Tank Manual2 Of2

&& TANKManual Sponsor: D. M. Bosi / CTN 242-7218 / E-mail: [email protected]

50 Using This Manual

100 General Information

200 Fire Protection

300 Materials Considerations

400 Tank Design

500 Foundations and Groundwater Protection

600 Appurtenance Design

700 Instrumentation/Measurement

800 Evaporation Losses

900 Construction

1000 Inspection and Testing

1100 Maintenance

1200 Special Types of Tanks

Glossary

Appendix A - Tank Appurtenance Vendors

Appendix B - Conversion Tables

Appendix C - Guidelines For Seismically Evaluating And RetrofittingExisting Tanks

800 EVAPORATION LOSSES

This section of the Tank Manual has been deferred. For information and details about evaporation, please consultthe sponsor of this manual. More information may also be obtained from the documents listed below. They canbe ordered directly from API.

API Bulletin 2516 Evaporation Loss from Low-pressure Tanks

API Publication 2517 Evaporation Loss from External Floating Roof Tanks

API MPMS19.1 Evaporative Loss from Fixed Roof Tanks

API Publication 2519 Evaporation Loss from Internal Floating Roof Tanks

API Bulletin 2521 Use of Pressure-vacuum Vent Valves for Atmospheric Pressure Tanks to ReduceEvaporation Loss

Tank Manual 800 Evaporation Losses

June 1994 800-1

T O

C O N T E N T S

900 CONSTRUCTION

Abstract

This section is designed for the Company representative or engineer responsible for construction of a new tankor replacement of major components (bottom and/or roof) of an existing tank. More than any other factors, goodcommunication with the contractor and careful dimensional checks, especially early in construction, influence thesuccess of the job. A useful tank hold points checklist is included. Appendix A lists suppliers of appurtenancesand other tank materials.

Contents Page Page

910 Foundations 900-2

911 Concrete Work

912 Installing the Secondary Containmentand Leak Detection System

913 Bottom-to-Foundation Seal

920 Bottom Construction 900-4

921 Bottoms for New Tanks

922 Bottom Replacement

930 Shell Construction 900-6

940 Roofs 900-7

941 Aluminum Dome Roofs

950 Tank Hold Points Checklist 900-17

990 References 900-17

Tank Manual 900 Construction

June 1994 900-1

T O

C O N T E N T S

910 FOUNDATIONS

The Company has installed many types of tank foun-dations over the years: oiled sand or dirt pads, plank,crushed rock, rock, brick and concrete ringwalls, etc.More recently it has used the ringwall design with sec-ondary containment and leak detection. This sectionwill discuss what to watch out for during the construc-tion of the latter design, although most of the criticalfactors and checks will apply to other designs as well.The remarks below apply both to new foundations and,during bottom replacement, to the spacer installed be-tween the old and the new bottom.

The foundation consists of a concrete ring on whichthe tank shell will rest. Inside the ring is a layer ofcompacted fill. An HDPE membrane liner is stretchedover the fill and impaled on the reinforcing bars thatstick up from the ring about 1-1/2 inches. For bottomreplacement, the membrane is placed on top of the oldbottom (see Section 912).

A concrete pad (or spacer, for bottom replacements) ispoured on top of the membrane liner. If the pad is tobe reinforced with polypropylene fiber or wire mesh,this material is placed on the membrane before theconcrete is poured. After the pour, grooves in a pieshape arrangement are cut in the pad to drain any liq-uid leaking from the tank to the outside where it canbe seen.

Standard Drawings GD-D1120 and GF-S1121 provideexcellent illustrations of the requirements for new leakdetection bottoms and foundations.

911 Concrete Work

Dimension Checks

During construction of the foundation, critical dimen-sions such as diameters, depths, levels, ringwall depth,fill depth, waterdraw basin dimensions, telltale line lo-cation, etc., must be checked for accuracy against thedrawings.

Excavation and Fill

Before Concrete is Poured. Any backfilling of the ex-cavation made for the foundation should be welltamped into place. The bottom of the excavationshould be checked for adequate compacting. Formingfor the vertical walls of the foundation should extendbelow the grade specified.

After Concrete is Poured. Backfill around the ring-wall and waterdraw basin after removal of forms

should be well compacted.

Concrete for Foundation

Before ordering the concrete, check mix proportionsand mix timing with concrete subcontractor. Chloridesalts should not be added to the mix to accelerate hard-ening, and soluble chlorides should not exceed 0.15%,as recommended by the American Concrete Institute’spublication 201.2R-77 “Guide to Durable Concrete.”Also check proportion of concrete to polypropylene fi-ber reinforcement material, where used for the pad.

Before Pouring

• Slump Test. Be sure you have cylinders on handto perform slump tests.

• Ringwall Forms. Before concrete is poured, thetop of the ringwall forms should be checked forlevel by survey: the elevation of the top of the con-crete must be within 1/2 inch of the specified ele-vation at all points. In addition, elevations shouldnot vary by more than 1/8 inch in any 30-foot cir-cumferential length, nor more than 1/4 inch aboutthe entire circumference.

• Reinforcing Bars. Before concrete is poured,check that the bars are the correct size and dimen-sions and that they are placed according to thedrawings and specifications. The bars must be atleast 1-1/2 inches away from the foundation formsfor adequate coverage when the concrete is poured.

• Concrete Pad. If wire mesh is used as a concretepad reinforcement instead of the recommendedpolypropylene fiber, check that there are sufficient“chairs” to hold the wire the proper distance abovethe fill or old bottom. Before pouring, check theslope to ensure there will be sufficient concreteover the wire reinforcement.

During Pouring

• Mix Consistency. Perform slump test and checkthat concrete is worked into all areas so there areno voids or trapped bubbles of air.

• Coverage, Concrete Pad. The minimum concretecoverage depth should be checked against thespecification.

After Pouring

• Concrete Ringwall. Immediately after the ringwallis poured, elevations and tolerances should be

900 Construction Tank Manual

900-2 June 1994

checked by survey. Swelling of the formed areausually results in a slight lowering of the top edgeof the form. A slight variation in the ringwall di-ameter is not critical but any variation in the topof the ringwall and pad elevation is. The height (topelevation) of the pad edge form should be checkedfor elevation by survey, not by measuring from thetop of the ringwall pour.

Check that drain pipes through the concrete ring-wall are clear, not plugged.

• Exposed Edges. All exposed edges of final poursshould be chamfered. Minimum thicknesses shouldbe checked immediately following the pour.

• Concrete Pad. After the forms are removed andneeded patching completed on the outside edge ofthe pad, check that the concrete patches or groutadhere properly.

• When to Cut the Leak Detection Grooves. Saw-cutting of the grooves in the concrete pad shouldbe done as soon as the concrete is cured enoughfor foot traffic. Usually this is 24 to 48 hours afterthe pour. This is the optimum time for ease of cut-ting and to avoid broken edges. See Section 912below for the proper method for saw-cutting thegrooves.

912 Installing the Secondary Containmentand Leak Detection System

Together, the membrane liner and the grooves cut intothe concrete pad are the secondary containment andleak detection system. This section tells you what towatch for during membrane liner installation. Also re-fer to the following additional sources of informationin the Tank Manual: Section 500, “Foundations andGroundwater Protection”; Specification TAM-MN-1,“Tank Bottom Replacement and Membrane Place-ment”; and Specification TAM-MS-4763, “MembraneLiner for New Tanks.”

When to Install the Membrane Liner

• New foundations: the membrane is placed aftercompletion of the concrete ringwall, removal of theinternal ring forms, and backfilling and compacting(to the proper slope) of the area inside the ringwall.

• Cone up bottom foundations: the membrane is in-stalled under the waterdraw basin prior to its pour.

• Cone down bottom foundations: the center sumpand sump liner along with the telltale line from the

sump liner to the standpipe outside the tank areplaced prior to membrane installation.

How the Membrane Liner is Attached

• New foundations: the membrane liner is impaledover the concrete ring foundation reinforcing barsextending vertically from the foundation (seeStandard Drawing GF-S1121).

• Replacement bottoms: the membrane is attached tothe old bottom at the shell by adhesive/sealant andby impaling (see Standard Drawing GD-D1120).The old center sump is cut out and replaced witha new sump and sump liner, and telltale line run toa standpipe outside the tank for cone down bot-toms.

Forming the Membrane Liner. The membrane linershould be level, smooth and free of wrinkles as prac-tical before the sheets are extrusion welded (or bonded)together. Check extrusion welds (or lap joint adhesion)for bond and leakage. Bond can be checked with adulled ice pick, and leakage by vacuum test similar tothat used for welded steel plate seams.

On replacement bottoms, the membrane at the “ratholes” should be well sealed with adhesive/sealant. (Onbottom replacement jobs, rat holes are the cutouts inthe old shell that allow leaks to drain from the groovesin the concrete pad and out to a gutter.)

Telltale Pipes. These pipes carry the liquid from leaksaway from the tank to where an operator can see it.On cone down bottoms, telltale pipes should bechecked for level and tested for leakage. The backfillshould be tamped. On replacement bottom installationof the telltale line, the area under the concrete ringwall(or area under the shell) should be back filled withconcrete to avoid local settlement.

Sump. Center sump elevation should be exactly tospecification. The sump should rest fully on well com-pacted soil. If the base under the center sump has anytendency to shift or settle, an unformed, polypropylenefiber reinforced 4-inch thick pad should be installedand checked for elevation before the basin is installed.

Leak Detection Grooves. Follow the rules below forgrooves:

• Grooves in the concrete pad are best made by saw-cutting.

• Grooves should line up and extend to the “ratholes” cut in the existing shell on cone up bottom


June 1994 900-3

replacements. The last 12 to 15 inches will have tobe chiseled. On cone down bottoms, grooves shallstop 12 to 15 inches from the shell, which will nothave “ratholes.”

• Grooves should extend to the distance from theshell that the concrete saw can cut on replacementcone down bottoms.

• The groove layout should be checked againstproper drawing detail. Note the difference betweenthe cone up and cone down groove pattern.

913 Bottom-to-Foundation Seal

Before placing the new bottom plates (or annular ring),a band of sealant is placed at the edge of the founda-tion or pad. This sealant prevents groundwater fromentering under the tank.

920 BOTTOM CONSTRUCTION

This section covers field installation of steel bottoms.

921 Bottoms for New Tanks

Bottoms Not Requiring Annular Rings. The newbottom sheets are tacked into place, then welded.Watch for excessive overlapping of plates and grindingdown of the upper plate to hide a less-than-full filletweld. Before welding, check that enough plate extendsbeyond the outside edge of the shell radius to meet thespecified overlap.

Cone up Bottoms Requiring Annular Rings. The an-nular ring plate should be installed first. Annular platemust be welded with full penetration welds. As manyplates as can be handled may be back welded into asingle section for installation. Welding these assembledsections together in place requires the use of backupstrips (see Figure 900-1). After installation of the an-nular ring, the bottom plate is tack welded in place andthen welded. The plates should shingle toward the lowpoint, i.e., the outside row of plates should be installedfirst with the higher center plate row installed last.

Cone down Bottoms with Annular Rings. The pre-ferred method of installing a new cone down bottomwith annular ring is to install the bottom deck platefirst, shingled toward the center (i.e., the row of platesrunning through the center is placed first). The annularring is then placed on top of the deck plate with itsinstallation being the same as detailed above. Installingthe annular ring first traps a small amount of liquidnear the edge of the shell. The finished fillet weld at-taching the annular ring to the bottom deck plate

should, as a minimum, be equal to the bottom deckplate thickness. If the surface is to be coated, the weldshould be ground to a smooth radius.

922 Bottom Replacement

For a complete description of the requirements for re-placing tank bottoms, see the commented version ofMaintenance Specification TAM-MN-1, Tank BottomReplacement, and the discussion above. Below is asummary of the procedure to follow for tank bottomreplacement for small and large tanks.

Small Tanks

Small tank bottom replacement is best done by lifting(or jacking up) the tank, placing a prefabricated bottomon the foundation, then lowering the tank to within 2inches of the new bottom, cutting the tank shell justabove the old bottom weld, sliding the old bottom outand then lowering the shell and roof into place. Theshell is then welded into place and tested.

Large Tanks

For replacing the bottoms of large tanks, follow thesteps described below for each of the replacementphases: preparation, bottom-to-shell welding, weldseam testing, and welding of pads and reinforcingplates to bottom.

Preparation Phase

To prepare the shell for bottom replacement followthese steps:

X22844.DXFTAM900-1.GEM

Fig. 900-1 Details of Annular Ring Butt Weld andBackup Strip Installation


900-4 June 1994

1. Remove internal appurtenances, supports, andbrackets.

2. Cut horizontal slots in the shell. These slots areusually about 5-1/2 to 8-1/2 feet long with 6inches of shell left between the slots. The heightof the slot should be 3/4 inch. The lower face ofthe slot should be relieved (notched out) for buttwelded annular ring backup strips. The bottomedge of the slot will act as a form for the concretespacer. See Figure 900-2.

3. Weld square C-shaped support clamps (or “dogs”)of heavy steel to the shell so that the open area ofthe “C” allows the new bottom plate to slipthrough the shell with the required overhang. SeeFigure 900-2.

4. Install membrane under roof supports. Formaround fixed roof supports and wrap floating rooflegs as discussed in Specification TAM-MN-1.

5. Install the membrane liner as discussed in Section910 and shown on Drawing GD-D1120.

6. Install the concrete spacer. Complete concretearound supports as discussed in the specification.

7. Remove 6-inch spacers between slots, install annularring through shell slots and install bottom plate.

Relieving Shell over Bottom Plate Weld. A portionof the shell plate directly over the field welded bottomlapped plate or butt welded annular ring joint shouldbe notched in order to permit completion of the weldunder the tank shell. Each of the lap welded bottomplates or butt welded annular ring joints under the shellshould be inspected before the notch can be welded up.Failure in this weld joint can produce a bottom leakalmost impossible to track down. See Figure 900-1.

Bottom-to-Shell Weld Seam

Minimum weld thickness is specified in API 650, Para-graph 3.1.5.7. There is no increase in strength by ex-ceeding the thinner plate thickness dimension with theweld. However, since this particular weld is subject toconsiderable potential corrosion, on cone up bottomsin particular, some extra corrosion allowance in theweld is useful.


Fig. 900-2 Slot Configuration for Replacement Bottom


June 1994 900-5

Procedure. The ideal step-by-step procedure in makingand testing the bottom-to-shell welds is to weld the in-side weld first, leak test the weld by applying dieseloil or penetrant to the weld side and visually inspectingfor leakage on the exterior of the shell. The exteriorweld is then made. This method ensures a leak-freestockside weld. It should be used wherever the bottomdesign does not include a thick welded annular ring.

Bottoms equipped with annular rings cannot be weldedthis way. Making the stockside weld first causes theannular ring plate to rotate about the bottom edge ofthe shell. For this reason, the outer weld must be madefirst and tested before the inner weld is made.

Verify that all traces of diesel oil or penetrant are re-moved by detergent washing from the opposite sideprior to making the weld.

Replacement Bottoms. After the bottom-to-shell weldhas been completed and tested, the “dogs” supportingthe shell are removed and the tank permitted to settledown on the spacer pad.

Vacuum Testing of Weld Seams

Vacuum testing of weld seams is often done as the bot-tom seam welding progresses; however, this practice isnot recommended. Sometimes slag inclusions occur inthe welds, particularly at stop and start weld points.Vacuum testing immediately after welding does notgive these inclusions enough time to open up. For thisreason, vacuum testing of bottom welds should be de-layed for 4 or more days (if possible) after welding.Failure due to hydrogen cracking should be evident af-ter 1 day.

Pads and Reinforcing Plates

All pads or reinforcing plates welded to the tank bot-tom should be, as a minimum, seal welded all around.No clip, support, bracket, etc., should be welded to thebottom plate without a pad between the item weldedon and the bottom plate. This precaution avoids con-centrated loads that might tear the bottom.

930 SHELL CONSTRUCTION

Building a tank shell round and plumb is of criticalimportance for all floating roof tanks and for thosefixed roof tanks that might have internal floating roofsinstalled in the future. A round and plumb shell mini-mizes the annular space variation between the shell and

floating roof and, therefore, gives better sealing andless maintenance of the seal. The key to constructinga truly round and plumb tank is to ensure that the topedges of the shell courses are level, especially the edgeof the first course.

Plate Preparation and Shop Inspection

Tank erectors have fabrication shops where tank plateis processed and tank appurtenances are fabricated.Plate processing includes:

• Cutting each plate square to size

• Beveling edges for field welds

• Forming plate to required curvatures

• Abrasive blasting and priming the plate

A Company representative should inspect work doneat the shop. A checklist for shop inspectors is includedin Section 1040.

Leveling

Leveling the top of the first course is critical for shellroundness. The smaller the degree of variation from level,the more perfectly round the tank will be, and the remain-der of the shell will be easier to erect. The shell levelshould be checked after the plate is tack welded ordogged in place. The level of the top of the first coursemay be corrected by wedges placed between the tanksteel bottom and foundation. The level of the remainderof the courses should also be checked. Squared plates willreduce out-of-level problems.

Welding

Peaking and Banding

API 650, Paragraphs 5.5.4. and 5.5.5, cover “peaking”and “banding.” These terms refer to the distortion ordimpling of shell plate and seams inward or outward.Ideally, the welding of shell horizontal and verticalseams should be done with alternating weld bead in-side and outside to avoid peaking and banding. Theweld joint should be closely checked by use of astraight edge on horizontal seams and by a board cutto the exact tank radius on the vertical seams. If peak-ing or banding is detected, no further welding shouldbe done on that seam until a procedure is developedthat will not worsen the condition.


900-6 June 1994

Improper shop forming of the shell plates and inade-quate cribbing of the rolled plates during shipping andstorage can also contribute to peaking and banding.

Welding and Welder Qualification

Section 7 of API 650 covers welding procedure andwelder qualifications. In addition, most operatingcompanies have extensive welding specifications andwelder qualification documents.

Weld Quality Control

Onsite weld quality control by a knowledgeable andexperienced welding inspector is strongly recom-mended. Most major operating organizations havetheir own welding inspection capability. Smaller or-ganizations that do not should either arrange for thatservice from a nearby Company organization or con-tract the service.

Wind Girders and Preventing WindDamage During Erection

All open-top tanks over 50 feet in diameter have windgirders to stabilize the shell. Wind girders are coveredin API 650, Section 3.9. All plate-to-plate juncturesshould be seal welded to prevent corrosion productfrom breaking welds.

Preventing Wind Damage

Before the fixed roof is installed (and for open-toptanks, before the wind girder is installed), failure toprotect the shell from wind-caused buckling can resultin major damage and delay in tank erection.

• Protection against buckling should begin with theerection of the third course.

• Protection can be in the form of temporary clipsinstalled at the top of the shell and connected bysteel cables to ground anchors.

• On floating roof and open-top tanks, the windgirder can be raised and temporarily attached toeach shell course as the shell is erected. It thencan act as not only protection against wind dam-age, but as a work platform and walkway.

Dimensional Checks During Erection

Shell Plate

As mentioned earlier, the level of each shell plate andcourse should be checked during erection. The levelof each plate should be checked as it is set in place

with corrections made by adjusting the thickness of thewedges placed between plates on the horizontal seam.Plate surfaces should be flush with lower and upperplates on the stockside.

Tank Diameter

The tank diameter is checked by measuring the tankcircumference as each course is erected. “Hourglass”or “barrel” shaped shells are not an unusual occur-rence. This problem is prevented by adhering strin-gently to the gap specification between plates,checking individual plate lengths, and using scribedpoints for lineup at the top edge of the shell courseplate being installed. Often the last plate on a coursebeing installed is designated to be trimmed to fit inthe field to adjust for errors. At other times weld spac-ing is used.

Peaking and Banding Checks

These checks should be made during the placing andweld up of each shell plate. The checks are made us-ing a long straight edge (held vertically on the stock-side surface) or a board cut to the exact shell radius(held horizontally across the vertical weld seam).

940 ROOFS

This section discusses the construction of fixed andfloating roofs and roof drains.

Fixed Roof

A fixed roof is constructed after the bottom and shellare erected. Lap welded roof deck plate should be laidin reverse shingle orientation to prevent capture ofcondensate in the stockside overlapped seam. Thefixed roof should be built with a frangible joint (roof-deck-plate-to-top-angle weld) as described in Section400. Excess weld material should be removed bygrinding. This joint is critical to protect the shell andbottom-to-shell seam during internal overpressure.

Floating Roof

Some tank builders prefabricate sections of the pon-toon for assembly inside the tank while others merelycut plates and assemble the roof in place. Erection ofthe floating roof usually begins after completion of thefirst shell course. An even annular space all around theroof is of primary importance. The roof is usually as-sembled on low temporary supports (see Figure 900-3).The roof is then raised by air or is floated on water tothe high leg position where the leg assemblies are in-stalled. Once the roof leg assemblies have been in-


June 1994 900-7

stalled and entry to the tank under the roof is possible,the roof leg or guide assembly should be welded to thereinforcing pad or roof deck plate from the undersideof the roof. See Figure 900-4.

All floating roof pontoon compartment bulkheadsshould be welded so as to make the pontoon vaportight. This requires that each inspection hatch cover beequipped with a gooseneck vent.

Roof Drains

General

At all times during floating roof construction and whilethe tank is out of service for repair or rebuilding, adrain system for the floating roof must be operational.

This can be done by leaving the flexible section of thedrain system unconnected, permitting rainwater fromthe roof to drain into the tank. It also can be done byleaving the drain system open (unplugged at the roofbasin and with the valve on the shell open).

Articulated Joint Roof Drains

Roof drain systems consisting of rigid pipe sectionsand articulated joints (such as the externally sealedChicksan) must be installed accurately to the drawingdimensions.

The drain system must be designed to accommodatethe floating roof at any position, from its resting posi-tion on low legs to its design safe oil height.

Two common errors made by people unfamiliar witharticulated joint roof drains is to adjust the dimensionsto better fit the high leg position, and to get the articu-lated joints with their counterbalance bosses in thewrong orientation.

Flexible Pipe Roof Drains

The “lay pattern” of the flexible pipe roof drain(Coflexip or Mesa brands) and the “twist” in the pipewhen connecting the flange are critical to proper op-eration. The flexible pipe manufacturer’s design anddimensions must be followed. If an error is apparenteven though construction dimensions were accuratelyfollowed, the manufacturer of the flexible pipe shouldbe notified and any re-dimensioning delayed until themanufacturer has corrected the discrepancy in design.The lay pattern and installation dimensions and orien-tation must be designed to avoid obstructions, particu-larly roof legs, at both the “low” or operating rooflevel and at the “high” or out-of-service level. The de-sign is peculiar to each tank.

941 Aluminum Dome Roofs

Introduction

This section covers the aluminum dome roof, its appli-cations, use guidelines, and a comparison of alternativetank-covering methods. Figure 900-5 shows an alumi-num geodesic dome plan and elevation.

Aluminum geodesic dome roofs, or storage tank cov-ers, offer two unique advantages over other coveringmaterial:

1. They are clear-span structures — meaning that thesupport of the structure is provided at the periph-ery only, without the need for column supports in-

x25478.DXFTAM900-3.GEM

Fig. 900-3 Temporary Supports—New Floating Roof


Fig. 900-4 Welding of Roof Leg to Roof DeckPlate


900-8 June 1994

side the projected plan area of the roof. Clearspans of up to 300 feet or more are possible.

2. They are economically competitive and in manycases the lowest cost option for covering a tank.

Originally aluminum geodesic dome roofs were usedto convert external floating-roof tanks to internal float-ing-roof tanks, minimizing the effects of weather onmaintenance and operation. By the late 1970s the alu-minum geodesic dome roof gained widespread use asa cover for both retrofitted and new tanks. Followingthe implementation of the Clean Air Act, the aluminumdome roof enjoyed a resurgence as a means of reduc-ing air emissions. Today there are several thousanddome roof tanks in existence.

Applications

Weather Covers

Tank covers or roofs are used to reduce many weatherrelated problems associated with external floating rooftanks. External floating roof tanks must be periodicallydrained to eliminate the bottom water layers that formwhen rainwater runs down the inside wall of the tank

shell and past the roof seals. This water must then betreated to remove environmentally unacceptable mate-rials before it is discharged. Additionally, external roofdrains are subject to freezing, plugging with debris, andrequire frequent inspection to assure that they areworking. An aluminum dome roof eliminates all ofthese problems. Figure 900-6 shows this schematically.

Product Purity

Many diesel fuel tanks are covered to reduce water in-filtration. Too much water in the tank can lead to tur-bidity and off-spec material. To purge the fuel ofwater, the tank must be allowed to settle then watercoalescing units (or other types of water removal sys-tem) must be used.

Keeping water out of fuels is particularly important formaterials which do not easily phase-separate in tanks.Examples include alcohols, such as motor fuel oxygen-ates. It is preferable to store products such as MTBE(Methyl Tertiary Butyl Ether, a gasoline oxygenate ad-ditive) in covered tanks because water content maycause the product not to meet specifications.

If aluminum is compatible with the product beingstored, these domes should be considered for fixed rooftanks that have been internally coated to eliminateproduct contamination problems resulting from iron,iron salts or rust contamination as a result of shell cor-rosion.

X47216.HPGTAM9005.GEM

Fig. 900-5 Aluminum Dome Roof


Fig. 900-6 Weather Related Problems of ExternalFloating Roof Tanks


June 1994 900-9

External Corrosion Resistance

Because aluminum dome roofs are corrosion resistantin most atmospheres, they can be used in any geo-graphical area. However, in marine environments thealuminum roof must be located at least 200 yards fromseawater or shoreline.

Internal Corrosion Resistance

Due to its corrosion resistance to hydrogen sulfide, analuminum dome roof is useful for sour product service,sour crudes, sour waste water, and many other corro-sive environments.

In steel roof applications where underside corrosion isa problem, corrosive vapors condense and get into thecrevices of lap welded joints, initiating corrosion. Toprevent corrosion in these applications, steel roofs aredesigned as follows:

• A reverse shingle layout is often used to minimizecondensing liquid on the underside of plates and increvices.

• Seal welding the laps on the bottom side is anotheralternative.

• Some roofs use external rafters so that the there areno crevices (API 650 does not allow welding theroof plates to the rafters). In all the above cases,the use of an aluminum dome roof should be con-sidered.

Emission Reduction

An internal floating roof tank suffers less evaporationloss and emissions than a comparable external floatingroof tank. Emission and losses from roof seals are ef-fected by wind speed. Since the wind speed above theseals in an internal floating roof is almost zero, theemission of air pollutants is minimized. Either a con-ventional steel roof or a dome roof will have the sameeffect on emissions. However, the geodesic dome hasan advantage that is not available with a conventionalroof. Large steel roofs, on internal floating roof appli-cations, must be supported by columns. These supportcolumns must penetrate the roof. At each penetrationthere are some emissions. Because the geodesic domeroof is a clear-span structure, or a structure that is sup-ported entirely at the perimeter, there is no internalroof penetration. See Figures 900-7 and 900-8.

Figure 900-9 shows some typical emissions compari-sons for covered tanks.

Pressurized Applications

Applications that may involve pressure are usuallyfixed-roof tank applications with inert gas blanketingunder some small pressure (less than 2" wc) or in va-por recovery systems. Although API 650, (AppendixG) allows pressures under the dome of up to 9 incheswc, this is never used in practice. The typical valuesare around 2 inches of water column maximum. Prob-lems with leakage have been significant above thispressure and larger tanks are not designed to handle


Fig. 900-7 Wind Effect on External Floating RoofEmissions


Fig. 900-8 Aluminum vs Cone Roof Emissions


900-10 June 1994

more pressure. Dome manufacturers are, however,making improvements to the joint details of domes,and increased pressure allowances are becoming morecommon.

In vapor tight, pressurized-hydrocarbon services, orfuel-gas blanketed services, silicone seal materialsshould not be used. The migration of hydrocarbon intothe joints has caused many problems. Neoprene or Se-coflex polysulfide used around hub covers and batonstrips work well as sealants.

Fire Susceptibility

Because external floating roof tanks are subject to rim-seal fires caused by lightning strikes, covering the tankreduces the possibility of fires. However, lightning-caused fires have occurred in aluminum dome coveredtanks. Such fires occur because flammable vapors ac-cumulate above the floating roof and are ignited by alightning strike to the circulation vents. This occur-rence is extremely rare and is usually caused by somekind of plant upset. Normally the venting specified byAppendix H of API 650 is adequate, even under lowwind conditions, to maintain all flammable petroleumproducts well under the lower flammable limit.

It should be noted that no fires have occurred that havesignificantly heated the interior vapor space of an in-ternal floating roof tank. Because aluminum loses itsstrength at relatively low temperatures compared tocarbon steels, a temperature rise in the vapor spacecould cause the dome to collapse onto the floating roof.

Because fire probability in dome-covered floating rooftanks is low, fixed fire fighting equipment need not be

installed on these tanks. If they do occur, fires may befought through the hatches or light panels in the roof.In spite of having a dome roof, some fire regulationscall for installation of fixed foam systems on tankswith flammable materials.

Design Requirements

Standards

API 650 (Appendix G) is the only aluminum domestandard that sets out design criteria for structurally sup-ported aluminum dome roofs. However, the domes, be-ing part of a larger structure, are often regulated asbuilding structures and are subject to local building per-mit and fire department requirements. Live and deadloadings, as well as maximum height requirements, areoften regulated by the building permit authorities. API650, (Appendix G) recognizes the following applica-tions of aluminum domes on tanks:

For new tanks

• For atmospheric pressure

• For internal pressure up to nine inches water column

However, there are numerous practical design consid-erations that are not covered by the standard, some ofwhich are covered below.

Physical Characteristics

Dome size is not limited; however, the radius of thealuminum dome must be within 0.7 - 1.2 times the di-ameter of the tank. For carbon steel dome roofs the ac-ceptable dome radius is 0.8 - 1.2 times the diameter ofthe tank. The flatter dome (1.2D) is the same as thecarbon steel dome, however, the allowed steeper alumi-num dome has been limited arbitrarily to a steepness of0.7D. Steeper domes can be built.

Skylights are sometimes used on tank domes. Whenthey are used, a typical usage is at a ratio of 1% of theprojected area of the dome. They can be used to let inlight and to do visual inspections required by EPA. Theuse of skylights is optional, but when used they mustbe constructed of 0.25 inch minimum thickness clearacrylic or polycarbonate plastics.

Materials

The structural members are typically 6061-T6. The pan-els are series 3000 or 5000 aluminum with a requiredminimum thickness of 0.05 inch. Fasteners are alumi-num or stainless steel. All aluminum must be electri-cally isolated from carbon steel by an austenitic

TAM900-9.TIF

Fig. 900-9 Emission Loss Comparison CoveredTanks - No Guide-Pole


June 1994 900-11

stainless steel spacer or elastomeric isolator bearingpad. The aluminum dome must be electrically bondedto the tank shell using 1/8 inch stainless steel cableconductors at every third support.

Coatings

It is very rare for domes to be coated or painted inter-nally or externally because the cost is quite high. As-thetic considerations would be the only reason to painta dome. If painted, the surfaces must be first degreasedand etched for good adhesion.

Two Basic Dome Designs

The weight of the aluminum dome structure generatesan outward thrust as shown in Figure 900-10. The flat-ter the structure the greater the outward radial thrust.To handle this force, the dome manufacturer’s havestandardized on two basic type of roof designs:

1. Fixed Base Design. In this design the tank shellabsorbs the horizontal thrust caused by the dome’sweight.

This is the preferred method of construction for newtanks. Since there is no tension ring, the radial thrustis taken by the top of the tank, requiring less struc-tural aluminum. However, the dome manufacturermust supply the load conditions that the tank will berequired to handle as a result of the horizontal thrustfrom the dome. Additionally, the tank must havesome stiffening at the top to withstand the dome ishorizontal thrust loads, often a wind girder.

This design has one other advantage. The domeflexes less due to a given load because the base isrestrained by the tank shell. Less movement in thedome means less possibility for fatigue or leaks.

2. Sliding Base Design. In this configuration, the out-ward thrust is handled by a “tension ring” in thestructure. The only force acting on the tank isgravity. This design works well when modifyingexisting tanks because there is no need to modifythe shell which is already designed to handle thedead weight of the dome. A detail of the tensionring is shown in Figure 900-11.

Attachment of Dome To Tank Shell

The dome is attached to the tank shell for both thefixed and sliding base design by means of supportpoints as shown in Figures 900-12A and 900-12B. Thespecific details of attachment vary from one manufac-turer to another. The detail for the fixed or slidingbase design is similar, but in the sliding base design(where the support points must be free to move ra-dially) a sheet of teflon is used as the bearing surfaceand a slotted-bolt hole allows the radial movement.

Elevation Of Aluminum Dome

Figure 900-13 shows typical dome mounting details forexisting tanks. To provide ventilation the dome is ele-vated slightly above the top of the tank. The supportpoints (sliding type) transfer the loading through col-umns to wind girders so that the top of the tank shellwill not be over-stressed at the points of attachment.

Figure 900-13 appears on page following.

A retrofitted tank dome poses a business decision:either lose some tank capacity or spend the extramoney to add sufficient height to the dome so that notank space is lost. Tank space is lost due to floatingroof appurtenances, such as seals or floating roof legsthat project upward. This can vary up to several feet.To raise the roof high enough to avoid loss of tankspace, free-board must be installed above the top of thetank shell to support the dome. Any open space mustbe covered. This is usually done with aluminum rollformed into sidewall panels.

Design Loadings

The minimum dead loading is the weight of the roofitself and all accessories attached to it. Typically, alu-


Fig. 900-10 Forces on Dome Structures


900-12 June 1994


Fig. 900-11 Tension Ring

X47200.HPGTAM90012A.GEM

Fig. 900-12 Support Point

X47208.HPGTAM90012B.GEM


June 1994 900-13

minum dome roofs average 2.5 psf (1⁄2 inch wc), whichis about 1/3 the weight of conventional 3/16 inch thickcarbon steel roofs.

The live load is 25 psf or greater if required by theregulatory agencies or building codes. API 650, Ap-pendix G includes requirements for unbalanced loads,panel loading, and concentrated loading. It also givesrequirements for the load combinations such as dead-load-plus-seismic. The suppliers are required to runthrough a series of load combinations to assure thatthe roof is structurally adequate for the application. Ifthere is any internal pressure, that number must be in-cluded in the load calculations.

One of the design-loading conditions that requiresgood communication between the purchaser and thesupplier is the means of transferring the roof loadsto the tank shell. The tank and foundation must bechecked to assure that they are adequate to assumethe increased loading from the added roof. Since thetop of an existing tank is rarely round, the dome

must be constructed to accommodate this toleranceproblem. This is done by the allowance for large tol-erances made at the support points. It must also accom-modate thermal expansion of the roof within atemperature range of 120°F. For existing tanks, theeasiest way to handle some of these problems is to de-sign the roof to shell junction with a sliding surface sothat only vertical loads are transferred to the tank shell.For new tanks, the tank rim is often strengthened suf-ficiently so that the roof is rigidly attached to the shellwhich is designed to take all of the roof loadings. Whentanks have internal pressure, the preferred design is to rig-idly affix the roof to the shell. If a sliding joint is used,a sealing fabric must be installed to contain the internalpressure. This design is more subject to failure than thefixed-base design.

Shell Buckling

Local and general shell buckling must have a mini-mum safety factor of 1.65. General shell bucklingcan be determined from:

NOTES:1. SUPPORT POST TRANSFERS REACTIONS

TO THE WINDGIRDER TO PREVENT OVER-STRESSING OF THE TOP OF THE TANKSHELL AT POINTS OF ATTACHMENT.

2. FREEBOARD IS ENCLOSED BY ROLLFORMED SIDEWALL PANELS WHICH AREATTACHED TO SUPPORT POSTS.

3. POST ELEVATES DOME ABOVE TOP OFTANK.


Fig. 900-13 Tension Ring


900-14 June 1994

W = 2258 x 106 √IxA

(SF) LR2

(Eq. 900-1)

where:

W = allowable live load, psf

Ix = moment of inertia of beam about thestrong axis, in2

A = cross section area of beam, in2

R = spherical radius of dome, in

L = average dome beam length, in

SF = safety factor

= 1.65

Tension Ring Area

The minimum tension ring area is determined from:

A = 11 D2

ntanαsin

180n

Ft

(Eq. 900-2)

where

A = net area of tension beam, in2

D = tank diameter, ft

n = number of dome supports

α = 1⁄ 2 the central angle of the dome orthe roof slope at the tank shell

Ft = allowable stress of the tension ring, psi

Roof-Shell Junction

A dome roof is never considered to be frangible. How-ever, internal pressure would probably blow out domepanels or destroy the roof long before the shell or bot-tom would be affected and could therefore be an ef-fective means of preserving the integrity of the tankcontents during an over-pressure situation.

Temperature Limits

API establishes a maximum operating temperature foraluminum dome roofs of 200°F.

Wind Loading

Unless specified by the tank/owner operator, the de-fault wind loading condition is 100 mph.

Seismic Loading

The seismic loading is presumed to act uniformly overthe dome and the design basis for the dome is:

F = .24ZIWr

(Eq. 900-3)

where

F = horizontal force

Z = zone coefficient

I = essential facilities factor

= 1.0 for most cases

Wr = weight of tank roof, lb

Testing

For atmospheric applications the roof is simply hoseddown and checked on the underside for the evidenceof leakage. When the tank is designed for internal pres-sure, it should be pressurized with air and soap-bubble,and leak tested.

Appurtenances

Roof hatches are optional. However, most tank appli-cations use only 1 hatch. If there is a rolling ladderleft in a tank, a hatch is often supplied for it. Figure900-14 shows the details of a roof hatch.

Roof nozzles should be constructed per Figure 900-15.They are used for high level alarms or for thief hatchpurposes. Many applications do not have any roof noz-zles.

Skylights are optional See Figure 900-16. However,they provide natural lighting for the interior and alsoprovide a means to do visual inspection of roof sealsthat are required to be performed annually by EPA.They are recommended and they should be provided ata rate of 1% of the projected area of the dome.


June 1994 900-15

Dome roofs are vented by the gap between the roofand the shell, making peripheral shell vents unneces-sary. One center vent at the top is required per API650 (Appendix 11), usually an 8 inch vent. Typically,there is no special access provided for this hatch.

Internal Rolling Ladders

When an existing tank is retrofitted with a dome, theexisting rolling ladder can be left in place. Because thedome usually interferes with the operation at the topof the ladder, the dome manufacturers often reattachthe ladder to the structural members of the dome. Thisrequires that the bottom of the rolling ladder be ex-tended to suit the modifications.

Often the tank owner/operator does not wish to makethe modifications or there are no modifications that canbe made to accommodate the new dome and the fulltravel range of the floating roof. In these cases the lad-der is removed and tank owners do one of two thingsfor access to the internal roof:

1. They use a rope ladder for access when needed.

2. They wait until the floating roof is at its high level


Fig. 900-14 Typical Access Hatch Detail

X47202.HPGTAM900-15.GEM

Fig. 900-15 Typical Nozzle Section at DuctPenetration with Flanged Connection

X47203.HPGTAM900-16.GEM

Fig. 900-16 Skylight Panel Detail


900-16 June 1994

in the tank and simply access the top of the roofby stepping onto it.

Access to the internal roof is required periodically forseal, appurtenance and roof condition inspections.

Platforms and Walkways

In existing tanks retrofitted with domes, some problemsrelated to the tank gager’s platform often arise. In thesecases modification must be made to raise or relocatethe platform to clear the dome.

Walkways are rarely used on domes as there is reallyno reason to access the top of the dome. The centervent at the top does not need maintenance in mostcases. However, when many tanks are located near oneanother, walkways have been used to provide accessas shown in Figure 900-17.

Construction

Domes can be constructed on operating tanks that arefilled with flammable materials since there is no hot-work involved. The typical construction sequence be-gins with the loading of the structural materials andsheet panels onto the top of the floating roof. The roofstructure is assembled using jackstands with bolted andother types of fasteners. The entire roof fits within theshell space. The roof can be raised until the dome is

higher than the top of the tank shell and then loweredonto its support points. The support points have suffi-cient radial adjustment to accommodate the typical out-of-round that exists in tank shells near the top.

Typical construction times will be according to Figure900-18.

Costs. For rough estimating purposes for aluminumdomes, refer to Figure 900-19.

950 TANK HOLD POINTS CHECKLIST

Figure 900-20 is a tank hold points checklist to be usedwhen constructing a tank.

990 REFERENCES

1. Morovich, The Use of Aluminum Dome TankRoofs, Proceedings of the 2nd International Sym-posium on Aboveground Storage Tanks, January14-16, 1992, Houston Texas, Materials TechnologyInstitute, 1992

2. Barnes, New Tank Roofs Capture Evaporating Va-pors, Louisiana Contractor, 12/1992

3. Barrett, Geodesic-dome Tank Roof Cuts WaterContamination, Vapor Losses, Oil and Gas Journal,7/10/1989

Diameter, ft Time, Weeks

30 - 70 1

70 - 100 2

100 - 120 3

TAM9018.WPFig. 900-18 Aluminum Dome Roof Construction

Period

Diameter, ft Installed Cost, $/ft 3

0 - 50 20 - 40

50 - 100 15 - 20

100 - 200 10 - 15

Fig. 900-19 Costs for Aluminum DomesTAM90019.WP

TAM90017.TIF

Fig. 900-17 Aluminum Dome Roof Walkways(Courtesy of Conservatek)


June 1994 900-17

TANK HOLD POINTS CHECKLIST

The items below are inspection hold points for the construction of ____ Tank in the ____________ Tank Fieldand are part of the contract. Company Engineer or Company Representative will initial this checklist after eachitem has been satisfactorily completed. Contractor will notify Company when these items are ready for inspec-tion. Company will have the time length indicated to inspect and approve or disapprove each item. Repairsand/or delays necessary to make each installation satisfactory will be at Contractor’s expense and will notconstitute delay by Company.

Item Engr. InitialCompany Rep.

Initial

1. Ringwall Installation(8 Dayshift hours after completion)

2. Soil Compaction & Sand Fill(8 Dayshift hours after completion)

3. Membrane Installation(8 Dayshift hours after completion)

4. Concrete Pad Placement(8 Dayshift hours after completion)

5. Concrete Cure Time/Clean Up(8 Dayshift hours after completion)

6. Bottom Plate Vacuum Test(8 Dayshift hours after completion)

7. Annular Ring Diesel Test(48 Dayshift hours after completion)

8. Shell 1st Course Inserts Installation and X-Ray(8 Dayshift hours after completion)

9. Shell 2nd Course Installation and X-Ray(8 Dayshift hours after completion)

10. Shell 3rd Course Installation and X-Ray(8 Dayshift hours after completion)

11. Shell 4th Course Installation and X-Ray(8 Dayshift hours after completion)





16. Roof Plate Vacuum Test(8 Dayshift hours after completion)

17. Hydrotest Tank & Install Roof Seal(8 Dayshift hours after completion)

18. AQMD Roof Seal Inspection(8 Dayshift hours after completion) TAM90020.WP

Fig. 900-20 Tank Hold Points Checklist


900-18 June 1994

1000 IN-SERVICE ABOVEGROUND STORAGE TANKS: GUIDELINESFOR INSPECTION, REPAIR, ALTERATION, ANDRECONSTRUCTION

Abstract

This section covers the inspection, repair, alteration, and maintenance of in-service, aboveground storage tanks(ASTs) — welded and riveted, non-refrigerated, and atmospheric — and focuses on the American Petroleum In-stitute’s (API) Standard 653 relating to these activities. A synopsis of this recently released standard is includedas Figure 1000-1 of this chapter.

Contents Page Page

1010 Background 2

1011 Industry Standards

1012 Intent of API 653

1013 Responsibility and Compliance

1014 Implementation: Time and Costs

1015 Other Considerations

1016 Recommended Implementation

1020 Preventing Failures: API 653 6

1030 Assessing Suitability for Service 6

1031 Reasons for Assessing Suitability forService

1032 Physical Considerations

1040 Inspection 7

1041 Inspection Philosophy

1042 Three Types of Periodic Inspections

1043 General Requirements forPost-installation Inspections

1044 Inspection Methods

1045 Typical AST Bottom InspectionTechniques

1046 Other Inspection Methods and Tools

1047 Leak Detection Methods of Inspection

1050 API 653 Repair and AlterationGuidelines

24

1051 Repairs of AST Components

1052 Welding

1053 Shell Plates and Penetrations

1054 Bottom Plates and Slumps

1055 Roofs and Foundations

1056 Hot Taps

1057 Hydrostatic Testing of Repaired,Altered, or Reconstructed ASTs

1058 Dismantling and Reconstruction

1060 The Mechanical Integrity Elementof OSHA 29 CFR 1910.119

34

1070 API Recommended Practice RP 575 35

1080 References 35

1090 Other Resources 35

Tank Manual 1000 Inspection and Testing

March 1993 1000-1

T O

C O N T E N T S

1010 BACKGROUND

Recent incidents involving ASTs have caused publicand legislative bodies to view them as environmentallyhazardous equipment. The most notable event occurredin 1988 in Floreffe, PA, when a sudden and cata-strophic spill released over one million gallons of fueloil into the Monagahela river, a drinking water sourcefor several municipalities.

Such episodes have contributed to the current attitudeof local, state, and federal agencies toward ASTs: i.e.,any leak or spill that contaminates subsurface or navi-gable waters often results in:

• Severe financial and legal penalties, and

• The potential for new and stricter regulations (cor-rective, not preventive) that specify secondary con-tainment or post-incident regulatory requirements.

Recently, API issued several, new, preventive stand-ards and recommended practices (RPs) for in-serviceASTs.

1011 Industry Standards

Many standards (e.g., API 620 and 650, AWWA D-100,UL-142), based on industry experiences, assist engineersin the design or construction of ASTs and assure a rea-sonably failure-free AST at installation. There were,however, no industry standards or practices for the in-spection or maintenance of in-service ASTs until API re-cently issued:

1. API 653, Tank Inspection, Repair, Alteration, andReconstruction. (See synopsis in Figure 1000-1.)

2. API RP 651, Cathodic Protection.

3. API RP 653, Interior Linings.

These documents are intended to reduce AST failuresand their associated environmental problems.

Note: Figure 1000-1 appears on page following.

1012 Intent of API 653

API 653, in conjunction with the several other APIpublications (see 1080 References), provides a compre-hensive AST spill-or-release-protection plan. Thisstandard is, in fact, an inspection document that out-lines a program of minimum maintenance require-

ments for the foundations, bottoms, shells, structures,roofs, appurtenances, and nozzles of in-service ASTs.

While it does not provide AST owners with cookbookanswers to all problems, this standard does offer thebest and most cost-effective current technology to en-sure that in-service ASTs:

1. Do not leak.

2. Do not fail catastrophically because of brittle frac-ture or structural breakdown.

1013 Responsibility and Compliance

Responsibility

Owner/Operator. The owner/operator of the AST hasthe ultimate responsibility for complying or not com-plying with the provisions of API 653. This standardplaces the burden of determining long-range suitabilityof service on the owner/operator and defines the degreeof quality by:

• Establishing the qualifications of inspection personnel.

• Requiring that findings be documented at the timeof inspections.

The Company. The Company can assign certain taskssuch as repairs or data collection to others, but mustdefine clearly the limits of responsibility for these tasksbefore the work commences.

Compliance

For most facilities, a standard in itself is rarely man-dated under law, except by implication; i.e., to complywith local, state, or federal authorities’ references to in-dustrial standards or good engineering practice.OSHA’s Process Safety Management Regulation1910.119 states, for example, that employers mustmaintain written on-going integrity procedures, followgenerally accepted good engineering practices, anddocument each inspection.

API 653 sets minimum requirements for ASTs and,therefore, authorities having jurisdiction may imposethis standard because nothing better exists. Such is thecase with EPA’s Spill Prevention Control and Coun-termeasures (SPCC) regulations that require regularlyscheduled, documented inspections of ASTs in facili-ties near navigable waterways. While EPA’s SPCCprogram does not mandate API 653, it is prescribed bydefault unless the owner/operator is already complyingwith all requirements of API 653.

1000 Inspection and Testing Tank Manual

1000-2 March 1993

1014 Implementation: Time and Costs

Implementation Timeframe

API 653 does not specify a deadline for compliancebut does require owner/operators to perform internalinspections at ten-year intervals (longer ones being anexception). All in-service ASTs should, therefore, bescheduled for an initial, comprehensive, internal in-spection within ten years. (See also Cost of InternalInspections later in this section.) Many companies maycomplete this work within a three- to five-year period,depending on the size of their facilities.

A standard does exist; therefore, any delay in compli-ance translates into an unnecessary risk for theowner/operator. A major AST failure now in a facilitythat has not begun to initiate API 653 would mostprobably:

• Outrage the public and devastate the owner/opera-tor’s image.

• Raise jurisdictional inquiries into the owner/opera-tor’s reasons for non-compliance with an industrystandard.

• Incur environmental penalties and liabilities in civiland possibly in criminal courts.

Suggestions for Mitigating Costs

Planning can mitigate the cost of implementing API653, particularly in three broad areas: cost of internalinspections, assessing suitability for service, estab-lishing and maintaining recordkeeping systems.

Cost of internal inspections. Attributed to preparingASTs for internal inspections and to interrupting theiroperations, these costs can reach millions of dollars peryear for a large, integrated oil company. API 653 sug-gests ways to increase the interval between internal in-spections to as many as 20 years, thus reducing thecost dramatically.

Assessing suitability for service. Engineering evalu-ations of ASTs can lower the costs of attaining fit-for-service status. For a AST with many violations of thecurrent standard, the difference in cost is appreciablebetween simply correcting everything and correctingonly those items an engineering evaluation deems nec-essary.

Establishing and maintaining recordkeeping sys-tems. Establishing a Companywide standard for re-cordkeeping — a standardized system, including

software — would be cost-effective, particularly if API653 were to become a Company policy in the future.

There are other, less obvious items that have an impacton controlling the overall cost of complying with API653:

Recouping costs. The costs associated with institutingAPI 653 are more than recouped by ensuring that theowner/operator does not:

• Incur post-incident costs of site remediation andheavy EPA-imposed fines.

• Experience costly business interruption.

• Expend additional funds to ensure that ASTs al-ready involved in incidents now comply with themany new AST regulations.

Note: The standard’s fitness-for-service programcould, in itself, have prevented many notableAST catastrophes.

Cost-saving, new designs. Operating costs of ASTs canbe expected to benefit from new AST designs whichshould incorporate those factors that will extend the pe-riod between internal inspections: e.g., liners, corrosionallowance, cathodic protection, and leak detection.

1015 Other Considerations

Assuming that the decision or policy is made to com-ply with API 653, there are several issues to considerbefore launching the program, including establishing:

• A budget for compliance

• An inspection team of employees, contractors, or acombination (see Inspection Agencies later in thissection)

• The procedures for

– Recordkeeping

– Inspections

* Operator’s monthly (required by API 653)

* Periodic external

* Internal (and the means of safe entry toASTs)

• A compilation of data on all in-service ASTs: ages,last inspections, problems, construction data, draw-ings, etc.


March 1993 1000-3

API Standard 653 is based upon and extends the principles of API 650.

Section 1 - Summary

API 653 provides minimum requirements for maintaining the integrity of in-service, aboveground storage tanks (ASTs). Theserequirements includes inspection, repairs, alterations, relocation, and reconstruction. The owner/operator is responsible for comply-ing with these standards and for following safe working practices.

Section 2 - Suitability for Service

General: When a change occurs in the original condition of the AST, personnel experienced in tank design must evaluatethe AST’s suitability for service.

Tank Roof Evaluation: When roof plates corrode to an average thickness of less than .09 inch per 100 square inches ofarea, they must be repaired or replaced. The principles in API 650, Appendix C offer guidance for evaluating an existingfloating roof but upgrading is not mandatory.

Change of Service: Any change of service involving internal pressure, operating temperatures or venting requirements mustbe evaluated according to the principles of API 650.

Tank Shell Evaluation: API 653 describes methods of determining the minimum thickness of corroded areas for evaluationfor suitability for service. Distortions, flaws, cracks, shell welds and shell penetrations must be assessed and evaluated onan individual basis.

Tank Bottom Evaluation: As leaks in tank bottoms are unacceptable, the causes of any potential failure mechanism (suchas settlement and corrosion) must be considered. If a tank bottom is being replaced, consider installing a leak-detectionsystem. Lining and cathodic protection of bottoms is covered by API RP 652.

During internal inspections, AST bottoms must be measured and the thickness determined. The minimum thickness of ASTbottoms is 0.1 inch unless the tank is lined in accordance with API RP 652 or has leak detection and containment for whichthe minimum thickness is decreased to 0.05 inch.

The minimum thickness of annular plates is usually greater than 0.1 inch; however, thicker values may be required forseismic reasons. (See API 653, Table 2-2 for minimum thicknesses.)

Section 3 - Brittle Fracture Considerations

This section provides a means of assessing an AST’s susceptibility to brittle fracture. Owner/operators must evaluate anychange of service (such as operation at a lower temperature) to determine if it increases the risk of failure due to brittlefracture. Industrial experience indicates the risk of brittle fracture is minimal if:• The shell is less than 1/2-inch thick;• The shell metal temperature is 60 degrees F or above;• The shell stresses are less than 7 ksi; or • The AST was hydrostatically tested at the lowest operating temperature.

The decision tree in API 653, Figure 3.1 helps determine susceptibility to brittle fracture.

Section 4 - Inspection

Three inspections are required:

1. Routine in-service inspection: This inspection must be performed monthly and can be performed by anyone. It includesa visual inspection of the AST’s exterior surface to check for leaks, shell distortions, settlement, corrosion, and anyother deleterious conditions.

2. Formal external inspection: This inspection must be performed at every five years of service or the quarter corrosion-rate life of the shell, whichever is less. (See checklist in API 653, Appendix C.) An API 653 certified inspector mustdo the inspection.

