INSPECTIONEERING JOURNALvir-inspection.com/assets/Inspectioneering_Journal... · 2 INSPECTIONEERING JOURNAL May/June 2007 Introduction The American Petroleum Institute (API) is issuing

INSPECTIONEERINGJOURNALMAY

JUNE2007_____

Vol 13Issue 3

API p. 2

Tech Report on

SCC of CS in Fuel

Grade Ethanol

Heat p. 3Exchanger Tube

Inspection – Update

RBI p. 11Utilizing Metrics

Maximizing the

Value

Why p. 17 Operating Sites

Just Don’t Get It

…”Hence the likelihood that

inspection will find changing corrosion

rates because of process changes that are

unknown to them is quite low.” Why Some Operating Sites Just Don’t Get It,

by John Reynolds

9-13EUROCORR 2007, Konzerthaus Freiburg im Breisgau, Germany > VE and more. For more information visit the web site http://www.eurocorr.org/EUROCORR+2007.html 16-20NACE Corrosion Technology Week 2007, Houston, TX > For more information contact Linda Goldberg phone: 281/228-6221 e-mail: [email protected] 17-19API Fall Refining Meeting, San Antonio, TX > CAS, RI, NDE, FFS, RBI. For more information visit the web site www.API.org

May / June2007_____

Vol 13 Issue 3

The Inspectioneering® Journal is a bi-monthly,

copyright protected, periodical publishedsix times per year.

Please address allcorrespondence to:

The Inspectioneering® Journal5315 FM 1960 West,

Suite B 237Houston, TX77069 USA

Phone: (281) 397-7075Fax: (281) 397-9996Email: [email protected]

Website:www.inspectioneering.com

Publisher:Dawn Alvarado

Chief Editor:Gregory C. Alvarado

Contributing Author:

John T. Reynolds, Shell Global Solutions (US), Inc.

(retired)

Brian BeresfordTechCorr Inspection

and Engineering

(ISSN 1082-6955)

IJ Industry.....Activities PlannerThe Inspectioneering® Journal does not warrant nor guarantee the accuracy of any infor-mation contained, nor the extent of inclusiveness, in the Industry Activities Planner. It is imperative that interested parties contact the sponsoring organizations, for each par-ticular event, to verify dates, information and locations, prior to any planning or decision making regarding the value of each event. Readers may contact the Inspectioneering® Journal office to obtain appropriate contact information.

Please e-mail any activities of interest you think applicable to the Inspectioneering® community to [email protected].

11-1327th Annual ILTA (Independent Liquid Terminals Assn.) International Operating Conference & Exhibition, George R. Brown Convention Center and Hilton Hotel, Houston, TX > RI, CAS, VE. For more information visit the web site http://www.ilta.org/CalendarofEvents/AOCTS/2007/2007info.htm 12-13Asset Integrity Management Summit, The Marcliffe Hotel, Aberdeen, UK > CAS, RL, NDE, FFS, MI, RBI, FFS, RI and more. For more information visit the web site http://www.iqpc.com/cgi-bin/templates/genevent.html?topic=229&event=12757& 20-23ASME International Chemical and Petroleum Industry Inspection Technology (ICPIIT) X Conference, Houston, TX >NDE, VE, CAS, RI. For more information visit the web site http://www.asnt.org/events/conferences/icpiit/icpiit.htm

JUNE 2007

22-2734th Annual Review of Progress in Quantitative Nondestructive Evaluation, Colorado School of Mines, Golden, Colorado > NDE

JULY 2007

SEPTEMBER 2007

9-11ESOPE 2007, European Symposium on Pressure Equipment, Paris, France> FFS, RBI, VE, CAS, RI, NDE. For more information visit the web site http://www.afiap.org/MAJ/evenementsEsope_2007_En.pdf

OC TOBER 2007

http://www.afiap.org/MAJ/evenementsEsope_

http://www.eurocorr.org/EUROCORR+2007.html

http://www.eurocorr.org/EUROCORR+2007.html

mailto:[email protected]

http://www.API.org

http://www.inspectioneering.com

http://www

http://www.iqpc.com

http://www.asnt

I N D E X -

New from API .................................2API Technical Report 939-D, Second Edition, Stress Corrosion Cracking of Carbon Steel in Fuel Grade Ethanol: Review, Experience Survey, Field Monitoring, and Laboratory Testing

Inspection of Heat .................... 3-10Exchanger, Condenser & Fin Fan Coolers Tubes – An Update

Risk Based Inspection ............. 11-16Utilizing MetricsMaximizing the Value

Why Some Operating Sites ....... 17-20 “Just Don’t Get It”

Please make checks payable to The Inspectioneering Journal 5315 FM 1960 West, Suite B 237

Houston, TX 77069 Telephone: (281) 397-7075 Fax: (281) 397-9996

Email: [email protected] Website: www.inspectioneering.com

Subscriber Name (Recipient)

Company Name

Address

City State/Province Zip/Code

Phone Fax

Email URL

Credit Card No. Expiration Date

Cardholder Signature Date

Digital Subscriptions Available: Send pricing, format and delivery questions to [email protected]

YESI would like to subscribe to the INSPECTIONEERING JOURNAL

Single subscriptions cost $225.00 U.S. per year (6 issues). 10% discount for2 yr. subscriptions. Contact us for details on multiple subscription pricing. Non-U.S. subscribers add for postage, handling and transfers: in Canada and Mexico: add $40.00 U.S. per year, All others: add $50.00 U.S. per year. Except wire transfers: add $40.00 U.S. per transfer.

