Saudi Aramco Repair Alteration of Storage Tanks

Note: The source of the technical material in this volume is the ProfessionalEngineering Development Program (PEDP) of Engineering Services.

Warning: The material contained in this document was developed for SaudiAramco and is intended for the exclusive use of Saudi Aramco’semployees. Any material contained in this document which is not alreadyin the public domain may not be copied, reproduced, sold, given, ordisclosed to third parties, or otherwise used in whole, or in part, withoutthe written permission of the Vice President, Engineering Services, SaudiAramco.

Chapter : Vessels For additional information on this subject, contactFile Reference: MEX20308 J.H. Thomas on 875-2230

Engineering EncyclopediaSaudi Aramco DeskTop Standards

Determining Requirements forRepair or Alteration of Storage Tanks

Engineering Encyclopedia Vessels

Determining Requirements for Repair or Alteration of Storage Tanks

Saudi Aramco DeskTop Standards

CONTENTS PAGE

APPLICATION OF SAES-D-108 AND API-653 TO THE REPAIR ORALTERATION OF EXISTING STORAGE TANKS ......................................................... 1

Scope of SAES-D-108 and API-653................................................................................ 1

SAES-D-108 ................................................................................................................. 1

API-653......................................................................................................................... 2

Application of SAES-D-108 and API-653 ....................................................................... 4

Suitability for Service ................................................................................................... 4

Repairs and Alterations ................................................................................................. 6

Dismantling and Reconstruction ................................................................................... 7

Hot Tapping .................................................................................................................. 8

STORAGE TANK INSPECTION INTERVAL REQUIREMENTS................................. 15

Reasons for Inspection ................................................................................................... 15

SAEP-20 Requirements for Inspection Intervals............................................................ 21

On-Stream Inspection (OSI)........................................................................................ 23

Out-of-Service Inspection (T&I)................................................................................. 24

Inspection and History Reports ...................................................................................... 25

DETERMINING REPAIR OR ALTERATION REQUIREMENTS FORSTORAGE TANK SHELLS AND SHELL PENETRATIONS ........................................ 29

Deterioration of Storage Tank Shells ............................................................................. 29

General Corrosion ....................................................................................................... 29

Pitting Corrosion ......................................................................................................... 30




Tank Shell Evaluation .................................................................................................... 30

Actual Thickness Determination ................................................................................. 30

Minimum Thickness Calculation for Welded Tank Shell ........................................... 32

Minimum Thickness Calculation for Riveted Tank Shell ........................................... 35

Other Shell Evaluations............................................................................................... 36

Minor Defects in Shell Material.................................................................................. 37

Major Defects in Shell Material .................................................................................. 38

Defective Weld Repairs .............................................................................................. 39

Alteration of Shells to Change Height ........................................................................ 40

Situations Involving Shell Penetrations.......................................................................... 46

New Items or Replacement Items ............................................................................... 46

Alteration of Existing Penetration............................................................................... 47

DETERMINING REPAIR OR ALTERATION REQUIREMENTS FORSTORAGE TANK BOTTOMS......................................................................................... 52

Types of Bottom Corrosion............................................................................................ 52

External Corrosion ...................................................................................................... 52

Internal Corrosion ....................................................................................................... 54

Minimum Thickness for Tank Bottom Plate .................................................................. 55

Bottom Thickness Calculation .................................................................................... 57

Overall Evaluation Considerations.............................................................................. 58

Minimum Thickness for Annular Plate Ring ................................................................. 59

Requirements for Repairs to Bottom.............................................................................. 61

Repair of a Portion of Tank Bottom............................................................................ 61

Replacement of Entire Bottom.................................................................................... 65




Effects of Use of Internal Lining or Cathodic Protection Systems................................. 67

Internal Lining............................................................................................................. 69

Cathodic Protection System ........................................................................................ 71

DETERMINING REPAIR OR ALTERATION REQUIREMENTS FORTHE ROOFS OF FIXED ROOF AND FLOATING ROOF STORAGETANKS.............................................................................................................................. 78

Criteria for Roof Evaluation........................................................................................... 78

Fixed Roofs................................................................................................................. 79

Floating Roofs............................................................................................................. 81

Repair Requirements for Fixed Roofs............................................................................ 83

Repair Requirements for Floating Roofs........................................................................ 83

Criteria for Repair or Replacement of Floating Roof Seals............................................ 85

Repair Considerations for Internal Floating Roofs......................................................... 86

DETERMINING REPAIR OR ALTERATION REQUIREMENTS FORSITUATIONS THAT INVOLVE TANK SETTLEMENT ............................................... 87

Shell Settlement.............................................................................................................. 87

Types........................................................................................................................... 87

Evaluation ................................................................................................................... 92

Bottom Settlement.......................................................................................................... 94

Types........................................................................................................................... 94

Evaluation ................................................................................................................... 98

Methods for Correcting Settlement Problems .............................................................. 100

Shell Releveling Considerations and Techniques ..................................................... 100




Bottom Releveling Considerations and Techniques.................................................. 105




HYDROTESTING REQUIREMENTS THAT ARE SPECIFIED IN SAES-A-004 AND API-653 ...................................................................................................... 109

SAES-A-004 Requirements ......................................................................................... 109

API-653 Requirements ................................................................................................. 109

WORK AID 1: PROCEDURE FOR DETERMINING REPAIR ORALTERATION REQUIREMENTS FOR SITUATIONS INVOLVINGSTORAGE TANK SHELLS AND SHELL PENETRATIONS ...................................... 111

Work Aid 1A: Procedural Steps.................................................................................. 111

Work Aid 1B: Inspection Data.................................................................................... 112

Tank Shell ................................................................................................................. 112

Tank Shell Penetrations............................................................................................. 117

Work Aid 1C: Reference to Pertinent Content From SAES-D-108 ............................ 118

Tank Shells................................................................................................................ 118


Work Aid 1D: Reference to Pertinent Content From API-653 ................................... 119

Tank Shells................................................................................................................ 119


WORK AID 2: PROCEDURE FOR DETERMINING REPAIR ORALTERATION REQUIREMENTS FOR STORAGE TANK BOTTOMS..................... 128

Work Aid 2A: Inspection Data.................................................................................... 128

Work Aid 2B: Reference to Pertinent Content From SAES-D-108 ............................ 129

Work Aid 2C: Reference to Pertinent Content From API-653.................................... 130




WORK AID 3: PROCEDURE FOR DETERMINING REPAIR ORALTERATION REQUIREMENTS FOR THE ROOFS OF FIXED ROOFAND FLOATING ROOF STORAGE TANKS............................................................... 135




Floating Roof ............................................................................................................ 136

WORK AID 4: PROCEDURE FOR DETERMINING REPAIR ORALTERATION REQUIREMENTS FOR SITUATIONS INVOLVINGTANK SETTLEMENT.................................................................................................... 137




Shell Settlement Evaluation ...................................................................................... 141

Bottom Settlement Evaluation................................................................................... 142

GLOSSARY.................................................................................................................... 143



Saudi Aramco DeskTop Standards 1

APPLICATION OF SAES-D-108 AND API-653 TO THE REPAIR OR ALTERATIONOF EXISTING STORAGE TANKS

Prior modules focused on the Saudi Aramco and industry requirements that apply to newatmospheric storage tanks. After a tank has been placed into service, it is treated as anexisting tank rather than as a new tank, and different engineering standards are applied to itsevaluation. Existing storage tanks may experience various forms of deterioration or changesin application requirements that could result in the need for repair or alteration. The primaryengineering standards that apply to existing storage tanks are as follows:

• SAES-D-108, Storage Tank Integrity

• API-653, Tank Inspection, Repair, Alteration, and Reconstruction

Scope of SAES-D-108 and API-653

The paragraphs that follow discuss the scopes of SAES-D-108 and API-653.

SAES-D-108

SAES-D-108 is the Saudi Aramco Engineering Standard that applies to the repair andalteration of existing atmospheric storage tanks. SAES-D-108 uses API-653 as the basereference standard, and it then specifies additions and exceptions to API-653 requirements.

SAES-D-108 modifies API-653 requirements in the following areas:

• Bottom plate thickness measurements and minimum acceptable thickness

• Removal and replacement of shell plate material

• Repair of shell penetrations

• Repair of tank bottoms

• Hot taps

• Nondestructive examinations

• Hydrostatic testing

Any conflicts between SAES-D-108 and other Saudi Aramco engineering documents must beresolved by the Saudi Aramco Manager of the Consulting Services Department at Dhahran.




API-653

API-653 is the industry standard that applies to the repair and maintenance of existingatmospheric storage tanks. The scope of API-653 is as follows:

• API-653 applies to carbon and low-alloy steel tanks that were built incompliance with the requirements of API-650, Welded Steel Tanks for OilStorage, and its predecessor API-12C, API Specification for Welded OilStorage Tanks.

The majority of tanks will be of carbon steel construction.

• API-653 provides minimum requirements for maintaining the integrity ofwelded or riveted, nonrefrigerated, atmospheric, aboveground storage tanksafter they have been placed into service.

These tanks are the tank types that are covered by API-650 and/or API-12C,and API-653 is not intended to cover other tank types. While welded ratherthan riveted tank construction is now used, many existing riveted tanks are stillin service, and they must be maintained in acceptable operating condition.

Note that refrigerated, low-pressure, and/or underground storage tanks are notwithin the scope of API-653. However, many API-653 requirements aregeneral enough to also apply to these other tank types. Thus, API-653 may beused as an information resource and guideline to help develop appropriateinspection and maintenance programs for these other tank types.

• API-653 covers maintenance inspection, repair, alteration, relocation andreconstruction.

This scope ensures that any work activity which could affect a tank's suitabilityfor its intended service is included.

• API-653 is limited to the foundation, the bottom, the shell, the structure, theroof, attached appurtenances, and nozzles up to the face of the first flange, thefirst threaded joint, or the first welded-end connection.

These components are the primary components that relate to the tank'sstructural integrity and/or could have a significant environmental impact shouldtheir condition not be acceptable.




• API-653 governs in the case of conflicts between it and API-650 or API-12C.

This order of precedence clearly establishes API-653 as the governingdocument once a tank has been placed into service. Should there be conflictsamong the various tank-related design standards, the governing standardshierarchy for an existing atmospheric storage tank is as follows:

- API-653- Original construction standard- Current edition of original construction standard- API-650

API-653 is not a design standard for new tank construction. However, API-653 applies someAPI-650 requirements within its procedures. In addition, API-653 requirements still must beconsidered in new tank design because API-653 requirements can affect several designdecisions that must be made. For example, API-653 specifies minimum acceptable bottomplate thickness requirements after a tank has been in service. In certain situations, theminimum acceptable bottom plate thickness may require the use of a thicker bottom plate fora new tank than API-650 requires as a minimum. The thicker bottom plate may be needed inorder to have an acceptable tank bottom inspection interval and design life.

API-653 is intended for use by qualified engineering and inspection personnel who areexperienced in the design, fabrication, repair, construction, and maintenance of storage tanks.In cases where API-653 (or API-650 or API-12C) does not contain appropriate requirementsfor a specific situation, the intent is to provide tank integrity that is equivalent to current API-650 requirements.

Many owner companies have used internally developed inspection, repair, and maintenancepractices prior to the introduction of API-653. Now that API-653 exists, it must beconsidered by all companies that have atmospheric storage tanks. Companies that haveestablished tank inspection, repair, and maintenance procedures should review them withrespect to API-653. Companies that have less formal procedures will be under increasedpressure to meet API-653 requirements as a minimum.




Application of SAES-D-108 and API-653

API-653 is divided into several major sections, and SAES-D-108 modifies several of thesesections. The following paragraphs describe the application of several of these sections ingeneral terms and identify Saudi Aramco modifications to these sections.

Suitability for Service

Section 2 of API-653 specifies requirements that must be followed to assess storage tanksuitability for service. In other words, is the current tank integrity acceptable for the intendedoperation? In addition, will the integrity still be acceptable during the entire next period ofoperation until the tank is taken out of service again and inspected?

An engineering evaluation must be performed when inspection results indicate that a changehas occurred from the original physical condition of the tank. Thus, conformance to API-653requirements means that inspection data cannot just be filed away and forgotten. Inspectiondata must be evaluated to confirm that the tank integrity is still acceptable for continuedservice at the intended design conditions. Tank suitability for service also must be assessedwhen considering a change in service, repairs, alterations, dismantling, relocation, orreconstruction.

A wide variety of factors must be considered when a tank's suitability for service is assessed.Several of these factors are as follows:

• Internal or external corrosion. For example, has the shell corroded to the pointwhere it is no longer structurally sound? Is the bottom in danger of "holingthrough" and leaking?

• Actual stress levels in comparison to allowable values. Has the shell corrodedto the point where its stresses are higher than acceptable stresses?

• Properties of the stored liquid, such as its specific gravity, temperature, andcorrosivity. Has there been a change in service such that the new liquid that isbeing stored has a higher specific gravity, is being stored at a temperature thatis over 93°C (200°F), or is more corrosive than the liquid that the tank wasoriginally designed to store?

• Design metal temperature. Has the tank service changed such that a lowerdesign metal temperature must be considered than was used in the originaldesign?




• External roof live load, wind, seismic load. Has there been sufficientdeterioration in the tank such that these other design loads must also beconsidered in assessing the tank's structural integrity?

• Tank foundation, soil and settlement conditions. Has excessive settlementoccurred? Are there any indications of concrete ringwall cracking or spalling?

• Chemical analysis and mechanical properties of the tank materials. Theseitems will not change since the tank was originally constructed, but these itemsare factors that must be considered when the structural integrity of the tank isevaluated.

• Distortions in the shell or roof. These distortions might indicate that there havebeen problems with excessive internal or external pressures. Such problemscould be caused by higher than design filling or emptying rates or by impropervent operation.

• Changes in operating conditions, such as filling and emptying rates orfrequency. Such changes might require that the vent capacities be increased.

The suitability for service of a storage tank is assessed by evaluating the current condition ofthe tank's primary structural components with respect to API-653 acceptance criteria. Theprimary structural components that are evaluated are those structural components that directlyaffect the tank's capability to store liquid. These components are as follows:

• Roof• Shell• Bottom• Foundation

Para. 2.4 of SAES-D-108 modifies the suitability-for-service requirements that are containedin API-653 with respect to assessment of the bottom. Saudi Aramco accepts the other API-653 suitability-for-service requirements.




Repairs and Alterations

Storage tank repairs are required when the structural integrity of the tank has been reduced tothe point where the tank is no longer suitable for the desired service. Typical examples ofstorage tank repairs are as follows:

• Removal and replacement of material that is required in order to maintain tankintegrity, such as portions of the shell, roof, or bottom. This material includesweld metal as well as base material.

• Jacking and re-leveling of the tank shell, bottom, or roof.

• Addition of reinforcing plates to existing shell openings.

• Repair of flaws, such as gouges or tears, by grinding followed by welding.

Storage tank alterations are required when the service requirements for the tank are changed.Typical examples of storage tank alterations are as follows:

• Addition of manways or nozzles that are over 300 mm (12 in.) in nominal size

• Increase or decrease in shell height

Section 7 of API-653 specifies requirements for tank repair and alteration for the followingareas:


• Repair of defects in shell plate material

• Change of shell height

• Repair of defective welds


• Addition, replacement, or alteration of shell penetrations

• Tank bottom repair

• Fixed roof repair

• Floating roof repair, including repair or replacement of perimeter seals

• Hot taps




Section 7 of SAES-D-108 modifies the repair and alteration requirements that are contained inAPI-653 in the following areas:



• Tank bottom repair

• Hot taps

Section 9 and Section 10 of API-653 contain welding and inspection requirements,respectively, that must be followed for tank repairs and alterations.

Section 10 of SAES-D-108 modifies API-653 inspection requirements by requiring thatcompleted fillet weld repairs be examined by wet fluorescent magnetic particle inspectionover their full length.

Dismantling and Reconstruction

There are sometimes situations when it might be advantageous to dismantle an existingstorage tank and to reconstruct it in another location. For example, an existing storage tankmight be in the way of a planned new process unit, but the tank capacity is still needed.Therefore, it might be less expensive to dismantle the existing tank and to relocate it, ratherthan construct a new tank.

A great deal of cutting and rewelding is required to dismantle and to reconstruct an existingstorage tank. The reconstructed tank must have acceptable mechanical integrity for theservice conditions, especially with respect to brittle fracture resistance. Fracture toughnessand brittle fracture were discussed in MEX 203.02.

It is especially difficult to confirm acceptable mechanical integrity if the tank to bereconstructed is more than about 25 years old. The materials that were used to construct oldtanks will not meet current fracture toughness requirements, and thus these old tanks are moreprone to failure due to brittle fracture. In addition, if the construction material is unknown, itmust be assumed that the material would not meet current fracture toughness requirements.The cutting and rewelding that are required to dismantle and to reconstruct a tank that wasconstructed with material that does not meet current fracture toughness requirements increasesthe risk of brittle fracture still further.




One of the prime factors that initiated the preparation of API-653 was a catastrophic brittlefracture of a fuel oil storage tank that occurred in the late 1980's in the U.S. This failureoccurred the first time that the tank was filled after it had been reconstructed, and it resulted ina major fuel oil discharge into a nearby river. Therefore, the reconstruction requirements thatare contained in Sections 5, 6, and 8 of API-653 are conservative, especially thoserequirements that relate to the reuse of existing material. These requirements cover:

• Original material requirements• Design considerations• Dismantling and reconstruction methods

SAES-D-108 does not modify any API-653 requirements with respect to dismantling andreconstruction.

