life management of above ground atmospheric storage tanks

Life Management Of Above Ground Atmospheric Storage Tanks

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Life Management Of Above Ground AtmosphericStorage Tanks

C.J. Moss, RR Griffiths, A Bishop, M Dinon Contact

Abstract

The integrity of tanks needs to be well managed because they can contain a large inventory ofhazardous materials and because of the high costs such as cleaning and waste disposal prior toinspection and maintenance. The WTIA Petro Chem - Refinery " Save Money and Re-engineer withTechnology" (SMART) Group has collectively identified tanks as an area where collaborative workwould be beneficial.

The damage mechanisms associated with tanks can be complex and varied. Mechanisms includeunderfloor corrosion (where cathodic protection and drainage issues are important), internal corrosion(where the contents of the tank, the presence of species such as sulphate reducing bacteria andtemperature control the corrosion rates) and non-corrosion related mechanisms such as differentialsettlement.

When risk is defined as the product of likelihood and consequence, it is apparent that tanks deservehigh profile in a risk directed inspection program. It is maintained in the paper that it is possible todevelop inspection scopes directed on the basis of risk. Such an approach permits the use ofresources to be optimised while the overall costs of maintenance are minimised. Inspection andturnaround costs may be minimised and the risk of business and safety impacts reduced to anacceptable level whilst meeting statutory occupational health, safety and environmental requirements.

This paper reviews Australian requirements pertaining to the scope and interval of tank inspection andidentifies gaps in requirements. Inspection needs are presented and techniques such as acousticemission and floor scanning are discussed. Case studies of tank asset management are presented.

Background

Tanks have been around since the beginning of hydrocarbon production. However, relative to pressureequipment, limited information is available for tank integrity management. Tanks vary considerably insize, from small Australian Standards (AS) 1692 class 4 or 5 tanks, where the size is typically 50,000litres, to American Petroleum Institute (API) 620 and 650 tanks where the size may be tens of millionsof litres. In the ten years of life assessment and life extension conferences in Australia, to the authors'knowledge, few papers have been presented on tank issues. Perhaps the perception that tanks aresimple, ambient pressure equipment leads to them receiving less attention in the technical literature.Additionally, the generally high reliability and perception of tanks as infrastructure rather than planthas meant that tank maintenance approaches have tended to be reactive. Whatever the case, reviewof tank design and operating experience shows that tank issues can be complex and responses toleaks have been costly and anything but simple.

The failure of a tank can have several undesirable effects such as endangering personnel, affecting theenvironment and interrupting the operator's business. In a 1988 API worldwide survey, tank rupturesaccounted for 5 % of the 132 releases that occurred worldwide between 1970 and 1988 butaccounted for almost 19 % of the released material. An example of a failure with dramatic results wasin January 1988 in Pennsylvania, where 500,000 gallons of fuel flowed from an above ground tankinto the Monogahela River, the major source of water for many local towns. The cost of clean up,damage to the environment and adverse publicity associated with this and other releases spawned



present tank regulations and the development of API 653.

Whilst pressure integrity management is well-developed in standards such as AS3788, tank integrityrequirements in Australia are evolving. Whether published standards for tank integrity are available ornot, it is apparent that well planned preventive, rather than reactive, measures should be taken intank maintenance and reliability. It is interesting to note that in the USA, tank regulations and rulesgenerally focus on mitigative rather than preventive aspects; for example leaks and spills aremitigated by secondary containment rather than prevented by design and inspection. The importanceof inspection and condition monitoring in avoiding failures, maintaining safety and optimisingavailability is unquestionable. However, in a competitive business environment, down time forinspection requires considerable justification.

Facilities with tanks often present additional risks beyond site risks such as potential injury to sitepersonnel, damage to equipment and lost business. Tanks are often located in areas of environmentalvalue or, because of the encroachment of suburbia, are close to the community. Furthermore,incidents may create unfavourable publicity through media coverage. Consideration of the cost oflitigation and fines from accidental releases alone can warrant setting up an inspection program.Companies therefore require a consistent approach for assessing tank integrity and maintainingcompliance with industry standards and regulatory, that is, community requirements. Such anapproach must

show that tanks are not leaking and will not leak before next inspectionreduce the potential for releasesmaintain tanks in safe operating condition, andmake repairs and determine if and when replacement is necessary.

This paper presents a of information resources, regulatory requirements and describes case studies oftank asset management from three companies. Gaps and opportunities are presented to promotedialogue and raise awareness of needs.