___________________________________________________________________________________________________

___________________________________________________________________________________________________

___________________________________________________________________________________________________

___________________________________________________________________________________________________

___________________________________________________________________________________________________

___________________________________________________________________________________________________

_______________________________________________________________

Renewal New Subscription Check Enclosed Bill Me (payment due in 30 days)

_______________________________________________________________________________________

Cardholder Name________________________________

IJ Article Submission and Publication 1. All articles must adhere to the Guidelines and Requirements listed on our web site at http://www.inspectioneering.com/publishanarticle.htm. 2. Authors must have/obtain authorized permission to print, with company and name byline, in this publication. 3. Send duplicates of all photos, illustrations, and visual aids with permission to reprint. Must be submitted with draft article. “IJ” retains right to reprint and archive all visual aids submitted for use. 4. Unless otherwise requested, articles must be one page in length, 10 to 12 cpi, single spaced. 5. Editor and contributing editors will make all final decisions regarding acceptance of article, i.e. value and appropriateness judgements, along with editing decisions. 6. Author is responsible for final review, following step 5, and authorization from his/her employer to release, as necessary. 7. All articles accepted by the “IJ” become the property of the “IJ”. No reprint is permitted without prior written authorization.

The Inspectioneering® Journal assumes no responsibilities or liabilities for the accuracy or application of methodologies, technologies, philosophies, references, case histories, or un-authorized release of company information in relation to any printed subject matter in the Inspectioneering® Journal The Inspectioneering® Journal, the editors and authors, or anyone acting on their behalf, assume no responsibility or liability, without limitation, for the use of information published in the Inspectioneering® Journal.

http://www.inspectioneering.com/publishanarticle.htm

2 INSPECTIONEERING JOURNAL May/June 2007

Introduction The American Petroleum Institute (API) is issuing this publications announcement to inform companies involved in the distribution, transportation, storage, and blending of denatured fuel ethanol of a potential for metal cracking and product leakage from carbon steel equipment in certain portions of the fuel ethanol distribution system. API, with assistance from the Renewable Fuels Association (RFA), has published Technical Report 939-D, Second Edition, that describes cracking events and associated ethanol leaks, the results of related research and field studies, and preliminary guidelines for mitigation and prevention. However, this announcement is being issued at this time so that handlers of fuel ethanol can evaluate the need for additional appropriate precautions.

Background Fuel ethanol is increasingly being used as a gasoline oxygenate and extender. It is supplied to specifications described in ASTM D 4806 that provides guidance primarily for product purity and functionality of fuel ethanol in gasoline blends used in automotive engines. Once manufactured, fuel ethanol is transported by a number of means (e.g. tanker trucks, rail tanker cars, barges and pipelines) to ethanol distribution facilities and gasoline blending facilities where it is held in storage tanks prior to blending with gasoline. The primary material of construction used in this distribution system is carbon steel. Until recently, fuel ethanol was not widely recognized for its potential to cause cracking of carbon steel. API is issuing this announcement because of the potential impact of cracking and leaks if this problem is not adequately managed.

Field Experience In the API investigations conducted to date, it is apparent that a number of leaks have occurred in equipment handling fuel ethanol due to cracking of the carbon steel. Approximately two dozen cases of cracking and leaks have been documented in various types of equipment including storage tanks, piping, and associated handling equipment in the distribution system for fuel ethanol, and in an ethanol transport pipelines. However, there have been no reported cases at ethanol manufacturing facilities, nor has cracking been reported after ethanol has been added into conventional gasoline blends with nominally 10 percent ethanol with balance gasoline. Thus far, no cracking events have been reported in carbon steel equipment exposed to E85 fuel blends.

New From API

API Technical Report 939-D, Second Edition,Stress Corrosion Cracking of Carbon Steel inFuel Grade Ethanol: Review, Experience Survey, Field Monitoring, and Laboratory Testing

Key MessagesThere have been metallurgical investigations conducted in several documented cases and preliminary research has been conducted by API with the assistance of the RFA. Even though the factors that lead to cracking are not completely understood, it is known to occur by a phenomenon referred to as stress corrosion cracking. Based on a survey of companies involved in the distribution and handling of fuel ethanol, several have taken steps to inspect for cracks and mitigate this problem. Inspection techniques have included use of wet fluorescent magnetic particle testing to find cracks on interior surfaces exposed to fuel ethanol. Mitigation techniques used by some companies include thermal stress relief of welds in piping and the use of internal coatings in storage tanks that are resistant to immersion in ethanol, however, these measures are considered interim until more research is conducted. Most recently, laboratory tests have indicated a susceptibility to cracking of carbon steel in E85 blends of fuel ethanol and gasoline however, there have been no documented cases of cracking of carbon steel equipment in E85 in the field.

Additional Information

The following are resources for additional information:

ASTM D 4806,Specifications for Fuel Grade EthanolASTM International100 Barr Harbor DriveP.O. Box C700West Conshohocken, PA 19428-2959Order Information: Phone 610-832-9585;Online: www.astm.org

Please contact API at [email protected] if you have information on failures of carbon steel equipment in fuel ethanol service or in ethanol gasoline blends.

