Corrosion Monitoring
Content
CORROSION MONITORING
IN
OIL & GAS INDUSTRY
SEONYEOB LI GS ENGINEERING & CONSTRUCTION, CO., LTD.
PLANT PROCESS ENGINEERING TEAM
21 JUNE 2012
CAUSES OF FAILURE IN REFINING & PETROCHEMICAL PLANTS IN JAPAN (2004)
“Comparing the 2004 survey results with data from a similar 1984 survey Comparing the 2004 survey results with data from a similar 1984 survey shows the situation appears unchanged over the past 20 years.”
Source: R.D. Kane, Chemical Engineering, June 2007
MATERIAL SELECTION - REALITY
Compromise between expensive CRA’s and less expensive, more available metal susceptible to corrosion. susceptible 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 corrosion behavior in operating plant and equipment
DEVELOPMENT OF MONITORING PLAN
1. 2.
It shall be included in the detailed design stage of plant and facilities. Corrosion Risk Assessment (system by system base)
1) 2) 3) 4)
Process stream parameters Specific corrosion mechanisms or modes of attack likely to occur Corrosion rate estimation Consequences of system failures
3. 3
Development of corrosion monitoring plan
1) 2) 3) 4)
Monitoring system design including types, locations and orientation Prescribed monitoring frequency Monitoring procedures Allocation of responsibility
OBJECTIVES OF CORROSION MONITORING
Diagnosis of corrosion problem Monitoring corrosion control methods Advanced warning of system upsets leading to corrosion damage Invoking process control Determination of inspection and/or maintenance schedules Estimating service life of equipment g 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 problems. problems
Positions of special sensitivity where turbulence, velocity mixing, temperature of pH etc. may be of concern. H b f
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, etc. caused 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 8 In gas, 8. Corrosion may be accelerated where water has accumulated. Coupons in such systems must be located where they will be water‐wet to correlate with corroding areas. Coupons located in the vapor phase could indicate only slight corrosion when water‐wet areas are corroding severely.”
LOCATIONS – NACE RP0497
EXAMPLE OF PROBE INSTALLATION (FOR COLUMN TRAY MONITORING)
PROBE LOCATION
MONITORING DEVICE ACCESS
The probe and coupon monitoring devices should be available without
the need to shut down the facility. th d t h t d th f ilit
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
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 corrosion environment of interest. For any monitoring program, control checks should be included to ensure reliability of the data. reliability 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 MONITORING TECHNIQUES
Hyd drogen probes pat tch San Monitoring nd Dev vices Dissolved gasses Gal lvanic probes Dissolved solids ○ ○ ○ ○ ○ ○ X X X X X X X Field Signature Me ethod (FSM) We eight loss cou upon LPR R probes Bac cteria mo onitoring ○ ○ ○ ○ X ○ X X X X X X ○ ER probes
Seawater injection and cooling system Produced water treatment and injection systems q Aquifer water Effluent water Boiler feedwater and stream condensate Multiphase flow with water Unstabilized crude oil Hydrocarbon gas Fractionation units, CDU, and pipework FCCU, reactor columns FCCU reactor col mns Solvent extraction units, amine/caustic treaters and piping Vacuum towers, regenerators, process units, and pp pipework Storage vessels/tanks with separated water bottoms
○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
○5 ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
○4 ○ ○1 ○ ○ ○3 X X X X X X X
○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
○ ○ ○ X X ○ X X X X X X X
○ X X ○2 ○2 ○2 X X X X X X X
X ○ X X X ○ ○ ○ ○ ○ X X X
○ ○ ○ ○ ○ ○ X X X X ○ ○ ○
pH6
O2 O2, CO2, H2S CO2, H2S O O2 O2 X CO2, H2S X O2 X O2 O2 CO2, H2S
○ : 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 possible 2: 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 tendency 5: 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 Intrusive*3 Corrosion coupons Electrical resistance (ER) Linear polarization resistance (LPR) Indirect*1 On‐line pH or water analysis Internal hydrogen flux probes Ultrasonic testing Radiography External hydrogen flux probes Analysis of water samples obtained y p through an existing valve Surface patch hydrogen probes
Non‐intrusive
*1 To measure a direct result of corrosion. *2 To measure an outcome of the corrosion process *3 To require entry into the process stream
Of the techniques listed above, corrosion coupons, ER and LPR f Of th t h i li t d b i ER d LPR form the core of industrial corrosion th f i d t i l i monitoring systems.
