the rusty chronicle - issue 02 december 2001[1]

NEWSLETTERMaterials and Inspection Engineering

December 2001

Confidential

‘The Rusty Chronicle’

EDITORIAL 3

RECENT/UPCOMING EVENTS 5

MATERIAL ISSUES 6A new Method to Determine Soil Corrosivity 6Low silicon carbon steel in sulphur-containing, high temperature environments 6Gas Plant cooling water problems 7Selection of gaskets for acid services 8Synergistic Effects of Chloride and H2S on Sulphide Stress 9Cracking/Stress Corrosion Cracking of Austenitic Stainless Steels 9New DEP 30.10.02.32-Gen for Cr-Mo Equipment 9Caustic SCC in Austenitic stainless steel 10St Fergus gas plant cuts potential vibration problems in pipework 11Welding Specifications latest developments 12

INSPECTION ISSUES 13Non Intrusive Inspection at elevated temperature 13Storage tank fabrication inspection - TOFD in lieu of RT 13101 Essential Elements in a PEI Management Program 15Engineering Highlights – Equilon Enterprises, LLC – October, 2001 18

AND NOW FOR SOMETHING A LITTLE MORE LIGHT-HEARTED 20The Rusty Crossword 20

LAST MINUTE HOT TOPICS 21New Hydrocarbon Accounting System - Potential for Corrosivity Mapping 21

WHO’S WHO IN OGEI 22

The Materials and Inspection Engineering Newsletter December 2001 - issue 2C

ON

FI

DE

NT

IA

L

Contents

NOTICEThe material in this Newsletter is for use by the operating units constituting Shell Global Solutions and the companies with which they have a service agreementonly, and is provided subject to the terms of the relevant service agreements. It is provided for the purpose of information only and should not be applied in anyspecific situation without having obtained further clarification and advice from Shell Global Solutions. The operating units constituting Shell Global Solutions acceptno liability for the application of the material contained herein by anyone.Copyright of this publication is vested in Shell Global Solutions International B.V., The Hague.

If you have any questions or comments about the Materials and Inspection Engineering Newsletter, please contact the editorDrew Green (Tel.: +31 (0)20 630 3167, E-mail: [email protected]).

New CUI Inspection and Maintenance Practice Being Issued

Corrosion under insulation (CUI) is older than our industry, and almost all processing facilities have

equipment that suffers from the “disease”. In some facilities in moist, warm climates, it’s a major expense,

whereas in others like arid climates it’s more of an occasional nuisance. Regardless, it still needs to be

managed properly in order to avoid reliability and process safety impacts on our business.

Shell Chemicals has identified CUI as a major threat to their business and has funded an effort to come

up with a practical, cost-effective inspection and maintenance program for operating facilities. To that

end, an international group of Shell inspection and maintenance engineers have assembled a new

standard (recommended practice) for risk-based inspection and maintenance of equipment susceptible to

CUI. That standard, which is due to be issued in January, describes how to assess the risk (probability

and consequence) of CUI, utilizing the Shell RAM (Risk Assessment Matrix). After assessing the CUI risk

associated with susceptible equipment and piping, the standard recommends one of six different

inspection strategies, commensurate with the level of risk associated with a potential CUI leak. I fully

expect that sites that implement such a risk-based program, will be able to achieve the lowest total cost of

ownership for their operating equipment susceptible to CUI.

The document contains a lot of information about the CUI problem and is easy to understand and apply.

In addition to the risk assessment and inspection strategy determination, the document includes sections

on CUI inspection tools and techniques, CUI record keeping, how to determine the likelihood and

susceptibility to CUI, information on coatings, cladding, and insulation, and CUI preventative

maintenance and restoration.

Many of our chemicals manufacturing sites have already begun to use the document. It’s a good example

of what an international network of subject-matter-experts can do in a relatively short period of time. I’m

aware of many other topics related to corrosion and asset integrity preservation, where site or national

standards currently exist, that would be good starting points for creating more international

recommended practices.

Contacts for further information are Andre Blaauw and John Reynolds.

M. A. (Mike) Rogalski

I’d like to draw your attention to two editorial errors noted in the last Rusty Chronicle - Issue 1-2001 as follows:

1. A glaring ommission in the Staff Moves section was that Mr John Whitfield was transferred out from the

position of OGEI/1 distributed team worker in Singapore to take up a new role as Integrity Manager

at Shell Chemicals Stanlow Site in the UK. To quote John “How often we forget those closest to us!”.

I wish John every success in his new job and offer my humble apologies for the error.

2. In the technical achievement section the SADAF Chemicals company in The Kingdom of Saudi Arabia was

referred to as a third party customer - SADAF is ofcourse a Shell joint venture company. Again

my apologies for the error.

Finally thanks to all those who have contributed to the Newsletter in 2001, without your support this publication

would simply not be possible. To all The Rusty Chronicle readers I wish you a happy and successful 2002.

Drew Green (Editor)

The Materials and Inspection Engineering Newsletter December 2001 - issue 2

CO

NF

ID

EN

TI

AL

3

Editorial


CO

NF

ID

EN

TI

AL

5

Far East and European MIEM 2001The Far East and European Materials and Inspection Engi-neering Meetings (MIEM) were held in Kuala Lumpur in Octo-ber and Amsterdam in November respectively. These meet-ings were again very popular with around 100 delegatesattending in total. The agenda covered a wide range of top-ics such as: Asset Integrity Management, External CorrosionManagement, The ever popular Technology Market with bothShell Global Solutions International and third party NDT spe-cialist service suppliers being represented, OP/EP CorrosionIssues, The current status of RBI/RRM and last but not leastNon Intrusive Inspection.

The agenda of the MIEM was modified to give more discus-sion time in the form of syndicate sessions. Although thesewere generally well received it was clear that we still havesome work to do in preparation and delivery of this aspectof the MIEM.

Delegates at the European MIEM gave an average CSI scoreof 3.6 (on a scale from 0-5), against our target of 3.5, whichillustrates that overall opinion is positive. Several points forimprovement were noted during the meetings and these willbe considered during the preparation for next years MIEM.Whilst we’re on the subject please note in your diaries thatthe European MIEM 2002 will be held in Amsterdam from10th to 12th June.

Finally we hope to issue the minutes from the 2001 MIEM inQ2/2002 at the latest.

Our thanks go to all the contributors and delegates whohelped to make the 2001 MIEMs such a success long may itcontinue.

Regards from the MIEM organising committee.

RECENT/UPCOMING EVENTS


ON

FI

DE

NT

IA

L

6

The Materials and Inspection Engineering group togetherwith the Network Environmental Risk Assessment (NERA)group have developed a pocket soil corrosivity meter and soilcorrosivity assessment method as an addition to Integrity riskassessment tools designed to improve equipment managementand reduce costs.

The pocket soil corrosivity meter can be used as a simple toolto quickly assess the potential corrosivity of a soil but it is alsoat the heart of a more extensive risk assessment study. It useselectrochemical techniques and yields more accurate resultsthan the commonly applied soil resistance measurement meth-ods.

The soil corrosivity risk assessment method, which has beencalled “Next Generation” (NG), is a structured approach todescribe the soil, material and site conditions. It allows every-thing from a desktop study and soil corrosivity measurementsfor prioritising underground equipment, to full corrosion andintegrity risk assessment studies. NG has the advantage ofbeing more accurate, flexible and, in most cases, cheaper inapplication than the currently available soil corrosivity assess-ment methods.