Printed copies of API TR 939-D, Second Edition, may be purchased for $147.00 each. API members receive a 30% discount on orders. For more information on ordering this and all API publications, visit www.api.org/cat.

Second Edition, May 2007Pages: 172Price: $147.00Product No. C939D2

http://www.api.org/cat

http://www.astm.org



Editor’s note: A well designed qualification demonstration testing program is strongly recommended

for these NDE techniques and operators applying them. Many articles on such a program have

appeared in the “IJ”. This type of “gate keeping” program should include consideration for the types of

flaws or damage expected, the degree of damage, accuracy, the orientation of damage, extenuating

factors such as tubesheet, baffle and fin presence or proximity, etc. The operator, procedure, hardware

and software should be qualified, collectively. Verification and confirmation of results are always

recommended prior to undertaking any costly repairs or replacements.

Inspection of Heat Exchanger,Condenser & Fin Fan

Coolers Tubes – An UpdateBy Brian Beresford,

TechCorr Inspection & Engineering, Houston, TX

Tube inspection is a vital tool for the refining and petrochemical industries. Heat

exchangers and condensers are designed to sustain 100% separation between

the products in the tube (tube side) and the products in the vessel (shell side). A

leaking tube can not only cause a significant impact to production it can cause

major environmental issues and the potential for loss of life.

Tube Inspection techniques have been available for decades. Historically the

costs for inspections have been extraordinarily high due to probe manufacturing

and instrumentation costs. Only nuclear facilities which are heavily regulated

could afford these services. Over the past decade improvements in manufacturing

capabilities have helped to decrease the cost for testing devices. The 1986

Process Safety Improvement Act also resulted in an increased demand for inspection services. These two factors

have contributed to more cost effective probe design and decreased cost to perform inspections. Tube inspection

services are much more cost effective for the oil and gas industry equipment operators than in the past.

Now exchangers and condensers are being inspected on a more regular basis. This has lead to improved bundle

reliability for the oil and gas companies. The inspection allow the operators to improve preventative maintenance

programs by identifying damaged tubes requiring immediate replacement during maintenance outages and the

ability to more accurately determine remaining life so maintenance activities can be scheduled during future outages

and finally the ability to manage “Risk” by reducing the number of unforeseen unplanned outages. These benefits

have provided significant reliability improvements for refinery and petrochemical operators and will continue to grow

as technology and implementation practices continue to improve over time.

Current Technology

Tube inspection techniques include Eddy Current, Remote Field Eddy Current, Magnetic Flux Leakage, IRIS (UT

technique) and LOTIS (Laser) profilemetry. Although this article focuses on electromagnetic based techniques the

ultrasonic and laser techniques require mentioning as the techniques are very complimentary and often used in

parallel.

Tube inspection is typically broken down into two (2) categories; ferrous and nonferrous. Ferrous materials refer to

materials with magnetic properties such as carbon steel and 400 series stainless steel. Nonferrous materials refer

to materials with nonmagnetic properties such as copper, brass, Inconel and most stainless steels. The following

table shows the techniques that are used for the different tubes materials.

Technique Table EddyCurrent

Remote FieldEddy Current

MagneticFlux Leakage

IRIS (UT) Laser

Ferrous X X X X

Nonferrous X X X

Key words:

ferro-magnetic,non-ferro-magnetic,

eddy current, remote field eddy

current, laser profilometry, internal

rotary inspection system (IRIS),

baffle, tubesheet, externally

referenced electromagnetic

technique, fin tubes, accuracy,

austenitic, ferritic, cleanliness


Although the choice of technique used is primarily

influenced by the type of “failure mechanism”

needed to be detected many times the technique

used is dictated by the tube cleanliness. For

example, whereas the utilization of IRIS and

Laser require a high degree of tube cleanliness,

ET, RFT and MFL do not require the same

level of cleanliness. There are several damage

mechanisms and flaws that can occur on the

outside or inside diameter surfaces (O.D. or I.D.)

as well as volumetric damage. The following table

shows the various flaws that can be detected with

the various techniques for both nonferrous and

ferrous tubing materials.

Eddy Current

Eddy Current Testing (ET) is very sensitive to a great

number of variables making it a powerful examination

tool. The eddy current testing method is based on

inducing electrical currents (eddy currents) in electrically

conductive materials. For tube inspection, bobbin type

probes are used containing coils as shown. In theory,

any defects in the material such as cracks, pitting, wall

loss or other discontinuities will disrupt the flow of the

eddy currents and be detected by the instrumentation.

Most heat exchanger bundles contain supports

that are many times likely targets for service type

damage such as fretting, galvanic or oxygen concentration cell

corrosion. Multi-frequency channel systems are capable of

suppressing or mixing out the unwanted signals responses from

supports in order to closely interrogate the material under and near

the supports. Mixing is also used for the detection of defects near,

at, or within the tubesheet. Conventional eddy current testing

is employed primarily on non-ferrous (nonmagnetic) materials

due to permeability effects of ferrous materials. Many times the

owner/users of the exchangers prefer eddy current testing to IRIS

(internal rotary inspection system) inspection as the cleanliness

of the tubes is less critical. Additionally, the productivity of eddy

current testing can be as much as 3 – 4 times faster than this type

of UT inspection.