MONITORING METHODS
Corrosion coupon
LPR probe
Bioprobe for monitoring bacteria Source: Alabama Specialty Products, www.metalsamples.com Electrical resistance probe
17
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 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. 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
ASTM G58
“C” Ring – ASTM G38 C
INHIBITOR COMPARISON USING COUPONS (OIL WELL)
FLOW
35 ppm Water Soluble Chemical
35 ppm
25 ppm
Oil Soluble Chemical
CORROSION RATE FROM COUPON DATA
Simplest and most reliable technique for corrosion rate determination is
the Weight Loss Technique. th W i ht L T h i Corrosion Rate = [mass loss]/[(exposed surface area] ∙ [time]) p or = 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 GUIDELINES
General l (mm/y) < 0.025 0.025 – 0.12 0.13 – 0.25 > 0.25 Max. Pitting (mm/y) < 0.13 0.13 – 0.20 0.21 – 0.38 > 0.38 Corrosion Rating Low Moderate High Severe
CORROSION COUPONS
Advantages Inexpensive, easily applied Coupon made of materials similar to pipe or vessel Visual inspection identifies mode of corrosion attack Samples available for scale or surface deposit analysis Sources of microbiological data Applicable to all environments Disadvantages Corrosion rate averaged over exposure time Corrosion rate calculation assumes uniform corrosion Data generation slow (long exposure times) Requires insertion and retrieval under pressure or at a turnaround
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
부식생성물
O
2000
Si S Ca Fe
1
MIC
1000
Al
2
일반부식생성물
0 3000 0 3
Inorganic corrosion
2000
O Fe Ca Si
1000
0 0 1
S
2 3
keV
AVERAGE CORROSION RATE VS. INSTANTANEOUS CORROSION RATE
TYPES OF PITTING (ASTM G46) ( )
Ratio of maximum localized corrosion rate to general corrosion rate determined by mass g y loss (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
elements relative to a reference non‐corroding element sealed within the l t l ti t f di l t l d ithi th probe body.
L R A
ER PROBE TYPES (CORROSOMETER®) (
Velocity shield
ER PROBE
TRADEOFF BETWEEN SENSITIVITY AND SENSOR 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
Advantages Direct measurement of metal loss Disadvantages Sensitive to thermal change
Will work in most environments: does not require Corrosion rate calculated as uniform corrosion. continuous aqueous phase No information on localized corrosion (suitable for multiphase, non‐aqueous environments) (suitable for multiphase non aqueous environments) Quicker response than corrosion coupons Continuously logged probes give high quality data (logging rate as low as 5 min) (trends and changes in corrosion activity) Meter output is in cumulative metal loss. Slope of data needed to calculated corrosion rate High sensitivity type probe is available. (Takreer RRE #2) Non‐corroding elements can be used as pure N di l t b d erosion monitor. Manual readings subject to signal noise (probe connections) Crevice corrosion can occur on poorly constructed flush‐type probes Requires insertion and retrieval under pressure which can have safety implications Requires several days to determine a reliable corrosion rate trend Adversely affected by conductive sulfide film Ad l ff t d b d ti lfid fil 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 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 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 noise (EN)
ELECTROCHEMICAL CORROSION MONITORING
Corrosion in an electrochemical process that can be monitored by
measuring potential & current that characterize the corrosion process. i t ti l & t th t h t i th i
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) pp E = Eapp ‐ Ecorr = alog ia/io,M ‐ alog icorr/io,M = a log ia/icorr = a/2.303 ln ia/icorr l ia = icorr e2.303E/
a
E
Eapp Ecorr
ic
ia
io,a
c
log i g
Similarly, ic = icorr e‐2.303E/
a
iapp = ia ‐ ic = icorr (e2.303E/ – e‐2.303E/ ) = icorr (2.303E/a + 2.303E/c) = 2.303icorrE(a + c)/ac = icorrE/B S Stern Geary equation G i
c
assuming that a = c = 0.12 Rp = E/iapp = B/icorr = 0.026/icorr B/i 0.026/i Rp: polarization resistance.