"SMART" Petrochemical group activities

Three SMART groups representing the pipeline, power generation and petrochemical industries wereformed shortly after the launch of the Ozweld Technology Support Centres Network Project in late1998. The Petrochemical group has 12 member companies from refineries, gas plants and chemicalplants. The SMART Group has been successful in identifying technological needs by creating adiscussion forum at company level and a cooperative spirit of working together, despite participantsbeing associated with different companies. A fundamental aim of each SMART group is the creation ofa close network of key participants from that particular industry and to identify " expert technologytools" needed to help improve industry viability. In line with this theme, the SMART Petrochemicalgroup identified a need to review the most effective NDT techniques for tanks to improve tank assetmanagement.

Regulatory Requirements and Knowledge Bases

In Australia, tank in-service inspections are generally identified in petroleum regulations, occupationalhealth and safety regulations or dangerous goods regulations. Details vary from state to state butmost make reference to AS1642, AS1940 and AS3788, which address design, construction, operationsand maintenance in varying levels of detail. Beyond Australia, there are several design codes thatprovide good assurance on fitness for service: in particular, the standards and recommended practicesproduced by the American Petroleum Institute (API) are recognised as world class. Tank selection hashistorically been a complex process of optimising an array of requirements such as design, capacityand cost. Other factors include corrosion prevention systems and environmental regulations. Inplanning to design and construct new tankage, there are ample standards geared to provideagreement on design and fabrication between the supplier and purchaser. Such standards ensure thatthe tank will not fail when put into service and were not intended to deal with long term maintenance



and inspection. There are a number of API standards and recommended practices which provideguidelines on design, fabrication, operation, cleaning, inspection and repair of tanks and which can beused to develop tank integrity programs and procedures. Selected information is contained inAppendix 1. The most important guide on in-service integrity is API 653.

Summary of Useful Tank Inspection and Repair Standards and GuidesAS1692-1989

Tanks for flammable and combustible liquids

Details design and construction requirements for tanks, but makes no reference topost-construction inspection issues.

AS1940-1993

The storage and handling of combustible liquids

States that a procedure for the inspection of tank vents and fittings shall beestablished to ensure that pressure/vacuum and emergency tank passages are clearand any relief valves are operating correctly. Such inspections shall be carried out atperiods not exceeding 12 months, or as necessary depending on the application.

A procedure for the maintenance of tanks, including testing, inspection and monitoring.Clause 9.8.14 and Table 9.1 detail record keeping, repairs, limited filling heights,testing and inspection frequencies for category 6 tanks. Operational inspections shallbe carried out monthly, shell, bottom and roof integrity related inspections shall becarried out at a maximum interval of 10 years. States that the minimum allowable floorthickness is 4mm.

AS3788 -1996Appendix T(Normative)

In-service Inspection of tanks

Deals with API 620 tanks, calls up AS1940 inspection interval category 6, ie. 10 yearlyinternal inspection required. Also references API 653, AIP CP 16 (10 yearly internalinspection intervals).

AS3873 -1995

Pressure Equipment - Operation and Maintenance

Specifies requirements and owner and contractor responsibilities and gives guidance onoperation, maintenance, and operational surveillance and risk assessment of pressureequipment. Reference to this standard is provides for good working practice for tanks.

API 575-1995

Inspection of atmospheric and low-pressure storage tanks

Details reasons for inspection and methods of inspection, methods of repair, recordkeeping and reporting.

Provides check sheets for in service and out of service inspection.API RP651-1997

Cathodic Protection of Aboveground Storage Tanks

Details damage mechanisms and CP requirementsAPI 652-1997

Lining of aboveground petroleum storage tank bottoms

Details lining selection, cleaning and lining installation procedures.

Makes no reference to post-construction inspection issues.API 653-1995

Tank inspection, repair, alteration, and reconstruction

Details minimum requirements for maintaining integrity of storage tanks, inspectionfrequency and methods of inspection, methods of repair, alteration, record keeping andreporting.

Provides check sheets for in service and out of service, internal and external inspectionand API 620 and 650 code compliance.



Recommends monthly operational external visual, 5 yearly external inspection byauthorised inspector, 10 yearly internal inspection with possibility of 20 yearly bottominspection where corrosion rate has been measured.

API 2000-1994

Venting atmospheric and low pressure storage tanks

Fire protectionAPI 2015-1994

Safe entry and cleaning of petroleum storage tanks

Details safety precautions and standards of cleaning for inspection.API 2021 Fighting fires in and around flammable and combustable liquid

atmospheric petroleum storage tanksAPI 2207-1998

Preparing tank bottoms for hot work

Details safety precautions for hot work on tank bottoms.API 2200 Improving owner and contractor safety performanceAPI 12R1-1997

Recommended practice for setting, maintenance, inspection, operation, and repair oftanks in production services

Provides useful guidelines on tank corrosion mechanisms. Provides check sheets for inservice and out of service, internal and external inspection.