3. Formal internal inspection: The inspection interval is based on corrosion rates. The minimum thickness of the bottomplate at the next inspection cannot be less than 0.1 inch for ASTs without leak detection or leak containment and 0.05for ASTs with leak detection and leak containment or ASTs with reinforced linings greater than 0.05 inch thick inaccordance with API RP 652. An API 653 certified inspector must do the inspecting.

For each AST in service, the owner/operator must retain construction records, inspection history, and repair/alteration historyrecords, and the results of any material tests and analyses.

Inspectors must have the following education:

1. A degree in engineering plus one year’s experience.

2. A two-year certificate in engineering plus two years’ experience.

TA1000-1.WPFig. 1000-1 Synopsis API Standard 653, Edition 1, January 1991Tank Inspection, Repair, Alteration, and Reconstruction (1 of 2)


1000-4 March 1993

3. A high school diploma and three years’ experience.

Section 5 - Materials

All new materials used in repairs, alterations or reconstruction must conform to the current applicable standard. For recon-structed tanks, the material must be identified.

Section 6 - Design Considerations for Reconstructed Tanks

Reconstructed tanks are not common; therefore, this section is not included in this summary

Section 7 - Tank Repair and Alteration

The basis for repairs and alterations is equivalent to those in API 650. The minimum dimension of shell plate repairs is 12inches or 12 times the shell thickness, whichever is greater. Shell plates must be welded with complete penetration andcomplete fusion. Fillet-welded, lapped patches are not allowed. Details are given for shell penetration repairs/additions anddefective weld repairs.

Information about repairs for AST bottoms includes the critical zone. This area is defined as being within 12 inches of theshell or the inside edge of the annular plate where no welding or patching is allowed except for repairing widely scatteredpits or cracks. In the critical zone, defective areas must be replaced with new plate.

When replacing the AST’s bottom, a new bottom may be installed, separated from the old bottom with a non-corrosivematerial cushion. Consider providing a means of preventing galvanic corrosion. Shell penetrations may have to be raised.The old bottom may be removed.

Rules for repairing fixed roofs, self-supported roofs, and floating roofs are given.

Hot taps must be carried out in accordance with API 2201.

Section 8 - Dismantling and Reconstruction

This section provides procedures for dismantling and reconstructing existing welded ASTs that are to be relocated from theiroriginal site.

Section 9 - Welding

Welding procedures, welders, and operators are required or must be qualified in accordance with Section 9 of the ASMECode.

The weldability of the existing AST steel must be verified.

Welder’s identification mark must be hand- or machine stamped next to completed welds at three-foot intervals.

Section 10 - Examination and Testing

The methods of NDE for visual, magnetic particle, liquid penetrant, ultrasonic, and radiography must follow API 650 andthe supplemental requirements of API 653. Any welding on the shell-to-bottom joint must be inspected along its entire lengthby the vacuum box method. Rules for inspection of other repairs are given.

A full 24-hour hydrostatic test must be performed on reconstructed ASTs or any AST that has undergone major repairs oralterations, including:

• Shell penetrations larger than 12 inches• New bottoms• Repairs to the critical zone near the shell to bottom joint• Shell jacking

API 653, Section 10.3.2 gives cases where hydrostatic testing may be exempted.

AST settlement shall be surveyed before and after a hydrostatic test.

Section 11 - Marking and Recordkeeping

Reconstructed tanks must be identified by a nameplate with the information given in this section.

When an AST is evaluated, repaired, altered, or reconstructed in accordance with API 653, the owner/operator must retainthe following information as part of the records: calculations, construction and repair drawings, examinations, and test data.

API 653: AppendicesAppendix A – Background on Past Editions of API Welded Storage Tank StandardsAppendix B – Evaluation of Tank Bottom SettlementAppendix C – Checklists for Tank InspectionAppendix D – Reserved for Future MaterialAppendix E – Technical Inquiries

TA1000-1.WPFig. 1000-1 Synopsis API Standard 653, Edition 1, January 1991

Tank Inspection, Repair, Alteration, and Reconstruction (2 of 2)


March 1993 1000-5

Inspection Agencies

As API 653 was issued recently, there are few peopleexperienced in inspecting in-service ASTs. Theowner/operator may choose to contract this work or tohandle it within the Company. The considerations arecost (employee vs. contractor) and availability oftrained and experienced inspectors.

If the owner/operator chooses to select an in-house in-spector, that individual must have not only experiencein inspecting in-service ASTs but also the necessaryfreedom and authority to carry out the intended pur-pose of API 653.

1016 Recommended Implementation

We recommend implementing a program to ensure theintegrity of ASTs by complying with API 653 for thereasons stated above and also because most Opco’s:

• Take a highly responsible attitude towards environ-mental protection.

• Will want to comply with Company Policy 530,Operating Facilities – Safety, Fire, Health, and En-vironment.

1020 PREVENTING FAILURES:API 653

In API 653, there are three basic mechanisms to pre-vent potential AST failures:

1. Assessing suitability of service

2. Inspection

3. Repair and alteration guidelines

1030 ASSESSING SUITABILITY FORSERVICE

API 653 emphasizes that organizations that maintainor have access to engineering and inspection personneltechnically trained and experienced in tank design,fabrication, repairs, construction and inspection mustconduct AST evaluations. (See also API 653, Section 2,for rules governing AST evaluations.)

1031 Reasons for Assessing Suitability forService

Assessing suitability for service is generally requiredunder the following circumstances:

1. The results of an inspection show a physicalchange from the AST’s original condition.

2. The owner/operator believes it necessary or desir-able to change certain aspects of the service(whether or not a physical change has occurred).Examples of such changes include:

• Storing fluids that are incompatible with theAST’s construction materials (leading to pitting,unpredictable corrosion rates, stress corrosioncracking, etc.)

• Changing the density of the stored product

• Distortion of the AST’s shell, roof, or bottom

• A noticeable change or movement in shell dis-tortions

• A very high transfer rate of fluid into or out ofthe AST

• High, low, or varying service temperatures

• Locally thin areas in the shell

• The presence of cracks

• Brittle fracture considerations

• Foundation problems

1032 Physical Considerations

The physical conditions discussed in this subsection arebrittle fractures and AST components, including roof,shell, bottom, foundation; and design assessments.

Brittle Fractures

Brittle fractures often result in catastrophic failures be-cause the tear in the metal propagates at sonic speedsand travels through the material for great distances.These disasters occur in carbon steels at low ambienttemperatures and at relatively low stress levels.

There are three prerequisites for inducing brittle frac-tures:

1. Tensile stress must be at least 7 ksi, based uponempirical data.

2. Notches and other stress risers must be present.Examples are as follows:

• Improperly welded, temporary erection bracketsthat have been left in place


1000-6 March 1993

• Improperly repaired tears in shells resulting frominflicting hammer blows to remove erection gearthat was welded to the shell

• Deep undercutting and weld flaws in the ASTseams

• Stress concentrations resulting from improper re-pairs, such as square patches in the shell

• Unremoved arc strikes

• Improperly repaired cracked welds

3. Material toughness must be insufficient for the par-ticular service conditions of temperature, constraint,and loading rate.

It is important to evaluate any change in AST service toensure that it does not increase the risk of brittle fracture.Figure 1000-2 is a decision tree which can be used toevaluate this risk. An exemption curve for ASTs con-structed of unknown steels is shown in Figure 1000-3.See also the example in Figure 1000-4.

AST Components

The following AST components must be evaluated forsuitability for service: (See also 1051 Repairs of ASTComponents.)

AST Roof. API 653, Section 2, provides qualitativeguidelines for evaluating both fixed and floating ASTroofs. API 653, Section 7, offers quantitative guidelinesfor any repairs.

AST Shell. API 653 provides quantitative guidelines forpersonnel experienced in AST design to evaluate ASTshells. This experience is required as many of these de-cisions and procedures depend on good engineering judg-ment and a thorough understanding of the behavior ofmembrane structure. See Figure 1000-5 for an exampleof how to make a determination of shell thickness.

Note: Figures 1000-3 through 1000-5 appear onpages following.

AST Bottom. API 653 requires that essentially two majorfactors be considered in evaluating the bottom of an ASTfor suitability for service:

1. The AST must be inspected for conditions that areknown to cause bottom leakage or failure.

2. The actual thickness of the bottom, and annularplates, if applicable, must be determined.

AST Foundation. API 653 provides few quantitativeguidelines for evaluating an AST’s foundation for suit-ability for service. (See Section 1055 for more details onfoundation settlement and the need for repairs).

Design Assessment.

The design considerations in API 653, Section 6, applyequally to reconstructed ASTs and alterations to in-serv-ice ASTs. The following is a list of requirements of par-ticular importance that are not addressed elsewhere:

• The owner/operator should stipulate any specific de-sign considerations other than normal product loading.

• To prevent applying old and potentially inaccurate in-spection data, measurements should be taken within180 days of relocating or altering an AST to deter-mine the thickness which is to be applied to each shellcourse for checking the AST’s design.

• There are specific design considerations related toproduct height, test water level, corrosion allowance,joint efficiency, and allowable stress levels. (See API653, Section 6.4)

• ASTs altered by increasing their height may requireadditional wind stiffening.

• There are specific seismic design considerations. (SeeAPI 653, Section 6.8.)

1040 INSPECTION

There are several types of AST inspections:

1. Shop inspections of

• Shop-fabricated ASTs

• Portions of shop-fabricated, field-erected ASTs

2. Inspections of in-service ASTs which is the focus ofAPI 653 and this section of this manual.

3. Formal internal inspections of ASTs also covered byAPI 653 and this section. See Figures 1000-6, 1000-7, 1000-8, and 1000-9 respectively for checklists forthese types of inspections.

Note: Figures 1000-6 through 1000-9 appear atthe end of this Section.


March 1993 1000-7

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X46289.PLTTAM10003.GEM

Fig. 1000-3 Exemption Curve for Tanks Constructed of Carbon Steel of Unknown Toughness(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991. Reprinted Courtesy of the American Petroleum Institute)

The use of the decision tree format is illustrated by the following example.

A hypothetical tank was storing heated No. 6 Fuel Oil and now is being considered for ambient temperature storing aproduct with a specific gravity of 1.1. The tank is 180 feet-0 inches in diameter and 48 feet high. The tank was built ofA283-C shell plate material and is located in a regionwhere the lowest one-day mean low temperature is -15°F. The design metal temperature then is 0°F. A sketchof the tank, including the shell plate thicknesses, isshown in the figure to the right. No significant shell cor-rosion has been recorded. The tank was constructed priorto publication of the API 650, 7th Edition.

Each of the key steps in Figure 1000-2 is numbered cor-responding to the explanation provided. These explana-tions, together with comments pertaining to the tank inthe example, are given below.

1. These tanks meet the API Standard 650, 7th Editionor later, requirements to minimize the risk of failuredue to brittle fracture. Tanks may also be shown tomeet the toughness requirements of API Standard650, 7th Edition or later, by impact testing couponsamples from a representative number of shell plates.

TAM1000-4.WPFig. 1000-4 Example Illustrating Use of Figures 1000-2 and 1000-3 (1 of 3)

X46292.PLTTA1000-4.GEM

Tank: 180 Foot in Diameter,1.232 Inches Nominal PlateThickness First Course

EXAMPLE 1


March 1993 1000-9

This tank was constructed before the API 650, 7th Edition was issued and it exceeds the thickness limitations of thisstandard for A283-C material.

In order to justify using this tank under ambient conditions, one should make CVN impact tests on all shell platesover 1/2 inch thick. Also, since the heat affected zone of the vertical weld seams can have lower CVN impact valuesthan the parent metal, the vertical weld seams and the heat affected zone should also be impact tested. API 650 requiresimpact testing the heat affected zone of the vertical weld seams if they were welded using an automatic or semiauto-matic process. API 650 requires impact testing the heat affected zone of the vertical weld seams if they were weldedusing an automatic or semiautomatic process.

The tank shell material, the weld metal, and the heat affected zone should meet the acceptance requirements of API650, Table 2-2, at the design metal temperature 0°F.

CVN impact tests were run for the A283-C material. From these tests it was determined that the tank does not havethe required notch toughness at 0°F and further evaluation is required.

2. Many tanks that continue to operate successfully in the same service were not built to the requirements of API Standard650, 7th Edition or later. These tanks are potentially susceptible to failure due to brittle fracture and require an assess-ment as illustrated by the decision tree. (Figure 1000-2).

Since this tank may not remain in the same service, additional evaluation is required.

3. For the purposes of this assessment, hydrostatic testing demonstrates that an above ground atmospheric storage tankin a petroleum or chemical service is fit for continued service and at minimal risk of failure due to brittle fracture,provided that all governing requirements for repairs, alteration, reconstruction, or change in service are in accordancewith this standard (including a need for hydrostatic testing after major repairs, modifications, or reconstruction). Theeffectiveness of the hydrostatic test in demonstrating fitness for continued service is shown by industry experience.

The records indicate the tank was originally hydrotested.

The original hydrotest loading will tend to blunt any pre-existing crack tips and greatly reduce the changes of a brittlefracture. In this case however, the product to be stored has a higher specific gravity; therefore the original hydrotestwill not stress the tank to the same degree as the product. The blunting of any previous cracks by the hydrotest maynot be sufficient to overcome the effect of the additional stresses imposed by the the more dense product.

A possible solution is to lower the product level sufficiently so that the tensile hoop stresses at the tank bottom donot exceed the hoop stresses from the hydrostatic test.

Consideration should be given to tank shell settlements and foundation erosion which can impose additional tensileforces in the hoop direction at the base of the tank. These additional forces, together with the liquid head forces, cancreate very high tensile forces, which at the lower operating temperature could precipitate a brittle fracture at somedefect.

4. If a tank shell thickness is no greater than 0.5 inches, the risk of failure due to brittle fracture is minimal, providedthat an evaluation for suitability of service per Section 2 has been performed. The original nominal thickness for thethickest tank shell plate shall be used for this assessment.

Thinner plates generally have better impact properties than thicker plates. In this case the shell plate exceeds 0.5 inchesand this exemption does not apply.

5. No known tank failures due to brittle fracture has occurred at shell metal temperatures of 60°F or above. Similarassurance against brittle fracture can be gained by increasing the metal temperature by heating the tank contents.

Heating the tank contents is an expensive option in this case, requiring heater and insulation. The Company has de-termined heating to be not economically practical.

6. Industry experience and laboratory tests have shown that a membrane stress in tank shell plates of at least 7 ksi isrequired to cause failure due to brittle fracture.

In this example, the design stress is 21,000 psi, so this exemption does not apply, unless one were to drop the operatinglevel to 14 ft-6 inches. This would lower the tensile hoop stresses to 7,000 psi for the product density of 1.1.

TAM1000-4.WPFig. 1000-4 Example Illustrating Use of Figures 1000-2 and 1000-3 (2 of 3)

EXAMPLE 1 (Continued)


1000-10 March 1993

TAM10004.WP

7. Tanks constructed from steels listed in Figure 2-1 of API Standard 650 can be used in accordance with their exemptioncurves, provided that an evaluation for suitability of service per Section 2 of this standard has been performed. Tanksfabricated from steels of unknown toughness thicker than 1/2 inch and operating at a shell metal temperature below600°F can be used if the tank meets the requirements of Figure 3-2. The original nominal thickness for the thickest tankshell plate shall be used for the assessment. For unheated tanks, the shell metal temperature shall be the design metaltemperature as defined in 2.2.2.9.3 of API Standard 650.

The tank material in this example does not meet the exemptions of API 650. Under no circumstances can GroupI materials, such as A283-C, be used at a design metal temperatures less than 100°F, without impact testing. Also themaximum thickness limitation for Group I materials is one-inch. In this example, the lower two shell courses are overone-inch thick.

The combination of the design temperature and the plate thickness places this tank in the additional assessment requiredregion of the API 653 impact testing exemption curves, Figure 1000-03.

8. The risk of failure due to brittle fracture is minimal once a tank has demonstrated that it can operate at a specifiedmaximum liquid level at the lowest expected temperature without failing. For the purpose of this assessment, lowestexpected temperature is defined as the lowest one-day mean temperature as shown in Figure 2-2 of API Standard 650for the continental United States. It is necessary to check tank log records and meteorological records to ensure that thetank had operated at the specified maximum liquid level when the one-day mean temperature was as low as shown inFigure 2-2 of API Standard 650.

This tank is to operate at lower temperatures and store products of higher specific gravity so additional considerationsare necessary.

9. An evaluation can be performed to establish a safe operating envelope for a tank based on the past operating history.This evaluation shall be based on the most severe combination of temperature and liquid level experienced by the tankduring its life. The evaluation may show that the tank needs to be re-rated or operated differently; several options exist:

a. Restrict the liquid level

b. Restrict the minimum metal temperature

c. Change the service to a stored product with a lower specific gravity.

d. Combinations of a, b, and c above.

The Company can also make a more rigorous analysis to determine the risk of failure due to brittle fracture by performinga fracture mechanics analysis based upon established principles and practices. The procedures and acceptance criteria forconducting an alternative analysis are not included in this standard.

In the case being considered, past operating history does not provide any assurance against brittle fracture. Dropping theoperating level will not satisfy the requirements of API 653 unless the product level is reduced to 14 feet-6 inches whichwill reduce the maximum tensile stresses to 7,000 psi.

If this tank is to operate under the proposed product density and temperature, a more rigorous analysis is required, suchas fracture mechanics. Consult CRTC for any cases involving fracture mechanics or other, more rigorous analyses.

The more rigorous fracture mechanics evaluation may indicate that the tank can operate at the lower temperature. How-ever, if any repairs or alterations are required, they must conform to API 653 before the tank can be put into the moresevere service conditions.

10. An assessment shall be made to determine if the change in service places the tank at greater risk of failure due to brittlefracture. The service can be considered more severe and creating a greater risk of brittle fracture if the service temperatureis reduced (for example, changing from heated oil service to ambient temperature product), or the product is changedto one with a greater specific gravity and thus increasing stresses.

Since this tank is to store product with a higher specific gravity and at ambient temperature, it is being considered fora more severe service. This places the tank at a greater risk of failure due to brittle fracture and further assessment isrequired.

TAM1000-4 WP

Fig. 1000-4 Example Illustrating Use of Figures 1000-2 and 1000-3 (3 of 3)



March 1993 1000-11

X46293.PLTTA10005A.GEM

X46294.PLTTA10005B.GEM

API 653 provides quantitative guidelines for evaluating the shells of tanks and further requires that such evaluation beconducted by personnel experienced in tank design. This experience requirement is based on the fact that many of thedecisions and procedures described in API 653 in this regard require good engineering judgment and a thorough under-standing of membrane structure behavior.

Corrosion will vary in severity and extent from tank to tank, depending on product, age, service, and environmental condi-tions, and many other factors. Recognizing this fact—coupled with the fact that the Standard requires experienced andqualified inspectors—the intent of API 653 is to allow the inspector sufficient latitude to evaluate the corrosion on a casebasis, and not to apply specific rules, in terms of numbers and locations of measurements, which may not be appropriatefor all cases.

In evaluating the tank shell for suitability for service, onemust first determine the actual thicknesses. Two “actualthicknesses,” t1 and t2, are calculated for comparison tothe minimum calculated required thicknesses. The actualthickness determination is made from a grid applied tothe corroded area in accordance with Figure 1000-5A.

By reference to Figure 1000-5C, API 653 allows the in-spector to first determine t2, the least minimum thicknessin the corroded area, by any means deemed appropriateby the inspector. This might be strategically placed UTreadings located by visual observation, or by more so-phisticated mapping techniques.

Once t2 is established, L can be calculated.

One procedure for determination of the actual thickness,including the placement of L is as follows:

It is important to recognize that neither API 653 nor thefollowing procedure can address every individual case.The following are minimum requirements which shouldbe supplemented by the individual inspector with addi-tional inspection as the circumstances dictate.

1. Visually observe each shell plate in every shellcourse to identity any areas of obvious corrosion. Ar-eas of particular concern include the first shell courseimmediately above the bottom plate, heat affectedzones adjacent to welds, and long term liquid-vaportransition zones.

2. Measure and record the thicknesses at the cornersand midspan edge of each plate in accordance withFigure 1000-5B. For tanks in which there are no cor-roded areas of considerable size, and for tanks inwhich the shell corrosion is uniform over the entireshell surface, the least of the thicknesses measured ineach course represents the minimum thickness forthat course.

3. If corroded areas of considerable size are obvious byvisual observation, the area must be evaluated in ac-cordance with API 653, Section 2.3.2. This is doneby “mapping” the area with five plane lines as shownin Figures 1000-5A and 1000-5C.

TAM10005.WPFig. 1000-5 Example Illustrating Use of API 653, Figure 2-1 (1 of 2)

EXAMPLE 2

Fig. 1000-5A Determining Minimum WallThickness in Thinnest Shell Area

Fig. 1000-5B Spot Checking Plates for Thickness


1000-12 March 1993

4. A minimum of 25 measurements should be takenin each corroded area of considerable size to es-tablish t2. It is not necessary to record the locationsof these readings, but the inspector should usegood judgment in selecting the locations for thesemeasurements in order to develop a representativemap of the corroded area.

5. Once t2 is established, L can be calculated.

6. Having established t2 and calculated L, the inspec-tor will then determine visually or otherwise whichone, or more, of five vertical planes in the area islikely to be most affected by corrosion. A mini-mum of five profile measurements shall be madeover the length L on the plane(s) determined to bemost affected by corrosion. The lowest averagethickness from the sets of profile measurements foreach affected plane is t7.

7. In placing L, it is important to recognize that L isnot “fixed” at a particular location, but rather is“movable” and should be located based on thejudgment of the inspector. In practice, the inspectorshould locate L by visually determining whichplane and which part of the plane “looks the worst”. If this is not obvious, he may elect to try different placements ofL over one or more planes. Note that t2 need not be located directly on a plane line, as shown in Figures 1000-5A and1000-5C.

8. t1 and t2 shall be recorded for each shell course for subsequent comparison to the minimum permitted values determinedby calculation.

The following example illustrates the above steps.

1. Figure C shows an area of corrosion visually observed in the first shell course of a 180-foot diameter tank with anominal first course thickness of 1.232 inches.

2. For the purposes of this example, corner and midspan edge thicknesses do not control.

3. The area is mapped with five vertical plane lines as shown in Figure 1000-5A.

4. t2, the minimum of 25 angle beam ultrasonic thickness measurements, is 1.11 inches.

5. L = 3.7 √Dt2 = 52.3 inches.

6. The Inspector determines that vertical plane lines c and d are the planes likely to be most affected by corrosion. Thefive thicknesses measured along length L for planes c and d are:

For plane c: 1.07, 1.19, 1.10, 1.04, and 1.20 inches. Average thickness = 1.12 inches.

For plane d: 1.20, 1.17, 1.05, 1.12, and 1.16 inches. Average thickness = 1.14 inches.

The lowest average thickness, t1, from plane c, is 1.12 inches.

7. The location of t2 for this case is not located on a vertical plane line.

8. Record t2 = 1.11 inches and tl = 1.12 inches for comparison to calculated minimum permitted values.

API 653 permits a design by formula or an alternative design by analysis to calculate the minimum required thickness forbutt welded tanks.

TAM10005.WPFig. 1000-5 Example Illustrating Use of API 653, Figure 2-1 (2 of 2)


X46295.PLTTA10005C.GEM

Fig. 1000-5C Determining Minimum Wall Thickness


March 1993 1000-13

1041 Inspection Philosophy

The philosophy of API 653 is that the owner/operatorconduct a thorough initial inspection of each AST toestablish a baseline. Future inspections are comparedto the baseline to determine either the rate of corrosionor those changes that might affect the AST’s suitabilityfor service. The owner/operator also observes physicalchanges and rates of change over a specified period.From this data, an experienced AST engineer judgesthe AST’s suitability for continued service or its needof repair.

For new construction: The Company inspects anAST from fabrication to the end of its service life.

For field-erected ASTs: Fabrication inspections helpto avoid delays caused by delivery of faulty material atthe erection site.

For shop-fabricated ASTs: Inspection assures compli-ance with design and material specifications.

1042 Three Types of Periodic Inspections

To ensure that the AST bottoms and shells have neitherexisting nor potential leaks or failures before the next in-spection, API 653 requires three different types of peri-odic inspections, as described below:

1. Routine In-Service Inspection

Description: A visual inspection to determine if therehas been a change since the previous routine inspec-tion; includes such observations as shell buckling,leaks, foundation problems, settlement. We recom-mend adopting a form similar to Figure 1000-10 forthis inspection.

Inspector: AST operator or someone who does nothave to meet the strict qualification requirements forthe formal inspections in Section 1043 – InspectionPersonnel Requirements.

Frequency: Once per month

2. Formal In-Service Inspection

Description: Examine all parts of an AST accessi-ble without removing it from service. (See API653, Appendix C, for a checklist of the details forthis level of inspection.)

Inspector: Qualified personnel. (See “API 653 Inspec-tion Personnel Requirements” later in this section.)

Frequency: At the quarter corrosion-life of the shellor every five years, whichever is less.

3. Formal Internal Inspection

This level of inspection represents a major change tothe practices of most owner/operators.

Description: Examine an AST after it is removedfrom service and prepared to all the inspection agencysafe entry. This is usually a costly and inconvenientaspect of the program but API 653 states that it isrequired to ensure that the bottom is not severely cor-roded and leaking, to gather the data necessary forthe minimum bottom and shell thickness assessments,and to assure that the AST will not fail during thenext in service run. [1]

Inspector: Qualified personnel. (See “API 653 Inspec-tion Personnel Requirements” later in this section.)

Frequency: Governed by the minimum thickness ofthe bottom. Both topside and bottom-side corrosion

DateFacility or LocationTank Number

ConditionYes

/ No *Comments and

Location

Berm erosion NoStanding water NoProduct leaks NoShell distortion NoShell settlement NoPaint problems NoCorrosion NoFoundation damage NoInsulation damage NoFaulty level gage NoOther faulty gage NoOther No* If a change has occurred since the last monthly

inspection, note a Yes or No in this column and entera description of the problem, the location, and the natureof the change.

TA100010.WP

Fig. 1000-10 Monthly Inspection Form


1000-14 March 1993

are considered. The time interval is complete whenthe bottom reaches a computed minimum thicknessshown in Figure 1000-11. In no case, however, isthe interval allowed to exceed 20 years.

1043 General Requirements forPost-installation Inspections

After the AST is installed, the Company should con-duct regular in-service and internal inspections, follow-ing the principles of API 653, and should use the datacollected to:

• Determine if the AST is suitable for continuedservice.

• Reduce the possibility of leaks and spills enteringthe environment while the AST is in service anduntil the next scheduled internal inspection.

• Plan preventive maintenance for the AST.

• Compare the history of each AST with others insimilar service.

• Develop a baseline of data to assist in conductingan engineering evaluation of the AST’s present con-dition and in projecting its future condition.

• Make wise, long-range decisions.

• Schedule future inspections.

Although many consider API 653 to be primarily aninspection standard applicable to in-service ASTs, thiscomprehensive document helps owner/operators deter-mine each AST’s suitability for service. Inspection,however, is a major part of the standard. In essence,the inspector is making a judgment that the AST issuitable for service and unlikely to fail until at leastthe required inspection deadline.

The following paragraphs highlight API 653’s inspec-tion requirements, and this standard’s impact on cur-rent industrial practices.

API 653 Compared to Current Inspection Programs

Those operating facilities that have AST inspectionprograms should compare their programs to API 653to ensure that they meet the minimum requirements ofAPI 653, especially in terms of:

• Evaluating ASTs for suitability for service

• Reviewing concerns for brittle fracture

• Conducting engineering evaluations of any ASTthat shows non-compliance in such areas as exces-sive settlement.

API 653 strongly emphasizes effective inspection tech-niques; yet, this standard was designed for practical ap-plication: to perform inspections and implementimprovements while minimizing service interruptions.

Inspection Records: API 653, Section 4.10, requiresthat the owner/operator maintain a complete set of re-cords, including:

• Construction records — nameplate information,drawings, specifications, completion reports, mate-rial tests, etc.

• Inspection history — measurements, condition ofparts inspected, examinations and tests, descrip-tions, corrosion rates, and inspection interval ratecalculations.

• Repair/Alteration history — any repairs, alterations,replacements, and service changes.

Federal EPA Regulations, 40 CFR 112.7 (e), requirefiling the AST’s inspection report with the SPCC Planat the facility/terminal. As the EPA and each of thestates adopt API 653, owner/operators will be requiredto satisfy the record keeping requirements of API 653and to keep those records reasonably accessible to thesubject facility/terminal.

Several prepackaged computer programs store newconstruction data along with the inspection report data;but, at present, these programs can store neither inspec-tion reports with the AST data nor calculate corrosionrates with predicted new inspection dates.

Inspection Reports: Inspection reports must include,as a minimum:

Computed MinimumThickness at theNext Inspection AST Bottom Design

0.1" No Leak Detectionor Containment ofBottom

0.05" With Leak Detectionand/or ContainmentOR With ReinforcedLining > 0.05"

TA100011.WP

Fig. 1000-11 Internal Inspections Based on AST’sBottom Thickness at Next Inspection


March 1993 1000-15

• Any metal-thickness measurements

• Conditions found for applicable components listed onthe Inspection Checklist (see API 653, Appendix C orFigures 1000-6 through 1000-9).

• Description of any previous repairs or alterationsfound during the inspection

• Any elevation readings taken

• Settlement evaluation (if previous elevation readingsare available)

• Recommendations for repairs and/or alterations, if re-quired

Additionally, if repairs or alterations are recommended,the report must also include:

• Reasons for the repairs or alterations or both

• Sketches showing the location and extent of recom-mended repairs or alterations or both

Inspection reports become part of the owner’s permanentrecords and should be written appropriately for review byregulatory authorities.

AST Files: Each AST should have a file associated withit including:

• All previous inspection reports

• Contract face sheets, authorizations, charges, specifi-cation, and work lists

• Thickness-gaging records and calculation printouts

• Swingline ballasting information (ballast calculations,drawings with dimension, etc)

• Bills of material for special or unusual materials orequipment incorporated into the AST

• Air Quality Management District calculations andpermit applications

• Work lists and work requisitions of permanent work

• Data sheets on operating levels, such as safe oilheights, low pump outs, hold-off distances, etc.

• Construction drawings or references to where draw-ings can be found

• Photographs and dimension of internals that are notavailable while the AST is in service

Inspection Checklists: API 653, Appendix C providescomplete checklists for in-service and internal inspec-tions. These checklists are reproduced at the end of thissection as Figures 1000-8 and 1000-9.

Inspection Personnel Requirements: API 653 specifiesthat qualified inspection personnel or agencies (eithercontractor or owner/operator employees) must carry outinspections. The qualified inspector must meet certaineducation and experience requirements:

• An engineering degree plus one year’s experience inAST inspection.

• A two-year certificate in engineering (or equivalent)and two years’ experience.

• A high school education and three years’ experience.

All inspectors must be API certified.

The inspector gathering the data should be certified tomeet the requirements in the Society of NondestructiveTesting Technical Council, Document 1A, 1988 edition.The inspector actually responsible for the inspectionshould meet the requirements in API 653.

1044 Inspection Methods

All inspection methods have one goal: to define the pre-sent physical condition of the AST. They range from thesight and touch of an experienced person to state-of-the-art technologies; and a combination of methods and toolsis necessary to carry out a complete inspection.

Note: Many techniques for inspecting AST bottomsmay also be applied to roof and shell plates.

Since every method has advantages and limitations, thecondition of the AST and the objective of the inspectionare two main factors in selecting the appropriate tech-nique. For instance, if the AST is in fairly good conditionand should be returned to service as soon as possible, theowner/operator may elect to use magnetic flux leakageequipment for inspecting the bottom and manual ultra-sonic testing for spot checking the shell and the roof.

Minimum Testing for General Inspections: The follow-ing tests are the recommended minimum for general in-spections:

• Formal external inspection:

– Visual

– Straight Beam Ultrasonic


1000-16 March 1993

•F

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TA1

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Tank M

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March 1993

1000-17

1045 Typical AST Bottom InspectionTechniques

AST bottom integrity and leak prevention is probablythe single, most important issue facing the majority ofAST facility owner/operators who are consideringcompliance with API 653.

Bottom-assessment difficulties have led manyowner/operators to ignore this item unless there is evi-dence of a leak. API 653, however, states that leaks intank bottoms are not acceptable while tanks are in-service and also requests that, when replacing anAST’s bottom, the owner/operator consider installing aleak-detection system.

API has intentionally made allowances for improvingtechnology or advanced inspection practices to increasethe basic inspection intervals if the owner/operator hasother means of determining suitability for service. Inno case, however, is the interval allowed to exceed 20years.

The owner/operator must conduct a quantitative evalu-ation of the AST’s bottom plates to determine the cor-rosion allowance, corrosion rate, and internalinspection intervals required by API 653. When thecorrosion rates are unknown and records of similarservice experience are unavailable, the maximum inter-val between internal inspections is decreased from 20years to a maximum of 10 years.

The underside of AST bottoms that rest on pads or onthe soil cannot be inspected readily from the outsidefor corrosion or other damage; however, there are sev-eral methods practiced:

Tunneling

When the AST is empty, a tunnel may be cut under itbut only near the edge as it is difficult to refill a tunnelproperly. Clean sand or crushed limestone are the besttypes of fill material for tunnels. Coupon cutting, dis-cussed later in this section, is safer and usually aquicker method of inspection.

Damming

The following methods are used very infrequently andmay require hydrostatic testing of the AST after in-spection. In each case, a temporary clay dam or sealis placed around the base outside the AST. Going overthe entire bottom of the AST with an air-operated ham-mer improves the effectiveness of these methods. Thesharp jarring of the bottom plates frequently causessufficient scale to pop out of pits to make them leak

detectably. Seek guidance by consulting with CRTCpersonnel and with contractors experienced in thesemethods.

Soap Solution. The inside surface of the AST’s bottomis coated with soap solution; a hose applies air pressure(less than three inches of water) under the bottom ofthe AST through the clay seal or through a drilled andtapped hole (or holes) in the bottom. The bottom isthen inspected for soap bubbles that indicate leaks.

Water Leaks. Water is pumped under the AST (heldby the clay dam) to a depth of approximately sixinches above the level of the highest point of theAST’s bottom. Vents are required to allow trapped airto escape. Leaks are then evident if the water seepsthrough to the inside of the AST. This approach cancause the AST’s pad to wash out or shift, dependingon its construction. To build the air pressure to the de-sired value may involve considerable plastering of theclay seal.

Water In/Air Under. Approximately six inches ofwater are pumped into the AST, and nine inches wcof air are pumped under the AST. (The water must bepumped into the AST before applying air pressure un-der the AST.) Leaks are identified by air bubblingthrough the water in the AST.

Hammer Testing

Usually, the hammer is a brass ballpeen that weighs 16to 18 ounces. When an experienced inspector wields ahammer to strike the steel, the sound, vibration, dent-ing, and movement produced can reveal such defectsas reduced thickness in the AST walls, loose joints,and intergranular cracking. Primarily a means for ex-amining the interior of the AST’s bottom and the ex-terior chime area, hammer testing is usually useful onlyfor determining gross flaws and imminent failure as ithas many limitations:

• Only a small fraction of the bottom surface can betested, therefore, many areas can and are missed.

• Hammer testing should not be performed on certainmaterials, as damage may result:

– Enameled, ceramic, or glass-lined ASTs,where the lining may be damaged by thehammer.

– Equipment storing caustics, even if stress-re-lieved, as stress-corrosion cracks have beenfound at hammer marks in such equipment,regardless if hammered from the outside.


1000-18 March 1993

– Nipples and small piping that may crack whenrigidly supported and struck too vigorously.

– Brittle materials, such as cast iron, some highalloys of steel, and some nonferrous materials,such as brass and bronze: light tapping with ahammer may be permissible on some of thesematerials.

– Equipment containing toxic or combustiblematerials under pressure.

– Other materials where hammering might resultin stress corrosion or cracking.

• Hammer testing should be used with visual inspectionto complete a first inspection of the AST bottom.

• Hammer testing should be considered as a first lineof defense to focus on areas that may be nearingfailure.

Follow-up techniques, coupon cutting, ultrasonic test-ing, and radiography are necessary to complete a thor-ough inspection job. Radiography is impossible unlessthere is access to the underside of the AST.

If hammering reveals defects, perform verification test-ing in these areas using ultrasonic, vacuum box, or ra-diographic methods (if possible).

Advantages: Hammering is a simple, inexpensive, andeffective tool for identifying defects in steel ASTs.

Disadvantages: Hammering is a subjective, acquiredskill rather than an objective, easily defined test pro-cedure, and hence is subject to human error.

Vacuum Testing

The vacuum box has an open bottom covered with arubber gasket and a clear-glass top. A vacuum gageand connection are installed through the side of thebox. (See diagram Figure 1000-13.) The seam or sur-face of the AST’s shell is first wetted with a soap so-lution, then the vacuum box is pressed tightly over thearea to be tested. The gasket forms a seal; and a vac-uum pump or air ejector, connected to the box by ahose, allows a vacuum to be maintained inside the box.Leaks appear as soap bubbles to those looking throughthe glass top of the vacuum box.

Precautionary Note: Recent experience has shown thattraditional vacuum pressures of 2 psi below atmos-pheric pressure are insufficient to detect leaking, low-surface-tension, mobile liquids such as MTBE. It isrecommended that the vacuum box pressures be in-creased to at least 10 psi below atmospheric pressure

to reduce the possibility of leaks occurring throughminute fissures in the weld seams.

The vacuum box test is a simple procedure that re-quires very little training and can detect three types ofdefects:

• Leaks in seams or welds

• Small pinpoint leaks in pitted areas

• Intergranular corrosion which occurs in the grainstructure of steel and can result in the steel’s actu-ally becoming porous even though it does not ap-pear corroded. (Intergranular corrosion typically isa phenomenon of ASTs in the chemical industry.)

Vacuum testing may be used on welds in the bottom,floating roof, and floating roof pontoons during newconstruction, post-repair, and general surveillance in-spections. API 653 requires this test on the shell-to-bottom weld and on the bottom-plate-weld seams. Thismethod is good for determining pinhole leaks. How-ever, it cannot find poor welding problems such as

X46369.PLTTA100013.GEMFig. 1000-13 Vacuum Box


March 1993 1000-19

cracks, lack of fusion, and other defects that do notproduce leaking.

Coupon Cutting

When underside corrosion is suspected (as indicated byother tests, such as hammering or ultrasonic), or whenaccurate checks are desirable, cut at least 12-inch-di-ameter representative sections, otherwise known ascoupons, from the bottom plate. These coupons arecleaned and then may be inspected in detail for corro-sion or other defects, including inspection under labo-ratory conditions by a qualified metallurgist.

API 653, Section 7, details methods for removingspecimens and repairing holes. We recommend that re-pairs be made in accordance with Figure 1000-14 toareas of AST bottoms from which coupons were re-moved.

Advantages: The advantage of using coupons is thata complete visual picture of the bottom side is avail-able for study. The pH, presence of moisture and set-tlement can also be examined.

Disadvantages: The disadvantage of this method is thatit is a destructive testing method.

Magnetic-flux Exclusion Test

Magnetic-flux exclusion is a relatively new, generalsurveillance inspection method that the oil industry is

accepting rapidly. Magnetic-flux exclusion testing as-sesses pitting corrosion and other defects on the under-side and topside of AST bottoms. This test will seeapproximately 95 percent of the bottom compared tothe 10 percent to 25 percent for the grid techniques ofhammer testing, coupon cutting, or ultrasonic testing.It must, however, be followed by ultrasonic tests onidentified pits to obtain a comprehensive view of thephysical condition of the bottom.

For this method, the AST must be taken out of service,emptied, and the floor cleaned of loose scale, dirt, andoil. Broom cleaning of the AST bottom may be ade-quate; but, where layers of corrosion and flakes ofscale and corrosion exist, hydroblast cleaning of thesurface is preferred as loose scale gives false readings.

Magnetic-flux exclusion is a form of eddy current test-ing that uses Hall Effect sensors to detect the changesin the magnetic flux field of the floor plate. Thismethod is a very useful qualitative test that detects pit-ting on both sides of the plate but detects neither gentlychanging thicknesses nor flaws at the lap joint welds.This method will read through thin film coatings thatare in good condition.

Magnetic-flux exclusion is highly recommended as ageneral qualitative inspection tool. Results are more re-liable than a statistical grid pattern which is safe forinspecting a fairly new bottom, but can be misleadingfor a bottom that is nearing the end of its useful life.For example, an AST was considered liquid tight aftera grid pattern inspection. A trial of the magnetic-fluxexclusion was run on this AST and revealed three pinholes, each one nearly 1/32 of an inch in diameter.Note: An AST with 30 feet of liquid can lose nearly600 gallons a day through one 1/16-inch hole.

The cost of magnetic flux exclusion testing is about$300 per hour. The total cost of testing is dependentupon the size of the AST and the extent of defects.

Advantages: Magnetic-flux exclusion testing is rapidand scans the entire AST bottom, rather than just por-tions of the AST.

Disadvantages: Magnetic-flux exclusion equipment isheavy and cumbersome; ultrasonic confirmation is re-quired in the areas where anomalies in the magneticfield indicate that defects may be present.

X46278.PLTTA100014.GEM

Fig. 1000-14 Patching Areas in Existing Bottoms


1000-20 March 1993

1046 Other Inspection Methods and Tools

Visual Examination

Visual examination is one of the most important, basic,and indispensable testing methods available to the in-spector and is conducted on all new construction andfor routine and repair related inspections. The inspectorusually has a portable set of tools to assist with thevisual examination: mirrors, magnifying glasses, scrap-ers, hammers, probes, and measuring tools. (See Figure1000-15.) The visual method requires that an experi-enced inspector locate problems quickly then chooseand apply the best method(s) to define more clearly thephysical condition of the problems.

The following inspection techniques are not recom-mended:

• Not recommended for visual inspections of theAST’s bottom underside: Raising the AST on airbags and with timber blocking.

• Not recommended for the internal inspection ofthe AST bottom: Floating the entire AST on waterand then going inside to look for leaks (the floattest).

Air Testing

New or altered nozzle reinforcement pad welds aretested by applying air pressure of up to 7 psig to thereinforcement pad or other enclosed area. The weldsare brushed with a soap solution, and the resulting bub-bling indicates the flawed weld areas. For this test, thereinforcing pad must have a drilled and tapped NPThole.

Dye Penetrant

The penetrant dye (such as Zyglo or Dychex) isbrushed or sprayed on a cleaned and dried surface.After approximately five minutes of contact time, thedye is cleaned off; and a chemical developer (thatgives a white appearance when dry) is sprayed on thesurface. Through its absorptive nature and by capillaryaction, the developer draws the dye out of the irregu-larities and exposes defects.

Penetrant dyes are applied to new and repaired weldsand to check root passes. In AST shells, penetrant dyescan also detect surface cracks that are not apparent byvisual inspection. This method also is a useful for in-specting piping, welds, or nozzle/shell connections.

Advantages: The dye-penetrant method provides notonly a clear, visible clue to potential problems but alsoeasily interpreted test results.

Disadvantages: The dye-penetrant method is highly laborintensive, requiring very clean surfaces; does not revealsubsurface defects; and will not reveal lamination and po-rosity unless the edge of the plate is examined.

Magnetic-particle Testing

The magnetic-particle method is based on the principlethat a change in the material’s continuity distorts anymagnetic lines of force present in a ferromagnetic ma-terial, such as a sharp dimensional change or a discon-tinuity.

Magnetic-particle testing primarily detects surface ornear-surface defects in magnetic materials. The area tobe inspected is first wirebrushed vigorously, sand-blasted, and cleaned of oily residues; then it is mag-netized. Magnetic-particle powders are applied invarious contrasting colors to spotlight defects.

If the discontinuity is at or close to the surface of amagnetized material, flux lines are distorted at the sur-face, a condition that is termed flux leakage. When finemagnetic particles are distributed over the area of thediscontinuity where the flux leakage exists, they are

Useful hand tools include:

• Sliver — broken hacksaw blade, to pry into lap joints,cracks or corrosion craters where dirt and scale obscurevision.

• Scraper — chisel, for scraping dirt and scale.

• Digger — a combination hammer and chisel to peck atscale, or to sound objects; the chisel end can be usedas a scraper.

• Mirrors and Reflectors — for viewing hidden surfaces.

• Magnifiers — for finding small, difficult-to-detectdefects.

• Lights — spark-proof.

• Internal Visual Scope — for providing a 360° view ofinternal surfaces such as pipes.

• Binoculars — for more careful observation of inacces-sible points.

• Hammer — for tapping metal surfaces; sound variationsmay indicate corrosion weakness.

• Calipers — for measuring plates or openings.TA100015.WP

Fig. 1000-15 Aboveground Tank Inspection Tools


March 1993 1000-21

held in place. The accumulation of particles is visibleunder proper lighting, thus highlighting the area of thediscontinuity. If a discontinuity is exposed to the sur-face, the flux leakage is a maximum for a given sizeand shape of discontinuity. When a discontinuity is be-low the surface, flux leakage diminishes; therefore, dis-continuities must be open to the surface or in the nearsubsurface to create flux leakage of sufficient strengthto accumulate magnetic particles.

The type of defect can be determined from the shapeof the accumulated magnetic powder. Surface cracksare indicated by a fine line of accumulated powderalong the crack.

Subsurface cracks or incomplete weld penetration areindicated by a coarser or broader line of accumulatedpowder. Cracks are not indicated if they are parallel tothe magnetic lines, therefore, it is necessary to vary thedirection of magnetism. This method causes a residualmagnetization undesirable for some equipment and,therefore, requires demagnetization.

A number of different types of magnetic-particle in-spection machines are available. Selection of a specifictype depends on the intended application, the type andmagnitude of the magnetizing current required, and thedesired level of productivity. The magnetic powdermay be obtained in various colors and should be se-lected to contrast with the article that is being in-spected. For a critical inspection, a fluorescent powdermay be chosen and is usually applied as a liquid sus-pension; however, a darkened area and ultraviolet lightis needed to interpret the results.

Post-inspection cleaning follows magnetic-particle test-ing and may include:,

• Blowing off dry magnetic particles with com-pressed air

• Drying wet particles and removing them by brush-ing or with compressed air

• Removing wet particles by flushing with solvent

Advantages: Magnetic-particle testing is simple andeconomical.

Disadvantages: Magnetic-particle testing works onlyon materials that can be magnetized, can only detectsurface and near-surface discontinuities, and does notreveal the depth of a defect.

Ultrasonic Testing

Ultrasonic testing is a powerful method of determiningthe thickness of a corroded plate. Ultrasonics is asound wave that can propagate through most materialsat very high frequencies. The piezoelectric effect of acrystal in a transducer converts electrical pulses intomechanical sound waves. Electronic instrumentationthen captures the return sound wave to determine thedepth. To calibrate the instrument, readings are takenof standard thicknesses of gage blocks. Two differentinstruments have been developed to use this ultrasonicpulse-echo technique: the straight beam and the shearwave.

The Straight Beam: During the general surveillanceinspection, the straight-beam ultrasonic test can beused on all plates. For specific areas, this test can con-firm and enhance the results of other broad-scope sur-vey methods. When tracking the general corrosion rate,a minimum of six easily identifiable points per plate isrecommended.

The straight-beam instrument determines the results ofa plate’s general corrosion. It finds the depth of thefirst flaw (which could be a lamination or carbon in-clusion) or the opposite surface. This instrument is ex-cellent for monitoring the remaining thickness of aplate and the depth of a pit. This instrument takes asingle point reading and requires a clean first surfacecontact. Readings are taken on a grid pattern or atproblem areas already identified by other methods.

The straight-beam instrument has been added to a re-mote operated crawler to increase the usefulness of ul-trasonic testing on shell, roof, and bottom plates. Theshots this instrument takes are still single points andrequire a reasonably smooth surface. The instrumentcannot take shots on the weld lines. Continuing devel-opments of the crawlers will produce a machine thatwill take a continuous strip of shots across a plate ex-cept at a weld.

The Shear Wave: The shear wave (or angle beam)test is normally used on welds during new constructionor on weld repairs.

The shear-wave instrument detects stress-inducedcracks that are always perpendicular to the surface.This instrument needs a skillful operator and is cali-brated from standardized reference material. In shear-wave examination, the sound wave enters the materialor weld at a known angle.

While the capital cost of an instrument is probablysomewhat unimportant since the operator usually owns


1000-22 March 1993

his own, an ultrasonic thickness gage costs about$2500. The capital cost for an ultrasonic analysis in-strument is about $6000. The cost for an operator isabout $300 to $400 per day.

Advantages: Ultrasonic gaging can find surface orbacksurface discontinuities.

Disadvantages:

• Ultrasonic gaging tests only portions of the AST,and a statistical evaluation assesses the integrity ofthe entire AST; and

• The AST may have to be taken out of service, emp-tied, and cleaned prior to testing; and

• This method is highly dependent on the operator,particularly for shear-wave examination.

Radiographic Testing

X-rays and gamma rays are the most common radia-tions in AST inspections. Each type of radiation hasunique advantages in penetration power and ease ofmobility. The X-ray is produced by an X-ray machine;the gamma ray is generated by the decay of a radio-active isotope material that is contained in a small cap-sule. Radiography is excellent for detecting volumetrictype flaws, such as slag inclusions, porosity, lack ofpenetration and internal undercut.

Cracks and fusion problems can be more difficult todetect because the orientation of the flaw to the filmmust be within about plus or minus 2 degrees to showup clearly on the exposure. For these types of flaws,ultrasonic testing is the preferred inspection tool; andthe component to be inspected is placed between anelectromagnetic radiation source (of relatively shortwavelength) and a photographic film plate. When therays pass through the object, cracks or other voids ab-sorb rays less than solid material. On the photographicfilm plate, the flaws appear as darkened areas whilethe remainder of the exposed object appears lighter.Objects of uniform density and thickness, with noflaws, produce images of a uniform shade.

Special health and safety precautions must be takenwhere there is the possibility of exposure to X-rays orgamma rays. Radiography may only be conducted byqualified radiographers who, in the United States, havesuccessfully completed a course in radiation healthphysics as prescribed by the U.S. Nuclear RegulatoryCommission (NRC). Radiographers performing radio-graphic examination must be certified by the manufac-turer as meeting the requirements of certification

outlined in American Society for Nondestructive Test-ing (ASNT) Recommended Practice SNT-TC-1A.Training and experience are required to interpret cor-rectly the images produced on the radiographic film.To use radioactive isotopes, a company in the U.S.must be licensed by the NRC and also comply withCalifornia, Title 8, Health and Safety Code (which isstricter that the NRC requirements).

Advantages: Radiographic testing can find internal orsubsurface discontinuities and provides a permanent re-cord (the radiograph) which is available for others toview.

Disadvantages: Radiographic testing requires that bothsides of the material to be tested must be accessible,an uncommon situation for AST bottoms.

Other Radiation-Type Instruments

In addition to the X-ray and gamma ray instruments,portable gamma ray instruments are particularly usefulfor measuring piping, and, to a lesser extent, AST wallthickness. Radiographic testing is used on new weldsbut seldom for general surveillance inspections anduses penetrating radiation from a radioactive source totransmit the rays through the material to the recordingfilm. With this method, gamma rays are sent throughthe wall being analyzed; and a detector helps to countthe rays that pass through the wall. The rays that donot pass through are a function of the density andthickness of the wall. Because the density is a knownconstant, the thickness is determined to an average er-ror of less than three percent.

These instruments contain a radioisotope; but, becausethe amount is small, there is limited danger when pre-cautions are taken. Considerable experience is requiredto operate radiation-type instruments proficiently andsafely. Personnel must be trained fully to work withthese instruments which are delicate and must be han-dled with care.

Advantages: Radiographic testing is very good at de-tecting localized material degradation in welds.

Disadvantages: Radiographic testing is poor at detect-ing plate lamination.

1047 Leak Detection Methods ofInspection

The following external inspection methods have poten-tial as leak detectors, but all need to be more accurate.Consider them only as screening devices for prioritiz-ing AST internal inspections. If, however, an AST is


March 1993 1000-23

equipped with a double bottom, the leak-monitoringfeature of this design provides the best indication of aleak.

Acoustic Emission Method: Acoustic emissions arestress waves produced by movement in materials. Thewaves result from the action of a stimulation force,such as sound, introduced into a AST by strategicallylocated instrumentation. The sound emissions aremonitored, the location of the sound’s generator (theleak) located by triangulation. Attaining the degree ofaccuracy needed to detect small leaks is not, however,within current technological capabilities.

Advantages: Acoustic emission testing may identifythose ASTs that may be leaking and help to set priori-ties for large storage fields.

Disadvantages: The method is sensitive to extraneousnoise sources such as nearby roads, other equipment,pipelines; trains or airplanes may also interfere with thetesting.

Soil-gas Chromatography Method: An electrochemi-cal analysis; this method finds a known chemical com-pound in a general sample of material. A volatile,organic, AST-liquid-compatible chemical is added tothe AST. After a specified length of time, vapor sam-ples are taken from soil probes around the AST andthen analyzed for the known chemical tracer com-pound.

Advantages: This method has an advantage in that itis more sensitive than groundwater monitoring methodsand can detect leaks soon after they occur.

Disadvantages: Soil-gas chromatography is very timeconsuming; requires the AST to be isolated too long;and would require huge amounts of tracer chemical inan operating AST.

Hydrostatic Monitoring Method

Hydrostatic AST gaging has led some researchers toadapt the theory of the U-tube manometer for ASTleak testing. The AST is one leg of the manometer anda reference standpipe is the other leg. Leakproof valvesand very highly sensitive differential-pressuretransducers are installed in the U section of the ma-nometer. Comparing the reference pressure to a chang-ing pressure in the AST indicates the leak and overtime indicates the leak rate. In theory, this is a verysimple and easy test method.