Technique Flaw Detection Table for Nonferrous Tubing

NONFERROUS MATERIALS

DamageMechanism

ConventionalEddy Current

RemoteField Eddy

Current(RFT)

MagneticFlux

Leakage(MFL)

IRIS (UT) Laser

I.D. General WallLoss Yes Yes

(Limited) N/A Yes Yes

O.D. General WallLoss Yes N/A N/A Yes N/A

I.D. Pitting Yes (need properCalibration standard) N/A N/A Yes (Limited

pit size) Yes

O.D. Pitting Yes N/A N/A Yes No

I.D. Cracking(stress corrosion

cracking)

Yes (need properCalibration standard) N/A N/A No Yes

(Limited)

O.D. Cracking(stress corrosion

cracking)Yes N/A N/A No No

Volumetric Flaws Yes N/A N/A Yes (Limited) N/A

Technique Flaw Detection Table for Ferrous Tubing

FERROUS MATERIALS

DamageMechanism

ConventionalEddy Current

RemoteField Eddy

Current(RFT)

Magnetic FluxLeakage

(MFL) IRIS (UT) Laser

I.D. General WallLoss Yes (Limited) Yes Yes (Limited) Yes Yes

Limited

O.D. General WallLoss N/A Yes Yes (Limited) Yes N/A

I.D. Pitting Yes (Limited) Yes Yes Yes Yes

O.D. Pitting N/A Yes Yes Yes No

I.D. Cracking(stress corrosion

cracking) Yes (Limited) Yes No No Yes(Limited)

O.D. Cracking(stress corrosion

cracking)N/A Yes No No No

Volumetric Flaws(embedded, etc.) N/A Yes No Yes (Limited) N/A

An inside-coil or bobbin coil consists of several turns of wire wrapped around a cylindrical form. This probe type is passed through the inside diameter of test specimens such as tubes and bores.


Remote Field Eddy Current (RFT)

Remote Field Eddy Current Testing (RFT) was

developed for ferrous or carbon steel materials and

requires a special RFT probe in which the exciter

coil is separated from the pickup coil or coils by a

distance of two-to-three times the tube diameter.

The receiving or pick up coil then detects the flux

lines generated that cross the tube wall twice.

Due to the highly magnetic properties of ferrous

materials, meaningful eddy current testing requires

higher power fields. Where previous eddy current

techniques on ferrous tubing required complete

magnetic saturation of the tube material, RFT does

not. The remote RFT amplifier provides the higher power output levels needed for ferrous tube inspection, and the

RFT probe coils are designed to handle the increased power levels. Because RFT is transmitted through the tube

wall, it is equally sensitive to flaws on the inside diameter (ID) or outside diameter (OD) of the tube. The accuracy

for heat exchanger tubes is generally +/- 10%. The accuracy for boiler tubes is generally +/- 20%. The reason for

the accuracy difference from exchanger tubes to boiler tubes is the average cross sectional volume. The larger the

tube the bigger the average cross sectional volume and the less accurate you will be. As with eddy current, many

times the owner/users of the exchangers prefer RFT testing to spinning UT type inspection as the cleanliness of

the tubes is less critical. Additionally, the productivity of eddy current testing can be as much as 2 - 3 times faster.

RFT is a bit slower than eddy current and it is important that the speed of travel is as constant as possible to obtain

accurate responses.

Magnetic Flux Leakage (MFL)

MFL is based on the magnetization of the material

to inspect using a strong magnet located inside the

probe (see illustration). As the probe encounters a wall

reduction or a sharp discontinuity, the flux distribution

varies around that area and is detected either with

a Hall-effect sensor or an inductive pickup coil. This

is the result of the large flux leakage response that is

generated. MFL has been used successfully on carbon

steel fin fan tubes. MFL techniques are less sensitive to

the aluminum fins. These perturbations in the magnetic

field are detected by the sensors positioned within the magnetic circuit, recorded and later analyzed and reviewed.

Internal Rotary Inspection System (IRIS)

Internal Rotary Inspection System (IRIS) is sensitive to both ID and OD forms of volumetric wall loss. The technique

uses an ultrasonic beam to scan the tube internal surface in a helical pattern ensuring that the full tube length is

tested. The IRIS system monitors the front wall and the back wall echoes in order to precisely measure the tube

wall thickness. Measurements can be as accurate as +/- .005 inches. IRIS accuracy and sensitivity are seriously

compromised in the presence of ID or OD deposits, bends, and geometry changes. One of the draw backs of IRIS

inspections is that the tubes are required to be extremely clean and typically are “soda” blasted. IRIS takes 2-3 times

longer than RFT. If areas of geometry changes require examination, complementary methods must be employed.

IRIS is not sensitive to non-volumetric forms of degradation such as cracking. Verification and confirmation of results

is always recommended prior to undertaking any costly repairs or replacements.

Laser Optical Tube Inspection System (LOTIS)

Laser measurement tools for gauging are based on the principle of optical triangulation. A laser source similar to a

standard laser pointer is directed at the surface whose height is to be measured. An imaging lens collects the light

reflected from the surface and focuses it onto a position-sensitive detector. The output from the detector is processed


electronically to convert the detector positions to accurate height measurements that can be stored on a computer

for subsequent display and analysis. The laser spins inside the tube creating a helical “rifle” pattern or footprint. The

tighter the pattern the more thorough the inspection and the longer the time required for inspection. This method

requires high levels of cleanliness and typically that no moisture or moisture droplets are inside the tubes. Deposits

will absorb the laser light and moisture will refract the light creating areas of data dropout or erroneous data.