The tools can be used to answer questions like: “Do I needcathodic protection?”, “What is the corrosion risk of myunderground structures when the CP and/or the coatingfails?”, “Where along the pipeline or on my site are theareas with the highest corrosion risks?”, “What are the life

time expectations of my underground equipment and whatdo I have to do to control this?“ They can be used as stand-alone tools or as part of ongoing External Corrosion Man-agement.

The soil corrosivity risk assessment method and the pocket soilcorrosivity meter have been successfully used as part of theNERA package with projects in Europe, Africa and Japan.The “Pocket Soil Corrosivity Meter” and the NG method weremost recently successfully applied for corrosion risk assess-ments for BLNG and Shell Expro (Bacton).

For further information on the techniques or their applicationplease contact Johan Van Roij, Willem Liek or AndreaEtheridge.

A new Method to Determine Soil Corrosivity

MATERIAL ISSUES

A recent failure at MER illustrates the well-known failure ofcarbon steel serving in sulphidising atmospheres at elevatedtemperatures. This is a reminder of the necessity to specify sil-icon-killed steel in such an environment.

In November 2000, after 13 years in service, MER’s desu-perating column failed at an elbow of the bottom outlet pip-ing. The column was operating at 370 °C and in an envi-ronment containing 2.2% sulphur. The bottom was clad with410 SS, but the piping had been changed from 5Cr-0.5Moto carbon steel with a 0.1 % min silicon content specification.

The failure occurred near to an elbow. The piping upstreamof this elbow, just before a weld, showed a much higher cor-rosion rate than the downstream piping. This suggests that themetallurgy of the piping may have played a significant rolein the mechanism of failure.

The corrosion rate (since 1987) of this circuit varies from10 MPY to 18 MPY, except for 30 MPY of the failed elbow.

Silicon content of the replaced piping section was analysedand was found to vary from 0.19 to 0.25 % with the excep-tion of the failed elbow at 0.10 %, which still met the mini-mum specification requirement.

Silicon content is known to play a role in the mitigation of hightemperature sulphidation corrosion and there are many indus-trial and Shell experiences, similar to the above, attributedto low silicon carbon steel material (many of which can befound by searching the NACE Refin*Cor database). Differ-ences in corrosion rates, from 3 to 10 times higher, have beenfound in low silicon material. For this reason, it has been Shellstandard to use silicon-killed (A106) piping for high tem-perature applications where sulphur or H2S could be present,before temperature or sulphur levels dictate upgrading to 5Crsteel. Current practice is to use 5 Cr steel in slurry/LCO/HCOservice at temperatures above 240 – 250 °C.

For further information contact the Editor.

Low silicon carbon steel in sulphur-containing, hightemperature environments

The ‘Pocket Soil Corrosivity’ meter in use at Bacton.


CO

NF

ID

EN

TI

AL

7

As heat exchangers are a crucial part of LNG plants, it isessential to keep the interval between maintenance proce-dures as long as possible. From a starting point of the detailsof the cooling medium, improved maintenance intervals canbe achieved by careful materials selection and sufficient cor-rosion protection.

Corrosion damage recently observed in part of the seawa-ter heat exchanger system of an LNG plant has highlightedthe importance of these factors.

The following materials were used:Tubes: CuNi 66Cu30Ni2Fe2Mn;Tube sheets: carbon steel with aluminium-bronze explosion-bonded cladding on the water side;Channel boxes and covers: carbon steel with aluminiumbronze cladding. The plates were explosion clad and therest was overlay welded;Water lines: GRE;Gaskets: mostly brass corrugated double jacketed graphiteor non-asbestos filler.

The brass of the pass partition gasket, as the least noble metal,corroded resulting in a narrow gap. Seawater bypass start-ed at this narrow gap in the corroded portion of the gasket,and the seawater velocity caused erosion induced corrosionof the pass partition and the grooves in the tubesheet/chan-nel cover. The temporary repairs made to keep the system run-ning need to be completed now by an extensive repair cam-paign. Replacement of the gaskets with more suitablematerials will eliminate some of the problems in the future.

At the same time, pitting corrosion of the aluminium bronzeoccurred; in particular in the weld overlay areas. The sensi-tivity of the aluminium bronze to pitting remains a concern.With the relatively low iron content of the seawater in that partof the world, soft iron anodes have proven to protect the alu-minium bronze. Apart from electrochemical protection, addi-tion of iron to the seawater may offer a mechanism of pro-tection since copper-based alloys require some iron in orderto build a protective scale.

However, since the soft iron anodes have an expected life,which is shorter than that required by the major mainte-nance cycles and extra ferrous ion dosing is not allowed, ithas been decided instead to install an impressed currentcathodic protection system to the majority of the seawater heatexchangers. The objective of such a system is to polarise thealuminium bronze surface of the tube sheets and channelboxes by -100 mV to stop the observed galvanic corrosion.This method is suitable for the protection of the in- and out-let channel boxes and for the return channel boxes of the non-floating head exchangers.

For the floating heads, the impracticalities of installing noz-zles, anodes and cabling have resulted in another solution.Using an aluminium spray coating will protect the floatinghead and the accompanying tubesheet in this area. An alu-minium spray coating is sacrificial to the aluminium bronzeand CuNi. Therefore, coating of the tubesheets is without riskof preferential galvanic corrosion of the aluminium bronzecladding by the CuNi tubes, if there is any small damage ofthe coating.

For further information contact Simon Marsh

Gas Plant cooling water problems

Pitting on an Aluminium Bronze tubesheet.


ON

FI

DE

NT

IA

L

8

IntroductionBerre site located south of France operates chemical plantsusing acid (e.g. H2SO4) in the process. In 1996 we bannedall asbestos gaskets and from 1997 to 2000, we contractedone supplier for acid gasket (PGACF from Siem Supranite).But increase of gasket budget (especially maintenance costsduring turnaround) was a big concern for maintenance peo-ple. We estimate mean costs increased by roughly 450kEuro/year for piping and vessels. In consequence a studywas conducted in order to seek and to approve new gaskets,and to negotiate a new 3 years contract.

SummaryFrom Shell MESC specification SPE 85/104 & suppliers datawe selected eight gaskets from six suppliers, and tested themfollowing CEN standard procedure. Tests were conducted bythe French Cetim organisation who are specialised in labo-ratory tests for valves and gaskets. Tests consisted of leakage,thickness change, creep measurements at service tempera-tures, and visual examination.

Only four gaskets were accepted. The others were sub-stan-dard and two were found dangerous for acid service.

ConclusionMany suppliers were prepared to provide gaskets but onlya few are fit for service. This study will allow us to reduce gas-ket expenditure while maintaining a good level of quality &safety. You can obtain more information from the author.

Example of leakage curve Samples diameter 40 mm Pressure 40 bar Helium In red: Temperature range from 20 °C to 260 °C In blue: Leak of Helium (atm.cm3/s)

Example of gasket photographyBad gasket after - before test

Good gasket after - before test

References• Cetim test report - 16th January 2001• CEN standard Pr En 13555 • Shell MESC SPE 85/104 Gaskets, PTFE, reinforced with

mineral filler.

For further information contact Philippe Fevrier, Shell Chemicals Berre

Selection of gaskets for acid services


CO

NF

ID

EN

TI

AL

9

A new DEP titled “MATERIALS AND FABRICATION REQUIRE-MENTS FOR Cr-Mo HEAVY WALL PRESSURE VESSELS(AMENDMENTS/SUPPLEMENTS TO API 934)” will be includ-ed on the next DEP CD-ROM. The issue of this DEP is timelysince there are several new hydroprocessing projects currentlybeing developed to address the need for lower sulphur prod-uct specifications and this DEP will be used for the reactor ves-sels and high pressure heat exchanger equipment.