TYPICAL POLARIZATION RESISTANCE PLOT
FARADAY’S LAW AND CORROSION RATES
Q M m nF F
Where g ( ) Q = charge (C) = I∙t F = Faraday’s constant (96,500 C/eq.) n = number of equivalents (moles of electrons) transferred per mol of metal m = mass of metal corroded (g) M = molecular (atomic) weight of metal (g/mole) Corrosion R ( C i Rate (mm/y) = (8.76104 ∙ m) / (A ∙ D ∙ T) / ) (8 6 ) / (A D T) Where A = Coupon surface area (cm2) D = Material density (g/cm3) p ( ) T = Time of exposure (hours)
LPR PROBE
•
Gives instantaneous corrosion rates Only used in conductive, aqueous solutions Based on the current flow between two or more electrodes Requires the surface to become polarized and current resistance is measured. 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 electrochemical noise (EN) to detect pitting along with l h l d l h LPR probe.
LPR PROBE
Advantages Rapid measurement of corrosivity Sensitive to any process changes: flow, pressure, temperature, etc. Disadvantages General corrosion rates indicative of trend rather than absolute Continuous water phase required Probes are susceptible to fouling by deposits or hydrocarbon phase. No localized corrosion information
ALGORITHM FOR SUITABILITY OF ER AND LPR TECHNIQUES
OTHER TECHNIQUES
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 Station
DIRECT NON-INTRUSIVE TECHNIQUES
Field signature method (FSM)
NDT methods
RT IMAGE - EXAMPLE
54
INDIRECT ON-LINE TECHNIQUES
Hydrogen monitoring Acoustic solid particle detectors Water chemistry parameters Process parameters
HYDROGEN FLUX MONITORING
Hydrogen‐related problems Blistering HIC SOHIC SSC Hydrogen probe to monitor hydrogen absorption by steel I Intrusive (finger probes) – P i (fi b ) Pressure detection d i 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) content yg ( ) Conductivity P Process parameters t Pressure temperature
INDIRECT OFF-LINE TECHNIQUES
Water chemistry parameters
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) bacteria (API RP38‐SRB) Sessile bacteria (NACE TM0194)
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 OVERHEADS
Methods
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 analysis Residual test of filming inhibitor (3‐5 ppm) d l ffl hb Metal analysis of oil (for NAC control) Corrosion rate measurements 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 Tower overhead Overhead piping and condensers – water condensation + acid chlorides not neutralized and/or inhibited.
CORROSION MONITORING IN CRUDE UNIT OVERHEADS
Corrosion Probes Statistics (example) NACE Survey (1983) A breakdown of monitoring practices (129 CDU across 44 companies worldwide)
ER Probes (CORROSOMETER) LPR Probes (CORRATER) Corrosion Coupons (COSASCO type) None of above (?)