Hot Tapping

A "hot tap" or "hot tapping" refers to the procedure that is used to add a new nozzle to astorage tank, pipe, or pressure vessel without taking the storage tank, pipe, or pressure vesselout of service. Adding a nozzle by hot tapping is sometimes advantageous because ofoperational considerations. Adding nozzles by hot tapping is not an uncommon practice,especially in piping systems. However, since there are inherent risks associated with addingnozzles while a storage tank or pipe is still in service, this procedure should only be usedwhere it is impractical to take the tank or pipe out of service.

A hot tap is performed by:

• Welding a suitably sized and reinforced nozzle to the tank. This nozzle has aflanged end.

• Pressure-testing the nozzle connection.

• Bolting a full-port valve to the flanged nozzle, and bolting a hot tap machine tothe valve.

• Opening the valve and using the hot tap machine cutter to cut an opening in thetank and to hold the cut piece.

• Extracting the cut piece of plate, called the "coupon," through the valve andinto the cutting machine housing.

• Closing the valve and removing the hot tap machine.




Figure 1 illustrates the basic arrangement for making a hot tap. A new pipe section,instrument, or equipment item can then be bolted onto the flanged valve as required.

Figure 1. Basic Hot Tap Arrangement




API-653 Requirements - API-653 contains hot tap requirements in Para. 7.13. Several ofthese requirements are summarized in the paragraphs that follow. Course Participants arereferred to API-653 for additional information.

• API-653 contains requirements for radial nozzle installation, which is the mostcommon orientation. If a nonradial nozzle must be installed by hot tapping,additional requirements must be developed. These additional requirementsmay entail items such as:

- Additional engineering calculations to ensure that the shell thickness isadequate

- Further inspection

- Installation limitations of the hot tap machine

- Minimum permitted nozzle angle

• Hot taps are not permitted on:

- The roof or within the tank vapor space. A flammable mixture mayform in this area, and it may be ignited by the heat from the hot tapcutting or welding operations.

- Tanks where the heat of welding can cause environmental cracking,such as caustic cracking or stress corrosion cracking.

- Tanks that require postweld heat treatment (PWHT). PWHT cannot bedone with the tank in service.

- Laminated or badly pitted shell plate. This restriction ensures that thehot tap will be made only into a sound area of the tank shell. Sufficientvisual, pit gauge, and ultrasonic inspection measurements must be madeto ensure that the tank shell thickness and integrity are adequate for thehot tap. The hot tap must be relocated as needed to a sound area on thetank.

• Connection size and shell plate thickness limitations are as provided in Figure2:




Connection Size, NPS Minimum Required Shell PlateThickness

mm in. mm in.

≤ 200 ≤ 8 6.35 1/4

≤ 355 ≤ 14 9.5 3/8

≤ 460 ≤ 18 12.7 1/2

Figure 2. Minimum Shell Thickness for Hot Taps

In order to ensure that the shell thickness meets these minimum limits, ultrasonic thicknessmeasurements must be made of the tank shell plate where both the nozzle and reinforcing padwelds will be made. If the shell is too thin, the hot tap should be relocated to a thicker area.These minimum shell thicknesses only consider hot tap requirements, and they are based onthe thickness that is required to prevent burning through the plate while the nozzle is weldedto the shell. These thicknesses are not necessarily sufficient for the hydrostatic head or otherdesign loads that are imposed on the tank. The shell thickness must be checked separately forthese other loads.

API-653 requires that shell plate thickness measurements be taken in at least four places alongthe circumference of the proposed nozzle location. Four locations are adequate for relativelysmall diameter nozzles in tanks where localized corrosion is not expected. However, moremeasurements may be required for larger diameter nozzles or in locations where localizedcorrosion may be a consideration.

By implication, the largest nozzle size that may be hot tapped is 460 mm (18 in.).

• The minimum spacing in any direction between the hot tap and adjacent

nozzles shall be at least Rt where "R" is the tank radius and "t" is the tank

shell plate thickness. The Rt spacing is measured toe-to-toe between thewelds. This minimum spacing requirement is to avoid excessive localizedstresses that might develop due to the proximity of geometric discontinuities.




• Only steels that are of known acceptable fracture toughness may be hot tapped.One measure of meeting this requirement is if it is known that the steel metcurrent API fracture toughness requirements. Meeting current API fracturetoughness requirements means either that the steel was exempt from impacttesting, or that it was impact-tested at the design metal temperature.

Steels that are of unknown fracture toughness may be hot tapped if theminimum shell metal temperature during the hot tap meets or exceeds theexemption curve in Figure 7-5 of API-653 based on the plate thickness wherethe hot tap is being done. In this case, the steel is known to have fracturetoughness that is sufficient to not have a brittle fracture while the hot tap isbeing done.

• Welding shall be done using low hydrogen electrodes.

API-653 requires that a hot tap procedure be developed and documented. The proceduremust be specific to the particular hot tap that is to be done. API-653 also requires that the hottap procedure include practices that are given in API Publication 2201, Procedure forWelding or Hot Tapping on Equipment Containing Flammables. Several of these practicesare noted in the paragraphs that follow. Course Participants are referred to API-2201 foradditional information.

• Metallurgical considerations, such as low minimum design metal temperaturesor small, shop-fabricated tanks that have been stress-relieved (e.g., for causticor amine services), must be accounted for.

• Service fluid characteristics that would make hot tapping unsafe must beconsidered. These fluid characteristics include the following:

- Chemicals that are likely to decompose or become hazardous from theheat of welding (such as acids, chlorides, or peroxides).

- Vapor/air or vapor/oxygen mixtures that are within the flammable orexplosive ranges.

- Certain unsaturated hydrocarbons, such as ethylene, that may undergoan exothermic decomposition reaction due to the welding or cutting heatthat occurs during hot tapping.

• Appropriate plans and procedures must be prepared. These plans andprocedures must include appropriate design, welding, inspection, and safetyrequirements.




• Tank operations must be stopped during the hot tapping. For example:

- Pumping into or out of the tank must be stopped.

- All valves on liquid lines must be closed, tagged, locked, or otherwiserendered inoperable.

- All mixer operations must be stopped.

- Operations that are associated with gas-blanketing valves or with othervalves that could cause venting from the tank must be avoided.

• Turn off all heating coils during hot tapping. Turning off the coils will help todissipate the heat that is generated by the cutting and welding operations.

• Maintain a liquid level of at least 1 m (3 ft.) above the hot work area whenwelding or cutting is being done. This liquid level will help to dissipate theheat that is generated, and it will help to keep the hot tapping sufficiently belowthe vapor space.

• In general, hot work should not be done on either the deck or pontoons of afloating roof tank due to the likelihood that a flammable mixture will be presentunder the deck.

Owner companies such as Saudi Aramco typically have their own detailed hot tap proceduresand restrictions that build upon the API-653 and API-2201 requirements. Saudi Aramcorequirements are highlighted in the section that follows.

SAES-D-108 Requirements - SAES-D-108 requires that a stress analysis be performed forhot taps that are larger than 460 mm (18 in.) pipe size. Recall that API-653 minimumacceptable shell thickness requirements stop at this pipe size. Therefore, Saudi Aramcowould permit larger diameter hot taps, but they are treated as special cases. The ConsultingServices Department should be consulted for these situations.

SAES-D-108 refers to Saudi Aramco General Instruction G.I. 441.010, Installation of HotTapped Connections, for requirements that are related to installation procedures,organizational responsibilities for various phases of the work, and safety considerations. Thedetailed emphasis of G.I. 441.010 is on hot taps that are made into piping systems becausethese comprise the vast majority of all of the hot taps that are made. However, the overallsafety and procedural requirements that are contained in G.I. 441.010 apply to storage tankhot taps as well. The paragraphs that follow highlight the primary organizationalresponsibilities for hot taps. Participants are referred to G.I. 441.010 for detailed information.




A Saudi Aramco area maintenance or construction organization will typically initiate arequest for a hot tap by providing general descriptive information of the requirements onForm A-7627. The initiating engineer will generally serve in a coordination and follow-uprole among the appropriate operations, inspection, engineering, and maintenanceorganizations throughout the hot tap procedural process. The maintenance or constructionorganization is responsible for performing the physical work that is required for the hot tap.

Operations is responsible for specifying the design conditions and for meeting the appropriatesafety, work permit, and operating procedure requirements.

Engineering is responsible for the following:

• Development of the required design details and drawings for the hot tapconnection and reinforcement

• Design calculations

• Specifying hydrotest pressure

• Installation and weld procedures

Inspection is responsible for the following:

• Inspection for the thickness and condition of the tank shell plate in the areawhere the welding will be done.

• Welding procedure approval.

• Inspecting the connection before and during the installation for compliancewith the specifications.

• Witnessing and approving the hydrotests of the hot tap valve and the installednozzle.




STORAGE TANK INSPECTION INTERVAL REQUIREMENTS

Storage tank components will deteriorate to some extent after they have been exposed to theoperating conditions. This deterioration must be identified before it affects the structuralintegrity of the tank so that appropriate repairs and maintenance are done on a planned basisrather than on an unscheduled basis.

Storage tanks must be inspected by qualified inspectors at reasonable intervals in order todetermine the current condition of the storage tanks and to permit assessment of theirsuitability for continued service. Tank integrity assessments cannot be made unless tanks areinspected at regular intervals. The sections that follow discuss the primary reasons forinspecting a storage tank, the SAEP-20 requirements for inspection intervals, and theInspection and History Report that is used to document the tank's condition as determinedfrom inspections that have been done.

Reasons for Inspection

In order to determine their physical condition and the type, rate, and causes of deteriorationthat may have occurred, storage tanks are inspected after they have been placed intooperation. The information that is obtained from each inspection must be recorded to permitboth current evaluation and future reference.

Periodic inspection is necessary to determine whether the structural integrity of the tank is stillacceptable and whether the tank remains safe for continued operation. Before the conditionhas deteriorated to the point where leakage of hazardous fluid or other failures occur, trends intank condition can be identified and appropriate corrective action can be taken. Such leakageor tank failure would cause an unplanned shutdown with consequent disruption in operationalplans.

Periodic inspection permits the development and execution of a planned maintenance andrepair schedule. Corrosion rates and remaining corrosion allowances can be predicted basedon the inspection results. This corrosion rate and remaining corrosion allowance informationis then used to identify and plan for the necessary materials, labor, time, and costs that arerequired to keep the storage tank in acceptable operating condition.

External inspections may be made visually or with other nondestructive techniques while thetank is in operation and still closed. These operational inspections may identify problemssuch as the following:

• Leaks

• Shell distortion

• Obvious shell settlement or foundation damage




• Obvious signs of corrosion

• Condition of paint, coatings, and appurtenances

Early identification of problems such as those listed above and their causes can help in thedevelopment of appropriate corrective action, it can prevent more extensive damage, and itcan direct the planning efforts for later internal inspections and maintenance activities.

Periodic internal inspection of the tank is also required to identify potential problems that arenot visible from the outside of the tank. The following are several reasons for doing aninternal tank inspection:

• To identify any severe corrosion or leakage of the bottom.

• To gather sufficient data to perform shell and bottom plate minimum thicknessassessments that are part of the required suitability for service evaluation.

• To identify locally corroded areas of the shell that were not identified by anyexternal inspection that was done.

• To identify any bottom settlement that has occurred.

Figure 3 (in four parts) illustrates typical locations on a tank that must be inspectedperiodically, and notes many of the types of deterioration that must be considered.




Figure 3. Inspection Locations and Tank Deterioration




Figure 3, cont'd. Inspection Locations and Tank Deterioration












SAEP-20 Requirements for Inspection Intervals

Section 4 of API-653 specifies tank inspection interval requirements for external inspectionwith the tank in-service and internal inspection intervals with the tank out-of-service. SaudiAramco terminology for these inspections, as defined in SAEP-20, Equipment InspectionSchedule, are as follows:

• On-Stream Inspection (OSI) for the in-service inspection

• Test and Inspection (T&I) for the out-of-service inspection

Saudi Aramco sets tank inspection intervals based on SAEP-20 requirements rather thanbased on API-653 requirements. API-653 also divides external inspection into routine in-service inspection and scheduled inspection. This concept of dividing the external inspectionand the general considerations that are contained in API-653 still apply with SAEP-20inspection interval requirements.

Several factors that must be considered in the determination of suitable inspection intervalsare as follows:

• Nature of the stored liquid. What is its expected corrosivity?

• Results of visual maintenance checks. Are there obvious areas of concern?Are there visible leaks?

• Corrosion allowances and corrosion rates. What was anticipated as part of theoriginal design, and what has been the actual experience?

• Corrosion prevention systems. Is there an internal lining or cathodic protectionsystem installed?

• Conditions at previous inspections. What deterioration was already identifiedand where was it?

• Methods and materials of construction and repair. Do the materials and repairmethods that were used meet current requirements?

• Tank location. Is the tank relatively isolated, or is it in a high-risk area whereleakage could have significant consequences?

• Potential risk of air or water pollution. Is the tank near a major body of wateror residential area?

• Is a leak detection system installed?




• Changes in operation. Have there been changes in the filling and emptyingfrequency that would affect the reliability of tank components? For example, isa floating roof being landed more frequently? Has the stored liquid beenchanged to one that is more corrosive?

• Local jurisdictional requirements. Do local governmental authorities requirespecific inspection frequencies?

As stated earlier, storage tanks must be inspected at reasonable intervals to determine theircurrent condition and to permit assessment of their suitability for continued service. SaudiAramco develops tank inspection interval requirements based on procedures that arecontained in SAEP-20. SAEP-20 also contains procedures that must be followed to extend orto deviate from the inspection intervals that were originally established, and it assignsimplementation responsibilities to specific Saudi Aramco organizational functions.

SAEP-20 requires that an Equipment Inspection Schedule (EIS) be developed for tanks thatare in the following categories:

• Utilities, production, processing, storage, and transportation of oil, gas, and by-products.

• Critical community facilities which, upon failure, could be hazardous or couldcause serious inconvenience to the community.

• Critical equipment (i.e., equipment that cannot be inspected by any meansexcept if it is taken out of service during a T&I).

The EIS must be prepared, and it must be included in the Inspection Record Book as part ofthe Project Record Book. The EIS must be submitted for approval 30 days prior tocompletion of the facility. The approval process involves Saudi Aramco ProjectManagement, the facility's Operations Engineering Unit, and the facility's Inspection Unit.Therefore, all of the appropriate organizations are involved in the development of the EIS,and they will provide relevant Saudi Aramco experience to this process.

SAEP-20 requires that inspection intervals be specified for both On-Stream Inspection (OSI)and Test and Inspection (T&I). In both cases, initial inspection intervals (I-OSI and I-T&I)and subsequent inspection intervals must be specified.




SAEP-20 contains procedures that classify fixed equipment, including storage tanks, withrespect to Corrosion Service Classes. Table II of SAEP-20 defines four Corrosion ServiceClasses based on corrosion rate (or special problems). The maximum OSI and T&I inspectionintervals are then determined, primarily based on these Corrosion Service Classes, and onother factors that are stated in SAEP-20.

On-Stream Inspection (OSI)

The tank's external condition should be monitored by close visual inspection from the groundon a routine basis by personnel who are familiar with storage tanks but who are notnecessarily qualified inspectors. For example, these routine visual inspections may be doneby operations or maintenance personnel who must be in the area as part of their primary jobfunction. The intent of the routine inspections is to identify questionable items that should beexamined in more detail by qualified inspectors.

Formal external inspections must be made by qualified inspection personnel on a scheduledbasis. The OSI interval is determined by criteria that are contained in SAEP-20. The requiredOSI interval is determined based on the anticipated or measured corrosion rates, pastexperience, and any findings that are obtained from the routine in-service inspections thatwere made. Ultrasonic thickness measurements of the shell are a part of this inspection.

External nondestructive examination (NDE) that is done as part of the OSI providesinformation that may be used to adjust T&I intervals that were initially specified, ifappropriate, based on actual inspection results. OSI can be done at any time. However, basedon Table II of SAEP-20, the maximum interval for the initial OSI for tanks will be in therange of 12 to 24 months, based on the Corrosion Service Class of the tank. There is someflexibility in setting this initial OSI interval, and the Area Operations Inspection Unit shouldbe consulted to finalize the initial OSI interval based on the general factors that werepreviously noted.

Subsequent OSI intervals are determined using one of the following methods (based on Para.3.5.7.2 of SAEP-20):

• Annual OSI scheduling for logistical purposes.

• Calculated based on the remaining tank life using the results of priorinspections. The maximum subsequent OSI interval that is determined on thisbasis should be no more than the smaller of one-fourth of the remaining life, orfive years.




Out-of-Service Inspection (T&I)

Internal inspection intervals (i.e., T&I intervals) are determined, based on prior corrosion rateexperience with other tanks in similar service and experience with the particular tank that isbeing evaluated if prior inspection data is available. This T&I interval is determined bycriteria that are contained in SAEP-20. In most cases, internal inspection intervals aredetermined based on bottom corrosion rates. The time interval for internal inspection must beset to ensure that the bottom does not thin below values that are specified in API-653 beforethe next internal inspection. The intent is to prevent a hole in the bottom that would permiteven a small leak of liquid from the tank. Bottom leaks can continue for a long time beforeany visible evidence of them appears outside of the tank.

The T&I is done with the tank out-of-service, and it permits complete assessment of the insidesurfaces of the shell, the bottom, and the roof, plus an assessment of all internal components.The initial T&I (I-T&I) is required to determine if there are any unforeseen problems and toobtain more data to help to set or to adjust subsequent T&I intervals. Saudi Aramco has agreat deal of operating experience with most tank services and company locations. Therefore,storage tanks can be considered as "standard equipment" for the purposes of using SAEP-20to set an I-T&I. The I-T&I interval would then be set at 24 months for all Corrosion ServiceClasses based on Table I of SAEP-20.