Software Mapping, Trending and Final Reporting

Data management has drastically changed and improved within the last few years. We are able to quickly build maps

for all types of components. Examination results can be displayed in standard or custom formats. Convenient drawing

tools give a professional CAD look without needing to invest in an extensive learning curve. Customized drawings and

maps for exchangers, condensers, boilers, and pressure vessels are easily created. Documentation associated with an

examination can be digitally stored with the component report and drawing for tracking and documentation. Work orders,

repair documentation, procedures, photos and notes are easily accessible for reference. No more trying to find hard copies

from the last inspection or repair—now it is all together—electronically.

Trending allows you to have multiple maps in one drawing file. A must for condition assessment, you can compare by

superimposing the results of any two examinations and present the results in your choice of formats i.e. map, graph or text.

Comparisons can be made for overall or specific damage types. For example, compare only pit type damage or only wear

type damage. Comparisons can also be linked to a report editor so reports can be generated specifically for growth rate

assessment using built-in routines.

Two dimensional views can be directly applied to a two dimensional model of the component. The model can be generated and

positioned horizontally or vertically to show top, bottom, and/or side views. This allows for extremely detailed assessments

as damage can be displayed by type, location, depth or any combination of parameters.

Reporting features can link data from the map and data sheet(s) directly to the reports. The report format can often be

tailored by the user to quickly generate detailed final reports or for fast turnaround for end of day status. Tools exist to easily

import any results in text format from prior reports.

What is the Future for Exchanger Tube Inspection

The future has been a long time coming. With the change of computers and software we are now able to store

larger data files. As a result inspection technology which could only be performed using super computers can now

be utilized in the field. Analysis has also become more affective as imaging capabilities have significantly increased

over the past decade. As a result many new techniques are available to inspect exchangers, condensers, boilers

and equipment in general.

As a wrap-up we will cover some new technologies and improvements.


Some of the advanced tubular technologies include XRFT a solution to inspect Fin Fan Coolers which historically

could not be inspected using electromagnetic techniques. Remote Field and Eddy Current “Array” technology

using segmented coils is providing much more sensitivity to small volume pitting and cracking. Finally the SPNR™

probe technology is a non-surface riding coil that provides 100% imagining in a C-scan plot excellent for difficult

defect mechanisms.

Fin Fan Inspection

Conventional remote field testing (RFT) is not reliable when inspecting carbon steel fin fan coolers. The fins disturb

the electro-magnetic field. This forced the use of ultrasonic methods to inspect fin fan coolers however cleanliness

became a major limitation to ultrasonic methods. As a result the Externally Referenced Electromagnetic Technique

(XRFT) was developed.

XRFT is an electromagnetic

technique using the Remote

Field phenomena connected

with an external reference to

eliminate extraneous noises

by utilizing a balanced system

(i.e. the extraneous noise is

caused by the fins). XRFT

has an accuracy rate of +/-

10% of nominal wall, good

sensitivity to gradual wall loss

and sensitivity to pitting. Pit

detection and sizing is directly

dependent on fill factor and

pit diameter size. XRFT has

good repeatability and tubes

can be inspected at 1’ per/

sec with very little cleaning

required. This technique has

good false positive recognition and has made data analysis easy to interpret. The external reference self-comparison

differential arrangement uses two differential probes and is setup to provide differential and absolute responses.

It essentially combines the self-comparison differential coil arrangement with the external reference absolute coil

arrangement. The other probe, located in an external reference sample, compares one of its coils with one of the coils

in the inspection probe to provide absolute information and detection of long flaws and dimensional variations.

Probe Designs & Improvements

Although technology has allowed high volume data acquisition to become a reality

the improved probe design and manufacturing capabilities have helped to change

the tubular inspection business forever.

The Conventional “Bobbin Probe” is a single segmented coil design measuring the

average cross sectional volume loss. As a result this method is quantitative.

Averages 360° Area

Vector Additions of Multiple Defects

Defect Morphology Difficult to Determine

New “Array” Probe is a six to eight segmented coil design allowing volumetric

discrimination and improved sizing capabilities.

Segmented coils decreases affects of averaging

Increased signal to noise ratio

Limits vector additions of multiple defects

Provides more detailed information on defect morphology.


A C-Scan Presentation of the data is now possible using the array probe technology. This presentation is extremely useful

during the analysis phase as metal loss can be attributed to specific quadrants within the tube being inspected. As such the

morphology of the defect can be better determined when compared to the conventional bobbin probe technique

SPNR™ (Pronounced Spinner) Eddy Current Probe

SPNR = Send-Receive Polarized Non-Contact Rotating probe has

historically been utilized in the nuclear industry. The SPNR probe

produces two channels per frequency. One channel is sensitive to

circumferential flaws and the other sensitive to axial flaws. These

channels have been tuned so that they are near identical and

overlapping. Any flaw that is volumetric in nature produces equal

signals on both the Circ and Axial channels.