59% 1% 17% 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 circuits. tower 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
CORROSION MONITORING IN FCCU
Reactor & regenerator g
High temperature (900‐1200oF) Not by probes, but by UT or visual inspection Fractionator overhead system, side stripper Fractionator overhead system side stripper Effluent piping of the compressor after coolers
Corrosion probes
CORROSION MONITORING IN CLER UNIT
Chemical Test
CN‐ and SCN‐ content in wastewater stream pH (high pressure condensate) for water wash control Condenser/cooler bunldes (high pH corrosion of Cu alloys) Heat exchanger effluents in gas compression system Debutanizer overhead system, etc. Sour water lines Different elevation of the absorber/stripper tower Vapor/liquid interface area of the high‐pressure separator drum
Corrosion probes
Hydrogen monitoring Probe
HIGH PRESSURE ACCESS FITTING FOR A RETRIEVABLE PROBE
COUPON INSTALLATION INTO HIGH PRESSURE LINE
67
CORROSION MONITORING SYSTEMS
Use of Portable CorrosometerTM Instrument for M f Measuring Corrosion of Shell-side of Heat Exchanger i C i f Sh ll id f H t E h
ON-LINE THICKNESS MEASUREMENTS
Source: Hydrocarbon Processing, March 2012, pp.35-37
ASSESSMENT OF CORROSION INHIBITOR PERFORMANCE FOR MEG REBOILER
Temp. : 140 C solution : EG + inhibitor
0.400 0.375 0.350 0.325 0.300 0.275 0.250 0.225
o
Ar blowing (+ NaCl 16%) Air blowing (+ NaCl 16%) Ar blowing g Air blowing
mm/yr r
0.200 0.175 0.150 0.125 0.100 0 100 0.075 0.050 0.025 0.000 22 24 26 28 30 32 34 36
EG:water 60:40
EG:water 78:22
38
40
42
water %
River Water Analysis
LPR (CASE STUDY – HONEYWELL) (
Chemical Treatment
Program
Cycled Water
Analysis
LPR (CASE STUDY – HONEYWELL) (
LPR (CASE STUDY – HONEYWELL) (
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) 2) 3) ) 4) 5) 6) 7) 8) 9) 10) 11) 12) 1) 2) 13) 14) 15) 16) ) 17) 18) 19) R.D. Kane, Chemical Engineering, June 2007, 34. Coursebook for Corrosion Control in the Refining Industry, NACE International, July 2011. Survey of Corrosion Cost in Japan, Committee on Cost of Corrosion in Japan, Japan Society of Corrosion Engineering (JSCE), 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) March 2001. Alabama Specialty Products, www.metalsamples.com. NACE RP0775, Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations, 2005. NACE RP0497, Field Corrosion Evaluation Using Metallic Test Specimens, 2004. ASTM G4 “Standard Guide for Conducting Corrosion Coupon Tests in Feld Applications” ASTM G46 “Standard Guide for Examination and Evaluation of Pitting Corrosion” ASTM G102 “Standard Practice for Calculation of Corrosion Rates and Related Information from Electrochemical Measurements.” Coursebook for Corrosion Basics, NACE International, Jan 2003. P.R. Roberge, Handbook of Corrosion Engineering, McGraw‐Hill, 2000. P.A. Schweitzer, Corrosion of Linings and Coatings – Cathodic and Inhibitor Protection and Corrosion Monitoring, CRC Press, 2007. NACE Publication 3T199 “Techniques for Monitoring Corrosion and Related Parameters in Field Applications,” NACE International, 1999. NACE Publication 3D170 ““Electrical and Electrochemical Methods for Determining Corrosion Rates,” NACE International Application Note AN 107, Corrosion Monitoring in Crude Unit Distillation Columns, Rohrback Cosasco Systems, Inc., April 1990. J. Gutzeit, Crude Unit Corrosion Guide – A Complete How‐To Manual, PCC, 2004. Application Note AN 109, Corrosion Monitoring in Fluid Catalytic Crackers (FCC), Rohrback Cosasco Systems, Inc., April 1990. K. Wold and R. Stoen, Monitoring Internal Corrosion in Pipelins, ASTME India Oil & Gas Pipeline Conference, GOA, February , g p , p , , y 2011. Operating Manual for Model CET5000, Series SmartCET Corrosion Monitoring Transmitter, Honeywell, July 2006. P. Collins, Hydrocarbon Processing, March 2012, 35. Guidance on Practice for Corrosion Monitoring, Engineering Technical Practices GP 06‐70, BP Group, 2005.