The subsequent T&I intervals are based on equipment and service conditions or operatingexperience, and they are determined by application of the following factors:

• Remaining Life. The subsequent T&I interval can be no more than the smallerof half the calculated remaining tank life or ten years. The remaining life isbased on the existing (i.e., remaining) corrosion allowance divided by themaximum corrosion rate that is determined by inspection data that wereobtained from the OSI or from prior experience.

• Service Criteria. The subsequent T&I interval can be no more than thatdetermined from Table I of SAEP-20 based on the Corrosion Service Class.This subsequent T&I interval will range between 30 and 120 months.

• Specific Equipment Category. This categorization is based on Para. 3.5.9 ofSAEP-20 as follows:

- 10 years for storage tanks and RLPG tanks at 17 kPa (2.5 psig) and less(including water)

- 20 years for refrigerated double-wall storage tanks at less than 17 kPa(2.5 psig)

Use of these inspection intervals is only acceptable if an ultrasonic thicknesssurvey for pitting is passed 6 to 12 months before the start of the scheduledinterval.




Inspection and History Reports

Historical inspection records are important because they form the basis for developing ascheduled tank inspection and maintenance program. Section II of API-653 requires that theowner/operator maintain a complete record file for each tank. The record file must includeinformation on construction details, calculations, inspection history, and repair/alterationhistory. This information helps to determine appropriate inspection intervals based on actualexperience, and it identifies any changes that were made to the tank that could affect itsstructural integrity. In situations where records do not exist for a particular tank, judgmentsmust be made based on experience with similar tanks that are in the same service. However,record keeping should begin currently even if earlier information is not available.

An Inspection and History Report documents the results of a storage tank inspection that isdone during a T&I, and it forms the basis of the tank's historical records. A typical storagetank Inspection and History Report will include at least the following sections:

• Identification and Documentation Information. This section includes itemssuch as the tank identification number and name, tank location, tank service,date of inspection, and inspector's name.

• Scope and History. This section specifies the scope of the current inspection aswell as the inspection methods that were used (such as visual observations andultrasonic measurements). The use of any special inspection techniques shouldbe documented.

This section also summarizes the tank's history, such as when it was placed intoservice, when the last T&I was done, and any significant inspection findings orrepairs that were made during the last T&I. The Equipment InspectionSchedule (EIS), with the associated On-Stream Inspection (OSI) and Test &Inspection (T&I) intervals, are not a part of the Inspection and History Report,but these items may be referred to if required as part of the evaluation.

The inspector should have reviewed the operating history of the tank, and heshould have identified any operating difficulties that occurred during the lastperiod of operation prior to the T&I. Anything unusual in the operating historyshould be documented in the report because an operations factor might havecontributed to problems that are noted during the inspection. This tank historyreview should also include whether any problems were found on similar tanksduring their T&Is that affected how the current inspection was conducted.




• Observations and Recommendations. This section provides the results of theinspection, and it is divided into subsections based on the main tankcomponents (such as shell sections, roof, bottom, nozzles, and foundation).The visual observations of the inspector are recorded for each component, asare the results of any measurements (such as thickness readings) that are made.One or more sketches of the tank will normally be included in order to identifythe locations of the thickness measurements or other observations that aremade. Locating the observations and measurements in this manner helps toidentify the potential causes of problems, and it highlights areas to inspectduring subsequent T&Is. Inspection of the same locations during T&Is helps toestablish trends in tank deterioration, especially corrosion.

The complete information file for the tank will include the Tank Data Sheet-Layout ofAppurtenances (Form 2696), the Safety Instruction Sheet (Form 2693), the contractor's tankdata specification sheet, fabrication drawings, and the mechanical design calculations. It maybe necessary to refer to this additional information in order to evaluate the current inspectiondata. However, this additional information is not part of the Inspection and History Report.




Inspection and History Reports, cont'd

Figures 4 and 5 provide overall formats that summarize the primary sections and informationthat are combined in an Inspection and History Report.

Identification and Documentation Information

Scope and History

Observations and Recommendations

Item Observations/Recommendations

Shell

Wind Girder

Roof

Bottom

Coating

Nozzles and Flanges

Foundation

Paint System

Insulation System

Ladders, Stairways, Platforms

Auxiliary Equipment (Gage connections,alarms, vents, etc.)

Grounding Connections

Cathodic Protection System

Figure 4. Components of Inspection and History Report




Sketch of Tank Shell or Bottom With ThicknessMeasurement Points Indicated

Prepared By Inspector

Thickness Data

PointNumber

OriginalNominal

Thickness

MinimumRequiredThickness

Measured Thickness

Figure 5. Inspection and History Report Thickness Measurement Data




DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR STORAGETANK SHELLS AND SHELL PENETRATIONS

This section discusses the evaluation of storage tank shells and shell penetrations of existingstorage tanks. In each case, the existing condition of the storage tank is considered togetherwith the tank design requirements in order to determine an appropriate course of action.

Work Aid 1 contains procedures and criteria for making these determinations.

Deterioration of Storage Tank Shells

Flaws in the base metal or welds, distortion, corrosion, or other deterioration may occur in thetank shell during operation. In order to determine the continued suitability of the tank shellfor the intended service, the condition of the tank shell must be quantified by inspection, andit must be evaluated by experienced engineering personnel. The possibility that the tankcondition will deteriorate further during the next period of operation must be considered inperforming this evaluation. For example, if corrosion has occurred, further corrosion duringthe next period of operation must be considered. Thus, the current tank condition may beacceptable for the design loads, but future corrosion may make the tank conditionunacceptable at some point during the next period of operation.

Corrosion is the most common tank shell deterioration that must be dealt with. In most cases,the hydrostatic head that is imposed by the stored liquid is the governing design load.Therefore, most of the discussion that follows focuses on assessing the suitability of acorroded tank shell for the hydrostatic head. Other situations will be discussed briefly in laterparagraphs.

Shell corrosion may be classified as either general corrosion or pitting corrosion. Thisdistinction must be made because a different evaluation approach is used for each type ofcorrosion.

General Corrosion

A corrosion site will be classified as general corrosion when the material has thinned in arelatively uniform manner over the area. At a general corrosion site, the main concern is howmuch thickness has been lost. If too much thickness is removed, the corroded area of theshell can no longer sustain the loads that are imposed during normal operation, and a shellfailure may result. Recall from MEX 203.03 that the determination of the required shellthickness is based on both an allowable stress and the imposed hydrostatic head from thestored liquid. Therefore, if the shell corrodes too much, the resulting stresses can exceed theallowable stresses with the original design liquid fill height.




Pitting Corrosion

Pitting corrosion is when the material has been removed in a very localized area, giving acrater-like appearance to the surface. Pits can be very deep or shallow and be of varyingdiameters. Pitting is not of great concern as a threat towards the overall integrity of the shellunless the pits are present in close proximity to each other and unless they are very deep andextensive. However, pits can result in local leaks if they progress through the entire shellthickness.

Tank Shell Evaluation

Evaluation of shell corrosion consists of determining if the current condition of the shell isadequate for the tank service. If a change in tank service is being considered, the shell mustbe evaluated for the new service conditions. For example, if the stored liquid will be changedto one with a higher specific gravity, the higher specific gravity must be considered in theevaluation. The evaluation must consider all anticipated loading conditions and loadcombinations, not necessarily just the hydrostatic pressure load. These conditions are thesame conditions that were originally considered when the tank was designed (refer to MEX203.03). The evaluation must also consider any future corrosion that may take place until thenext T&I. Consideration of any future possible corrosion helps ensure that the tank will bestructurally sound during the entire period of operation until the next T&I.

The possible results of the evaluation can be any one of the following:

• The shell may be adequate without restrictions for the required service.

• The shell may need to be repaired to permit the required service.

• The allowable liquid level may need to be reduced in order to keep the shellstresses within allowable limits.

• The tank may need to be retired.

When the current shell condition is found to be unacceptable, which option is taken dependson the extent of repairs that are required, the available time to make the repairs, and the costof such repairs.

Actual Thickness Determination

Ultrasonic (UT) measuring devices determine the thickness of the shell over a small area thatis covered by the UT transducer. UT measurements are satisfactory for determining theoverall shell thickness in the area of the transducer, but the transducer area is too large forsatisfactory determination of the shell thickness for pitting types of corrosion. Therefore, a pitgauge is used to determine the amount of penetration (i.e., depth) in a corrosion pit. A pit




gauge consists of both a thin shaft that can probe to the bottom of the pit and a mechanism for"marking" the depth of the probe beyond the general surface of the surrounding material.




A general UT thickness survey of a tank will typically require a minimum of three readingson each shell course along vertical lines on the North, East, South, and West sides of the tank.Additional readings are taken in areas of the shell that have pitting corrosion or in other areasthat obviously have extensive corrosion. For the corroded areas, the thickness readings aretaken by means of a grid pattern that is placed over the area in order to permit detailedevaluation. The amount of inspection can be increased further, if appropriate, based on theinitial evaluation results.

The minimum thicknesses that are found from the UT survey may be used directly in the shellintegrity assessment. As long as use of the minimum thicknesses does not result in the needfor either repairs or a fill height restriction, there is no incentive to inspect or evaluate theshell further. However, API-653 permits a less conservative but technically acceptableapproach to determine the thickness that is used in the shell integrity assessment.

For shells that have large, generally corroded areas, the measured thicknesses may be"averaged" in order to arrive at an overall strength of the shell to use in the integrityassessment. The basic concept that is employed here is that thicker areas in a corroded regionserve to reinforce areas that are more corroded. An analogy is the use of excess metal that isavailable in a pipe or pressure vessel shell as reinforcement of a branch connection. WorkAid 1 contains the procedure that is used to perform this thickness averaging.

API-653 also permits pitted areas to be completely ignored if the pits can be considered as"widely scattered," based on their depth and spacing. Work Aid 1 contains the criteria thatmust be satisfied for pits to be considered "widely scattered." The rationale here is that aslong as the pit depth and spacing are within the stated limits, they will not decrease thestructural integrity of the tank shell. If the pits cannot be considered "widely scattered," theymust be evaluated as general corrosion.

Minimum Thickness Calculation for Welded Tank Shell

Once the actual shell thicknesses have been determined, they must be compared to theminimum required thicknesses in order to determine if the actual shell thicknesses areacceptable. Work Aid 1 contains the procedure for calculating the minimum requiredthicknesses. The following paragraphs highlight several considerations with respect to thisprocedure.

• Unlike API-650, API-653 uses a slightly more conservative allowable stressbasis for the bottom and second courses than for the upper courses. Recallfrom MEX 203.03 that for the design of a new tank, the shell plate allowablestress (design or hydrotest case) is only a function of material specification andis not based on a consideration of what shell course the plate is in. Thisincreased conservatism in API-653 is due to the generally more complex stressdistribution in these lower courses that is not being accounted for in theevaluation. In spite of this, the API-653 allowable stress basis is slightly moreliberal than API-650 in order not to be overly conservative while still beingsafe.




API-653 still permits evaluation of a tank shell even if the material is unknown.However, in the case of unknown material, API-653 requires an allowablestress that corresponds to a relatively weak carbon steel. Thus, if there is nodocumentation that a stronger material was actually used, a significant fillheight restriction might be required even if there has been no corrosion.

• The original weld joint efficiency must be used in the thickness calculationprocedure. However, if the original weld joint efficiency is unknown, a verylow weld joint efficiency of 0.7 must be used. Here again, use of this low weldjoint efficiency could result in a significant fill height restriction even withoutcorrosion.

API-653 permits making a distinction between areas that are near welds andthose areas that are away from welds with regard to the use of weld jointefficiency in the shell evaluation. A weld joint efficiency of 1.0 may be usedwhen evaluating corroded areas that are far enough away from welds.Therefore, use of the original joint efficiency (or 0.7 if unknown) whenevaluating corroded areas that are located away from welds is too conservativeand not required. If use of the weld joint efficiency is a significant factor for aparticular tank, additional inspection data that locates corroded regions withrespect to tank shell welds could be helpful.

• The specific gravity of the stored liquid is used in the thickness calculation. Ifit is anticipated that the tank might have to be hydrotested in the future due torepairs or alterations, a specific gravity of 1.0 should be used. It is possible thatthere could be no fill height restriction for the normally stored liquid but thatthere could be a fill height restriction for the hydrotest water, because ofcorroded areas in the shell.

• If the relatively simple hand calculation procedures that are contained in API-653 find that the tank is unacceptable, API-653 permits the use of the "designby analysis" approach that is contained in Section VIII, Division 2, Appendix 4of the ASME Code. This approach requires detailed computer calculations andmore thickness inspection measurements to accurately model the corrosion aswell as to categorize and to evaluate the stresses. However, a tank that is foundto be unacceptable by the simple procedures is often found to be acceptablewhen the Division 2 procedures are used.




One common example of where a Division 2 approach often yieldssignificantly improved results is when localized shell corrosion (Figure 6) inthe bottom-to-shell junction region is being evaluated. The simplifiedcalculation procedures are based on a membrane stress evaluation, whereas thelocal shell stresses near the bottom are predominantly bending stresses innature. Evaluating these local stresses as membrane stresses is a reasonableapproach for new tank design, but it is excessively conservative when acorroded tank is being evaluated for continued operation. The Division 2analysis approach categorizes the calculated stresses into membrane andbending components, and it permits the separate evaluation of these stresscomponents. Bending stresses may safely have a higher allowable stress valuethan membrane stresses. Analyses that have been done on this basis have oftenfound that fairly severe localized corrosion, which would have required repairbased on the simplified calculation procedures, is acceptable without repair.

Figure 6. Localized Shell Corrosion




Minimum Thickness Calculation for Riveted Tank Shell

All new tanks that are designed and constructed in accordance with API-650 are of weldedconstruction. However, there are many older tanks that are still in service and that are ofriveted construction. In these older tanks, the individual shell plates are attached to each otherby rivets, as illustrated in Figure 7.

Figure 7. Riveted Shell Construction




As shown in Figure 7, two shell plate attachment details were used in riveted shellconstruction. In one detail, the shell plates are lapped over each other and riveted together.In the second detail, the shell plates are brought close to each other, butt straps are placedboth inside and outside of the shell such that the shell plates are located between the buttstraps, and the assembly is riveted together. The butt-strap design is the stronger of the two.In each case, the size and spacing of the rivets and the number of rivet rows were determinedduring detailed engineering based on the required design loads.

The shell thickness for riveted tanks is evaluated through use of the same minimum thicknessformula that is used for welded shell construction with the following exceptions:

S = 145 MPa (21 000 psi)

E = 1.0 for shell plate that is 150 mm (6 in.) or more away from rivets

Table 2-1 of API-653 provides rivet joint efficiencies that may be used for locations that arewithin 150 mm (6 in.) of rivets. These rivet joint efficiencies are based on both whether thejoint is a lap or butt type and the number of rivet rows that are used to connect the plates.These joint efficiencies are recognized as being conservative; therefore, as an alternative,API-653 also permits the use of calculated rivet joint efficiencies. Alternate allowablestresses that are specified in API-653 must be used if calculated rivet joint efficiencies areused.

CSD should be consulted if repairs are required to a riveted storage tank for two reasons:

• A riveted tank will be old, and the shell plate material will not meet currentfracture toughness requirements. Therefore, the design details and installationprocedures that are used for any welded repairs or alterations must be carefullyreviewed to ensure that they do not increase the risk of brittle fracture.

• The heat of welding causes differential thermal expansion, which often leads tothe loosening of riveted joints and leakage from the shell. Therefore, repair andalteration alternatives must be considered in order to select the alternative withthe least probability of causing or increasing a leakage problem.

Other Shell Evaluations

The calculations that have been discussed thus far consider only liquid loading. Liquidloading is generally the limiting factor in tank shell evaluations. However, API-653 requiresthe evaluation of other loads in accordance with the original construction standard. Theseother loads include the following:

• Wind-induced buckling

• Seismic loads

• Operating temperatures that are over 93°C (200°F)




• Vacuum that is caused by external pressure

• External loads that are caused by piping; attached equipment such as mixers;hold down lugs; etc.

• Wind-induced overturning moment

• Loads that are due to tank settlement

Engineering judgment is required to determine the extent to which any of these loads areconsidered in the evaluation. CSD should be consulted as needed for assessment of theseother loads.

Minor Defects in Shell Material

A minor defect in the shell material may be defined by one of the following criteria:

• A defect that does not require any repair at all.

• The defect repair that is required may be done with weld overlay. This amountof required repair implies that the defect is small.

• If a replacement plate is required to repair the defect, the replacement plate isno larger than 300 mm (12 in.) on any one side. This amount of repair isconsidered to be small.

Work Aid 1 defines criteria for when repairs must be done and requirements that must be metfor the repairs themselves.

Typical situations that may be considered minor shell defects includes the following:

• Isolated pits

• Relatively small amounts of localized corrosion

• Scars, gouges, tears, isolated cracks




The need to repair minor defects such as those listed above, is determined on an individualbasis. If the defects are located in areas of the shell where the plate thickness exceeds thethickness required by the design conditions, grinding the defects to a smooth contour withoutfurther repair is permissible. This grinding is done in order to minimize localized stressconcentration effects that are due to any abrupt geometric changes that are associated with thedefect. In situations where grinding thins the plate to an unacceptable level (i.e., thinner thanis required to resist the design loads), weld metal must be added to repair the defect. Aqualified weld procedure must be used for any welding that is done.

Major Defects in Shell Material

Major defects in shell material are those defects that would require the use of replacementinsert plates that are more than 300 mm (12 in.) on a side in order to restore the tank to therequired structural integrity. The most common situation where this amount of repair isrequired is if there is extensive general corrosion or severe pitting. Other possible major shelldefects include excessive shell distortions or laminations. Work Aid 1 defines criteria forwhen repairs must be done as well as criteria for the repairs themselves.