At this time, the Company does not recommend us-ing this method for leak detection.

Disadvantages:

• Hydrostatic monitoring requires isolating the ASTfor a long period of time as a test of one day orless always gives erroneous results, and averagingthe diurnal volume fluctuations of the AST eachday for three to five days increases the accuracy.Complicated mathematical adjustments to the pres-sure data are necessary in both the AST and stand-pipe to account for the volume change due to thethermal expansion of their shells.

• Another difficult adjustment to the pressure data isto account accurately for the vaporization losses inboth the AST and the standpipe that are not pro-portionate to their cross-sectional areas.

• Eliminating the standpipe does not simplify the testbecause temperature profiles, volume adjustments,and evaporation losses become even more criticalto the accuracy of the test.

• Temperature profiles must be taken in the horizon-tal and vertical planes of the liquid; and tempera-tures must be taken on the circumference of theshell to accurately determine the differential expan-sion of the shell.

1050 API 653 REPAIR ANDALTERATION GUIDELINES

API 653 addresses all aspects of work involving ex-isting petroleum ASTs, including repairs, alteration,and relocation. In many cases, very little specific in-formation is given about the details of the repairs;therefore, an engineer experienced in AST design, re-pair, and constructions should review and endorse spe-cific details.

To ensure comparable quality of workmanship andlevel of quality control measures (such as NDE) be-tween new construction and alternations/repairs, manyAPI 653 requirements and practices are derived fromor are extensions of API 650. At the same time, sincefew specific details are given for alterations and repairsand many requirements are identical, the principles ofdesign and construction for new ASTs offer guidancefor repairs and alterations.

NDE Procedures/Qualifications/Acceptance Standards:API 653, Sections 10.1.1.1 and 10.1.1.2 state that Non-destructive Examination Procedures, qualifications andacceptance criteria shall be prepared for visual, mag-netic particle, liquid penetrant, ultrasonic, and radio-graphic methods and that API 650 sets the


1000-24 March 1993

qualifications for personnel performing nondestructiveexaminations.

Welding Procedures/Qualifications/Acceptance Stand-ards: API 653, Section 9 describes welding require-ments. API 653, Section 9.1.1, identical to API 650requirements, states that Welding Procedure Specifica-tions (WPS), and welders and welding operators shallbe qualified in accordance with Section IX of theASME Code [2].

The requirements for welders’ identifying, marking,and recording detailed in API 653, Section 9.2.1 areidentical to those of API 650.

Figure 1000-16 lists the common types of work onASTs, the problems encountered with this type ofwork, and the recommended inspection and testing.While industrial standards may dictate acceptable test-ing methods, the Company often requires supplemen-tal methods to increase reliability or to accommodatesituations that warrant additional or unusual testingmethods.

Consult the local inspection organization or CRTC’sMaterial and Equipment Engineering Unit for moreinformation.

Repairs: API 653, Section 1.5.9 discusses both minor(or routine) and major repairs which are generally re-placement of components or restoration to a safe con-dition. Nameplates and API 653 certification are notrequired and should not be used on ASTs repaired inaccordance with API 653.

Alterations: API 653, Section 1.5.1 defines alterations.They are any work involving cutting, burning, welding,or heating operations that change the physical dimen-sions or configuration of the AST. Alterations may bethe result of suitability for service evaluations or ASTinspections. Nameplates and API 653 certification arenot required and should not be used on ASTs alteredin accordance with API 653.

Alterations may be required under the following cir-cumstances:

• The owner/operator may wish to increase the ca-pacity of an AST by increasing shell height. Thealtered shell design must take into consideration allanticipated loadings, including wind and seismic, ifapplicable, and allowable soil-bearing capacity.

• The owner/operator may want to add new penetra-tions to accommodate changes in piping systems.Similarly, existing penetrations may be altered for

increased external loadings or to comply with cur-rent API 650 details.

Dismantling and Reconstruction: Although uncom-mon, an AST may be relocated by cutting it down andre-erecting it. This task must be planned and executedcarefully to ensure a quality finished product. For defi-nitions, see API 653, Sections 1.5.7 and 1.5.8.

1051 Repairs of AST Components

Those AST components for which API 653 providesrules for repair are listed and then discussed individu-ally below (numbers in parentheses refer to paragraphsin API 653):

Shell plates (Sections 7.1, 7-2)Defective welds (Section 7.5)Shell penetrations (Sections 7.6, 7.7)Bottom plates (Section 7.9)Slumps (Section 7.9.1.3)Fixed roofs (Section 7.10)Floating roofs (Section 7.11)Floating roof seals (Section 7.12)Foundations (Appendix B)

1052 Welding

Minimum Weld Spacing Requirements

API 653, Figure 7-1 shows minimum dimensions andweld spacing requirements for repair and patch plates;however, Figure 7-1 has an error. Until it is revised,use Figure 1000-17.

Figure 1000-17 appears on page following.

As with other API 653 requirements common to allwork, API 650’s criteria for weld spacing applies. Al-though the figures and wording are somewhat confus-ing, the intent of API 653 and API 650 is to followthe same weld-spacing criteria.

In practice, the current API 650 weld-spacing require-ments were not observed in many original AST con-structions. It is not the intent of API 653 to requirethat weld spacings be corrected in such cases, pro-vided the service history of the AST has been main-tained satisfactorily. If, however, either or both of twoadjacent welds are disturbed (as in the case of a newbottom installation), the resulting weld spacingsmust satisfy the requirements of the current edition


March 1993 1000-25

Tank Repairs, Problems, and Recommended Tests/Inspections

Repair Common Problems Inspection Methods

Weld Repairs

Lap weld patches onplate (bottom and roofonly)

Pinhole leaksBurn throughCracking

One side visible: vacuum test.

2 sides visible: penetrant test.

On bottoms: hydrotest to safe oil height

If indications of leakage, add biodegradable dye toconfirm

Butt welded patches onplate

Weak weldPinholesCracking

Radiograph, if accessible. Otherwise, penetrant testor magnetic particle test

Hydrotest to the safe oil height.

Major Component Replacement

Annular ringreplacement

Seam leaks Shell-to-ring fillet weld: Penetrant or diesel testouter weld before making inner weld. Penetranttest inner weld.

Radial butt welds: spot radiograph per API 650.Penetrant test.

Ring-to-plate lap welds: vacuum test.

Hydrotest to safe oil height

Bottom replacement Bottom leaks Annular ring: See above

Bottom plate lap welds: vacuum test weld seams.

Hydrotest to safe oil height.

Door sheet or shellcourse replacement

Weld leaks Penetrant test first and last weld pass

100% radiograph

Hydrotest to safe oil height

Check for peaking and banding

TA100016.WPFig. 1000-16 Tank Repairs, Problems, and Recommended Tests/Inspections (1 of 2)


1000-26 March 1993

TA100016.WP

Tank Repairs, Problems, and Recommended Tests/Inspections

Repair Common Problems Inspection Methods

Shell nozzle installation Weld cracks Nozzle welds: penetrant test first and last pass ormagnetic particle test. Ultrasonic test.

Reinforcing pad: soap test welds by pressurizingspace between pad and plate to 10 psig per API650. Hydrotest to safe oil height.

Installation of a new in-ternal floating roof in afixed roof tank

Roof hangup Check plumb of columns.

Inspect all column surfaces and entire shell overentire travel distance of IFR.

Installation of a newfloating roof

Roof hangup

Annular space variationcausing problems withroof seals

Pontoon leaks

Have surveyor check shell roundness and plumb.

Check tank diameters at multiple levels. Measureannular space variations as roof rises.

Vacuum test fillet welds.

Insert smoke generator inside pontoon or visuallyinspect. Inspect pontoons during hydrotest.

Appurtenance Replacement or Repairs

Floating roof legreplacement

Leaks at leg reinforcingpad weld

Penetrant test or magnetic particle test the weld.

Verify that reinforcing is on underside of roof.

Roof drain repairs Roof drain leaks Pressure test to 50 psi per API 650.

Check layout dimensions closely.

New swingpontoons

Leaking Pressurize pontoons to 7 psig and block in. Checkpressure loss over 30 minutes. Soap test weldseams while pressured.

Gagewell installation Floating roof jams

Vapor plug or samplerhangup

Check plumb of pipe with level. Measure edge ofpipe to shell spacing at multiple levels.

Visually inspect. Lower plug and check for drag.

Fig. 1000-16 Tank Repairs, Problems, and Recommended Tests/Inspections (2 of 2)


March 1993 1000-27

of API 650. New welds must satisfy these minimumspacing requirements.

Defective Welds

API 653 distinguishes between existing welds and newwelds. New welds include repair welds of existingwelds with flaws.

Existing Welds. When found to have cracks (duringinspections or at any other times), all existing welds,including shell-to-bottom welds, must have the defec-tive area removed and repaired by welding. Welds that

have lack of fusion, slag, and porosity must be evalu-ated. If they meet the requirements of the original stand-ard of construction, they need not be repaired. If,however, such flaws are not acceptable to the originalstandard, the defective area must be removed and re-paired by welding. Weld undercuts, corrosion, and pittingmust be evaluated and, if unsuitable for service, repaired.Weld reinforcement of existing welds in excess of API650 criteria is acceptable, provided it does not cause op-erational problems (e.g., undue wear of seals).

Limits of Repairs for Existing Welds. If the NDE ofrepairs, installation of new plates, or reconstruction


Fig. 1000-17 Acceptable Details for Replacement for Shell Plate Material(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991. Reprinted Courtesy of the American Petroleum Institute.)


1000-28 March 1993

(dismantling and reconstructing) reveals flaws in exist-ing welds, the acceptance criteria for such flaws andthe limits of any needed NDE and repairs may bebased on the original standard of construction. If theoriginal standard cannot be established, the acceptancecriteria and the limits of any repairs must be made inaccordance with the current edition of API 650.

Quality and Details of Repair, New Plate Installa-tion, and Reconstruction Welds. The material and de-tails of such welds must comply with the currentedition of API 650. For example, the repair of a partialfusion butt weld is complete penetration and completefusion. For reconstructed ASTs, shell replacement andnew butt joints must have complete penetration and becomplete fusion welds.

NDE of Repaired Existing Welds and of NewWelds. Areas in which defects in existing welds havebeen removed must be examined visually and by MT(or PT) before welding:

• Completed repairs of existing butt welds should beRT (or UT) examined for the full length of the re-pair.

• Completed repairs of existing fillet welds should beMT (or PT) examined.

• Butt welds for inserting new shell plates or doorsheets should be spot RT examined.

• Each vertical and horizontal seam and new inter-section between shell vertical and horizontal weldsshould be RT examined.

• New butt welds in reconstructed ASTs should bespot RT examined.

1053 Shell Plates and Penetrations

Shell Plates

API 653 regulates the repair and replacement of shellplates and focuses on minimum thickness, minimumdimensions of replacement plate, weld-joint design forreplacement plates, and repair of defects such as flaws,cracks, gouges and tears (such as those left after re-moving the contractor’s temporary accessories).

Although not referred to specifically in API 653, Sec-tion 7, specifications for all materials used when re-placing shell plates, inserts, and reinforcing plates mustconform to the applicable material requirement stand-ards. In the case of repairs to an API 650 or API 12CAST, the material-temperature-toughness requirements

of the current edition of API 650 and of the materialapply; and it must be able to be welded (by an ap-proved welding procedure) to the existing material.

Installing a replacement plate or a section of a plateon an existing AST introduces the potential for dis-tortions. These arise from shrinkage stresses in weld-ing, especially when welding an already distortedshell. To reduce such effects, consideration must begiven to proper fit-up, heat input, and welding se-quence (API 653, Par. 7.2.3.4).

No specific limiting distortion values are given. The re-paired (reconstructed) shell is expected to satisfy thewind-buckling and seismic-stability requirements (Par.6.6.2 and Par. 6-8) of the applicable standard. The im-plication is that API 650 tolerances should apply and thatthe tolerances in API 653, Paragraph 8.5 for dismantledand reconstructed ASTs could also be considered.

All flaws (defects) in the shell plates such as cracks,scars, gouges, tears, lamination, arc strikes are to beremoved by grinding or by welding (using qualifiedprocedures). Further grinding may be necessary as de-termined by an engineering evaluation. Welded repairsare made when the remaining plate thickness is inade-quate after grinding. Flaws, such as scars with asmooth profile, may be exempt from repairs if an en-gineering evaluation accepts them.

Shell Penetrations

API 650 Section 3 for Design is the basis for any repairsto shell penetrations, including the addition of any re-quired reinforcing plates to unreinforced penetrations.

1054 Bottom Plates and Slumps

Depending on the extent of damage to the bottom, re-pairs may range from replacing only a portion of thebottom plates to the entire bottom.

Critical Zone

If repairs within the critical zone are more extensivethan those permitted by API 653, a new section of bot-tom plate must be installed. API 653 defines the limitsof a critical zone (see Figure 1000-18) as the bottomplate adjacent to the shell. This area is considered criti-cal for two basic reasons, namely:

1. High Stress: The level of stress in this high-stressarea cannot be predicted by the membrane theoryalone. The rotational forces and discontinuitystresses (resulting from the geometry of the junctionand the presence of penetrations in the first shell


March 1993 1000-29

course) subject the area to high-stress concentra-tions.

2. Corrosion: Historically, this area is subject to corro-sion.

Repairing the Bottom Plate away from the CriticalZone: API 653 does not restrict repairs to the bottomplate away from the critical zone. In accordance with thecurrent API 650, Company practice for repairs of the bot-tom plate away from the critical zone is generally to uselap welded round cornered cover plates of material se-lected. (See Figure 1000-14.)

Slumps

API 653 does not permit repairs to slumps within thecritical zone (see Figure 1000-18). If a slump, or a portionof it, is located in the critical zone and is in need of re-pair, the slump must be removed, repaired, and then re-installed (if required) in accordance with the weld spacingrequirements of API 650.

Replacing Entire AST Bottoms

API 653 permits new bottoms to be installed with or with-out removing the existing bottom. When the existing bot-tom is to be removed and replaced with a new one,Company practice is to cut through and remove the bottom.

Other Reasons for Complete Replacement: Under cer-tain circumstances, the owner/operator may choose to re-place the entire bottom plate rather than repairing severalsmall portions because:

• The physical damage to the bottom plate is so extensivethat complete replacement is more economical than lo-cal repair.

• The remaining bottom-plate thickness is within the ac-ceptance criteria for suitability for service evaluation,but the owner/operator wishes to upgrade or extend theAST’s service life by incorporating thicker plates toincrease the corrosion allowance.

• The owner/operator wants to incorporate one or a com-bination of systems: leak detection, secondary contain-ment, cathodic protection.

Replacing without Removing Existing Bottom

API 653 specifies the following requirements when in-stalling a complete new AST bottom and not removingthe existing bottom.

1. The new bottom plate must be installed by slottingthe shell. All rules for weld spacing in current API650 must be observed. (See Figure 1000-19 fordetails.)

2. The new bottom floor may rest on a layer of sand,gravel, concrete, or other suitable noncorrosive


Fig. 1000-18 Critical Zone for Tanks With andWithout Annular Plates


Fig. 1000-19 Slotted Shell Detail for New Bottomin Existing Tank


1000-30 March 1993

material. (By suitable, API 653 means a materialthat provides uniform support of the new bottomplate to the same extent as required by API 650for new construction.)

3. All foundation subgrade voids must be filled withsand, gravel, crushed limestone, concrete, or grout.

4. Existing shell penetrations near the existing floormay need to be modified to satisfy weld-spacingrequirements of the current API 650. (See Figures1000-17, 1000-20, and 1000-21 for details.)

5. Modification of floating roof support legs may benecessary.

6. Bearing plates for floating roof support legs androof support columns must be installed.

1055 Roofs and Foundations

Fixed and Floating Roofs

Fixed Roofs: API 653 provides no specific require-ments for the repair of fixed roofs. The intent of API653 is to meet API 650’s minimum requirements forrepaired or replaced parts in roof design.

Floating Roofs: Similar to fixed roofs, API 653 pro-vides few guidelines for the repair of internal and ex-ternal floating roofs. No leaks are permitted, and anyleaks must be repaired by rewelding the leaking jointor by patch plates.

Floating Roof Seals: API 653 specifically permits therepair of primary and secondary seal systems while theAST is in service, provided that, for primary seals, nomore than one-fourth of the seal is removed for repairat a time. For some types of primary seals, in-serviceaccessibility may limit the extent of repairs that can beaccomplished.

Proper seal-to-shell gaps must be maintained to ensurethat the seal functions properly and that the final re-paired seal system complies with the regulatory re-quirements of all applicable jurisdictions.

Foundations

API 653, Appendix B provides guidelines for theevaluating AST bottom settlement.


Fig. 1000-20 Method for Raising Shell Nozzles(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction,First Edition, January 1991. Reprinted Courtesy of the American PetroleumInstitute.)


Fig. 1000-21 Shell Nozzle Modification


March 1993 1000-31

If AST settlements are outside the guidelines of API653, Appendix B, repairs are not necessarily mandated,but consideration should be given to making repairs ora rigorous stress analysis should be performed to evalu-ate the deformed profile ... The judgement on repairsshould be tempered with knowledge of AST service his-tory, previous repairs, previous inspections, AST founda-tion conditions, soil characteristics, the material of (AST)construction, and estimates of future settlement [3].

API 653 recognizes that an AST’s settlement is notnecessarily a single type (edge settlement versus local-ized settlement versus planar tilting) but rather is usu-ally a combination of several types.

When settlements exceed the guidelines of API 653,Appendix B, this standard only mentions the followingapproaches for correcting settlement and gives no de-tailed requirements for any of them:

• Localized repairs of the bottom plate

• Partial re-leveling of the AST periphery

• Major re-leveling of the entire AST bottom

• Filling foundation subgrade voids with sand, gravel,crushed limestone, concrete, or grout

1056 Hot Taps

API 653 permits hot tapping of ASTs, provided it isperformed in accordance with specific procedures (e.g.,API Publication 2201) and details (see Figure 1000-22in this section or API 653, Figure 7-5).

If, in the course of an inspection, a hot tap is foundon an existing AST, its suitability for service must beevaluated and action taken depending on the outcome:

• No change in service: The hot tap should be evalu-ated for compliance with the details shown in API653, Figure 7-5.

• A change in service: The hot tap should be removedand, if necessary, replaced with a permanent penetra-tion in accordance with API 653, Section 6.5.

It is recommended that all hot taps be removedwhen the AST is cleaned and gas freed and replacedwith complying details.

1057 Hydrostatic Testing of Repaired,Altered, or Reconstructed ASTs

Required Hydrostatic Testing

API 653, Section 10 covers hydrostatic testing require-ments. Figure 1000-23 summarizes the conditions forwhich hydrostatic testing is required.

Note: There is a loophole in API 653, Table 10.Use this manual’s Figure 1000-23 instead.

A full hydrostatic test is required for reconstructedASTs and after major repairs or major alterations to aAST, unless it is exempted as described below. A ma-jor repair or alteration is defined as follows:

• Installation of any shell penetration beneath the designliquid level and larger than 12 inches or any bottompenetration located within 12 inches of the shell.

• Replacement of any shell material beneath the de-sign liquid level or any annular plate ring materialwhere the longest dimension exceeds 12 inches.


Fig. 1000-22 Exemption Curve for Hot TappingTanks with Steels of UnknownToughness

(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction,First Edition, January 1991. Reprinted Courtesy of the American PetroleumInstitute.)


1000-32 March 1993

• Complete or partial removal or replacement of morethan 12 inches of vertical weld joining shell plates, orradial welds joining the annular plate ring.

• Replacement of an AST bottom.

• Removal and replacement of any part of the shell-to-bottom weld.

• Whenever there has been shell jacking.

Hydrostatic Testing Exemption

Hydrotesting may be exempted under the followingconditions:

1. The toughness (resistance to brittle fracture) of theexisting AST material is unknown; but the shellmetal temperature/shell thickness combination fallsabove the curve of Figure 1000-24; and all of thefollowing specific conditions are satisfied:

a. An engineer, experienced in AST design perAPI 650, has reviewed and approved themethod of repair.

b. Repair materials meet current API 650 require-ments.

c. Existing vertical and horizontal shell joint weldsshall have complete penetration and completefusion. The root pass and completed weld passof new welds, attaching shell plate to shell platemust be examined visually and in accordancewith API 650 radiographic methods.

In addition, for plate thicknesses greater thanone inch, each side of the complete length of the

Basic Condition Specific

Requirements

Shell Condition1. Tank material of unknown

toughness, but satisfies theexemption criteria ofFigure 10-1.

a,b,c,d

2. Tank material meets thetoughness requirements ofAPI 650, seventh editionor later.

a,b,c,d

Bottom Condition3. Tank repairs limited to

bottom plates or annularplate ring (excluding shell-to-bottom weld).

a,b

Specific Requirements:a. The repair method has been reviewed and approved by

an engineer experienced in storage tank design in ac-cordance with API Standard 650.

b. Material used for the repair shall meet API Standard650 requirements.

c. Vertical and horizontal shell joint welds shall havecomplete penetration and complete fusion. The rootpass and final pass examination shall be in accordancewith 10.1.5 of API 653. In addition, the finished weldshall be fully radiographed.

d. Shell penetrations shall be installed with completepenetration and complete fusion welds for the reinforc-ing plate to nozzle neck and nozzle neck to shell joints.The root pass of the nozzle attachment weld shall beaback gouged and examined by magnetic particle orliquid penetrant methods; the completed weld shall beexamined by ultrasonic method. Examination and ac-ceptance criteria for nondestructive examinations shallbe in accordance with 10.1.1 of API 653.

TA100023.WP

Fig. 1000-23 Conditions for Exemption from TankHydrostatic Test for Major Repairs andAlterations



Fig. 1000-24 Exemption Curve for HydrostaticTesting of Tanks



March 1993 1000-33

back-gouged surface of the root pass and finalpass must be examined by magnetic particle orliquid penetrant methods; the finished weld mustalso be radiographed fully.

d. Shell penetrations must be installed with com-plete penetration and complete fusion welds forthe reinforcing plate to nozzle neck and nozzleneck to shell joints. The root pass of the nozzleattachment weld must be back-gouged and ex-amined by magnetic particle or liquid penetrantmethods; the completed weld by the ultrasonicmethod. Examination and acceptance criteriamust meet the requirements in the current edi-tion of API 650 for nondestructive examina-tions.

2. The AST material must meet not only the tough-ness requirements of API 650 ( 7th edition or later)but also the specific conditions in 1.a. through 1.d.(above).

3. AST repairs that are limited to the bottom platesor annular plate rings, exclude the shell-to-bottomweld, and satisfy specific conditions in 1.a.through 1.b. (above). Note that whenever theshell-to-bottom weld is involved, a hydrostatictest is required.

4. After replacing a door sheet to facilitate repairs oralterations, provided both of the following condi-tions are satisfied:

a. The spacing between the shell-to-bottom weldand the weld of the lower edge of the door sheetis either of the following:

• Greater than three inches for ASTs less thanor equal to 1/2-inch thick; or

• Greater than eight times the shell thicknessor ten inches for ASTs greater than 1/2-inchthick.

b. The AST is otherwise exempt from hydrostatictesting.

Other Considerations for Hydrostatic Testing

Although API 653, Section 10 defines the conditionsfor which hydrostatic testing is definitely required andnot required, some situations may require a case-basisassessment to determine if hydrostatic testing isneeded. An example is an AST converted from heatedto non-heated service. API 653 Paragraph 3.2.2 advisesthe need to consider a hydrostatic test for a change of

service. Depending on the type of changes, the servicehistory, and reduction in the level of operating tem-perature, an experienced AST engineer may need toconduct a review and decide whether or not hydrostatictesting is required.

1058 Dismantling and Reconstruction

It is the intent of API 653 that the structural integrityand serviceability of an AST not be compromised dur-ing dismantling and reconstruction.

For existing ASTs, API 653, Section 8 gives specificdetails for these processes and should be reviewedcarefully and understood fully before initiating a dis-mantle/reconstruct contract. Among the most importantAPI 653 requirements are that:

• Without exception, a reconstructed AST requires ahydrostatic test.

• An AST reconstructed in accordance with API 653must be:

– Identified with a nameplate similar to thatshown in API 653, Figure 11-1.

– Certified with a statement as shown in API653, Figure 11-2.

• Different organizations should not dismantle andsubsequently reconstruct ASTs.

• A written dismantling procedure must be preparedin accordance with the OSHA requirement.

• While API 653 permits less restrictive tolerancesthan API 650 for reconstruction of the AST itself,the foundation tolerances specified in API 653, Sec-tion 8.5.6 are as restrictive as those in API 650.

1060 THE MECHANICAL INTEGRITYELEMENT OF OSHA 29 CFR1910.119

Figure 1000-25 summarizes inspection, testing andmaintenance requirements published in national andCorporate standards, codes, procedures, practices andspecifications. It is included to assist you in developingwritten procedures needed to comply with OSHA 29CFR 1910.119.

Figure 1000-25 appears on pages following.


1000-34 March 1993

The mechanical integrity element of OSHA 29 CFR1910.119 requires that facilities:

• Revise, develop, and implement written maintenance,inspection, and integrity measures to ensure the con-tinuing mechanical integrity of these facilities.

• Develop procedures that follow good engineeringpractice and generally accepted industrial standards.

• Document inspections.

Figure 1000-25 does not provide details, designs, norprocedures but merely represents a list to start devel-oping compliance tailored to the facility in question; itis not intended to:

• Cover every standard or code of practice.

• Endorse, recommend, or approve any inspection,procedure, guideline or standard.

1070 API RECOMMENDED PRACTICERP 575

API RP 575, Inspection of Atmospheric and Low-Pres-sure Storage Tanks is a new, tutorial document thatprovides many good diagrams and figures to help withconducting AST inspections.

1080 REFERENCES

[1], [2], [3]

API Std. 653; Tank Inspection, Repair, Alteration, andReconstruction

1090 Other Resources

API RP 651; Cathodic Protection for Aboveground Pe-troleum Storage Tanks

API RP 652; Lining of Aboveground Petroleum Stor-age Tanks

API Std. 650; Welded Steel Tanks for Oil Storage

API Std. 620; Design and Construction of Large,Welded Low-Pressure Storage Tanks

API Std. 2000; Venting Atmospheric and Low-PressureStorage Tanks

API RP 2003; Protection Against Ignitions Arising Outof Static, Lightning, and Strong Currents

API Pub. 2015; Cleaning Petroleum Storage Tanks

API Pub. 2207; Preparing Tank Bottoms for Hot Work

API Pub. 2217; Guidelines for Continued Space Workin the Petroleum Industry


March 1993 1000-35

TA100025A

.PC

XF

ig. 1000-25Inspection, T

esting, and Maintenance R

equirements (1 of 9)


Tank M

anual

1000-36M

arch 1993

TA100025B

.PC

XF




Tank M

anual1000 Inspection and T

esting

March 1993

1000-37

TA100025C

.PC

XF





Tank M

anual

1000-38M

arch 1993

TA100025D

.PC

XF




Tank M


esting

March 1993

1000-39

TA100025E

.PC

XF





Tank M

anual

1000-40M

arch 1993

TA100025F.P

CX

Fig. 1000-25

Inspection, Testing, and M

aintenance Requirem

ents (6 of 9)

Tank M


esting

March 1993

1000-41

TA100025G

.PC

XF





Tank M

anual

1000-42M

arch 1993

TA100025H

.PC

XF




Tank M


esting

March 1993

1000-43

TA100025I.P

CX

Fig. 1000-25

Inspection, Testing, and M

aintenance Requirem

ents (9 of 9)


Tank M

anual

1000-44M

arch 1993

Shop Work for Field-Erected Tanks: Inspection and Checklist

The Quality Assurance Team of CRTC’s Materials and Equipment Engineering Unit can arrange shop inspections.The principal reason for shop inspection of field-erected tank components is to avoid receipt of faulty material atthe erection site which can result in delay or force the user to accept something that is less than required ordesired. The following inspection plan is typical for API 650 or API 12D tanks. It can be adjusted to fit specialcircumstances or to reduce costs.

INSPECTION CHECKLIST

Item: Report #:

Specific Location:Check if

Completed Activity Comments

Pre-inspection meeting at Vendor’s Shop (prior to start of plateprocessing or fabrication).

Review purchase order, supplements, list sheets, referencedspecifications.

Review Chevron inspection requirements.

Review fabrication schedule.

Check weld procedures for compliance with ASME Section IX.

Verify welders are qualified to follow the appropriate procedures.

Shell Plate InspectionWith a micrometer, gage every shell plate at five equally spacedpoints on each end (or at the frequency required by the ASTspecification) to verify it is within API tolerance on specifiedthickness.

Measure diagonals of each plate to verify squareness; differencein diagonals not to exceed 1/8 inch.

Visually inspect both sides of every shell plate for:1. Laminations, scars, and pits. A few small scars and pits may be

weld repaired and ground to bring plate up to requiredthickness. A plate is rejected if scars or pits are prevalent.Laminated plate is rejected.

2. Straightness after rolling (freedom from buckles or waves).

3. Imperfections or damage along weld bevels or edges that wouldinterfere with fit-up or welding.

4. Curvature across plate width caused by worn plate rolls. Platesare rejected if curvature in this direction exceeds API 650banding limits.

Verify that plate is cribbed after rolling to prevent flatteningplates at bottom of stack and that it will also be cribbed fortransport.

Material Test Reports:1. Compare the heat number and slab number found on every

shell plate with the heat/slab numbers found on the materialtest reports.

2. Review the material test reports to verify that chemical andphysical test results meet the applicable ASTM requirements.For some plate materials, ASTM does not require that the millmark every plate with the heat/slab number. If plates are notmarked, the Vendor must mark each plate with a code numberor piece number so that thickness readings can be traced backto a particular plate to help track plates visually inspected.

TAM10006.WPFig. 1000-6 Field-Erected Tanks Inspection Checklist (1 of 2)


March 1993 1000-45

TAM10006.WP


Item: Report #:



Check shell and roof plate cleaning and painting.1. Make random inspections of surface preparation of plate

(usually by sandblast or gritblast) prior to painting. Checkdegree of cleaning and anchor pattern against what isspecified.

2. Visually inspect primer on every plate for runs, sags, mudcracking, holidays, entrapped dirt, or other deficiencies.Verify that all edges were masked to keep paint two inchesfrom joints to be field welded.

3. Measure primer thickness on every plate at five locations, onefoot in from each corner and in the center of each plate toverify specified minimum thickness is present.

Appurtenance Inspection (Appurtenances will in most cases beshop-fabricated.)

Spot check fit-up of appurtenances prior to welding.

Witness approximately 25 percent of magnetic-particleexaminations of nozzle/reinforcing pad welds that do not requirestressrelief and all magnetic particle examination for manway, nozzle,and reinforcing pad welds that require stress relief. Magneticparticle examination of welds requiring stress relief arewitnessed after stress relief.Review furnace charts for correct time and temperatures on shellplate assemblies requiring stress relief.

Witness approximately 25 percent of the air/soap film testing ofreinforcing pad welds. Witness all of the air/soap film testing of thereinforcing pad welds which require stress relief (after stress relief).

Spot check handrails, grating, and stairs against the structural steelSpecification CIV-EG-398 and details shown on standard drawings.

Verify that the shop can trace nozzle neck and reinforcing padmaterials back to material test reports.

Make random dimensional checks.

Visually inspect all welds on nozzles, AST plate, and floating roofsections. Weld quality is expected to be per ASME Section VIIIfor types of flaws not specifically covered by API 650 or API12D.

Visually inspect all welds on structural parts for compliance withAWS Structural Welding Code D-1.1.

Records and Documents (to be obtained from Vendor)Retain material test reports for all shell plate and bottom plate.

Retain furnace charts for all items requiring stress relief.

Fig. 1000-6 Field-Erected Tanks Inspection Checklist (2 of 2)


1000-46 March 1993

TAM10007.WP

Shop-fabricated Tanks: Inspection and Checklist

Shop inspection is done by the Quality Assurance Team of CRTC’s Materials and Equipment Engineering Unit.The following inspection plan is typical for API 650 and API 12F ASTs. It can be adjusted to fit special circum-stances.


Item: Report #:



Pre-inspection meeting at Vendor’s Shop (prior to start of plateprocessing or fabrication).

Review purchase order, supplements, list sheets, referencedspecifications.

Review Chevron inspection requirements.

Review fabrication schedule.

Check weld procedures for compliance with ASME Section IX.

Verify welders are qualified to follow the appropriate procedures.

Inspection Checklist

Make one or two inspection visits during fabrication to verify that:1. Joint details, materials, and workmanship are within API 650 or

API 12F requirements.2. Qualified welding procedures and welders are being used.

Inspect after fabrication but prior to pressure/leak test.1. Review material test reports for all AST plates to verify that

plates are the specification/grade and thickness shown on Tankand Appurtenance Schedule or approved Vendor drawing.

2. Visually inspect all welds inside and outside. Weld quality isexpected to be per ASME Section VIII for types of flaws notspecifically covered by API 650 or API 12F.

3. Check joint misalignment, weld reinforcement, plumbness,roundness, peaking, and banding against API 650 or API 12Flimits

4. Review radiographs (if required) of welds.

5. Make a complete dimensional and orientation check.

6. Check connections for correct size and rating.

7. Check ladders and platforms against standard drawings orapproved Vendor drawings.

Witness a leak test per API 650 or API 12F, or witness ahydrostatic test. A hydrostatic test in the vertical position ispreferred over an air test since this more closely represents ASTloading in service.

Inspect after external painting if painting is required. (Internalcoating will require two or three additional visits.)1. Inspect surfaces for runs, sags, mud cracking, holidays,

entrapped dirt or other deficiencies.2. Check paint thickness at random locations and compare to

thickness required by the specification. Also measure any areaswhich appear visually to be thin. Verify that paint is thebrand/type specified or approved.

Fig. 1000-7 Shop-fabricated Tanks: Inspection and Checklist


March 1993 1000-47

(This page reserved for future use.)


1000-48 March 1993


Item: Report #:



1.1. FOUNDATION

Measure foundation levelness and bottom elevations (seeAppendix B for extent of measurements).1.1.1 Concrete Ringa. Inspect for broken concrete, spalling, and cracks, particularly

under backup bars used in welding butt welded annular ringsunder the shell.

b. Inspect drain openings in ring, back of waterdraw basins, andtop surface of ring for indications of bottom leakage.

c. Inspect for cavities under foundation and vegetation againstbottom of tank.

d. Check that runoff rainwater from the shell drains away fromtank.

e. Check for settlement around perimeter of tank.1.1.2 Asphalta. Check for settling of tank into asphalt base which would

direct runoff rainwater under the tank instead of away fromit.

b. Look for areas where leaching of oil has left rock fillerexposed, which indicates hydrocarbon leakage.

1.1.3 Oiled Dirt or SandCheck for settlement into the base which would direct runoffrainwater under the tank rather than away from it.

1.1.4 RockPresence of crushed rock under the steel bottom usually resultsin severe underside corrosion. Make a note to do additionalbottom plate examination (ultrasonic, hammer testing, orturning of coupons) when the tank is out of service.

1.1.5 Site Drainagea. Check site for drainage away from the tank and associated

piping and manifolds.b. Check operating condition of dike drains.1.1.6 Housekeeping

Inspect the area for buildup of trash, vegetation, and otherinflammables buildup.

1.2 SHELLS1.2.1 External Visual Inspectiona. Visually inspect for paint failures, pitting, and corrosion.b. Clean off the bottom angle area and inspect for corrosion and

thinning on plate and weld.c. Inspect the bottom-to-foundation seal, if any.1.2.2 Internal (Floating Roof Tank)

Visually inspect for grooving, corrosion, pitting, and coatingfailures.

TAM10008.WPFig. 1000-8 Tank In-Service Inspection Checklist (1 of 6)(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991.Reprinted Courtesy of the American Petroleum Institute.)


March 1993 1000-49


Item: Report #:



1.2.3 Riveted Shell Inspectiona. Inspect external surface for rivet and seam leaks.b. Locate leaks by sketch or photo (location will be lost when

shell is abrasive cleaned for painting).c. Inspect rivets for corrosion loss and wear.d. Inspect vertical seams to see if they have been full fillet lap

welded to increase joint efficiency.e. If no record exists of vertical riveted seams, dimension and

sketch (or photograph) the rivet pattern: number of rows,rivet size, pitch length, and note whether the joint is buttriveted or lap riveted.

1.2.4 Windgirder (Floating Roof Tanks)a. Inspect windgirder and handrail for corrosion damage (paint

failure, pitting, corrosion product buildup), especially whereit occurs at tack welded junctions, and for broken welds.

b. Check support welds to shell for pitting, especially on shellplates.

c. Note whether supports have reinforcing pads welded to shell.1.3 SHELL APPURTENANCES1.3.1 Manways and Nozzlesa. Inspect for cracks or signs of leakage on weld joints at

nozzles, manways, and reinforcing plates.b. Inspect for shell plate dimpling around nozzles, caused by

excessive pipe deflection.c. Inspect for flange leaks and leaks around bolting.d. Inspect sealing of insulation around manways and nozzles.e. Check for inadequate manway flange and cover thickness on

mixer manways.1.3.2 Tank Piping Manifoldsa. Inspect manifold piping, flanges, and valves for leaks.b. Inspect fire fighting system components.c. Check for anchored piping which would be hazardous to the

tank shell or bottom connections during earth movement.d. Check for adequate thermal pressure relief of piping to the tank.e. Check operation of regulators for tanks with purge gas systems.f. Check sample connections for leaks and for proper valve

operation.g. Check for damage and test the accuracy of temperature

indicators.h. Check welds on shell-mounted davit clips above valves 6

inches and larger.1.3.3 Autogage Systema. Inspect autogage tape guide and lower sheave housing

(floating swings) for leaks.b. Inspect autogage head for damage

TAM10008.WPFig. 1000-8 Tank In-Service Inspection Checklist (2 of 6)(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991.Reprinted Courtesy of the American Petroleum Institute.)


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c. Bump the checker on autogage head for proper movement oftape.

d. Identify size and construction material of autogage tape guide(floating roof tanks).

e. Ask operator if tape tends to hang up during tank roofmovement (floating roof tanks).

f. Compare actual product level to the reading on the autogage(maximum variation is 2 inches).

g. On floating roof tanks, when the roof is in the lowest position,check that no more than 2 feet of tape are exposed at theend of the tape guide.

h. Inspect condition of board and legibility of board-type autogages.i. Test freedom of movement of marker and float.1.3.4 Shell-Mounted Sample Stationa. Inspect sample lines for function of valves and plugging of

lines, including drain or return-to-tank line.b. Check circulation pump for leaks and operating problems. c. Test bracing and supports of sample system lines and equipment.1.3.5 Heater (Shell Manway Mounted)

Inspect condensate drain for presence of oil indicating leakage.1.3.6 Mixera. Inspect for proper mounting flange and support.b. Inspect for leakage.c. Inspect condition of power lines and connections to mixer.1.3.7 Swing Lines: Winch Operationa. Nonfloating. Raise, then lower the swing line with the winch,

and check for cable tightness to confirm that swing linelowered properly.

b. Floating. With tank half full or more, lower the swing line, thenlet out cable and check if swing has pulled cable tight,indicating that the winch is operating properly.

c. Indicator. Check that the indicator moves in the properdirection: Floating swing line indicators show a lower levelas cable is wound up on the winch. Nonfloating swing lineindicators show the opposite.

1.3.8 Swing Lines: External Guide SystemCheck for leaks at threaded and flanged joints.

1.3.9 Swing Lines: Identify Ballast Varying NeedCheck for significant difference in stock specific gravity.

1.3.10 Swing Lines: Cable Material and Conditiona. For nonstainless steel cable, check for corrosion over entire

length.b. All cable: check for wear or fraying.1.3.11 Swing Lines: Product Sample Comparison

TAM10008.WPFig. 1000-8 Tank In-Service Inspection Checklist (3 of 6)(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991. Reprinted Courtesy of the American Petroleum Institute.).


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Check for water or gravity differences that would indicate a leaking swing joint.

1.3.12 Swing Lines: TargetTarget should indicate direction of swing opening (up or down)and height above bottom where suction will be lost withswing on bottom support.

1.4 ROOFS

1.4.1 Deck Plate Internal CorrosionFor safety, before accessing the roof, check the ultrasonic instrument or lightly use a ball peen hammer to test the deckplate near the edge of the roof for thinning. (Corrosionnormally attacks the deck plate at the edge of a fixed roofand at the rafters in the center of the roof first.)

1.4.2 Deck Plate External CorrosionVisually inspect for paint failure, holes, pitting, and corrosionproduct on the roof deck.

1.4.3 Roof Deck DrainageLook for indication of standing water. (Significant sagging offixed roof deck indicates potential rafter failure. Largestanding water areas on a floating roof indicates inadequatedrainage design or, if to one sided, an unlevel roof withpossible leaking pontoons.)

1.4.4 Level of Floating RoofAt several locations, measure distance from roof rim to ahorizontal weld seam above the roof. A variance in thereadings indicates a nonlevel roof with possible shell out-of-round, out-of-plumb, leaking pontoons or hangup. On smalldiameter tanks, an unlevel condition can indicate unequalloading at that level.

1.4.5 Gas Test Internal Floating RoofTest for explosive gas on top of the internal floating roof.Readings could indicate a leaking roof, leaking seal system,or inadequate ventilation of the area above the internalfloating roof.

1.4.6 Roof Insulationa. Visually inspect for cracks or leaks in the insulation weather

coat where runoff rainwater could penetrate the insulation.b. Inspect for wet insulation under the weather coat.c. Remove small test sections of insulation and check roof deck

for corrosion and holes near the edge of the insulated area.1.4.7 Floating Roof Seal Systemsa. Measure and record maximum seal-to-shell gaps:

at low pumpoutat midshellat high liquid level

TAM10008.WPFig. 1000-8 Tank In-Service Inspection Checklist (4 of 6)(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991. Reprinted Courtesy of the American Petroleum Institute.).


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b. Measure and record annular space at 30-foot spacing(minimum of 4 quadrants) around roof and record.Measurements should be taken in directly opposite pairs.

Opposite Pair 1

Opposite Pair 2

c. Check if seal fabric on primary shoe seals is pulling shoesaway from shell (fabric not wide enough).

d. Inspect fabric for deterioration, holes, tears, and cracks.

e. Inspect visible metallic parts for corrosion and wear.

f. Inspect for openings in seals that would permit vaporemissions.

g. Inspect for protruding bolt or rivet heads against the shell.

h. Pull both primary and secondary seal systems back all aroundthe shell to check their operation.

i. Inspect secondary seals for signs of buckling or indicationsthat their angle with the shell is too shallow.

j. Inspect wedge-type wiper seals for flexibility, resilience,cracks, and tears.

1.5 ROOF APPURTENANCES

1.5.1 Sample Hatcha. Inspect conditions and functioning of sample hatch cover.

b. On tanks governed by Air Quality Monitoring Districts rules,check for the condition of seal inside hatch cover.

c. Check for corrosion and plugging on thief and gage hatchcover.

d. Where sample hatch is used to reel gage stock level, check formarker and tab stating hold off distance.

e. Check for reinforcing pad where sample hatch pipe penetratesthe roof deck.

f. On floating roof sample hatch and recoil systems, inspectoperation of recoil reel and condition of rope.

g. Test operation of system.

h. On ultraclean stocks such as JP4, check for presence andcondition of protective coating or liner inside sample hatch(preventing rust from pipe getting into sample).

1.5.2 Gagewella. Inspect visible portion of the gagewell for thinning, size of

slots, and cover condition.b. Check for a hold off distance marker and tab with hold off

distance (legible).c. On floating roofs, inspect condition of roof guide for a

gagewell, particularly the condition of the rollers forgrooving.

TAM10008.WP

Fig. 1000-8 Tank In-Service Inspection Checklist (5 of 6)(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991. Reprinted Courtesy of the American Petroleum Institute.)


March 1993 1000-53


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d. If accessible, check the distance from the gagewell pipe to thetank shell at different levels.

e. If tank has a gagewell washer, check valve for leakage and forpresence of a bull plug or blind flange.

1.5.3 Fixed Roof Scaffold SupportInspect scaffold support for corrosion, wear, and structuralsoundness.

1.5.4 Autogage: Inspection Hatch and Guides (Fixed Roof)a. Check the hatch for corrosion and missing bolts.

b. Look for corrosion on the tape guide’s and float guide’s wireanchors.

1.5.5 Autogage: Float Well Covera. Inspect for corrosion.

b. Check tape cable for wear or fraying caused by rubbing onthe cover.

1.5.6 Sample Hatch (Internal Floating Roof)a. Check overall conditions.

b. When equipped with a fabric seal, check for automatic sealingafter sampling.

c. When equipped with a recoil reel opening device, check forproper operation.

1.5.7 Roof-Mounted Vents (Internal Floating Roof)Check condition of screens, locking, and pivot pins.

1.5.8 Gaging Platform Drip RingOn fixed roof tanks with drip rings under the gaging platformor sampling area, inspect for plugged drain return to the tank.

1.5.9 Emergency Roof DrainsInspect vapor plugs for emergency drain: that seal fabricdiscs are slightly smaller than the pipe ID and that fabricseal is above the liquid level.

1.5.10 Removable Roof Leg RacksCheck for leg racks on roof.

1.5.11 Vacuum BreakersReport size, number, and type of vacuum breakers. Inspectvacuum breakers. If high legs are set, check for setting ofmechanical vacuum breaker in high leg position.

1.5.12 Rim Ventsa. Check condition of the screen on the rim vent cover.

b. Check for plating off or removal of rim vents wherejurisdictional rules do not permit removal.

1.5.13 Pontoon Inspection Hatches

1.6 Accessways (See Figure 1000-9 Item 2.12)

TAM10008.WPFig. 1000-8 Tank In-Service Inspection Checklist (6 of 6)API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991. Reprinted Courtesy of the American Petroleum Institute.)


1000-54 March 1993


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Specific LocationCheck if


2.1 OVERVIEWa. Check that tank has been cleaned, is gas free, and safe for

entry.b. Check that the tank is completely isolated from product lines,

all electrical power, and steam lines.c. Check that roof is adequately supported, including fixed roof

structure and floating roof legs.d. Check for presence of falling object hazards, such as

corroded-through roof rafters, asphalt stalactites, and trappedhydrocarbons in unopened or plugged equipment orappurtenances, ledges, etc.

e. Inspect for slipping hazards on the bottom and roof decks.f. Inspect structural welds on accessways and clips.g. Check surfaces needing inspection for a heavy-scale buildup

and check weld seams and oily surfaces where welding is tobe done. Note areas needing more cleaning, including blasting.

2.2 TANK EXTERIORa. Inspect appurtenances opened during cleaning such as lower

floating swing sheave assemblies, nozzle interiors (afterremoval of valves).

b. Hammer test or ultrasonically test the roof.c. Enter and inspect the floating roof pontoon compartments.2.3 BOTTOM INTERIOR SURFACEa. Using a flashlight held close to and parallel to the bottom

plates, and using the bottom plate layout as a guide, visuallyinspect and hammer test the entire bottom.

b. Measure the depth of pitting and describe the pittingappearance (sharp-edged, lake-type, dense, scattered, etc.).

c. Mark areas requiring patching or further inspection.d. Mark locations for turning coupons for inspection.e. Inspect all welds for corrosion and leaks, particularly the

shell-to-bottom weld.f. Inspect sketch plates for corrosion.g. Locate and mark voids under the bottom.h. Record bottom data on a layout sketch using the existing

bottom plates as a grid. List the number and sizes of patchesrequired.

i. Vacuum test the bottom lap welds.j. Hammer test or ultrasonically examine any slightly discolored

spots or damp areas.k. Check for reinforcing pads under all bottom attached clips,

brackets, and supports.l. Inspect floating roof leg pads for pitting or cutting, and

excessive dimpling (indicating excessive loading).m. Check the column bases of fixed roof supports for adequate

pads and restraining clips.

TAM10009.WPFig. 1000-9 Tank Out-of-Service Inspection Checklist (1 of 11)(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991. Reprinted Courtesy of the American Petroleum Institute.)


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n. In Earthquake Zones 3 and 4, check that roof supports are notwelded down to the tank bottom, but are only restrainedfrom horizontal movement.

o. Check area beneath swing line cable for indications of cablecutting or dragging.

p. Mark old oil and air test connection for removal and patching.q. Identify and report low areas on the bottom that do not drain

adequately.r. Inspect coating for holes, disbonding, deterioration, and

discoloration.2.4 SHELL SEAMS AND PLATEa. On cone up bottoms, closely inspect and gage the depth of

metal loss on the lower 2 to 4 inches of the shell (area ofstanding water).

b. Measure the depth of pitting on each course.c. Inspect and estimate the amount of metal loss on the heads of

rivets and bolts.d. Inspect shell-to-bottom riveted lap joints.e. Inspect for vertical grooving damage from seal assembly

protrusions.f. Inspect existing protective coatings for damage, deterioration,

and disbonding.g. Check for areas of rubbing (indicating too much pressure by

the seal assembly shoes or inadequate annular space).h. Visually inspect the shell plates and seams for indications of

leakage.i. If the shell has riveted or bolted seams, record the leak

locations by film or chart in case the locations are lostduring surface preparation for painting.

j. Measure annular space at 40-foot intervals.

k. Survey the shell to check for roundness and plumb.2.5 SHELL-MOUNTED OVERFLOWSa. Inspect overflow for corrosion and adequate screening.b. Check location of overflow that it is not above any tank

valves or equipment.2.6 ROOF INTERIOR SURFACE2.6.1 Generala. Visually inspect the underside surface of the roof plates for

holes, scale buildup, and pitting.b. Hammer test or ultrasonically examine to check for thin areas,

particularly in the vapor space of floating roofs and at edgeof roof on cone roof tank.

Fig. 1000-9 Tank Out-of-Service Inspection Checklist (2 of 11)(API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, First Edition, January 1991. Reprinted Courtesy of the American Petroleum Institute.)


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c. Check all clips, brackets, braces, etc., welded to the roof deckplate for welded reinforcing pads and see that they have notbroken free.

d. If no pad is present, penetrant test for cracking of the weld ordeck plate.

e. Inspect the protective coating for breaks, disbondment, anddeterioration.

f. Spark test the interior surface coating if recoating is notplanned.

2.6.2 Fixed Roof Support Structurea. Inspect the support columns for thinning in the upper 2 feet.b. On API columns (two channels welded together) check for

corrosion scale breaking the tack welds, unless the jointbetween the channels is completely seal welded.

c. Check that the reinforcing pad on the bottom is seal welded tothe tank bottom with horizontal movement restraining clipswelded to the pad.

d. Determine if pipe column supports are concrete filled or openpipe. If open pipe, check for a drain opening in the bottomof the pipe.

e. Inspect and gage rafters for thinning, particularly near thecenter of the roof. Report metal loss.

f. Check for loose or twisted rafters.g. Inspect girders for thinning and check that they are attached

securely to the top of the columns.h. Report if the columns have cross-bracing in the area between

the low pumpout and top of the shell (for future internalfloating roof installation).

i. Inspect and report presence of any roof-mounted swing linebumpers.

j Photograph the roof structure if no rafter layout drawing exists.2.7 FIXED ROOF APPURTENANCES2.7.1 Inspection and Light Hatchesa. Inspect the hatches for corrosion, paint and coating failures,

holes, and cover sealing.b. On loose covers, check for a safety chain in good condition.c. On light hatches over 30 inches across, check for safety rods.d. Inspect the condition of the gaskets on bolted or latched down

hatch covers.2.7.2 Staging Support Connection

Inspect the condition of the staging support for corrosion.2.7.3 Breathers and Ventsa. Inspect and service the breather.b. Inspect screens on vents and breathers.2.7.4 Emergency P/V Hatches



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a. Inspect and service pressure/vacuum hatches. (Setting shouldbe high enough to prevent chattering of breather duringnormal operation. See breather manufacturer’s guide.)

b. Inspect liquid seal hatches for corrosion and proper liquid levelin the seal.

2.7.5 Sample Hatcha. Inspect sample hatch for corrosion.b. Check that the cover operates properly.c. If the tank has no gagewell, check for a hold off distance

marker and check measurement.2.8 FLOATING ROOF2.8.1 Roof Decka. Hammer test the area between roof rim and shell. (If access

for hammer testing is inadequate, measure the distance fromthe bottom edge of the roof to the corroded area and thenhammer test from inside the pontoon.)

b. In sour water service, clean and test all deck plate weld seamsfrom cracking unless the lower laps have been seal welded.

c. Check that either the roof drain is open or the drain plug inthe roof is open in case of unexpected rain.

d. On flat bottomed and cone down bottom roof decks, check fora vapor dam around the periphery of the roof. The damshould be continuous without break to prevent escape ofvapors to the seal area from under the center of the roof.

2.8.2 Floating Roof Pontoonsa. Visually inspect each pontoon for liquid leakage.b. Run a light wire through the gooseneck vents on locked down

inspection hatch covers to make sure they are open.c. Inspect lockdown latches on each cover.d. Check and report if each pontoon is:

(1) Vapor tight (bulkhead seal welded on one side onbottom,sides, and top),

(2) Liquid tight (seal welded on bottom and sides only), or(3) Unacceptable (minimum acceptable condition is liquid

tight).2.8.3 Floating Roof Cutoutsa. Inspect underside of cutouts for mechanical damage.b. Inspect welds for cracks.c. Inspect plate for thinning, pitting, and erosion.d. Measure mixer cutouts and record plate thickness for future

mixer installation or replacement.Plate thickness

2.8.4 Floating Roof Supportsa. Inspect fixed low and removable high floating roof legs for

thinning.