API 327-1994

Aboveground storage tank standards: a tutorial

Summarises contents of all API standards and provides worked examples fordetermination of corrosion rate and inspection interval.

API 334-1996

A guide to leak detection for above ground storage tanks

Summarises trials and validation on key 4 techniques.NACE RP0193-1993 External Cathodic Protection of On-Grade Metallic Storage Tank Bottoms

Tank Asset Management and API 653

The primary applicable Australian standards for in-service inspection of tanks are AS1940 and AS3788,which specify requirements for regular operational surveillance and a maximum internal inspectioninterval of ten years. API 653 is an important additional document that addresses suitability for serviceand repair and alteration requirements for large, atmospheric pressure above ground, steel storagetanks. API 653 cannot provide a cook book of answers to all issues and therefore should be regardedas outlining a program of minimum requirements for maintaining tank integrity. It outlines bestavailable, cost-effective technology to ensure that leaks or catastrophic failure do not occur.

API 653 departs from most inspection specifications in that it requires an engineering analysis of theinspection data. Thickness measurements are evaluated to ensure that the tank is structurally sound,within allowable stresses for the required design conditions and will not leak before the nextinspection. Confirming that a tank will not leak goes beyond ensuring that it will not failcatastrophically, since even a small leak is unacceptable. API 653 emphasises the need for engineeringexperience when evaluating a tank's suitability for service. It requires that evaluation be conducted byorganisations that maintain or have access to engineering and inspection personnel who aretechnically trained and experienced in tank issues.

API 653 recognises that fabrication and inspection records for older storage tanks may be incompleteand the original degree of inspection and construction material may be unknown. However, it stillprovides a structural integrity evaluation of such tanks by using conservative assumptions. In thesecases, shell thickness calculations use a low weld joint efficiency of 0.7 and assume the use of arelatively low-strength material. This reinforces the benefits of maintaining proper tank design,



fabrication and inspection records. The concepts of three-stage life assessment, developed forpressure equipment and outlined in AS3788 Appendix U may be used. If records are inadequate or ifdamage mechanisms are not understood, the next stage of assessment is used. The information fromeach stage feeds into the next. Successive stages are more comprehensive and costly: therefore eachstage is performed only as required. The data requirements of the three stages of tank assessmentare summarised in Table 1.

Feature Stage 1 Stage 2 Stage 3History Anecdotal Plant Records / Operations

logReview PlantRecords

Dimensions Design Nominal (GeneralArrangement drawings)

Measured

Condition Records or Nominal Inspection DetailedInspection

Contents (fillheights)

Design Operational Measured

Stresses Design orOperational Simple CalculationRefinedAnalysis

MaterialProperties

Assumed to be lowstrength

Specification minima Heat data

Table 1: Suggested data requirements for the multi-staged assessment of tanks.

MORE RIGOROUS ASSESSMENT MORE ACCURATE OPERATIONAL DATE REQUIRED MORE ACCURATE UNDERSTANDING OF CONDITION

An inspection program should address the four main storage tank components: the roof, shell, bottomand foundation. There are several subcategories within these main components, including the tankbottom to shell connection, shell penetrations and roof connections. There are other factors that canaffect the life of tanks, including fixed fire fighting systems and floating roof drains. These will not beconsidered here.

Compliance with API 653 costs time and money. Although compliance with API 653 is not mandatory,such industry standards have always had the standing of " good industry practice" in the view of mostregulatory authorities. Compliance with API 653 or a corporate or other equivalent is really aninvestment, in that the long term costs are likely to be more than recouped, due to avoided costs ofsite remediation from spills, potential fines and lost business. API 563 may also more directly reducecosts in demonstrating that tanks built to older design standards continue to be fit for service.

Engineering analysis methods are potential alternatives to repairing a problem tank. The decision onwhich approach to take, repair or analysis, should be made on a case-by-case basis on relative costsand schedule considerations. If using the API 653 shell-thickness calculations based on minimal datadoes not cause a severe fill-height restriction or mandate extensive repairs, then the additionalexpense and time required for further analysis may not be justified. However, if the initial inspectionand evaluation results show that there is a significant problem then the additional inspection andevaluation may be worthwhile. Thickness "averaging" is possible. With this approach, credit is takenfor reinforcement provided by thicker regions that are next to corroded regions of a tank shell. Similarcredit may be taken by performing thickness calculations based on specific elevations of corrodedregions. This accounts for actual hydrostatic head imposed at the corroded region, rather than makingits minimum required thickness equal to that required at the bottom of the particular shell course.

If analysis is required, API 653 provides guidelines for many types of repairs and alterations, includingpatch plates, alteration of nozzles, bulge repairs, bottom repairs or replacement, roof repairs, floatingroof seal repairs, hot taps and repair of defective welds.