As you can see by the title, this DEP is in fact an endorsement,with a few additional requirements, of the recently publishedAPI 934 Recommended Practice (RP), which addresses thesame subject. This industry consensus document brings togeth-er the best practices and experiences of all the major engi-neering contractors, fabricators and end users and has takenmany years of committee effort and review cycles. Here is abrief history of the document highlighting the input and con-tributions of several Shell and Equilon staff members.

In early 1990 it was felt that there was sufficient commonal-ity between the end user and contractor specifications for Cr-Mo equipment that an industry standard could be developedthat could ultimately reduce costs and delivery times for

hydroprocessing reactors. A Materials Properties Council(MPC) committee of interested parties was put together tostudy this proposal and create a draft standard from a ques-tionnaire that evaluated end user best practices and require-ments. I formed and chaired this original MPC committee,prior to joining Shell. In 1996 the MPC committee proposalfor a standard specification was sent to the AmericanPetroleum Institute (API) with a recommendation that a RP bedeveloped. After a few years of additional work the RP wasready for balloting. Hearl Mead and Dick Horvath of Equi-lon were very active in resolving the ballot comments and get-ting this RP to the publication stage. The RP was finally pub-lished in early 2001. Andre Blaauw then took the lead ingetting the DEP ready. This DEP has now been fully approvedand implemented in the Shell GSI standards system.

It is hoped that the use of this DEP/API RP on Shell SGI pro-jects will make it easier, quicker and cheaper to purchasereactors and other high pressure Cr-Mo equipment that com-plies with rigorous industry standardised materials compo-sition, testing, fabrication and inspection requirements.

For further information contact Keith Lewis

New DEP 30.10.02.32-Gen for Cr-Mo Equipment

Shell GSI have recently investigated a case of Stress Corro-sion Cracking on a new facility. The mechanism is reportedas Chloride Stress Corrosion Cracking, however the causecannot positively be traced to the presence of ‘’significantlyhigh’’ levels of chloride alone. It is currently believed that thepresence of H2S may have played a role in the crackingmechanism.

For certain Austenitic Stainless steels, it has been recognizedthat there may be a synergistic effect of certain species, suchas Chloride, on Sulphide Stress Cracking and/or H2S onChloride Stress Corrosion Cracking. To date, no quantitativelimiting guidelines have been able to be given.

There is currently a proposed Revision to NACE StandardMR0175 - 2001, in which quantitative guidelines are givenfor various austenitic stainless steels, defining acceptable lim-its, where applicable, for temperature, H2S pp, CO2 pp.and Chloride level.

As a guideline, 18/8 Austenitic Stainless Steels are limitedto a maximum temperature of 60 °C and 100 KPa abs. H2Spp, for Chloride levels exceeding 50 mg/l. If Chloride is< 50 mg/l, the allowable H2S pp may be raised to a maxi-mum of 350 KPa abs.

For further information contact Marc Kemp

Synergistic Effects of Chloride and H2S on Sulphide Stress Cracking/Stress Corrosion Cracking of Austenitic Stainless Steels


ON

FI

DE

NT

IA

L

10

A newly constructed Type 347 SS component failed recent-ly after less than 40 hours of service primarily exposed tosteam. The failure consisted of severe cracking of weldsthroughout the component. Most of the cracking was of cir-cumferential welds that had not been stress-relieved, butother welds also cracked. Cracks ran both along the lengthof the welds and perpendicular to the welds.

Metallographic cross sections showed that the cracks weretransgranular and highly branched. Most materials and cor-rosion engineers associate this appearance so closely withchloride Stress Corrosion Cracking (SCC) that one can eas-ily jump to the wrong conclusion without careful considera-tion of all evidence. A recent paper calls caustic SCC ofstainless steels a “forgotten phenomenon” because most studyof this failure mechanism was done about thirty years ago.*Most metallurgists are familiar with caustic cracking of car-bon steel, but caustic cracking of austenitic stainless steels isless well-known.

The point of this note is to review some of the important evi-dence in identifying a caustic SCC failure mode and to cre-ate awareness of the problem. This kind of failure can bequick, unexpected, and spectacular. Care must be taken indesign and operation to avoid these failures.

Identification:1. The most important point in identifying caustic SCC is

that the cracks may be either transgranular or inter-granular. Transgranular caustic SCC will have the samebranched appearance as chloride SCC, and crackappearance alone is not a reliable means of distin-guishing between these failure modes.

2. The presence of caustic within the cracks is very goodevidence for caustic SCC. A quick test that will givesome evidence is to wet the fracture surface with a dropof water and measure the pH of the water using pHpaper. A basic pH suggests the presence of caustic.More reliable evidence can be found by looking forsodium or potassium and oxygen in a crack using anSEM with X-ray spectroscopy capabilities. Dry grindinga cross section of a crack is the most direct way to lookfor these elements, but liquid extraction can be veryeffective as well. Because many caustic supplies alsocontain chlorides, chloride may be coincident with sodi-um. The presence of chloride is not necessarily evidenceof chloride SCC.

3. Caustic SCC may propagate very quickly. Crack growthrates of a quarter inch (6.25 mm) per hour have beenmeasured in Type 347 SS. A very fast failure is a rea-son to suspect caustic SCC.

4. Caustic SCC may sometimes produce a “bluing” of thefracture surface. While this color change should not beconsidered a reliable evidence, some of the fracture sur-faces in the most recent failure were a deep blue color.

Awareness1. Cracking can occur very quickly. If hot caustic of any

concentration is contacting stainless steel equipment, therisk of cracking is immediate. For temperatures above300°F (150 °C), any concentration over 20% can causecracking within a day. Lower concentrations requirehigher temperatures, but temperatures near 600 °F(315 °C) can cause cracking within a day at any con-centration. These exposures must be avoided, and ifthey occur, the equipment should be inspected as quick-ly as possible. Temperatures as low as 200 °F (100 °C)can cause cracking within 100 to 300 days, and thesafe limit is now considered to be in the 150 °F (65 °C)to 200 °F (100 °C) range.

2. Stress relief offers some protection, but this protection isnot certain. Very low stress levels can propagate causticstress cracks, and elimination of the caustic exposure isthe only certain mitigation.

3. Alloys with higher nickel content have improved resis-tance to caustic SCC, but they are not immune. Molyb-denum makes a stainless steel more susceptible to caus-tic SCC, so Type 316 SS will have less resistance thanType 304 SS. At some caustic concentrations, sensitizedstainless steel is much more susceptible than non-sensi-tized stainless steel. Therefore low-carbon and stabi-lized grades may offer improved resistance.

4. Coatings have offered good resistance to externalcracking where caustic splashes or drips on equipmentwalls. Protective coatings are particularly recommendedfor Corrosion Under Insulation (CUI) situations.

Caustic SCC in Austenitic stainless steel

This micrograph shows a small network of secondary cracks near the initiation

point of a large crack.


CO

NF

ID

EN

TI

AL

11

Although there can be pitfalls in the diagnosis of a causticstress corrosion cracking problem in austenitic stainless steels,the analysis is straightforward when all of the evidence iscarefully collected and evaluated. Operational variables,particularly temperature, are very important in this analysis.Avoidance depends on awareness and precautions to avoidexposure of stainless steels to hot caustic.