QUESTIONS?
IN
OIL & GAS INDUSTRY
SEONYEOB LI GS ENGINEERING & CONSTRUCTION, CO., LTD.
PLANT PROCESS ENGINEERING TEAM
21 JUNE 2012
CAUSES OF FAILURE IN REFINING & PETROCHEMICAL PLANTS IN JAPAN (2004)
“Comparing the 2004 survey results with data from a similar 1984 survey Comparing the 2004 survey results with data from a similar 1984 survey shows the situation appears unchanged over the past 20 years.”
Source: R.D. Kane, Chemical Engineering, June 2007
MATERIAL SELECTION - REALITY
Compromise between expensive CRA’s and less expensive, more available metal susceptible to corrosion. susceptible 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 corrosion behavior in operating plant and equipment
DEVELOPMENT OF MONITORING PLAN
1. 2.
It shall be included in the detailed design stage of plant and facilities. Corrosion Risk Assessment (system by system base)
1) 2) 3) 4)
Process stream parameters Specific corrosion mechanisms or modes of attack likely to occur Corrosion rate estimation Consequences of system failures
3. 3
Development of corrosion monitoring plan
1) 2) 3) 4)
Monitoring system design including types, locations and orientation Prescribed monitoring frequency Monitoring procedures Allocation of responsibility
OBJECTIVES OF CORROSION MONITORING
Diagnosis of corrosion problem Monitoring corrosion control methods Advanced warning of system upsets leading to corrosion damage Invoking process control Determination of inspection and/or maintenance schedules Estimating service life of equipment g 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 problems. problems
Positions of special sensitivity where turbulence, velocity mixing, temperature of pH etc. may be of concern. H b f
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, etc. caused 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 8 In gas, 8. Corrosion may be accelerated where water has accumulated. Coupons in such systems must be located where they will be water‐wet to correlate with corroding areas. Coupons located in the vapor phase could indicate only slight corrosion when water‐wet areas are corroding severely.”
LOCATIONS – NACE RP0497
EXAMPLE OF PROBE INSTALLATION (FOR COLUMN TRAY MONITORING)
PROBE LOCATION
MONITORING DEVICE ACCESS
The probe and coupon monitoring devices should be available without
the need to shut down the facility. th d t h t d th f ilit
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
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 corrosion environment of interest. For any monitoring program, control checks should be included to ensure reliability of the data. reliability 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 MONITORING TECHNIQUES
Hyd drogen probes pat tch San Monitoring nd Dev vices Dissolved gasses Gal lvanic probes Dissolved solids ○ ○ ○ ○ ○ ○ X X X X X X X Field Signature Me ethod (FSM) We eight loss cou upon LPR R probes Bac cteria mo onitoring ○ ○ ○ ○ X ○ X X X X X X ○ ER probes
Seawater injection and cooling system Produced water treatment and injection systems q Aquifer water Effluent water Boiler feedwater and stream condensate Multiphase flow with water Unstabilized crude oil Hydrocarbon gas Fractionation units, CDU, and pipework FCCU, reactor columns FCCU reactor col mns Solvent extraction units, amine/caustic treaters and piping Vacuum towers, regenerators, process units, and pp pipework Storage vessels/tanks with separated water bottoms
○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
○5 ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
○4 ○ ○1 ○ ○ ○3 X X X X X X X
○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
○ ○ ○ X X ○ X X X X X X X
○ X X ○2 ○2 ○2 X X X X X X X
X ○ X X X ○ ○ ○ ○ ○ X X X
○ ○ ○ ○ ○ ○ X X X X ○ ○ ○
pH6
O2 O2, CO2, H2S CO2, H2S O O2 O2 X CO2, H2S X O2 X O2 O2 CO2, H2S
○ : 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 possible 2: 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 tendency 5: 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 Intrusive*3 Corrosion coupons Electrical resistance (ER) Linear polarization resistance (LPR) Indirect*1 On‐line pH or water analysis Internal hydrogen flux probes Ultrasonic testing Radiography External hydrogen flux probes Analysis of water samples obtained y p through an existing valve Surface patch hydrogen probes
Non‐intrusive
*1 To measure a direct result of corrosion. *2 To measure an outcome of the corrosion process *3 To require entry into the process stream
Of the techniques listed above, corrosion coupons, ER and LPR f Of th t h i li t d b i ER d LPR form the core of industrial corrosion th f i d t i l i monitoring systems.