Tank Inspection and Leak Methods



Appendix C of API 653 contains comprehensive checklists to perform in-service and out-of-servicevisual inspections. Some checklist items relate to tank operational factors, such as whether the levelcontrol is operational, while other items relate to structural integrity issues. The philosophy of API 653is to gather data and to perform a thorough initial inspection in order to establish a baseline for eachtank inspection against which future inspections may be used to determine rates of corrosion orchanges that might affect fitness for service. The scope of inspection is always subject tointerpretation: for instance, a cursory or limited inspection may miss the one pit in the floor that canlead to a leak. To inspect for floor top-side corrosion, it is essential that the floor is cleaned by gritblasting. While expensive (several tens of thousands of dollars for a crude tank), it has proven to bethe only sure way of uncovering defects. It is usually found that tank integrity assurance costs aredominated by cleaning / sludge removal activities prior to inspection and application of confined spaceentry precautions, rather than by inspection costs.

Few alternatives are available to inspect the tank bottom for underside corrosion. Commerciallyavailable inspection techniques include those based on magnetic-flux exclusion (MFE) and automatedultrasonics. Both inspection techniques require that the floor is dry and free of dirt, sediment andcorrosion products[Z You and D Bauer. Materials Evaluation. July 1994, pp 816 - 818. V52. Combiningeddy current and magnetic flux leakage for tank floor inspection] . A recommended minimuminspection would be a MFE inspection of all floor plates with ultrasonic follow-up of suspect areas,vacuum-box testing of floor-plate welds and dry magnetic particle or liquid penetrant inspection of theshell-to-bottom weld. Again, future general corrosion and pitting rates, both topside and underside,need to be estimated to evaluate the acceptability of the current bottom thickness. It may be usefulto cut out coupons from the floor for visual inspection of the underside, and to allow cathodicprotection potential to be confirmed at different distances from the periphery to the centre of thetank. API653 does not explicitly state how many thickness measurement points must be used in eachshell course or plate. If the tank interior is accessible for visual examination, a minimum number ofmeasurements should establish nominal thicknesses and additional inspection of localised corrodedareas will provide corrosion rate data. The required future corrosion allowance is then estimated, toensure that the shell will not thin below the minimum acceptable level before the next inspection.

There are a number of techniques which offers the possibility of on line inspection of large API tankssuch as volumetric or mass methods, acoustic emission (AE), soil vapour monitoring and inventorycontrol. Extensive development, trialing and validation has been undertaken by API. Table 2summarises the characteristics of these four leak detection methods.

Volumetric AcousticEmission Soil vapourmonitoring

Inventorycontrol

Measurementconcept

Measurechanges inlevelAccount forchanges inmeasured levelor massInterpret anymeasurementthat exceedsexpectedchange as aleak

Measure AE aspasses throughpin hole orfrom oxidespallingPlot AE eventson tank floormapInterpretclusters ofevents as leak

Use acompound inthe tank thatcan contactthe bottomand migratethrough backfillMonitor forsigns ofchemicalmarkerInterpretspecificconcentrationsof marker as aleak

Keep a detailedrecord ofadditions andwithdrawals ofproduct overgiven periodOver sameperiod monitorlevels or massInterpretdiscrepancy asa leak

Noise sources Temperature Process Insufficient Metering error



fluctuationsEvaporation orcondensationStructuraldeformationVariablegeometry(floating roof)Leaking valves

operationsWater layer orsludgeStructuraldeformationCondensationMultiple leaksWeatherAmbient noiseLeaking valves

markerconcentrationChemicalinterferenceHydrologyNaturalpresence ofmarkerexternal totank

Tank gaugeerrorTemperaturefluctuationsEvaporation orcondensationStructuraldeformationVariable tankgeometryLeaking valves

Demonstrationmethod

Impressed leak Acoustic leaksimulator

Inject markerinto back fill

Test tankknown free ofleaks

Operationalrequirements

SuspendnormaloperationsInstall valveblinds (or useleak tightvalvesDeployinstrumentationWait 24 hrsbefore startingtest

SuspendnormaloperationsDeployinstrumentationNight testingpreferableRestricttransfers ofadjacent tanksWait 12 hrsbefore startingtest

Install probesunder soilIf addingchemical(rather thantargetingproductcomponent)distributemarkerTank remainsin servicethroughoutoperation

Tank remainsin servicethroughoutoperation

Total timetaken

4 - 72 hrs 4 - 16 hrs Hours toweeks(depends onsoilpermeability)

Days to weeks

Minimuminstrumentation

Level sensorTemperaturesensorsFor massmeasurements,a DP cell,thermocouples

Array ofaccelerometers(external) orhydrophones(internal)