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b. Inspect for notching at bottom of legs for drainage.c. Inspect for leg buckling or belling at bottom.d. Inspect pinhole in roof guide for tears.e. Check plumb of all legs.f. Inspect for adequate reinforcing gussets on all legs through a

single portion of the roof.g. Inspect the area around the roof legs for cracking if there is no

internal reinforcing pad or if the topside pad is not welded tothe deck plate on the underside.

h. Inspect the sealing system on the two-position legs and thevapor plugs in the fixed low leg for deterioration of thegaskets.

i. On shell-mounted roof supports, check for adequate clearancebased on the maximum floating roof movement asdetermined by the position of the roof relative to thegagewell and/or counter-rotational device.

2.9 FLOATING ROOF SEAL ASSEMBLIES2.9.1 Primary Shoe Assemblya. Remove four sections of foam log (foam-filled seals) for

inspection, on 90-degree locations.b. Inspect hanger attachment to roof rim for thinning, bending,

broken welds, and wear of pinholes.c. Inspect clips welded to roof rim for thinning.d. Shoes: Inspect for thinning and holes in shoes.e. Inspect for bimetal bolts, clips, and attachments.f. Seal fabric: Inspect for deterioration, stiffening, holes, and

tears in fabric.g. Measure length of fabric from top of shoe to roof rim, and

check against maximum anticipated annular space as roofoperates.

h. Inspect any modification of shoes over shell nozzles, mixers,etc., for clearance.

i. Inspect shoes for damage caused by striking shell nozzles, mixers, etc.

2.9.2 Primary Toroidal Assemblya. Inspect seal fabric for wear, deterioration, holes, and tears.b. Inspect hold-down system for buckling or bending.c. Inspect foam for liquid absorption and deterioration.2.9.3 Rim-Mounted Secondariesa. Inspect the rim-mounted bolting bar for corrosion and broken

welds.b. Measure and chart seal-to-shell gaps.c. Visually inspect seal from below, looking for holes as evident

by light.d. Inspect fabric for deterioration and stiffness.e. Inspect for mechanical damage, corrosion, and wear on tip in

contact with shell.



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f. Inspect for contact with obstructions above top of shell.2.10 FLOATING ROOF APPURTENANCES2.10.1 Roof Manwaysa. Inspect walls of manways for pitting and thinning.b. On tanks with interface autogages, check seal around gage

tape cable and guide wires through manway cover.c. Inspect cover gasket and bolts.2.10.2 Rim Venta. Check rim vent for pitting and holes.b. Check vent for condition of screen.c. On floating roof tanks where the environmental rules require

closing off the vent, check the vent pipe for corrosion at thepipe-to-rim joint and check that the blinding is adequate.

2.10.3 Vacuum Breaker, Breather Typea. Service and check operation of breather valve.b. Check that nozzle pipe projects no more than 1/2-inch below

roof deck.c. Inspect reinforcing pad and pad welds.2.10.4 Vacuum Breaker, Mechanical Type

Inspect the stem for thinning. Measure how far the vacuumbreaker cover is raised off the pipe when the roof is restingon high or low legs.:On high legsOn low legs

2.10.5 Roof Drains: Open Systems, Including EmergencyDrains

a. Check liquid level inside open roof drains for adequatefreeboard. Report if there is insufficient distance betweenliquid level and top of drain.

b. If tank comes under Air Quality Monitoring District rules,inspect the roof drain vapor plug.

c. If emergency drain is not at the center of the roof, check thatthere are at least three emergency drains.

2.10.6 Closed Drain Systems: Drain Basinsa. Inspect for thinning and pitting.b. Inspect protective coating (topside).c. Inspect basin cover or screen for corrosion.d. Test operation of check valve.e. Check for presence of check valve where bottom of basin is

below product level.f. Inspect drain basin(s) to roof deck welds for cracking.g. Inspect drain basin(s) outlet pipe for adequate reinforcement to

roof deck (including reinforcing pad).2.10.7 Closed Drain Systems: Fixed Drain Line on Tank

Bottom



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a. Hammer test fixed drain line on tank bottom for thinning andscale/debris plugging.

b. Inspect supports and reinforcing pads for weld failures andcorrosion.

c. Check that pipe is guided, not rigidly locked to supports, toavoid tearing of tank bottom plate.

2.10.8 Closed Drain Systems: Flexible Pipe Draina. Inspect for damage to exterior of pipe.b. Check for obstructions that pipe could catch on.c. Inspect shields to protect pipe from snagging.d. Inspect results of hydrotest on flexible roof drain system.2.10.9 Closed Drain Systems: Articulated Joint Draina. Hammer test rigid pipe in flexible joint system for thinning

and scale/debris plugging.b. Inspect system for signs of bending or strain.c. Inspect results of system hydrotest.d. Inspect landing leg and pad.2.10.10 Autogage System and Alarmsa. Check freedom of movement of tape through autogage tape

guide.b. Inspect sheaves for freedom of movement.c. Test operation checker.d. Inspect tape and tape cable for twisting and fraying.e. Test the tape’s freedom of movement through guide sheaves

and tape guide pipe.f. On open-top tanks, check that gate tapes with cables have no

more than one foot of tape exposed with float at lowest point.g. Check float for leakage.h. Test float guide wire anchors for spring action by pulling on

wire and releasing.i. Inspect floatwells in floating roofs for thinning and pitting of

walls just above the liquid level.j. Check that the autogage tape is firmly attached to the float.k. Inspect the tape cable and float guide wire fabric seals through

the float well cover.l. Inspect the bottom guide wire attachment clip: inspect for a

temporary weighted bar instead of a permanent welded-downclip.

m. Inspect board-type autogage indicators for legibility andfreedom of movement of indicator.

n. Measure and record these distances to determine if sealdamage will occur if tanks is run over:(1) From shell top angle to underside of tape guide system.(2) From liquid level on floating top to top of secondary seal.

o. Identify floating roofs where the tape is connected directly tothe roof.



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p. Overfill alarm: Inspect tank overfill prevention alarm switchesfor proper operation.

2.11 COMMON TANK APPURTENANCES2.11.1 Gagewella. Inspect gagewell pipe for thinning at about two-thirds distance

above the bottom: look for thinning at the edge of the slots.b. Check for corrosion of the pipe joint. Check that sample cords,

weights, thermometers, etc., have been removed from the pipe.c. Check for cone at bottom end of pipe about 1 foot above the

bottom.d. Check condition of well washer pipe and that its flared end is

directed at the near side of the hold-off pad.e. Check that supports for gagewell are welded to pad or to shell

and not directly to bottom plate.f. Check operation of gagewell cover.g. Check presence of a hold-off distance marker in well pipe and

record hold-off distance. Hold-off Distance:h. Identify and report size and pipe schedule, and whether pipe is

solid or slotted. Report slot size.i. Check that the hold-off distance plate is seal welded to the

bottom and that any gagewell supports are welded to theplate and not directly to the bottom.

j. Inspect vapor control float and cable.k. Check for presence and condition of gagewell washer.l. Check for bull plug or plate blind on gagewell washer valve.m. Inspect gagewell guide in floating roof for pitting and thinning.n. Inspect the guide rollers and sliding plates for freedom of

movement.o. Inspect condition of gagewell pipe seal system.p. On black oil and diesel services: if gagewell is also used for

sampling, check for presence of a thief- and gage-type hatchto avoid spillage.

q. Visually inspect inside of pipe for pipe weld protrusions whichcould catch or damage vapor control float.

2.11.2 Sampling Systems: Roof Sample Hatchesa. Inspect roof-mounted sample hatches for reinforcing pads and

cracking.b. Inspect cover for operation.c. For tanks complying with Air Quality Monitoring District rules,

inspect sample hatch covers for adequate sealing.d. Check horizontal alighnment of internal floating roof sample

hatches under fixed roof hatches.e. Inspect the sealing system on the internal floating roof sample

hatch cover.f. Inspect floating roof sample hatch cover recoil reel and rope.2.11.3 Shell Nozzlesa. Inspect shell nozzles for thinning and pitting.



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b. Inspect hot tap nozzles for trimming of holes.c. Identify type of shell nozzles.d. Identify and describe internal piping, including elbow up and

elbow down types.2.11.4 For Nozzles Extended Into the Tanka. Inspect pipe support pads welded to tank bottom.b. Inspect so see that pipe is free to move along support without

strain or tearing action on bottom plate.c. Inspect nozzle valves for packing leaks and damaged flange

faces.d. Inspect heater steam nozzle flanges and valves for wire cutting.e. Report which nozzles have thermal pressure relief bosses and

valves.f. In internal elbow-down fill line nozzles, inspect the wear plate

on the tank bottom.g. On elbow-up fill lines in floating roof tanks, check that

opening is directed against underside of roof, not againstvapor space. Inspect impact area for erosion.

2.11.5 Diffusers and Air Rolling Systemsa. Inspect diffuser pipe for erosion and thinning.b. Check holes in diffuser for excessive wear and enlargement.c. Inspect diffuser supports for damage and corrosion.d. Check that diffuser supports restrain, not anchor, longitudinal

line movement.e. Inspect air spiders on bottom of lube oil tanks for plugging

and damaged or broken threaded joints.2.11.6 Swing Linesa. Inspect flexible joint for cracks and leaks.b. Scribe the flexible joint across the two moving faces and raise

end of swing line to check the joint’s freedom of movement,indicated by separation of scribe marks.

c. Check that flexible joints over 6 inches are supported.d. Inspect the swing pipe for deep pitting and weld corrosion.e. Loosen the vent plugs in the pontoons and listen for a vacuum.

Lack of a vacuum indicates a leaking pontoon.f. Check the results of air test on pontoons during repairs.g. Inspect the pontoons for pitting.h. Inspect the pull-down cable connections to the swing.i. Inspect the condition of the bottom-mounted support, fixed

roof limiting bumper, or shell-mounted limiting bumper forwood condition, weld and bolt corrosion, and seal welding tobottom or shell.

j. Inspect safety hold-down chain for corrosion and weak links.k. Check that there is a welded reinforcing pad where the chain

connects to the bottom.



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l. If the floating swing in a floating or internal floating roof tankdoes not have a limiting device preventing the swing fromexceeding 60 degrees, measure and calculate the maximumangle possible with the roof on overflow.Max. angle on overflow (If the calculated angle exceeds 65degrees, recommend installation of a limiting bracket.)

m. Inspect pull-down cable for fraying.n. Inspect for three cable clamps where cable attaches to end of

swing line (single-reeved) or to roof assembly (double-reeved). Inspect sheaves for freedom of movement.

o. Inspect winch operation and check the height indicator forlegibility and accuracy.

p. Inspect bottom-mounted sheave assembly at end of pontoon forfreedom of rotation of sheave.

q. Inspect shell-mounted lower sheave assembly for freedom ofrotation of sheave, corrosion thinning, and pitting of sheavehousing.

r. Inspect upper sheave assembly for freedom of movement ofsheave.

s. Inspect the cable counterbalance assembly for corrosion andfreedom of operation.

2.11.7 Manway Heater Racksa. Inspect the manway heater racks for broken welds and bending

of the sliding rails.b. Measure and record the length of the heater of the track.2.11.8 Mixer Wear Plates and Deflector Standsa. Inspect bottom and shell plates and deflector stands.b. Inspect for erosion and corrosion on the wear plates. Inspect

for rigidity, structural soundness, corrosion, and erosion ofdeck plates and reinforcing pads that are seal welded to thebottom under the deflector stand legs.

c. Measure for propeller clearance between the bottom ofdeflector stand and roof when the roof is on low legs.

2.12 ACCESS STRUCTURES2.12.1 Handrailsa. Identify and report type (steel pipe, galvanized pipe, square

tube, angle) and size of handrails. Inspect for pitting andholes, paint failure.

b. Inspect attachment welds.c. Identify cold joints and sharp edges. Inspect the handrails and

midrails.d. Inspect safety drop bar (or safety chain) for corrosion,

functioning, and length.e. Inspect the handrail between the rolling ladder and the gaging

platform for a hazardous opening when the floating roof is atits lowest level.

2.12.2 Platform Framea. Inspect frame for corrosion and paint failure.



1000-64 March 1993

TAM10009.WP


Item: Report #:



b. Inspect the attachment of frame to supports and supports totank: for corrosion and weld failure.

c. Check reinforcing pads where supports are attached to shell orroof.

d. Inspect the surface that deck plate or grating rests on, forthinning and holes.

e. Check that flat-surface to flat-surface junctures are seal welded.2.12.3 Deck Plate and Gratinga. Inspect deck plate for corrosion-caused thinning or holes (not

drain holes) and paint failure.b. Inspect plate-to-frame weld for rust scale buildup.c. Inspect grating for corrosion-caused thinning of bars and failure

of welds.d. Check grating tie down clips. Where grating has been

retrofitted to replace plate, measure the rise of the step belowand above the grating surface and compare with other riserson the stairway.

2.12.4 Stairway Stringersa. Inspect spiral stairway stringers for corrosion, paint failure, and

weld failure. Inspect attachment of stairway treads to stringer.b. Inspect stairway supports to shell welds and reinforcing pads.c. Inspect steel support attachment to concrete base for corrosion.2.12.5 Rolling Laddera. Inspect rolling ladder stringers for corrosion.b, Identify and inspect ladder-fixed rungs (square bar, round bar,

angles) for weld attachment to stringers and corrosion,particularly where angle rungs are welded to stringers.

c. Check for wear and corrosion where rolling ladder attaches togaging platform.

d. Inspect pivot bar for wear and secureness.e. Inspect operation of self-leveling stairway treads.f. Inspect for corrosion and wear on moving parts.



March 1993 1000-65

1100 MAINTENANCE

Abstract

This section discusses the general considerations and philosophy of maintenance for tanks. Included are proceduresfor shutdown planning, tank cleaning, replacement and repair of major components, in-service repairs, reratingand retiring corroded tanks, and the application of coatings and paint. A tank shutdown checklist is also attached.

Contents Page

1110 Shutdown Planning 1100-2

1120 Tank Cleaning 1100-2

1121 Tank Entry Precautions

1122 Company and Industry Documents

1123 Operating Methods to MinimizeSediment

1124 Estimating Sludge Quantity

1125 Determining Sludge Content

1126 Sediment Types and RemovalProcedures

1127 Separating Salvable fromNon-salvable Material in Sludge

1128 Final Cleaning

1129 Levels of Cleaning Required

1130 Major Component Replacementor Repair

1100-7

1131 Bottom Replacement or Repair

1132 Shell Repair

1133 Fixed Roof Repair or Replacement

1134 Steel Floating Roof Repair orReplacement

1135 Internal Floating Roof Retrofit,Replacement or Repair

1136 Seal System Repair or Replacement

1140 In-service Repairs 1100-13

1141 Safety Guidelines for In-service Workon Tanks

Page

1142 In-service Shell Repairs

1143 Hot Tapping of Tanks in Service

1144 Fixed Roof Repairs

1145 Floating Roof Repairs

1146 Floating Roof Seal Systems

1147 Insulation

1148 Appurtenances

1150 Rerating and Retiring CorrodedTanks

1100-18

1151 Gaging the Shell Thickness

1152 Calculating the Reduction of the SafeOil Height Required forContinued Operation

1153 Determining the Effect on Operations

1154 Examining Alternatives forMaintaining the Existing Capacity

1155 Economic Justification for Repair,Replacement, Reallocation orRerating

1160 Coating and Painting 1100-20

1161 Exterior Coatings

1162 Internal Coatings

1163 Inspection

1170 Tank Settlement 1100-21

1180 References 1100-34

1190 Tank Shutdown Checklist 1100-35

Tank Manual 1100 Maintenance

June 1994 1100-1

T O

C O N T E N T S

1110 SHUTDOWN PLANNING

Attached at the end of this section is a sample tankshutdown checklist (Figure 1100-1) from the RichmondRefinery. It lists the typical work done during a tankshutdown and can be utilized by the engineer or com-pany representative to plan the work.

El Segundo has a much more detailed worklist whichcan be obtained by calling their Tank Maintenancegroup.

Note: Figure 1100-1 appears at end of thissection

1120 TANK CLEANING

Tanks are cleaned for various reasons:

• Slop tanks which accumulate heavy sediment needto be cleaned periodically in order to continue ef-ficient operation.

• Gasoline or jet fuel tanks sometimes must becleaned in order to meet the product specifications.

• Tanks coming out of service for maintenance mustbe cleaned and gas freed before they can be en-tered.

This section gives general guidance on both in-serviceand out-of-service tank cleaning and refers to variousother Company and industry documents on this subject.It is intended to be used as a guide—however, localconditions and experience influence the actual proce-dures used.

1121 Tank Entry Precautions

Both OSHA’s confined space entry rules codified in29CFR1910.146, as well as the 5th edition of APIStandard 2015, apply to all tank entry conditions. Sincethere are standards only, detailed checklists such aspre-planning checklists, isolation and tagging proce-dures, work plans, equipment for listing and monitor-ing must be worked out in the planning phases of thejob.

1122 Company and Industry Documents

Different Company organizations have prepared guide-lines for venting and cleaning tanks, some of which arelisted below. Copies of Company publications are

available through each department; the API publicationmay be obtained directly from API (their address isgiven in Section 100).

1. API RP 2015, “Cleaning Petroleum StorageTanks.”

2. Fire Prevention Manual, “Fire Protection ThroughInspection and Maintenance.”

3. Manufacturing Department, Chevron U.S.A.

a. ES-666, Cleaning and Repair of Tanks (ElSegundo Refinery)

b. Operating Standard AR-9240, Cleaning Tanks(Richmond Refinery)

c. Operating Standard AR-9241, Cleaning andRepairing Leaded Gasoline Tanks (RichmondRefinery)

4. Marketing Department, Chevron U.S.A., Opera-tions Standard, Section IX, Part D, “Tank CleaningInstructions.”

5. Pipe Line Department, Chevron U.S.A., Safe Prac-tice Regulations, 5.011.2 “Tank Cleaning.”

1123 Operating Methods to MinimizeSediment

This section discusses equipment and procedures to usewhile the tank is in operation to reduce the amount ofsludge to be removed.

Variable Angle Mixers

Variable angle (or swivel) mixers have been used forcleaning gas oil, heavy oil, and crude tanks. The flowpatterns created by these mixers significantly reduceoily waste disposal problems. The changing patterns re-duce the areas of sediment buildup and keep the sedi-ments in suspension with the stored fluid or with aflush fluid. They are then removed by pumping themixture out of the tank. When compared to conven-tional manual cleaning, this method may be faster andmore economical.

A variable angle mixer has a ball-type stuffing boxmounted in a special manway cover that allows angularmovement. Figure 1100-2 shows the variable anglemixer, which has 60-degree angular adjustment. Theflow patterns established by the normal fixed anglemixer allow sediment accumulations in dead spots(Figure 1100-3). The variable angle mixer can directflow patterns to almost any area of the tank and elimi-

1100 Maintenance Tank Manual

1100-2 June 1994

nates most dead spots. (Small-diameter tanks may notneed a variable angle mixer). The advantages of usingthe variable angle mixer are:

1. Valuable oil is recovered from oily solids and iseasily transported to the refining units.

2. Tank capacity is increased because solid wastedoes not accumulate in the tank.

3. Tank downtime is reduced.

4. Very little solid waste must be disposed of.

5. Overall cleaning costs are reduced.

6. Cleaning operation is essentially all done fromoutside the tank.

7. Exposure of people to the tank’s atmosphere canbe minimized or eliminated.

8. Recovered oil may pay for the cleanup costs, suchas: mixer cost, labor costs, etc.

9. The costs for variable angle and fixed angle mix-ers are very competitive.

Variable angle mixers are often used during normal op-eration to minimize sludge buildup. These mixers canbe purchased with a motor drive to change the mixerposition on a continuous cycle, eliminating the need formanual adjustment. Section 670 discusses the sizing re-quirements for mixers.

Procedure for Using a Variable Angle Mixer toClean a Tank

The following is a general procedure for the use of avariable angle mixer prior to taking a tank out of serv-ice. This procedure is being used less frequently be-cause 1) a large amount of solvent is required and 2)the oil/solids separation systems are much improved.

1. Determine the composition of the sediment. Thisanalysis is the basis for selecting the solvent forcleaning.

TAM11002.GEM

Fig. 1100-2 Variable Angle Mixer with 60-degree Angular Adjustment

TAM11003.GEM

FIXED ANGLE MIXER VARIABLE ANGLE MIXER

Fig. 1100-3 Sludge Buildup for Fixed Angle Mixer Compared to Variable Angle Mixer


June 1994 1100-3

2. Add the solvent to the tank to at least 6 feet abovethe mixer. This is the minimum level of liquid dur-ing operation of the mixer to avoid cavitation ofthe fluid while mixing.

3. The mixers are run from 5 to 15 days in positionsranging from 30 degrees right to 30 degrees left.Manufacturers recommend that the position bechanged every 24 hours (Company practice hasfrequently been to change the position every 8hours).

4. The spent solvent is pumped out of the tank andmay be refined. More than one cleaning cycle maybe required to thoroughly clean a tank.

5. If the tank is not satisfactorily cleaned, then sedi-ment may need to be removed mechanically.

Figure 1100-4 shows typical mixer arrangements fordifferent size tanks. Arrangements will vary dependingon the type of tank bottom, tank volume, stock prop-erties, maintenance access and power available. Expe-rience suggests a 50-hp mixer normally has thecapacity to clean a tank up to 150-foot diameter. Fortanks of 150-foot diameter and larger, consider usingtwo or more mixers. Small tanks would require a mixerof about 25 hp, depending on the stored fluid.

Mixers used for both cleaning and blending serviceusually require more horsepower than those requiredfor cleaning only. Mixer size and numbers should beverified by analysis of the sludge to be removed andconsultation with the manufacturer.

Hydraulic Jet Nozzles

Hydraulic jet nozzles can be installed inside a tank toperform the same function as the variable angle mixer.These nozzles require both pumping pressure and vol-ume. Both the jet nozzles and the mixers perform thesame function, injecting energy into the tank to removesediment from the bottom and suspend it temporarilyin the liquid. Section 670 discusses mixing nozzles inmore detail.

1124 Estimating Sludge Quantity

After as much stock is drained from the tank as pos-sible, a mixture of oil, water, and solids remains. Thismixture is referred to as sludge or sediment. You musthave a good understanding of the type and quantity ofsludge to be removed from the tank to make sound de-cisions regarding:

• Sludge removal procedures

TAM11004.GEM

Fig. 1100-4 Typical Mixer Arrangement forDifferent Size Tanks


1100-4 June 1994

• The cost of the job

• Waste disposal requirements

This section discusses the methods for estimating thequantity of sludge.

Gaging Sludge Depth

Two special tips which replace the plumb bob on thetypical operator’s reel gage can be fabricated and usedto measure the sediment level. The tip to determine thedistance from the gaging point to the tank bottom is along, sharp-ended probe weighing 5 to 8 pounds. Itsweight combined with the reduced friction area is usedto penetrate the sludge. The second tip should weighabout 1/2 to 1 pound and have a wide disc at the bot-tom. This tip is designed to sink through the stock butto be too light to rapidly sink into the bottom sludge.Take several readings of the bottom and sludge levelsin different locations to obtain an accurate profile.These readings can be taken through the gage well,roof hatches, and roof legs, if necessary, using propersafety procedures.

Visual Survey Through Open Shell Manway

After the tank is pumped out and the shell manway isopened, use natural sunlight and a large mirror, or astrong spotlight, to visually inspect the sediment. Usinginternal appurtenances of known height, such as por-tions of the roof drain fixed pipe, bottom supports forswing lines, or fixed roof column supports, estimatesludge depth. If necessary, the depth can be closely es-timated by use of a survey level (with allowance forthe bottom slope). As many readings should be madeas reasonable, at different locations.

From the readings, use a simple volume calculation toestimate the quantity of sludge to be removed. Caution:sludge rarely builds up evenly over the entire bottom.

1125 Determining Sludge Content

We collect and test sludge samples to know whichwaste disposal requirements apply and also what haz-ards personnel may be exposed to while ridding a tankof sediment.

Tanks Unsafe to Enter

For tanks which are unsafe to enter, samples will haveto be taken from the manway(s). Each phase (solid,water and oil) will have to be sampled separately ac-cording to the following instructions.

1. If the liquid layer is deep enough to collect a sam-ple, collect a 1-quart sample of each liquid phase(oil and water) from any one manway. Label thedepth of each liquid layer sampled. If the liquidlayer is too shallow to get a sample (less than 1inch) ignore the liquid and sample only the solids.

2. Sample the solid phase from all available man-ways using the solids sampler. Collect equalamounts of sample from each manway until 1/2gallon has been collected. Include the depth of thesolids layer on the tag.

Tanks Safe To Enter

For tanks where entry is possible, the solids and liquidsshould be sampled according to the following proce-dure:

1. Collect a sample of each liquid layer as outlinedin Step 1 above.

2. Estimate the number of barrels of solids remainingin the tank according to the following formula:

Barrels left = 0.14 x d2 x h

where:

d = tank diameter (ft)

h = height of waste (ft)

3. Determine the number of sample points to be in-cluded in the composite sample according to thefollowing table.

Barrels Left No. of Sample Points

0-3000 33000-6000 46000-12,000 512,000-20,000 6

Collect the samples at the points shown in Figure1100-5. If only three points are to be sampled, sampleat points 1, 2 and 3. Prepare a 1/2-gallon compositesample by collecting equal amounts at each samplepoint.

Testing Sludge Content

Consult with your local waste disposal organization todetermine the specific tests to run.


June 1994 1100-5

1126 Sediment Types and RemovalProcedures

Most sediments are normally one of four types: pum-pable sediment, non-pumpable sediment, scale, andcatalyst fines. However, there can be combinations ofthese types to remove.

Pumpable Sediment

This sediment can be pumped out of the tank by useof a vacuum truck or, if necessary, diaphragm pumps.Manual methods (squeegees) may be required to movethe sediment to the hose. Many crudes, gas-oils, etc.,are typical of this class. Sometimes steam lances canturn non-pumpable sediment into pumpable sediment.Solvents and mixers or jet nozzles, and heat, are alsopotential methods.

Non-pumpable Sediment

Residual sediment that cannot be pumped but must bemined, scraped, or shoveled is very expensive to re-move. On larger tanks, entering the tank with mechani-cal equipment (front-end loaders, or small bulldozers)may be more economical even with the need for cut-ting a door sheet in the shell or roof. Asphalt, asphalti-nes, and baked sediment (from tank heaters) are typicalexamples of non-pumpable sediment.

Scale

Scale corrosion product, mostly from the shell but alsofrom the roof and bottom, is the third category of sedi-ment to be removed. This scale can contain trapped

stock, water, and possibly hazardous gases. Typicalservices that produce scale include gasoline, thinnersand solvents, jet fuels and pentane-hexanes. Until allscale has been removed, personnel should wear full-body protective equipment, and the tank interior shouldbe continuously tested for explosive gas, aromatics,and H2S.

Normally the scale can be moved by water (hydroblast-ing) and pumped out by vacuum truck or diaphragmpump. Caution: if the scale is over 1 to 2 inches deep,movement by water can release trapped gas causing anexplosive mixture to form in the vapor space. If waterwashing cannot be done, it may be necessary to re-move the majority of the scale by bucket and shovelafter the tank is safe to enter.

Catalyst Fines

Refineries with catalytic crackers will usually have oneor more tanks containing a large amount of catalystfines. Catalyst fines are usually too heavy for easypumping and too soft for mining. Mixers and regularcycling of the tank contents through a solids extractionsystem while the tank is in service are recommendedto keep the catalyst fine level low. Normally tanks withcatalyst fines are cleaned by shoveling the fines intothe suction of a vacuum truck or conveyor belt. Enter-ing a tank with fines can be hazardous. The fines trapcycle oil. Piles of fines can collapse causing a hazard-ous flow of cycle oil and fines.

Protection Against Spillage

Cleaning a tank can result in material being spilled onthe ground outside of the tank unless precautions aretaken. This spillage can be avoided by doing the fol-lowing:

Frequently Cleaned Tanks. For tanks which must becleaned frequently (more than once every 5 years), de-sign the tank with facilities to impound any spills:

• Flush-mounted cleanout connection(s) designed toAPI 650.

• A concrete cleanout basin around each connectionto contain any spillage.

Tanks Cleaned Less Often. For tanks which are onlycleaned as part of their scheduled maintenance shut-down, the above facilities are normally not justified.Instead, the cleaning contractor should build a tempo-rary dike around the manway(s) used for cleanout andline the area with plastic to contain spills.

TAM11005.GEM

Fig. 1100-5 Sludge Sampling Locations


1100-6 June 1994

1127 Separating Salvable fromNon-salvable Material in Sludge

Heavy hydrocarbons and sediment normally drop to thebottom of a tank. Simple removal and disposal of thismaterial is uneconomical. Our objective should be tomaximize oil recovery and minimize hazardouswaste disposal.

As sludge material is removed from a tank, it can beprocessed through equipment to separate the usable oilfrom the water and from the unusable solids. Severaltypes of equipment are available to do this work. Repu-table companies furnishing the equipment can test rep-resentative samples of the sediment removed from thetank and determine the best system to use. They nor-mally require a 1 to 5 gallon sample. Care should betaken to obtain a true sample of the sediment and notthe stock above the sediment. Typical equipment usedfor separation includes: rockers, centrifuges, chemicaltreating tanks, shakers, settling tanks, presses, filters,and heavy metal extraction units.

Procedures and equipment for separation and for haz-ardous waste management are continually being up-dated. Vendor claims must be backed by proven results.We strongly recommend that you discuss your particu-lar requirements with other tank maintenance groups.Sometimes distant contractors with proven technologymay be more economical to use than local contractors.You can also consult CRTC’s tank specialist for newtechnology on waste processing.

1128 Final Cleaning

After the sediment is removed, a final cleaning mustoften be performed before maintenance work. Themethods and equipment used in the final tank cleaningprocess are determined by the type of contaminate andthe degree of cleanliness needed.

Non-oily Contaminate

This contaminate is primarily scale (corrosion product)with possibly some trapped hydrocarbons, especially ifthe tank has had a change of service. Typical servicesinclude gasoline, thinners, and some jet fuels. Usuallythe scale can be removed by pressure washing (200psi) or hydroblasting (6,000-10,000 psi). Very hard,tight and active scale may require abrasive blasting orultra high pressure (35,000-70,000 psi) hydroblasting.

Oily Contaminate

This contaminate is primarily hydrocarbon and may bea tightly bonded asphalt-like or greasy deposit. Typical

services include crude oil, recovered oil, and gas oil.Usually a pressure washer along with sprayed-on de-tergent will remove the contaminate. If scale is alsopresent or the baked on material is too hard and wellbonded, hydroblasting may be necessary. Oily surfacesshould never be cleaned by abrasive blasting. Oilcan be embedded in the metal surface by abrasiveblasting thereby causing major problems with futurecoating application.

1129 Levels of Cleaning Required

Figure 1100-6 gives required levels of cleaning.

1130 MAJOR COMPONENTREPLACEMENT OR REPAIR

This section discusses work to be done when tank isout-of-service. For in-service repairs, see Section 1140.

Objectives Level of Cleaning

• Change of serviceor remove sludge toimprove tank opera-tion or product qual-ity.

• Remove sludge. Nofinal cleaningrequired.

• Tank out-of-servicewell before its duedate. Quick visual in-spection requested;no repairs antici-pated.

• Remove sludge.Remove scale if itimpedes inspection.

• Tank out-of-serviceon normal mainte-nance interval (10years). Detailed in-spection needed.

• Remove sludge.Remove scale forthorough inspection.

• Welding requiredin the tank.

• Remove sludge.Remove scale.Clean oily film off ofmetal.

• Coating required. • Remove sludge.Clean oily film offmetal. Abrasiveblast surface to rec-ommended finish.

TAM11006.WP

Fig. 1100-6 Summary of Levels of Cleaning


June 1994 1100-7

1131 Bottom Replacement or Repair

This section discusses the justification for replacing abottom versus a less costly repair. It also gives guid-ance on the types of replacement bottoms along withthe repair methods available and where they are appli-cable.

Philosophy

Repair is recommended over replacement when:

• Corrosion and pitting are not severe and patchingor weld repairs can be accomplished economically.

• The maximum depth of unrepaired stockside pitsand underside pits will not exceed the plate thick-ness before the end of the next run. Figure 1100-7gives the procedure for determining the remaininglife of a bottom.

• Corrosion and pitting are localized to a specificarea (i.e., annular ring corrosion due to water stand-ing around the inside edge of the shell).

• Most of the pitting is underside, and externalcathodic protection is being installed to minimizethis pitting.

Procedure for Determining the Remaining Life of a Tank Bottom

Step 1 Gage bottom plate thickness in multiple locations where there is no bottom pittingobserved on the stockside or indicated on the underside. Average the readings.

Average Reading: ____ 0.inch

Step 2 Gage the depth of the deepest stockside pitting not to be patched during the shut-down and record.

Deepest Pitting: 0.___ inch

Step 3 Gage the depth of the deepest pit on the underside of the bottom by measuringturned coupons.

Deepest Pitting: 0.___ inch

Step 4 Determine whether the stockside bottom is to be protective coated. If it is, stocksidepitting rate in Step 5 is zero.

Yes_____ No_____

Step 5 Determine the following rates:

General Corrosion Rate: 0.___ inch/yrStockside Pitting Rate: 0.___ inch/yrUnderside Pitting Rate: 0.___ inch/yr

Step 6 Perform the following calculation:Remaining bottom general thickness: = 0. _____Less general bottom corrosion rate X years next operating run: = 0. _____Less deepest unrepaired stockside pitting: = 0. _____Less deepest underside pitting: = 0. _____Less stockside pitting rate X years next operating run: = 0. _____Less underside pitting rate X years next operating run: = 0. _____

Total ____

If total is equal to or less than zero, the bottom should be replaced.TAM11007.WP

Fig. 1100-7 Procedure for Determining the Remaining Life of a Tank Bottom


1100-8 June 1994

Repair Alternatives

Weld Repair and Plate Patching. These methods arefor repairing mechanical damage and stockside pitting.Patching is also done to repair openings in the bottomresulting from turning coupons. The following guide-lines are suggested:

1. Repair holes by welding on patches, rather than byspot welding.

2. Before welding, plug holes to prevent moisturefrom leaking into the tank from under the bottom.Normally, wood plugs are used, but anything thatwill stop the seepage long enough to complete theweld all around the patch is acceptable. Preventingmoisture leakage keeps the fillet weld on the patchfrom cracking.

3. Spot weld pits half way or more through the plateif the pit is not greater than 1 inch in diameter andis surrounded by substantially full thickness mate-rial. Shallower pits may be filled with special ep-oxy compounds, if necessary, pr ior to theapplication of internal coatings.

4. Patch pitted areas of larger than 1 inch diameterwith pieces of 1/4-inch plate full fillet welded allaround. Time can be saved by supplying patch ma-terial consisting of random-sized square and rec-tangular pieces with dimensions from 4 to 30inches sheared from scrap plate. Sheared patchesmust be small enough to pass through the shellmanway or existing opening.

Annular Ring Replacement. Water accumulatingaround the inside edge of the shell can cause acceler-ated corrosion on the bottom in this area. For tanksover 100 feet in diameter, it is often less costly to re-place the annular ring than the entire bottom. See Sec-tion 400 and API 650 for annular ring design andinstallation.

Laminate Reinforced Coating. Section 1160 discussesthe various internal coating systems available for tanks.Company Specification COM-MS-4738 is a standardspecification to use for thin film, glass flake, or lami-nate-reinforced coatings. Because properly appliedlaminates have some structural strength, they can be aneffective tool for prolonging the life of a tank bottomwhich has moderate underside corrosion. However,they must be used cautiously.

Laminates should not be used in the following situ-ations:

• Where a hole has worn through the bottom plate

• Where the bottom plate will hole through beforethe end of the next run and no leakage can be al-lowed

• Where general corrosion has caused loss of struc-tural strength in the annular ring area. A rule ofthumb is not to coat the annular ring if there is a20% general reduction in plate thickness over any2-square foot area of the annular ring

Thin Film or Glass Flake Coatings. Thin film or glassflake coatings can be used in conjunction with bottomrepairs or a new bottom to prolong the life of the bot-tom. They should not be put on over a bottom withsevere internal or external corrosion or pitting.

Section 1160 discusses the use of these coatings. Speci-fication COM-MS-4738 specifies the materials and ap-plication procedures. Section 100 of the CoatingsManual discusses in more detail the factors that affectthe type of coatings selected. Thin film coating is mosteffective when used with internal cathodic protection.See Maintenance Specification TAM-MN-3.

External Cathodic Protection. Cathodic protectioncan be used to stop underside bottom corrosion of ex-isting tanks. If there is no portland cement concreteslab, asphaltic concrete pavement, or penetration mac-adam pavement under the tank, properly appliedcathodic protection will almost always be effective inpreventing further corrosion. However, a concrete slabor pavement under the tank may make cathodic pro-tection ineffective.

An impermeable pavement will prevent the flow ofcathodic protective current to the bottom steel.Cathodic protection will be effective where there arepermeable areas or breaks in the pavement and willprevent moisture-caused corrosion at these locations.However, cathodic protection cannot eliminate corro-sion due to moisture migrating under the tank frompermeable to impermeable areas. Similarly, cathodicprotection cannot completely control corrosion causedby moisture penetration beneath the tank from the pe-riphery due to breathing. It is very difficult to deter-mine conclusively from short term field tests whethercathodic protection will be helpful for a specific situ-ation. Section 550 and the Corrosion Prevention Man-ual discuss cathodic protection in more detail.


June 1994 1100-9

Bottom Replacement

Maintenance Specification. A bottom replacementspecification, TAM-MN-1, is included in Volume 2 ofthis manual.

Types of Replacement Bottoms. The considerations inselecting a replacement bottom are generally the sameas for new construction. These are discussed in Sec-tions 100 and 520.

Secondary Containment and Leak Detection Bot-toms. If future leakage cannot be tolerated, then a ret-rofit bottom, which includes secondary containmentand leak detection, should be installed (see StandardDrawing GD-D1120, sheets 1 and 2). A membrane(HDPE) liner is placed over the existing steel bottomand overlaid with a concrete slab. The new steel bot-tom is then placed above the slab. This retrofit designworks best where you expect minimal bottom settle-ment. If large settlement is expected, a membrane linerwith a sand cushion over it and cathodic protectionsystem should be installed. The old steel bottom mayneed to be removed in this case due to the amount ofstorage volume lost to the sand cushion. This approachis generally not recommended because of the sandshifting and causing voids. (See Standard DrawingGD-S1121, sheets 1 and 2). Refer to Section 540 formembrane design and selection.

Non-leak Detection Bottoms. An important item toconsider when secondary containment and leak detec-tion are not included is that the new steel bottom willbe anodic to the old steel bottom. This galvanic effectaccelerates corrosion of the new bottom and has pro-duced bottom failures in as little as four years. There-fore, it is essential either to remove the old corrodedbottom before putting in the new bottom, or else toprovide a good dielectric shield to stop current flowbetween the two.

An asphalt pad between the old and new bottoms pro-vides a good dielectric shield, but it may not entirelystop water migration to the tank bottom. However, ina retrofit situation, there will be a semi-intact old bot-tom beneath the asphalt, and most of the tank settlingwill have already occurred, so the chance for successof asphalt is much greater than in the case of new con-struction. Therefore, if secondary containment is notrequired, asphalt may be a viable alternative. SeeTAM-EF-364 for asphalt pad foundation design.

Replacement Bottom Installation. The replacementbottom plates should be installed in accordance withAPI 650. Generally, the replacement sketch plates (bot-tom plates upon which the shell rests) or annular ring

plates are slid through a slot cut in the shell. The newbottom is continuously welded to the shell, both insideand outside, using fillet welds on the top. Intermittentfillet welds for strength are made between the new bot-tom and the lower part of the old shell. The weld sizeshould be enough to develop the full strength of thebottom plates in bending. Undercutting at the toe ofthe fillets should be avoided. Care must be taken to besure the new pad fully supports the new bottom nextto the shell.

Annular ring plates are butt welded together using a1/8 inch thick compatible backing strip, 2 inches wide,under the joint where it passes through the shell. In-side, the bottom plates are welded with a 1-1/4 inchlap and a full fillet lap weld as for new API tanks.Where no annular ring is required, the upper plate iscrimped to be level with the lower plates, and a grooveweld is made from the top penetrating to the backingstrip. In either case, it is necessary to notch (rat hole)the shell over this joint in the tank bottom to permitthe welder to make a good weld through the shell. SeeFigure 900-1 for details of the annular ring installationin a replacement bottom.

Section 900 discusses the critical areas to monitorwhen replacing a bottom and describes the normalstep-by-step replacement procedure.

1132 Shell Repair

Shell replacement is generally not economical becausereplacing a shell also requires roof replacement. How-ever, shells can be repaired within limitations and withcertain risks. Shell repair alternatives are listed below.

1. Replacement of Individual Plates. Individualplates are replaced usually to repair mechanicaldamage or to replace multiple shell nozzles orother openings.

2. Bottom Course Replacement. This repair typi-cally corrects for corrosion losses, and is com-pleted one plate at a time.

3. Upper Shell Course Replacement. This repair isusually used to correct internal vapor space corro-sion. It is more suitable for fixed roof tanks. Itmay or may not include roof replacement. Keepingthe shell in round and maintaining the tolerancesrequired for a floating roof are very difficult. How-ever, it has been accomplished when done withcare.


1100-10 June 1994

4. Upgrading Shell’s Earthquake Resistance. Youcan make the shell resistant to seismic-causedbuckling by 1) installing vertical wide flanges orbeams on the bottom two courses of the shell, or2) replacing the bottom shell course with thickerplate, one plate at a time. These repairs may beincluded with installation of a new annular ringunder the shell. Tanks built to API 650 revisionsafter 1979 should not require such a repairmethod. See Section 400 for more details on seis-mic design. Consult CRTC’s Civil and StructuralTeam or a structural engineer when consideringthis design. Note the first option cannot be usedto change safe oil height.

5. Reduction in Buckles (bumps and dents). Thiscan be done by installing a structural memberrolled to the proper radius and installed with theaid of a clip and winch. The buckle in the area ofthe repair will be reduced, but smaller buckles canbe expected on either side of the repair. On a float-ing roof tank this repair may enable the seal sys-tem to work properly. An alternative method is toreplace the area of the buckle with new platerolled and sized to the opening cut.

6. Door Sheets. These are cut in a shell to permitentry of mechanical equipment and to completemajor repairs or rebuilding of the tank. Qualifiedwelding procedures must be used for the materialinvolved, and corners of the replacement platesrounded to a radius equal to 5 to 10 times the platethickness to reduce stress concentrations. (SeeMaintenance Specification TAM-MN-2, DoorsheetRemoval and Reinstallation, in Volume 2 of thismanual).

7. Vertical Riveted Seam Repair. The joint effi-ciency of a lap riveted vertical shell seam is usu-ally about 0.64. This joint efficiency can beincreased to 0.75 by full fillet lap welding bothsides of the lapped seam plus seal welding of therivets. This is a difficult, costly procedure and nor-mally not justifiable unless the alternative is to re-tire the tank.

8. Sealing of Riveted Seams. Sometimes leakingseams are repaired by applying a sealant. This re-pair, which will not upgrade joint efficiency, iscovered in Maintenance Specification TAM-MN-7.

Refer to Sections 400 and 900 for information on tankshell design and construction. Section 1150 coversrerating and retiring of shells.

1133 Fixed Roof Repair or Replacement

The decision to replace or repair a fixed roof is nor-mally based on the condition of the supporting struc-ture. The most severe internal corrosion normallyoccurs on the roof deck near the shell and on the raf-ters near the center of the roof. If calipering the raftersat the center of the roof reveals adequate remainingmetal, only a portion of the roof deck may have to bereplaced. It is usually obvious whether or not there isadequate remaining metal in the rafters. If there is anydoubt, a structural engineer should be consulted. Pro-tective coating of the corroded areas can extend the lifeof the roof. Consult with CRTC’s Materials and Equip-ment Engineering Unit on the type of coating to use.

External corrosion on a fixed roof is usually the resultof poor painting maintenance or failure of the roof in-sulation weatherjacket to keep out moisture. Externalcorrosion justifies replacement of the roof deck plateonly, not the roof support structure.

The major types of roof repair are discussed below.

Replacement—Maintenance Specification

Maintenance Specification TAM-MN-6, for replacing afixed roof, is included in Volume 2 of this manual. Re-fer to API 650 and Section 400 for roof joint details.

Safety

From a safety standpoint, the internal supports must beinspected and declared structurally sound before allow-ing people or equipment on the roof. Personnel shouldnever walk on the old deck plate between the supports.Plywood sheets, placed so that they bridge the gap be-tween supports, should be used as a working surface.

Changing the Frangible Joint Design

As mentioned in Section 400, fixed roof tanks shouldhave a weak roof-to-shell joint (frangible joint) in ad-dition to an API 2000 venting system.

Section 400 and API 650 also give the design detailsof a frangible joint.

For existing tanks, the frangible joint can be broughtin compliance with the above by:

• Removing any patches over the weld seam

• Grinding down the existing weld

• Removing and rewelding the fillet weld


June 1994 1100-11

Note: Grooving the roof deck plate near the shellis not an acceptable way to create a frangible joint.

Door Sheets

Sometimes an opening is cut in a roof to permit low-ering of equipment into the tank. Rafters may be re-moved to clear this opening. If the deck plate removedis serviceable, the opening should be cut rectangularwith one dimension 4 inches greater than the other. Byrotating the plate 90 degrees, it can be reinstalled alongwith a single narrow patch along one edge. See Main-tenance Specification TAM-MN-2 in Volume 2 of thismanual.

1134 Steel Floating Roof Repair orReplacement

Questions that must be answered to determine whetheror not a floating roof can be repaired or must be re-placed include:

• What is the extent and depth of corrosion? At theend of the next operating run will there be at least0.10 inch of metal remaining at all points? Figure1100-7 can be used for this calculation also.

• Can the roof be kept in round during repairs?

• Does the roof design meet current legal require-ments and/or operating requirements?

• Is there a metallurgical problem, i.e., tendency tocrack?

• Is there adequate annular space throughout its travelfor the seal to work properly.

Roof Replacement—TAM-MS-968

Model Specification TAM-MS-968, Floating Roofs andInternal Floating Covers, is included in Volume 2 ofthis manual. Use this specification for new constructionor the replacement of an external floating roof.

Roof Repairs

Suitable repairs that can be made to a floating roof in-clude:

• Patching with new steel plate. Consider the effecton roof drainage.

• Replacement of rim plate. Replace the rim platewhile deck plate is intact to prevent roof from go-ing out of round.

• Replacement of leg supports

• Adjusting height of legs

• Installation of reinforcing pads around legs

• Installation, replacement and repair of roof appur-tenances

• Cutting out buckles and patching. Make sure roofis adequately braced to prevent its going out ofround.

1135 Internal Floating Roof Retrofit,Replacement or Repair

Retrofit

As discussed in Section 400, existing fixed roof tanksare often retrofitted with internal floating roofs becauseof a change in service or regulations. The major con-cern with retrofitting is that the roof maintain a properseal with the shell. You must verify that the retrofit al-lows this.

Replacement

Situations or conditions which justify replacement ofan aluminum internal floating roof include:

• Change of service to one that is not compatiblewith aluminum, such as caustic liquids, or to aheavy sediment-building service, such as recoveredoil. In this case, the replacement roof would besteel.

• Buckling due to turbulence. In addition to replacingthe roof, consider ways to reduce turbulence, e.g.,installing a diffuser on the fill line.

Repair

Repair alternatives for aluminum internal roofs include:

• Replacement of mechanically damaged parts, in-cluding skin, pontoons, and legs

• Replacement of individual panels on contact-typeroofs

Maintenance Specification for Replacement

A specification for the installation of an internal float-ing roof in an existing tank is included in Volume 2 ofthis manual. See TAM-MN-5.


1100-12 June 1994

1136 Seal System Repair or Replacement

The three common reasons for seal system repair andreplacement are:

• Inability to meet emission regulations

• Mechanical damage

• Deterioration of material (corrosion and wear onsteel and fabric failure)

Inability to meet emission regulations—usually seal-to-shell gap requirements—is corrected by one of threemeans:

• Adjusting the hanger system on primary shoe seals,and adding foam leg filler in toroidal seals

• Increasing the length of rim mounted secondaryseals in the problem area

• Replacing all or part of the seal system along withpossible installation of a false rim. This step shouldonly be taken after checking the annular space vari-ation at several levels from low pump out to safeoil height.

Mechanical damage—Damaged parts are usually re-placed in kind. Before the damage is repaired, thecause of the damage should be identified and corrected.Buckled parts should be replaced, not straightened.Torn seal fabric can be replaced.

Deterioration of material—Material deterioration re-sults from wear and corrosion on metallic elements andchemical deterioration of seal fabric. Some of this de-terioration is expected. The service life and inspectioninformation will indicate whether a change of materialis warranted.

Refer to Section 400 for the advantages and disadvan-tages of various seal systems.

Steps to Take During Seal Retrofitting

1. Refer to Section 400 for help in determining thetype of seal system to install. Seals that can berepaired or replaced in service are recom-mended.

2. Check for shell out-of-round and annular spacevariation through the entire range of roof travel.

3. Check the remaining roof rim thickness. If the roofrim is less than 0.15 inch thick, it could bend ortear at seal system attachment points, destroyingthe seal system and possibly sinking the roof. Roof

rims can be replaced. The new roof rim should beat least 5/16 inch thick.

Maintenance Specification

Specification TAM-MN-4, for replacing a seal system,is included in Volume 2 of this manual.

Air Quality Inspections

Engineers should consult the local environmental or-ganization to determine the air quality inspection re-quirements for their project. Scheduling and adequatenotification of the regulatory agencies should beplanned. The seal system should be inspected by aCompany inspector and all problem areas resolved be-fore having an air quality inspector look at it. The pri-mary seal system should be inspected before asecondary seal is installed.

1140 IN-SERVICE REPAIRS

Because it is costly to remove tanks from service andclean them for entry, it is often necessary to work ontanks while they are in service. This section discussesin-service repairs and the safety guidelines for complet-ing these repairs.

1141 Safety Guidelines for In-serviceWork on Tanks

All work should be in accordance with the latest edi-tion of API Standard 2015.

Gas Testing

Before the start of repair work, test the vapor space inthe tank and the surrounding area for combustiblegases, aromatics, hydrogen sulfide, and any other an-ticipated hazardous gases. A tag which shows the date,time, gas concentrations, and other pertinent informa-tion must be attached to the tank.

Gas tests must be taken at intervals as required to en-sure safety during progress of the work, and as a mini-mum should be taken at the following times:

• Before work is started each day

• At least hourly or when conditions change

• Just before work is resumed, if work has been in-terrupted for a period of 1 hour or more

• Just before work is resumed after any stock move-ments in or out of the tank


June 1994 1100-13

• After removal of a portion of the seal assembly andinjection of inert gas and before work on the sealsystem begins

• At any other time when, in the opinion of the Com-pany or Contractor, it is necessary to ensure safety

No work will be permitted without fresh air breathingequipment in areas where the hydrogen sulfide concen-tration exceeds ten (10) parts per million or the aro-matics concentration exceeds one (1) part per million.

Hot Work Precautions

No work will be permitted in areas where the concen-tration of combustible gases exceeds 0.05 on the J-W(or other approved) combustible gas indicator. Hotwork must be immediately stopped and all personnelmust immediately leave the tank when the combustiblegas concentration exceeds this limit.

Stock must not be transferred to or from the tank whilework is being performed. To avoid accidental pumpinginto or out of the tank, valves must be closed andtagged by the operator. These valves must not betouched during the repair work.

No hot work is allowed on any roof in service. Hotwork on the shell, such as hot tapping nozzles, clips,brackets, attachments, etc., requires that the liquid levelbe a minimum of 3 feet above the highest weld point.A liquid level is necessary to keep the shell cool andto prevent possible hot surface ignition of the tank va-por space. Work above this level on the shell must beperformed “cold.” Hot work on shell spiral stairways(but not on the shell) must be enclosed with a non-po-rous material and continuously tested for concentra-tions of combustible gases. Section 1143 contains adetailed hot tap procedure.

Floating Roof Entry Precautions

In all cases when it is necessary for personnel to goonto the roof, a safety watch must stand by at the topof the stairway. If the person on the roof is overcomewith gas, the safety watch must immediately summonhelp.

When the top of the floating roof is more than 4 feetbelow the top of the shell, the top of the roof is definedas an enclosed space. Two (2) safety watches must bepresent, one at the top of the stairway to the tank andthe other on the floating roof, and they must continu-ously test for combustible and hazardous gases. Thesafety watch at the top of the stairway must not de-

scend into the tank but will summon help by radio ifnecessary.

When workers are using fresh air breathing equipment,there must be a safety watch with a Scott Air Pack onthe gager’s platform. A second safety watch must beon the ground monitoring the breathing air (compressoror air bottles). Tank emergency egress must be pro-vided. This can be a crane or a portable hoist mountedon the rim.

When working on the floating roof seal assembly, nomore than 25% of the vapor space must be exposed atany one time.

1142 In-service Shell Repairs

Leaks in in-service shells can be repaired in the fol-lowing ways.

• Single holes can be temporarily repaired by insert-ing a screwed plug and applying epoxy around theplug to seal and hold it. The tank should be takenout of service immediately to complete a permanentrepair.

• Rivet and seam leaks can be repaired by peeningthe metal around a leak to seal off the leaking area.Care must be taken to avoid applying too muchforce. Epoxy seam sealers also can be used, but thetank level must be lower than the leak.

1143 Hot Tapping of Tanks in Service

General

Occasionally there is a need to install a new nozzle orother appurtenance on a tank shell without taking thetank out of service. This work can be accomplishedsafely by hot tapping, if proper procedures and precau-tions are used.