This Eddy Current technology is super sensitive to nearly any type

of defect mechanism imaginable. It provides a three-dimensional image of the defect allowing detailed data analysis and

presentation.

Advantages of SPNR - Polarized sensitivity to flaw orientation results in a maximum response to an indication running

parallel to the line of centers between the coils. Excellent flaw characterization. Excellent characterization of “noise” signals

including reduced sensitivity to thermal variations and improved characterization of lift off (expansions, ovality, denting),

support structures and deposits.

Use of the SPNR probe instead of surface-riding rotating probes considerably reduces inspection time, consumable costs,

Simplified analysis and reduced number of questionable calls. Compatible with common data acquisition systems and

analysis software SPNR™ Probe is easily reconfigured to a variety of tube diameters and materials.

SPNR™ Reformer Tube Development

TechCorr Inspection & Engineering was requested by Methanex in Punta Arenas, Chile to design and develop an

examination technique for the examination of reformer tube headers specifically looking for axial and circumferential. The

tube specifications are 800-HT 6” inside diameter excess and the header length is 5950mm (19.5 feet). TechCorr utilized

Eddy Current Testing spinner probe technology and was able to see the heat affected zone from the weld and multiple


axial ligament cracks. The 3-D C-Scan images from the spinner probe were extremely clear and conclusive! This type of

3-D C-Scan display can be implemented to any type of tubing, flat and curved surfaces.


Flaw Legend

A. ID Groove 1/16” wide .008” (19%) deep

B. Carbon steel drilled hole support

C. Dia. 0.028” through wall hole

D. 4 x 100% Axial EDM @ 90° x .005” wide

E. Dia. 7/64” x 0.025” (60%) deep FBH

F. Dia. 3/16” x 0.017” (40%) deep FBH

G. 4 x Dia. 3/16” @90° x 0.008” (20%) deep FBH

H. OD Groove 1/8” wide 0.004” (10%) deep

I. Dia. 0.052” through wall hole

J. Dia. 0.052” through wall hole

K. Dia. 0.052” through wall hole

L. Dia. 0.052” through wall hole

M. 0.001” x 0.750” wide rolled indentation

Brian (Bear) Beresford Biography: Brian started his heat exchanger tube inspection career in 1983 with

Zetec Incorporated in Issaquah, Washington. Throughout his twenty fours years of

service Bear has worked in nuclear power facilities, petrochemical facilities, nuclear

naval submarines and of course the oil refining business. His job functions have

included tubular inspection related product sales, strategic business development,

new product design, new product testing, probe development and field services. Mr.

Beresford is a functioning level three (III) analyst in accordance with ASNT-TC-1A

while qualified to EPRI TR-107569-V1R5 QDA.

http://www.refineryinspectors.com

http://www.pro-inspect.com


This is part 2 in a multi-part series. Part 1 set the stage in explaining the basics of RBI, including

• How confidence and uncertainty are managed effectively

• The importance of a good materials/corrosion/damage mechanisms review

• Factoring NDE into the RBI equation – credits and debits

• The importance of good, realistic, credible RBI calculation models based on sound and industry accepted technological basis

• Explanation of RBI as a relative risk ranking tool

• Importance of consistency to ensure relativities and therefore risk rankings are valid

• Risk is dynamic • The pitfalls and liabilities in using “black box”

technologies

As I am most familiar with API Base Resource Document 581, I will continue to use this technical basis for this article. Other important reasons for using this document:

• The document is available in the public domain for reference

• It is most often referenced by developers and users of most, if not all, RBI software tools

• It is very comprehensive and fully develops

the risk, i.e. consequence and likelihood of failure scenarios to establish a full understanding

• Once one is able to grasp the technical basis of API’s quantitative approach (more qualitative approaches are included in this document, also) it is easier to back off or “zoom out”, validate and understand the more qualitative approaches

Risk Refresher

For the sake of the RBI discussion, Risk is the combined consideration of consequence/s of failure (CoF) and probability of failure (PoF). It should include considerations for safety, environmental impact, business interruption, equipment repair and replacement costs, etc. Output measures should be provided for both sides of the risk equation and combined.

PoF X CoF = Risk

Where the following components are considered in the PoF calculation:

Generic failure frequency X damage factor (DF) X management factor = PoF

The damage factor represents how much confidence you have in what you believe to

Risk-Based Inspection

Utilizing MetricsMaximizing the Value

Part 2

Editorial by Greg Alvarado, “IJ” Chief Editor

Key words: risk-based inspection (RBI), fitness for service, risk in sq.’ per year, risk is dynamic, relative risk, consistency, probability of failure, likelihood of failure, generic failure frequency, damage factor, RCA, FMEA

RBI Basic Premise – How much confidence do I need to have in what I believe to be the condition of the equipment – Greg Alvarado


be the condition of the equipment, i.e. age, corrosion or damage rate/s for all potential damage mechanisms, past and future inspection effectiveness’ for each damage type, materials properties, remaining thickness or ability to contain the process. This factor adjusts the generic failure frequency for that type of equipment.

The software, software facilities and project documentation must make it easy to identify the risk drivers, e.g. lack of inspection history (aka confidence in the real condition of the equipment), corrosion rate, thin wall, toxic chemicals contained, susceptibility to unstable conditions (such as acid carryover), etc. so the user can manage them appropriately at the right times.

