element probes of the retractable types High temperature cylindrical element probes of the retractable types

CORROSION MONITORING IN FCCU

Reactor & regenerator g High temperature (900‐1200oF) Not by probes, but by UT or visual inspection

Corrosion probes Fractionator overhead system side stripper Fractionator overhead system, side stripper Effluent piping of the compressor after coolers

CORROSION MONITORING IN CLER UNIT

Chemical Test CN‐ and SCN‐ content in wastewater stream pH (high pressure condensate) for water wash control

Corrosion probes Condenser/cooler bunldes (high pH corrosion of Cu alloys) Condenser/cooler bunldes (high pH corrosion of Cu alloys) Heat exchanger effluents in gas compression system Debutanizer overhead system, etc.

Hydrogen monitoring Probe Sour water lines Different elevation of the absorber/stripper tower Different elevation of the absorber/stripper tower Vapor/liquid interface area of the high‐pressure separator drum

HIGH PRESSURE ACCESS FITTING FOR A

RETRIEVABLE PROBERETRIEVABLE PROBE

COUPON INSTALLATION INTO HIGH

PRESSURE LINEPRESSURE LINE

67

CORROSION MONITORING SYSTEMS

Use of Portable CorrosometerTM Instrument f M i C i f Sh ll id f H t E hfor Measuring Corrosion of Shell-side of Heat Exchanger

ON-LINE THICKNESS MEASUREMENTS

Source: Hydrocarbon Processing, March 2012, pp.35-37

ASSESSMENT OF CORROSION INHIBITOR

PERFORMANCE FOR MEG REBOILERPERFORMANCE FOR MEG REBOILER

Temp. : 140oC

0.3250.3500.3750.400

solution : EG + inhibitor

Ar blowing (+ NaCl 16%) Air blowing (+ NaCl 16%)Ar blowing

0.2250.2500.2750.300

EG:waterr

g Air blowing

0 1000.1250.1500.1750.200

EG:water

60:40

78:22m

m/y

r

0.0000.0250.0500.0750.100

22 24 26 28 30 32 34 36 38 40 42

water %

LPR (CASE STUDY – HONEYWELL)( ) River Water Analysis

Chemical Treatment Program

Cycled Water Analysis

LPR (CASE STUDY – HONEYWELL)( )



EXAMPLE – EFFECT OF UNSTABLE OPERATION

Source: N.P. Hilton, Hydrocarbon Processing, March 2012, 49.

ON-LINE MONITORING

MONITORING STRATEGY

CORROSION AS A PROCESS CONTROL VARIABLE!

REFERENCES

1) R.D. Kane, Chemical Engineering, June 2007, 34.2) Coursebook for Corrosion Control in the Refining Industry, NACE International, July 2011.) S f C i C i J C i C f C i i J J S i f C i E i i (JSCE) 3) Survey of Corrosion Cost in Japan, Committee on Cost of Corrosion in Japan, Japan Society of Corrosion Engineering (JSCE),

March 2001.4) Alabama Specialty Products, www.metalsamples.com.5) NACE RP0775, Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations, 2005.6) NACE RP0497, Field Corrosion Evaluation Using Metallic Test Specimens, 2004.7) ASTM G4 “Standard Guide for Conducting Corrosion Coupon Tests in Feld Applications”8) ASTM G46 “Standard Guide for Examination and Evaluation of Pitting Corrosion”9) ASTM G102 “Standard Practice for Calculation of Corrosion Rates and Related Information from Electrochemical

Measurements.” 10) Coursebook for Corrosion Basics, NACE International, Jan 2003.11) P.R. Roberge, Handbook of Corrosion Engineering, McGraw‐Hill, 2000.12) P.A. Schweitzer, Corrosion of Linings and Coatings – Cathodic and Inhibitor Protection and Corrosion Monitoring, CRC Press,

2007. 1) NACE Publication 3T199 “Techniques for Monitoring Corrosion and Related Parameters in Field Applications,” NACE

International, 1999.2) NACE Publication 3D170 ““Electrical and Electrochemical Methods for Determining Corrosion Rates,” NACE International13) Application Note AN 107, Corrosion Monitoring in Crude Unit Distillation Columns, Rohrback Cosasco Systems, Inc., April 1990.14) J. Gutzeit, Crude Unit Corrosion Guide – A Complete How‐To Manual, PCC, 2004.15) Application Note AN 109, Corrosion Monitoring in Fluid Catalytic Crackers (FCC), Rohrback Cosasco Systems, Inc., April 1990.16) K. Wold and R. Stoen, Monitoring Internal Corrosion in Pipelins, ASTME India Oil & Gas Pipeline Conference, GOA, February ) , g p , p , , y

2011.17) Operating Manual for Model CET5000, Series SmartCET Corrosion Monitoring Transmitter, Honeywell, July 2006.18) P. Collins, Hydrocarbon Processing, March 2012, 35.19) Guidance on Practice for Corrosion Monitoring, Engineering Technical Practices GP 06‐70, BP Group, 2005.

QUESTIONS?QUESTIONS?

Corrosion Monitoring

Documents