An alternative which should not be overlooked is thepossibility of installing the required new nozzle on amanway cover. The advantages, if operationally feasi-ble, are the ability to remove the manway cover to theshop where the quality of the alteration work can betested, and the elimination of hazardous work in thetank area.

Safety Precautions

Hot tapping is a useful method of making in-servicerepairs, but it involves hazards which must be recog-nized and weighed against alternative solutions.


1100-14 June 1994

Since welding done on a hot tapping job cannot be in-spected or tested thoroughly, this work should be doneonly by skilled welders under competent supervision.Welding requires that the area be completely gas freeand that J-W readings be taken continuously during thewelding process to assure no vapor accumulates. Allsources of vapor in and adjoining the area should beproperly controlled, and the timing of the work shouldcorrespond to the in-breathing (emptying) of tankswhich might contribute vapor to the area.

The liquid level should be at least 3 feet above thelevel where welding work is being done. Consult thelocal operating management for any requirementsspecific to your plant.

The gas testing and hot work precautions listed in Sec-tion 1141 should be used during a hot tap.

Equipment

Several makes of hot tap machines can be purchasedor rented. Although they were developed primarily foruse on pipe lines, they are also suitable for use on tankshells. The size of the machine needed depends on thesize of hole. Some machines can make cuts up to 12inches in diameter. Note that hot tap cutters usually cuta hole somewhat smaller than the nozzle inside diame-ter. This must be considered if appurtenances are to gothrough the hole.

Pre-work Inspection

Before a hot tap is made, UT gage the tank shell atthe location of the hot tap for any possible deficienciesand review recent records of interior inspection of thetank. Every effort should be made to determine the

soundness of the shell plate. If there is reason to sus-pect shell plate deficiencies, hot tapping should beavoided.

Nozzle Location and Hot Tapping Procedure

The new nozzle should be kept clear of existing seams.Pipe, flanges, reinforcing plate and details should con-form to API 650 nozzle details. Only the method ofwelding the nozzle to the tank should differ from API650. Since the interior backup weld for the nozzle ob-viously cannot be made with the tank in service, itmust be altered as indicated in the following procedurefor pipe connections over 2 inches. All other weldsshould follow API 650.

Small connections up to 2 inches. Install a weld bossper Standard Drawing GB-L31368 (see Pressure VesselManual).

Pipe connections over 2 inches. These nozzles requirea reinforcing plate. Install nozzle and reinforcing platein accordance with Figures 1100-8 and 1100-9 and thefollowing procedure:

1. Bevel nozzle end 37-1/2 degrees with 1/16-inch lipedge.

2. Tack to shell with 1/16-inch lip edge spacing.

3. Apply full penetration weld with good fusion topipe and shell. Leave no undercut on pipe and re-move all slag and weld splatter from shell andpipe. See Figure 1100-8.

If pipe connection is large enough to be weldedon the inside of the nozzle, back gouge or grindthe nozzle-to-shell weld. Clean metal and back

TAM11008.GEM

Fig. 1100-8 Hot-tap Welding Details—Nozzle-to-Shell


June 1994 1100-15

weld to assure full penetration and fusion through-out thickness of nozzle-to-shell weld.

4. Hydrostatic test nozzle to 50 psi.

5. Roll reinforcing plate to fit snugly to shell. Triminside diameter of opening to fit toe of pipe weldleaving appropriate lip edge space and groove di-mensions for the diameter of hole and thickness tobe welded. See Figure 1100-9.

6. Press pad firmly against shell and tack outside di-ameter of pad.

7. Weld inside diameter of pad being sure to get goodfusion to shell.

8. Finish weld with smooth fillet from top of pad tonozzle surface. Leave no porosity or undercuts.

9. Complete the weld on the periphery of the pad perAPI 650.

10. Test reinforcing plate with air pressure to 10 psi.

Limitations

Hot tapping of tanks should not be done if the nozzlediameter is over 12 inches. If a larger nozzle is neces-sary, the tank should be taken out of service and thenozzle assembly shop-welded and stress-relieved. Seesection on shells in Specification TAM-EG-967.

1144 Fixed Roof Repairs

Fixed roof repairs can be made in the following ways.

• Holes in the deck plate can be cold patched. Apatch plate to cover the area is prepared with holesdrilled along the edge. After applying a sealant/ad-hesive to the deck plate where the edge of the patchplate will be, the patch plate is then set in placeand fastened with sheet metal screws.

• Thin roof deck can be repaired by applying a lami-nate coating. Holes are first covered with lightsheet metal patches held in place with sealant/ad-hesive or sheet metal screws. See the CoatingsManual for more details on laminate coatings.

• Appurtenances can be installed using the follow-ing methods:

1. Existing pipes can be cut off, threaded, and athreaded flange installed with the new appur-tenance bolted on. If no lifting force will beapplied when the appurtenance is used (suchas the funnel on a sample hatch), the attach-ment can also be made by gluing the flangeto the pipe. In this case, tack welds on the in-side of the slip-on flange can hold it in placebefore gluing.

2. A surface-mounted appurtenance can be in-stalled on the roof deck by welding a reinforc-ing pad on the appurtenance in the shop,cutting an opening in the roof deck, and thenattaching the appurtenance to the roof deck inthe same manner as a large patch.

TAM11009.GEM

Fig. 1100-9 Hot-tap Welding Details—Reinforcing Plates


1100-16 June 1994

1145 Floating Roof Repairs

Floating roof repairs can be made in the followingways.

• Temporary repairs of holes in the deck plate canmade with steel plugs and sealant as done withshells.

• Cold patches can be made in the same manner aswith a fixed roof, with the following additionalsteps:

1. The leak must be momentarily plugged usinga plug and sealant.

2. The patch should be conical shaped so as notto displace the temporary plug while the patchis being installed.

3. After installation of the patch, the area shouldbe thoroughly cleaned of all oily contaminateand an epoxy sealant installed over the patchafter adequate surface preparation.

• A thin upper deck of pontoons can be repaired inthe same manner as a fixed roof: by sheet metalpatching and laminate coating.

• Rolled or bent floating roof fixed low legs can becut off internally (below the lower roof deck) byuse of an ultra-high pressure hydrocutter. The re-mainder of the roof leg through the roof then be-comes the guide sleeve for a temporarytwo-position leg.

1146 Floating Roof Seal Systems

Rim-mounted primary shoe and toroidal seal systemscan be removed, repaired, or replaced. To minimizeevaporation and potential hazard to the workers, nomore than one-fourth of the roof seal system should beout of the tank at one time. Temporary spacers to keepthe roof centered should be used during the repairs.Primary seal systems mounted partly or fully below thebolting bar or top of the rim usually cannot be reachedto allow removal in service. In this case, in-service re-pairs are restricted to replacement of the primary sealfabric.

Rim-mounted secondary seals are readily installed, re-paired, or replaced with the tank in service, as areshoe-mounted secondaries.

1147 Insulation

In-service repairs to insulation on the shell and fixedroof can be made by the following methods.

Shell. Shell insulation can be installed, repaired, or re-placed in service. A special bar with studs for the lay-bar installation will be required to provide studs abovea level 3 feet below the stock level of the tank. Belowthat level, the bar will be welded to the tank using thehot tap procedure described in Section 1143. (See Fig-ure 1100-10.)

Fixed Roof. Roof insulation is normally impaled onstuds welded to the roof. In-service replacement of in-

TA110010.GEM

Fig. 1100-10 Laybar Installation—In-service Tank


June 1994 1100-17

sulation is feasible as long as the impaling studs arenot damaged.

Where in-service installation is required without studs,one company, Thermacon, has a design consisting ofcables in tension across the roof which are attachedcold to the top angle. These cables hold the roof insu-lation in place.

1148 Appurtenances

Bolted-on appurtenances, such as valves, breathers,hatch covers, manway-mounted mixers, and heaters,etc., and threaded appurtenances, such as hatch covers,autogage guides, etc., can be replaced in service. Toinstall some appurtenances will require that the tanklevel be pumped down. Some appurtenances which areabove the liquid level, such as sample hatch funnels onexisting sample hatches of floating roofs, and thosefixed roof appurtenances mounted directly to the roof,can be replaced in service.

In-service repairs can be made on stairways, platforms,and wind girders by bolting instead of welding. Suchattachments must be well sealed to prevent corrosionproduct between the surfaces from breaking the bolts.

Rolling ladders can be removed from the tank and re-paired, rebuilt, or replaced in service.

1150 RERATING AND RETIRINGCORRODED TANKS

Engineers are sometimes asked to:

• Determine the remaining life of a tank at the exist-ing safe oil height (SOH)

• Lower a tank’s safe oil height to compensate forthinning of the shell

• Determine when a tank should be removed fromservice

In general, the procedure can be broken down to thefollowing steps.

• Gage the shell thickness to establish a corrosionrate.

• Calculate the remaining life or the new safe oilheight. Recheck wind and earthquake stability.

• Determine the effect on operations of reducing thesafe oil height.

• Examine the alternatives for maintaining the exist-ing capacity.

• Compare the upgrade cost to the operating penaltiesfor reducing the safe oil height.

1151 Gaging the Shell Thickness

Gage the thickness of shell plate at multiple points byinspection. Normally the maximum time between shellgagings is 10 years or at half the remaining life. Wherea reduction in the safe oil height is called for, shellthickness should be gaged at 3-year intervals to mini-mize operating capacity loss. The measurements ob-tained establish the corrosion rate. When a tank serviceis changed to one with different corrosion rates, theshell should be gaged.

1152 Calculating the Reduction of theSafe Oil Height Required forContinued Operation

In 1963, the Company adopted a proposal that revisedthe Company’s basis for rerating and retiring tanks toallow for higher condemning stresses for most weldedtanks built after 1949 because of improved materials,better fabrication details, increased weld inspection,and better welding.

The revised method divides existing tankage into twocategories, each with a procedure for computingstresses. These procedures should not be used on hottanks (over 200°F).

1. Welded tanks built prior to 1949, welded tanksbuilt in 1949 or later which do not satisfy therequirements of 2-a or 2-b below, and all riv-eted tanks should continue to be rerated using thelong-standing Company method (there is no com-parable procedure for bolted tanks). TAM-EF-317,Tank Strength Calculation Sheet, can be used todetermine the safe oil height reductions for thiscategory of tanks.

a. Stresses shall be computed at a point 1 footabove the seam and shall be based on thegravity of oil in the tank and actual shellthicknesses less any required allowance forcorrosion. (Some use 30-degree API as thelightest practical gravity.)

b. A stress of 21,000 psi in plate tension for steelbefore applying joint efficiency factor, and15,000 psi for wrought iron, shall not be ex-


1100-18 June 1994

ceeded. The diameter of the rivet plus 1/8 inchshall be used for computing plate tension.

c. A rivet shearing stress of 19,000 psi, based onthe original net cross-sectional area of therivet, shall not be exceeded.

d. For steel, a bearing stress on rivets and platesof 32,000 psi for single shear or 35,000 psifor double shear, based on the original netcross-sectional area of the rivet, shall not beexceeded.

e. A joint efficiency of 75% shall be used incomputing the strength of lap-riveted verticaljoints that have been strengthened by welding.(Wrought iron tanks cannot be welded.) Ajoint efficiency of 85% shall be used for buttwelded tanks.

Note: Due to the protection given by rivet heads andbutt straps, the corrosion of the shell at the joint is fre-quently less than the corrosion of the shell generally.If the true strength of the joint must be determined,someone familiar with riveted joint calculations shouldcarry out the inspection.

2. For most welded tanks built during and sub-sequent to 1949, minimum shell plate thicknessshould be determined as outlined in 1-a above.These newer tanks are defined as follows:

a. Basic API 650 tanks having design metal tem-peratures greater than 50°F.

b. Basic API 650 tanks having design metal tem-peratures between 0°F and 50°F which werebuilt with the improved materials and prac-tices required by TAM-EG-967.

The maximum allowable stress shall be thesmaller of:

Bottom Course Upper Courses

0.80 y or T/2.35 0.88 y or T/2.12

where y is the specified minimum yieldstrength of the plate (use 30,000 psi if thespecification is not known); and T is thespecified minimum tensile strength of theplate. T shall not exceed 75,000 psi. (Use55,000 psi if the specification is not known.)

The joint efficiency shall be:

E = 1.0 for tanks which were spot radio-graphed during construction

E = 0.85 for tanks which were examined bysectioning

E = 0.70 for tanks without any examinationother than visual

3. Any tanks with a general shell thickness at or be-low 0.10 inch should be retired or the thin platereplaced. Also, wind and earthquake stabilityshould be checked on tank shells which havethinned. These factors are covered in Section 400.

1153 Determining the Effect onOperations

The engineer may need to answer the following ques-tions:

1. Can the operators live with a capacity reductioncaused by a thin shell? If they can, the safe oilheight is usually reduced.

2. If the safe oil height reduction is 5 feet or more,will the shell be in danger of rupture if the tankis filled to overflow by mistake? A tank overflowmay occur, and we must verify that the tank isstructurally sound in this circumstance.

3. If the loss of operating capacity is not acceptable,can we make up for the lost capacity somewhereelse? If not, then rebuilding or replacement are theremaining alternatives.

1154 Examining Alternatives forMaintaining the Existing Capacity

Typical alternatives are:

• Replacement of individual plates or entire courses

• Upgrading of joint efficiency and recalculation.Welded shells built before 1949 can be X-rayed andwelds repaired to increase joint efficiency from85% to 100%. Lap riveted joints with around 64%efficiency can be welded, giving a 75% joint effi-ciency.

• Coating to prevent further capacity loss


June 1994 1100-19

• Reallocation of services with necessary tank andpiping modifications

• Reducing unavailable stock by tank modifications

1155 Economic Justification for Repair,Replacement, Reallocation orRerating

After choosing the best alternative for maintaining theexisting capacity from those alternatives listed abovein Section 1154, compare the cost to that of reratingor retiring the tank. Work with your local planning or-ganization to develop the necessary economic justifica-tion.

1160 COATING AND PAINTING

This section contains basic information for coating in-ternal and external surfaces of storage tanks. For moredetailed information refer to the appropriate sections inthe Coatings Manual.

1161 Exterior Coatings

Exterior refers to the outside surfaces of a tank plus itsstairway, wind girder, etc. External surfaces are coatedfor several reasons: to protect against corrosion, to im-prove appearance, and to reduce evaporative losses. Se-lect a coating system by deciding on the reasons forcoating and then use the guidelines found in the Coat-ings Manual.

One of the most important considerations in choosinga coating system is that the system selected must com-ply with the local air district regulations concerningVolatile Organic Compound (VOC). COM-EF-872-Blists the acceptable brands which have low (less than420 gm/liter) VOC content.

New Construction (See External Coatings in the Coat-ings Manual.)

There are two bas ic external coating systems:coastal/inland and high performance.

1. Coastal/Inland

• Standard system for mild environments

• Usually a 3-coat alkyd system

• Poor life in severe exposures (less than 2 years)

• Inexpensive material that is easy to apply

• Requires commercial blasted surface (SSPC-SP6)

• May be applied over hand tool cleaned surface, butwill reduce the coating life 30 to 50%

2. High Performance

• Usually a 3-coat system: inorganic zinc primer,polyamide epoxy tie-coat, and polyurethane finish

• Has a longer life than an alkyd system, approxi-mately 20 to 25 years in mild service

• Installed cost is higher than an alkyd system. How-ever, its cost/year can be 50 to 100% less due toits longer life

• System recommended for severe exposures, such aschemical plant environments

• Requires applicators experienced with 3-coat sys-tems

• Requires a near white metal blasted surface (SSPC-SP10)

Maintenance (See the Maintenance Section of theCoatings Manual.)

There are two systems normally used for field coatingor touching up tanks: alkyd primer/alkyd enamel (Coat-ing System 2.1) and epoxy mastic/polyurethane (Coat-ing System 2.15).

1. Coating System 2.1

• Standard system for mild environments

• Poor life in severe exposures (less than 2 years)

• Inexpensive material that is easy to apply


2. Coating System 2.15

• Has a longer life than an alkyd system, approxi-mately 15 to 20 years in mild services

• Installed cost is higher than an alkyd system. How-ever, its cost/year can be 50 to 100% less due toits longer life

• System recommended for severe services

• Requires an abrasive blasted surface


1100-20 June 1994


• May be applied over old paint, with similar reduc-tion in coating life

1162 Internal Coatings

The Coatings Manual covers liquid coatings applied tothe inside surfaces of a tank. They are used to ensureproduct purity, to protect the tank from stockside cor-rosion, and, in limited cases, to extend the life of atank bottom suffering underside corrosion. Section1130 of this manual discusses the use of internal coat-ings as a repair alternative.

Coatings applied to the interior of tanks are in severeservice and require superior surface preparation andcoating application. Surfaces must be abrasive blastedto SSPC-SP5 (white metal) and the first coat appliedbefore rusting. This preparation may require dehumidi-fication equipment or a holding primer. We do not rec-ommend holding primers unless absolutely necessarybecause they are usually lower in performance than theprimary coating and lead to early failures.

Listed below are the three internal coating systemsused by the Company.

1. Non-reinforced thin film coatings (10-20 milsDFT)

• Usually epoxy or epoxy phenolic

• Should be considered first

• Not good in high abrasion service

• Most thin films will not adequately cover se-verely corroded or pitted surfaces

• Excellent to use in conjunction with sacrificialanodes to prolong the life of new bottoms

2. Glass flake coatings (40-100 mils DFT)

• Usually polyester or vinyl ester resins

• Can be used in place of thin film coatings

• Cost approximately twice as much as thin filmcoatings

• Have good abrasion resistance

• Will cover corroded and pitted surfaces

• Only used where thin films will not work

3. Laminate reinforced coatings (100+ mils DFT)

• Usually polyester or vinyl ester resins

• Most expensive system

• Only used where structural support is needed

• Creates a problem for leak detection due towicking through the laminate

1163 Inspection

Inspection is the most important aspect of a coatingsjob. Surveys have shown that almost 80% of all pre-mature coating failures are due to poor surface prepa-ration or paint application. Therefore, inspection shouldbe an integral part of the job, beginning with surfacepreparation, paint application and finally completion.Internal coatings should also be inspected by means ofa low or high voltage detector to locate pinholes andholidays.

Consult with CRTC’s Materials & Equipment Engi-neering Unit coating specialist for questions or prob-lems not covered in the Coatings Manual or above.

1170 TANK SETTLEMENT

Tanks are relatively flexible structures which tolerate alarge amount of settlement without signs of distress.However, tank settlement has caused failures such asinoperative floating roofs, shell and roof buckling dam-age, leaks, and loss of tank contents. Foundation de-sign, soil conditions, tank geometry and loading, aswell as drainage, all have a significant effect on settle-ment.

Large petroleum tanks are generally constructed oncompacted soil foundations or granular material, whilesmaller tanks are often built on concrete slabs. The set-tlement covered in this discussion pertain to large tanks(over 50 feet in diameter) because most large tanks arebuilt on foundations where the thickness, elasticity andcompressibility of the foundation and subsoil layerscan vary enough to produce non-planar distortionswhen uniformly loaded. However, the basic principlesapply to all tanks, especially uniform settling and pla-nar tilt.

When filled, tanks will uniformly load the foundationbeneath the tank as the result of hydrostatic pressurein a disk pattern. However, the tank edge:

• carries an increased load from the shell and roofweight.


June 1994 1100-21

• can suffer loading effects such as twisting of theplates under the shall due to shell rotation.

Note: The tank edge is defined as that area of the tankwhich is comprised of the tank shell, the roof sup-ported by the shell, and the foundation directly be-neath.

For these reasons, most settlement problems occur inthe foundation that is under the outside edge of thetank. Settlement problems are assessed by taking ele-vation readings at the base of the tank. Nonetheless,failures have occurred from interior settling that wentundetected in elevation readings.

Settlement failure poses serious consequences to safetyand surrounding property. Until the mid 1950s, tankswere limited to about 200,000 bbls capacity. Sincethen, capacity has increased to 800,000 and 1,000,000bbl. Considering these tank sizes, criteria must beavailable to ascertain the extent of settlement and cor-rection procedures.

Spotting Settlement Problems

Tank settling can be indicated by any of the following:

• Roof binding on floating roof tanks.

• Damage or early wear-out of floating roof seals.

• Shell buckling in fixed or floating roof tanks.

• Roof buckling in fixed roof tanks.

• Loss of support in fixed-tank, roof support col-umns.

• Cracking of welds.

• Loss of acceptable appearance.

• Over stressed piping connections

• Accelerated corrosion due to drainage patternchanges on the outside of the tank.

• Inoperative or less effective drainage on the interiorof the tank, especially where cone-up, cone-down,or single sloped bottoms are used.

• Increased susceptibility to seismic damage as a re-sult of distorted, over stressed or deformed bottoms.

• Leaks in the bottom of shell.

The most serious failure results in leakage or loss ofcontents. The presence of even a small crack in the

tank bottom can be a serious threat to the integrity ofthe tank. Several notable settlement failures have fol-lowed this sequence:

1. Development of an initial leak caused by a crackin the tank bottom.

2. Washed out foundation support immediately nearthe initial leak location, causing the crack to growfrom lack of support.

3. Increased leakage and undermining of the supportunder the tank. The bottom plates separate fromthemselves or from the shell where the foundationhas washed away.

Prior to several incidents [1] leakage was seen emanat-ing at the chime, but the contents could not be pumpedout before a major failure occurred.

Kinds of Settling

Tank settlement occurs in the following categories:

• Uniform Settlement

• Planar Tilt

• Differential Shell Settlement

• Global Dishing

• Local Interior Settling

• Sloped Bottoms

• Edge Settlement

Uniform Settling. In this type of settling the soil con-ditions are relatively uniform, soft or compressible, andastorage tank will slowly, but uniformly sink down-ward as shown in Figure 1100-11. Uniform settlingposes no significant problems; however, there are twoimportant side effects:

1. Water Ingress occurs when a depression or watertrap is formed around the tank’s periphery whereit meets the soil. When it rains, moisture accumu-lates under the tank bottom near the shell or chimeregion and corrodes the bottom.

2. Piping connected to the tank will eventually be-come over stressed by the tank movement.

To assess the degree of uniform settlement, simplymonitor elevations at the base of the tank.

Planar Tilt . In this mode the tank tips as a rigid struc-ture. (See Figure 1100-12). Often planar tilt accompa-


1100-22 June 1994

nies uniform settlement. Planar tilt can be assessedfrom an external tank inspection conducted by takingelevation readings at the base of the tank. The follow-ing may occur as the tilt becomes severe:

1. Appearance. The human eye is sensitive to verti-cal lines. With a relatively small angle of tilt theappearance of a tank begins to look strange. Thepublic or employees may begin to question thesafety of the tank and the operating and mainte-nance practices of the owner. Planar tilt limited toD/50 is a reasonable plumbness specification thatprovides an acceptable tank appearance.

2. Hydrostatic Increase. The tilt of the tank resultsin an increase in hydrostatic head as shown in Fig-ure 1100-12.

If the increased stress causes the shell to exceedthe design-allowable stress, there are several solu-tions:

• Lower the liquid level.

• Operate the tank slightly above allowablestresses.

3. Reduced Storage Capacity. Because the maxi-mum liquid level is often just beneath the roof or

overflow, the allowable liquid level may have tobe reduced to accommodate the planar tilt.

4. Ovalizing. If a tank tilts, the plan view will be anellipse, shown in Figure 1100-12. Because floatingroof tanks have specific clearances and out-of-round tolerances for their rim seals to work prop-erly, planar tilt can cause a seal problem. However,the amount of planar tilt would have to be extremefor ovalizing to become a problem.

Differential Shell Settlement. Differential settlement,alone or in combination with uniform settlement andplanar tilt, results in a tank bottom which is no longera planar structure. This type of settlement problem canbe assessed by taking elevation readings around thecircumference of the tank shell, where the bottom pro-jects beyond the shell.

Figures 1100-12 through 1100-14 are shownon the pages following.

The readings can then be plotted as shown in the Fig-ure 1100-13. If the bottom of the tank is planar, thena cosine curve may be fitted through the measuredpoints. However, if there is differential edge settlement,then a best-fit cosine curve can be fitted to thesepoints.

Differential shell settlement is more serious than uni-form or planar tilt settlement because deflection of thestructure on a local scale is involved which produceshigh local stresses. Differential edge settlement resultsin two main problems:

1. Ovalizing. As shown in Figure 1100-14, differen-tial settlement occuring in the tank bottom near theshell produces an out-of-round condition at the topof tanks which are not restricted in movement(e.g., a floating roof tank). One of the most seriousproblems with bottom differential-edge settlementin floating roof tanks is the operation of the float-ing roof. Because floating roof seals have specifictolerance limits between the edge of the roof andthe tank shell, ovalizing can interfere with the op-eration or destroy the seal itself.

If the bending stiffness of the tank is much lessthan the extensional stiffness (thin wall structure),then the theory of extensionless deformations maybe used to compute the relationship between dif-ferential settlement and radial deformation at thetop of the tank.

GRADE

GRADE

WATER INGRESS CAUSESACCELERATED UNDERSIDECORROSION

PIPE SUPPORT

PIPE SUPPORT

UNIFORM SETTLEMENT

POSSIBLE OVERSTRESS OFPIPING AND TANK NOZZLE

S =

S

X47103.HPGTM110011.GEM

Fig. 1100-11 Uniform Settlement


June 1994 1100-23


Fig. 1100-12 Planar Tilt Settlement


1100-24 June 1994


Fig. 1100-13 Differential Tank Settlement


June 1994 1100-25

It has been found that with specific readings ofsettlement, the following finite difference equationmay be used to estimate ovaling:

r = DH2

N2

π2 ∆ Si

(Eq. 1100-1)

where:

i = station number of elevation reading takenat base of tank

r = radial shell displacement at top of tank

N = number of stations or readings

H = shell height at which radialdisplacements are calculated

D = tank diameter

∆S = measured settlement at ith location

x = circumferential shell coordinate

2. Shell Stresses. Non-planar, differential settlementmay generate shell stress near the top of the tankand may result in buckling of the upper shellcourses. In the past, the amount of differential set-tlement allowed was determined by arbitrarily lim-iting the differential settlement to a constant,which represented a ratio of the settlement to thespan between consecutive settlement measure-ments. Figure 1100-15 shows how various struc-tures, particularly buildings, are damaged when theslope represented by the deflection-to-span ratioexceeds some value.


Fig. 1100-14 Problems Resulting from Shell Out-of-Roundness Due to Nonuniform Settle-ment

X47107.HPGTM1100-15.GEM

Fig. 1100-15 Limiting Angular Distortion


1100-26 June 1994

One commonly used limit [2] is

∆S= 1450

(Eq. 1100-2)

where:

l = length between settlement readings, feet

∆S = allowable settlement

Local slopes limited to approximately l/450 to l/350applied to tank have proven conservative, and result intanks being releveled when further settlement couldhave been tolerated.

The API 653 formula uses a factor of safety of twotimes:

∆S = .011 σy1

2

2EH(Eq. 1100-3)

Global Dishing. The entire tank bottom settles relativeto the shell. This may occur singly or in combinationwith other forms of settlement. There is no one formof global settling, however, the majority of tank bot-toms do tend to form a dished shape as shown in Fig-ure 1100-16. There are several other common global

settling patterns and investigators have recommendedcriteria for each type as shown in Figure 1100-17. [3]

The problems associated with general global settlingare:

• High stresses generated in the bottom plates and fil-let welds.

X47110.DWGTA110017.TIF

Fig. 1100-17 Normalized Settlement of Tank Bottom

X47109.HPGTM1100-16.GEM

Fig. 1100-16 Dish Settling


June 1994 1100-27

• Tensile stresses near the shell-to-bottom welds thatmay cause shell buckling.

• Change in calibrated tank volumes (strapping chartsand gauges).

• Change in the drainage of the tank bottom profileand puddling when attempting to empty tank.

The literature suggests maximum global dishing valuesthat range from D/50 to D/100 depending on founda-tion type, safety factor or empirical data. The valuestated in the 1st edition, of API 653 is D/64. For globaldishing these values appear to be reasonable. A 100foot diameter tank using the provisions of Appendix Bof API 653 would have a total dish settlement ofB=.37R where B is in inches and R is in feet of 18.5inches. However, for values of R less than 3 - 5 feetthese limitations are not really applicable to local set-tling as explained later.

The methods presented above are based upon the largedeflection theory of circular flat plates with edges thatare not free to move radially. However, when the dif-ference in settlement between the center and the pe-riphery of the tank is large, there are indications that

the bottom membrane does move inward radially or theshell will be pulled in as shown in Figure 1100-16.From theoretical considerations, the difference in mem-brane stresses generated between a circular plate sim-ply supported with a fixed edge and an edge that isfree to move radially is a factor of about 3. [4] Thismeans that the stresses will be 1/3 as high for bottomplates that are free to slide as for those that are not.When the tank is loaded with liquid, the bottom platesare probably held in place more securely; therefore, itmay not be a valid assumption to use the free edgecondition.

For other modes of global settling it has been sug-gested [5] that different allowable settlements be pro-vided for the different configurations. This is shown inFigure 1100-17.

Local Interior Settling

Local settling that occurs in the interior of tanks oftentakes the form of depressions as shown in Figure 1100-18. Local interior settling poses similar problems toGlobal Dishing and the proposed methods of assigninga tolerance are again based upon the theory of largedeflection. Some of the methods include a relaxation,


Fig. 1100-18 Bottom Settlement


1100-28 June 1994

when the settling occurs near the tank wall, to take intoaccount the freedom of the plate near the shell to slideradially inward as the depression increases.

Note that the tank fabrication process leads to bucklesand bulges in the bottom plates. When the tank is filledwith liquid, these tend to level out, but often reappearwhen the liquid is removed. Most of the models cur-rently proposed for developing settlement criteria donot take into account the initial waviness of the bottom.

This type of settling is inevitable in compacted earthfoundations because soil composition and thicknessvaries under the tank. Deformations are usually formedgradually, without sharp changes in slope, so that thebottom plates are adequately supported. Risk of failurefrom this type of settlement is minimal unless there areserious problems with the welding integrity.

When large voids form under the tank bottom, the bot-tom plates may lift off the soil completely as shownin Figure 1100-18. Although this is not usually a prob-lem, a large void can lead to localized rippling effects.The tank releveling section covers the problems asso-ciated with filling these voids with grout.

Sloped Bottoms. The previous settling discussions ap-ply to flat bottom tanks; however, many tanks haveslopes intentionally built into the bottom. They fall intothree categories:

1. Single slope

2. Cone up

3. Cone down

Because the design slope of these bottoms averagesabout one inch in ten feet, they can still be consideredflat bottoms and the previous sections apply.

However, one special situation arises when the bottomis sloped: Cone up bottoms, subject to general dishsettlement, can tolerate more total settlement thaneither flat bottom, cone-down, or single-slope bottoms.As settling occurs, the bottom compresses and becomesflat. As the soil settles below the tank, the compressivestresses that were generated become relieved until theshell base becomes cone down, approximately equal tothe magnitude of the original cone up condition. SeeFigure 1100-19.

However, if the initial cone-up slope is significant,the settling relatively uniform, and the bottom con-

X47112.HPGTM1100-19.GEM

Fig. 1100-19 Tank Bottom Ripples


June 1994 1100-29

structed with lap welded joints, a phenomenon knownas rippling can occur, usually during the hydrostatictest on newly constructed tanks. Because of the linearlayout of bottom plates and the use of fillet welds, acrease or a fold can form, covering large parts of thediameter, as shown in Figure 1100-19. The ripples aretypically unidirectional and occur in the long directionof the bottom plates. The crease may be very severe(a radius curvature of approximately one foot is not un-common) and indicates that yield stresses have beenexceeded. The ripple can act as a stiffening beam andcause increased differential settlement and bottom fail-ure.

The allowable settlement of cone up should be morethan twice that of a flat or otherwise sloped-bottomtank. The maximum slope should be 3/4 inch per 10feet to avoid rippling.

Edge Settlement. Edge settlement occurs in the bot-tom plates near the shell as shown in Figure 1100-20.It is difficult to determine this condition from the ex-terior of the tank; however, seen from inside the tank,this is one of the most obvious forms of settling.

Edge settlement occurs frequently in tanks thathave been built on grades or compressible soils. Ifthe soil has not been compacted sufficiently or be-comes soft when wet, the probability of edge settle-ment increases. Edge settlement is mainly due toincreased loading on the foundation at the peripheryfrom the weight of the steel. Usually the foundationhas not been extended far enough beyond the tank ra-dius to prevent lateral squeezing of the foundation (seeFigure 1100-20).

Edge settling can occur locally in soft spots around theedge of the foundation; however, it usually involves arather substantial portion of the tank. Edge settlementis rarely seen in tanks that are constructed on rein-forced concrete ringwall foundations. It is most uncom-mon where the tank is built on a crushed stone ringwallfoundation.

The two fillet welds between the annular plate, shell,and the bottom plates induce stresses into the annularplate that cause upward bulges. Not strictly edge set-tlement, these bulges may contribute to it by creatingan initial slope in the annular plate which in turn setsup residual stresses that cause the tank bottom under

Fig. 1100-20 Edge Settlement



1100-30 June 1994

the shell to apply greater downward pressure on thesoil. The initial slope may be attributed to edge settle-ment when it was caused by the welding. Proper weldprocedures, careful selection of the welding sequencefor all welds in the bottom annular plate, and carefulfitup should minimize this problem.

Settlement Criteria. To date there is no appropriatemethod for estimating tolerable edge settlement. Thereare, however, numerous tanks in service showing edgesettlement with magnitudes of 6 to 18 inches over aspan of 1 to 2 feet and functioning without leaks orfailures.

Edge settlement is unlike other kinds of settling. API653 and other proposals are based upon a model thatis similar to the dishing models described above. Be-cause this type of settlement involves substantial yield-ing of the bottom plates (apparent from the largedeflections over short spans), any model that uses anallowable stress basis for limiting settlement is prob-ably extremely conservative. A strain-limiting approachmay be more appropriate.

One equation that can be used to estimate maximumallowable edge settlement is:

B = max (2 inch or 0.41R2)(Eq. 1100-4)

B = acceptable settlement, inches

R = distance over which settlement occurs, feet

t = thickness of bottom plate, inches

Designing for Settlement. Depending on the degreeand type of settlement expected (determined from simi-lar installations in the area or from soil surveys), thereare several means of designing for expected settlementwith increasing effectiveness:

1. Standard lap-welded bottom

2. Annular plates with lap-welded bottom

3. Butt-welded bottoms

These construction methods increase in effectiveness(1-3), and they also increase in price. Unless neededfor reasons high settlement, the butt-welded tank bot-tom is generally ruled out on a cost/benefit basis. Be-cause the standard lap welded tank bottom is the mosteconomic, there is a tendency to use this design forlocations even where significant settlement is expected.

Additional construction measures can be more effec-tive, such as deeper levels of soil compaction, crushed

stone ringwalls, reinforced concrete ringwalls or slabson ringwall foundations.

The use of annular plates reduces edge settlement. Theuse of concrete ringwalls virtually eliminates edge set-tlement.

Releveling Tanks

Releveling tanks is a common procedure for correctingexcessive settlement problems such as buckling shellplates, leakage in the bottom plates, excessive out-of-round and high stresses. When floating roof tank baseshave experienced differential settlement, the roofs canbind and seals may be damaged or ineffective. Fre-quently, releveling causes the tank to reassume a roundshape. Tanks that have been buckled due to settlementor tanks that have been constructed with initial out-of-round are usually not improved by releveling.

Releveling Methods. Some companies specialize intank releveling. Deal only with reputable contractorswho have carefully planned a shell-releveling proce-dure which has proven effective.

All releveling procedures should include these factors:

• For floating roof tanks, the roof should be sup-ported from the shell to prevent excessive stressesand the possibility of cracks occurring from differ-ential movement.

• When tank jacking methods are used, it is possibleto jack tanks up approximately 10 feet high, allow-ing for bottom inspection, cleaning, removing con-taminated soil where leakage has occur red,rebuilding of the foundation if necessary, or coatingfrom the underside.

• Support must be supplied for fixed-roof supports sothat roof buckling and damage does not occur. Fig-ure 1100-21 shows one way of supporting the roof.

• The amount of differential jacking must be control-led so that shell buckling or weld damage in thecorner welds, or in the bottom plates, does not oc-cur.

• In all tank releveling procedures large groups areinvolved and mistakes could cause injuries or un-anticipated costs. Any work of this nature shouldbe carefully reviewed for safety, environmentalconcerns, and good practices. The owner shouldalso be convinced that those performing the workhave direct experience using the proposed methods.


June 1994 1100-31

• A releveled tank should be hydrostatically tested.Testing may not be necessary in a few cases suchas small tanks where the shell stresses are low orthere was very limited jacking.

• Corrected piping should be disconnected if relevel-ing will produce excessive stresses causing equip-ment damage. Underground piping connections tothe tank should be exposed for monitoring.

Shell Jacking is a common releveling method wherelugs are welded to the shell near the base as shown inFigure 1100-22. Typical spacing is about 15 feet. Oncethe lugs are in place and a suitable jacking pad set up,jacking proceeds around the tank circumference insmall increments. Jacking in small increments preventswarping the bottom excessively out of plane. Shims areinstalled as the jacks are moved around and the tankcan be raised to any desired elevation. The tank bottomwill sag down somewhat, but will not cause structuralproblems with the bottom welds if the welds are sound.

Typical specified tolerances average about 1/4 inch oflevel for any measured point on the tank perimeter atthe base.

Contractor responsibilities include:

• Furnish, design, install, and remove lugs.

• Remove any weld arc strikes and ground out re-maining slag.

• Recommend the prior loading under each shimmedarea to prevent foundation damage and settling.(Recommended shim spacing is 3 feet.)

• Propose if and how sand or grout should be appliedto low points under the tank bottom.

• Monitor radial tolerances when correcting an out-of-round tank.

• Provide complete written procedures for all workto be undertaken.


Fig. 1100-21 Floating Roof Support


1100-32 June 1994

If the jacking exposes a large area under the tank, ap-plying a flowable grout or sand layer will provide aplanar foundation for the tank to rest on. However,miscellaneous injection of grout through holes cut intothe bottom plates is usually ineffective or makes thesituation worse.

If the work is meant to correct out-of-round, requirefrequent monitoring of the radial tolerances as well asthe effect of releveling on these tolerances. At leasteight equally spaced points at the top of the shellshould used for monitoring. Elevations as well as radialmeasurements should be made before and after thework.

A hydrostatic test should be conducted after the tankis releveled.

The Under-the-Shell Releveling Method uses jackingunder the bottom of the shell. Small pits are excavatedto hold the jack under the tank shell. Figure 1100-23

shows a typical jack arrangement for this method. Theprinciple objection to this method is that pits must beexcavated beneath the tank shell. In soil foundations,this may cause a loss of compaction in the order of 40-50%. [6] Another problem is that the spacing forshims and for jack points must be greater than theshell-jacking method and therefore would providehigher soil stresses while the work is in progress.

The same procedures, specifications, precautions andtesting as covered under shell jacking should be ob-served.

Tank Leveling by Pressure Grouting or sand pump-ing is used to force low spots or settled areas upward.This method can be used to raise small or large areaswhere tank bottoms are low. The contractor forces sandor grout under pressure into the area to stabilize thebottom plates. Where the involved areas are small andnumerous, this method is usually ineffective becausethe mixture will flow through the areas of least resis-

Fig. 1100-22 Jacking Lugs Used on Large Tanks



June 1994 1100-33

tance and lift the plates even further. It also causes thetank to rest on points rather than uniformly.

However, there are some cases where grout can beused effectively: pressure grouting has been effectivelyused to level areas under fixed roof supports, for ex-ample.

A tank owner considering this method should examinea step-by-step proposal from the contractor to assurethat good practices are involved and that all safety andenvironmental regulations are considered. Before cut-ting the bottom to inject grout, precautions must betaken to handle the possible existence of flammableliquids or toxic substances that could have been storedor leaked in the past.

1180 REFERENCES

1. James S. Clarke, Recent Tank Bottom and Foun-dation Problems, Esso Research and EngineeringCo., Florham Park, NJ 1971

2. DeBeer, E. Foundation problems of petroleumtanks, Annal. l’Inst. Belge Petrole 1969 6 25-40.

3. D’Orazio and Duncan, Differential Settlements inSteel Tanks Journal of Beotechnical EngineeringVol 113, No 9, 12/4/1986.

4. Timeshenko, Theory of Plates and Shells, 2nd edi-tion, Table 82.

5. Timothy B. D’Orazio and James M. Duncan, Dif-ferential Settlements in Steel Tanks Journal ofGeotechnical Engineering, Vol 113, No. 9, Septem-ber, 1987 ISSN 0733-9410/87/0009-0967/$01.00

6. James S. Clarke, Recent Tank bottom and Founda-tion Problems, Esso Research and EngineeringCo., Florham Park, NJ 1971

Fig. 1100-23 Jacking Pit Dimensions



1100-34 June 1994

RESOURCES

DeBeer, E. E., Foundation Problems of PetroleumTanks, Annales de L’Institut Belge du Petrole, No. 6,1969, pp. 25-40

Malik, Z. Morton, J., and Ruiz, C., Ovalization of Cy-lindrical Tanks as a Result of Foundation Settlement,Journal of Strain Analysis, Vol. 12, No. 4, 1977 pp.339-348.

Timoshenko, S., Theory of Plates and Shells, McGraw-Hill Book Co., Inc., New York, N.Y., 1955

Sullivan, R. A., Nowicki, J. F., Settlement of Structures,Conference organized by the British Geotechnical So-ciety at The Lady Mitchell Hall, Cambridge held inApril 1974

Duncan, J.M., D’Orazio, T. B., Stability of Steel oilStorage Tanks, Journal of Geotechnical Engineering,Vol 110, No. 9, September, 1984

Duncan, J.M., D’Orazio, T. B., Distortion of SteelTanks Due to Settlement of their Walls, Journal ofGeotechnical Engineering, Vol 115, No. 6 . 9, June,1989

API 653, Appendix B.

Sullivan, R. A. , and Nowicki, J. F. 1974, DifferentialSettlements of Cylindirical Oil Tanks. Proceedings,Conference on Settlement of Structures, BritishGeotechnical Society, Cambridge, pp402-424.

Marr, W. A., Ramos, J. A., and Lambe, T. W. CriteriaFor Settlement of Tanks, Journal of the GeotechnicalEngineering Division Proceedings of the American So-ciety of Civil Engineers, Vol. 108, No GT8, August,1982.

D’Orazio, T. B., Duncan, J. M. Differential Settlementsin Steel Tanks, Journal of Geotechnical Engineering ,Vol. 113, No. 9, September, 1987.

Koczwara, F. A. Simple Method Calculates Tank ShellDistortion, Hydrocarbon Processing, August 1980

EEMUA (The Engineering Equipment and MaterialsUsers Association) Document No 159 (Draft)

Duncan, J. M., D’Orazio, T. B., and Myers, P. E., Set-tlement of Tanks on Clay, presented at ASCE Settle-ment ’94

1190 TANK SHUTDOWN CHECKLIST

This tank checklist is available on the disk included atthe end of Volume 2 of the Tank Manual. The filenameof this Lotus spreadsheet is CKLIST.WK1. The blankboxes in the “Work Completed” columns require a sig-nature. Boxes with xxxxxx’s do not.


June 1994 1100-35

Fig. 1100-1 Tank Shutdown Checklist (1 of 7)


1100-36 June 1994



June 1994 1100-37



1100-38 June 1994



June 1994 1100-39



1100-40 June 1994



June 1994 1100-41



1100-42 June 1994

1200 SPECIAL TYPES OF TANKS

Abstract

This section discusses several special types of tanks and the design considerations which set these tanks apartfrom a standard API 650 tank. Included are: elevated temperature tanks with a discussion of the hazards of op-erating these tanks (frothover, corrosion, pluming, and internal fires); low pressure tanks; underground tanks witha list of typical services and manufacturers; aboveground vertical nonmetallic tanks; Underwriters’ Laboratories(UL) tanks and sulfur tanks. The discussion of refrigerated and rubber or plastic-lined tanks has been deferred.

Contents Page Page

1210 Elevated Temperature Tanks 1200-2

1211 API 650, Appendix M

1212 Hazards of Operating ElevatedTemperature Tanks

1213 Frothover

1214 Corrosion

1215 Pluming

1216 Internal Fires

1217 Other Design Considerations

1220 Low Pressure Tanks 1200-8

1221 Standards

1222 Design Consideration

1230 Underground Tanks 1200-10

1231 Environmental Considerations

1232 Typical Services

1233 Manufacturers

1234 Design

1235 Installation and Handling

1236 Cost

1237 Company Experience

1238 Reference Documents

1240 Aboveground VerticalNonmetallic Tanks

1200-12

1241 Molded Polyethylene Tanks

1242 Fiberglass Reinforced Plastic (FRP)Tanks

1250 Underwriters’ Laboratories(UL) Tanks

1200-15

1251 General

1252 Codes and Standards

1253 Design Considerations

1260 Sulfur Tanks 1200-16

1261 Past Problems

1262 Foundation

1263 Tank Bottom

1264 Bottom Heater Coil

1265 Shell

1266 Roof

1267 Insulation

1268 Miscellaneous Features

1269 Operations

1270 Aluminum Tanks 1200-20

Tank Manual 1200 Special Types of Tanks

June 1994 1200-1

T O

C O N T E N T S

1210 ELEVATED TEMPERATURETANKS

Elevated temperature tanks are tanks containing stockabove 200°F. This section discusses the hazards of op-erating elevated temperature tanks and design changesto standard API 650 tanks which will minimize thesehazards.

1211 API 650, Appendix M

API 650, Appendix, M gives guidelines for the struc-tural design of tanks above 200°F. It does not considerthe hazards and design considerations discussed in thissection.

1212 Hazards of Operating ElevatedTemperature Tanks

The primary hazards of operating hot tanks are:

1. Frothover caused by water being vaporized by theheat of the stock.

2. Accelerated corrosion both internal and external tothe tank.

3. Pluming caused by introducing light stock into thehot tank.

4. Internal fires caused by iron sulfide buildup andsubsequent combustion when air is introduced intothe tank.

The following sections discuss these hazards in moredetail along with ways to minimize the hazards.

1213 Frothover

Definition

Frothover is the overflow of a tank occurring when en-trained or bottoms water is vaporized by the heat ofthe stock. This is distinct from a boilover which occursfrom a tank on fire when a “heat wave” reaches thebottoms water and vaporizes it. Boilovers are not cov-ered here but further information on them may befound in the Fire Prevention Manual.

Conditions Necessary for Frothover to Occur

• The tank must contain stock which will froth whenagitated with boiling water—usually a viscousstock such as a heavy residuum, asphalt, or roadoil.

• The tank must contain water. The water can be inthe form of freewater or an emulsion layer or dis-solved or entrained water in the stock. Such watermay inadvertently be introduced into a hot oil tankby one or more of the following means:

– As condensate on the inside of the tank roof orshell from water vapor in in-breathed air orblanketing gas.

– As steam leaking from the tank heater.

– As dissolved water in the stock stream due todirect contact of the stock with steam in a re-fining process.

– As dissolved or entrained water introduced intothe stock stream from a leaking process heateror cooler.

– As slugs of water or wet stock accumulated inextraneous piping connections, dead ends, etc.,and introduced into the stock stream duringtransfers.

• The temperature of the stock in the tank or enteringthe tank must be high enough to boil water underthe conditions in the tank.

• Means must exist to transfer sufficient heat fromthe stock to the water to boil it, under the condi-tions in the tank. Such means include:

– Pumping water or water-bearing stock into hotstock in a tank.

– Pumping hot stock into a tank containing awater layer, emulsion layer, or wet stock. Pock-ets of water can be trapped by sediment, par-ticularly at the shell on coneup bottoms. Theremay be water in the bottom of a hot oil tank,even when the bulk oil temperature is above theboiling point of water, because of stratificationof cooler, heavier fluid near the bottom of thetank, and suppression of boiling by pressure ofthe liquid head in the tank.

– Transfer of heat by conduction or convectionfrom a hot stock layer to a water or water-bear-ing layer.

Severity of Frothover

The severity of frothovers is variable, depending uponthe amount of water present and the heat available tovaporize it. In some cases frothover may result only insome oil being discharged through vents; in other

1200 Special Types of Tanks Tank Manual

1200-2 June 1989

cases, the roof of the tank may be ruptured. In extremecases, the release may occur with considerable violenceand the froth discharged may spread to surrounding ar-eas.

Minimize Water in the Tank

A hot tank must contain water to froth. This sectiondiscusses ways to minimize sources of water at thetank. Obviously, proper operation and maintenance ofupstream units is critical to avoid process upsets orequipment failure which could send water to a hottank. Following are some good procedures for prevent-ing water from entering or accumulating in a tank.

• Insulate the tank shell to prevent condensation ofwater vapor unless the tank is designed to stratifycold and hot oil layers as outlined below. Insulatethe tank roof to prevent accelerated corrosion. SeeSection 1214 for more details.

• Avoid internal tank heaters. Consider the installa-tion of an external tank heating and circulating sys-tem with the oil-side pressure greater than thesteam-side. Similarly, consider making or changingprocess heater or cooler installations so that the hotoil side of heat exchange units is maintained at ahigher pressure than the “wet” side.

• Avoid low spots and extraneous piping connections(dead ends, laterals, alternate lines, etc.) in the pip-ing system. Provide drains in unavoidable low spotsto eliminate settled-out water or water from hydro-static testing. Consider using high flash stocks as atesting medium when complete drainage of linescannot be assured.

• Install a cone down bottom with center sump or asingle slope bottom with maximum allowable slopeof 1-1/2% to 2-1/2% to prevent water from accu-mulating.

• Install an elbow-type bottom outlet at the shell sothat water is continually drawn off with the stock.Tanks too large in diameter for an economical sin-gle slope design bottom should be cone down withcenter sump. The typical cone down syphon outletshould be modified in accordance with Figure1200-1.

Minimize the Effect of Heat Transfer in the Tank

Frothover occurs when heat transfers between the hotstock and the water. This section discusses ways ofminimizing heat transfer.

Operate Below 200°°F, if Possible. Upstream anddownstream plants should be designed to operate thetank below 200°F, if possible. Tanks should be oper-ated above 200°F only if required for economic rea-sons or to keep the stock fluid.

Maintain Uniform Temperature Above the BoilingPoint of Water. If it is necessary to operate above200°F at any level in the tank, design facilities to en-sure a uniform tank temperature safely above the maxi-mum possible boiling point of water under the tankconditions. For safety, this temperature should be atleast 10°F above the boiling point of water under thestatic pressure equivalent to a full tank. In establishingthe uniform minimum temperature at which a particulartank is to be maintained consider the effect of fluctua-tions due to such factors as weather extremes, ther-mometry errors, and operating upsets which may

TAM12001.GEM

Fig. 1200-1 Typical Syphon Outlet for Conedown Tank


June 1994 1200-3

change the temperature of stocks entering the tank. Theuniform high temperature may be reached and main-tained by a combination of two or more of the follow-ing means:

• Insulating the tank shell (See Section 1214.)

• Heating and circulating the stock. Take suction onthe bottom outlet line, pump stock through an ex-ternal heater and return to the tank through an in-sulated externally mounted circulating line withmultiple shell inlet nozzles. Shell nozzles shouldhave internally mounted directional nozzles de-signed to heat and circulate the stock on the bottomof the tank. The tank fill system should permit fill-ing through the regular shell fill nozzle (hot feed)or the circulating and heating system (cold feed).

• Circulating stock by means of a shell mounted vari-able angle tank mixer designed for high tempera-ture service

• Feeding and drawing the tank from connections ator very near the tank bottom

• Introducing “cold” stock into a “hot” filling line ata location which will allow thorough mixing beforeentering the tank

• Installing Venturi-type inlet connections on the tank

Design for Stratification

If it is necessary to operate the tank at temperaturesbelow and above the boiling point of water under tankconditions, design an installation which will preventagitation of the “cold” stock with the “hot” stock en-tering the tank, thereby maintaining a layer of coldstock in the tank. This cold layer will insulate unavoid-able water in the tank bottom against the hot stocklayer. An example of a satisfactory design is shown inFigure 1200-2, “Schematic Layout of Appurtenancesfor a Tank Operating Both Above and Below the Boil-ing Point of Water.” This design provides the followingfeatures:

• A single slope or cone down bottom with a slopeof 1-1/2% to 2-1/2% to drain all water towards thewater draw

• A suction weir 3 feet above bottom

• A filling swing pipe set to discharge upward notless than 5 feet above bottom

• A 6-point temperature recorder to measure and re-cord the temperatures from the tank bottom to the

5 foot level at least 5 feet from the tank shell. Insmall tanks (20 feet maximum diameter) and in in-sulated tanks, however, long bayonet-type shell dialthermometers may give satisfactory temperaturereadings.

• In addition to fitting the tank with these features, itshould be operated with the low pump out in therange of 7 to 10 feet

Chemical Injection

Silicone anti-foaming agents sometimes reduce thehazard of frothover. These materials, however, poisoncertain process catalysts, so their use in specific casesmust be thoroughly investigated.

Minimize the Effect of Frothover

In locating and designing hot oil tanks subject to frot-hover, attempt to minimize the effect of a frothover asfollows:

• Locate new hot oil tanks in relatively isolated po-sitions separated from other tanks and facilities bythe maximum distance practicable. Give considera-tion to locations, if available, near non-hazardouslow-lying drainage areas that could contain majoroverflows.

• Provide firewalls so that each hot oil tank is iso-lated from the next. Tanks of 40-feet diameter orless, however, may be suitably grouped to effectfirewall cost savings. Design the impounding basinto contain a volume at least equal to that of thetank or tanks.

Arrange the layout of firewalls to direct possibleoverflow to a suitable drainage area. Metal copingsatop firewalls will turn the flow of oil back uponitself and may be used on both tank and diversionalfirewalls.