The guiding philosophy that is used to determine specific repair requirements is that therepairs must restore tank integrity, the repairs themselves must not make the existing tankintegrity worse, and current API-650 requirements must be met to as great an extent possiblein making the repairs. The paragraphs that follow highlight several of the primaryrequirements regarding the repair of major shell defects.

• The replacement plate material, welding and welder qualifications, and weldingconsumables must meet current API-650 requirements. These requirementsensure that all new components and welding have the same integrity as incurrent new tank construction. The primary concern is to not increase the riskof experiencing a brittle fracture as a result of the repairs that are done.

• A minimum replacement plate size is specified in order to avoid having newwelds too close to each other. Weld shrinkage stresses could become excessiveand lead to excessive distortion if the welds are too close together.

• Square or rectangular replacement plates must have rounded corners rather thansharp corners. Rounded corners reduce local stress concentration effects, andresidual welding stresses, and thus they make it less likely that cracks wouldinitiate at the plate corners when the tank is placed back into service.




• Minimum distances are specified between the new replacement plate welds andthe existing welds that are in the shell. Acceptable distances between welds arebased on shell plate thicknesses, and different distances are specified for eachtype of shell weld (i.e., vertical, horizontal, shell-to-bottom, or radial bottomplate welds). The intent of these minimum distances is to minimize the effectthat shrinkage stresses from the new welds have on existing tank welds.

Defective Weld Repairs

Work Aid 1 contains criteria that may be used to determine when repairs to welds arerequired. When weld repairs are required, the defective area must be completely removed, asuitable weld preparation must be made, and a qualified weld procedure must be used.

It is always important to determine the root cause of any defect that is found, whether it is at aweld or not. However, a root-cause assessment is more important for a weld defect becausethe cause might be less obvious. The primary questions that must be answered in doing aroot-cause assessment of a weld defect are as follows:

• What type of defect is it? For example, the defect may be a crack, corrosion,undercut, lack of fusion, or other weld imperfection. The type of defectinfluences whether it needs to be repaired and how the repair should be done.

• Is the defect from the original construction or did it occur during tankoperation? For example, a lack of penetration or weld undercut is an originalfabrication defect. A crack could be an original fabrication defect as well.However, a crack could also be caused by excessive local loads, such as loadsfrom a piping system or excessive settlement.

• How extensive is the defect and where is it? For example, cracks will almostalways require repair, especially if they occur at the shell-to-bottom weld.However, a corroded weld may not need to be repaired as long as the weld isthick enough for the imposed loads. Less than full penetration at a weld mayalso not require repair if the weld is at a high enough elevation in the tank shellsuch that the actual weld thickness is sufficient for the imposed loads.




Alteration of Shells to Change Height

It is sometimes desirable to increase the existing shell height in order to increase storagecapacity of the tank. Increasing the shell height is permissible as long as the following itemsare considered in the evaluation.

• The existing shell course thicknesses must be evaluated for acceptability basedon the increased design liquid level in the tank that the higher shell permits.Some shell height increase might be possible in situations where there has notbeen significant corrosion or where the originally supplied plate thicknessesexceeded those that were required. However, from a practical standpoint, itwould be unusual if much more than a 10-15% height increase was possible.

• The increased shell height would effect the tank design for wind and seismicloads. A higher shell for a floating roof tank makes the shell more prone towind-induced buckling. Therefore, the existing wind girder design must bechecked. A higher shell also increases the maximum tank overturning momentdue to wind or maximum seismic loads.

• All design and installation details must meet the same requirements as for therepair of major shell defects. These details were previously discussed.

Sample Problem 1: Determine if Shell Repair is Required

The external floating roof tank that is described in Figure 8 has been in service for 15 years.




Figure 8. Sample Problem 1 Tank




The following additional design data is available:

• The design liquid fill height is 61 ft.

• The stored hydrocarbon has a specific gravity of 0.85.

• The specified minimum tensile strength for the shell steel is 60 000 psi.

• The specified minimum yield strength for the shell steel is 35 000 psi.

• The original shell weld joint efficiency is 0.85.

An ultrasonic thickness inspection was made of the shell during a T&I. The followingdeterioration was found and was noted in the Inspection and History Report that wasprepared:

• There is an area of almost uniform corrosion in the bottom shell course. Thethickness readings in this area along the critical plane are: 0.75 in., 0.70 in.,0.68 in., 0.75 in., and 0.73 in. The bottom of the critical plane begins at anelevation of 5 ft. above the bottom of the tank. The thickness readings weremade along a length of 28 in.

• A single deep pit is located in the third shell course and is 4 ft. below the top ofthe course. The pit measures 0.5 in. deep and is approximately 0.5 in. indiameter. There is no general corrosion in the area of the pit.

You must determine if any repairs are required to the tank shell in order to maintain the samedesign liquid fill height. The following additional information is provided:

• It is desired to have a T&I interval of 10 years.

• Hydrotest of the tank is not a factor to consider unless a major repair isrequired.

• Assume that only the stored liquid needs to be considered in this evaluation(i.e., no other loads) and that there will be no change in service.




Solution

Work Aid 1 is used to solve this problem.

• Evaluate the corroded area in the bottom shell course.

Confirm that the distance that was used for the thickness measurements is acceptablefor averaging.

L = 3.7 Dt2D = 100 ft.t2 = 0.68 in.

L = 3.7 100( ) 0.68( )= 30.5 in.

Therefore, the maximum permitted value of L is 30.5 in. Because the measurementswere made along a shell length of 28 in., this measurement length is acceptable.

Determine the minimum average thickness, t1, along the critical plane.

t1 =0.75 + 0.70+ 0.68 + 0.75 + 0.73

5

t1 = 0.722 in.

Determine the allowable stress to use. Because this is the bottom course:

0.8Y = 0.8 x 35 000 = 28 000 psi

0.426T = 0.426 x 60 000 = 25 560 psi

Therefore, S = 25 560 psi

Determine the minimum required thickness at the lowest elevation of the corrodedregion, tmin.

tmin =2.6D H −1( )G

SE




Because the bottom of the critical plane is 5 ft. above the tank bottom, H = (61-5) = 56ft.

tmin =2.6( ) 100( ) 56−1( ) 0.85( )

25 560( ) 0.85( )= 0.56 in.

The t1 value of 0.722 in. is greater than the tmin value of 0.56 in. Therefore, the shellhas adequate thickness in this corroded area today. But what about future corrosion inthe next 10 years until the next T&I?

Corrosion Rate =

0.75− 0.68( )15

= 0.00467 in. /year

CA = 0.00467 x 10 = 0.0467 in.

tmin + CA = 0.56 + 0.0467 = 0.607 in., < t1 = 0.722 in.

0.6 tmin + CA = 0.6 x 0.56 + 0.0467 = 0.383 in., < t2 = 0.68 in.

Therefore, the corroded area in the bottom course is acceptable without repair basedon the desired T&I interval of 10 years. It must also be confirmed that this 10 yearinterval is no more than half the remaining tank life.

Based on the previous results, it is clear that the (tmin + CA) criterion is the governingcase. First calculate the remaining corrosion allowance.

CA/remaining = 0.722 - 0.56 = 0.162 in.

RemainingLife =CA /remaining

CorrosionRate=

0.1620.00467

Remaining Life = 34.7 years

Because the 10 year desired T&I interval is less than half of the remaining life,the 10 year T&I interval is also acceptable based on that criterion.




• Evaluate the deep pit in the third shell course.

Determine the allowable stress to use. Because this is an upper course:

0.88Y = 0.88 x 35 000 = 30 800 psi

0.472T = 0.472 x 60 000 = 28 320 psi

Therefore, S = 28 320 psi

Because the pit is 4 ft. above the bottom of the third course and each course is 8 ft.high, H = (61-2 ¥ 8-4) = 41 ft.

tmin =2.6( ) 100( ) 41− 1( ) 0.85( )

28 320( ) 0.85( )= 0.367 in.

The pitting rate was

0.515

= 0.0333 in. /year

Pitting Allowance = 0.0333 x 10 = 0.333 in.

The remaining shell thickness at the bottom of the pit, tpit, is (0.625 - 0.5) = 0.125 in.

Determine the required thickness at the bottom of the pit.

0.5tmin + Pitting Allowance( ) = 0.5 × 0.367+ 0.333 = 0.5165 in.

Because the required shell thickness, 0.5165 in., is greater than tpit, the pitted area ofthe shell must be repaired. There is no reason to also check the pit using the "halfremaining life" criterion because the pitted area has already failed the first evaluationcriterion. Because there is only one isolated pit, a weld overlay repair is sufficient. Aqualified weld procedure and welder must be used to make this repair.




Situations Involving Shell Penetrations

It may be necessary to do the following on existing shell penetrations:

• Repair existing shell penetrations

• Add new penetrations to an existing tank

• Replace existing penetrations

• Alter existing penetrations

Requirements that are associated with shell penetrations on existing tanks are contained inWork Aid 1. The paragraphs that follow discuss several of these requirements.

New Items or Replacement Items

A new shell penetration (or nozzle) may be required due to a change in tank service, to add anew feature that requires a nozzle, or to replace a deteriorated nozzle. The following areseveral examples of when a new shell penetration is required:

• The tank service may change to one that requires heated storage rather thanambient temperature storage. In this case, nozzles are required to add eitherheaters or steam circulation pipes.

• A hydrostatic tank gauging system may be required. In this case, new nozzlesare required to permit installation of the gauging instruments.

• A nozzle neck may be so badly corroded that installation of a replacementnozzle is more practical than repairing the existing nozzle.

A new or replacement shell penetration will typically be added during a T&I. Penetrationsmay also be added by hot tapping, if they are not flush type connections, as long as therequirements and restrictions on hot tapping that were discussed earlier are met. However,hot tapping shell penetrations should always be considered as a last resort and only if there aresignificant economic incentives to hot tap.

In all cases, new or replacement shell penetrations must either meet API-650 or API-653requirements. This requirement ensures that the new penetration itself meets current integrityrequirements and will not adversely affect the structural integrity of the existing tank shell andassociated shell welds. It is especially important to meet the requirements for minimumdistance between new and existing welds and to meet the nozzle reinforcement requirements.




Alteration of Existing Penetration

An existing shell penetration may require alteration for one of the following reasons:

• It may be necessary to add a reinforcing plate to a penetration that does nothave one already. Reinforcement plate addition may be necessary to resist theimposed hydrostatic loads or piping loads.

• It may be necessary to add a new tank bottom above the existing bottom, andexisting nozzles that are located in the bottom course might need to be raised topermit this addition.

In each case, it is preferable that the modified shell penetrations meet current API-650requirements. These requirements include the minimum reinforcement area and the minimumpermitted spacing between adjacent welds. However, Saudi Aramco’s normal practice is notto mandate that shell penetrations be elevated in order to meet API-650 reinforcement andelevation requirements. Instead, CSD has analyzed each case in order to ensure safe designand operation while at the same time being cost effective.

Figures 9 and 10 show conceptual details for the addition of a new reinforcing plate to anexisting nozzle. In each case, the new reinforcing plate must be split into two pieces in orderto fit over the neck of the existing nozzle, and the plate is then fillet welded to the tank shelland nozzle neck. Each reinforcing plate piece is drilled with a telltale hole that permitspressure testing the reinforcing plate welds.

The detail that is shown in Figure 9 is acceptable as long as the distance between thereinforcing plate weld to the shell and the shell-to-bottom weld does not violate the API-650minimum spacing requirements between adjacent welds. The "tombstone type" reinforcementthat is shown in Figure 10 is required for nozzles where the reinforcement plate weld to theshell would be too close to the shell-to-bottom weld. The "tombstone type" reinforcementplate extends down to the tank bottom (or annular plate) and is welded to both the bottom (orannular plate) and the shell.




Figure 9. Reinforcement Plate Added to Nozzle




Figure 10. "Tombstone Type" Reinforcement Plate Added to Nozzle




It may be necessary to add a new bottom above an existing bottom in cases where the existingbottom has corroded to the extent that repair is not practical. In this case, the new bottom isinstalled approximately 100 mm (4 in.) above the existing bottom. When a new bottom isinstalled in this manner, the spacing between existing welds around penetrations that arelocated in the bottom shell course and the shell-to-bottom weld of the new bottom willprobably not meet API-650 minimum weld spacing requirements. The following threeoptions are possible if the minimum weld spacing requirements are not met:

• The existing reinforcing plate may be trimmed to increase the space betweenthe welds provided that the modified reinforcement plate detail meets API-650requirements. The trimming must be done carefully in order not to damage theshell plate. The attachment weld for the portion of the reinforcement plate thatis removed must also be removed by gouging or grinding.

Most situations cannot be handled in this manner because there will not beenough reinforcement left after the trimming is done.

• The existing reinforcing plate may be completely removed and then a newreinforcing plate can be added. The conceptual details that are used for thisoption are the same as for adding a new reinforcement plate as shown inFigures 9 and 10. Again, the shell plate must not be damaged and the existingreinforcement plate welds must be removed.

This option is acceptable as long as the distance between the nozzle centerlineand the new tank bottom is not less than what is required for an API-650 "Low-Type" nozzle (see Table 3-8 of API-650).

• The last option that may be considered is to relocate the existing nozzle to ahigher position on the shell in order to meet the minimum weld spacingrequirements. This relocation is done by cutting the shell section that containsthe nozzle and its reinforcing plate and raising the entire assembly to thecorrect elevation. Figure 11 illustrates this option.

As previously noted, Saudi Aramco normally analyzes each situation individually in order todetermine the most cost effective approach to use in each case.




Figure 11. Raising Nozzle Assembly




DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR STORAGETANK BOTTOMS

This section discusses the following topics:

• Types of bottom corrosion

• Minimum thickness for the tank bottom plate

• Minimum thickness for the annular plate ring

• Requirements for repairs to the bottom

• Effects of using an internal lining or cathodic protection system

The existing condition of the storage tank bottom is determined by inspections that are madeduring a T&I. The bottom condition is then evaluated using Saudi Aramco and APIrequirements to determine if the bottom is acceptable for continued operation. Work Aid 2contains the procedures and criteria that are used for making these determinations.

Types of Bottom Corrosion

Of all tank components, the bottom is the one that is most likely to suffer corrosion attack tothe extent that significant repairs are required. Corrosion not only affects refinery storagetanks, but corrosion also affects storage tanks that are in production, terminal, pipeline, andmarketing facilities as well. Both internal and external surfaces (i.e., topside and underside)of the tank bottom may be subject to corrosion. Successful, economic repair or control ofbottom corrosion depends first on the determination of what type of corrosion is involved.

External Corrosion

External (i.e., underside) bottom corrosion commonly occurs when moisture is present and acoarse (greater than 19 mm [3/4 in.] size) and poorly meshed aggregate is used in the tankpad. Figure 12 illustrates the corrosive action that may occur around aggregate. There is alow oxygen content at the points of contact between the tank bottom and the aggregate,whereas the adjacent void spaces are relatively oxygen rich. This oxygen difference betweenadjacent locations along the bottom establishes an electrochemical potential and results inpitting-type corrosion, which is known as oxygen concentration cell corrosion.




Figure 12. Oxygen Concentration Cell Corrosion

Water acts as an electrolyte in the process of oxygen concentration cell corrosion. Moisturemay be present on the underside of the bottom plates due to tank settlement, poor tank pitdrainage, and/or deterioration of the ring seal around the tank perimeter. This settlement,poor drainage, or seal deterioration permits rising groundwater or rainwater to reach the tankbottom.

The resistivity of the soil also affects the rate of corrosion because the soil is part of theelectrical circuit. Treated crushed-stone foundations, oiled sand, and compact hot asphaltroad mix have high resistivities and also limit the presence of water on the underside of thetank bottom. However, other foundation pad materials may have low resistivities. Lowresistivities increase the chance for current flow and accelerate the rate of corrosion. Thisoxygen cell pitting corrosion is extremely aggressive and can hole through a tank bottom inonly a few years.




The underside of the bottom plates may also experience corrosion if the tank pad materialscontain chemical contaminants that have highly corrosive sulfur compounds. This situationwould occur if chemical wastes or cinders were previously dumped where the tank is erected.Product that saturates the soil under the tank as a result of previous tank leaks may also causeexternal corrosion. This type of corrosion frequently takes the form of a general metalthinning. The rate of corrosion depends on the corrosivity of the materials that are involved.

Another cause of external tank bottom corrosion is galvanic action. Galvanic action canoccur between double bottoms, between nearby structures and the tank bottom, or betweenactive and noble areas of the same tank bottom. Stray electric currents may also be a sourceof galvanic corrosion, but instances of stray electric current problems are rare.

Internal Corrosion

Internal (i.e., topside) bottom plate corrosion can occur in tanks that store crude oil, distillates,heating oil, heavy residual fuel oils, asphalts, and other corrosive liquids. Corrosive attack onthe bottom plates is typically initiated by water that is entrained in crude oil that contains salts,hydrogen sulfide, and carbon dioxide. As the water settles out of the oil, the water reacts withsulfur compounds and produces an acidic condition. The acidic condition promotes corrosiveattack. Water also can accumulate by condensation from the air, settle down to the bottom,and contribute to bottom plate corrosion. Water is constantly being added to storage tankswith each new batch of oil or product that enters the tank.

Gasoline and other nontreated light products do not normally contain acidic impurities, suchas H2S or CO2; therefore, acid-induced corrosion is not a problem in these cases. However,because of the high solubility of oxygen in these light products, some dissolved oxygen canmigrate to the bottom water layer and induce a small, but overall uniform, corrosion rate ofapproximately 0.025 to 0.05 mm/yr. (1 to 2 mil/yr.). The considerable distance from thevapor space, that is the oxygen supply, to the bottom brine layer limits the oxygenconcentration. The limited oxygen concentration limits the extent of corrosion that can occur.