* Esmacher, M.J., Stress Corrosion Cracking of Stainless SteelComponents in Steam Service, Paper No. 1496, Corrosion2001 Conference Papers, Houston, Texas, 2001.

For further information contact Bill Kelly PEI

Shell Global Solutions has played a key role in enabling theSt Fergus gas plant in the UK to increase throughput safelyby minimising the risk of vibrational fatigue in the key pip-ing systems, and hence avoid major spending on new infras-tructure.

A joint team from Shell Global Solutions, Shell St Fergus andATL Consulting used a new vibration management procedureto identify those main lines and small-bore connections at theplant with an increased potential risk from vibration failure.Shell Global Solutions and ATL have developed the procedure.After the study, preventive measures could confidently betaken to minimise fatigue prior to the planned increase inthroughput.

Out of several thousands of piping connections affected bythe increased production, only a small proportion requiredbracing. This bracing will lead to both higher plant availabilityand increased health, safety and environment integrity at theSt. Fergus plant.

One of the most significant benefits will be the minimisationof unexpected, potentially hazardous and extremely expen-sive, small-bore connection failures. The magnitude of poten-tial production savings can be illustrated by realising that theaverage downtime to repair a broken small-bore connectioncan be about a day. On an average-sized gas plant this couldeasily mean $0.5 million in lost production.

At St Fergus 342 main lines were assessed. The vibrationmanagement procedure revealed that 264 of these lineswould not suffer sufficient vibration, under the proposedthroughputs, for the small-bore connections or mainlinepipework to be a concern. A further four were shown to needvibration monitoring when throughput increases.

However, 78 lines, required specialist, detailed analysis toquantify the risk of failure. Of these, 22 lines (6 systems) were

identified as requiring main-line modifications. In addition,70 lines needed their small-bore connections to be checked– adequate protection can often be provided by simple brac-ing or removal of cantilevered masses (e.g. isolation valveson low-point drains or high-point vents) if required.

As a consequence of the work at St. Fergus a managementprocedure was developed that can be generically applied asthe template for specific projects, plant changes and siteobservations. Application of this management process alsoenables technology transfer to local personnel, to allow man-agement of threatening vibrational fatigue to continue afterthe study team has dispersed.

A software package, part of the vibration management pro-cedure, offers a proactive methodology that can be carriedout by on-site personnel with no specific vibration expertise,such as mechanical or inspection engineers. A further advan-tage is that assessment time for small-bore connections andmain-line pipework is typically reduced by about 75% usingthe vibration management procedure in comparison to the tra-ditional assessment methods. In addition, a verifiable audittrail is created.

For further information contact Tom Martin

St Fergus gas plant cuts potential vibration problems in pipework


ON

FI

DE

NT

IA

L

12

Major oil companies have compared their company ownedwelding specifications and developed a generic weldingspecification, which has recently been published as:

API 582: Recommended Practice and Supplementary WeldingGuidelines for the Chemical, Oil, and Gas Industries. Don Kim of Equilon has played a major role in achieving thismilestone. The aim is that this API recommended practice willprovide uniformity in setting welding requirements This Recommended Practice provides supplementary guide-lines and practices for welding and welding related topics forshop and field fabrication, repair and modification of:a. Pressure-containing equipment such as pressure vessels,

heat exchangers, tankage, piping, heater tubes, pres-sure boundaries of rotating equipment, and attachmentswelded thereto.

b. Non-removable internals for pressure vessels

c. Structural items attached and related to process equip-ment

d. Any other equipment or component item when refer-enced by an applicable purchase document

This API document is general in nature and is intended to aug-ment the welding requirements of ASME Section IX and sim-ilar Codes, Standards and Practices. The intent of API 582 isto be inclusive of Chemical, Oil and Gas Industry standards,although there are many areas not covered herein, e.g.pipeline welding and offshore structural welding are inten-tionally not covered.

It is the intention that API 582 will replace the general sec-tion of DEP 30.10.60.18 Welding of Metals. Specific weld-ing issues will be covered with the development of weldingbest practices on an as needed basis.

For further information contact Andre Blaauw

Welding Specifications latest developments


CO

NF

ID

EN

TI

AL

13

During a tank construction project for one of the operatingunits a first time application was realised, inspecting thewelds of a storage tank by automated ultrasonics in lieu ofradiography (RT). At the request of the tank construction con-tractor a change in the inspection approach was proposed,with the clear benefit of shorter fabrication schedules in thefuture.

The OU project team requested Shell Global Solutions tosupport them with the approval of the proposed procedure.Salient aspects and learning points from this exercise aregiven below:

The ultrasonic inspection was initially based on the require-ments as stated in ASME Code Case 22351, which is appli-cable to a wall thickness range of 0.5”-12”. The Code Caseprovides accept/reject criteria purely based on defect dimen-sions and requires sizing techniques to be used havingdemonstrated an “acceptable performance”. The conse-quence is that in the range of interest (<1” WT) only the Timeof Flight Diffraction technique can meet code requirements.

Upon implementation, for the lower wall thickness range, theflaw length rejection criteria appeared so tight that this wouldresult in too many rejected indications, thus unnecessaryrepairs. Therefore the criteria of the Draft European code forTOFD2 were included in this project, amalgamated with com-plementary ASME Code Case requirements.

The requirements of the ASME Code Case clearly reflect theintent to produce an objective, reproducible inspection result:it requires automated examination; it also avoids charac-terising indications as planar/non-planar, treating all thesame.

Although TOFD was chosen as the main technique it becamevery clear that additional pulse echo angle beam examina-tion (PE) was required to fully satisfy the Code requirements.A learning point of the whole exercise was that the mix of

TOFD and PE is strongly determined by the restrictions onaccess (it was for instance decided that the main inspectionshould be carried out from one side of the plate only) and bythe geometry of the welds. At the end some welds had to beexcluded from UT (falling back on RT) because TOFD hadunacceptably large blind zones in places.

A significant effort was given to the validation of the proce-dure, inspection system and personnel, following a formalsystem as defined in the European Inspection QualificationMethodology for the Pressure Equipment Industry, based onpractical assessment and technical justification. Such a rig-orous validation was required as the contractor had to forcethe inspection team up the learning curve in a relatively shortperiod of time, including training by an experienced NDT con-tractor prior to mobilisation and training and validation dur-ing the implementation on-site.

For rounding off the field validation the need arose to carryout a formal, independent validation of the inspection per-sonnel. For this purpose an independent validation was car-ried out of the personnel aspects, by an institute independentfrom Shell, the Inspection Validation Centre (IVC) from the UK.This approach qualified the inspection team, allowing the con-tractor to start implementing the ultrasonic inspection on thetank.

References1. ASME Boiler and Pressure Vessel Code, Case 2235-2,

“Use of ultrasonic examination in Lieu of Radiography,Section VIII, Division 1 and 2”, Approval Date: Febru-ary 7, 2000 (followed now by 2235-3, July 10, 2001)

2. Draft European Standard, prEN XXXX, 19th November1997, “Acceptance criteria for the Time of FlightDiffraction inspection technique, Document TO 97-50rev.1”.

For further information contact Sieger Terpstraor Michell Schipper

Storage tank fabrication inspection - TOFD in lieu of RT

On Shell Nederland Chemicals site at Moerdijk non intrusiveinspection has been carried out on a reactor vessel and a heatexchanger shell of the MSPO plant. With the inspection of thereactor SNC could avoid opening up the vessel in an upcom-ing shutdown, while inspection of the heat exchanger shellavoided a required shut down well before the planned shut-down to enable replacement of the shell. The special natureof these inspections was that they combined the need toinspect for very small pitting and cracking at a temperatureof around 160 °C.