Probes (undertank)Gaschromatographor optic fibresensor to sortand analyseconcentration,or method ofsampling forlaboratoryanalysis

Tank gauge,flow meters(specificmeasurementsmade withlevel gaugemay besubstituted)

Key Features Pre-testwaiting periodMay have lowproduct level /long testdurationMay haveexternalsensorsKnowncoefficient of

Digital timeseriesHigh datacollectionthresholdMulti-pathdiscriminationTimeregistration ofeventsClose spacing

Backfillcompatiblewith targetOptimumnumber ofprobesWater layerdrained oftarget thatpenetrateswater

LongreconciliationperiodFrequentmeasurementof productlevelsWell calibratedinstrumentationAccuratecalculations



thermalexpansion oftank shellPreciseinstrumentationrequiredCompensationfor thermallyinduced noiseMay needfloating roofnot in contactwith product

of transducersAveraging ofdataSpeed of soundin water andsludge layersBackfill mustcontain airPre-testwaiting periodPresence andextent ofsludge layerscharacterised

Lowbackgroundlevel of targetrequired

Table 2: General characteristics of tank leak detection technologies. After API 334[API 334 119. Guide to leak detection forASTs]

Case Studies

Santos Queensland and Northern Territory Business Unit

Santos QNTBU operate approximately 450 tanks over a vast area: for example, petroleum leases insouth west Queensland are larger than some European countries. Operation involves a wide variety oftanks, such as static and movable storage tanks (wash, production, well fracture stimulation), API 620and 650 tanks, water tanks (potable, fire, secondary settlement or separation), underground storagetanks and diesel fuel dispensing tanks (eg. for oil pump engines). Over half of the tanks have been inservice more than 15 years. Typical tanks are shown in Figures 1 and 2.

Fig 1: Typical Santos owned API 650tank, at Lytton. Some CALTEX tanks in

the background

Fig 2: Typical Santos owned field productiontank.

Santos is enhancing its management systems for the integrity assurance of equipment, includingtanks. The tank integrity assurance program has compiled a database of tanks detailing tank location,size, commissioning date, redundancy and many other details. Inspection schedules for assessment ofexternal and internal condition (using conventional techniques and AE) are being refined, as areprocedures for record keeping and in-service monthly inspections. After establishing corrosion rates,inspection intervals based on risk are determined and inspection programs implemented.

In the risk assessments that are performed, the probability of tank failure is based on: -

identification of potential failure mechanisms (both internal and external corrosion mechanismsare considered)records of repair and refurbishmentquality of design, construction and maintenance programscurrent tank integrity



effectiveness of previous inspectionscorrosiveness of contents (including the presence of microbial corrosion eg. sulphate reducingbacteria)condition and effectiveness of cathodic protection systemsprevious experience of corrosion in related plant (eg. associated flow lines and pipelines)number of attachments or appurtenances (an indication of the complexity of the tank andlikelihood of failure).

In the risk assessments that are performed, the consequences of failure are based on: -

possible site personnel injury and impact on surrounding communitypotential volume of leak and its impact on the surrounding environmentredundancy of systems (spare storage available)engineering costs of repair, refurbishment or replacementcosts associated with outages or down time and the use of replacement plant.

As an example of the detail involved in the risk assessment a factor is used to consider the variouscontents of tanks: mixtures of oil and water are more corrosive than water, which are in turn morecorrosive than crude. The water cut is taken as an indicator of corrosion likelihood. A threshold of30% is used, below which corrosion is considered unlikely.

The overall evaluation of plant risk is a product of the probability and consequence of failure. Whenthis risk factor has been determined it is possible to categorise and rate tanks with regard to theirpotential impact on operation. Risk assessment data is shown in Figure 3. Note the logarithmic Y-axis.It is apparent that risk is dominated by a limited number of tanks. This result is typical of the riskprofile generated by risk based inspection assessments, where a Pareto principle of 80% of the riskresulting from 20% of the equipment is generally found.

Fig 3: Santos tank asset management program, output from relative risk ranking of tanks bybusiness area. Ranking refers to the position on a list of tanks sorted in order of highest risk

to lowest risk.Note Y axis is logarithmic

BP (Bulwer Island) Refinery



Tankage includes crude oil tanks, which typically may contain 40 million litres, intermediate-productand end-product tanks that may be a tenth that size, and tanks for ancillary storage (such ascondensate, caustic, and other components that assist the refinery operation) which are typicallyabout a tenth of that size again. Construction can be floating roof, cone roof, cone roof with internalfloating roof, and cone up or cone down floor. While often regarded as static equipment, they are infact the only examples of refinery equipment that are routinely stressed to their full design value andthis occurs cyclically.