Pitting-type corrosion may result from concentration cell corrosion that occurs when a surfacedeposit (e.g., mill scale) or a crevice exists on the metal surface and creates an area of lowoxygen concentration. The internal side of tank bottoms usually experiences this corrosiondue to deposited wax or other debris. The accelerated pitting that results may occur at rates of0.5 to 2 mm/yr. (20 to 80 mils/yr.). Sulfate-reducing bacteria may also cause rapid pitting,with the pits exhibiting shiny metal surfaces. Pitting that is caused by sulfate-reducingbacteria is much less common than concentration cell corrosion.

In addition, aggressive galvanic pitting corrosion may be caused by the presence of mill scale,and galvanic "knife edge" corrosion may occur in the vicinity of welds. Galvanic "knifeedge" corrosion can cause severe metal loss, especially if a bottom coating that has beenapplied has failed in the area of the weld.




Minimum Thickness for Tank Bottom Plate

Leaks from the tank bottom are not acceptable because the leaking liquid will proceed directlyinto the foundation and eventually migrate further away from the tank. If these leaks are leftunattended for an extended period of time, the leaking liquid could eventually undermine thefoundation and lead to a more serious bottom failure that results in more severe leakage. Inany case, even small hydrocarbon or chemical leaks result in environmental pollutionconcerns that cannot be ignored. Unfortunately, a tank bottom may have been leaking intothe foundation for a very long time before any visible signs of leakage are detected.

Tank bottoms must be assessed for integrity during a T&I. During this inspection, the entirefloor should be visually examined for holes, cracked welds, and any areas that werepreviously repaired. All floor seams and the bottom-to-shell junction weld should be testedusing a vacuum box to identify leaks that were not apparent during the visual inspection.Ultrasonic thickness measurements should be made over the entire floor on a regular patternto identify thinned areas. Additional readings should be made near any thinned areas that arefound, or other regions where increased corrosion may be expected (such as near the sump orshell), to better define the situation.

As previously discussed and illustrated in Figure 13, bottom plate corrosion may includegeneral corrosion and pitting corrosion. In most cases, general corrosion will occur on thetopside while pitting corrosion may occur on both the topside and underside.




To = Original Plate thickness

Figure 13. Bottom Plate Corrosion

Bottom plate thickness measurements must be made in sufficient quantity and accuracy to beable to assess the current condition of both the topside and underside with respect to generalcorrosion and pitting-type corrosion, and to determine the general corrosion rate and pittingrate. The remaining bottom thickness must be quantified and compared to allowable limitsthat are specified in API-653. The minimum permitted bottom plate thicknesses are not basedon any stress criteria. The minimum permitted thicknesses are intended to provide a safetymargin before "holing through" the bottom, and assume that the bottom is still supporteduniformly. Any condition of nonuniform support or settlement, and its impact on requiredthickness, must be evaluated separately.




Work Aid 2 provides the procedures and requirements to follow when the condition of anexisting tank bottom plate must be evaluated. The paragraphs that follow highlight severalaspects of bottom evaluation.

Bottom Thickness Calculation

API-653 permits two alternative methods for quantifying the remaining thickness of a tankbottom: the deterministic method and the probabilistic method.

Deterministic Method - The deterministic method requires that the remaining bottomthickness, as calculated by two different equations, be at least equal to the minimum thicknessthat is required by API-653. Both equations consider the original bottom plate thickness,general corrosion, topside and underside pitting (average and maximum), corrosion rate, andpitting rate. In each case, the equation starts with the original plate thickness, subtractsthinning that has occurred already, subtracts further thinning that is expected to occur until thenext T&I, and arrives at a remaining bottom plate thickness.

The difference between the two equations is that in one, the average depth of internal pittingis combined with the maximum depth of underside pitting. The second equation combines themaximum depth of internal pitting with the average depth of underside pitting. Thus there is atacit assumption that the location of the deepest internal pit will never coincide with thelocation of the deepest underside pit. This separation between the two deepest pits cannot beguaranteed, but it is a reasonable assumption to use for overall evaluation purposes. WorkAid 2 is based on this evaluation approach.

API-653 does not specify the inspection procedures that must be used, nor their extent, todetermine the values that are needed to solve these equations. The inspection details are leftup to the owner.

Probabilistic Method - The probabilistic method is a statistical analysis of the thickness datathat are obtained from inspection measurements. The objective of this method is to predictthe remaining minimum thickness of the bottom based only on sample scanningmeasurements, not extensive measurements, and then to determine whether the minimumthickness will be less than the API-653 minimum acceptable value. The intent of thisapproach is to reduce the amount of inspection time that is needed, and to predict the worstpossible condition in the bottom on a statistical basis with a reasonable degree of confidence.Here again, API-653 does not specify the details that are required to apply this method.

One negative aspect to the probabilistic method is that if it predicts that the tank bottom is toothin, it does not locate where the thinnest areas are. Thus, if a problem is predicted, a moreextensive inspection of the tank bottom is still required to develop specific repairrequirements.




Overall Evaluation Considerations

As previously stated, API-653 does not specify the extent of inspection that is needed tosatisfy the evaluation requirements nor the inspection procedures that must be followed. Thetank owner must develop the specific procedure and data collection details that he feels aresufficient to satisfy API-653 requirements. There are conflicting aspects to thisdetermination.

Sufficient measurements must be made to quantify the maximum pitting and generalcorrosion that has taken place and to develop reasonable average values. This requirementtends toward increasing the extent of inspection that is done in order to maximize confidencein the data that is collected and the evaluations that are made. However, the time and cost thatare associated with the inspection increase as the extent of the inspection increases. Abalance must be made that provides sufficient confidence in having defined the actualcondition of the bottom without being excessive in terms of inspection time and cost.

The approach to bottom inspection often involves an initial screening inspection to assess theoverall condition of the bottom. The initial screening usually includes visual, ultrasonic, pitgauge, and Magnetic Flux Exclusion (MFE) measurements. More detailed follow-upinspections are then made, as required, based on the initial inspection results. The followingoutlines some items that must be considered:

• How will the maximum and average depth of underside pitting be determined,inasmuch as the underside is not visible?

- A 100% ultrasonic thickness survey of the bottom is time consuming,expensive, and still may not identify highly localized areas of deepunderside pits.

- Statistical analysis approaches have been developed that will predict themost likely depth of the deepest pit based on a relatively small numberof thickness measurement data points. This is an example of theprobabilistic method.

- Sections of floor plate can be cut out to locally examine the undersidecondition, but this is a hit or miss approach.

- A Magnetic Flux Exclusion floor scanner may be used to detectcorrosion or pitting from either the topside or underside of the plate.The scanner is set at a certain thickness threshold level, and the entiretank floor is scanned.




The scanner qualitatively locates areas that are thinner than thethickness threshold level setting, and follow-up ultrasonic thicknessmeasurements are then made to quantify the actual thicknesses. Thekey to this approach is that the thickness threshold level must be set sothat significant corrosion and pitting are located without making anextraordinarily large number of actual thickness measurements.

• How many measurements are necessary to determine the average amount ofgeneral corrosion and internal pitting? Will measurements be made in eachplate or in randomly selected areas throughout the bottom?

• Will the tank be divided into sections, or even individual plates, for evaluationpurposes, or will the bottom be evaluated as a whole? The extent to which thebottom is divided will probably be determined based on whether there areclearly visible areas of severe internal corrosion or pitting. Severe internalcorrosion or pitting might occur in areas near a center sump, or near the tankperiphery where sludge or sediment might accumulate.

• Does the tank have an internal lining and/or cathodic protection systeminstalled? If not, would installation of one and/or the other affect the need forbottom repair? Note that installation of these features affects the futurecorrosion and pitting of the bottom, not what has already occurred.

• What is the extent of repair that is needed to make the bottom acceptable? Forexample, would repair of several very localized areas of corrosion make thebottom acceptable?

Minimum Thickness for Annular Plate Ring

As discussed in MEX 203.03, butt-welded annular plates are required for particular situationsbased on local load and stress distribution considerations. Examples of where annular platesare used include the following:

• Large diameter tanks• Large settlement situations• Earthquake design considerations

The annular plate is required for local load distribution, and the stress distribution in thisregion of the tank is relatively complex. Therefore, API-653 thickness acceptance criteria aremore conservative for an annular plate than they are for the rest of the tank bottom. Theminimum thickness criteria for annular plates are based on the following factors:




• Product specific gravity

- If the product specific gravity is less than 1.0 and the annular plate wasnot required for seismic considerations, its minimum acceptablethickness is the value that is specified by Table 2-2 of API-653 pluscorrosion allowance. The minimum acceptable annular plate thicknessspecified by Table 2-2 is based on the thickness and stress in the firstshell course.

- If the product specific gravity is 1.0 or greater, the minimum acceptableannular plate thickness is the value that is specified in Table 3-1 of API-650, plus corrosion allowance.

• Seismic considerations. If the annular plate was needed due to seismicconsiderations, a new seismic analysis must be performed based on the actualannular plate thickness that is measured.

If the thickness acceptance criteria are not met, API-653 permits performance of a detailedstress analysis in an attempt to confirm the acceptability of a thinner annular plate for thespecific tank. Such an analysis would be based on the ASME Code Section VIII, Division 2.A Division 2 stress analysis requires calculation of the specific stress types (e.g., membrane,bending, local, general) and has acceptance criteria based on the type of stress. The analysismust consider the extent and location of the corrosion, the degree of foundation support, andthe applied loads. A Division 2 analysis might be advantageous if the API-653 acceptancecriteria would require extensive annular plate replacement.




Requirements for Repairs to Bottom

Bottom plate repair or replacement must be done if the condition of the bottom does not meetthe API-653 acceptance criteria. The following sections discuss the available options.

Repair of a Portion of Tank Bottom

Tank bottom repair may consist of one or more of the following options:

• Weld overlay repair of internally corroded or pitted areas.

• Lap-welded patch plates over corroded or pitted areas.

• Removal of bottom plate sections and replacement by new lap-welded bottomplates.

• Weld repairs to cracked bottom plate lap welds or shell-to-bottom fillet weld.The root cause of weld cracks should be determined so that appropriatecorrective action can be taken.

The specific approach that is used depends on the extent of the deterioration as well as on costand time.

Installation of an internal lining or cathodic protection system are other options that may beconsidered if general corrosion or pitting corrosion is excessive. However, these optionsaddress the entire bottom rather than just a portion of it, and are actually bottomenhancements rather than repairs. These two options will be discussed in a later section ofthis module.

Any cracks or leaks that are found in bottom plate lap welds or in the shell-to-bottom filletweld must be weld repaired. The cause of such cracks should be determined and corrected sothat the cracks do not recur. Weld cracks in these areas are typically caused by settlement,original weld defects, or undersized welds.

Repairs to corroded and pitted areas of the bottom plate are made using either weld overlay orlap-welded patch plates. The choice between these two options is based on the depth and sizeof the areas that are to be repaired. Weld overlay is used for relatively small and scatteredcorroded or pitted areas, and patch plates are used for larger areas.




Bottom plate repairs are required only to the extent that is necessary to satisfy the API-653minimum thickness requirements, as described in Work Aid 2. Parameters that form part ofthe bottom plate thickness evaluation include:

• Maximum and average internal and external pit depths

• Average general internal corrosion

If the initial evaluation finds that the existing bottom plate thickness is unacceptable, aniterative approach may be used to determine the extent of repairs that are required based ontheir effect on the evaluation parameters. For example:

• If internal pitting is a problem, assume a maximum pit depth that would beallowed to remain after repairs are made (i.e., assume all pits that are deeperthan this value would be repaired). Then recalculate the minimum remainingthicknesses using the new maximum and average internal pit depths based onthe "after repair" dimensions. The internal pitting rate would still be based onthe maximum pit depth that occurred, not the maximum pit depth that remainsafter repair, unless an internal lining is installed to prevent future pitting.

• If general internal corrosion is a problem, determine how much new plate mustbe added to decrease the average internal corrosion enough for the remainingthickness to be acceptable.

API-653 defines the critical zone of a tank bottom as within the annular plate ring, within 300mm (12 in.) of the shell, or within 300 mm (12 in.) of the inside edge of the annular plate ring.This region of the bottom is considered to be critical because the stresses that occur there arecomplex in nature. These complex stresses are due to both bending of the tank shell causedby the hydrostatic head and differential shell and/or bottom settlement. Because this area iscritical, no welding, welded-on patch plates, or weld overlays are allowed within the criticalzone except for welding of the following:

• Widely scattered pits• Cracks in bottom plates• Shell-to-bottom weld• Welding that is required to replace complete sections of the bottom or annular

plate

If more extensive repairs are required within the critical zone, the bottom plate or annularplate under the bottom shell course must be cut out and a new plate must be installed. Thisplate replacement has less detrimental impact on the local stress distribution than if repairs aredone by localized weld repair or by the patch plate.




As previously noted, a stress analysis may be used in an attempt to demonstrate that a locallycorroded area of the bottom plate or annular plate near the shell is acceptable without repair.Stress analysis may be considered as an option if extensive bottom plate replacement orannular ring replacement would otherwise be required.

When it is necessary to weld a new annular plate or bottom plate to an existing shell plate ofunknown fracture toughness, increased attention must be paid to the weld procedures andinspection procedures that are used. The weld details and weld procedures must minimize therisk of brittle fracture.

The following should be considered to help minimize the risk of brittle fracture:

• Use an elongated fillet weld shape (illustrated in Figure 14) to reduce the localstress intensification.

Fillet welds are normally shaped such that their leg lengths are equal. A filletweld that has one leg longer than the other leg (e.g., 2:1 or 3:1) has a lowerstress intensification factor, and thus a lower local stress, than an equal-legfillet weld. A brittle fracture will normally initiate at a stress intensificationpoint. Reducing the local stress reduces the brittle fracture risk.

• Use a temper-bead weld technique (illustrated in Figure 15) to provide somedegree of local stress relief and improved ductility. In this weld technique,weld metal is applied in overlapping beads and in a specific sequence. Theapplication sequence ensures that any weld bead that contacts the tank shell ispartially covered by another weld bead and provides stress relief and improvedductility in the weld-to-shell fusion zone. Improving the material properties inthis manner decreases the risk of brittle fracture.

• Perform careful inspection and testing of the initial and final welds (e.g., MTand vacuum box leak test) to help ensure higher weld quality. A brittle fracturecan initiate at a weld defect.




Figure 14. Elongated Fillet Weld

Figure 15. Temper-Bead Welding

Use of a combination of repair or bottom replacement options is commonly required to solvea remaining thickness problem. If the extent of required repairs becomes too large, acompletely new bottom must be installed. The bottom repair versus replacement decision ismade on an individual basis based on cost comparisons and schedule considerations.




Replacement of Entire Bottom

An entire tank bottom may require replacement if corrosion is so extensive that the bottomcannot be repaired economically. A second bottom may also be required if a tank is beingmodified in order to add secondary containment and leak detection capability. The followingsummarizes API-653 requirements and additional information for installing a replacementbottom over an existing bottom.

• Any voids in the foundation that are below the old bottom must be filled withmaterial such as sand, grout, concrete or crushed limestone. The old bottomwill still provide weight support for the tank and its contents, and the oldbottom must be supported by the underlying tank foundation.

• A cushion of noncorrosive material such as sand, crushed stone, gravel, orconcrete must be used between the old and new bottoms (illustrated in Figure16). This cushion will typically be 75-100 mm (3 - 4 in.) thick. An oiled sandmixture is often used for this purpose to reduce the likelihood of undersidecorrosion. This cushion provides uniform support of the new bottom andtransmits the applied weight loads to the original bottom and underlyingfoundation pad.

• A uniform slot is cut in the shell parallel to the tank bottom as shown in Figure16. The cut edges of the shell are to be ground, and the new bottom or annularring plates are passed through this slot and outside the shell. The new platesare then welded to the bottom shell course. All dimensional, welding details,and weld spacing requirements must meet API-650 requirements.

From a practical standpoint, the complete slot cannot be made around the entireshell at once. The shell will typically be cut such that uniformly spaced,relatively short sections of the shell remain uncut to provide support for theupper shell. The remaining uncut shell sections are cut after adjacent newbottom sections are installed.




Figure 16. Slotted Shell for New Bottom Installation




• The potential for galvanic corrosion should be addressed by removing the oldtank bottom or by the installation of a cathodic protection system (noted inFigure 16). If the old bottom is left in place, install a liner on it prior toinstalling the fill material in order to prevent galvanic coupling between the twobottoms.

In situations where a new bottom must be installed, it may be worthwhile toalso consider the installation of a secondary containment and leak detectionsystem as well. In addition to detecting and containing any bottom leaks thatmight occur, such a system provides another advantage. API-653 permits thebottom plate to corrode to a thickness of 1.25 mm (0.05 in.), rather than thenormal 2.5 mm (0.1 in.), when a secondary containment and leak detectionsystem is installed.

• Existing shell penetrations might have to be raised if the elevation of the newbottom cuts through their reinforcing plates (which will often be the case) or ifthe minimum weld space requirements of API-653 are not met. Raisingexisting shell penetrations because of a new bottom installation was previouslydiscussed.

• If the tank has a floating roof, the new bottom profile must keep the roof levelwhen it is resting on its support legs in the down position. This requirement isidentical to what is required for a new tank.

• New bearing plates for floating roof support legs and for fixed roof supportcolumns must be installed. Again, this requirement is no different from therequirements for a new tank.