MONITORING METHODS
Corrosion coupon
LPR probe
Bioprobe for monitoring bacteria Source: Alabama Specialty Products, www.metalsamples.com Electrical resistance probe
17
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 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. 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
ASTM G58
“C” Ring – ASTM G38 C
INHIBITOR COMPARISON USING COUPONS (OIL WELL)
FLOW
35 ppm Water Soluble Chemical
35 ppm
25 ppm
Oil Soluble Chemical
CORROSION RATE FROM COUPON DATA
Simplest and most reliable technique for corrosion rate determination is
the Weight Loss Technique. th W i ht L T h i Corrosion Rate = [mass loss]/[(exposed surface area] ∙ [time]) p or = 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 GUIDELINES
General l (mm/y) < 0.025 0.025 – 0.12 0.13 – 0.25 > 0.25 Max. Pitting (mm/y) < 0.13 0.13 – 0.20 0.21 – 0.38 > 0.38 Corrosion Rating Low Moderate High Severe
CORROSION COUPONS
Advantages Inexpensive, easily applied Coupon made of materials similar to pipe or vessel Visual inspection identifies mode of corrosion attack Samples available for scale or surface deposit analysis Sources of microbiological data Applicable to all environments Disadvantages Corrosion rate averaged over exposure time Corrosion rate calculation assumes uniform corrosion Data generation slow (long exposure times) Requires insertion and retrieval under pressure or at a turnaround
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
부식생성물
O
2000
Si S Ca Fe
1
MIC
1000
Al
2
일반부식생성물
0 3000 0 3
Inorganic corrosion
2000
O Fe Ca Si
1000
0 0 1
S
2 3
keV
AVERAGE CORROSION RATE VS. INSTANTANEOUS CORROSION RATE
TYPES OF PITTING (ASTM G46) ( )
Ratio of maximum localized corrosion rate to general corrosion rate determined by mass g y loss (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
elements relative to a reference non‐corroding element sealed within the l t l ti t f di l t l d ithi th probe body.
L R A
ER PROBE TYPES (CORROSOMETER®) (
Velocity shield
ER PROBE
TRADEOFF BETWEEN SENSITIVITY AND SENSOR 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
Advantages Direct measurement of metal loss Disadvantages Sensitive to thermal change
Will work in most environments: does not require Corrosion rate calculated as uniform corrosion. continuous aqueous phase No information on localized corrosion (suitable for multiphase, non‐aqueous environments) (suitable for multiphase non aqueous environments) Quicker response than corrosion coupons Continuously logged probes give high quality data (logging rate as low as 5 min) (trends and changes in corrosion activity) Meter output is in cumulative metal loss. Slope of data needed to calculated corrosion rate High sensitivity type probe is available. (Takreer RRE #2) Non‐corroding elements can be used as pure N di l t b d erosion monitor. Manual readings subject to signal noise (probe connections) Crevice corrosion can occur on poorly constructed flush‐type probes Requires insertion and retrieval under pressure which can have safety implications Requires several days to determine a reliable corrosion rate trend Adversely affected by conductive sulfide film Ad l ff t d b d ti lfid fil 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 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 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 noise (EN)
ELECTROCHEMICAL CORROSION MONITORING
Corrosion in an electrochemical process that can be monitored by
measuring potential & current that characterize the corrosion process. i t ti l & t th t h t i th i
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) pp E = Eapp ‐ Ecorr = alog ia/io,M ‐ alog icorr/io,M = a log ia/icorr = a/2.303 ln ia/icorr l ia = icorr e2.303E/
a
E
Eapp Ecorr
ic
ia
io,a
c
log i g
Similarly, ic = icorr e‐2.303E/
a
iapp = ia ‐ ic = icorr (e2.303E/ – e‐2.303E/ ) = icorr (2.303E/a + 2.303E/c) = 2.303icorrE(a + c)/ac = icorrE/B S Stern Geary equation G i
c
assuming that a = c = 0.12 Rp = E/iapp = B/icorr = 0.026/icorr B/i 0.026/i Rp: polarization resistance.