With these types of capabilities and information we can begin to create and evaluate metrics.

Current Refining and Petrochemical Industries Metrics Status

In the 1990’s with the growing popularity and maturing of RCM (reliability centered maintenance), in regards to plant equipment, we began seeing the emergence of metrics and concepts like:

• % of design availability• % of desired reliability• costs of LPOs (cost of lost profit

opportunities often due to unplanned outages)

• Process hazards risk matrices for company decision making

• and more….We at least began to track these metrics and try to identify root causes via structured root cause analysis and began being proactive by performing rigorous FMEA (failure modes and effects analysis).

This now sets the stage for proactive

management of equipment reliability. The picture has been painted that past practices, i.e. using past thickness readings to calculate corrosion rates, using corrosion coupons and corrosion probes to manage equipment was like driving a car by looking through the rear view mirror. Tools like RBI, when linked with effective management of change programs, materials operating windows (also referred to as key process reliability parameters or integrity operating windows), digital controls systems and automatic notifications programs help us drive our plants forward by looking out the windshield and taking advantage of our instrument panel.

Impact of Consistency on Reliable Metrics

There is an old adage that states, “If I can measure it I can manage it”. This is most often true. In the world of RBI, as we learned from the last article, it is important to measure “it” consistently. Once we believe in the measurement model and practice measures consistently (this is imperative when using relative risk), the metrics can be very powerful and valuable. If we do not maintain consistency we will lose relatively, greatly diminishing the value and validity of the relative risk measures.

Some hints for maintaining consistency in the RBI process (the process includes the working process, associated activities, the RBI software, associated software platforms, etc.):

• Develop and follow a corporate RBI best practice (“what to do”) (amongst other things this procedure might contain the Risk Target, Inspection Effectiveness Tables, the corporate risk philosophy, etc.)

• Develop and follow a site RBI procedure (amongst other things this document will contain specific “how to’s” in the RBI process like; local rules and regulations, corporate regulations, the type of RBI used, reference to the technical basis of the RBI used, RBI team members and roles, RBI ever greening, performing data validation, how RBI “fits into” the equipment reliability


program, establishing the RBI corrosion rate or damage susceptibility, etc.)

• Use a software tool that best forces the RBI team to follow a structured process

• Document any deviations, assumptions or changes sufficient to understand the logic and recreate the study at a later time with a different team of people

• Train RBI facilitators to assure they are all on “the same page”

Something to keep in mind, the more qualitative the RBI approach is, the more it is affected by the opinions of the participants. These can change daily. Hence, a very prescriptive procedure is recommended for qualitative studies, especially.

Companies like Solomon Associates have been benchmarking refineries and providing measures in various areas, related to performance, for some time. These measures cover many areas, in addition to fixed equipment reliability. These measure are, when it comes to fixed equipment reliability, at a much higher level than API RBI and therefore do not as readily point to the risk drivers. Plants often want to be in their 1st quartile of performance. Just to demonstrate the importance of consistency in relative measures, all plants are placed, in this study, into a size range measured in EDC or equivalent distillation capacities. There are others who perform similar comparisons and many owner operators benchmark themselves, internally. For the purposes of this publication, we will focus on RBI.

RBI Produces Helpful Metrics

And now for what I hope you find helpful guidance. All things considered in the risk equation, i.e. safety, environment, business, equipment inspection, replacement and repair costs, etc., in terms of relative risk measures metrics can help us determine:

1. Am I doing the right things (in his book, The 7 Habits of Highly Effective People, Stephen Covey explains the importance

of first focusing on doing the right things, or being effective, versus being efficient. Once we have assured ourselves we are doing the right things we may then work on efficiencies. Otherwise, we may just be doing the wrong things faster. Understanding this perspective brings many benefits such as appreciating the power of good predictive models and if I am considering it, how to evaluate if the “streamlined” approach I am considering will perform as desired or is it a waste of time or even worse, creating a false sense of security, for example.)?

v The risk analysis should tell us immediately:4 Is the risk being driven by consequence

or likelihood or both4 The analysis should “zero in” on the

particular risk drivers in any category (see Figure 3)■ For example, if the driving risk is PoF

and is attributable to the potential for Cl stress corrosion cracking, how many times has the component been inspected for such? Has it ever been detected? If not, it may be that as soon as an effective inspection is performed for this mechanism and SCC found not to be present, that the PoF drops considerably for some period of time.

■ On the other hand, for example, if it is a crude overhead line that is susceptible to severe thinning and has been inspected often with the appropriate types of inspection, it may be nearing end of life.

4 The RBI analyst should have the documentation to validate the results and test them appropriately

2. Am I moving in the right direction, i.e. versus past practices, am I reducing risks at each measurement iteration, or at least keeping it at an acceptable level?

By measuring risk in units such as sq.’/year or financial terms and knowing how much it costs to perform a task and being able to ascertain


this number (risk in square feet per year or financial risk) at any time in the lifetime of the equipment we can compare the relative payoff of any action or inaction, for example:

Figure 1.