Effects of Use of Internal Lining or Cathodic Protection Systems

Installation of an internal lining or cathodic protection (CP) system may be used as a means tolessen future corrosion problems in an existing storage tank. A lining or CP system may beinstalled as part of the original installation of a new storage tank or as part of a maintenanceprogram when excessive corrosion is found in an existing tank.

A properly designed, installed, and maintained internal lining will prevent any future internalcorrosion or pitting. Therefore, when calculating the minimum remaining bottom platethicknesses in an API-653 evaluation, the internal corrosion rate and pitting rate parameterswill be zero. Eliminating future corrosion or pitting in this manner reduces the extent ofrepairs that are required to make the bottom acceptable.

A properly designed, installed, and maintained cathodic protection system prevents any futureunderside pitting of the bottom when this pitting was caused by galvanic action. Therefore,when calculating the minimum remaining bottom plate thicknesses in an API-653 evaluation,the underside pitting rate will be zero. Here again, eliminating underside pitting in thismanner reduces the extent of repairs that are required to make the bottom acceptable.




The sections that follow briefly discuss internal linings and cathodic protection systems.




Internal Lining

A glass-reinforced plastic (GRP) lining is the type that is most commonly used to protect tankbottoms from internal corrosion. A GRP lining is an effective and economical method forreinforcing and corrosion-proofing new and deteriorated tank bottoms. This versatile repairmethod is adaptable to both welded and riveted construction, and it offers importantadvantages over in-kind replacement of corroded steel. These advantages include:

• Greater ease and speed of installation• Superior corrosion resistance• Elimination of hot work (i.e., no welding is required)• Generally lower cost

These factors, coupled with the ruggedness and durability of a GRP lining, make this methodan acceptable tank bottom repair and enhancement technique.

GRP lining involves the application of either a glass-reinforced epoxy resin or glass-reinforced polyester resin directly over the existing bottom. The term GRP is sometimes usedinterchangeably with FRP (fiber reinforced plastic). The reinforcement or filler material maybe any one of the following:

• Fiberglas cloth, which is woven material or fabric

• Fiberglas mat, which is similar to cloth, but made from fibers that aredistributed randomly, rather than woven

• Chopped roving, which is bunches of rope-like strands

• Glass flakes

Refurbishing a tank bottom by the installation of a GRP lining is the most practical alternativeto installation of new steel bottoms when significant internal corrosion or pitting is a problem.This alternative should be considered when a tank bottom has corroded and/or pitted to thepoint where its minimum remaining thickness is at the API-653 limit, or will reach that limitbefore the next T&I, and internal corrosion or internal pitting is a major factor that has causedthat bottom deterioration.




While a GRP lining is an attractive bottom repair option, it is not appropriate under thefollowing circumstances:

• GRP linings are not suitable in situations where serious structural weakeningdue to general corrosion loss has damaged the mechanical integrity of the tankbottom. Although properly designed and installed GRP linings can havesufficient structural integrity to "bridge" relatively large diameter holes (50 mm[2 in.] to 125 mm[5 in.] in diameter), GRP linings cannot be expected to replace the steel tankbottom.

• GRP linings must not be used for heated tankage that requires elevated storagetemperatures. The maximum permissible storage temperature limits for liningsthat utilize conventional polyesters and epoxies are 60°C (140°F) and 82°C(180°F), respectively. Asphalt and heavy fuel oil storage tanks normallyrequire storage temperatures that exceed the safe limits of GRP linings.

• GRP linings cannot be used in applications where the linings may be subject toconcentrated chemical attack by strong acids or aromatic solvents. However,the application of a suitable gel coating over the lining would protect the GRPlining as long as the gel coating that is used is resistant to attack by the storedliquid. In most conventional refinery tankage where only trace amounts ofacids or aromatic solvents are present, a GRP lining will exhibit goodresistance and may be used.

• GRP lining applications and repairs should only be undertaken if a qualifiedcontractor with demonstrated experience and expertise in GRP liningtechnology is available.

• GRP linings must not be used without first installing new steel reinforcingplates in critical locations on the tank bottom, such as the bearing plates locateddirectly below roof support legs. In addition, patch plates must be installed torepair large holes prior to installing a GRP lining. If a large number of patchplates is required, installation of a new bottom may become more economicalthan GRP lining repairs. In general, holes that are greater than 25 mm (1 in.) indiameter or areas with clusters of smaller holes should be repaired with 6.35mm (1/4 in.) thick steel patch plates prior to installing the lining.

• While GRP linings are useful for tank bottom repairs, the linings are notsuitable to deter soil-side corrosion. If aggressive soil-side corrosion is aproblem, a cathodic protection system should be installed to supplement thelining.

SAES-H-101, Aramco Paints and Coatings Systems, provides specifications for acceptablecoating systems, as well as installation and inspection requirements for these coatings.




Cathodic Protection System

Cathodic protection is a technique that is used to reduce electrochemical corrosion. The goalof a cathodic protection (CP) system is to force sufficient electric current onto a structure tohalt or reverse any discharge of corrosion current from the structure. CP systems foraboveground storage tanks are installed to protect the sketch plate or annular plate and thebottom from soil-side corrosion. These CP systems are generally effective and are relativelylow in cost when compared to tank bottom repair or replacement. CP should be consideredwhen a tank bottom has corroded to the point where its minimum remaining thickness is at theAPI-653 limit, or will reach that limit before the next T&I, and external corrosion or pitting isa major factor.

Design and installation of CP systems is complex and should follow the requirements that arespecified in SAES-X-500, Cathodic Protection Tank and Vessel Internals, and SAES-X-600,Cathodic Protection In-Plant Facilities. Although the design and installation of CP systemswill be contracted to outside firms, some knowledge of CP is required to evaluate proposeddesigns and assure correct maintenance. The two most common causes for failed CP systemsare poor electric current distribution (which relates to system design), and lack of propermaintenance.

There are two types of CP systems: sacrificial anode and impressed current. The followingmaterial briefly discusses these two types. When either of the two types are installed ondouble-bottom tanks or tanks that have impermeable plastic membranes, specialconsiderations are involved. Double bottoms or impermeable membranes will shield theprotective current from the tank bottom that is to be protected, and CP will not be provided.

Sacrificial Anode - Sacrificial anode systems are based on the electrical potential differencebetween two dissimilar metals when exposed in soil or water. When the two metals areelectrically connected, the more anodic material is allowed to corrode or is "sacrificed," andthe protective electric current flows to the more cathodic material (structure to be protected).

Sacrificial anode systems are usually less costly for smaller diameter tanks and have lowermaintenance needs than impressed current systems. However, the electric current availabilityof sacrificial anode systems is limited by the electrical potential difference that naturallyoccurs between the tank bottom metal and the sacrificial anode material. Sacrificial anodesare generally alloy metals of magnesium, zinc, or aluminum that limit the electrical potentialdifference to between 0.5 and 1.0 volt for carbon steel tank bottoms.

Placement of the sacrificial anodes near the tank is critical to electric current distribution andcorrosion protection. The anodes should be geometrically placed around the tank that is to beprotected. An example of such an arrangement is shown in Figure 17. As a rule, sacrificialanode systems do not produce sufficient corrosion protection for tanks that are larger than 10m (30 ft.) in diameter.




Figure 17. Typical Sacrificial Anode System




Impressed Current - An impressed current system uses an external DC power source,usually a rectifier, to artificially impress anodes with electric current that then flows to thetank bottom. An impressed current system has the advantages of being able to produce thelarge driving electrical potential and high electric current output that are needed tosatisfactorily protect large diameter tank bottoms. Electric current can also be increased ordecreased as any variation in need occurs. Impressed current systems generally require ahigher capital investment and maintenance level than sacrificial anode systems for smalltanks, but cost less for larger tanks. Several different designs of impressed current systemsare possible. The particular design that is selected often depends on the soil profile and thesurrounding structures.

Impressed current anode materials range from scrap iron to impregnated graphite, platinizedtitanium, niobium, and tantalum. These materials vary in cost and expected design life.Anode material selection often depends upon what material is best suited for the soil andwater conditions in which they will be buried.

SAES-X-600 requires that aboveground storage tanks be protected with a distributed,impressed current anode system in accordance with Saudi Aramco Standard Drawing AA-036355.SAES-X-600 requires that the anodes be no more the 20 m (60 ft.) apart center-to-center, andthat the anodes be between 5 m (15 ft.) and 10 m (30 ft.) from the tank wall. SAES-X-600also requires that tanks that are 10 m (30 ft.) in diameter and greater have reference electrodesburied under their bottom plates. The required number and location of the referenceelectrodes are specified based on tank diameter. Figure 18 is an outline drawing of a typicaldistributed impressed current system.




Figure 18. Typical Impressed Current System




Sample Problem 2: Evaluating Tank Bottom Remaining Thickness

Bottom plate thickness measurements have been made during the T&I of a 100 ft. diameterfixed roof tank. The results of these measurements and other data, as documented in theInspection and History Report and the tank files, are as follows:

• The original bottom thickness was 0.35 in.

• There is no internal lining installed.

• There is no cathodic protection system installed.

• The tank is 10 years old and has been in the same service for the entire time.

• The next planned T&I is in 10 years.

• The average depth of all internal pitting is 0.0035 in.

• There are four deep internal pits in the tank bottom. There are also a largenumber of shallower pits scattered throughout the tank bottom. All the deeppits are outside the critical zone of the bottom. The data on the pits are asfollows:

- One pit near the center of the tank has a depth of 0.202 in.

- One pit approximately 20 ft. North of the center of the tank has a depthof 0.119 in.

- One pit approximately 30 ft. Southwest of the center of the tank has adepth of 0.096 in.

- One pit approximately 26 ft. Southeast of the center of the tank has adepth of 0.102 in.

- The deepest of the other pits is 0.089 in.

- If the four deepest pits were all repaired, the average depth of internalpitting that will remain is 0.0024 in.

• The average depth of external pitting is 0.0017 in.

• The depth of the deepest external pit is 0.004 in.

• The average depth of general corrosion is 0.043 in.

• The maximum depth of general corrosion is 0.05 in.




Evaluate the inspection data for the bottom and determine if any repairs are required. Ifrepairs are required, determine what should be done.

Solution


The following data are available from the given information:

GCa = 0.043 in. StPa = 0.0035 in.

StPm = 0.202 in. UPa = 0.0017 in.

UPm = 0.004 in. GCm = 0.05 in.

Or = 10 years N = 10 years

To = 0.35 in.

Calculate the pitting rate and corrosion rate from the data.

StPr = StPmN

= 0.20210

= 0.0202 in. /yr.

UPr =UPm

N=

0.00410

= 0.0004 in./ yr.

GCr =GCm

N=

0.0510

= 0.005 in. /yr.

Determine the minimum bottom thicknesses, MRT1 and MRT2.

MRT1 = To - GCa - StPa - UPm - (StPr + UPr + GCr)Or

MRT1 = 0.350 − 0.043 − 0.0035 − 0.004 − 0.0202 + 0.0004 + 0.005( ) 10( )= 0.0435 in.

MRT2 = To − GCa − StPm − UPa − StPr + UPr + GCr( )Or

MRT2 = 0.350 − 0.043 − 0.202 − 0.0017 − 0.0202 + 0.0004 + 0.005( ) 10( )= −0.1527 in.




Because both MRT1 and MRT2 are well under the acceptable value of 0.1 in., bottom platerepairs are required.

In examining the calculations, the two biggest factors that influence the MRT calculations arethe maximum depth of internal pitting and the influence of the maximum internal pitting rate.If an internal lining is installed, both StPr and GCr would be zero. Determine if installing aninternal lining is enough without other repairs.

MRT1 = 0.350 - 0.043 - 0.0035 - 0.004 - (0 + 0.0004 + 0)10

MRT1 = 0.2955 in.

MRT2 = 0.350 − 0.043 − 0.202 − 0.0017 − 0 + 0.0004 + 0( ) 10( )= 0.0993 in.

Because MRT2 is still less than 0.1 in., additional repairs are required, Assume that the fourdeepest pits are also repaired by weld overlay. Therefore:

StPm = 0.089 in.

StPa = 0.0024 in.

Recalculate the value of MRT2 with these new values.

MRT2 = 0.350 − 0.043 − 0.089 − 0.0017 − 0 + 0.0004 + 0( ) 10( )= 0.2123 in.

MRT2 is now acceptable. Because MRT1 was already acceptable in the prior calculation andthe pit repair reduces the average internal pit depth that remains, MRT1 does not have to berecalculated.

In summary, the four deepest pits in the tank bottom should be repaired by weld overlay, andan internal lining should be installed, in order to make the bottom acceptable.




DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR THE ROOFSOF FIXED ROOF AND FLOATING ROOF STORAGE TANKS

This section discusses the following topics:

• Criteria for the evaluation of fixed and floating roofs

• Repair requirements for fixed and floating roofs

• Criteria for repair or replacement of floating roof seals

Criteria for Roof Evaluation

Deteriorated tank roofs and deteriorated floating roof seals can affect air quality by permittinghydrocarbon leakage from the tank. These deteriorated conditions can also decrease overalltank safety by making the tank more prone to a fire that is caused by a lightening strike. Ifdeterioration is allowed to progress to an extreme state, the roof could experience a significantstructural failure that is caused by the applied loads. Work Aid 3 provides procedures thatmay be used to evaluate the condition of existing tank roofs. The paragraphs that followprovide additional background information and guidance.

The primary factor that must be considered in all tank roof evaluations is corrosion. Thecondition of the perimeter seal must also be considered for floating roofs.

External corrosion on roof surfaces is usually most severe at depressions in the roof wherewater can collect. If the tank stores hydrocarbons that produce corrosive vapors, corrosionwill also tend to be severe near roof openings where the corrosive vapor can flow out of thetank (e.g., at holes, pressure vents, and floating-roof seals).

Inspection for corrosion on the outside of a roof is similar to inspection for corrosion on theoutside of the tank shell. However, additional safety precautions are required to ensure thatinspection personnel are not injured while working around deteriorated areas of the roof. Forexample, the following safety precautions should be followed:

• It may be necessary to place support members across rafters if the roof plate isbadly corroded. In this manner, inspection personnel do not need to stepdirectly on severely corroded roof plates.

• Gas tests should be made before inspection is begun, especially for floatingroofs. Respirators should be worn or be readily available, depending on thetest results.

• One man should remain off the roof as a safety watch to get help, if needed.




Fixed Roofs

Corrosion is the principal cause of deterioration of fixed roofs. Tanks that store "sour" crudesare especially vulnerable to internal corrosion on the underside of the roof. Tanks that arelocated in humid climates and industrial areas may experience rapid external roof corrosion.Corrosion of fixed roofs is generally due to three phenomena:

• Internal corrosion from condensed vapor

• External corrosion from atmospheric conditions

• External corrosion under insulation

Regular inspections can also avert or minimize problems with corroded or distorted supportcolumns, rafters, girders, plugged pressure-vacuum vents, and defective welds.

Causes and Rates of Internal Corrosion - Corrosion on the underside of fixed roofs resultsfrom the condensation of vapors that are contained in the tank. This type of attack can appearas general corrosion or pitting corrosion. Internal roof corrosion has only been observed intanks that store "sour" crudes or distillates that contain free H2S. The corrosivity on theunderside of a tank roof is generally low in the absence of both air and H2S in the vaporspace. However, internal roof corrosion becomes considerable when both H2S and air arepresent in the vapor.

The roofs of tanks in "sour" crude service can have a life of about 2 to 12 years before smallholes may develop from internal corrosion. The long-term corrosion rates correspond toabout 0.5 to3 mm/yr. (20 - 120 mils/yr.). The corrosion rate is not necessarily a function of the totalsulfur content in the crude, but rather of the concentration of free H2S in the crude oil ordistillate. Cases have been reported where severe vapor space corrosion occurred in tankswith crude oils having a total sulfur content as low as from 0.02% to 3.0%.

Causes and Rates of External Corrosion - Atmospheric corrosion is common on fixed roofsbut is generally not severe. Tanks that are located near marine environments mightexperience substantial metal loss due to atmospheric corrosion caused by chlorides that arenaturally present in their environment.

Corrosion under insulation that is installed on tank roofs presents a more serious problembecause metal loss can be very rapid and severe. Unfortunately, corrosion under insulationcannot be detected by visual examination or by nondestructive testing methods withoutremoving insulation. This type of corrosion depends on the penetration of water or watervapor into the insulation system, and subsequent retention of the water in the insulation. Allcommon types of insulation, including mineral wool, glass fiber silicates, foam glass block,polyurethane foam, and phenolic foam block, have been involved in such corrosion.




Tank design details can aggravate the problem of corrosion under insulation. As an example,in one roof insulation system design (illustrated in Figure 19) the shell-to-roof junctionincluded a75 mm (3 in.) vertical rim around the junction. This rim retained rainwater that passedthrough the aluminum weather jacketing and resulted in severe roof corrosion.

Figure 19. Poor Roof Insulation Detail

Another prime cause of corrosion is poor maintenance of roof insulation systems. Theorganic materials that are used to caulk metal jackets dry out and crack with age. The crackedcaulk permits water ingress if the caulk is not maintained. In addition, metal jackets may notbe sealed properly at openings into the tank when the jacket is installed. Solar radiation canalso degrade the weather barrier or vapor barrier and make the barrier less able to prevent theentry of water underneath.




Thickness Measurements - When the tank is in-service, visual checks should be made forexternal corrosion of the roof plates. If the tank is insulated, the condition of the insulationshould be checked to the extent possible and include the following areas:

• Condition of seal and/or adhesion of insulation at the tank roof• Condition of seal around vents or other openings• Indications of ultraviolet degradation of the jacket

If rainwater penetration of the insulation is suspected, it may be advisable to remove smallportions of the insulation for further investigation of its condition and that of the roof platesunderneath. Atmospherically degraded insulation should be removed to minimize firehazards, as well as the potential for severe corrosion of the roof. Degraded insulation canbecome a considerable fire hazard for tanks that store low-flash-point products.