Contents can be at any temperature from ambient to well over 100C, and can be quite hazardous:the 'lead' additive for leaded petrol, Tetra-ethyl lead, is a highly toxic compound which also bringswith it particular corrosion issues. Although now phased out at this refinery the tanks and ancillaryequipment are still to be disposed of, and it is probable that product tanks that have contained tracesof the compound will always have to be treated as if the compound is still present.

The biggest life management issue is corrosion of floor plates. Corrosion from under the floor strikesrandomly; tanks badly affected may be situated next to tanks which are not affected. It is assumedthat this is caused by variations in the nature of the fill under the tanks, which was pumped up fromthe river bed during construction of the refinery. Experience is that, with cone-up tanks, the outer 6metres of the tank floor is susceptible (occasionally 8 metres). The tanks were originally constructedwith 1/4 inch (6mm) floor plate with no annular ring: replacements incorporate a 10 mm thick annularring. Cathodic protection can help but does not provide a complete answer, as soil conditions can bevery difficult and small portions of the floor may be 'shielded' from the CP current. Internal corrosion,on the floor top face, is caused by bacteria or from acid or other contamination of product. Defectscan be general or local pitting in plates or welds. Cracking has rarely been found.

Coating the floor with glass fibre reinforced resins was common in the 1970s and 1980s but is nolonger practised. It had been thought that this would bridge across corrosion pits that continue togrow and perforate the plate after the lining is applied but there has been a failure and the liningmade the leak very hard to locate. Furthermore there is a fear that this may mask a potential problemuntil sudden rapid failure occurs. Reinforced resins can also make ultrasonic inspection of the floorplate difficult or impossible, although magnetic flux leakage devices will perform well through such acoating. Applying a suitable paint coating will give good protection to the top surface of the floor,while still allowing ultrasonic inspection of the plate and better assurance as to whether any thinningfound is from the top or bottom surface of the plate.

A further issue with tank floors is with the small area of floor plate that protrudes beyond the tankshell, known as the 'chime'. Where there is no annular ring, the joins between sections of the chimeare made with a joggled joint, which is fillet welded. As the tank fills the chime is stressed in tensionand we have seen cracking in the fillet welds, with a tendency for this to be worse where the joint isorientated radially. Several attempts have been made to calculate stresses in this area with noconclusive result. There have been no failures but occasionally cracks have been found propagatedinto the floor to shell weld. The chime is also subject to severe corrosion from underneath but, forsome unexplained reason, this does not appear to progress under the tank shell unless it is coincidentwith corrosion occurring further in.

The shells of some product tanks have corroded internally, particularly with floating roof tanks inleaded petrol service. The lead additive contained bromide and chloride compounds, which brokedown in sunlight to form hydrobromic or hydrochloric acid. This caused deep pitting of the shell wherethe wall is repeatedly wetted as the level changes. Replacing tank strakes was only a temporarysolution, and initial attempts at painting failed quickly. An assessment of procedures and inspection offailed coatings suggested that much of the problem lay in not properly curing before filling the tank.Coupled with a program devised to select suitable coatings this has lead to a very successful solutionto the problem, and no strake replacements have been made in over ten years despite many tanksbeing painted when shells had already corroded to the minimum allowable thickness.

Floating roofs have particular integrity issues. External corrosion can occur where water and blown-indirt collects, around the roof drain sump and where attachments are welded to the roof. Particular



attention to details of design, inspection and painting are required to manage this. Floating roof legand leg sleeves corrode in the vapour zone, and close inspection is required before a tank is taken outof service to ensure the safety of maintenance operations inside the tank. Similarly the sides ofpontoons corrode severely in the vapour zone. This area, despite the difficulty of access, must beinspected and painted. Volatile components can create vapour bubbles under the roof which can causethe roof to tilt, and possibly to sink. Venting the high point adjacent to the pontoon at several placesaround the tank will prevent this. Floating roofs are constructed of lap welded plate. Corrosion canoccur in the lap between the plates. Experience indicates that this always occurs only on the bottomplate and taking sections has never revealed any corrosion attack on the weld zone. Interestingly, thiseffect has never been seen on floor plates. Lapped plates can also give rise to problems when othercomponents are welded through a lap and it can be very difficult to seal all leak paths. With largetanks, wind action is said to cause the roof to 'ripple' giving rise to fatigue cracking in lap joints butthis has never been experienced at the refinery.

External corrosion can also occur on insulated tanks, which tend to operate at optimum temperaturesfor corrosion. Attempts at performing global inspections without removing insulation, for exampleusing thermography, have not been successful and stripping areas for inspection has been the onlysuccessful method found. Techniques available for inspecting pipe for corrosion under insulation arenot generally applicable to tanks.

Caltex (Lytton) Refinery

The general description of tanks within BP Bulwer Island also applies to Caltex Lytton, with theexception that all Lytton tanks have been constructed with cone up floors.