TYPICAL POLARIZATION RESISTANCE PLOT
FARADAY’S LAW AND CORROSION RATES
Q M m nF F
Where g ( ) Q = charge (C) = I∙t F = Faraday’s constant (96,500 C/eq.) n = number of equivalents (moles of electrons) transferred per mol of metal m = mass of metal corroded (g) M = molecular (atomic) weight of metal (g/mole) Corrosion R ( C i Rate (mm/y) = (8.76104 ∙ m) / (A ∙ D ∙ T) / ) (8 6 ) / (A D T) Where A = Coupon surface area (cm2) D = Material density (g/cm3) p ( ) T = Time of exposure (hours)
LPR PROBE
•
Gives instantaneous corrosion rates Only used in conductive, aqueous solutions Based on the current flow between two or more electrodes Requires the surface to become polarized and current resistance is measured. 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 electrochemical noise (EN) to detect pitting along with l h l d l h LPR probe.
LPR PROBE
Advantages Rapid measurement of corrosivity Sensitive to any process changes: flow, pressure, temperature, etc. Disadvantages General corrosion rates indicative of trend rather than absolute Continuous water phase required Probes are susceptible to fouling by deposits or hydrocarbon phase. No localized corrosion information
ALGORITHM FOR SUITABILITY OF ER AND LPR TECHNIQUES
OTHER TECHNIQUES
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 Station
DIRECT NON-INTRUSIVE TECHNIQUES
Field signature method (FSM)
NDT methods
RT IMAGE - EXAMPLE
54
INDIRECT ON-LINE TECHNIQUES
Hydrogen monitoring Acoustic solid particle detectors Water chemistry parameters Process parameters
HYDROGEN FLUX MONITORING
Hydrogen‐related problems Blistering HIC SOHIC SSC Hydrogen probe to monitor hydrogen absorption by steel I Intrusive (finger probes) – P i (fi b ) Pressure detection d i 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) content yg ( ) Conductivity P Process parameters t Pressure temperature
INDIRECT OFF-LINE TECHNIQUES
Water chemistry parameters
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) bacteria (API RP38‐SRB) Sessile bacteria (NACE TM0194)
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 OVERHEADS
Methods
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 analysis Residual test of filming inhibitor (3‐5 ppm) d l ffl hb Metal analysis of oil (for NAC control) Corrosion rate measurements 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 Tower overhead Overhead piping and condensers – water condensation + acid chlorides not neutralized and/or inhibited.
CORROSION MONITORING IN CRUDE UNIT OVERHEADS
Corrosion Probes Statistics (example) NACE Survey (1983) A breakdown of monitoring practices (129 CDU across 44 companies worldwide)
ER Probes (CORROSOMETER) LPR Probes (CORRATER) Corrosion Coupons (COSASCO type) None of above (?)