Visual in-service checks for corrosion should be supplemented by ultrasonic thickness checksof the roof plate. Specific experience will dictate the number and location of roof thicknessmeasurement points.

When the tank is out-of-service, detailed external and internal visual inspections will indicateif there are any areas of significant corrosion that require closer investigation. If internalscaffolding will not be used, it may be necessary to cut inspection openings in the roof platesin order to inspect the roof support structure.

Evaluation of Fixed Roof Corrosion - Work Aid 3 contains a procedure that may be used toevaluate corrosion in fixed roofs. If significant corrosion has occurred in roof supportstructural members, stress calculations must be made to confirm that the support structure stillmeets API-650 allowable stress limits.

Floating Roofs

Causes and Rates of Corrosion - Inasmuch as the roof of a floating roof tank rests on theliquid that is stored in the tank, underside corrosion of the roof is usually slight. Metal loss atcorrosion rates of 0.3 mm/yr. (12 mils/yr.) or less are typical on the underside of floating roofsthat are in gasoline blending, light naphtha, and virgin naphtha services, especially onpontoon rim plates that extend to the liquid level. Use of mechanical mixers or jet mixers insuch cases increases the liquid circulation velocity and can accelerate corrosion of the steelthat is in contact with the liquid. In isolated cases, severe corrosion has occurred on theunderside of the roof plate lap joints where moisture and other corrodants can accumulate inthe crevices that are formed by the lap joints.




Atmospheric corrosion on the topside of external floating roofs is common because therelatively horizontal roof surface tends to collect particulate contamination from the air, andthe rainwater run-off is too slow to effectively remove the contamination. Depressions orirregularities in the roof surface will retain moisture, and then the moisture can penetrate anycoating that is installed on the roof (e.g., paint) and establish corrosion cells. As the moisturefinally evaporates, its mineral content is left on the roof to further contaminate the surface.Scale and rust that is scraped from the shell inside surface during roof movement andsubsequently deposited on the roof may also contribute to the corrosion process.

For tanks that are located in marine environments or in locations that use recirculating saltwater cooling towers, rapid atmospheric corrosion of tank roofs can occur. In most otherareas, however, external corrosion of floating roofs is not severe.

Inspection for Roof Corrosion - Visual in-service checks will locate areas of especiallysevere corrosion, such as at depressions in the roof surface, areas around roof support sleeves,near roof drains and vents, and similar locations where water can accumulate. Badly corrodedareas of the roof should be examined for evidence of leaks. The condition of the paint on theroof will provide a good indication of any potential roof corrosion problem. Tank roofsgenerally require more frequent repainting than tank shells because weathering of the paintsystem is more severe on the roof due to its exposure to sunlight and the presence of pools ofwater.

When the tank is out-of-service, the underside of the roof should be checked for corrosion.Ultrasonic thickness measurements should then be made to determine the rate of corrosion.The external face of the pontoon in the region of the liquid level should be inspected forgrooving, pitting, and corrosion because this area is prone to corrosion due to the liquid-vaporinterface. The interior of the pontoons on double deck roofs is another location that should beinspected for corrosion.

Recommended retirement thicknesses for floating roof deck plates and pontoons are dictatedby structural requirements. Work Aid 3 contains a procedure that may be used to evaluatecorrosion in floating roofs.

Pontoon rim thickness requirements are generally governed by buckling stability or stressconsiderations based on the design rainwater load. These considerations are a function oftank diameter. If corrosion significantly reduces the rim thickness, a buckling and stressanalysis may be required, and CSD should be contacted.




Repair Requirements for Fixed Roofs

The primary concern with roof plate thinning is to ensure that there is still adequate vaportightness and structural load bearing capability for both environmental loads (e.g., rainwater)and maintenance loads. Corrosion and holing through of roof plates increase the risk ofexplosions and fire due to direct lightning strikes on the roof. Roof plate buckling can cause"ponding" of rainwater. This ponding can cause tank roof collapse from excessive amountsof rainwater and locally high corrosion.

Excessively thin, holed through, or buckled areas of the roof plate are typically repaired bylap-welded patch plates. Depending on the extent of the deteriorated area, these patch platesmay be welded over the existing roof plates, or the existing roof plates may be removed andreplaced by new plates. Repairs or alterations to the roof support system must meet API-653requirements.

Roof plate welds that have corroded excessively or are cracked are repaired by rewelding.Special attention should be paid to any repairs that are made in the area of the roof-to-shelljunction. If a frangible joint is required, any repairs that are made must ensure that thefrangible joint requirements are still met. Specifically, too large a repair weld violates thefrangible joint requirements.

If significant deterioration has occurred within an unexpectedly short period of time, the rootcause should be determined before the repair requirements are finalized. For example:

• If severe roof underside or support corrosion occurred, should the replacementplates and structural members be made thicker?

• If severe topside corrosion occurred, was this corrosion due to inadequateinspection and maintenance procedures?

• Has the tank service been changed to one where internal corrosion is a moresignificant factor than it was in the previous service?

Repair Requirements for Floating Roofs

Deteriorated floating roofs must be repaired for the same reasons as fixed roofs. However,additional considerations apply to floating roofs. Cracks or punctures in the floating roofdeck or pontoons permit stored liquid to get on the deck or into the pontoons. Pontoondamage can also permit rainwater to get into the pontoon. This pontoon damage reduces thefloatation capability of the roof and must be repaired.




External floating roofs of large diameter tanks are sometimes prone to rippling when windblows across the deck. Large diameter tank roofs are also prone to pontoon buckling due toexcessive rainwater accumulation on the center deck. The wind rippling can crack the centerdeck welds and/or make the roof prone to sinking by rocking the roof to the point where somestored liquid gets on top of the deck. Pontoon buckling can reduce the roof stability andflotation capability, and make the roof prone to sinking as well. If these problems areencountered, it may be necessary to add circumferential stiffening rings to the deck orpontoon to provide additional stiffening. Floating roof stiffeners are illustrated in Figure 20.CSD should be consulted in situations like these in order to develop appropriate repair details.

Figure 20. Floating Roof Stiffeners

Any repair that will restore the roof to a condition that allows it to perform its function isacceptable. Such repairs might include replacement or patching of corroded or excessivelydeformed deck plates, repairs to corroded or excessively deformed deck plates, or repairs tocorroded or cracked deck plate lap welds.




Criteria for Repair or Replacement of Floating Roof Seals

Floating roof seals will deteriorate with time due to abrasion with the tank shell, ambientconditions, and attack by the stored liquid. When repair or replacement alternatives are beingconsidered, the selection of the seal material that is used must take into consideration theliquid that is being stored. If the stored liquid has changed since the original tankconstruction, it may be necessary to change the seal material or seal design in order to achieveadequate service life.

Rim-mounted primary mechanical shoe seals and toroidal seals can often be repaired orreplaced with the tank in service. No more than one quarter of the seal should be removedfrom an in-service tank at one time. This limitation minimizes evaporation losses and reducesthe danger to workers. Temporary spacers must be used to keep the roof centered during sealreplacement.

Primary seal systems that are mounted partly or fully below the rim usually cannot beremoved with the tank in-service. In-service repairs must normally be limited to replacing theprimary seal fabric in these cases.

Rim-mounted or shoe-mounted secondary seals and weathershields may be installed, repairedor replaced with the tank in service because they are above the primary seal.

The cause of any seal damage or deterioration must be determined so that appropriate actioncan be taken. The following requirements must be met:

• Buckled parts of the seal must be replaced, not straightened. A straightenedpart can never be returned to like-new condition and will be more prone tobuckling again during tank operation.

• Torn seal fabric must be replaced and not repaired. Repaired fabric is moreprone to subsequent tearing than new fabric.

• Determine if a change in seal material is required due to deterioration that hasoccurred. Confirm that the seal material is compatible with the stored liquid,especially if there has been a change in tank service since the originalconstruction.

Any seal repairs or replacements must ensure that the required seal-to-shell gap requirementsare met. Meeting the gap requirements is especially important if the replacement seal isdifferent from the original design. There are variations among different seal designs withrespect to their ability to accommodate the actual roof-to-shell rim space. One or more of thefollowing options may be required, depending on the situation:

• Adjust the hanger system on primary shoe seals.

• Add foam filler in toroidal seals.




• Increase the length of rim-mounted secondary seals in the problem area.

• Replace all or part of the primary seal system, along with possible installationof a rim extension for a secondary seal.

Repair Considerations for Internal Floating Roofs

Inspection and repair considerations for internal floating roofs are similar to those that areused for external floating roofs. Because the internal floating roof is protected from theambient environment, factors that can cause deterioration of external floating roofs (e.g., windand rainwater accumulations) are not relevant for internal floating roofs.

The following briefly summarizes the primary items on internal floating roofs that must beinspected and evaluated:

• The roof deck should be visually checked for any accumulation of product.

- For welded steel decks, such an accumulation would be due to crackedwelds. Any suspect welds should be vacuum box tested and repaired asneeded.

- For bolted roof construction, such an accumulation may be due to loosebolts and clamps. These bolts and clamps should be tightened asneeded.

• The pontoons should be checked for tightness to confirm that the roof flotationcapability is maintained.

• Roof support legs should be checked for corrosion and repaired or replaced asneeded.

• The peripheral roof seal should be checked for wear, deterioration caused bythe stored liquid, and adequate contact with the shell. Damaged seals must bereplaced because such seals could permit excessive vapor losses and causerestrictions in roof travel.

• Seals are installed at the floating roof deck around the fixed roof supportcolumns and around the access ladder that is located between the fixed roof andthe floating roof. These seals should also be inspected for wear, deterioration,and adequate contact.




DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR SITUATIONSTHAT INVOLVE TANK SETTLEMENT

This section discusses the following topics concerning tank settlement:

• Shell settlement• Bottom settlement• Correcting settlement problems

In spite of all attempts to prevent or minimize settlement during tank foundation design andconstruction, tank shell and/or bottom settlement may still occur over a period of time afterthe tank has been placed in service. Therefore, shell and bottom settlement must be evaluatedas part of the periodic tank maintenance activity to determine if any corrective action isrequired. The types of shell and bottom settlement that may occur must first be understood inorder to make these evaluations. The sections that follow review the principal types ofsettlement and describe how they are evaluated.

Shell Settlement

Types

The three types of shell settlement that may occur are as follows:

• Uniform• Planar tilt• Differential

Uniform Shell Settlement - Uniform shell settlement and the problems that it may cause areillustrated in Figure 21. In uniform shell settlement the shell remains level as it settles. Thistype of settlement does not introduce significant stresses or distortions in the tank shell orbottom and does not necessarily require correction. Problems that can be caused by uniformshell settlement and possible corrective actions are as follows:

• Blockage of surface water drainage from the tank pad into the diked area mayresult in water retention at the tank shell. Water retention can be corrected byregrading the tank pit such that water cannot accumulate near the tank. If thisproblem is not corrected, it can cause localized tank corrosion in the lowerportion of the bottom course and annular plate and sketch plate area.

• Differential settlement between piping supports and the connecting tank nozzlemay cause overstress of the pipe or tank nozzle. This problem is usuallycorrected by adjusting the pipe supports.




Figure 21. Uniform Shell Settlement

Planar Tilt Shell Settlement - Planar tilt shell settlement is when the shell tilts as it settlesand the bottom of the shell remains in a plane. If the shell elevations are plotted on a linearscale, true planar tilt settlement produces a sine or cosine curve as illustrated in Figure 22. Asthe shell tilts, stresses are introduced that tend to change the shape of the shell. The top of theshell tends to become elliptical. Shell out-of-roundness can be determined by checking topdiameters and floating roof seal clearances around the circumference of the tank. Figure 22also illustrates the effect that planar tilt settlement can have on a tank. Typical problems thatmay be caused by planar tilt are as follows:

• Distortion or support problems in connected pipe

• Poor surface drainage near the tank

• Malfunction of floating roof seals

• Other interference with floating roofs travel

• Buckling in flanges or webs of wind girders




Figure 22. Planar Tilt Settlement




Differential Shell Settlement - Differential shell settlement is when the bottom of the shell isno longer in either a level or tilted plane. API-653 also refers to differential shell settlementas out-of-plane deflection. With differential settlement, the shell undergoes different amountsof settlement at different points around its circumference. This settlement usually does notdamage the tank structure as long as the settlement is minor and there is adequate supportunder the shell. The amount of differential settlement is defined as the deviation between theactual shell settlements and the sine or cosine curve that represents true planar tilt.

A plot that describes differential settlement is shown in Figure 23. The inherent stiffness ofthe shell tends to concentrate shell support at the points with the least amount of settlement.As with planar tilt settlement, the top of the shell tends to become elliptical. Differentialsettlement can cause the same problems as planar tilt settlement. In addition, differentialsettlement may cause the shell to buckle or cause the shell-to-bottom area to becomeoverstressed. Figure 24 illustrates the potential problems that may result from differentialshell settlement.

Figure 23. Settlement Readings Showing Differential Shell Settlement




Figure 24. Effects of Differential Shell Settlement




Evaluation

32-SAMSS-005 requires that shell settlement measurements be made before, during, and afterhydrostatic testing of newly constructed tanks. The purpose of these measurements is todetermine if the settlement that occurs during the initial filling of the tank is within acceptablelimits. Shell elevation measurements will then be made periodically during the life of the tankto determine if any unexpectedly large settlements occur. The interval between elevationmeasurements is determined based on the results of these measurements. If no settlementproblems are indicated, elevation measurements will typically be made during each T&I.Shorter settlement measurement intervals are used if initial measurements indicate that theremight be settlement problems. Tank elevation measurements will not disrupt operationsbecause the measurements can be made with the tank in service.

The shell settlement readings are made relative to the elevation of a permanent bench mark(See Figure 25). The bench mark must be installed in such a manner that it will not beaffected by future ground settlement due to the tankage. This permanent bench mark permitsan accurate measurement of tank shell settlement over a period of years.

Figure 25. Tank Shell Settlement Measurements




Reference points are established on the tank shell by welding nuts or similar steel objects tothe tank shell. The reference points are located 100 mm (4 in.) above the bottom edge of thebottom shell course at equal distances around the circumference of the tank. One referencepoint is located at the catch basin. The minimum number of reference points depends uponthe diameter of the tank. API-653 requires that at least 8 reference points be used, and thatthe reference points be spaced no more than 9.1 m (30 ft.) apart.

The elevation measuring instrument should be set up at least 1-1/2 tank diameters away fromthe tank shell. The elevation readings should be accurate to within 2 mm (1/16 in.).

Appendix B of API-653 contains a basis that may be used for the evaluation of differentialshell settlement (i.e., out-of-plane deflection). The API-653 evaluation basis is contained inWork Aid 4 and is based on the following parameters:

• Arc length between shell elevation measurement points

• Tank height

• Modulus of Elasticity and yield strength of the tank shell plate

In order to use the API-653 basis, the shell elevation measurements that are made must firstbe converted to out-of-plane deflections around the tank circumference. This data conversionis typically done using a computer program and subtracts the uniform and planar tiltsettlement components from the total settlement measurements.

If the measured differential shell settlement exceeds the API-653 acceptance basis, CSDshould be contacted before any action is taken to relevel the tank. Further evaluations aretypically made to determine if the settlement has caused any damage or operational problemsto the tank. Experience has shown that excessive differential shell settlement will typicallycause shell distortion before any failure will occur. A detailed stress analysis may also bedone to help make a decision. Releveling a tank can be expensive and could cause moreproblems than it solves if it is not done properly.




Bottom Settlement

Types

The three types of bottom settlement that may occur are as follows:

• Localized

• Center-to-edge

• Combined bottom and shell

Localized Bottom Settlement - Localized depressions in the tank bottom are normally due toa soft spot or void in the foundation. Voids in the foundation may occur when settlement hasoccurred and the tank has been jacked for repairs. After the jacking operation, the foundationmust be refilled with a grout material to fill in the vacant spaces. However, no technique canguarantee that the vacant spaces are entirely refilled. Therefore, after jacking operations, it isnot unusual for voids to exist in the foundation. Tunneling under a tank to inspect bottomplates, or leakage through a bottom plate that softens or disperses pad material, are othermechanisms that can also cause voids in the foundation.

The bottom plate is not designed to support the tank contents without being uniformlysupported from underneath by the foundation. Therefore, a localized weakness in thefoundation soil can cause overstress in the bottom plates and result in a bottom plate weldfailure. If the foundation in the area of the weld failure is unstable or poorly drained, theresulting leak can wash out a considerable portion of the foundation and lead to a major tankbottom failure. Figure 26 illustrates localized bottom settlements that may result from softspots or voids in the foundation.




Figure 26. Localized Bottom Settlement

In addition to localized bottom settlement that can occur away from the tank shell, localizedsettlement can occur near the shell of a tank. Localized bottom settlement that occurs near thetank shell is normally accompanied by shell settlement, and the two settlements should beconsidered together.




Center-to-Edge Bottom Settlement - Center-to-edge bottom settlement is illustrated inFigure 27. A relatively large center-to-edge bottom settlement over the entire bottom may beaccommodated without overstressing the tank bottom because the bottom plates act as a thinmembrane and are flexible. However, extreme cases can occur when the bottom settlementtakes up all slack in the bottom plate and exerts an inward pull on the shell, as illustrated inthe detail in Figure 27.

Figure 27. Center-To-Edge Bottom Settlement




On tanks that are less than about 50 m (150 ft.) in diameter, excessive bottom settlement islikely to buckle the shell. On tanks that are over about 50 m (150 ft.) in diameter, frictionaldrag is a bigger factor and excessive settlement is more likely to overstress the bottom platesbefore noticeable shell buckling occurs.