Inspection MSPO reactor vesselSeveral years ago an on-stream inspection was developed forSeraya Chemicals, to inspect their SMPO EBHP reactor ves-sel. This demonstrated that small pitting in the order of 2-5mm diameter and 2-5 mm depth in the wall of a stainless steelvessel (20 mm WT) could be detected reliably by ultrasonicsemi-mechanised inspection, at a temperature of 160 °C. Sev-eral repeat measurements proved the reproducibility of thesemeasurements, although some teething problems had to beovercome when inspecting at 160 °C.

Non Intrusive Inspection at elevated temperature

INSPECTION ISSUES


ON

FI

DE

NT

IA

L

14

A similar inspection was required this time on the EBHP reac-tor in Moerdijk; however, the presence of a roll bond claddingat the inside provided an additional challenge: the interfaceecho from the clad-to-basemetal transition produces an ultra-sonic echo that is in the order of the respons from pitting inthe given size range.

An option that is not feasible is to try to detect a pit-echo inbetween the cladlayer echoes; that would require an extreme-ly high resolution and an unrealistic setting of gates andthresholds to detect these pit echoes. With simple, fast scan-ning semi-mechanised systems such as “Mapscan”, ‘And-scan”, or “Seescan” this will not lead to a robust scan set-up.

The way out of this problem was found by carefully selectingthe probe, optimising the response of the pit-echo relative tothe clad interface echo. This allowed robust echo-detection,as depicted in figure 1.

With such a probe, capable to operate at elevated temper-ature, tests were performed on pitted specimens at elevatedtemperature, to demonstrate that the system was able todetect the defects. During the actual inspection on the reac-tor no defects were detected, but it could be proven that theinspection was carried out with the required sensitivity byclosely watching the echo patterns during scanning. Theinspection proved to be very successful.

Pitting and crack detection in heat exchang-er headerA heat exchanger header box, made of stainless steel 321,needed inspection to demonstrate that cracks found duringan earlier internal inspection had not grown. Although a smallitem by its size, the non intrusive inspection was not straight-forward, giving some interesting learning points.

With eddy current the majority of the header could be inspect-ed, but material properties of the upper nozzle and an areaof the header shell around the nozzle disturbed the eddy cur-rent inspection. This had to be inspected with ultrasonics.

The angle beam inspection for cracks was outwith normalpractice, requiring scanning at a carefully selected sensitivi-ty, also in many directions, because of the unknown orien-tation of the cracks; aim was to ensure detection of signifi-cant cracks if present (for which FFP analysis was done) andavoid false calls on minute SCC that had remained after aprevious repair. Inspection near the shell-nozzle weld requiredextra care as well, to avoid false calls from the grainy weldmaterial.

A specification was prepared by Shell Global Solutions, sothat SNC could develop a procedure together with the NDTcontractor. Procedure and contractor team were validatedprior to field inspection, whereafter a successful inspectioncould be carried out.

For further information contact Michell Schipper or Sieger TerpstraThanks to Rien Neggers of SNC Moerdijk

Figure 1 With an ultrasonic normal beam probe on a cladded reactor wall

echoes are obtained from the clad interface, backwall of the

cladding surface, and a possible pit in the 3 mm thick clad layer. If

the pit would grow through the clad layer into the C-steel base

metal then an echo would appear in front of the interface echo.

Figure 2 Stainless steel header box requiring non intrusive inspection. UT was

applied to the top nozzle and the shell around it, the remainder was

covered by eddy current.


CO

NF

ID

EN

TI

AL

15

SummaryThis item contains a significantly shortened version of JohnReynolds’ original paper. In the interest of saving space butstill giving you a good flavour of what’s on offer only the first10 of the actual 101essential elements are included. Com-plete copies of the article are available from the author or theeditor.

Abstract The full paper outlines the 101 essential elements that need tobe in place, and functioning well, to effectively and effi-ciently, preserve and protect the reliability and integrity ofpressure equipment (vessels, exchangers, furnaces, boilers,piping, tanks, relief systems) in the refining and petrochem-ical industry. This paper is not just about minimum compli-ance with rules, regulations or standards; rather it is aboutwhat needs to be accomplished to build and maintain a pro-gram of operational excellence in pressure equipment integri-ty that will permit owner-users to make maximum use of theirphysical assets to generate income. Compliance is not the keyto success in pressure equipment integrity management(PEIM); operational excellence is.

Each of the 101 work processes outlined in this paper, isexplained concisely to the extent necessary, so that owner-users will know what needs to be done to maintain andimprove their PEIM program. This paper does not prescribehow each of these 101 key elements is to be accomplished,as that description would result in a book rather than apaper. This paper simply outlines all the fundamentals that arenecessary to avoid losses, avoid safety incidents, and main-tain reliability of pressure equipment. It pulls together a com-plete overview of the entire spectrum of programs, proce-dures, and preventative measures needed to achieve firstquartile performance in maintaining pressure equipmentintegrity (PEI).

The first ten essential elements ofPEIM

Management of Change (MOC) for PEIIssuesMOC is one of the most important aspects PEIM. There is amultitude of incidents that can be traced to changes thatwere made in the hardware or process chemistry that even-tually caused a breech of containment. Process chemistrychanges are equally, if not more important than hardwarechanges when it comes to the need for effective MOC. Unfor-tunately, many involved more in the operation and processside of our business, sometimes make changes to equipmentand process variables, assuming that any change in materi-al degradation will be picked up in the next inspection. That’ssimply not the way it works. Inspectors must know aboutthese changes in order to change their inspection strategy and

tactics, or the results may well be a breech of containment.

Do you have an effective MOC work process in place that willallow inspectors to know when and if they need to changeinspection methods and schedule, to account for a processchange?

Positive Material Identification (PMI)An effective PMI program for new and existing alloy pipingsystems is another top priority for PEIM. API RP 578, Mate-rial Verification for New and Existing Alloy Piping Systems,is an excellent document for instituting an effective PMI pro-gram for new installations, maintenance materials, and forchecking of materials of existing systems, in-service, thatmay have rogue materials in place. Time and time again,users report incidents related to the failure of a piece of a pip-ing system that was not the same as that specified for the restof the piping system. PMI surveys, made by users looking foroff-spec material, routinely report finding between 1 and3% incorrect materials, with some reporting non-confor-mances up in the double digits. I believe that PMI problemsaccount for one of the leading causes of breaches of con-tainment in our industry which are classified as mechanicalintegrity incidents.

Are you using API 578 effectively to identify rogue materi-als that might cause unexpected failures in your pressureequipment, for both new and existing equipment?

Temporary Repairs and InstallationsAn effective QA/QC program must be in place to assure thattemporary repairs are completed, only by qualified person-nel, using approved methods and procedures, so that the riskof an incident is not increased by faulty or inadequate repairs.This includes all leak sealing and leak dissipating devices.Likewise, it is necessary to record and track temporary pip-ing installations, to make sure they are adequate for the pur-pose intended and the length of time intended. An effectiveMOC procedure should cover both of these issues.

Do you have an effective work process in place for tempo-rary repairs and temporary installations that will avoidunscheduled outages from the failures of inappropriaterepairs or installations?