1214 Corrosion

Causes of Corrosion

Accelerated corrosion occurs in cool spots where mois-ture can condense. The condensed moisture will com-bine with H2S or SO2 to make acid which attacks thecarbon steel. Accelerated corrosion will also occur un-derneath the tank bottom if water is allowed to contactthe bottom.


1200-4 June 1989

Ways to Minimize Internal Corrosion

• Install a cone down bottom with a center sump ora single slope bottom with a bottom outlet as dis-

cussed above. This design minimizes standingwater in the tanks.

TAM12002.GEM

Fig. 1200-2 Schematic Layout of Appurtenances for Tank Operating Both Above and Below the BoilingPoint of Water


June 1994 1200-5

• Add a protective coat to the stockside in the vaporspace area. See the Coatings Manual for more in-formation on internal coatings.

• Insulate tank shell and roof to eliminate “coldspots” where moisture can condense. See the Insu-lation and Refractory Manual for details and speci-fications.

– Avoid attaching clips, brackets, or braces to theshell that would penetrate the insulation. Neces-sary insulation penetrations, such as for shellnozzles, should be fully insulated, includingvalves.

– Install a welded steel plate flashing on the topangle as shown in Figure 1200-3 to prevent wet-ting of the shell insulation behind the weather-jacket. This prevents both internal and externalcorrosion.

– On hot tanks, the engineer must account forthermal expansion in the design of both the shelland roof insulation systems. The banding on theshell weather coating must have adequate springexpansion units built in.

– For roof insulation, a metallic weatherjacketsystem is preferred. Nonmetallic weatherjacketsare generally not satisfactory for high tempera-ture tanks. Cracking or openings in the weather-jacket surface results in wet insulation. Metalweather coats must be capable of adequate lo-calized expansion and contraction without dam-age. Sealants and other nonmetallic substancesmust be suitable for the temperature encoun-tered.

TAM12003.GEM

Fig. 1200-3 Insulated Tanks—Ways to Minimize External and Underside Corrosion


1200-6 June 1989

• Protect the steel plate of the shell and roof fromexternal corrosion by coating. Inorganic zinc is rec-ommended for hot tanks.

• Design the foundation to eliminate the possibilityof water contacting the bottom.

– Do not use asphalt for the pad. A concreteringwall with concrete pad is the preferred de-sign. (See Section 520.)

– If piling is required, do not use wooden piles—they do not hold up to the heat. Concrete pilesare preferred.

– Avoid installing hot tanks in areas with a highwater table. The heat tends to pull the moistureup through the ground.

– As with all tanks, drainage of rainwater awayfrom the tanks and sealing the tank bottom tothe foundation are critical to prevent entry ofrainwater and humid air under the bottom.

1215 Pluming

Causes

Pluming, or visible emissions from the tank, can becaused by introducing low specific gravity (light)stocks into a hot tank. These volatile emissions can bea serious fire hazard if ignition sources are in the area.

The major ways light stock can be mistakenly routedto a hot tank are 1) by process upsets or mismanifold-ing, or 2) by plant shutdowns and subsequent linewashes.

Possible Ways to Prevent Pluming

While sound operational procedures are of utmost im-portance, the following design changes can also beconsidered to avoid pluming:

• Install manifolds which are dedicated to the hotstock(s). All other connections should be blinded ordisconnected.

• Install temperature indicators and low temperaturealarms on both ends of the feed line to the tank. Inaddition to monitoring temperature changes in theline, these indicators will also help the operatorsmonitor line flushes.

• Steam trace and insulate the line to avoid the needfor flushing before shutting down.

1216 Internal Fires

Causes

Pyrophoric iron sulfide fires can occur and are dis-cussed in more detail in Section 1260. Even tanks withnitrogen purge have had fires when air was introducedthrough holes in the shell or roof that were hidden byinsulation.

Minimizing the Possibility of Internal Fires

Consider using an inert purge with 5 to 6% oxygen tooxidize iron sulfide deposits as they occur. The inertpurge must be sized to keep a positive pressure on thetank when the tank is being emptied at the maximumrate. This positive tank pressure prevents air beingsucked into the tank through the vacuum breakers.

1217 Other Design Considerations

Thermal Expansion Effects

The expansion of the tank as it is heated from ambientto operating temperature must be taken into account forthe following design parameters:

• Foundation dimensions and design

• Piping flexibility

• Anchored shell connections—need to slot bolt holesin bottom plate to compensate for thermal expan-sion

• Insulation (See Section 1214)

Vacuum Breaker Design

The engineer must consider the following in sizing thevacuum breaker:

• What is the “inbreathing” rate caused by maximumcooling of the tank at low levels? Multiple breakersmay be necessary.

• Vacuum breakers on hot tanks, especially asphalttanks, tend to plug. The engineer should incorporatein the design: 1) the ability to remove and cleanthe vacuum breakers easily, or 2) additional break-ers and emergency vacuum pressure hatches tocompensate for the loss of capacity when pluggingbegins.


June 1994 1200-7

1220 LOW PRESSURE TANKS

Pressure storage tanks are divided into two categories:low pressure tanks for pressures from atmospheric to15 psig, and pressure vessels for pressures above 15psig. This section discusses the standards and designconsiderations for low pressure tanks in such servicesas LPG or refrigerated ammonia. The design of pres-sure vessels is covered in the Pressure Vessel Manual.

1221 Standards

API Standard 620, Recommended Rules for Designand Construction of Large Welded Low PressureStorage Tanks

API Standard 620 is used for the design and construc-tion of tanks with low internal pressures up to 15 psig.This Standard would not normally be used to designtanks with small internal pressures of 2.5 psi and be-low, if they are cylindrical tanks with flat bottoms. API620 can be used to design cylindrical tanks with flatbottoms for internal pressures above 2.5 psi. API 620requires the design of tank shells by stress analysis thatincludes the biaxial stress state, in contrast to the rela-tively simple formulas and rules in API Standard 650.

API 650, Appendix F, Design of Tanks for SmallInternal Pressures

API 650, Appendix F, applies to flat bottom cylindricaltanks with pressures up to 2.5 psig. Its use is discussedin more detail in Section 400.

1222 Design Consideration

General

The various elements, other than design for pressure,that are considered in the selection and use of atmos-pheric storage tanks, as discussed in other sections ofthe Tank Manual, are also generally applicable to lowpressure storage tanks.

Shell Thickness

API Standard 620 requires using free-body diagrams todetermine the summation of forces in each componentof the tank shell (API 620, Paragraph 3.10.2). Abovethe maximum liquid level, only the forces resultingfrom the internal pressure need be considered (API620, Paragraph 3.3.1). Forces resulting from both theinternal pressure and the hydrostatic head of the liquidmust be considered below the maximum liquid level(API 620, Paragraph 3.3.2). Other significant loads,

such as those resulting from the support of the tank,piping connections, insulation, snow, wind, and earth-quake, should also be considered (API 620, Paragraph3.4). Figure 1200-4 illustrates the use of a free-bodydiagram to determine the forces acting upon typicaltank shell components. See also Section 400 of thismanual.

The minimum required thickness for each componentof the shell is calculated for the largest tensile forcedetermined by the free-body diagram and the allowabledesign stress of the steel used for construction (API620, Paragraph 3.10.3). If the free-body diagram re-veals both tensile and compressive forces, the mini-mum thickness required is the larger of the twothicknesses calculated to resist the tensile force or toresist buckling by the compressive force. The capabil-ity of a tank shell component to resist buckling undera compressive force in one direction is reduced by thecoexistence of a tensile force in another direction, and,therefore, the allowable stress in compression is lowerthan that in tension. The corrosion allowance, whichcan be different above and below the maximum liquidlevel, must be added to the minimum required thick-nesses determined for the forces in each shell compo-nent.

A joint efficiency for weld seams is incorporated intothe calculation of the minimum thickness required fortank shell components (API 620, Paragraph 3.26.3).The joint efficiency used depends upon the extent ofradiographic inspection performed to verify the qualityof construction. The weld seams in tank shell compo-nents will normally be double-welded butt joints, and100% joint efficiency is permitted when full radiogra-phy of a weld seam is performed. The joint efficiencyis reduced to 85% if spot radiography is used. Lapjoints are permitted, but they cannot be properly in-spected by radiography, and their joint efficiencies arevery low.

Cylindrical, Flat Bottom Tanks

Like the requirements of API 650, API 620 (Paragraph3.11.2) requires that the design of cylindrical tankswith flat bottoms that rest on a foundation must takeinto account the uplift caused by the internal pressureacting upon the roof. However, the uplift force of tanksdesigned according to API 620 will usually be greaterthan the counteracting weight of the shell and roof. An-chor bolts are normally used to resist the excess upliftforce not counterbalanced by the weight (API 620,Paragraph 3.11.3).


1200-8 June 1989

If the foundation will support the weight of the tank’scontents without significant movement, the hydrostaticpressure acting on the bottom need not be consideredwhen determining the forces with a free-body diagramfor calculating the required thickness of the bottom(API 620, Paragraph 3.11.1).

The free-body diagram for a cylindrical tank shell witha conical or dome roof reveals an unbalanced horizon-tal force at the roof-to-shell junction, as shown in Fig-ure 1200-5. Consequently, a discontinuity compressivestress is developed in the roof-to-shell joint by the lowinternal pressure. A knuckle curvature in the roof pro-vides a gradual transition in stress from the roof to theshell, and is the preferred method for resisting the com-pressive force (API 620, Paragraph 3.12.2). If aknuckle curvature is not employed, a compression ring

must be designed to stiffen the shell (API 620, Para-graph 3.12.1). Design of the compression ring is basedupon providing sufficient area at the roof-to-shell jointto withstand all of the forces in the roof and shell atthe joint that were determined by the free-body dia-gram (API 620, Paragraph 3.12.3.2).

Internal or external structural support must be providedif a tank designed for low internal pressures could dis-tort significantly under the various conditions of load-ing that it will be subjected to in service (API 620,Paragraph 3.13.1). It may not be feasible nor economi-cal to design the tank shell to be thick enough to resistdistortion under all possible combinations of loadingthat it could be subjected to, and, therefore, additionalinternal and external structural support may be neces-sary.

Fig. 1200-4 Some Typical Free-Body Diagrams for Certain Shapes of Tanks (API 620, Figure 3-2)

TAM1200-4.PCX


June 1994 1200-9

API 620 does not give the methodology for designinginternal or external structural support. It requires thatthe structural support be designed in accordance withgood structural engineering practices (API 620, Para-graph 3.13.1.1), and that it must maintain the tank instatic equilibrium without undue elastic straining underall combinations of loading (API 620, Paragraph3.13.3). Consult with the CRTC Civil and StructuralTeam for assistance in the structural support design.

Openings in the Shell

The rules in API Standard 620 for the design of open-ings in the shell of tanks designed for low internalpressures are somewhat more stringent than those inAPI Standard 650. The requirements for the reinforce-ment of openings (API 620, Paragraph 3.16), and thepermitted details of construction (API Figure 3-6) ap-proximate those in ASME Code Section VIII, DivisionI, for pressure vessels.

Emergency Venting

The design of the roof-to-shell joint according to API620 differs significantly from that in API 650, Appen-dix F. A frangible joint that is required to fail at aninternal pressure below the maximum allowable designpressure is not permitted by API 620 to be substitutedfor emergency pressure relieving devices.

As discussed in Section 600, Appurtenance Design,emergency venting devices should be sized in accord-ance with the requirements of NFPA No. 30, Flamma-ble and Combustible Liquids Code, and API Standard2000, Venting Atmospheric and Low Pressure StorageTanks. These standards cover emergency venting re-quirements for fire as well as other possible upset oremergency conditions, such as polymerization, decom-position, vaporization of condensate, or self-reactivity.

1230 UNDERGROUND TANKS

This section discusses the Company’s experience withunderground tanks, primarily in marketing facilities. Itfocuses on fiberglass reinforced plastic (FRP) tanks be-cause, until very recently, FRP was the standard mate-rial for buried tanks. Currently, composite tanks areused more often than FRP tanks. Composite tanks havedouble steel walls with fiberglass resin over the outerwall. Some existing steel tanks have been retrofittedwith FRP liners. The inspection and quality control re-quirements discussed in Section 1000 and 1240 alsoapply to this section. Underground concrete sumps andseptic tanks are covered in the Civil and StructuralManual.

TAM12005.PCC

Fig. 1200-5 Internal and External Structural Support


1200-10 June 1989

1231 Environmental Considerations

Many state and local governments regulate the instal-lation of underground tanks. They require varying de-grees of secondary containment, tank level monitoring,and groundwater monitoring. It is essential that engi-neering and operations understand these regulationswhen considering an underground tank installation.

In areas other than Marketing Service Stations, ourphilosophy should be to explore all of the other op-tions before installing an underground storage tank.

1232 Typical Services

Underground FRP tanks have been used extensively forfuel storage. The majority of these applications havebeen for gasoline storage in service stations. The obvi-ous advantage of fiberglass over carbon steel is thatfiberglass does not corrode as a result of adverse soilconditions or water in the tank. Federal law currentlyprohibits the installation of unprotected steel tanks ex-cept in locations where the electrical resistivity of thesoil is extremely high (thus the soil is presumed to benon-corrosive). Fiberglass tanks comply with federalstandards for external corrosion protection. In addition,when properly installed, these tanks meet the require-ments of NFPA Standard No. 30, the Uniform FireCode, and virtually all local codes governing the stor-age of flammable and combustible liquids.

All FRP tanks must be compatible with the liquidstored. Marketing has test requirements for qualifyingresins. Most common fuels are readily stored safely inFRP tanks, but some, like methanol, can break downfiberglass resins.

1233 Manufacturers

The two primary suppliers of underground FRP storagetanks are:

O/C FiberglassFiberglas TowerToledo, Ohio 43659(419) 248-6567

Xerxes Corporation7901 Xerxes Avenue SouthMinneapolis, Minnesota 55431(612) 887-1890

Both manufacturers make tanks approved by Under-writers’ Laboratories, Inc., and by Factory MutualLaboratories. These tanks are available in many stand-

ard sizes ranging from 550 to 12,000 gallons. Largertanks can be fabricated for unique applications.

The composite tank (also UL-approved) is supplied by:

Joor Manufacturing, Inc.1189 Industrial AvenueEscondido, California 92025(619) 745-0333

1234 Design

The standard tank (FRP or composite) is now a dou-ble-walled tank with leak detection for the annulus.This design is used to avoid groundwater contamina-tion from leaks. Piping is also double walled.

1235 Installation and Handling

FRP tanks are very susceptible to impact damage. Dur-ing transportation and offloading, they must be treatedwith more care than would be required for steel tanks.Handling tends to be easier since a plastic tank weighsroughly one-third as much as a steel tank of similarcapacity. To ensure that tanks have not been damaged,they should be tested when they arrive at the site aswell as after they have been installed.

Installation of FRP tanks requires an experienced con-tractor. The gravel or crushed rock which is used forbedding and backfill must be carefully placed such thatthere are no voids around the tanks. Since the FRP tankrelies on the rock backfill for much of its structuralstrength, poor backfilling could cause a tank failure.

Installation, handling and testing of fiberglass tanksshould be carried out in accordance with the manufac-turer’s instructions. In addition, CUSA Marketing Op-erations has developed detailed specifications andinstructions covering underground FRP tanks. See Sec-tion 1238 for a list of these references.

1236 Cost

As is the case for aboveground tanks, undergroundFRP tanks are generally more expensive than carbonsteel tanks. However, with the requirement for externalcorrosion protection of underground steel tanks, thecosts are now much more comparable.

1237 Company Experience

CUSA Marketing has extensive experience with FRPtanks for storage of motor vehicle fuel and used oil at


June 1994 1200-11

service stations. The first fiberglass tank at a Chevronstation was installed in 1971, and their use becamewidespread throughout the seventies. By 1979, it be-came Company policy to install only FRP tanks inservice stations. This development is typical of the in-dustry as a whole, for virtually every major oil com-pany now uses FRP tanks for underground storage ofmotor vehicle fuels.

In 1982, CUSA Marketing and CRTC’s Materials andEquipment Engineering Unit developed a detailedspecification covering the fabrication of undergroundfiberglass tanks to be used for product storage (seeSection 1238). Among other things, the specificationrequires that Company tanks have a greater cross-sec-tional wall thickness than is standard for the industry.In addition, the tanks are lined with a special vinyl es-ter resin, providing increased resistance to deteriorationby alcohol blend gasolines.

Underground fiberglass tanks installed according to thisspecification have performed well. Failures are rare,and are largely confined to early generation tanks.

1238 Reference Documents

1. Chevron U.S.A. Inc. Marketing Operations, Under-ground Tank and Piping Installation Drawings andSpecifications, 81-HQ-160 through 81-HQ-178.

2. Chevron U.S.A. Inc. Marketing Operations, Speci-fication MO-8000, “Underground Storage Tanks-Fi-berglass.”

3. Chevron U.S.A. Inc. Marketing Operations, Speci-fication MO-8010, “Double-wall Steel Tank WithFiberglass Coating.”

1240 ABOVEGROUND VERTICALNONMETALLIC TANKS

1241 Molded Polyethylene Tanks

Recommendation

Vertical, molded polyethylene tanks are generally notrecommended for use. They can be considered for tem-porary installations where the consequences of failurewould not be severe, and they can be used for perma-nent installations in smaller sizes (up to about 200 gal-lons) where the “Concerns and Deficiencies” listedbelow can be accommodated or accepted. The tempera-ture limit for these tanks is only 100°F. Because thesetanks are made of a highly corrosion resistant material

and are inexpensive (less costly than metal or FRPtanks), they are tempting to use, and have been usedsuccessfully for water treatment chemical storage.

Specifications

The following Company specificaton was written forpolyethylene tanks:

Specification No. SF-S-974, “800-Gallon SecondaryContainment Tanks Made of Crosslinked High DensityPolyethylene,” Chevron USA, Western Region Produc-tion, 7/15/88, M.T. Mc Donald.

Materials

Crosslinked polyethylene is preferred over non-crosslinked because the latter material is more proneto tearing of the shell wall.

Tank Construction

The basic polyethylene tank is produced by the rota-tional molding process. This process depends on moldmovement, heat, and gravity to mold a part. No pres-sure is applied. In the process, hollow molds are loadedwith a predetermined weight of powder. The weight isdetermined by the wall thickness required. The chargedmold is put into a hot air oven or other heat sourceand simultaneously rotated at slow speed (1 to 20 rpm)on two perpendicular axes. As the mold heats, the pow-der sticks to the mold surface to form the part. Afterall the powder has completely adhered to the mold, ad-ditional heating time causes the powder to melt andfuse together to develop the resin properties. Parts notproperly cured (crosslinked) will crack or shatter whenimpacted.

Controlled heating of the mold by adding insulatingmaterial to some of its exterior will cause the amountof powder that sticks to the mold to vary in differentlocations; in this way a tapered wall tank can be pro-duced (thinner at the top than near the bottom). Afterfusing, the mold is removed from the heat source,cooled, and the part demolded. A separate mold is re-quired for each tank size.

Fittings. Virtually all fittings are installed in the tankafter demolding. Fittings are of the bulkhead or thru-bolted type, installed by cutting a hole in the tank.Polyethylene foam gasketing is used between the fit-ting and tank wall. Bulkhead fittings are available inpolypropylene or PVC; thru-bolted fittings are Type304 or 316 stainless steel with studs and nozzle neckwelded to the inside plate. The nature of the fitting re-quires a threaded end; a threaded flange could be


1200-12 June 1989

placed on it. There is no additional tank wall thicknessfor opening reinforcement.

Restraints. There are no tank hold-downs molded intothe tank or attached later. For vertical tanks the recom-mended restraint consists of steel posts installed aroundthe tank with a slack cable strung between the posts.

Design calculations are commonly limited to wallthickness based on hoop stress and the post/cable re-straint system for wind and seismic loads; resistance ofthe tank wall to buckling from seismic loads (afrequent deficiency in FRP tanks) is not normallychecked.

Concerns and Deficiencies

Wall thickness cannot be carefully controlled. It ischecked on nozzle cutouts which are usually located atonly a couple of elevations.

The vendor’s recommended restraint system forwind and seismic loads would allow substantial tankmovement with objectionable loads on piping, tank fit-tings, and the tank wall. To lessen this problem, oneequipment packager designed a close fitting restraintsystem of steel posts with a rolled steel band weldedto the posts; another alternative is to pour a concretering around the bottom of the tank and place steelhold-downs across the top of the tank that are tied tothe concrete ring. However, even with an improved re-straint system, tank diameter grows enough betweenempty and full condition that piping flexibility must becarefully considered; flexible PVC pipe or hoses havealso been used.

Tank fittings of both polypropylene and PVC have ex-ternal threads to accommodate the nut that cinches thefitting against the tank wall. There are three problemswith these fittings:

1. Although the threads approximately match pipethreads and are intended for the attachment ofthreaded pipe fittings, they are straight threads;when a pipe fitting (which has tapered threads) isattached, there is good contact only at the firstthread of the tank fitting, which makes a weak con-nection and does not seal well.

2. Failures are chronic and premature at externalthreads in plastic fittings.

3. The gasket for the tank fitting is inside the tank;you must enter the tank to replace the gasket.

Thru-bolted stainless steel fittings will solve the firsttwo problems, but the piping connection on these fit-

tings must always be threaded because of the nature ofthe fittings.

Clips. Polyethylene cannot be joined by adhesives.Therefore, piping support clips, ladder clips, and plat-form clips could not be attached to the tank unlessbolted through the tank wall.

Flat, bolted-on tops always sag, so rain and washwater collects and then runs freely into the tankthrough gaps around the access opening; the tank mustbe entered to tighten or replace the bolts that attach thetop to the tank.

Irregularities in tank molds produce offsets in thetank wall up to 5/8 inch and noticeable “hourglassing”of some cylindrical sections.

Pinholes through the tank wall, the most common de-fect, are repaired by the manufacturer with a hot gluegun. The material used for repairs is not defined. Ad-hesives do not bond to polyethylene and are not a goodrepair material.

Improper cure (crosslinking) can result in poor impactresistance. Impact tests on tank cutouts are not nor-mally made but can be made at added cost.

Inspection

Shop inspection is not warranted on small tanks. Fortanks over 500 gallons, one shop visit for final inspec-tion is sufficient. The Quality Assurance section of

Purchasing performs the shop inspection, which in-cludes the following:

• Visual inspection of all surfaces inside and outsidefor significant flaws

• Dimensional check, including elevations and orien-tations of all fittings

• Verification that tank fittings are the size and typespecified

• Witnessing of the hydrostatic test (may requireseparate visit)

1242 Fiberglass Reinforced Plastic (FRP)Tanks

Recommendation

Vertical FRP tanks can be used as a less costly alter-native to high alloy or lined carbon steel tanks for cor-rosive services or services where the contents of the


June 1994 1200-13

tank must not be contaminated with rust or mill scale.Shop fabricated tanks are recommended. Shop facilitiesusually limit tank diameter to about 12 feet. Somelarger field erected FRP tanks have been built, but theCompany does not have experience with them. Highalloy or lined carbon steel tanks have been used forfield erected tanks. Temperature limitations of FRP de-pend on the contents of the tank and the resin used inconstruction; typically the upper limit is about 250°F.For many applications a complete design/constructionpackage is warranted, as discussed below.

Specifications, Standards, and Design

TAM-EG-3453 is the Company specification for verti-cal aboveground FRP storage tanks. It covers design,construction, and inspection requirements for FRPtanks, including calculation procedures for determiningshell thickness and hold-down bracket design to with-stand seismic and wind loads. TAM-EG-3453 refers toseveral basic industry standards; the most important isAPI 12P. API 12P is not very stringent. TAM-EG-3453corrects many of the shortcomings of API 12P but can-not cover all design and construction details in depth.For this reason a complete design/construction packageshould be prepared by an engineering firm with FRPdesign experience for FRP tanks or equipment where:

1. Failure would pose a significant hazard to person-nel or equipment.

2. Failure would cause substantial loss of revenue.

3. Contents of the tank are aggressively corrosive orover 200°F.

4. The tank is subjected to internal pressure or vac-uum.

In all other cases the quotation request should include:

1. TAM-EG-3453.

2. An outline drawing of the tank.

3. A Tank Data Sheet TAM-DS-3453, which includesa description of tank contents and stock properties.

4. Standard Drawing GD-D1265, which gives standardconstruction details for FRP tanks.

Tank Construction

Fibergla ss Reinforced Plastic (FRP) is a compositenon-homogeneous material made of a thermosettingresin reinforced with glass fibers in various forms.Tanks are normally made on molds that correspond to

the inside surface of the tank. Nozzles and other ap-purtenances are attached to the tank later, by means ofoverlays of glass fiber material that is wetted withresin. The tank laminate normally consists of an innercorrosion barrier (or liner ) for corrosion resistanceand a structural layer for strength.

There are three principal methods of building the struc-tural part of the tank wall.

1. Hand layup using chopped glass, often with inter-spersed layers of woven glass filaments.

2. Filament winding using continuous glass filamentswith a defined helix angle; reinforcement in the ax-ial direction is usually provided by interspersinglayers of woven glass filaments or unidirectionalfilaments in the axial direction.

3. Hoop winding using continuous glass filamentswithout a helix angle; this construction always re-quires interspersing layers of glass for axialstrength.

For all three construction methods the glass fiber ma-terial is thoroughly saturated with resin before or dur-ing its application.

Hoop winding is the most commonly used method forthe structural part of the tank wall since it requires theleast amount of material for required hoop strength andpermits a tank shell to be built quickly with low capitalexpenditure for the vendor’s plant equipment.

The inner corrosion barrier is applied to the mold be-fore the structural layer and consists of glass or syn-thetics to reinforce this resin rich layer (pure resin isbrittle and would crack without reinforcement). Con-tinuous filaments or woven filaments are never used inthe inner corrosion barrier.

Concerns and Limitations

The following limitations of vertical FRP tanks shouldbe addressed when considering their use for service.

1. FRP is easily damaged by impact.

2. The inner corrosion barrier is usually 0.1-inchthick; if part of it is lost through corrosion, erosion,or mechanical damage, rapid failure of the tank canoccur by liquid wicking along the glass filamentsin the structural layer.

3. Mating flanges must be flat faced with full faceelastomeric gaskets. Flange bolting procedures mustbe carefully controlled to avoid cracking flanges.


1200-14 June 1989

4. Piping must usually be independently supported toavoid damage to nozzles or nozzle/shell joints.

5. Most FRP fabricators have limited engineering ca-pabilities; most are unable to make seismic or windcalculations to show that the tank wall will resistbuckling and that tank hold downs are adequate(these design deficiencies are found frequently).Most FRP tanks have a height-to-diameter ratiogreater than 1, so hold downs are almost always re-quired for seismic forces, wind forces, or both.TAM-EG-3453 addresses this problem, but the fab-ricator’s calculations must be reviewed thoroughly.

6. Extreme care must be taken in setting the tank onits foundation. A sound way to set a tank is in ce-ment grout that is not too stiff; then put 1 to 2 feetof water in the tank to set it firmly into the grout.Excess grout is removed from around the tank sothat a grout “dish” is not formed that would collectspills and water. Stiff grout must also be packed un-der hold-down lugs. The grout must be allowed tocure before nuts on anchor bolts are tighteneddown. This precaution prevents damage to the tankwall or the glass windings that fasten the lugs tothe tank.

Inspection

Since an FRP tank is a composite structure that essen-tially is hand made, inspection must be done muchmore carefully than on a metal tank where welds arethe principal concern. It is difficult to find qualifiedFRP inspectors. Consequently, inspection costs for FRPtanks will be higher than for metal tanks. The QualityAssurance section of Purchasing performs (or hiresout) shop inspection that includes the following.

1. A pre-inspection meeting to review the purchase or-der, specifications, and our inspection requirements.

2. Visual inspection of the first course of the tankwhen it is removed from the mold.

3. Inspection during joining of shell courses.

4. Inspection during installation of nozzles.

5. Final inspection inside and outside of all surfaces(to the specified or approved acceptance standardfor flaws) when the tank is complete but prior toapplication of exterior color coat. Barcol hardnesstests and acetone sensitivity tests are witnessed atthis time.

6. Inspection after application of exterior color coat.

7. Witnessing of hydrostatic test. Hydrostatic tests arevery important and, if not obtainable in the shop,should always be done in the field before the tankis put in service. Hydrostatic tests should be heldfor 8 or more hours, and all surfaces of the tankinspected for leaks, seeps, or weeps.

1250 UNDERWRITERS’LABORATORIES (UL) TANKS

This section covers the design and use of shop-fabri-cated steel tanks that meet the Standards for Safety ofUnderwriters’ Laboratories, Inc., and are furnished bythe manufacturer with a “UL” label. Underwriters’Laboratories, Inc., is a non-profit organization that op-erates laboratories in the United States for the purposeof testing various devices, systems, and materials forpublic safety.

Fiberglass reinforced plastic UL tanks, used almost ex-clusively for the underground storage of products atservice stations, are discussed in Section 1230.

1251 General

UL tanks are primarily intended for the atmosphericstorage of non-corrosive flammable and combustibleliquids. They must be fabricated and tested before be-ing shipped from the factory. This requirement limitstheir size. The maximum diameter of horizontal tanksis 12 feet and the maximum height of vertical tanks is35 feet. The maximum capacity of a UL tank is about1000 barrels.

Within their size limits, both horizontal and verticalsteel tanks are used extensively for aboveground stor-age in bulk plants. They may be acceptable for use inother services such as small tanks in process plants.Vertical aboveground UL tanks are frequently less ex-pensive than the corresponding API 650, Appendix Jtank, a result both of less stringent requirements of ULstandards and the standardization inherent in UL tankdesigns.

1252 Codes and Standards

Steel Tanks

The Standards for Safety published by Underwriters’Laboratories, Inc., are as follows:

1. UL 58: Steel Underground Tanks for Flammableand Combustible Liquids. (Also approved as ANSIB137.1).


June 1994 1200-15

2. UL 142: Steel Aboveground Tanks for Flammableand Combustible Liquids.

Copies may be obtained directly from Underwriters’Laboratories, Inc. Their address is given in Section 140of this manual.

Fiberglass Reinforced Plastic Tanks

There are, at present, no UL standards for fiberglassreinforced plastic tanks. However, underground storagetanks fabricated of this material with a UL label areavailable from some manufacturers. (See Sections 1230and 1240.)

Other Regulations

Tanks fabricated in accordance with the above ULstandards comply with the Occupational Safety andHealth Standards (OSHA) of the U. S. Department ofLabor. They also comply with the NFPA 30 “Flamma-ble and Combustible Liquid Code.”

1253 Design Considerations

General

Design factors discussed elsewhere in the Tank Manualcan be applied to UL tanks. The existence of the ULlabel does not remove the need to exercise good engi-neering judgment. Underwriters’ Laboratories only pro-vides audit inspections of production. Unless previousexperience with a manufacturer indicates that it is notneeded, limited Company inspection should also beconducted.

Material and Design Requirements

Users of UL steel tanks should recognize that the UL58 and UL 142 Standards do not specify material anddesign requirements as closely as API 650, AppendixJ. This statement is not intended to imply that UL tanksare not adequate or acceptable for many servicesthroughout the Company. It is mentioned only to high-light the fact that there are different requirements thatmay affect the quality of the product. The most signifi-cant of these are as follows:

• UL standards specify that the tanks shall be con-structed of commercial grade steel of good weldingquality as compared to specific ASTM specifica-tions designated in API 650.

• UL standards permit various types of lap weldedshell joints in addition to a full penetration buttwelded joint, the only type of joint permitted by

API 650. Lap welded joints increase stress concen-trations and are difficult to inspect for quality ofwelding. When ordering vertical aboveground ULtanks, you should consider specifying butt weldedshell joints.

• Vertical UL tanks less than 10 feet in diameter donot have a frangible shell-to-roof attachment. Emer-gency venting should be provided on these tanks.Refer to Section 600 for guidance.

Foundations and Supports

Underground tanks must be designed to withstandground surface loads and resist uplift due to groundwater. Typically, for steel tanks the excavated hole ispadded with 6 inches of sand, and a minimum of 3feet of cover is provided for tanks located under pav-ing. Where ground water might float the tank, the mostcommonly used preventive measure is to provide aconcrete slab immediately above the tank. Alternatemethods are to place a concrete slab under the tankand use screw-in-type anchors; both of these requirestainless steel straps to hold down the tank.

Pier foundations or supports for aboveground horizon-tal tanks must be designed to adequately support thetank. Steel supports should be fire protected. Woodsupports are not recommended and, in the UnitedStates, are forbidden by OSHA regulations.

Wind and Earthquake Stability

Refer to Section 400 and the referenced Civil andStructural Manual, Section 100, for information on de-sign factors that will assure that aboveground UL tankswill resist wind and earthquake forces.

Location and Fire Protection

Refer to Section 200 for a discussion of factors to con-sider in choosing location and spacing of tanks and forgrounding information. Although NFPA requirementsare widely recognized, they might not always be thelimiting regulation.

1260 SULFUR TANKS

This section discusses the problems the Company hashad with tanks storing liquid sulfur. It lists the designchanges made to minimize these problems.


1200-16 June 1989

1261 Past Problems

Past problems can be grouped into three basic areas:internal corrosion, external corrosion, and pyrophoriciron sulfide fires.

Internal Corrosion

Moisture condenses in the tank, combining with H2Sand SO2 to make acid which attacks the carbon steel.Moisture can enter the tank in the following ways:

• Through the steam smothering system

• Through leaks in jacketed nozzles and lines

• Through leaks in the internal steam coil

• From air with high humidity

The steam tends to condense in areas where the shellor roof metal surface is coolest. Cool spots can becaused by inadequate or water-soaked insulation, me-tallic penetrations to the shell through the insulation,or by uneven heating in the tank.

External Corrosion

Water-soaked insulation on roof and shell causes severeexternal corrosion. It can also cool the metal offenough to promote internal corrosion, as mentionedabove. The water soaked insulation results from:

• Leaks from roof steam coil

• Poor roof sealing and flashing

• Leaks from jacket nozzles

• Failure of the roof weathercoat system

Pyrophoric Iron Sulfide Fires

Iron sulfide (FeS) forms on the interior metal surfacein the vapor space. If it is allowed to build up, it willspontaneously ignite in the presence of oxygen. Inmost cases, an SO2 plume is the only indicator of afire. Iron sulfide fires cause:

• Weakened roof supports which can buckle the roof

• Increased corrosion because smothering steam isoften used to stop the fire

Iron sulfide builds up in an inert atmosphere. Our ob-jective should be to have sufficient air sweepingthrough the vapor space so that the FeS oxidizes asquickly as it builds up.

The following sections discuss the changes which canbe made to an existing sulfur tank or added to a newtank design to prevent these three problems and extendthe tank life (approximately 10 years).

1262 Foundation• Install the tank on a concrete pad to avoid settling

in the center of the tank

• Install a single slope bottom with a slope of 2inches in 10 feet. This helps empty the tank whenit is being taken out of service. Any sulfur left inthe tank usually must be hydroblasted out—whichaccelerates internal corrosion.

1263 Tank Bottom• Use butt welded plate with a 1/8-inch backing strip.

Richmond used 1/2-inch thick plate to give somecorrosion allowance. The butt welded plate im-proves the drainage.

• Rough surfaces have been shown to be much moresusceptable to pitting. El Segundo grinds the buttwelds flush and smooth, and dyechecks for porosi-ties.

1264 Bottom Heater Coil• A bottom coil is recommended over a bayonet

heater because it provides much more even heatingof the tank.

• Design the coil in multiple cells (Richmond used4) to provide even heating.

• Use 316L Schedule 40 pipe to prevent the externalpitting and leaks experienced with carbon steel.

• Richmond used 2-inch pipe with rolled bends (18-inch diameter) to minimize internal welds.

• Install the coil the minimum distance from the floorthat will still allow easy drainage and cleaning. Sixinches from the pipe centerline to the floor is ade-quate. Minimize the height to prevent prolongedpluming when the tank is being filled initially.

1265 Shell• Install the outlet nozzle flush with the bottom

mounted on an API 650 flush-type cleanout door.See Figure 1200-6. This arrangement helps empty


June 1994 1200-17

the tank and prevents damage from hydroblastingwhen the tank is cleaned. The outlet nozzle mustbe completely encapsulated with insulation that isprotected from outside moisture—especially fromground moisture.

• Be liberal with the corrosion allowance on the shellplate. Richmond used 1/4 inch.

• For new tanks, minimize shell height. A large vaporspace results in cooler metal and increased corro-sion at the top of the tank.

• Consider a self-supporting stairway. Stairway-to-shell attachments can act like fins cooling the metalsurface and thereby accelerating corrosion.

• Minimize the penetrations through the insulation.Insulate all necessary penetrations.

1266 Roof

Corrosion Protection

• Consider adding corrosion allowance above thatnormally required. This added allowance increasesthe rafter size and gives more protection againstcorrosion and damage to the roof during a fire.

• If the diameter of the tank permits, install a self-supporting dome or externally supported roof. Thisdesign allows coating of the internal surfaces of theroof, eliminating iron sulfide corrosion.

External Roof Heater Coil

• An external roof heater is needed to keep the inter-nal surface above the condensation temperature.

• Consider using socket welded tubing, TIG weldedper the Swagelock procedure. Richmond used 0.065inch wall, 316L tubing. The alternatives are tubingwith compression fittings, which historically have

TAM12006.GEM

Fig. 1200-6 Outlet Nozzle Configuration


1200-18 June 1989

leaked, or socket welded pipe, which is more costlyto install.

The other advantage of socket welded tubing is thatyou can put a full hydrotest (450 psig) on it comparedto only a service test for compression fittings.

• Use 1/2-inch tubing for the roof and 1/4-inch tub-ing with Thermon heat transfer cement for the noz-zles and vents.

• Richmond added a condensate collection header onthe roof to keep the tubing runs shorter and moreeffective. Each tubing run was trapped. The numberof cells depends on the length of tubing run.

1267 Insulation

Shell Insulation

• Normally use 3 inches of fiberglass insulation withaluminum weather jacketing. See the Insulation andRefractory Manual for guidelines and specifica-tions.

• Install extra insulation on the upper part of theshell. This is needed to eliminate the fin effect fromthe top angle. (See Figure 1200-7.)

• Install extra insulation on nozzle and valve bodiesto cut down on stockside corrosion.

Roof Insulation

• The standard Owens Corning Roof Deck insulationis used (see Insulation and Refractory Manual).Richmond used 4-inch thick insulation.

• Sealing is very important. In the past, a tar andgravel sealer has been applied on top of the insu-lation. This sealer, however, does crack and allowmoisture to leak into the insulation; and it inhibitsmoisture already in the insulation from premeatingout.

As an alternative to tar and gravel sealer, Richmondused a Belzona Flexible Membrane over the RoofDeck insulation. This membrane is flexible yet allowssome permeation of water vapor. Experience with thistype of membrane is limited.

TAM12007.GEM

Fig. 1200-7 Sulfur Tank—Roof-to-Shell Flashing Details


June 1994 1200-19

Other refineries have had some experience with a me-tallic Thermacon weathercoating system held in placeby cables. This looks like an excellent product. Consultthe CRTC Materials and Equipment Engineering Unitif you have any questions on this subject.

Flashing

The roof-to-shell flashing design is extremely impor-tant. Figure 1200-7 shows a cross section of the flash-ing detail at the roof-to-shell joint. The major featurehere is a 6-inch, 10-gage, 304 stainless steel strip con-tinuously seal welded to the top angle. This strip pre-vents moisture underneath the roof insulation frommigrating under the shell insulation. This strip mustalso be insulated so that it does not act as a fin andactually cool the shell, causing corrosion problems.

1268 Miscellaneous Features

Smothering Systems

• If possible, use an N2 smothering system. This sys-tem eliminates a large source of moisture in thetank. Size the system to make the tank inert in 10minutes. Use this system only to smother a fire.

• If steam smothering is required, mount the controlvalve as close to the tank as possible to eliminatethe chance of a deadleg of condensate building updownstream of the valve.

Blanketing

• Some plants have used N2 blanketing to keep thetank inert. This is not recommended because it al-lows pyrophoric FeS to build up, resulting in firewhen oxygen enters the tank.

• We recommend installing six 8-inch vents on theroof every 60 degrees around the tank. An eductorpulls an air sweep into the vents through the tankand out the eductor line located at the center of theroof. This air sweep provides enough oxygen tocontinuously oxidize the FeS, preventing it frombuilding up. The vents need to be capped to keepthe rain out. The educted air usually goes to a caus-tic scrubber for removal of the H2S.

1269 Operations

Operate the tank with a minimal vapor space. Thismethod keeps the top warmer and provides less volumeto sweep.

1270 ALUMINUM TANKS

Introduction

Aluminum has a number of attributes that assure it aniche in the structural metals market: it’s light weight(approximately 1/3 the density of carbon steel, 0.1lb/in3) and its corrosion resistance. While its lightweight can be valuable, aluminum’s low modulus ofelasticity requires attention to control of deflectionsand buckling. By alloying aluminum with other ele-ments, physical properties comparable to carbon steelsmay be achieved. Also, the reflectivity of aluminummay eliminate the need for surface treatments. In non-structural applications, its high thermal and electricalconductivity are well known. Aluminum may beformed, machined, joined, welded and fastened bystandard methods and equipment that are also used incarbon steel fabrication.

Corrosion of Aluminum

Aluminum’s corrosion resistance is due to a thin alu-minum oxide film which forms quickly when alumi-num is exposed to oxygen and some aqueous solutions.Anodizing the surface by treating it with certain acidssimply builds a thick oxide layer. Because the tena-cious oxide film forms so readily, it will renew itselfwhen abraded away or chemically removed.

Aluminum responds to crevice corrosion by buildingup voluminous quantities of “white rust” or aluminumoxide. This is common where an aluminum surface istightly pressed against another surface. Potential forcrevice corrosion is high in tank bottoms because theseare often lap welded and corrosion starts from the un-derside.

The corrosion chemistry of aluminum is complex. Forexample, 0.1% water in methanol prevents corrosion,even at high temperatures, whereas a trace of water ac-celerates corrosion. However, because aluminum is im-mune to the corrosive effects of many chemicals, it isa candidate for tank construction.

Aluminum tends to pit with water that has chlorideions in it. Levels as low as .1 ppm of copper or of ironin water can react with aluminum, depositing metalliccopper or iron at local sites, which initiate pitting.Therefore, aluminum is not suitable for any tankswhich may have trace heavy metals in the stored liq-uid.

Cladding aluminum is an efficient way of reducingthrough-wall pitting. Alclad products are high strengthalloy cores, in sheet or tubing form, that have clad lay-


1200-20 June 1989

ers of pure aluminum or aluminum alloys bonded tothe core. The cladding is engineered to be anodic, orsacrificial to the core, and essentially creates a built-incathodic protection system. The clad material is usuallyless than 10% of the thickness of the total material andis non-heat treatable. Because of the sacrificial clad-ding, the corrosion progresses through the cladding butstops at the core.

Alloys

Numerous alloys are available for industrial applica-tions, each in a broad range of tempers. The AluminumAssociation has established a system of numerical des-ignations for all alloy grades in general commercialuse. These designations standardize the specificationsand properties of the material, regardless of the source.

The wrought alloys and temper designation are:

Aluminum 99% + pure 1xxxAlloying Element copper 2xxx

manganese 3xxxsilicon 4xxxmagnesium 5xxxmag and silicone 6xxxzinc 8xxxother 9xxx

Temper Designations are:

F = as fabricatedO = annealedH = strain hardenedW = solution heat treatedT = thermally treated to produce stable tempers

other than F, O, or H

Aluminum as a pure element is relatively lowstrength. The strength is enhanced by addition ofsmall amounts of other elements, heat treatmentand/or strain hardening, or cold working. Heat treat-able means the strength can be enhanced by heattreatment: non-heat treatable alloys can be coldworked for strength enhancement.

Applications

Aluminum is commonly used in hoppers and silos forplastics and resin storage. It is commonly used in thechemical industry for storage of fertilizers. Becausealuminum shows no low-temperature embrittlement, ithas been used in cryogenic storage. The non-sparkcharacteristics of aluminum alloys make is useful forsome applications where flammability is involved. Fig-

ure 1200-8 is a list of chemicals typically stored in alu-minum.

Figure 1200-8 appears at the end of this section.

Water Storage

Because aluminum is compatible with pure water, dis-tilled water, deionized water, uncontaminated rainwaterand heavy water used in nuclear reactors, aluminumstorage tanks are a cost effective material for these ap-plications. There is virtually no metal contamination ofwaters. For potable water, the amounts of dissolvedaluminum and salts are considered safe. Because sur-face preparations and coatings are not necessary, thealuminum storage tank will often be competitive withcoated carbon steel storage systems.

Fresh water is categorized as follows:

•Waters containing heavy metals such as copper, nickeland lead. Aluminum is not recommended for theseservices because the heavy metals may contribute tohigh pitting rates.

•Neutral or near-neutral waters. For waters in a pHrange of 6 - 9 there need be little concern about cor-rosion.

•Alkaline waters. A pH range of 8.5 - 9 is acceptable.

•Acid waters. A pH range of 4 or higher is acceptable.

Treated Water: Water containing dissolved gases suchas carbon dioxide or oxygen in condensate applicationsor water containing amines, chromates and polyphos-phates or other alkaline inhibitors. Aluminum may beused for these do not adversely affect the use applica-tions.

Recirculated water may become corrosive to alumi-num because it picks up copper and iron from variousequipment such as pumps, pipes, and instrumentation.The dissolved metals plate-out on the aluminum, caus-ing localized pitting. If the water is treated with inhibi-tors and cathodic protection, the problem can becontrolled.

High purity water systems can be a candidate for alu-minum storage systems. Aluminum is often used tostore heavy water from nuclear reactors.

Steam Condensate: If the water is free from boilercarry-over, aluminum may be used as it is unaffected


June 1994 1200-21

by condensate; however, alkaline water-treating com-pounds may be corrosive.

Sea Water: Copper-free aluminum alloys are resistantto clean sea water. The corrosion that occurs is usuallylocalized pitting.

Design, Materials, Fabrication, Construction andTesting

The recognized standard that covers the details for cy-lindrical aluminum storage tanks is ASME B96.1. Ad-ditional information about this standard is availablefrom P. E. Meyers (CTN 242-7215).

Costs

Cost considerations for aluminum tanks include mate-rials cost, labor costs and recurring maintenance costs.From the long-term viewpoint, the recurring costs ofrecoating or repainting becomes significant. From ashort-term view, the initial-installed cost is all that mat-ters. Other factors that could affect cost are plant shut-downs caused by unexpected failure of materials dueto corrosion, fatigue, or mechanical failure.

Recommendations

For some applications aluminum may be cost-competi-tive with stainless steel tanks if prices continue theirdownward trend. When aluminum tanks are shop fab-ricated, the costs per-unit-volume of storage capacityshould be lower because of the controlled conditionsneeded for welding and fabrication of aluminum. An-other significant advantage to shop fabricated tanks isthat the bottom may be coated so that pitting on theunderside is not a problem.

Because even trace quantities of various elements canaccelerate corrosion in aluminum, a compatibility studymust be conducted before using aluminum storagetanks.

REFERENCES• ASME, B96.1, “Welded Aluminum Alloy Storage

Tanks”

• Alcoa Structural Handbook

• Aluminum Association: “Aluminum in Storage”

• Aluminum Association: “Specifications for Alumi-num Structures”

• Aluminum Association: “Aluminum Standards andData 1990”

• Aluminum Association: “Specifications for Alumi-num Sheet”

• American Society of Metals, “Metals Handbook,Desk Edition,” 1985 LaQue and Copson, “Corro-sion Resistance of Metals and Alloys,” 2nd ed,American Chemical Society Monograph Series, Re-inhold Publishing Corporation, NY, 1963

• Editor: Hatch, “Aluminum Properties and PhysicalMetallury” American Society for Metals, 1984

• Editor: Uhlig, “The Corrosion Handbook,” Wileyand Sons, 1948

• Jawad and Farr, “Structural Analysis and Design ofProcess Equipment”

• Moody, “Analysis and Design of Plastic StorageTanks” Transactions of the ASME May 1969 pp.400

• Uhlig, “Corrosion and Corrosion Control, An Intro-duction To Corrosion Science and Engineering,”2nd ed, John Wiley and Sons, 1963

• Reynolds Metal Company, “Structural AluminumDesign,” 1962

• Metal Handbook, Ninth Edition, Volume 2, “Prop-erties and Selection: Nonferrous Alloys and PureMetals,” American Society for Metals, copyright1979


1200-22 June 1989

Acetaldehyde Creosote Methyl Ethyl Kerone Propylene GlycolAcetic Acid Cresol Mono-chloro-difluoro

MechaneRice

Acetic Anhydride Crotonaldehyde Molasses Rubber and Rubber ProductsAcetone Cyclohexane Naphthalene RyeAcrolein Cyclopentane Naphthenic Acid SafflowerAcrylonitrile Cyclopropane Naval Stores Salicylic Acid

Adipic Acid Dairy Products Nitric Acid (Concentrate) ShelacAlcohols (except for dry and boiling)

Dichlorobenzene Nitrocellulose Soap

Aldol Ebonite Nitrogen Fertilizers Sodium BicarbonateAlumina and its hydrates Essential Oils Nitroglycerine Sodium CarbonateAluminum Chlorideria Ester Gum Nitrous Oxide Sodium ChlorideAluminum Potassium Sulfate Ethyl Acetate Nylon and Nylon Saits Sodium NitrateAluminum Silicate Ethyl Aceroacerate Oils, Edible Sodium SulfateAluminum Sulfate Ethyl Alcohol Oleic Acid Soybeans and Soybean

ProductsAmmonia Ethylene Glycol Oxalic Acid StarchAmmoniated AmmoniumNitrate Solutions

Fatty Acids Oxygen Sugars

Ammonium Nitrate Feeds Paints, Varnishes & Paint Materials

Sulfur

Ammonium Sulfate Ferrous Sulfate Parafins Sulfur DioxideAmonium Thiocyanate Flour Paraformaldehydes Tail OilAniline Formaidehyde Paraldehyde TarAnthracene Furfural Peanuts and Peanut

ProductsTobacco Stems

Baking Powder Gasoline Pentane TolueneBarium Carbonate Glucose Perchlaroethylene TrichlrobenzeneBenzene Glycerin Petroleum Products, Refined TrichlroethyleneBenzoic Acid Grains Phthalic Acid UreaBone Black Grits, Hominy Phthalic Anhydride Vegetable OilsBone Acid Helium Pitch Vinyl AcetateButyl Acetate Hexamine Polyethylene Vinyl ResinsCalcium Carbide Hydrocyanic Acid Polystyrene Water, High PurityCalcium Chromate Hydrogen Potassium Carbonate Wood ChipsCarbon Dioxide Hydrogen Peroxide Potassium Chloride XyleneCarbon Disulfide Isobutyric Acid Potassium Iodide Zinc SulfideCarconic Acid Lacquer and its solvents Potassium NitrateCaster Oil LInseed Oil Potassium SulfateCoal Malt PropaneCod Liver Oil Manganese Dioxide Propionic AcidCorn Syrup Maple Syrup Propionic Anhydride

Fig. 1200-8 Typical Bulk Chemicals Handled in Aluminum Equipment

TAM12008.WP


June 1994 1200-23

GLOSSARY

-A-AIR BRIGHTENING: Injection of small bubbles of air,usually in certain lube oil stocks, to oxygenate and stirthe stock. Also called AIR ROLLING.

AIR SPIDER: A layout of small air pipe with holes alongits sides on a tank bottom for the purpose of air bright-ening the stock.

ANCHOR WEIGHT: A weight installed in a tank to whichthe guide wires or cables for an automatic tank gagefloat are attached to hold them taut and plumb. Alsocalled AUTO GAGE FLOAT GUIDE WIRE ANCHOR.

ANNULAR RING, BOTTOM: Part of the bottom under theshell, this butt welded plate is sometimes thicker thanthe remainder of the bottom. It strengthens the struc-tural area of the bottom in order to prevent bottom-to-shell seam failure.

ANNULAR SPACE: Horizontal space between the rim ofa floating roof and the tank shell. This space must bewide enough for the roof to move up and down withouthanging up on the shell.

ANTI-CHANNEL BAFFLES: Baffles built into productiontanks to maximize the residence time of wet crude inthe tank in order to allow the water to separate out.

ANTI-ROTATIONAL RODS: Steel rods installed betweenrafters (circumferentially) on a cone roof for the pur-pose of preventing the roof from twisting. Also calledEARTHQUAKE RODS.

API: American Petroleum Institute.

API GRAVITY: A means used by the petroleum industryto express the density of petroleum liquids. API gravityis measured by a hydrometer instrument having a scalegraduated in degrees API. For the relation between APIgravity and specific gravity, see Appendix B, Conver-sion Tables.

AUTO GAGE: An automatic system used to measureand display the liquid level or ullage in one or moretanks. The entire system includes the auto gage heador marker and marker board, the tape, a pipe tapeguide system, a float, a float well (for a floating roof),

a float guide system (for a fixed roof) consisting ofwires on each side of the float along with a tank bot-tom attaching bar and spring tension anchors mountedon the fixed roof. The gage can measure either con-tinuously, periodically, or on demand. Also calledAUTOMATIC TANK GAGE.

AUTO GAGE TAPE: A stainless steel tape, usually withholes at 1- to 2-inch intervals instead of markings, run-ning from the auto gage head or marker through a pipetape guide and connected on the other end to the autogage float or sometimes to the top of a floating roof.Also called GAGE TAPE.

-B-BACKUP STRIP: A thin strip of metal placed on thebackside of two plates to be butt welded, where a fullpenetration butt weld is required and access is avail-able to one side only.