The biggest life management issue is the limited access for cleaning and inspection imposed by theshortage of tanks and the lack of flexibility that this imposes. Tanks have traditionally been taken outof service for major inspections at fixed ten year intervals. As with the BP Bulwer Island tank farm, theCaltex Lytton tank farm was constructed on reclaimed land. This has been an advantage to Lyttonbecause it gives a conductive soil which gives good distribution of the cathodic protection currents.The tank farm is electrically continuous, the cathodic protection anode beds are distributed around thetank farm at convenient locations and are powered by very reliable robust transformer/rectifiers.Earlier tanks were constructed on oil sand, and later tanks on bitumen soaked boards. Thecombination of sound construction practices and good cathodic protection has meant that underfloorcorrosion has never been a problem at Lytton and maintenance attention can be directed tocontrolling internal corrosion from the crude and products.

Lytton has recently developed an Alliance with Saunders to cover tank inspection and maintenance.Saunders provide a tank manager on site, a Saunders tank inspector and a Saunders maintenanceworkforce. Budgeting is prepared by Saunders and approved by Caltex. The Alliance works onrisk/reward principles based upon key performance indicators that are still evolving. The Alliancedeveloped a risk hierarchy of all AS1692 Category 6 tanks, which has initially been used to prioritisethe external in-service inspections. The intention is that in the future it will be used as the basis to setintervals on a risk based inspection basis as allowed by API 653, although the regulatory authoritymust first approve this change. The risk matrix is a 6 x d6 type, with the likelihood of failure beingdetermined by looking at the floor, shell and roof in terms of the current inspection and anticipateddeterioration rate and the consequences of failure being determined by environmental issues, safetyissues, and production criticality.

Crude tank floors are painted, and the coating extends a metre up the walls. Fibreglass floor coatingsare still in service and have performed well because under-floor corrosion is almost non-existent but,as at BP Bulwer Island, there is a recent preference towards paints because they allow inspection ofthe steel thickness beneath using modern inspection methods. Although magnetic flux exclusionexamination of a crude tank floor has been tried, the results were disappointing and of little value.Nevertheless, there is interest in using techniques such as magnetic flux exclusion to better assessfloor condition in the future.



Gasoline tanks are painted to control corrosion and avtur tanks are painted for product cleanlinessreasons. Increasingly, there will be a tendency to paint other tanks in accordance with the aim toincrease the duration between major out of service inspections.

Opportunities and Gaps

There is reluctance in the inspection community to accept new technology at face value. There havebeen too many disappointments when new devices have been oversold and, in the case of newtechnology for tank inspections, even demonstrations can be expensive.

The development of magnetic flux leakage equipment for under-floor inspection has made a majorimpact on tank inspection and subsequent reliability but this still requires the tank to be taken out ofservice and cleaned. Confidence in the technique, using suitably skilled operators, is high. Currentdevelopments in floor inspection techniques include remote operated vehicles that can be inserted intotanks while filled with product and perform an ultrasound inspection of the floor plate. This is limitedto tanks which have only a light deposit on the floor and certainly would not be expected to succeedon crude tanks that can have two metres of heavy sludge. A method for performing such aninspection while the tank is in use unquestionably constitutes the 'Holy Grail' of tank inspections.

Acoustic emission (AE) has been developed to a sophisticated level [RK Miller. Mat. Eval. 6, 1990. Pp822 - 829. Tank bottom leak detection in AST by using AE], [CM Nickolaus. Mat. Eval., 1988. Pp 508 -512. AE monitoring of ASTs. ], [R Nordstrom. Mat. Eval. 48, 2,. 1990. Pp251 - 254. Direct tank bottomleak monitoring with AE.], [EG Eckert, MR Fierro and M Maresca. Materials Eval. Aug 1994. V52. Pp954 - 958. The AE noise environment associated with leak detection in ASTs] though is primarily amaintenance sorting tool. It has been used successfully by a number of large oil and gas companiesand is offered commercially by two Australian companies and under licence by other Australiancompanies. However, AE testing has shown mixed results, and detection of underfloor leakage onoperating tanks has given some disappointing results. It had been hoped that a leak would produce asignal that could be located with the tank on-line but results did not bear this out. On one occasion, aloose sample bottle on the tank floor was blamed for giving spurious signals (though how this wouldoccur with the tank 'stilled' for a day or so is not clear) but usually no feature has been found toexplain a false indication. It is currently thought that the signals produced by the corrosion reactionitself may be detected, and interest now lies in using this to assist in ranking tanks for inspectionbased on detection of corrosion activity rather than leakage. Therefore AE is not the 'Holy Grail' as itdoes not give an idea of the structural condition of the floor. A leak can be from many causes and themere act of corrosion may have different implications. The current development of remotely operatedvehicles (ROV's) to inspect on-line may bring this a step closer, bringing an array of inspectiontechniques onto the tank floor. In the case of ultrasonics, coupling a probe to the plate would be asimple matter (as has been proven by manual use in water tanks) and in principle many othertechniques could be applied. However a tank can be a very large structure - 60 metre diameter tanksare common - and a full survey over the floor of such a tank would be time consuming and expensive.