Key and Critical (K/C) Materials Degradation VariablesIdentifying, documenting, and implementing K/C variablesfor all historic and potential issues that could impact pressureequipment integrity, is of utmost importance. There needs tobe a systematic process, involving appropriate subject mat-ter experts (SME’s) to identify and document each processvariable that must stay within a specific range in order notto increase the chances of equipment failure beyond that nor-

101 Essential Elements in a PEI Management Program


ON

FI

DE

NT

IA

L

16

mally expected. Then, an effective implementation process,including operator training, on each K/C variable, needs tobe accomplished. These K/C variables include not only thestandard pressures and temperatures, but often include flowrates, a multitude of chemistry limitations, hydrogen partialpressures, heating and cooling rates, moisture contents, chlo-ride contamination limits, and a large variety of other vari-ables that may affect the ability of construction materials toresist degradation. Establishing and changing the list of PEIK/C variables should be another MOC issue.

Do you have all the key and critical operating variables, thatcan cause materials degradation, identified, documented,communicated and understood by operators in your plant?

Materials and Corrosion Engineering Routine access to subject matter experts (SME’s) in materialsand corrosion is paramount for any process unit that is or hasthe potential for being corrosive or otherwise causing mate-rials degradation that could lead to unexpected equipmentfailure. This expertise needs to be brought to bear, pro-active-ly, to prevent materials problems as well as reactively tounderstand and solve corrosion problems. To be most effec-tive these SME’s need to work very closely with inspectors, aswell as equipment and process engineers. The most wellrounded materials and corrosion SME’s should be knowl-edgeable, not just in metallurgy and materials selection, butalso in process chemistry, corrosion and degradation mech-anisms, corrosion and materials degradation prevention andmitigation.

Do you have easy access to materials and corrosion SME’swho provide guidance and knowledge transfer to your inspec-tors, in order to be able to predict where and when degra-dation will occur, so that inspections can be scheduled to avoidunexpected breeches of containment?

Inspection for Environmental CrackingAn effective inspection program must be in place if there isa potential for any of the multitude of possible environmen-tally caused cracking mechanisms, e.g. caustics, amines,chlorides, wet hydrogen sulfide, polythionic acids, ammonia,dearators, etc. An effective prevention program, led by theSME’s referenced above, is vital to such an effort; but whenthere is still a potential, an effective inspection program (tools,techniques, procedures, methods) must be in place to detectthe presence of environmental cracking. These programs,including the proper surface preparation, must be sensitiveenough to detect and quantify the damage that is occurring,if any. Materials and corrosion SME’s are vital to under-standing and predicting when and where any of these envi-ronmentally caused cracking mechanisms may be an issue.

Do you have all potential environmentally caused crackingmechanisms identified, and appropriate inspections planned,to avoid cracking failures in your pressure equipment?

Furnace Monitoring and InspectionFurnaces often are big contributors to reliability problems inmajor hydrocarbon process facilities. As such, an effectivefurnace program to monitor flame patterns, tube tempera-tures, hot spots, etc. is important to preventing tube leaks andruptures. Likewise, when a furnace is down for inspection andmaintenance, inspectors and engineers, knowledgeable inpotential deterioration mechanisms for tubulars, structuralmembers and refractory need to specify and implement aneffective inspection and data analysis effort. This effort willidentify potential causes of deterioration and predict remain-ing life of each furnace coil in the radiant and convection sec-tions. Furnace inspection and maintenance is a specializedbody of knowledge that needs to be imparted to thoseinvolved, in order to avoid unexpected reliability hits whena furnace comes off line in the middle of a run. And, don’talways assume that furnace tube failures are just reliabilityproblems; as higher-pressure hydroprocess furnace tube rup-tures have resulted in injuries and fatalities? The last fatalityfrom a furnace tube rupture, that I’m familiar with, occurredjust a few years ago at a Canadian refinery.

Do all your furnace coils have a reliable structural integrityanalysis and remnant life prediction so that you will not besurprised by predictable failures that could have been avoid-ed by scheduled inspection and maintenance?

Brittle Fracture PreventionOn the opposite end of the temperature spectrum from fur-naces is the need to have an effective program in place forthe prevention of brittle fracture. An in-service brittle fractureis one of those very low probabilities – very high conse-quence events that must be avoided at all costs. Hence inspec-tors, engineers and operators must be knowledgeable in thepotential for brittle fracture of materials operating belowtheir brittle to ductile transition temperature (that’s metallur-gical speak for operating below a temperature range wherethey are suitable). API RP 920, Prevention of Brittle Fractureof Pressure Vessels, outlines some effective inspection andmaintenance steps to take to avoid this potential. Special careand procedures are necessary to control cooling and heat-ing rates of heavy wall equipment in hydroprocess environ-ments. The new API RP 579, Fitness for Service also providesexcellent guidance on how to assess the potential for brittlefracture of equipment. Every few years I read about an enor-mous, catastrophic loss from brittle fracture. The last one wasin a gas plant in Australia, which resulted in two fatalities anda very large loss for the company, as well as a huge impacton customers.

Do all the right people at your plant know the minimumdesign metal temperature (MDMT) of all your equipment andhow to avoid the potential of brittle fracture, especially fromoperating upsets?


CO

NF

ID

EN

TI

AL

17

Effective Inspection Record Keeping SystemsEffective inspection record keeping systems are fundamentalto an effective PEIM program. Yet, often, inadequate recordkeeping is at the root of equipment failures and reliabilityproblems. Effective record keeping is not fun and it does notusually get much notice, until there is a major incident, andinadequate records are found to be a major contributing fac-tor. There must be an effective Inspection Data ManagementProgram (IDMP) in place and it must be kept up to date, oryou cannot have an effective PEIM program. This is such avital aspect, that regular internal audits should be conduct-ed by those knowledgeable in effective records systems todetermine if and where deficiencies exist. Just a couple ofyears ago, a refinery in Texas suffered a large incident whena section of pipe ruptured. Inadequate record keeping prac-tices were a primary cause, since it was previously known thatthe pipe was getting thin.

Do you keep all the data and information in your IDMP com-pletely up to date, with all the pertinent information from pre-vious inspections, so that you can assess the integrity of yourequipment and schedule the next inspection on the basis ofnecessary facts?

Flare System InspectionFlare systems must be inspected routinely for fouling andcorrosion. Clearly, when we need our flare systems to oper-ate in accordance with design under emergency relief con-ditions, we want to be assured that they are not fouled ordegraded. Radiographic inspections for fouling material atstrategic points will sometimes reveal that the flare lines arepartially plugged; in which case some maintenance and/oroperating measures to clear the restrictions will be necessary.Ultrasonic scanning and/or radiographic inspections forthinning are also vital to integrity management of flare sys-tems. Major disasters have occurred when thin flare lines sep-arated and fell to the ground during slug flow conditions thathave occurred during emergency relief scenarios. The last onethat I’m aware of occurred in a refinery in Great Britain inthe early 90’s.

Are your flare systems “out of sight – out of mind”; or do youdo sufficient monitoring and maintenance to rest assuredthat your most important emergency control system will per-form in accordance with design, when you need it most?