BANDING: The dimpling of the horizontal weld seambetween shell courses. It is identified and measured byplacing a flat board vertically against the shell over thehorizontal seam. Banding has the same appearance asa string tied tightly around the middle of a pillow.

BANDS: Stainless steel bands installed horizontallyaround a tank shell to hold insulation or weatherjacketin place.

BASIC SEDIMENT AND WATER (BS & W): See SEDIMENT

AND WATER.

BAYONET HEATER: See HEATER, MANWAY.

BAZOOKA: See SEAL SYSTEM CENTERING DEVICE.

BOTTOM GUIDE WIRE ANCHOR: A bar welded to the bot-tom of a tank to which guide wires or cables for thefloat of an automatic tank gage are attached.

BOTTOM SAMPLE: A spot sample taken from the mate-rial near the bottom surface of the tank or pipeline ata low point.

BREAKER, BREATHER-TYPE VACUUM: This floatingroof vacuum breaker consists of only the vacuumportion of the tank p/v valve. It will open to relievea vacuum under the roof when the tank is pumpedout but will not open on pressure, thus no chance of

Tank Manual Glossary

June 1989 Glossary-1

T O

C O N T E N T S

hydrocarbon emission to the atmosphere. This designdoes not require any increase in the low pump outlevel, thus does not increase amount of unavailablestock. A small bleeder valve on the breather nozzlepipe permits bleed-off of trapped air during initial fill-ing.

BREAKER, MECHANICAL VACUUM: A mechanical deviceused to break the vacuum under a floating roof whenthe tank continues to be pumped out after the roof legsland on the bottom. It prevents collapse of the roof. Itconsists of (1) an open pipe, usually 10-inch diameter,through the floating roof; and (2) a steel “hat” with apipe stem through it. The bottom end of the pipe stemcontacts the bottom before the roof lands on its legs,thus lifting the “hat” and breaking any vacuum. Break-ing the vacuum during operation is a violation of airquality rules, so the low pump out level on the tankhas to be raised to prevent rule violation. This resultsin more unavailable stock in the tank. This design isno longer recommended. Also called BREAKER, CB & I.

BREATHER VALVE: See VALVE, PRESSURE/VACUUM (P/V).

BULKHEADS: See FLOATING ROOF BULKHEADS.

BUMPER, BOTTOM: A support mounted on the tank bot-tom that supports the swing line in its lowest position.

BUMPER, ROOF: A bumper mounted on the cone roofrafters to stop the end of the non-floating swing lineat its maximum elevation and angle.

BUMPER, SHELL: A shell-mounted bumper that restrictsthe maximum elevation to which the swing can rise.

BUTT RIVETED: Two plates (normally thicker thanplates that are only lap riveted) end to end with buttstraps (narrow pieces of plate) installed on the insideand outside surfaces. ‘Unequal butt plates’ (the mostcommon design) means the inside plate is wider andthicker than the outside plate. Rivets on this design arein both single and double shear. Equal butt plates haveall rivets in double shear.

BUTT WELDED: Two plates are joined end to end by afull penetration weld.

-C-CABLE PULL: The amount of force in pounds necessaryto pull a floating swing line down against the excessflotation of the pontoons.

CALIBRATION (TANK): The relationship between liquidlevel and volume for tanks. The following terms per-tain to types of calibration.

BOTTOM CALIBRATION: (a) The determination of thetank volume below the dip point (strike plate) whichis zero on the tank gage table. (b) The quantity ofliquid contained in a tank below the dip point.

MEASUREMENT CALIBRATION METHOD: The methodof tank calibration in which volume capacities arecalculated from external and/or internal measure-ments of the tank dimensions. Strapping is an exam-ple of this type of method.

LIQUID CALIBRATION: The method of tank calibrationin which the capacities are determined volumes ofliquid.

OVER-CALIBRATION: A tank is said to be over-cali-brated when its nominal capacity is less than thatshown on its calibration table or by its capacity in-dicator.

UNDER-CALIBRATION: A tank is said to be under-cali-brated when its nominal capacity is greater than thatshown by its calibration table or capacity indicator.

CAPACITANCE PROBE, TANK LEVEL DETECTOR: An elec-trical detector of an automatic tank gage for sensingliquid level, which uses the electrical capacitance dif-ference between tank vapor or air and liquid to sensethe liquid surface.

CAPACITY: The volume of a container or tank filled toa specified level.

CAPACITY, GROSS: Nominal capacity, accurately stated.

CAPACITY, NOMINAL: Total tank volume to the top ofthe shell expressed in round numbers.

CAPACITY, OPERATING: Useable tank volume from lowpump out to safe oil height.

CATCH BASIN: A sump located at the shell that allowsa bottom attachment to protrude out for access.

CATHODIC PROTECTION: Use of electric current to in-hibit corrosion. Most common uses are to preventstockside pitting and underside corrosion on the bot-tom.

Glossary Tank Manual

Glossary-2 June 1989

CAULKING: Caulking a seam is the hammering orpeaning of metal around a leak to seal it.

CENTER CAP: A plate on the top of the center columnof a cone roof on which the rafters are supported. Alsocalled CROW’S NEST.

CHICKSAN JOINT: See ROOF DRAIN ARTICULATED JOINT.

CLINGAGE: The liquid film that adheres to the insidesurface of a container after it has been emptied.

CLOSING GAGE: The measurement in a tank after a de-livery or receipt.

COATING, LAMINATE: A system consisting of choppedfiber, fiber mesh or fiber cloth reinforced resin used asa protective coating and also as a membrane to spanthin areas of metal or pits in the metal. Most commonuses are on tank bottoms and fixed roofs. Also calledIPR, FIBERGLASS REINFORCED EPOXY, and REINFORCED

VINYL .

COATING, THICK FILM: An unreinforced submergedservice protective coating of more than 20 mils thick-ness. Most common system is an elastomeric urethane.Besides being used to a limited extent as a protectivecoating, elastomeric urethane is a common weathercoatsystem for insulation.

COATING, THIN FILM: An unreinforced submerged serv-ice protective coating of less than 20 mils thicknessused to protect the surface from corrosion.

COLUMNS: The vertical support for fixed roof tanks.Where tank radius can be spanned by a single rafter,only the center column is required. Where the radiusrequires two or more rows of rafters, two or more cir-cumferential rows of columns connected together cir-cumferentially by girders are required.

CONE DOWN BOTTOM: A tank bottom with the centerlower than the edge. Permits more complete water-drawing of a tank than the cone up design as the coneup results in water standing at the shell due to zerocircumferential slope. Usually has a sump in the centerwith siphon draw off internal piping.

CONE UP BOTTOM: A tank bottom with the centerhigher than the edge. Most common design installed.Usually has waterdraw or bottom outlet in the tank bot-tom near the shell at a catch basin.

COUNTERWEIGHT: A device which exerts force or ten-sion on the tape or cable of a gaging system to holdconnecting elements tight.

COUPON: A small piece of the steel plate removed formeasurement of its thickness. The opening is thenpatched.

COURSE, SHELL: One circumferential ring of plates ina tank. Courses are usually numbered from bottom totop. Course 1 is the bottom course.

CROSS BRACING: Bracing between roof support col-umns. No longer installed normally, it must be re-moved to permit installation of an internal floatingroof.

CROWS NEST: See CENTER CAP.

CURTAIN SEAL: See SEAL SYSTEM PRIMARY SEAL.

CUT: During tank gaging, the line of demarkation thatthe material (stock, water) makes on the measuringscale (gage tape).

-D-DATUM PLATE: A level metal plate attached to the tankshell or bottom, located directly under the dipping ref-erence point to provide a fixed contact surface fromwhich liquid depth measurement can be made. Alsocalled HOD PLATE.

DATUM POINT: The point on the gage well at the topof the tank from which all measurements for the cali-bration of the tank are related. Also called HOD POINT.

DEADWOOD: Any tank fitting, appurtenance or struc-tural member which affects tank capacity. Deadwoodis positive if it increases tank capacity or negative if itdecreases capacity.

DENSITY, RELATIVE: Ratio of the substance’s density attemperature, t1 to the density of pure water at tempera-ture, t1. Often called specific gravity.

DIESEL TESTING: See TESTING, PENETRANT.

DIFFERENTIAL SETTLEMENT: Settling of one part of atank shell more than another part. Also called UNEVEN

SETTLEMENT.

DIFFUSER: A device for slowing the velocity of stockentering a tank to reduce stock turbulence. It is a pipeextension of the shell fill nozzle having varying sizedholes along the sides and a blocked end. High levelsof particulate matter in the stock will erode the holes.The tank bottom must support the diffuser to avoid vi-bration-caused fatigue at the shell/nozzle joint.



DIP: The European term for the depth of liquid in astorage tank (see INNAGE, also OUTAGE [ULLAGE]).

DISSOLVED WATER: Water in solution in the oil at thedefined temperature and pressure.

DOUBLE REEVED: Refers to a cable system that goesfrom the cone roof mounted sheave to a sheave on theend of the non-floating swing line and then back to theroof, giving a 2:1 mechanical advantage.

DYE CHECKING: See TEST, PENETRANT.

DROP OUT SPOOL: A short section of pipe, flanged oneach end, for isolating piping from a tank. Usuallymounted on the shell nozzle or tank valve. The bestdesign has block valves on both ends of the drop outspool, which permits the spool to be removed, isolatingthe tank without opening the tank to the atmosphere ordepressurizing the pipeline.

-E-EARTHQUAKE RODS: See ANTI-ROTATIONAL RODS.

EMULSION: An oil/water mixture that does not readilyseparate.

ENTRAINED WATER: Water suspended in oil. Entrainedwater includes emulsions but does not include dis-solved water.

EXCESS FLOTATION: The amount of flotation furnishedby the swing line pontoons over the amount that giveszero buoyancy to the swing line system. The excessflotation must be enough to overcome the weight ofthe system and its friction while still enabling the op-erator to winch the swing down without excessive ef-fort.

-F-FIXED ROOF CENTER SUPPORT: A device or anchor ontop of the fixed roof at the center, from which stagingsupport cables can be suspended. Also called PAINTER’S

HOOK.

FLASH POINT: The lowest temperature at which liquidgives rise to a flammable gaseous mixture which willignite.

FLOAT, AUTOMATIC TANK GAGE: A liquid level detectingelement floating at the liquid surface in a tank whichmoves in a vertical direction to follow the change inliquid level.

FLOAT GUIDE WIRES, AUTOMATIC TANK GAGE: Solidwires or flexible cables used to guide the travel of anautomatic gage float.

FLOAT WELL: A round, vertical opening through theroof of a floating roof tank to contain and guide thetravel of the automatic gage float. It is equipped witha cover through which the auto gage tape cable passes(and in the case of the interface auto gage, the floatingguide wires also pass). Not completely vapor tight, thebottom is open with restricting bars or plate to keepthe float inside. (The interface float well is completelyopen and uses the guide wires to keep the float cen-tered.)

FLOATING COVER: See INTERNAL FLOATING ROOF.

FLOATING ROOF BULKHEADS: The radial vertical wallof a floating roof pontoon compartment. Seal weldingof the bottom and sides makes a liquid tight compart-ment. Seal welding all around makes a vapor tightcompartment, which is recommended.

FLOATING ROOF LOWER DECK: The lower deck of afloating double deck roof or the lower deck of a pon-toon ring. Usually in contact with stock. Lap weldedon the topside, limiting the overlap. Tack welding ofthe underside prevents fatigue failure of the seams. Incorrosive services such as process condensate (sourwater), seal welding of the laps on the underside orfull penetration butt welds of plate seams is recom-mended.

FLOATING ROOF RIM: The circumferential vertical wallof the floating roof, usually the outside face of theroof.

FLOATING ROOF TANK: A tank in which the roof floatsfreely on the surface of the liquid contents except atlow levels, when the weight of the roof is transmittedby its supporting legs to the tank bottom.

FLOATING ROOF UPPER DECK: The upper deck of afloating double deck roof or the upper deck of a pon-toon ring.

FLOTATION LEVEL: The depth of submergence of abuoyant automatic gage float in a liquid of known den-sity or weight.

FOAM SEAL: See SEAL SYSTEM TOROIDAL SEAL.

FRANGIBLE JOINT: On a cone roof tank the weld at-taching the roof deck plate to the shell top angle. It isdesigned to rupture, releasing internal pressure, beforethe bottom-to-shell seam ruptures, thus avoiding a cata-strophic tank failure.

FREEBOARD: The distance from the surface of theliquid to the top edge of the surface against whichit is being measured. This surface could be the top



edge of the floating roof rim, the bottom edge of thepinhole in the floating roof leg guide, the top edge ofthe emergency overflow drain pipe through the floatingroof, etc. It also can describe how much lower the roofcan sink before stock begins running onto the roof.

FREE WATER: The water present in a tank, which is notin suspension in the contained liquid (oil).

-G-GAGE HATCH: The opening in the top of a tank throughwhich dipping (gaging) and sampling operations arecarried out.

GAGE HEAD, AUTOMATIC TANK GAGE: The housing ofthe automatic tank gage which holds the indicator andtransmitter.

GAGE, INNAGE: The measurement from the tank bot-tom to the top of the liquid level in a tank.

GAGE, OUTAGE: The measurement from the top of theliquid level to the hold off distance point. Innage plusoutage gages will equal the hold off distance.

GAGE WELL: A vertical cylindrical slotted pipe (6- to12-inch diameter) built into a tank to contain the liquidlevel detecting element and located to reduce errorsarising from turbulence or agitation of the liquid. Italso acts as the counter-rotational device for floatingroofs. Also called STILL PIPE and STILLING WELL.

GAGING: A process of measuring the height of a liquidin a storage tank. This process can be manual (hand orreel gaging) or automatic (by automatic tank gagingequipment). Either method is usually done by loweringa weighted graduated steel tape through the tank roofand noting the level at which the oil surface cuts thetape when the weight gently touches the tank bottom.The corresponding European term is DIPPING.

GIRDER: On larger cone roof tanks where the span istoo great for one row of rafters, one or more rings ofgirders are used. Usually I-beams, they are installedcircumferentially with the ends of adjacent girders sup-ported by a column.

GUIDE POLE: A device (usually a cylindrical verticaltube) used in floating roof tanks to prevent rotation ofthe roof.

-H-HDPE - HIGH DENSITY POLYETHYLENE: Type of mem-brane primarily used in new bottoms or bottom re-placements for the purpose of detecting leaks.

HEATER COIL, BOTTOM: A serpentine piping systemrunning back and forth across a tank bottom usuallyabout 8 inches above it and supported from the tankbottom.

HOD: Hold off distance.

HOLD DOWN CHAIN: A safety chain near the end of theswing line that is attached to the tank bottom and re-stricts the maximum height of the swing.

HOLD DOWN SYSTEM: A device or system used to re-strict the amount a swing line can be elevated. Typicalhold down systems for both floating and non-floatingswings include a hold down chain (connected at thetank bottom and outer part of the swing line) and shellbumper. The roof bumper is used only on cone rooftanks. On floating roof tanks, the floating roof restrictsthe upward swing of the line unless the maximum an-gle with the tank overflowing would exceed 65 de-grees, in which case a hold down system would berequired. The normal design on swing lines in floatingroof tanks is to make the swing line long enough thatit cannot exceed 65 degrees maximum.

HOLD OFF DISTANCE: The accurate distance from a spe-cific point on a tank bottom to a known and identifiedpoint directly above. The HOD point will always beabove the roof and above the SOH. HOD is usuallymeasured through a gage well which prevents inaccu-racy due to horizontal movement of the tape. The HODis used to gage the tank by measuring the distancefrom the point above the roof to the liquid level (seeOUTAGE). By subtracting that distance from the HODdistance, the actual stock level can be determined. (SeeINNAGE.) Also called HOD.

HOLD OFF DISTANCE PLATE: A plate welded to the bot-tom and used as the specific lower point for measuringthe HOD. Usually located directly under the gage well,it can also be the reinforcing pad for the gage well bot-tom supports. Also called HOD PLATE and DATUM

PLATE.

HOLIDAYS: Pinholes or thin spots in coatings, which de-velop during application, or nicks and scrapes whichoccur later. Corrosion may start at these defects.



HOSE DRAIN: See ROOF DRAIN FLEXIBLE HOSE.

HOT TAPPING: Usually, a hot tap refers to the installa-tion of another connection to the tank by installing anozzle and valve and then cutting a hole in the tankwith special hot tapping equipment. Also called HOT

WORK.

HYDROTEST: See TEST, HYDROSTATIC.

-I-IMPRESSED CURRENT CATHODIC PROTECTION: An exter-nal cathodic protection system using an external powersource instead of the sacrificial anode.

INERT GAS: A gas that does not react with the sur-roundings.

INERTING: The process of pressurizing a tank’s vaporspace with an inert gas blanket (usually exhaust gas)to prevent formation of an explosive mixture.

INNAGE GAGE: The depth of liquid in a tank measuredfrom the datum plate or tank bottom to the surface ofthe liquid.

INSULATION, FOAM: Usually polyurethane foam insula-tion sprayed on a tank and then weathercoated. Notrecommended. Urethane foam can also be poured inblocks and installed in the same manner as fiberglassblocks.

INSULATION, IMPALED: Insulation system in whichblocks of insulation are impaled on heavy wirelikestuds welded to the shell or roof plate. The ends of thestuds are bent over, holding the insulation in place.Common usage on cone roofs, it is more expensive butmore secure than banding on tank shells.

INTERNAL FLOATING ROOF: A lightweight covering ofeither steel or aluminum material designed to float onthe surface of the liquid in a tank. Alternatively, acover may be supported by a float system so that it isjust above the free liquid surface. The device is usedto minimize evaporation of volatile products. Alsocalled FLOATING COVER.

-L-LADDER, ROLLING: A ladder hinged at the top and withwheels on the bottom that provides access to a floatingroof no matter how full or empty the tank is.

LAP RIVETED: Two plates joined together by lappingthe edge of one plate over the other and installing riv-ets through both plates. Rivets are all in single shear.

LAY BAR: A vertical aluminum bar mounted on a tankshell for the purpose of attaching bands holding insu-lation and weatherjackets.

LEG, HIGH (REMOVABLE): A floating roof leg that pro-vides enough clearance beneath the roof so that main-tenance work can be done. It is installed just beforethe last pumpdown of the tank.

LEG, LOW (FIXED): A leg that allows the floating roofto go to its lowest allowable position, i.e., normal op-erating position.

LEG, TWO-POSITION: A floating roof leg that is used forboth high and low positions. It has two holes for thesupport pin, one at the top (high leg position) and onein the middle (low leg position). Slightly less costlythan the fixed low and removable high leg design, itis not recommended because of the tendency for cor-rosion-caused freezeup in a position.

LEVEL SWITCH: A device which consists of a level sen-sor and a contact closure. Upon detection of liquid, itwill generate a change of status in the contact closure.

LIGHTNING SHUNTS: In floating roof tanks, a piece ofmetal installed above the roof seal to ground the float-ing roof to the shell to prevent sparking over the sealarea. Cone roof tanks do not require lightning shunts.

LOW PUMP OUT: The minimum level to which the tankshould be pumped. On fixed roof tanks the level is setto avoid cavitation or loss of suction when pumpingout the tank. It also may be set to assure internal heat-ers are adequately covered with stock. On floating andinternal floating roof tanks, it is set to prevent the rooffrom landing on its legs during operation. Also calledMINIMUM OPERATING LEVEL and LPO.

LOW SAMPLE: A spot sample taken at five-sixths thedepth of liquid below the top surface. Also calledLOWER SAMPLE.

LPO: See LOW PUMP OUT.



-M-MANWAY HEATER: A tank heater inserted through ashell manway and resting on a support frame. It resem-bles the bundle portion of a heat exchanger. Modernmanway heaters have finned tubes to increase surfacearea. Also called BAYONET HEATER.

MEMBRANE: Synthetic sheet in tank bottoms used assecondary containment. See HDPE.

MERCHANTABLE OIL: Liquid hydrocarbons which arejudged to be acceptable for custody transfer to a car-rier. The oil is settled and contains not more than a setamount of suspended sediment and water (S&W) andother impurities.

MINIMUM OPERATING LEVEL: See LOW PUMP OUT.

-N-NEG’ATOR MOTOR: The Neg’ator is a strip of flatspring stainless given a curvature so that in its relaxed,unstressed condition it remains a tightly wound spiral.Used in a gage head. Its motor eliminates counter-weight and cable assembly.

NET GALLONS AT 60°F: The measured gallons convertedto equivalent volume at 60°F.

NONPRESSURE TANK: A tank of conventional shape in-tended primarily for the storage of liquids at or nearatmospheric pressure. Also called ATMOSPHERIC PRES-

SURE TANK.

-O-OPENING GAGE: The measurement of liquid (stock,water) in a tank before a delivery or receipt.

OPERATION CHECKER, AUTOMATIC TANK GAGE: A de-vice used to check for free movement of the gagemechanism.

OPTICAL REFERENCE LINE METHOD: An optical tankcalibration method. It requires manual strapping of thebottom shell course but uses optical instruments tomeasure the other shell courses to determine tank di-ameter.

OPTICAL TRIANGULATION METHOD: An optical tankcalibration method. It uses one or two theodolite sta-tions to determine the diameter of the tank at groundlevel, either from outside or inside the tank.

OUTAGE (ULLAGE): The volume of available space ina tank unoccupied by contents. Hence ullaging, amethod of gaging the contents of a tank by measuring

the height of the liquid surface from the top of thetank.

OUTAGE GAGE: The distance from the liquid level tothe HOD or datum point.

OUT OF PLUMB: Refers to the misalignment of shellplates from the vertical axis (i.e., leaning in or out).

OUT OF ROUND: Indicates the shell radius is not con-stant around the circumference at the same elevation.Out-of-roundness can be detected in a floating rooftank by variation of annular space.

OUTSIDE WASH: Cleaning of the tank interior by hoseor high pressure nozzles from outside the tank (no per-sonnel entry) with sediment, oil and wash water drain-ing out the waterdraw.

-P-PAINTER’S HOOK: See FIXED ROOF CENTER SUPPORT.

PANOGRAPH DRAIN: See ROOF DRAIN ARTICULATED

JOINT.

PEAKING: The distortion of shell plate or seams inwardor outward. Peaking occurs on longitudinal seams as aresult of improperly formed plate or distortion fromwelding. A sweep cut to match the tank radius is usedto check degree of peaking; the sweep is used outsideof the tank for inward peaking and inside the tank foroutward peaking.

PINHOLE (HOLE IN COATINGS OR PLATE): A very smalldiameter hole in plate or coating.

PINHOLE (IN FLOATING ROOF LEGS): The hole throughthe upper end of the fixed roof leg or two-position roofleg guide, and the hole through the upper end of theremovable roof leg (or in the case of the two-positionroof leg, through the upper end and through approxi-mately the middle of the leg) through which a heavypin or bolt is inserted to hold the removable or two-position leg at the desired position (high leg positionor in the case of the two-position leg, high or low po-sition).

PONTOON BALLAST: Weight added to the swing linepontoons to achieve a set amount of cable pull, usually300 lbs. for swing lines to 16 inches and 500 lbs. forswing lines over 16 inches. Common ballasts are kero-sene and soluble oil in water.

PONTOONS: Normally two closed cylinders on the endof the swing pipe to provide buoyancy for the swingline.



POSITIONING WIRE OR CABLE: In a gaging system, thesolid or stranded wire or cable which connects the floatto the tape or which drives the dial indicator or trans-mitter.

POWERED MIXER: A tank mixer that requires an exter-nal source of power to operate.

PRESSURE: The following terms pertain to differentcategories of pressure.

PRESSURE, ATMOSPHERIC: The atmospheric pressureor pressure of one atmosphere. The normal atmos-phere (atm) is 101.325 Pa; the technical atmosphere(at) is 98,066.5 Pa.

PRESSURE HIGH VAPOR: A liquid which, at the meas-urement or proving temperature of the meter, has avapor pressure that is equal to or higher than atmos-pheric pressure (see LOW VAPOR PRESSURE LIQUID).

PRESSURE, LOW VAPOR: A liquid which, at the meas-urement or proving temperature of the meter, has avapor pressure less than atmospheric pressure (seeHIGH VAPOR PRESSURE LIQUID).

PRESSURE, REID VAPOR: The vapor pressure of a liq-uid at 100°F (37.78°C, 311°K) as determined byASTM D 323-58, Standard Method of Test for VaporPressure of Petroleum products (Reid Method).

PRESSURE, VAPOR (TRUE): The term applied to thetrue pressure of a substance to distinguish it frompartial pressure, gage pressure, etc. The pressuremeasured relative to zero pressure (vacuum).

PRESSURE-TYPE TANK: A tank specially constructed forthe storage of volatile liquids under pressure. Suchtanks are spheroidal, spherical, hemispherically-ended,or of other special shapes.

PRESSURE/VACUUM VALVE: See VALVE, PRESSURE/VAC-

UUM.

PRIMARY SEAL: See SEAL SYSTEM PRIMARY SEAL.

-R-RAFTER: The radial portion of a roof structure onwhich the roof deck plate is supported. Normally oncone roof structures, it is sometimes encountered inlarger (and obsolete) clear deck or high deck floatingroofs. Usually channels; on small tanks sometimes an-gles or pipe are used.

REFERENCE POINT: A fixed point above the tank towhich all subsequent level measurements are related.Also called DATUM POINT or HOLD OFF DISTANCE POINT.

REID VAPOR PRESSURE: See PRESSURE.

REPRESENTATIVE SAMPLE: A small portion extractedfrom the total volume of material, which contains thesame proportions of the various flowing constituents asthe total volume of liquid being transferred.

RINGWALL: The part of the foundation that supportsthe tank shell and prevents excessive settlement. Usu-ally concrete or crushed stone.

ROOF DRAIN, CLOSED: A drain system used on floatingroof tanks to drain off rain water from the top of theroof through a pipe system to the outside of the tankshell. The term ‘closed’ means the rain water will notcontaminate or contact the stock in the tank. The sys-tem includes one or more drain basins in the floatingroof, a flexible piping system that allows the roof totravel from its lowest to highest position, a fixed sec-tion of pipe on the bottom, a shell nozzle and valve,plus sometimes an outside drain pipe from the shellnozzle to the waterdraw basin.

ROOF DRAIN, OPEN: A drain system used on floatingroof tanks to drain off rain water from the top of theroof directly into the tank safely without flooding theroof deck with stock. It can be used where stock con-tamination with rainwater is acceptable.

ROOF DRAIN ARTICULATED JOINT: A closed roof drainsystem in which the flexible portion consists of articu-lated (rotating) joints with rigid pipe between joints.Articulated joints manufactured by Chicksan and modi-fied to include an external liquid seal are the mostcommon in existence. Articulated joint drain systemsare no longer recommended as they tend to put a hori-zontal thrust on the floating roof, causing problemswith seal closure. Also called PANOGRAPH DRAIN, andCHICKSAN JOINT.

ROOF DRAIN FLEXIBLE HOSE: A closed roof drain sys-tem in which the flexible portion consists of a rein-forced synthetic flexible hose with metallic flangedjoints on each end. The system is not recommendeddue to it is short life expectancy and susceptibility todeterioration by changes in service. Also called HOSE

DRAIN.



ROOF DRAIN FLEXIBLE PIPE: A closed roof drain systemin which the flexible portion consists of a section ofstainless steel flexible pipe, coated with a synthetic ma-terial on the outside (Mesa brand) or inside (Coflexipbrand), with pipe flanges on each end. This is the cur-rent recommended system.

-S-SACRIFICIAL ANODES: Usually aluminum blocks (al-though other metals such as zinc or magnesium maybe used) installed on the tank bottom to protect a sur-face against corrosion. The sacrificial anode corrodespreferentially to the steel bottom.

SAFE OIL HEIGHT: The maximum level the tank is sup-posed to be filled to. Initially set by design, it may bereduced by shell strength calculations, frothing, cascad-ing, etc. Also called SAFE OIL OPERATING HEIGHT andSOH.

SAMPLING: The process of obtaining a representativepart of a given tank volume for testing.

SEAL SYSTEM CENTERING DEVICE: A device limitingthe horizontal closing of the annular space. Springloaded models place an increasing horizontal thrustagainst the shell as the annular space is reduced. Usu-ally mounted below the roof. Mounting above the roofhas been done but is not recommended (overfilling thetank slightly can result in the centering device hangingup on top of the shell). Also called BAZOOKA.

SEAL SYSTEM EXPANSION JOINTS: Joints between indi-vidual shoes or sections of primary shoes in a shoe sealassembly that can expand and contract. Can be fabricor plate sliding on plate. One company uses accordion-type folds in the shoe for expansion joints.

SEAL SYSTEM PRIMARY SEAL: The seal fabric closingthe gap between the roof rim and shoes. Fabric mustbe resistant to vapors as it does not normally come incontact with the liquid in the tank. Also called CURTAIN

SEAL and MAIN SEAL.

SEAL SYSTEM PRESSURE PLATE: A spring steel plateused in secondary seal systems and certain primary sealdesigns to close the gap between the roof and shell. Italso applies pressure against the shell to keep the roofcentered. Usually of galvanized or stainless steel.

SEAL SYSTEM SHOES: Pieces of thin (10 gage forcarbon steel, 16 to 20 gage for galvanized and stain-less steel) metal held in face-to-face contact with the

shell by the hanger system. Flexibility of thin sheetspermits the shoe to follow the curvature of the shell.

SEAL SYSTEM SHOE SEAL: Complete primary seal sys-tem comprised of metallic shoes, hanger system, ex-pansion joints and primary or curtain seal fabric.

SEAL SYSTEM SHOE HANGERS: The mechanical systemused to support the seal assembly shoes and to placehorizontal thrust on the shoes to keep them flushagainst the tank shell. Usually lever arms or a combi-nation of springs and lever arm.

SEAL SYSTEM TOROIDAL SEAL: A primary seal systemcomprised of a urethane foam log enclosed in stock-resistant seal fabric with a metallic attachment andhold-down system to keep the seal from rolling out ofthe annular space as the roof descends. Also calledTUBE SEAL and FOAM SEAL.

SEAL UNIT, AUTOMATIC TANK GAGE: An assembly usedto seal the gage assembly from tank vapors.

SEAM SEALANT: A putty-like thick film protective coat-ing with good adhesive qualities. Used to plug smallriveted seam leaks on tank shells.

SECONDARY SEAL, RIM MOUNTED: A secondary sealsystem attached to the top edge of the floating roofrim. Seals entire gap from rim to shell.

SECONDARY SEAL, SHOE MOUNTED: A secondary sealmounted on the top edge of the primary seal shoe (notqualified as a secondary seal in many jurisdictions).Only seals gap from shoe to shell.

SEDIMENT: Solid materials such as sand, rust, andscale.

SEDIMENT AND WATER (S&W): A material coexistingwith, yet foreign to petroleum liquid, that requires aseparate measurement for sales accounting. This for-eign material includes emulsified or suspended waterand sediment (SW&S) (see FREE WATER). The quantityof S&W is normally determined by centrifuge testingof a sample of crude oil which is to be transferred.Also called BASIC SEDIMENT AND WATER (BS&W).

SETTLING TANK: A tank or system of piping whereinthe velocity of the liquid stream is sufficiently reducedto enable foreign particles or water to settle from theoil.

SHEAVES: Support wheels over which the tape, wire orcable rides.



SHELL COURSE: See COURSE, SHELL.

SHELL-TO-ROOF ANNULAR SPACE: The space betweenthe surfaces of the shell and roof rim in which the pri-mary and secondary seal systems are used to seal, re-ducing vapor emissions.

SHOE SEAL: See SEAL SYSTEM SHOE SEAL.

SINGLE REEVED: Refers to a cable system that goesfrom the cone-roof-mounted sheave to the end of thenon-floating swing line where it is attached, giving a1:1 mechanical ratio. Used only on small swing lines.

SINGLE SLOPE BOTTOM: A tank bottom where the entirebottom slopes in a single direction with a bottom drawoff or water draw at the low point.

SLUDGE: A highly viscous mixture of oil, water, sedi-ment, and residue.

SMALL TANK: A crude oil storage tank with a 1000barrel or less capacity.

SOH: See SAFE OIL HEIGHT.

SPECIFIC GRAVITY: See DENSITY, RELATIVE.

SP GR: Specific Gravity

SPHERE, SPHEROID TANK: A round or semi-round ball-like stationary liquid storage tank, supported on col-umns so that the entire tank shell is above grade.

SPIDER STAGING: A small portable staging suspendedfrom a single cable. An air-driven hoist raises and low-ers the staging on the shell. When equipped with theproper roller, it can be moved horizontally around theshell.

SPRING GUIDES: Curved flat plate springs, usually 2 to4 inches wide, mounted on internal floating roof rimsto keep the roof centered where the roof is notequipped with a seal system.

STATIC MIXER: Has no moving parts. The kinetic en-ergy of the moving fluid provides the power for mix-ing.

STAYTITE JOINT: See SWING JOINT, CENTRAL.

STORAGE TANK: A large container used for liquid(fluid) storage.

STRAPPING: The measurement of the external diameterof a vertical or horizontal cylindrical tank by stretchinga steel tape around each course of the tank’s plates andrecording the measurement.

SUN PRESSURE RELIEF: The SPR system protects linesto the tank from excessive pressure due to solar ther-mal expansion. It consists of a small line circumvent-ing the tank valves with a relief valve usually set at150 psig. Block valves at the pipeline and shell nozzlebosses permit isolation and maintenance of the reliefvalve. Also called SPR.

SWING JOINT, CENTRAL: The flexible joint portion of aswing line that rotates in a vertical plane only. Attachedto the shell nozzle on the stockside. Staytite is thebrand name of over 99% of the central swing joints inexistence. The swing line is in the same horizontal andvertical axis as the shell nozzle. Also called STAYTITE

JOINT.

SWING JOINT, OFFSET: This swing line is in the samehorizontal axis as the shell nozzle but offset to the sidein a different vertical axis. Two major manufacturersof designed offset joints are Chicksan and Staytite. Notrecommended due to twisting forces on the shell noz-zle.

SWING LINE: A pipe extension from a shell nozzle withan articulated joint which permits it to be raised orlowered in a vertical plane only. Used to permit fillingor taking suction at a level other than at the shell noz-zle height. Usually the pipe has an opening or elbowat the end directed either upward or downward, (ell upor ell down swing). Swing lines are further divided intotwo categories, non-floating and floating swings. Alsocalled SWING PIPE.

SWING LINE, FLOATING: A swing line equipped withone or more pontoons (usually a pair). Normally freeto float to the top of the liquid unless restrained by astop, hold down chain or cable system. Often equippedwith a cable system with winch to pull the swing linedown against its flotation to a lower level.

SWING LINE, NON-FLOATING: A swing line without pon-toons. It is raised and lowered by means of a cablesystem and winch. Can only be used in fixed or coneroof tanks.

SWING PIPE: See SWING LINE.

-T-TANK CAPACITY: The amount a tank can hold when itis full to the safe oil operating height, to the nearestbarrel, gallon or pound.

TANK CAPACITY TABLE: A table showing the accu-mulated volume per measurement increment fora particular tank. The volume shown on the tablemay be in gallons, barrels, liters or cubic meters. The



table may be prepared for use with innage gages oroutage gages. Refer to API Manual of PetroleumStandards, Chapter 2, Tank Calibration. Also calledSTRAPPING CHART, TANK TABLE and CALIBRATION TA-

BLE.

TANK CAPACITY, NOMINAL: The total amount of tankcapacity when the tank is filled to the design maximumsafe oil height (or full filling height) measured in bar-rels (gallons) and rounded off.

TANK CAPACITY, OPERATING: The total amount of stockin a tank available for operation. This is the totalamount from the low pump out level to the safe oilheight and is measured to the nearest barrel, gallon orpound.

TANK CAPACITY, UNAVAILABLE: The total amount ofstock that must be placed in the tank to fill it to thelow pump out level. This stock is not available for nor-mal tank operation and should be considered an invest-ment not recovered until the tank is abandoned ordismantled.

TANK TABLE: See TANK CAPACITY TABLE.

TAPE, AUTOMATIC TANK GAGE: A metal tape used toconnect the liquid level detecting element and thegage-head mechanism.

TEST, ADHESION: A test method to see if a coating sys-tem is bonding to the steel surface. This is a destructivetest which means the surface coating will have to berepaired. When the coating is applied, a 1-inch diame-ter piston is bonded against the exterior surface of thecoating. After cure, the amount of pull on the pistonbefore the coating no longer adheres to the tank deter-mines the coating’s adhesiveness. Also called PULL

TEST.

TEST, AIR: Applying a very low (usually 7 psig or less)air pressure to a confined space (under a tank bottomor to swing line pontoons) to detect leaks. On tank bot-tom tests, the area under the bottom is pressurized andthen the soapy water is spread on weld seams. Leaksare detected by formation of soap bubbles. On swingline pontoons, soapy water is applied to the welds inthe pontoons.

TEST, HAMMER: An inspection technique using a lighthammer to find and identify thinning of steel plate. Re-quiring training and experience, it detects thinning bysound and feel (thin areas feel softer).

TEST, HOLIDAY: A method for detecting voids in coat-ings. A wet sponge holiday detector is used for coat-

ings up to about 25 mils; voltage is usually only 671/2 volts; when the wet sponge contacts a void, anelectric circuit is completed which rings a bell. Sparktesters are used for thicker coatings; usually 15,000volts minimum, voltage setting is increased with coat-ing thickness. The probe is usually a fine bristle steelbrush. When a void is present near the brush, a visibleand audible arc will be present; a spark detector canburn through thin areas of the coating. Also calledSPARK TEST (HIGH VOLTAGE), and WET SPONGE TEST

(LOW VOLTAGE).

TEST, HYDROSTATIC: Filling a closed area with liquid,usually water, and detecting leaks by visual examina-tion. Most common use on tanks is by filling the tankto the safe oil height with water prior to returning atank to service. Hydrotests locate and/or identify leaks,and in the case of rupture, the release of water is muchless hazardous than stock. Also called HYDROTEST.

TESTING, PENETRANT: An identifiable liquid is used todetect holes, cracks and leaks in a welded steel seam.Normally penetrants are diesel fuel or commercial reddye. The liquid is applied freely to one side of the weldand then the other side is inspected visually for the liq-uid. To detect cracks that don’t go clear through theweld, or when the other side is not accessible, an un-developed dye is applied to a weld seam and then thesurface is wiped clean. A white developer is thensprayed on the surface. Any dye trapped in cracks thenbleeds into the developer and reveals the defect. Alsocalled DYE CHECKING and DIESEL TESTING.

TEST, VACUUM: Usually used on bottom or roof platefillet welds, a vacuum is pulled on an inspection box(it has a glass window on top). The box is placed overa weld seam that has been wetted down with soapywater. Bubbles form on the weld inside the box indi-cating a leak. Can also be used to test HDPE mem-brane weld seams.

TEST, WIPE: A test for the cure (hardening) of a re-cently applied coating to determine if the entire coat iscured or if only the surface has cured. Usually doneby a twisting action of a thumb on the coating surface.

THERMOWELL: A metal protective socket installed inthe shell of a storage tank into which the sensing ele-ment (e.g., temperature bulb) of a temperature measur-ing device is inserted.



THIEF: An industry term for a bottom closure, core-type sampler used to secure samples from storagetanks.

TOLERANCE: The amount of measurement error thatwill be allowed. It is a plus or minus value.

TOP SAMPLE: A spot sample taken from a tank ob-tained 15 cm (6 in.) below the top surface of the liquid.

TRANSMITTER: The sending element of a remote datatransmission system.

TRUE VAPOR PRESSURE: See PRESSURE.

TUBE SEAL: See SEAL SYSTEM TOROIDAL SEAL.

-U-ULLAGE GAGE: The distance from the surface of theliquid in a tank up to the reference point of the tank.Also called OUTAGE and OUTAGE GAGE.

ULLAGE PASTE: A paste which is applied to an ullage-rule or dip-tape and weight to indicate precisely thelevel at which the liquid meniscus cuts the graduatedportion. Also called HYDROCARBON PASTE and WATER

PASTE.

ULLAGE REFERENCE POINT: A point marked on the ul-lage-hatch, or on an attachment suitably located aboveor below the ullage-hatch, and situated at a distanceabove the bottom of a container greater than the maxi-mum liquid depth in the container. Measurements ofullage are taken from this reference point. Also calledHOD POINT.

ULLAGE-RULE: A graduated rule attached to a dip-tapeto facilitate the measurement of ullage. Also calledREEL GAGE.

ULTRASONIC GAGE: See UT GAGE.

UNEVEN SETTLEMENT: See DIFFERENTIAL SETTLEMENT.

UT GAGE: An electronic device that projects high fre-quency sound through a material, usually steel plate fortanks. The time the sound takes to travel through themedium and return is measured to establish plate thick-ness. Also called ULTRASONIC GAGE.

UT GAGING SHEAR WAVE: High frequency sound isprojected at an angle, usually 30 to 45 degrees intothe plate. The sound bounces back and forth throughthe plate from the near and far surfaces until it

strikes a discontinuity such as a crack, then returns.Shear wave locates the discontinuity by measuring itsdistance from the starting point. This distance is shownon a calibrated cathode tube. If accessible side issmooth, shear wave can be used to indicate pitting onthe opposite side of a plate. Operation requires moretraining, experience, and sophisticated equipment thanultrasonic measurement.

-V-VACUUM BREAKER: A device used to prevent vacuumfrom occurring in a floating roof tank.

VALVE, PRESSURE/VACUUM (P/V): A valve in the roof ofa fixed roof tank to relieve vacuum or pressure. It isusually set to open at 1/2 oz. pressure/vacuum. Thevalve saves stock loss by staying closed when no pres-sure/vacuum exists. Also called BREATHER VALVE.

VAPOR-TIGHT TANK: A tank of conventional shape in-tended primarily for the storage of volatile liquids suchas gasoline, and so constructed that it will withstandpressures differing only slightly from atmospheric.Such tanks are equipped with special devices whichpermit gaging without opening the tank to the atmos-phere.

VENTURI EDUCTOR: A light metal eductor (air movingdevice) built on the venturi principle used to initiallymake a tank gas-free. Normally installed on a tankshell nozzle, preferably the swing line nozzle. Poweredby steam or air, it exhausts gases from the tank.

VORTEX: The swirling motion of liquid often encoun-tered as it enters the outlet opening of a container(tank). The vortex (swirl) causes entrainment of con-siderable quantities of air or vapor with the liquid.

VORTEX ELIMINATOR: A device located at the outlet ofa tank designed to prevent swirling of the outgoing liq-uid and the resultant entrainment of air or vapor. Alsocalled SWIRL PLATE.

-W-WATER AND SEDIMENT SAMPLE: A sample obtainedfrom the bottom of the tank to determine the amountof nonmerchantable material present.

WATER BOTTOM: Water accumulated at (or sometimesadded to) the bottom of the oil in a storage tank.



WATER CUT: The operation of locating the oil/water in-terface and using that location to measure the volumesof oil and water in a shore tank or ship compartment.Also called WATER GAGE.

WATER DIP: The depth of free water in a container overand above the dip plate.

WATER DRAW: A connection to the low point of thetank bottom for removing water from the tank.

WATER DRAW BASIN: A concrete or brick basin withfloor extending outward from the tank and slightly un-der the tank. A drain line usually runs from the basinto segregated drainage or to an impound area. The steelwater draw outlet is in this basin. Floating roof drainlines are sometimes piped to this basin along with sur-face drainage under the tank manifold.

WATER-FINDING PASTE: A paste containing a chemicalwhich changes color in contact with water. The paste,when applied to a water-finding rule, indicates thelevel of free water in a container.

WATER GAGE: See WATER CUT.

WATER WASHING: Involves the use of a high-pressurewater stream to dislodge clingage and sediment fromthe bulkheads, bottoms, and internal structures of avessel’s cargo tanks.

WATER STOP: When rewelding a riveted seam that hasbeen cut (as for door sheets), a low-temperature weldto tie two plates together before full penetration weld-ing. The water stop keeps the rivets from stretchingwhen the plates thermally expand, which prevents thetank from leaking once it is refilled.

WEATHERCOAT: A coating system applied to the sur-face of shell or roof insulation to protect it from theweather and keep out water.

WEATHER JACKET: A rigid material, usually aluminumsheet or transite, used to cover and protect insulationon the shell or roof of a tank.

WEIGH TANK: A tank used with a weigh scale whichis used for measurement of the liquid contents of thetank.

WELD, DOUBLE LAP: Same as lap welded, except theplates are fillet welded on both sides. Used on (rare)lap welded tank shells and on floating roofs with se-vere corrosion problems.

WELD, DOUBLE PENETRATION: Two plates butt weldedtogether from one side, then welded from the oppositeside.

WELD, EXTRUSION: Fusion of two sheets of material;usually refers to welding of the high density polyeth-ylene membrane in secondary containment systems.

WELD, LAP: Two plates are lapped over each other attheir juncture and are welded together with a filletweld.

WIND GIRDER: A horizontal stiffening ring around thetop of the tank to provide resistance to ovaling of thetank due to wind pressures.

WIND GIRDER, INTERMEDIATE: A horizontal stiffeningring placed around the middle of a tank shell subjectto buckling due to wind pressure.

WIND SKIRT: A vertical extension of the shell to keepthe floating roof seal assembly from popping out andhanging up on top of the shell. Usually has openingsalong the bottom edge to prevent filling the tank abovethe top of the shell. Opening would have to have vaporseals maintained in order to meet AQMD rules.



Tank Manual Appendix A

June 1989 Page 1 of 4

Appendix ATank Appurtenance Vendors

This appendix helps you find vendors for tank appurtenances and other materials. The vendor numberson this page direct you to recommended suppliers listed on the next two pages.

APPURTENANCE OR MATERIAL VENDORS

Articulated Joints 19, 20

Autogage Equipment 7, 15

Breathers & Breather-type Vacuum Breakers 5, 7, 15

Flexible Pipe Roof Drains 9, 22

Hatch Covers 5, 7, 15

Heaters 14

Insulation Band Spring Assemblies 11

Mixers, Tank Hydraulic 2

Mixers, Tank Mechanical 6, 8

Polypropelene Concrete Reinforcement Fiber (Fibermesh) 18

Roofs, Aluminum Dome 13, 23

Roofs, Internal Aluminum Floating 10, 23

Seal System Fabric 1, 9, 12

Secondary Seals, Rim Mounted 16

Shoe Seals, Inservice Replaceable 16

Sumps, Prefabricated with HDPE Liners 4

Winches 7, 19

T O

C O N T E N T S

Appendix A Tank Manual

Page 2 of 4 June 1989

VENDORNUMBER BRAND NAME VENDOR NAME AND ADDRESS PHONE

1 BW&B BUFFALO WEAVING & BELTING (716) 875-7223CO. 260 Chandler St.Buffalo, NY 14207

2 BUTTERWORTH BUTTERWORTH (916) 622-1041

P.O. Box 963Diamond Springs, CA 95619

3 COLT COLT SERVICES, INC. (213) 436-6156P.O. Box 1408Long Beach, CA 90801

4 CON-TEC CON-TEC LINING INC. (805) 366-0202P.O. Box 5635Bakersfield, CA 93388

5 GROTH GROTH EQUIPMENT CORP. (713) 675-3230P.O. Box 15293Houston, TX 77220-5293

6 LIGHTNIN MIXING EQUIPMENT CO.,INC. (716) 436-5550135 Mt. Read Blvd.Rochester, NY 14603

7 SHANDS & JURS GPE CONTROLS (213) 595-45413633 N. Long Beach Blvd.Long Beach, CA 90807

8 JENSEN JENSEN INTERNATIONAL, INC. (918) 627-5770P.O. Box 470368Tulsa, OK 74147

9 MESA MESA RUBBER COMPANY (818) 359-93611726 S. Magnolia Ave.Monrovia, VA 91016

10 PETREX PETREX, INC. (814) 723-2050P.O. Box 907Warren, PA 16365

11 PLANT PLANT INSULATION CO. (415) 654-7363INSULATION P.O. Box 8646

Emeryville, CA 94662

Tank Manual Appendix A

June 1989 Page 3 of 4


12 REEVES REEVES BROTHERS, INC. (803) 570-9210P.O. Box 431Rutherfordton, NC 28139

13 TEMCOR TEMCOR (213) 320-0554P.O. Box 3039Torrance, CA 90510

14 THERMAL FIN THERMAL FINNED TUBE (213) 685-7546TUBE PROCESSORS, INC.

1850 E. 61st St.Los Angeles, CA 90001

15 VAREC VAREC (714) 527-895110800 Valley View St.Cypress, CA 90630

16 W-G (RFI) W-G SEALS, INC. (713) 292-301254 S. Woodstock CircleThe Woodlands, TX 77380

17 FIN-TUBE SNYDER ENGINEERING COMPANY (213) 331-30411227 E. ThackeryW. Covina, CA 91970

18 FIBERMESH FIBERMESH INC. (619) 259-090111760 Sorrento Valley Rd.Suite HSan Diego, CA 91125

19 STAYTITE J.M. HUBER CORP. (800) 858-4158P.O. Box 2871Borger, TX 79007

20 BRUNDAGE BEN W. BRUNDAGE CO. (415) 658-5137(CHICKSAN) 4390 Piedmont Ave.

Oakland, CA 94611

21 SERROT SERROT CORPORATION (714) 848-0227P.O. Box 470Huntington Beach, CA 92648-0470

Appendix A Tank Manual

Page 4 of 4 June 1989


22 COFLEXIP COFLEXIP & SERVICES, INC. (713) 627-8540422 SW Freeway, Suite 600Houston, TX 77027

23 ULTRAFLOTE ULTRA FLOTE CORPORTATION (713) 461-2100 8558 Katy Freeway Suite 100 Houston, TX 77024

APPENDIX B. Conversion Tables

Tank Manual Appendix B—Conversion Tables

June 1989 B-1

T O

C O N T E N T S

Multiply By To Obtain

Acres 43,560 Square feetAcres 4047 Square metersAcres 1.562 x 103 Square milesAcres 4840 Square yardsAcre-feet 43,560 Cubic feetAcre-feet 325,851 GallonsAcre-feet 1233.48 Cubic metersAtmospheres 76.0 Cms of mercuryAtmospheres 29.92 Inches of mercuryAtmospheres 33.90 Feet of waterAtmospheres 10.332 Kgs/sq meterAtmospheres 14.70 Lbs/sq inchAtmospheres 1.058 Tons/sq ftBarrels-oil 42 Gallons-oilBarrels-Beer 31 Gallons-BeerBarrels-Whiskey 45 Gallons-WhiskeyBarrels/Day-oil 0.02917 Gallons/Min-oilBags or sacks-cement 94 Pounds-cementBoard feet 144 sq in. Cubic inches

x 1 in.British Thermal Units 0.2520 Kilogram-caloriesBritish Thermal Units 777.6 Foot-lbsBritish Thermal Units 3.927 x 104 Horsepower-hrsBritish Thermal Units 107.5 Kilogram-metersBritish Thermal Units 2.928 x 104 Kilowatt-hrsB.T.U./min 12.96 Foot-lbs/secB.T.U./min 0.02356 HorsepowerB.T.U./min 0.01757 KilowattsB.T.U./min 17.57 WattsCentares (Centiares) 1 Square metersCentigrams 0.01 GramsCentiliters 0.01 LitersCentimeters 0.3937 InchesCentimeters 0.01 MetersCentimeters 10 MillimetersCentimeters of Mercury 0.01316 AtmospheresCentimeters of Mercury 0.4461 Feet of waterCentimeters of Mercury 136.0 Kgs/sq meterCentimeters of Mercury 27.85 Lbs/sq ftCentimeters of Mercury 0.1934 Lbs/sq inchCentimeters/sec 1.969 Feet/minCentimeters/sec 0.03281 Feet/secCentimeters/sec 0.036 Kilometers/hrCentimeters/sec 0.6 Meters/minCentimeters/sec 0.02237 Miles/hrCentimeters/sec 3.728 x 10-4 Miles/minCms/sec/sec 0.03281 Feet/sec/secCubic centimeters 3.531 x 10-5 Cubic feetCubic centimeters 6.102 x 10-2 Cubic inchesCubic centimeters 10-4 Cubic metersCubic centimeters 1.308 x 10-4 Cubic yardsCubic centimeters 2.642 x 10-4 GallonsCubic centimeters 9.999 x 10-4 LitersCubic centimeters 2.113 x 10-3 Pints (liq)Cubic centimeters 1.057 x 10-3 Quarts (liq)Cubic feet 2.832 x 10-4 Cubic cmsCubic feet 1728 Cubic inchesCubic feet 0.02832 Cubic metersCubic feet 0.03704 Cubic yardsCubic feet 7.48052 GallonsCubic feet 28.32 LitersCubic feet 59.84 Pints (liq)Cubic feet 29.92 Quarts (liq)