In Figure 1 the two risk profiles depict the top 100 risk items in one processing unit. Risk in sq’/year is on the “y” axis and the equipment items are on the “x” axis. The risk is cumulative over 4 years, i.e. the time between turnarounds. Turnaround is driven by catalyst removal. The blue profile (profile with most dramatic peaks and valleys) is under a traditional API 510/570 inspection program. The green profile (much smoother) is for the same unit if the API RBI plan is implemented. The peaks in the blue profile indicate areas of vulnerability that the RBI process identified. Knowing the inspection and inspection related maintenance costs for each strategy the following metrics can be easily derived:

• The average risk reduction, per dollar spent is 1.7 sq.’ per year under the traditional plan.

• The average risk reduction, per dollar spent is 2.7 sq.’ per year if the API RBI plan is implemented. This represents a 37% improvement in risk reduction per dollar spent on the inspection program. It is also noteworthy to mention that over $500 K was identified for reallocation to other areas of the plant’s reliability program, as a result.

Some people call this savings. It is best to refer to it as saavy risk management and being able to better focus resources.

Risk in sq.’ per year, is a relative measure. For example, let’s say the highest consequence area for a particular piece of equipment is safety related and is 10,000 sq’ for H2S exposure. Let’s say that the current PoF is 1 X 10-6,or one in one million years. Let’s also imagine that if nothing is done in 10 years, i.e. no inspection, that the PoF escalates to 1 X 10-4, or one in ten thousand years. If the consequence area does not change, and the PoF is one in ten thousand years, the risk is approximately 1 sq.’ per year.

3. How much is risk increasing over time? see Figure 34. By measuring uptime, availability, reliability,

leak rates, LPO occurrences, etc. can I make a direct comparison or indirect comparison to the impact of my RBI program?

5. Is it more beneficial for me to:5.1. Do nothing5.2. Inspect5.3. Repair5.4. Replace5.5. “Alloy up”5.6. Perform a fitness for service analysis5.7. Perform a remaining life assessment5.8. Install a damage mitigation system, e.g.

corrosion inhibition system6. The risk impact of a new chemical or

physical environment on equipment risk and reliability (e.g. changing crude slates to differing TANs), changing temperatures and/


or pressures, changing to a new chemical (e.g. containing chlorides), etc.7. The real impact of “overdue” TMLs (thickness monitoring locations)

Risk Matrix Versus Other Metrics

Risk is dynamic, not static. Over time some things that have a low probability of failure (PoF), today, will, as walls thin and/or materials properties degrade, increase in PoF. It is important to manage this equipment and understand when risk increases.

Figure 2. Traditional RBI Risk Matrix

Traditional RBI Risk MatrixStill a valuable snapshot of risk distribution for a population of items. While it does provide the percentages of equipment at various ranges in the risk matrix only at points in time, it tells nothing of risk drivers or risk escalation except from a very high level on an iterative basis. It does not discriminate what individual equipment items rose in risk or why.

Figure 3. Risk is dymamic API RBI Software Version 8.02 dynamic risk plot showing overall risk (top, dark green, curve), risk weighted HIC/SOHIC damage curve (second from top, light green), internal thinning curve (third from top, blue) over ten years or two projected turnaround cycles. The horizontal line at the “y” value of 50 represents a risk target or threshold of 50’sq./year. The plan period is 10 years. Note that an inspection for HIC/SOHIC

is being called for just before the overall risk for this component or vessel just before the risk target is achieved. If the damage is no worse than anticipated the HIC/SOHIC contribution to risk lessens, as we gain confidence in the true damage state through inspection. If this vessel were closer to end of life, the vertical slope of the damage/risk curves would increase and inspection would do little to nothing to decrease the slope/s.

In the next article I will continue by covering points 4 through 7 from the section, RBI Produces Helpful Metrics.


Items to be covered in future articles in this series:

• Case history examples of the impact of debits and credits on the PoF, risk and inspection strategies

• RBI and related management metrics – How can we know we are getting better? Leading and lagging measures.

• The importance of the damage/corrosion/materials review and usefulness of materials operating envelopes

• Piping reliability• Cross-functional group learning – The ultimate synergy and ROI• What do regulators have to say about RBI?• Design stage RBI• And more…..

If you have any questions about this article, would like further elaboration or reference information or are interested in other related topics, please send e-mail me at [email protected].

1 The 100 Largest Property Losses 1971-2001 (Large Property Damage Losses in the Hydrocarbon-Chemical Industry, 20th Edition: February 2003, A Publication of Marsh’s Risk Consulting Practice

2 New Forces at Work in Refining Industry - Views of Critical Business and Operations Trends, D. J. Peterson, Sergej Mahnovski , The Rand Corporation 2003, ISBN: 0-8330-3436-7

3 News Conference Statements U.S. Chemical Safety Board, October 31, 2006 by Chairman Carolyn Merritt

4 API Base Resource Document 581, 2nd Edition October 2000

5 Various past IJ articles on the subjects of RBI, damage mechanisms and NDE. Visit the on-line indices at http://www.inspectioneering.com/indices.htm

Gregory C. AlvaradoChief Editor

Inspectioneering Journal

http://www.inspectioneering.com/indices.htm


For Performance You Can Count On

Klad-AdforispectionV7.qxd 3/15/07 9:55 AM Page 1

Documents

INSPECTIONEERING JOURNALvir-inspection.com/assets/Inspectioneering_Journal... · 2 INSPECTIONEERING JOURNAL May/June 2007 Introduction The American Petroleum Institute (API) is issuing