For further information contact John T. Reynolds


ON

FI

DE

NT

IA

L

18

Turnaround Work Scope Assessment forPhenol-3 at DPCP

Author: John Reynolds, Pressure EquipmentIntegrityRequestor/Sponsor: Steve Rathweg/Joe Gilbert

A risk-based turnaround work scope assessment was con-ducted on numerous equipment items scheduled for inspec-tion and maintenance in the planned March/02 turnaroundfor PA-3. Using risk-based assessments, several large equip-ment items (columns and reboilers) were determined to be suit-able for consideration to extend internal inspection require-ments until the next turnaround, without incurringunacceptable risks (safety or reliability). This work process alsoallows turnaround planners to balance major inspectionsover the coming decade, as opposed to having them all fallearly in the decade during the upcoming turnaround. Thework process consumed about 30-40 person hours, and isexpected to save several hundred thousand dollars in Marchturnaround costs, and possibly much more if the scheduledturnaround can now be shortened.

PSRC FCCU Cat Losses Investigation andCorrection

R. A. Sanborn and Y. Chen, Energy & EquipmentEngineering, J. A. Horwege, Pressure EquipmentIntegrity, K. Kraft, PSRC, R. A. Arbesman, CatCrackingSponsor: Joe Wall - Tech Manager

The PSRC FCCU began experiencing high catalyst losses inMay. The losses increased slowly over the summer. In the lastweek in August, losses jumped to unacceptable levels(100TPD). WTC worked with PSRC staff to perform on-siteinspection and process analysis. It was determined that thecause of the loss was very severe localized erosion in thecyclone system. The erosion was due to partial bypassing ofthe primary cyclone due to a short “Gas Outlet Tube” in theprimary cyclones. WTC designed short term corrections toreduce the erosion, and provided risk based repair recom-mendations and details to allow operation to the next sched-uled turnaround. While the FCCU was down for these repairs,WTC led a risk analysis of the balance of the unit and inspect-ed other high risk areas. This inspection identified two slidevalves that required significant repairs to complete the run withminimal risk of an additional unscheduled shutdown. The unitwas restarted with normal operation in September. The esti-mated savings for PSRC related to reducing the potentialduration of this unscheduled shutdown is in the order of$800,000.

EMPRVAuthor: Greg Briner, Pressure Equipment Inspec-tion Department Sponsor: G. K. King – Martinez Refining

Inspection Data Management Software was implemented at

the EQUILON - Bakersfield Refinery in September of 2001.This project consisted of 40+ hours of hands-on classroomtraining and competency testing for the users, while the exist-ing Ultrapipe database was being converted into the EMPRVOracle database format.

Martinez FCCU Power Recovery TurbineVibration

Authors: J. A. Horwege, Pressure EquipmentIntegrity, M. J. Drosjack, Reliability & ProcessSafety, R.A. Sanborn, Energy & Equipment Engi-neering, R. A. Arbesman, Cat Cracking, JohnFelten and K.S. Taylor, Martinez Sponsor: W. J. McNally Manager Cracked Prod-ucts, Martinez

The Martinez FCCU Power Recovery Turbine (Hot GasExpander) has been experiencing increased vibration sinceApril. The vibration was not reduced by normal on-linecleaning techniques. Analysis of the vibration data sug-gested that the problem might be related to pipe supports orexpansion joints on the inlet or outlet pipe. WTC providedon site inspection, definition and analysis of measurementsthat concluded that although the support was not functioningas designed, and was significantly different than best prac-tice design, the pipe system was probably not the cause ofthe vibration. WTC provided design details for short term cor-rections to the pipe supports that will minimize the risk of mal-function until a planned replacement of the pipe to reflectproven best practice is complete. The actual cause of thevibration was blade erosion due to high catalyst losses fromthe Third Stage Separator (TSS). WTC coordinated theinspection of the TSS and determined that the cat losses werecaused by partial blockage of the TSS by refractory debris.

Remote Installation of Monitoring Softwareat Stanlow, UK

Author: Automation EngineeringSponsor: David Cole – Shell UK, Stanlow Refinery

Equilon/SIOP’s monitoring and diagnosis software, MD-1,was recently installed at Shell’s Stanlow UK Refinery by ET per-sonnel working from PCs in their offices at Westhollow. MD-1 is a process control system monitoring application thatrequires IT intensive configuration to connect to a process his-torian, database application, and e-mail server. Originally,a business trip to the UK was planned to perform the instal-lation, but by using Windows NetMeeting (a GI compliantapplication included in Windows 2000), ET personnel wereable to perform the installation using remote desktop control.It is estimated that it would have cost over $10k USD to sendan extra developer on the trip overseas. The success of theremote installation has been publicized, and similar savingsare expected on future installations as well as on the main-tenance of existing installations.

Engineering Highlights – Equilon Enterprises, LLC – October, 2001


CO

NF

ID

EN

TI

AL

19

Heat Exchanger Tubular Inspection - Perfor-mance Demonstration Testing

Author: Jim Haupt, Pressure Equipment IntegrityDepartment Sponsor: NDE TechNet, Mark Bell

This ongoing project has reached two further milestones.The primary objective of the project is to screen non-destruc-tive testing people and companies that we use to inspect ourheat exchanger tubes for corrosion and cracking damage.Industry data indicates that heat exchangers are the causeof a large proportion (31%) of unplanned unit shutdowns. Themilestones are: 1. An Intranet based Excel spreadsheet withthe performance data of all the examinees is available to allcompany inspection personnel. 2. A Microsoft Accessdatabase, which is used by the examinee, that is capable ofgrading and printing test results immediately after the test.This replaces the slow and cumbersome paper-based system.This database will also be populated with all of the previouspaper-based data so detailed queries can be run on thedata.

Engineering (R. W. Rolke)


ON

FI

DE

NT

IA

L

20

Lighten up and take a moment to ponder this quiz – if you’veread the newsletter this should be a breeze!

Across 1 Out of sight, out of mind? (3)5 Degradation of steel at high temperature and high

hydrogen partial pressure. (4)7 Straight-run crude oil fraction between LPG and

naptha. (4)9 An obnoxious, smelly gas. (3)10 Based on probability and consequence... (3)11 Galvanises steel. (4)12 PEC, DOS, AE, UT to name a few. (3)14. Detection, amplification and display of secondary

electrons. (3)15. Test for toughness. (6)16. Watch those emissions! (2)

Send your answers to [email protected] the end of February 2002. Correct answers willbe put into a hat and the winner drawn receives anexclusive Shell Global Solutions spirit level/screw-driver tool.

(Stay tuned….the answer will be printed in the nextissue of the Rusty Chronicle)

Down 1 Can be white, grey, ductile... (4, 4)2 A wet relation. (2)3 Rapid cracking of austenitic stainless steel. (7, 3)4 Why stainless steel is stainless. (8)6 Defend your buried assets with this. (2)8 As dense as ~ 7.9 g/cm3 (2)9 Discontinuity in a coating or a well deserved break. (7)13 We can’t live without these abbreviations! (3)

The Rusty Crossword

1 2 3 4

5

6

7 8 9

10

11

12 13 14

15 16

AND NOW FOR SOMETHING A LITTLE MORE LIGHT-HEARTED


CO

NF

ID

EN

TI

AL

21

LAST MINUTE HOT TOPICS

Shell have recently signed an agreement with TietoEnator fora new Hydrocarbon Accounting and Production ReportingSystem.

The software, which is being implemented globally in ShellOU’s, is Energy-Components (EC)

(http://energy-components.com) by Tietoenator

(http://tietoenator.com). This covers production, transport and sales of products andalso has production operations functionality.

EC has modules catering for chemical handling, storage andusage and also lab analysis. EC handles actual productionand also forecast production 0 - 24 months and is com-prised of a comprehensive suite of programmes. EC will belinked to SAP and probably use the SAP asset register.

OGEI/2 are investigating feasibility of configuring a ‘corro-sivity mapping’ module utilising live EC data and existingSGSI corrosion rate calculation tools.