All this assumes that any leak is from in-service deterioration, but there is much anecdotal evidence ofleaks from new construction, through weld defects or even missing welds. Vacuum testing of floorwelds is a physically demanding task and depends on great operator diligence for success. Sensitiveleak testing, injecting helium under the floor and detecting its emergence into the tank has been triedwith mixed results. It has been known for tanks to be put in service with large sections of the insidefloor to shell weld missing and on one occasion comparatively minor corrosion in the external weldopened up some gas pores which resulted in a leak. A small length of inner weld had been omittedsome distance away and the tank contents were able to track round between the two fillet welds thatconstituted the floor to shell joint.

In repairing tanks, replacement of floor plate is achieved by oxy-cutting the floor-shell weld andwelding in the new floor in the same location. The effect of repeating this several times over the lifeof a tank is largely unknown. The Welding Institute advises against welding in the same location morethan twice, yet floor replacements are made more often than this. Cutting out a section of shell to



move the weld location reduce the tank volume significantly, for example on a crude tank removing10 mm would reduce the volume by about 30,000 litres.

The issue of hydrotesting is also of interest. With pressure vessels, hydrotesting is performed at apressure significantly above the design. The API codes (650 and 653), however, require hydroteststresses to be calculated and have far lower allowable stress ratios (test to design). In view of the factthat testing can only be performed under a head of water equal to the tank height, and would onlygive 125% stress for a tank designed for product of SG 0.8, the code seems to be making anunnecessary complication. In fact, while the benefits of overstress under controlled conditions are welldocumented, these codes seem to work to ensure that such benefit is avoided. If the prospect ofbrittle fracture with a tank filled with icy water drove these requirements the codes should say so but,in any case, this issue is in need of clarification. A warm proof test may well have prevented thePennsylvania event referred to above. The reference below['Stress: are you giving enough?', RRGriffiths, Australian Welding Journal Vol 43, 3Q 1998, 'Controversy Corner' article.)] gives more detailof issues with tank hydrotesting.

Degradation of tanks is generally slow and failures are infrequent: indeed, many tank inspectionsdetect no defects and minimal change in condition. While there have been incidents, some quitespectacular, there have fortunately been no tank incidents that have had an impact on the localcommunity of 'Flixborough' or 'Bhopal' proportions. The Pennsylvania incident referred to above had amajor impact on the local river systems, as mentioned, but this was an unusual case involving a re-constructed tank. It is suggested that some, perhaps most, of the major incidents that have occurredhave been a result of less than adequate engineering or inspection rather than due to poor standardsand that, in the past, inspection performed with limited means and to the best of the inspector'sability reduced the impact of events, to just a floor leak, for example. This leads to the question ofhow much can the interval between inspections be extended without increasing risk.

Risk assessment of tanks provides a powerful approach for optimising inspection and refurbishmentstrategies. Risk assessment combines both the probability and consequences of failure to establish aprioritised list of plant. This allows the tank owner to allocate resources to high risk plant andminimise activities that are not doing an effective job of reducing risk. The scope and timing ofturnarounds and inspections can be optimised while reducing safety and environmental risk to anacceptable level. Risk based inspection techniques have been successfully applied to tanks[JTRenyolds. Inspectioneering Journal. March / April 2000. RBI of ASTs]. Improvements in inspectiontechniques and technology will further reduce the incidence of minor events. The changing importanceof environmental considerations make this essential. The time is right for application of risk based andrisks directed inspection techniques and the use of established three stage life assessment methods oftanks.

Conclusions

Tanks can pose hazards to the community, the environment and to operating companies because ofthe large inventory of materials and the criticality to the operation. These hazards are oftenoverlooked. There is considerable guidance available on tank inspection and integrity. This papercatalogues and discusses references, such as API653, and techniques, such as acoustic emission.

A number of case studies are presented which describe a variety of issues that need to be consideredwhen developing tank integrity management programs. Risk based and risk directed inspectiontechniques and the use of established three stage life assessment offer potential for establishingadequate, cost effective programs.

Acknowledgments

The authors are grateful to their colleagues for assistance in managing tank integrity programs. Thecontent of this paper should not be taken as necessarily reflecting policies or obligations of theassociated companies and is presented to convey the views and experience of the authors.



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