59% 1% 17% 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 circuits. tower 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
CORROSION MONITORING IN FCCU
Reactor & regenerator g
High temperature (900‐1200oF) Not by probes, but by UT or visual inspection Fractionator overhead system, side stripper Fractionator overhead system side stripper Effluent piping of the compressor after coolers
Corrosion probes
CORROSION MONITORING IN CLER UNIT
Chemical Test
CN‐ and SCN‐ content in wastewater stream pH (high pressure condensate) for water wash control Condenser/cooler bunldes (high pH corrosion of Cu alloys) Heat exchanger effluents in gas compression system Debutanizer overhead system, etc. Sour water lines Different elevation of the absorber/stripper tower Vapor/liquid interface area of the high‐pressure separator drum
Corrosion probes
Hydrogen monitoring Probe
HIGH PRESSURE ACCESS FITTING FOR A RETRIEVABLE PROBE
COUPON INSTALLATION INTO HIGH PRESSURE LINE
67
CORROSION MONITORING SYSTEMS
Use of Portable CorrosometerTM Instrument for M f Measuring Corrosion of Shell-side of Heat Exchanger i C i f Sh ll id f H t E h
ON-LINE THICKNESS MEASUREMENTS
Source: Hydrocarbon Processing, March 2012, pp.35-37
ASSESSMENT OF CORROSION INHIBITOR PERFORMANCE FOR MEG REBOILER
Temp. : 140 C solution : EG + inhibitor
0.400 0.375 0.350 0.325 0.300 0.275 0.250 0.225
o
Ar blowing (+ NaCl 16%) Air blowing (+ NaCl 16%) Ar blowing g Air blowing
mm/yr r
0.200 0.175 0.150 0.125 0.100 0 100 0.075 0.050 0.025 0.000 22 24 26 28 30 32 34 36
EG:water 60:40
EG:water 78:22
38
40
42
water %
River Water Analysis
LPR (CASE STUDY – HONEYWELL) (
Chemical Treatment
Program
Cycled Water
Analysis
LPR (CASE STUDY – HONEYWELL) (
LPR (CASE STUDY – HONEYWELL) (
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) 2) 3) ) 4) 5) 6) 7) 8) 9) 10) 11) 12) 1) 2) 13) 14) 15) 16) ) 17) 18) 19) R.D. Kane, Chemical Engineering, June 2007, 34. Coursebook for Corrosion Control in the Refining Industry, NACE International, July 2011. Survey of Corrosion Cost in Japan, Committee on Cost of Corrosion in Japan, Japan Society of Corrosion Engineering (JSCE), 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) March 2001. Alabama Specialty Products, www.metalsamples.com. NACE RP0775, Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations, 2005. NACE RP0497, Field Corrosion Evaluation Using Metallic Test Specimens, 2004. ASTM G4 “Standard Guide for Conducting Corrosion Coupon Tests in Feld Applications” ASTM G46 “Standard Guide for Examination and Evaluation of Pitting Corrosion” ASTM G102 “Standard Practice for Calculation of Corrosion Rates and Related Information from Electrochemical Measurements.” Coursebook for Corrosion Basics, NACE International, Jan 2003. P.R. Roberge, Handbook of Corrosion Engineering, McGraw‐Hill, 2000. P.A. Schweitzer, Corrosion of Linings and Coatings – Cathodic and Inhibitor Protection and Corrosion Monitoring, CRC Press, 2007. NACE Publication 3T199 “Techniques for Monitoring Corrosion and Related Parameters in Field Applications,” NACE International, 1999. NACE Publication 3D170 ““Electrical and Electrochemical Methods for Determining Corrosion Rates,” NACE International Application Note AN 107, Corrosion Monitoring in Crude Unit Distillation Columns, Rohrback Cosasco Systems, Inc., April 1990. J. Gutzeit, Crude Unit Corrosion Guide – A Complete How‐To Manual, PCC, 2004. Application Note AN 109, Corrosion Monitoring in Fluid Catalytic Crackers (FCC), Rohrback Cosasco Systems, Inc., April 1990. K. Wold and R. Stoen, Monitoring Internal Corrosion in Pipelins, ASTME India Oil & Gas Pipeline Conference, GOA, February , g p , p , , y 2011. Operating Manual for Model CET5000, Series SmartCET Corrosion Monitoring Transmitter, Honeywell, July 2006. P. Collins, Hydrocarbon Processing, March 2012, 35. Guidance on Practice for Corrosion Monitoring, Engineering Technical Practices GP 06‐70, BP Group, 2005.
QUESTIONS?