Cubic feet/min 472.0 Cubic cms/secCubic feet/min 0.1247 Gallons/secCubic feet/min 0.4719 Liters/secCubic feet/min 62.43 Pounds of water/minCubic feet/sec 0.646317 Millions gals/dayCubic feet/sec 448.831 Gallons/minCubic inches 16.39 Cubic centimetersCubic inches 5.787 x 10-4 Cubic feetCubic inches 1.639 x 10-5 Cubic metersCubic inches 2.143 x 10-5 Cubic yardsCubic inches 4.329 x 10-3 GallonsCubic inches 1.639 x 10-2 LitersCubic inches 0.03463 Pints (liq)Cubic inches 0.01732 Quarts (liq)Cubic meters 106 Cubic centimetersCubic meters 35.31 Cubic feetCubic meters 61023 Cubic inchesCubic meters 1.308 Cubic yardsCubic meters 264.2 GallonsCubic meters 999.97 LitersCubic meters 2113 Pints (liq)Cubic meters 1057 Quarts (liq)Cubic meters/hr 4.40 Gallons/minCubic yards 764,554.86 Cubic centimetersCubic yards 27 Cubic feetCubic yards 46.656 Cubic inchesCubic yards 0.7646 Cubic metersCubic yards 202.0 GallonsCubic yards 764.5 LitersCubic yards 1616 Pints (liq)Cubic yards 807.9 Quarts (liq)Cubic yards/min 0.45 Cubic feet/secCubic yards/min 3.366 Gallons/secCubic yards/min 12.74 Liters/secDecigrams 0.1 GramsDeciliters 0.1 LitersDecimeters 0.1 MetersDegrees (angle) 60 MinutesDegrees (angle) 0.01745 RadiansDegrees (angle) 3600 SecondsDegrees/sec 0.01745 Radians/secDegrees/sec 0.1667 Revolutions/minDegrees/sec 0.002778 Revolutions/secDekagrams 10 GramsDekaliters 10 LitersDekameters 10 MetersDrams 27.34375 GrainsDrams 0.0625 OuncesDrams 1.771845 GramsFathoms 6 FeetFeet 30.48 CentimetersFeet 12 InchesFeet 0.3048 MetersFeet 1/3 YardsFeet of water 0.0295 AtmospheresFeet of water 0.8826 Inches of mercuryFeet of water 304.8 Kgs/sq meterFeet of water 62.43 Lbs/sq ftFeet of water 0.4335 Lbs/sq inchFeet/min 0.5080 Centimeters/secFeet/min 0.01667 Feet/secFeet/min 0.01829 Kilometers/hrFeet/min 0.3048 Meters/min

Appendix B—Conversion Tables Tank Manual

B-2 June 1989


Feet/min 0.01136 Miles/hrFeet/sec 30.48 Centimeters/secFeet/sec 1.097 Kilometers/hrFeet/sec 0.5924 KnotsFeet/sec 18.29 Meters/minFeet/sec 0.6818 Miles/hrFeet/sec 0.01136 Miles/minFeet/sec/sec 30.48 Cms/sec/secFeet/sec/sec 0.3048 Meters/sec/secFoot-pounds 1.286 x 10-3 British Thermal UnitsFoot-pounds 5.050 x 10-7 Horsepower-hrsFoot-pounds 3.240 x 10-4 Kilogram-caloriesFoot-pounds 0.1383 Kilogram-metersFoot-pounds 3.766 x 10-7 Kilowatt-hoursFoot-pounds/min 2.140 x 10-5 B.T.U./secFoot-pounds/min 0.01667 Foot-pounds/secFoot-pounds/min 3.030 x 10-5 HorsepowerFoot-pounds/min 5.393 x 10-3 Gm-calories/secFoot-pounds/min 2.280 x 10-5 KilowattsFoot-pounds/sec 7.704 x 10-2 B.T.U./minFoot-pounds/sec 1.818 x 10-3 HorsepowerFoot-pounds/sec 1.941 x 10-2 Kg-calories/minFoot-pounds/sec 1.356 x 10-3 KilowattsGallons 3785 Cubic centimetersGallons 0.1337 Cubic feetGallons 231 Cubic inchesGallons 3.785 x 10-3 Cubic metersGallons 4.951 x 10-3 Cubic yardsGallons 3.785 LitersGallons 8 Pints (liq)Gallons 4 Quarts (liq)Gallons-Imperial 1.20095 U.S. gallonsGallons-U.S. 0.83267 Imperial GallonsGallons water 8.345 Pounds of waterGallons/min 2.228 x 10-3 Cubic feet/secGallons/min 0.06308 Liters/secGallons/min 8.0208 Cu ft/hrGrains (troy) 0.06480 GramsGrains (troy) 0.04167 Pennyweights (troy)Grains (troy) 2.0833 x 10-3 Ounces (troy)Grains/U.S. gal 17.118 Parts/millionGrains/U.S. gal 142.86 Lbs/million galGrains/Imp gal 14.254 Parts/millionGrams 980.7 DynesGrams 15.43 GrainsGrams .001 KilogramsGrams 1000 MilligramsGrams 0.03527 OuncesGrams 0.03215 Ounces (troy)Grams 2.205 x 10-3 PoundsGrams/cm 5.600 x 10-3 Pounds/inchGrams/cu cm 62.43 Pounds/cubic footGrams/cu cm 0.03613 Pounds/cubic inchGrams/liter 58.416 Grains/galGrams/liter 8.345 Pounds/1000 galsGrams/liter 0.06242 Pounds/cubic footGrams/liter 1000 Parts/millionHectares 2.471 AcresHectares 1.076 x 105 Square feetHectograms 100 GramsHectoliters 100 LitersHectometers 100 MetersHectowatts 100 Watts


Horsepower 42.44 B.T.U./minHorsepower 33,000 Foot-lbs/minHorsepower 550 Foot-lbs/secHorsepower 1.014 Horsepower (metric)Horsepower 10.547 Kg-calories/minHorsepower 0.7457 KilowattsHorsepower 745.7 WattsHorsepower (boiler) 33,493 B.T.U./hrHorsepower (boiler) 9.809 KilowattsHorsepower-hours 2546 B.T.U.Horsepower-hours 1.98 x 106 Foot-lbsHorsepower-hours 641.6 Kilogram-caloriesHorsepower-hours 2.737 x 105 Kilogram-metersHorsepower-hours 0.7457 Kilowatt-hoursInches 2.540 CentimetersInches of mercury 0.03342 AtmospheresInches of mercury 1.133 Feet of waterInches of mercury 345.3 Kgs/sq meterInches of mercury 70.73 Lbs/sq footInches of mercury (32°F) 0.491 Lbs/sq inchInches of water 0.002458 AtmospheresInches of water 0.07355 Inches of mercuryInches of water 25.40 Kgs/sq meterInches of water 0.578 Ounces/sq inchInches of water 5.202 Lbs/sq footInches of water 0.03613 Lbs/sq inchKilograms 980.665 DynesKilograms 2.205 LbsKilograms 1.102 x 10-3 Tons (short)Kilograms 103 GramsKilograms-cal/sec 3.968 B.T.U./secKilograms-cal/sec 3086 Foot-lbs/secKilograms-cal/sec 5.6145 HorsepowerKilograms-cal/sec 4186.7 WattsKilogram-cal/min 3085.9 Foot-lbs/minKilogram-cal/min 0.09351 HorsepowerKilogram-cal/min 69.733 WattsKgs/meter 0.6720 Lbs/footKgs/sq meter 9.678 x 10-5 AtmospheresKgs/sq meter 3.281 x 10-3 Feet of waterKgs/sq meter 2.896 x 10-3 Inches of mercuryKgs/sq meter 0.2048 Lbs/sq footKgs/sq meter 1.422 x 10-3 Lbs/sq inchKgs/sq millimeter 106 Kgs/sq meterKiloliters 103 LitersKilometers 105 CentimetersKilometers 3281 FeetKilometers 103 MetersKilometers 0.6214 MilesKilometers 1094 YardsKilometers/hr 27.78 Centimeters/secKilometers/hr 54.68 Feet/minKilometers/hr 0.9113 Feet/secKilometers/hr .5399 KnotsKilometers/hr 16.67 Meters/minKilometers/hr 0.6214 Miles/hrKms/hr/sec 27.78 Cms/sec/secKms/hr/sec 0.9113 Ft/sec/secKms/hr/sec 0.2778 Meters/sec/secKilowatts 56.907 B.T.U./minKilowatts 4.425 x 104 Foot-lbs/minKilowatts 737.6 Foot-lbs/secKilowatts 1.341 Horsepower


June 1989 B-3


Kilowatts 14.34 Kg-calories/minKilowatts 103 WattsKilowatt-hours 3414.4 B.T.U.Kilowatt-hours 2.655 x 106 Foot-lbsKilowatt-hours 1.341 Horsepower-hrsKilowatt-hours 860.4 Kilogram-caloriesKilowatt-hours 3.671 x 105 Kilogram-metersLiters 103 Cubic centimetersLiters 0.03531 Cubic feetLiters 61.02 Cubic inchesLiters 10-3 Cubic metersLiters 1.308 x 10-3 Cubic yardsLiters 0.2642 GallonsLiters 2.113 Pints (liq)Liters 1.057 Quarts (liq)Liters/min 5.886 x 10-4 Cubic ft/secLiters/min 4.403 x 10-3 Gals/secLumber Width (in.) xThickness (in.)/12 Length (ft.) Board feetMeters 100 CentimetersMeters 3.281 FeetMeters 39.37 InchesMeters 10-3 KilometersMeters 103 MillimetersMeters 1.094 YardsMeters/min 1.667 Centimeters/secMeters/min 3.281 Feet/minMeters/min 0.05468 Feet/secMeters/min 0.06 Kilometers/hrMeters/min 0.03728 Miles/hrMeters/sec 196.8 Feet/minMeters/sec 3.281 Feet/secMeters/sec 3.6 Kilometers/hrMeters/sec 0.06 Kilometers/minMeters/sec 2.287 Miles/hrMeters/sec 0.03728 Miles/minMicrons 10-6 MetersMiles 1.609 x 105 CentimetersMiles 5280 FeetMiles 1.609 KilometersMiles 1760 YardsMiles/hr 44.70 Centimeters/secMiles/hr 88 Feet/minMiles/hr 1.467 Feet/secMiles/hr 1.609 Kilometers/hrMiles/hr 0.8689 KnotsMiles/hr 26.82 Meters/minMiles/min 2682 Centimeters/secMiles/min 88 Feet/secMiles/min 1.609 Kilometers/minMiles/min 60 Miles/hrMilliers 103 KilogramsMilligrams 10-3 GramsMilliliters 10-3 LitersMillimeters 0.1 CentimetersMillimeters 0.03937 InchesMilligrams/liter 1 Parts/millionMillion gals/day 1.54723 Cubic ft/secMiner’s inches 1.5 Cubic ft/minMinutes (angle) 2.909 x 10-4 RadiansOunces 16 DramsOunces 437.5 GrainsOunces 0.0625 Pounds


Ounces 28.3495 GramsOunces 0.9115 Ounces (troy)Ounces 2.790 x 10-5 Tons (long)Ounces 2.835 x 10-5 Tons (metric)Ounces (troy) 480 GrainsOunces (troy) 20 Pennyweights (troy)Ounces (troy) 0.08333 Pounds (troy)Ounces (troy) 31.10348 GramsOunces (troy) 1.09714 Ounces (avoir)Ounces (fluid) 1.805 Cubic inchesOunces (fluid) 0.02957 LitersOunces/sq inch 0.0625 Lbs/sq inchParts/million 0.0584 Grains/U.S. galParts/million 0.07015 Grains/Imp galParts/million 8.345 Lbs/million galPennyweights (troy) 24 GrainsPennyweights (troy) 1.55517 GramsPennyweights (troy) 0.05 Ounces (troy)Pennyweights (troy) 4.1667 x 10-3 Pounds (troy)Pounds 16 OuncesPounds 256 DramsPounds 7000 GrainsPounds 0.0005 Tons (short)Pounds 453.5924 GramsPounds 1.21528 Pounds (troy)Pounds 14.5833 Ounces (troy)Pounds (troy) 5760 GrainsPounds (troy) 240 Pennyweights (troy)Pounds (troy) 12 Ounces (troy)Pounds (troy) 373.2417 GramsPounds (troy) 0.822857 Pounds (avoir)Pounds (troy) 13.1657 Ounces (avoir)Pounds (troy) 3.6735 x 10-4 Tons (long)Pounds (troy) 4.1143 x 10-4 Tons (short)Pounds (troy) 3.7324 x 10-4 Tons (metric)Pounds of water 0.01602 Cubic feetPounds of water 27.68 Cubic inchesPounds of water 0.1198 GallonsPounds of water/min 2.670 x 10-4 Cubic ft/secPounds/cubic foot 0.01602 Grams/cubic cmPounds/cubic foot 16.02 Kgs/cubic metersPounds/cubic foot 5.787 x 10-4 Lbs/cubic inchPounds/cubic inch 27.68 Grams/cubic cmPounds/cubic inch 2.768 x 104 Kgs/cubic meterPounds/cubic inch 1728 Lbs/cubic footPounds/foot 1.488 Kgs/meterPounds/inch 1152 Grams/cmPounds/sq foot 0.01602 Feet of waterPounds/sq foot 4.882 Kgs/sq meterPounds/sq foot 6.944 x 10-3 Pounds/sq inchPounds/sq inch 0.06804 AtmospheresPounds/sq inch 2.307 Feet of waterPounds/sq inch 2.036 Inches of mercuryPounds/sq inch 703.1 Kgs/sq meterQuadrants (angle) 90 DegreesQuadrants (angle) 5400 MinutesQuadrants (angle) 1.571 RadiansQuarts (dry) 67.20 Cubic inchesQuarts (liq) 57.75 Cubic inchesQuintal, Argentine 101.28 PoundsQuintal, Brazil 129.54 PoundsQuintal, Castile, Peru 101.43 PoundsQuintal, Chile 101.41 Pounds


B-4 June 1989


Quintal, Mexico 101.47 PoundsQuintal, metric 220.46 PoundsQuires 25 SheetsRadians 57.30 DegreesRadians 3438 MinutesRadians 0.637 QuadrantsRadians/sec 57.30 Degrees/secRadians/sec 0.1592 Revolutions/secRadians/sec 9.549 Revolutions/minRadians/sec/sec 573.0 Rev/min/minRadians/sec/sec 0.1592 Rev/sec/secReams 500 SheetsRevolutions 360 DegreesRevolutions 4 QuadrantsRevolutions 6.283 RadiansRevolutions/min 6 Degrees/secRevolutions/min 0.1047 Radians/secRevolutions/min 0.01667 Revolutions/secRevolutions/min/min 1.745 x 10-3 Rads/sec/secRevolutions/min/min 2.778 x 10-4 Revs/sec/secRevolutions/sec 360 Degrees/secRevolutions/sec 6.283 Radians/secRevolutions/sec 60 Revolutions/minRevolutions/sec/sec 6.283 Radians/sec/secRevolutions/sec/sec 3600 Revs/min/minSeconds (angle) 4.848 x 10-4 RadiansSquare centimeters 1.076 x 10-3 Square feetSquare centimeters 0.1550 Square inchesSquare centimeters 10-4 Square metersSquare centimeters 100 Square millimetersSquare feet 2.296 x 10-5 AcresSquare feet 929.0 Square centimetersSquare feet 144 Square inchesSquare feet 0.09290 Square metersSquare feet 3.587 x 10-4 Square milesSquare feet 1/9 Square yards1/Sq ft/ga/min 8.0208 Overflow rate (ft/hr)Square inches 6.452 Square centimetersSquare inches 6.944 x 10-3 Square feetSquare inches 645.2 Square millimetersSquare kilometers 247.1 AcresSquare kilometers 10.76 x 106 Square feetSquare kilometers 106 Square metersSquare kilometers 0.3861 Square milesSquare kilometers 1.196 x 106 Square yardsSquare meters 2.471 x 10-4 AcresSquare meters 10.76 Square feetSquare meters 3.861 x 10-7 Square milesSquare meters 1.196 Square yardsSquare miles 640 AcresSquare miles 27.88 x 106 Square feetSquare miles 2.590 Square kilometersSquare miles 3.098 x 106 Square yardsSquare millimeters 0.01 Square centimetersSquare millimeters 1.550 x 10-3 Square inchesSquare yards 2.066 x 10-4 AcresSquare yards 9 Square feetSquare yards 0.8361 Square metersSquare yards 3.228 x 10-7 Square milesTemp (°C) + 273 1 Abs. temp (°C)Temp (°C) + 17.78 1.8 Temp (°F)Temp (°F) + 460 1 Abs. temp (°F)Temp (°F) - 32 5/9 Temp (°C)


Tons (long) 1016 KilogramsTons (long) 2240 PoundsTons (long) 1.12000 Tons (short)Tons (metric) 103 KilogramsTons (metric) 2205 PoundsTons (short) 2000 PoundsTons (short) 32,000 OuncesTons (short) 907.1843 KilogramsTons (short) 2430.56 Pounds (troy)Tons (short) 0.89287 Tons (long)Tons (short) 29166.66 Ounces (troy)Tons (short) 0.90718 Tons (metric)Tons of water/24 hrs 83.333 Pounds water/hrTons of water/24 hrs 0.16643 Gallons/minTons of water/24 hrs 1.3349 Cu ft/hrWatts 0.05686 B.T.U./minWatts 44.25 Foot-lbs/minWatts 0.7376 Foot-lbs/secWatts 1.341 x 10-3 HorsepowerWatts 0.01434 Kg-calories/minWatts 10-3 KilowattsWatt-hours 3.414 B.T.U.Watt-hours 2655 Foot-lbsWatt-hours 1.341 x 10-3 Horsepower-hrsWatt-hours 0.8604 Kilogram-caloriesWatt-hours 367.1 Kilogram-metersWatt-hours 10-3 Kilowatt-hoursYards 91.44 CentimetersYards 3 FeetYards 36 InchesYards 0.9144 Meters


June 1989 B-5

TAMAPPB8.PCC

TEMPERATURE CONVERSION TABLE


B-6 June 1989

TAMAPPB9.PCC


June 1989 B-7

Appendix C: GUIDELINES FOR SEISMICALLY EVALUATING ANDRETROFITTING EXISTING TANKS

Table of Contents

C1.0 Introduction C-2

C2.0 Tank Evaluation Procedures and Methodology C-2

C2.1 Evaluating Seismically Vulnerable Tank Appurtenances C-3

C2.2 API 650 Earthquake Stability Requirements C-5

C2.3 Manos Stability Requirements C-6

C3.0 Appropriate Retrofit Decisions C-12

C3.1 Retrofit Decision Aids C-12

C4.0 General Tank Retrofit Approaches C-14

C4.1 Anchoring Tanks With Existing Slab Foundations C-16

C4.2 Anchoring Tanks With Existing Ringwall Foundations C-16

C4.3 Anchoring Tanks Without Existing Foundations C-16

C4.4 Anchoring Tanks During Tank Bottom Replacement C-16

C5.0 Design Considerations When Anchoring Existing Tanks C-18

C6.0 References C-21

Tank Manual Appendix C

June 1994 C-1

T O

C O N T E N T S

C1.0 INTRODUCTION

The purpose of this appendix is to provide the user with guidelines on evaluating and retrofitting existing tanksfor seismic considerations.

Oil storage tank’s are typically designed according to the industry standard API 650. Seismic considerations ascontained in Appendix E of API 650 first appeared in the 3rd revision of the Sixth Edition dated 10/15/79. Althoughthe general theory was developed earlier, few tanks were designed with this methodology before 1979. Also, sincethen, there have been some advances in the understanding of a tank’s dynamic performance. However, theseadvances have not been incorporated into the existing API code.

Because only recently constructed tanks have been designed to resist earthquakes, there may be several seismicallyvulnerable tanks in any given tank population. To limit a facility’s exposure to earthquake damage, seismicallyvulnerable tanks should be identified and their vulnerability reduced.

The following topics are covered in this report:

• Evaluating a tank’s safe capacity based on API seismic criteria and a method developed by George Manos[2].

• Retrofit Decision Aids.

• A review of tank retrofit options.

C2.0 TANK EVALUATION PROCEDURES AND METHODOLOGY

Existing tanks in high seismic zones (UBC zones 2, 3, and 4) that were built prior to the introduction of Appendix Ein API 650 should be evaluated for seismic stability. This section describes the recommended procedure for theseevaluations. The following brief discussions provides some theoretical background that will assist in understandingtank performance during earthquakes.

Tank Behavior During Earthquakes

When full, the tank’s contents represent most of the tank’s mass. Since earthquake forces are proportional to themass, the liquid’s response contributes the most to the seismic overturning moment

The dynamic behavior of the tank’s liquid can be divided into two groups. The liquid near the surface moves ina sloshing mode from one end of the tank to the other, often moving independently from the rest of the tank.This portion of the liquid is called the convective component. The lower liquid being confined by the sloshingliquid above, moves in unison with the tank’s walls and roof and is called the impulsive component. Both liquidsexert a horizontal force on the tank’s walls creating an overturning moment. This overturning moment causes anunanchored tank’s wall to lift up, pulling the bottom plate with it, and causing high compressive stresses in thetank wall opposite the uplifted side.

Resistance to the overturning moment is provided by the roof and shell weight as well as the liquid resting onthe uplifted portion of the bottom plate.

Identifying Seismically Vulnerable Tanks

A seismically vulnerable tank could be damaged during an earthquake possibly releasing some or all of its contents.The following steps will help identify which tanks are seismically vulnerable at a facility.

1. Assess the tank’s appurtenances and its general condition.

2. Evaluate the tank’s stability based upon tank size and H/D ratio.

3. Assess the tank’s stability using the method described in API 650 Appendix E.

Appendix C Tank Manual

C-2 June 1994

4. Reassess the tank’s stability using the method proposed by George C. Manos [2] if the tank failed theAPI assessment.

Tanks that fail both API and Manos methods may need their fill heights reduced or require retrofitting to decreasetheir vulnerability.

C2.1 Evaluating Seismically Vulnerable Tank Appurtenances

During earthquakes, the tank shell’s upward movement can cause damage to rigid attachments. Damaged attach-ments can spill product and cause tank down time. The amount of uplift is difficult to predict and only rarelyhas it been recorded. Generally, six inches of vertical displacement may be assumed for assessment purposes,although there has been an instance of a tank uplifting more than one foot during the 1964 Alaska earthquake.

Typical seismically vulnerable tank details are shown in Figure C-1 with explanations shown in Figure C-2. Pipingshould be assessed for rupture with loss of contents and it should be realized that the pipe may not remain elasticduring the entire six inch shell displacement. Also, in some cases, the piping may posess sufficient strength tofail the obstruction before the pipe fails (as in the case of a large diameter pipe passing beneath a walkway—detailW, Figure C-1).

Vertical pipes rigidly attached to the tank shell (detail J, Figure C-1) can cause loss of product above the attachpoint. For this case, U-Bolt connections should be considered rigid since they may bind with the pipe as the tankshell displaces vertically.

The tank wall near the roof level will also displace horizontally during an earthquake. Relative movement betweenthe tank shell and other tanks or the ground may damage the tank and its attached walkways. If the walkway isattached to the tank shell below the operating safe oil height, product may be lost due to tank shell damage (detailK1 in Figure C-1). Walkways attached above the operating safe oil height may be damaged but will in all likelihoodnot cause a loss of product. The amount of horizontal movement at the tank’s roof is difficult to predict, but wasrecorded for a group of 10.5 foot diameter by 30 foot high tanks during the 1994 Northridge earthquake. Thetanks in question moved together a total of approximately four to five inches. At that time, the walkway impactedthe tank, stopping further movement together. Estimated ground shaking at this facility was light however, andtherefore displacements during a design earthquake may be larger.

Several of the suggested retrofits require increased flexibility. Increasing flexibility may entail anything from re-placing the item to removing the nuts on the anchor bolts. It should be noted that since the anchor bolts need tostretch for uplift to occur, the amount of uplift will be much smaller for an anchored tank than an unanchoredtank. As such, many appurtenances that would be a problem if the tank is unanchored will not be a problem ifthe tank is anchored.


June 1994 C-3

JSTN01A0.HPGTAMAPC-1.GEM

Figure C-1 Seismically Vulnerable Tank Details


C-4 June 1994

C2.2 API 650 Earthquake Stability Requirements

To be seismically safe, API 650 Appendix E evaluates the shell’s compressive stresses. When ratio M/(D2(wt + wL)hereafter called the “stability ratio” approaches 1.57, the tank shell’s compressive stresses become excessive andthe tank is unstable. Since the tank shell’s compressive stress will exceed its allowable stress only when its stabilityratio is close to 1.57, the compressive stress usually doesn’t have to be checked. As a result, the tank’s stabilityis usually assessed by calculating its stability ratio.

As an initial stability check, the operating fluid-heightto tank-diameter ratio can be calculated and comparedto Figure C-3 below. Tanks with H/D’s less than thoselisted in Figure C-3 will most likely pass API 650criteria.

TAMAPC-3.WP

Possible Failure Scenario Suggested Retrofit

A Loss of Product due to pipe or tank shell failure. Add flexibility to pipe or removeobstruction.

B Loss of product due to pipe or tank shell failure. Add flexibility to pipe.

D Loss of product due to pipe or tank bottom failure. Add flexibility to pipe.

E Loss of product due to pipe or tank bottom failure. Reroute piping toward center of tankand/or extend concrete basin beyondpipe/tank connection and addflexibility to the pipe.

G Loss of product due to relative tank displacementsand piping inflexibility.

Increase piping flexibility byproviding horizontal or vertical bends.

J Loss of product at piping support due to shelltearing.

Anchor pipe at shell roof connectionor provide sliding connection.

K1 Loss of product due to relative tank displacementand walkway inflexibility.

Increase walkway flexibility toaccommodate relative displacements.

K2 Damage to walkway and/or tank roof but nosignificant loss of product.

Increase walkway flexibility toaccommodate relative displacements.

S Stairway damage with possible loss of contents. Support stairway exclusively on tankshell.

W Walkway damaged with possible loss of productdue to piping impact or walkway being attached totank shell and ground.

Increase piping flexibility, or attachwalkway exclusively to tank shell, orprovide more piping clearance.

Figure C-2 Seismically Vulnerable Tank Details and Potential Retrofits

Tank Diameter(Ft)

H/D

175’ > D 0.25

95’ > D ≤≤ 175’ 0.30

60’ > D ≤ ≤ 95’ 0.40

D ≤≤ 60’ 0.50

Figure C-3 Allowable H/D vs Tank Size


June 1994 C-5

The table was made using some conservative assumptions which are:

• Seismic zone 4

• Specific gravity of 1.0

• Annular ring thickness of 1/4 inch

• An S3 soil site

If the tank’s specific gravity is greater than 1.0, rests on an S4 soils site, or has an unusually thin shell (D/t >2000), the tank may satisfy Figure C-3 but not pass API 650 criteria. Tanks in this category should be evaluatednumerically by using API 650 Appendix E. An example of how to use the seismic requirements in API 650Appendix E is shown in Chapter 460 of this manual.

Tanks That Fail API Criterion

Tanks that have a stability ratio greater than 1.57 should have their safe seismic fill height calculated. This heightcan be found iteratively by using different fill heights until the stability ratio is just less than 1.57.

Tanks that fail API 650 criterion can alternatively be evaluated using method developed by George Manos. Thismethod is presented in detail in section C2.3.

It should be realized that Tanks with thinner than average shells may pass API 650 criteria but fail the Manosmethod. This is because the Manos method is more sensitive to the tank’s shell thickness than API 650. Thedifference becomes more pronounced for tanks with high strength steels and when a thickened annular ring isused. See section C2.3 for more detail.

C2.3 Manos Stability Requirements

Introduction

For most tanks API 650 Appendix E conservatively estimates their seismic performance. This is because API 650considerably underestimates the amount of bottom plate uplifted during an earthquake. The API approach assumesthe bottom plate develops plastic hinges and does not recognize the important role played by the in-plane stressesin the bottom plate during uplift. By underestimating the amount of bottom plate uplifted, API 650 underestimatesthe resisting liquid on the uplifted bottom plate. This causes API 650 to calculate stability ratios that are too highand therefore, fail some tanks for being unstable that are seismically safe. This effect becomes more pronouncedwith small diameter tanks.

As an alternative to the API 650 approach, Manos [2] has developed an approach based on experimental studiesthat better predicts tank seismic performance for most tanks. Instead of trying to model the complex dynamicuplifting plate behavior, Manos assumes a stress distribution at which the shell buckles and solves for the accel-eration. This acceleration, Ceq, is the response acceleration at which the tank wall buckles and the tank becomesunstable. Comparing Ceq to the peak spectral acceleration, Cex, specifies if the tank is stable.

Foundation stiffness can have a considerable effect on tank performance. Since a flexible foundation allows formore rigid-body motion it has more uplift, radial displacement and penetration. The compressive stresses in thetank shell are decreased as the foundation becomes more flexible and is accounted for by a foundation deformabilitycoefficient in the seismic resistance equation.


C-6 June 1994

Evaluation Procedure

The equation for determining the tank’s seismic resistance is:

Ceq = .372 SEts

2

δw GRH2

m1

mt

−1RH

n

tstp

0.1

(Eq C-1)

The above equation only considers the impulsive liquid for the earthquake forces. Since the tank’s shell androof only make a small contribution to the earthquake forces, this omission constitutes only a small inaccuracy.The sloshing liquid’s absence is compensated for by increasing the moment arm X1/H for the impulsive liquid.

The variables are explained below:

CeqCex

= Maximum impulsive acceleration at which the tank is stable (g)= Peak horizontal spectral acceleration at 2% damping (g)

EGHR

m1mt

WtFcSntptsδw

= Young’s modulus of the tank shell material (lb/ft2)= Content’s specific gravity= Liquid height (ft)= Tank radius (ft)= Ratio of impulsive to total mass (Figure E-2 from API 650 Appendix E)

= Total weight of the tank’s contents (lbs)= Total summed compressive force in the tank’s shell (lbs)= Foundation deformability coefficient= 0.1 + 0.2 H/R ≤ 0.25= Annular ring or bottom plate thickness (ft)= Tank-wall thickness (ft)= Unit weight of water (lb/ft3)

Graphical Procedure

Figure C-4 depicts a graphical representation of the Manos equations that can be used to facilitate rapid evaluationof the tank’s seismic stability. The nomenclature and units for the terms involved in the evaluation is the sameas just described for equation C-1. The procedure may be used to determine the safe seismic fill height for thetank. A step by step procedure follows.

1. Determine the maximum operating fill height, H, of the tank. If this information is not available from tank recordsor other sources, calculate it using the procedure described in subsection 434 or section 1150 of this manual.

2. Determine the following data from tank records or other appropriate sources:

- The tank diameter D- The specific gravity of the tank’s fluid contents, G, i.e., the ratio of the density of the fluid contents

to the density of water- The thickness of bottom course of the tank shell, ts- The thickness of the tank’s annular ring or bottom plate if the tank doesn’t have an annular ring, tp- The tank shell material’s yield strength, Fy- The foundation deformability coefficient, S

S = 1.2 for tanks supported on crushed rock, wood planks, asphalt pads or soil foundation

S = 1.0 for tanks supported on concrete rings or pads


June 1994 C-7

JST

N05A

0.HP

GTA

MA

PC

4.GE

M

Figure C

-4M

anos Tank S

eismic S

tability

Appendix C

Tank M

anual

C-8

June 1994

3. Calculate the lateral seismic acceleration Cex (in g’s), as follows.

(a) If site specific DBE (Design Basis Earthquake, typically corresponding to a return period of 475years) response spectra is available, then Ceq is taken as the peak of the 2% damped spectrum (2%damping is considered to be appropriate for the impulsive liquid’s response of unanchored tanks). Asite specific response spectrum shows the accelerations structures would experience for different struc-tural natural periods. The response spectrum is site specific, that is, it takes into account the site’s dis-tance to known faults and its soil profile. Response spectrum are usually produced by a soilsconsultant. If a response spectrum exists for some damping value other than 2%, the peak can bescaled to the 2% value as follows (see [4] for further details):

Cex = Sa (β) ⋅

3.66

4.38−(1.04(Lnβ))

(Eq C-2)

where:

β = damping ratio (in percent) for which the peak response spectrum acceleration is available

Sa (β) = peak spectral acceleration for damping ratio of β

For example, if the peak of the 5% response spectrum is known to be 0.95g, then β = 5.0, Sa (β) =0.95g and Cex, the peak response for 2% damping is:

Cex = 0.95g

3.664.38−1.04(Ln 5.0)

= 1.28g

(b) If a site specific response spectrum is not available, then use the values listed in Figure C-5. Thesevalues are shown in the paper by Manos using the amplification factor of 4.3 he recommends S1, S2,and S3 are soil types defined in the UBC [3].

SOIL TYPE

UBC SeismicZone (3) S1 S2 S3

1 0.19 0.23 0.29

2A 0.39 0.46 0.58

2B 0.52 0.62 0.77

3 0.77 0.93 1.16

4 1.03 1.24 1.55

TAMAPC-5.WP

Figure C-5 Peak Spectral Values Cex


June 1994 C-9

4. Using the values for D, G, Cex, ts, tp and S from Steps (1) through (3), calculate F(D) from the following equation:

F(D) = D2 GCex

(ts ⁄ tp)0.1tsS(Eq. C-3)

5. Calculate D/ts. Using Figure C-4 and entering the curve corresponding to the calculated value of D/ts at theappropriate F(D) value, determine the value of H/D. Note that if D/ts lies between two values for whichcurves are supplied, interpolate linearly between those two curves when determining the upper bound valuefrom Figure C-4. Also, low D/ts valves are limited by the tank shell’s yield stress.

6. Find the upperbound on H/D for the Cex value found in step 3. The vertical (i.e., constant H/D) lines inFigure C-4 represent upper bound values of H/D for different values of Cex. If the value of Cex found inStep (3) does not coincide with any of the values shown in Figure C-4, then the upper bound on H/D canbe interpolated or calculated from equation C-4.

HD

≤ 1.52Cex

+ 0.22

(Eq. C-4)

7. Take the lower of the H/D values found in steps 5 and 6 and multiply by D to get H. This is the seismicsafe fill height. If it is greater than the tank’s operating height, the tank is stable. If it is less then the tank’soperating height then the tank is unstable at the tank’s operating safe oil height.

Example

For an example of the above procedure, consider a 36 foot diameter by 35 foot high tank at the El SegundoRefinery. It is required to determine the seismic safe fill height for the tank.

1. Take H = Current Operating Safe Oil Height = 34.5 ft.

2. Tank Diameter D = 36 ft.Liquid specific gravity G = 1.0Bottom course shell thickness ts = 0.29 inches = 0.0242 feetBottom plate thickness tp = 0.25 inches = 0.0208 feetTank shell Yield strength Fy = 36 KsiFoundation rigidity factor S = 1.0 (Concrete Pad)

3. Following the procedure described above and using the 5% damped site specific response spectrum for theEl Segundo site, which has a peak of 0.95g, Cex = 1.28g.

4. Calculate F(D)

F(D) = D2 G Ceq

(ts ⁄ tp)0.1 tsS =

(36)2 1.0 (1.28)(0.0242 ⁄ 0.0208)0.10.0242 (1.0)

F(D) = 6.75 X 104

5. D/ts = 36/0.0242 = 1487. Since 1487 is almost 1500 use the D/ts = 1500 curve. From Figure C-4, the allowableH/D is about 0.75.

6. The upper bound on H/D for Cex = 1.28 is found by interpolating between the vertical lines of Cex = 1.2and Cex = 1.4. From Figure C-4 upper bound is about H/D = 1.4.

7. H/D = 0.75 from step 5 is the lower value and controls in this case. The seismic safe fill height is then:

0.75 (36’) = 27 ft.


C-10 June 1994

Since this is less than the current operating safe fill height, the tank is unstable at the tank’s operating safe oilheight.

Numerical Procedure

If increased accuracy is desired, the tank’s seismic safe fill height can be solved for numerically using an iterativeprocess. The procedure uses equation C-1 with the following modifications.

1. The Manos method uses 75% of the theoretical buckling stress. For small diameter tanks with low D/ts, thisstress may exceed the yield stress. The buckling stress is therefore limited to the shell’s yield stress. This istaken into account by calculating an additional variable, α, which relates the tank shell’s yield stress to itsbuckling stress.

α = σyield ⁄ σbuckle(Eq C-5)

σbuckle = 0.454E(ts)

R(Eq C-6)

If σbuckle ≤ σyield α = 1.0

2. The Manos method sums up the stresses in the shell to calculate an overturning moment. However, for smalltanks summing the compressive shell stresses may yield a force (Fc) which can be greater than the total tankweight including contents (Wt). To correct this problem, an additional variable, λ, which relates the tankcontent’s weight to the summed compressive force is introduced.

λ = Wt ⁄ Fc(Eq C-7)

Where:

Wt = 62.4 G(π H D2) ⁄ 4(Eq C-8)

Fc = 0.38SEts2(R⁄H)n(ts ⁄ tp)0.1

(Eq C-9)

If Wt ≥ Fc Then λ = 1.0

Ceq is calculated from equation C-1 and multiplied by the smaller of α or λλ to get a modified Ceq. If Ceq > Cexthen the tank is stable. When Ceq = Cex the fill height used, H, is the seismic safe fill height. To get this fillheight, equation C-1 is checked with different fill heights until Ceq = Cex.

Tanks that Fail API and Manos Criteria

A tank that has a Ceq less than the peak acceleration which the tank would be expected to see in an earthquakeCex, is unstable and should have its safe seismic fill height calculated. The safe seismic fill heights from API 650and Manos can be compared and for most cases, the safe seismic fill height based on the Manos method shouldbe used. This is usually the higher of the two. The Manos Method is more sensitive to the tank’s shell thicknessthan API 650 Appendix E. This may be particularly important for tanks which have thinner than average shellssuch as tanks with high-strength steels. For these tanks the Manos Method may calculate a lower safe seismicfill height than API 650.

While the Manos Method is more sensitive to tank shell thickness than API 650 Appendix E, it is less sensitiveto a tank’s annular ring thickness. A thicker annular ring allows the tank to mobilize more fluid as the tank shelluplifts and can have an important stabilizing affect on tank stability. For tanks with annular rings thicker than1/4 inch, Appendix E of API 650 is thought to be more appropriate.


June 1994 C-11

To reduce the seismic vulnerability of a tank, the maximum operating fill height should be reduced to the safeseismic fill height, or, alternately, a tank can be retrofitted. Section C3.0 and C4.0 discuss retrofit options in moredetail.

Legal Considerations

Many states require that new tanks be built in accordance with good engineering practice or applicable designcodes. The governing standard is often API 650 and in these cases the seismic design requirements listed inAppendix E have been used.

For assessing existing tanks, the applicable seismic standard becomes less clear. API 653 is the only standard thatcovers in service storage tanks. This standard does not specifically address which design code or standard shouldbe used to perform a seismic evaluation. Instead, it directs the tank engineer to consider and evaluate all anticipatedload conditions, including seismic loads. Because this standard does rely heavily on the principles of API 650one may presume that Appendix E may be used to evaluate an existing tank if nothing better exists. However,there is nothing to prevent the tank engineer from using other standards or codes. Since the various seismic codesand standards give differing results it is natural to choose the method that provides the lease costs to implement.Of course, prudent engineering judgment should always be used.

From a legal viewpoint, the important thing to do is for the engineer to document not only the basis for selectingthe method of analysis to be used but to document the rationale for the design conditions and to show thatconsideration was given to the risks associated with the proposed designs.

C3.0 APPROPRIATE RETROFIT DECISIONS

Once a tank has been identified as being seismically vulnerable, a choice needs to be made as to how to bestmitigate the tank’s seismic vulnerability. Some possible options are:

• Reducing the tank’s operating height

• Changing tank service to a lighter product

• Retrofitting the existing tank

• Building a new tank

• Mitigating the consequences of tank failure

Reducing the fill height to the safe seismic fill height and changing tank service are the easiest options to implement.However, these options may have a significant effect on a facility’s operation which may preclude choosing them.Additional techniques which can help an engineer decide which tanks should be retrofitted are presented in SectionC3.1

C3.1 Retrofit Decision Aids

When a tank is retrofitted, usually the safe seismic fill height can be raised to the tank’s maximum operatingheight. The additional tankage gained by the increase in height, however, may be small. This cost per additionalbarrel gained by retrofitting the tank may even exceed the cost per barrel of constructing a new tank. Therefore,it may be more cost effective to lower the tank to its safe fill height and build a new tank for the additionaltankage required rather than retrofit the existing tank.

The following step by step procedure explains the technique in more detail.

1. Identify the safe seismic fill height using the methods described in sections C2.2 and C2.3.

2. Using section four of this appendix, identify the retrofit options.


C-12 June 1994

3. Estimate the cost for the retrofit options identified.

4. Find the number of barrels gained when retrofitting the tank by taking the difference between themaximum operating height and the safe seismic fill height.

5. Divide the cost of each retrofit by the number of barrels gained by the retrofit. This will be the costper barrel gained.

6. Compare the cost per barrel gained to the cost per barrel for building a new tank. This comparisonwill show that in many cases it is cheaper to add capacity to a facility by building a new tank ratherthan retrofitting an existing tank.

This technique only compares tank retrofit and new tank costs. Other considerations such as the availability ofland for new tanks or plant operations may have a significant impact on which option is chosen.

Decision Analysis Methodology.

Decision analysis is a process which provides a rotational and consistent way to make decisions for complexproblems. This process can help the manager or engineer make decisions where a large uncertainty exists in thevariables involved or where there is little experience with similar projects to help the engineer make the decision.An added benefit of the process is that it documents why a decision was made. This may be particularly importantwhen dealing with regulatory agencies.

The decision analysis process has four basic steps. They are:

Step 1 Information Gathering and Decision Framing

This step helps define the problem and brings together information that will be needed. Information onthe following items and their interrelationship is needed. Typically, experts from the applicable fieldsare consulted during this step on the following items:

• Consequences of failure and the cost involved.

• Available options, both operational and structural.

• Variables which affect the problem.

Step 2 Model Development and Sensitivity Analysis

The information and its interrelationship identified in step one is modeled in a computer program whichthen determines the final results’ sensitivity to each variable. Variables that change the cost very littleare set at their mean value. This focuses the analysis on the few variables that will have a large impacton the cost of each option.

Step 3 Probalistic - Evaluation

Each option’s net present value is determined considering all the outcomes possible, which the variablesvarying within their given ranges. Only variables identified in step two as having a large impact onfinal outcome are considered.

Step 4 Develop Recommendations

Recommendations are formulated based on the insight steps two and three have provided. In most cases,the recommendation would be to proceed with the option that has the lowest net present cost.

Decision Analysis Methodology is an involved process that is most effective when large savings or high uncertaintyis present. An example of this would be evaluating a site that has a liquefaction potential and may require thesite’s tanks to have their foundations modified. For more information on Decision Analysis Methodology, contactCRTC’s Civil and Structural Technical Services Team.


June 1994 C-13

C4.0 GENERAL TANK RETROFIT APPROACHES

Once it has been decided that a tank needs to be retrofitted, the next step is to choose the retrofit method. Somepossible options are:

• Increasing the tank’s annular ring thickness

• Replacing the bottom shell course with a thicker plate

• Anchoring the tank

Increasing the tank’s annular ring thickness is usually the easiest and most cost effective option. This optioncan be done at the same time the tank’s bottom place is being replaced for excessive corrosion. This optionhowever, is usually only effective on large diameter tanks (greater than about 60’ diameter). Also, the maximumannular ring thickness is limited to the bottom shell course thickness which further limits the effectiveness of thisoption.

Increasing the bottom shell course thickness will make most tanks stable but does not help much for tankssmaller than about 20’ in diameter. Also, this retrofit may be difficult to implement and upper tank shell coursesmay also need to be replaced to prevent buckling.

Anchoring a tank will usually work for all tank sizes. Possible anchorage solutions will depend upon tank’sexisting foundation. Figure C-6 will aid in choosing the appropriate anchorage scheme.


C-14 June 1994

Figure C-6 Tank Foundation Retrofit Flow Chart

Note:

(1) Piles may be difficult to add to the existing foundation because of access limitations or soil difficulties.

(2) This method uses the tanks own mass to anchor itself and may be applied to any foundation systemas long as the soil loads are less than allowable loads. This method may not be the most economical.See section C4.4 for more details.


June 1994 C-15

C4.1 Anchoring Tanks with Existing Slab Foundations

The tank should be directly anchored to the slab with anchor bolts and chairs. If bolt edge distances are smallthe slab may need to be radially extended to confine the anchor bolts. The adequacy of the foundation should bechecked and tanks with thin slabs may require foundation modifications.

The slab should be designed for the forces applied to it. These include the soil pressure, the overturning moment,and the fluid weight on the uplifted portion of the foundation if uplift occurs. Also, the calculated soil pressuremust be less than its allowable. If the slab or the soil loads exceed their respective allowable loads, piles or alarger slab is required.

C4.2 Anchoring Tanks with Existing Ringwall Foundations

Tanks should be anchored to their ringwall using anchor bolts with chairs. For some tanks, the weight of theringwall may be enough to increase the tank’s stability; however, in most cases the ringwall will require modifi-cation. Typically, piles are added to anchor the ringwall which is radially extended to confine the anchor boltsand attach the piles. Differential settlement should be considered when adding piles.

C4.3 Anchoring Tanks without Existing Foundations

Tank sites which have high soil bearing capacities, may have many tanks with soil, rock or asphalt pad foundations.Tanks with these foundations must have some method of resisting the uplift forces which result from the overturningmoment. It is, however, very difficult to directly anchor these tanks to the soil, rock, or asphalt pad that they reston. Three methods of anchoring these tanks will now be briefly described.

For small tanks, a new slab foundation can be built. The tank can be temporarily moved by crane to a newlocation and the new foundation constructed at its original site. The tank should be anchored to its new slab withcast-in-place anchor bolts. Once the foundation is built, the tank can be moved back to its original location. Thefoundation should meet the allowable soil bearing pressures and be able to resist the anchorage forces but maynot need piles.

For large tanks, it is more economical to add a new ringwall under the tank’s shell. The tank is anchored to theringwall with cast-in-place anchor bolts. If the soil loads are high or if the tank is unstable without them, theringwall should be supported by piles. Figure C-7 shows a section of a typical tank anchorage where a newringwall is added. The pile type shown is a helical pile which is discussed in section C5.0.

When a tank’s bottom is being replaced it may be more economical to anchor the tank to its old bottom. Thismethod will be discussed in more detail in the next section, C4.4.

C4.4 Anchoring Tanks During Tank Bottom Replacement

Tank Bottom Replacement

A tank’s bottom plate must be replaced from time to time due to corrosion. Standard drawing DG-D1120 showsthe most common method of tank bottom replacement. The concrete spacer between the new and old tank bottomsprovides a clean even working surface to construct the new bottom. This spacer is not meant to resist any loadsother than bearing and is therefore lightly reinforced.

Seismic Retrofit

The tank’s resistance to overturning is related to the amount of tank bottom which lifts up with the tank as ittries to overturn. In this anchorage method, the concrete between the new and old tank bottoms shown on standarddrawing DG-D1120 is more heavily reinforced and its thickness increased. Thickening the concrete spacer betweenthe new and the old tank bottoms increases the amount of tank bottom lifted up during an earthquake and hencethe tank’s earthquake resistance. In affect, the tank anchors itself.


C-16 June 1994

The concrete spacer should be designed for the shears and moments created when the tank bottom uplifts. Also,since the old bottom’s strength is unreliable, new construction is necessary to tie the concrete spacer to the tankwall. A typical cross-section of this method is shown in Figure C-8.

This type of anchorage can be used with any existing foundation system. Soil pressures must be checked againstthe allowable bearing pressures and excessive soil pressure may preclude this retrofit option. Also, it should benoted that the concrete spacer reduces the tanks effective capacity.


Figure C-7 Typical Tank Anchorage with New Ringwall


June 1994 C-17

C5.0 DESIGN CONSIDERATIONS WHEN ANCHORING EXISTING TANKS

When anchoring a tank, the overturning moment, as calculated by API 650 Appendix E, must be resisted by allcomponents of the anchoring system. These are: the anchor bolts, anchor chairs, foundation, and the soil. Properseismic design should have sufficient ductility for good performance with a failure mode that causes the leastthreat to life safety and damage to the structure. The anchor bolts, therefore, are typically designed to be the“weak link” in the anchorage system with other components being designed for higher loads than the designforces.

Anchor Bolts

Anchor bolts attach the tank to its foundation and resist the tank’s overturning forces. Anchor bolts are designedso that they not only resist the overturning forces but also provide ductility by not pulling out of the concrete.Anchor bolt design is covered in Chapter 240 and Appendix B of the Civil and Structural Manual. Four types ofanchor bolts that may be used for anchoring a tank are:

1. Cast-In-Place anchor bolts

2. Adhesive anchors

3. Stainless steel bolts going through the foundation

4. Grouted-In-Place A307 bolts

Cast-In-Place bolts are the preferred bolt because they offer the best connection to concrete. They are cast withthe foundation, however, and therefore can only be used if a new foundation is poured.


Figure C-8 Tank Anchorage Combined with Tank Bottom Replacement


C-18 June 1994

For existing foundations, Adhesive anchors often provide the best solution. They require comparatively littleembedment depth and may be placed close to the tank shell. Like other alternatives they are however very sensitiveto edge distance. Also, adhesive anchors are usually limited to 11⁄4 inch in diameter or less.

Adhesive anchors are temperature sensitive and may not be appropriate for heated tanks containing wax or asphalt.

Stainless steel through-bolts go through the foundation and use the entire foundation depth to get the maximumconcrete pullout strength. In through-bolt construction a hole slightly larger than the bolt diameter is drilled throughthe foundation and a bolt with both ends threaded and without a head is placed in the hole. To prevent the boltfrom pulling out, a cover plate and nut are placed on the lower threaded end. This requires access to the undersideof the foundation which may be difficult for a combined foundation or foundations without piles. Since the bolt,nut, and plate are permanently in contact with the ground, stainless steel is used to prevent corrosion. To minimizethe loads on the anchor chairs and foundation, a mild strength steel should be used.

It should be noted that the foundation may be slightly thicker than shown on the existing drawings. Unless afield investigation is done to determine the footing’s actual thickness, the bolt should be a few inches longer thanwhat is required for design.

As an alternative to stainless steel through bolts, grouted-in-place A-307 bolts may be used. For grouted in placebolts, a hole, (one inch in diameter greater than the anchor bolt head) is drilled in the foundation and the bolt isplaced in the hole which is then filled with a non-shrink epoxy grout. These bolts do not require access to theunderside of the foundation but the embedment depth is limited to the foundation depth minus the required concretecover.

Since grouted-in-place bolts require a larger drilled hole than through-bolts or adhesive anchors, they will havea larger eccentricity with respect to the tank shell than other alternatives. This larger eccentricity will require ahigher chair and may limit the anchor bolt size.

Anchor Chairs

Anchor chair distribute the anchor bolt load to the tank shell so that the stresses are within their allowables. Thechair is designed so that the bolt yields well before the chair or tank shell. This is met by designing the chairfor the yield strength of the anchor bolt as specified by API 650 E.6.2.1. Although not required for existing tanks,anchor chairs should be located so that their weld spacings meet the requirements of API 650 3.8.1. When thetank shell material is not one of the types listed in 3.8.1, the weld spacings should still be met but may be relaxedfor special circumstances. Specifically, for chairs near the manway reinforcing plate, the weld spacing requirementsare impractical and, therefore, these anchor chairs may be placed on the reinforcing plate so long as the newwelds do not cross existing welds. Anchor chair design is covered in more detail in Chapter 460 of this manual.

When chair height becomes excessive an alternative to using anchor chairs is to use a continuous ring whichdistributes the forces more efficiently. A continuous ring must continue around the entire tank without any breaks.This requires the continuous ring to miss any appurtenances, some of which may need to be moved. Also, experiencehas shown that tanks are slightly out of round and may necessitate varying the ring width slightly.

Foundation

The foundation transfers the loads from the anchor bolts and tank to the piles or soil. The foundation must bedesigned for these loads.

For tanks with existing foundations, the foundation is typically extended to confine the anchor bolts. Holes aredrilled horizontally into the foundation with reinforcing steel epoxied into place to tie the new concrete to theexisting foundation. New and existing concrete is bonded together by roughening up the existing concrete surfaceand either applying a coat of epoxy or wire brushing the new concrete into the existing concrete just before theconcrete pour.


June 1994 C-19

If piles are added, they must be tied into the foundation to resist the uplift forces. For driven piles or caissonsthe uplift connection is made with reinforcing steel attached to the pile and embedded in the foundation. For helixpiles, the compression and tension are resisted by a plate welded to the pile and embedded in the concrete asshown in Figure C-7. The foundation is designed for the Concrete bearing pressures under the plate and thepunching shear.

Piles

Retrofitting tanks to resist earthquake forces will often require piles to resist the uplift forces. Piles bring theearthquake uplift forces down into the soil. Typical piles that can resist tension are:

• Driven Piles

• Caissons

• Helix Piles

Generally, driven piles are more expensive than the other two options and usually require more accessibility tothe site. Caisson piles, although less expensive and easier to install have limited uplift capacity. Chapter 230 inthe Civil and Structural Manual describes driven piles and caissons in more detail.

Because of their economy and ease of installation, Helix piles are usually the best alternative when retrofitting atank.

Helix piles are a metal shaft with one or more circular plates, 8 inches to 14 inches in diameter, attached in ahelical pattern. Unlike other piles, helix piles are torqued into place. This allows helix piles to be installed withsmaller equipment than other pile types.

Pile pullout resistance comes from the soil bearing on the circular plates. For piles with shallow embedments —defined as less than five circular plate diameters — the failure mode is a cone of soil projecting to the surfacefrom the circular plate. For piles with deep embedments, the failure mode is a plug of soil starting at the circularplate. A deep anchor is preferred since it will have a ductile failure mode. Very dense soils or soils with largeboulders make torquing helix piles into place difficult and may prevent their use entirely.

It is impractical to use piles to resist the uplift loads for tanks that are founded on rock or have a very shallowsoil profile. For these situations, rock bolts are an acceptable alternative.


C-20 June 1994

C6.0 REFERENCES

1. American Petroleum Institute, API Standard 650, Ninth Edition, Welded Steel Tanks for Oil Storage,Appendix E, Seismic Design of Storage Tanks, July 1993.

2. Manos, George C., “Earthquake Tank-Wall Stability of Unanchored Tanks”, American Society of CivilEngineers, Journal of Structural Engineering, Vol. 112, No. 8, August 1986.

3. International Conference of Building Officials, Uniform Building Code, 1991.

4. Newmark, N.M., and Hall, W. J., Earthquake Spectra and Design, Earthquake Engineering ResearchInstitute, 1982.


June 1994 C-21