For further information please contact Marc Kemp

New Hydrocarbon Accounting System - Potential for Corrosivity Mapping

CO

NF

ID

EN

TI

AL

22


OGEI Staff Moves 2001 (in)Name From To DateE. B. McDonald (Emma) New joiner OGEI/1 05-11-2001A. Etheridge (Andrea) OGE/1 New starter 29-10-2001

OGEI Staff Moves 2001 (out)Name From To DateJ. Whitfield (John) OGEI/1 Shell Chemicals 15-03-2001

• In the previuous issue we showed the services available from OGEI. • For this issue we are simply listing the department personnel contact details. • We plan to rationalise the services descriptions in the next issue.

Last Name First Name/ Telephone/extension E-mail Addressinitials

OGEI - Materials & Inspection EngineeringEquilon Technology, Llc - Wtc - Houston

Virtual Global Business ManagerRogalski Mike A. 281-544-7012 [email protected]

31-20-630-2300 [email protected]

OGEI/0 E-Mail: @shell.comBoes G. 31-20-630-2244 geertje.boes@Bos I.M. 31-20-630-3050 ingrid.bos@Kampschöer W.H.A.M. 31-20-630-2121 wilma.kampschoer@van Langen M.A.C. 31-20-630-2830 mirjam.vanlangen@

OGEI/ 1 - Downstream Materials Engineering Services (Amsterdam) E-Mail: @shell.comBlaauw A. 31-20-630-3671 andre.blaauw@de Boer M.P. 31-20-630-2461 marcpaul.deboer@van Bokhorst J.R. 31-20-630-3554 jan.vanbokhorst@Geenen P.V. 31-20-630-3146 peter.geenen@Green A. 31-20-630-3167 drew.green@Kapusta S.D. 31-20-630-2446 sergio.(s.)d.kapusta@Lewis K.R. 31-20-630-3147 keith.k.r.lewis@Liek W.E. 31-20-630-2594 willem.liek@van Loon P.J.M. 31-20-630-2627 peter.vanloon@Marsh S.R. 31-20-630-3157 simon.marsh@McDonald E.M. 31-20-630-2483 emma.mcdonald@Ryan T.F.J.N. 31-20-630-3117 tim.ryan@van Roij J.F.M. 31-20-630-3955 johan.vanroij@Schelling R. 31-20-630-3564 roy.schelling@van der Schot G.J.J. 31-20-630-3569 gerard.vanderschot@Smit K. 31-20-630-2308 kees.k.smit@Terwijn F.X. 31-20-630-2366 frans.terwijn@Wolfert A. 31-20-630-2298 ton.wolfert@Etheridge A.M. 44-151-373-5293 andrea.etheridge@Sargent M.A. 65-263-5398 [email protected]

WHO’S WHO IN OGEI

CO

NF

ID

EN

TI

AL

23


OGEI/ 2 - Upstream Materials Engineering Services (Amsterdam) E-mail: @shell.comDeurhof A. 31-20-630-2065 bram.deurhof@Groenenberg C.J.R. 31-20-630-2171 rob.groenenberg@Hendriksen E.L.J.A. 31-20-630-3544 edwin.Hendriksen@Huizinga S. 31-20-630-2449 sytze.huizinga@Janssen F.A.H. 31-20-630-2228 frans.f.janssen@de Jong J.G. 31-20-630-2592 jan.dejong@Kemp M.D.N. 31-20-630-2673 marc.d.n.kemp@Kerkveld G.E. 31-20-630-2438 gert.kerkveld@Koers R.W.J. 31-20-630-2229 ronald.koers@Martin J.T. 31-20-630-2205 tom.martin@Mesman A. 31-20-630-2282 arnold.mesman@de Mul L.M. 31-20-630-2318 leo.demul@Ohm R.K. 31-20-630-2628 rob.ohm@Orzessek K.M. 31-20-630-3160 karin.orzessek@Prager L.H. 31-20-630-2437 rik.prager@de Reus J.A.M. 31-20-630-2742 han.dereus@Rippon I.J. 31-70-311-2719 ian.rippon@Ritchie D. 31-20-630-2387 david.d.ritchie@Simon Thomas M.J.J. 31-20-630-2371 maarten.simonthomas@Stenger C.G.F. 31-20-630-2422 chris.stenger@Voermans C.W.M. 31-20-630-2485 cees.voermans@Wilcock N.J. 31-20-630-2079 neil.wilcock@van Zummeren J.B.W. 31-20-630-2493 hans.vanzummeren@

OGEI/ 3 - Inspection Technology (Amsterdam) E-mail: @shell.comCrouzen P.C.N. 31-20-630-2547 paul.crouzen@Geelen P.M.H. 31-20-630-2097 pierre.geelen@Jager S.F. 31-20-630-2753 sicco.jager@Kronemeijer D.A. 31-20-630-2643 dick.kronemeijer@van de Loo P.J. 31-20-630-2560 peter.vandeloo@Munns I.J. 31-20-630-2529 ian.munns@van Nisselroij J.J.M. 31-20-630-2564 jacq.vannisselroij@Roosenbrand A.G. 31-20-630-2384 bert.roosenbrandSchipper C.M. 31-20-630-2590 michell.schipper@van der Steen J. 31-20-630-3529 hans.vandersteen@Terpstra S. 31-20-630-3059 sieger.terpstra@van der Veer P.A.J. 31-20-630-2405 peter.vanderveer@Visser A. 31-20-630-2728 auke.visser@

OGEI/ 4 - Materials & Integrity (WTC - Houston)Brownlee Kirk 281-544-8538 [email protected] Ben 281-544-7332 [email protected] Jemei 281-544-6034 [email protected] Bob 281-544-7616 [email protected] Randy 281-544-7229 [email protected] Owen 281-544-7895 [email protected] Bruce 281-544-9090 [email protected] Howard 281-544-8012 [email protected] Bill 281-544-8059 [email protected] Bert 281-544-7028 [email protected] Paul 281-544-8273 [email protected] Kay 281-544-7972 [email protected] Lillian 281-544-8675 [email protected] Jeff 281-544-8018 [email protected] Francis 281-544-8540 [email protected] Lonnie 281-544-7432 [email protected]

CO

NF

ID

EN

TI

AL

24

Pressure Equipment Integrity Department (WTC - Houston)Bell Mark 281-544-7653 [email protected] Linda 281-544-7971 [email protected] Greg 281-544-8535 [email protected] Wendy 281-544-7900 [email protected] Jim 281-544-6790 [email protected] Deyuan 281-544-7132 [email protected] Bill 281-544-8171 [email protected] Manuel 281-544-9197 [email protected] Jess 281-544-8089 [email protected] Jim 281-544-7464 [email protected] Dick 281-544-8045 [email protected] Jason 281-544-8047 [email protected] Jacque 281-544-8010 [email protected] Mark 314-214-0222 [email protected] Bill 281-544-7976 [email protected] Nathan 281-544-7149 [email protected] Don 281-544-7187 [email protected] George 281-544-7865 [email protected] Hearl 281-544-8711 [email protected] Prashant 281-544-7927 [email protected] John 281-544-8194 [email protected] Dick 281-544-7925 [email protected] Saher 281-544-7914 [email protected] David 281-544-8333 [email protected] Lee 281-544-8564 [email protected] Tom 281-544-6215 [email protected] Larry 281-544-9033 [email protected]


the rusty chronicle - issue 02 december 2001[1]

Documents