In tanks that are built on poor foundations, the failure of a bottom weld can lead tocatastrophic foundation washout. However, if the tank foundation was preloaded andcomplies with Saudi Aramco design requirements, center-to-edge settlement should not be aproblem.

Combined Bottom and Shell Settlement - Bottom settlement will normally occur incombination with one or more types of shell settlement. Differential settlement of the shell ofa large diameter tank relative to its bottom can result in significant radial pull on the bottomplates by the shell. This type of settlement is illustrated in Figure 28. The difference insettlement between the shell and bottom must be absorbed over a very short distance in thebottom plates at the tank edge. The resulting excessive distortion of the bottom plates, thatmust accommodate all of the stretching, may crack a bottom fillet weld in the distorted region.The cracked fillet weld could lead to a failure of the bottom.

Figure 28. Combined Bottom and Shell Settlement




Evaluation

Although excessive bottom settlement occurs less frequently than shell settlement, bottomsettlement can result in greater damage and much higher releveling costs. At the same time, itis more difficult to determine bottom plate settlement patterns while the tank is underhydrotest or in service.

Because of the greater risks associated with bottom settlement, bottom elevation patterns aresometimes monitored while the tank is in service in locations where sub-soil conditions aredoubtful or unsatisfactory. In these situations, important data points can be checked bydropping a sounding line through roof openings, such as manholes and support leg openings,before and during hydrotest and while the tank is in service. Warped roof plates in a coneroof tank are a strong indication that excessive bottom settlement may have occurred. Inaddition, excessive shell settlement indicates a strong possibility of excessive bottomsettlement as well.

In most situations, bottom elevation measurements to determine settlement patterns will onlybe made when the tank is taken out of service for a T&I. API-653 contains recommendedlocations for bottom settlement measurements, as shown in Figure 29. Closer measurementspacing(75 - 150 mm [3 - 6 in.] apart) should be used in areas where the bottom elevation changesrapidly, especially close to the shell.




Figure 29. Bottom Settlement Measurement Locations




Appendix B of API-653 contains a basis that may be used for the evaluation of tank bottomsettlement. This basis is included in Work Aid 4. The API-653 criteria is based on thefollowing parameters:

• Depth of depression (or the height of the bulge) in the tank bottom. Note thatlocal areas of the bottom may be bulged up rather than depressed down.Bulges are evaluated using the same basis as depressions.

• Radius of the largest circle that may be inscribed within the depressed (orbulged) area.

• An assumption that the bottom plate lap welds are made with a single weldpass.

If the measured bottom plate settlement exceeds the API-653 acceptance basis, CSD shouldbe contacted before any action is taken to repair or relevel the bottom. The API-653evaluation basis is relatively conservative, and it may be worthwhile to do a detailed stressanalysis to determine the actual situation if extensive repair or releveling is required. TheAPI-653 basis is especially conservative if the bottom plate lap welds are made with two ormore weld passes rather than the one pass that API-653 assumes.

Methods for Correcting Settlement Problems

If the shell or bottom settlement is excessive, corrective action must be taken beforeunacceptable damage and tank leakage occurs. Because significant time is required toproperly plan, evaluate, and execute settlement corrections, the decision to relevel cannot betaken lightly. Improper releveling can cause as much or more damage to the tank than thesettlement that it is meant to correct. The paragraphs that follow describe the primaryconsiderations and techniques for correcting shell and bottom settlement.

Shell Releveling Considerations and Techniques

Considerations - Three forms of shell releveling may be considered: releveling only a part ofthe shell, releveling the entire shell, or releveling both the entire shell and the tank bottom aswell. The extent of releveling should be minimized consistent with fixing current problemsand minimizing the probability of needing future releveling.

In many cases, releveling only part of the shell is necessary. In these cases, the low points ofthe shell are jacked by amounts that range from 50 mm (2 in.) to 175 mm (7 in.). In addition,when the entire shell must be releveled and settlement is expected to continue, localoverjacking of the shell in areas of poor soil may be desirable. When overjacking isspecified, it should be done so that the resulting radial displacements of the shell will notcause floating roof binding or gaps between the floating roof and shell. Calculationprocedures are available that predict the amount of radial shell displacement for specifiedchanges in shell elevation.




Techniques - The most common technique for releveling a tank shell is to lift the shell withhydraulic jacks and pack selected materials beneath the bottom and annular plates. Twobasically different procedures for tank jacking are widely employed: jacking against the tankshell and jacking from beneath the bottom or annular plates.

When jacking against the tank shell, jacking lugs or brackets are welded to the tank shellaround its periphery as close to the bottom or annular plate as possible. Figure 30 illustratesthe details for typical jacking lugs. A compact hydraulic jack (or a pair of jacks) is placed ona timber footing at each bracket location, and the tank is gradually lifted to a height that isequal to the jack stroke (generally 100 mm [4 in.]). Timber beams or steel shims are thenused to temporarily support the tank shell while the jack is released, and additional timberbeams are placed between the jack and the foundation. The entire process is repeated untilthe tank shell is level and at the required elevation.

Figure 30. Typical Jacking Lugs




Depending on the jacking system, the jack spacing, and the shell thickness, externallymounted jacks can impose significant stresses on the tank shell. Therefore, it is important thatthe shell stresses be checked and any necessary strengthening measures carried out beforejacking is begun.

The major advantage of jacking against the shell when compared to jacking from beneath thebottom or annular plates is that disturbance to the existing foundation is minimal. Becausethe jacks are not beneath the shell, placement and compaction of select backfill is moreuniform and results in less potential for differential shell settlement in the future.

The disadvantage of jacking against the shell when compared to jacking from beneath theannular plates is the welding that is required to attach the brackets to the shell and to provideany necessary shell reinforcement. This welding can also build up residual stresses in theshell and possibly cause brittle fracture, particularly in older tanks where steels with poorfracture toughness were often used. On newer tanks that are constructed of high strengthsteel, the weldability of the bracket to the shell may be a problem.

There are at least two methods for jacking from beneath the bottom or annular plates: using ajacking frame, or excavating pits for the placement of hydraulic jacks.

The preferred method for jacking from beneath the bottom annular plates is to use a jackingframe. A typical jacking frame is illustrated in Figure 31. The frame is equipped with slenderjacking shoes that are shaped so that they can be easily slipped beneath the tank shell. Theframes are spaced every 3 to 4.5 m (10 to 15 ft.) around the tank periphery. The tank can bejacked to a maximum height of 300 mm (12 in.) with this method. No welding to the tankshell is required, and the jacking frames are reusable. Due to the size and shape of the jackingshoe, there is little disturbance to the existing foundation. The disadvantages of this methodare the initial fabrication cost of the frames and the limited jacking height of 300 mm (12 in.).The frames also cannot be used to lift and relevel the entire tank bottom; therefore, thismethod cannot be used for all tank releveling needs.




Figure 31. Typical Jacking Frame

Figure 32 illustrates pits that may be excavated beneath the bottom or annular plates toprovide space for placing hydraulic jacks. Jack spacing depends on the size of the tank andthe thickness of the shell. Jacks are typically spaced 6 to 7.5 m (20 to 25 ft.) apart; however,a stress analysis should be made for the specific tank to be jacked in order to determine therequired jack spacing. After placing the jacks, the tank is lifted to the desired height byutilizing timber cribbing. The jacking pits are then backfilled after the tank is lowered ontothe newly releveled foundation pad.

Localized settlement over the jacking pit areas can cause additional stresses in the annularplates and shell. Therefore, it is important to minimize these settlements and resulting stressesby keeping the size of the jacking pits as small as possible. Only high quality fill such ascrushed stone should be used, and the fill should be properly compacted by means of ramsand pneumatic compactors. Ideally, single-size crushed stone will be placed in the pits,because this type of material experiences the least amount of settlement due to tank loadingafter it is compacted.




Figure 32. Typical Jacking Pit

The actual jacking operation should be accomplished using a predetermined procedure thatconsiders the following factors:

• All tank elevation changes should be gradual to minimize stresses in the overalltank structure.

• Localized sections of differential settlement should first be jacked to a planarposition. The remaining tank shell can then be jacked to a level position, asrequired.




• Some overjacking may be done when further settlement can be anticipated andpredicted.

• Steel bearing plates under the jacks spread the jacking reaction and minimizethe risk that jacks may be tipped over or kicked out.

• When correcting for differential settlement, it is not imperative to place a jackat every jacking point and lift all points simultaneously. The releveling can beaccomplished with six to eight jacks operated in sequence. Jacking should bedone in small increments, a few millimeters (inches) at a time. Lifting shouldstart at the low point, move to the adjacent jacking point on one side, then tothe adjacent jacking point on the other side, and so on. After the tank is highenough to slip in steel shims, the first jack can be removed and repositioned onone side or the other. In this way, the lifting area can be extended to any pointon the tank circumference.

• When simultaneously lifting at multiple locations, all jacks should beconnected to a single hydraulic line and pump. Hydraulic connections to thejacks should include a safety system to prevent jack failure in case of a pumpor hydraulic line failure.

• During jacking operations, careful attention must be paid to the bottom plates,especially on floating roof tanks. When the shell is raised to a certain point, theshell begins to lift the bottom plates at the first row of roof support legs. If theshell has to be raised further, it will be necessary to release the loads from theselegs with temporary roof supports. Removing the load from these legs isaccomplished by welding temporary brackets to the inside of the shell tosupport the outer periphery of the pontoon.

Bottom Releveling Considerations and Techniques

Considerations - When the bottom must be releveled, the following items should beconsidered as possible options:

• If local areas of the bottom are depressed, pump Portland cement groutunderneath the affected area through a hole in the tank bottom.

• Lift the entire tank and relevel the affected area. Coarse sand or gravel shouldbe used as the filler material.

• Remove the bottom plates in the affected area, relevel, and replace the plates.When releveling, coarse sand or gravel should be used as the filler material.




• Add a second pass to the bottom plate fillet welds in the affected area. Prior toadding the second pass, the original fillet welds must be sand blasted andcleaned to ensure that the fillet welds are free of all scale and oil.

Techniques - The tank bottom may be releveled by pressure grouting, jacking, or other lesscommonly used methods. Selection among any of these releveling techniques, or acombination of them, should be based on an economic evaluation.

Pressure grouting of tank bottoms is appropriate for correcting settlement in localized areas ofthe bottom plates. In this technique, grout is injected under pressure between the bottom plateand the foundation pad, not directly into the pad. Pressure grouting has proven to besuccessful at many installations. A wide variety of grout mixes are offered by contractorspecialists. All of these mixes include various materials and additives that improvepumpability and flow characteristics. For tank bottom releveling, a low compressive strengthis a desirable characteristic of the grout, because a low compressive strength minimizes hardspots that might damage the bottom plates should further settlement occur.

Pressure grouting is generally not economical for releveling a large portion of a tank bottom.For tanks that require more than local releveling, it is usually more economical to lift theentire tank off its foundation and relevel and reshape the entire pad. When this technique isused, the entire tank is jacked up and cribbed to a height that provides headroom formotorized dumpers and small bulldozers. Mechanical equipment is then used to relevel andreshape the entire foundation with sand, gravel, and crushed stone. The tank is again jackedclear, cribbing removed, and jacks released to set the tank back on the new pad. Thistechnique has proven to be successful on numerous tanks for correcting extensive bottomsettlements.

Three other techniques can also be considered for bottom releveling:

• Float the tank on water or air, move the tank to an adjacent temporary site,repair the original foundation, and refloat the tank back onto the repairedfoundation.

• Lift the tank, slide the tank off its foundation using a rail system, and thenreturn the tank to the foundation after repairs are made.

• Remove the tank bottom plates, reshape the foundation, and install new bottomplates.

All of these techniques have been successfully used. The choice of the specific technique touse depends on factors such as cost, the extent of required repairs, the size and type of tank,and the experience of the contractor who is engaged to perform the work.




Sample Problem 3: Determine the Need for Corrective Action Based on Tank SettlementMeasurements

Shell settlement measurements were made of a 100 ft. diameter floating roof tank. The shellelevation measurements that were noted in the Inspection and History Report have beenconverted to out-of-plane deflections, and these deflections are shown in Figure 33. Thefollowing information is also available:

• There are no visible signs of shell distortion.

• The tank shell height is 51 ft.

• The yield stress of the shell plate material is 38 000 psi.

• The Modulus of Elasticity of the shell plate material is 29 500 000 psi.

Determine what action should be taken.

Reading Number Angular Position, Degrees Out-of-Plane Deflection, in.

1 0 0.01

2 30 0.06

3 60 -0.02

4 90 0.02

5 120 -0.02

6 150 0.02

7 180 0.01

8 210 0.02

9 240 -0.02

10 270 0.01

11 300 -0.02

12 330 -0.01

Figure 33. Sample Problem 3 Settlement Data




Solution


There are more than the minimum required number of settlement measurement points. Now,confirm that the settlement measurements were not made too far apart.

L = πDN

L =π 100( )

12= 26.2 ft.

Because this is less than 30 ft., the spacing between the measurements is acceptable.

Now determine the maximum permitted out-of-plane deflection.

S = 11 L2Y

2EH

S =11 × 26 .22 × 38 000

2 × 29 500 000 × 51

S = 0.095 ft . = 1.14 in .

Because the maximum measured out-of-plane deflection is only 0.06 in. and is less than thepermitted value of 1.14 in., no action is required.




HYDROTESTING REQUIREMENTS THAT ARE SPECIFIED IN SAES-A-004 ANDAPI-653

All new storage tanks are hydrotested as a final means to demonstrate their structural integritybefore the tanks are placed into service. There are no mandatory requirements for periodicre-hydrotesting of storage tanks to demonstrate their continued reliability unless changes havebeen made that could affect their structural integrity. API-653 specifies situations when anexisting storage tank must be re-hydrotested and when re-hydrotesting is not required.

SAES-A-004 Requirements

SAES-D-108 refers to SAES-A-004, Pressure Testing, for additional requirements withregard to hydrotesting existing atmospheric storage tanks.

The majority of the hydrotesting requirements that are contained in SAES-A-004 have moredirect applicability to piping systems, pressure vessels, and other pressurized equipment.However, SAES-A-004 also contains general procedural and personnel-safety relatedrequirements that are applicable to hydrotesting existing storage tanks. Areas within SAES-A-004 that contain requirements that apply to hydrotesting storage tanks are as follows:

• General Requirements - Para. 3.0

• Test Preparation - Para. 4.0

• Tanks - Para. 6.6

Refer to SAES-A-004 for specific requirements.

API-653 Requirements

Section 10 of API-653 requires that a full hydrostatic test be performed on an existing storagetank for the following situations (unless exempted by other criteria):

• A reconstructed tank

• Any tank that has undergone "major repairs" or "major alterations," unless thetank meets specific exemption requirements that are stated in API-653

The hydrotest must be held for 24 hours.




API-653 Requirements, cont'd

"Major repairs" and "major alterations" refer to operations that require cutting, addition,removal, and/or replacement of the annular plate ring, the shell-to-bottom weld, or a sizableportion of the shell. Examples of "major" work that would require re-hydrotesting are asfollows:

• Installation of any shell opening that is larger than 300 mm (12 in.) nominalsize and is located below the design liquid level.

• Installation of any opening into the bottom that is located within 300 mm (12in.) of the shell.

• Removal and replacement or addition of any shell plate that is located belowthe design liquid level, or any annular plate ring material, where the longestdimension of the replacement plate exceeds 300 mm (12 in.).

• Complete or partial (over half of the weld thickness) removal and replacementof more than 300 mm (12 in.) of vertical shell plate weld or radial weld thatjoins annular plate sections.

• Installation of a new bottom.

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

• Partial or complete jacking of the tank.

Re-hydrotesting an existing tank costs additional time and money. Re-hydrotesting alsofrequently causes problems with regard to water disposal if the hydrotest water becomescontaminated with remnants of the tank contents. Therefore, Para. 10.3.2 of API-653indicates that re-hydrotesting after major repairs or alterations is not required, provided thatspecific exemption criteria are met. The exemption criteria are based on the followingfactors:

• Material fracture toughness• Shell thickness and metal temperature• Details of the repairs or alterations• Welding and inspection details

The intent of the re-hydrotest exemption criteria is to identify situations where the repairs oralterations that are done are not likely to increase the risk of a brittle fracture in the tank. Are-hydrotest is not required for these low-risk situations. Participants are referred to API-653for the specific exemption requirements.

SAES-D-108 adds to the API-653 re-hydrotest requirements. Para. 10.3.1 specifies that themaximum tank shell stress during the re-hydrotest must be limited to 90% of the specifiedminimum yield strength of the material. The maximum shell stress must be based on theactual shell thicknesses that were measured during a shell inspection.




WORK AID 1: PROCEDURE FOR DETERMINING REPAIR OR ALTERATIONREQUIREMENTS FOR SITUATIONS INVOLVING STORAGETANK SHELLS AND SHELL PENETRATIONS

The procedures that are contained in this Work Aid may be used to determine the appropriaterepair or alteration requirements to be used for storage tank shells or shell penetrations. Theclass reference copies of API-653 and SAES-D-108 shall be used with this Work Aid. Thesereference documents are contained in Course Handouts 1 and 2, respectively. All needed tankinspection data may be obtained from the Inspection and History Reports.

Work Aid 1A: Procedural Steps

The general procedure that follows should be used to help determine appropriate repair oralteration requirements to use for storage tank shells or shell penetrations.

1. Analyze the inspection data that is available from a T&I and that is documented in anInspection and History Report to determine the current condition of the tank shell orshell penetration, prior inspection and repair history, the extent of the problem (if any),and any alterations that may be required.

2. Gather the necessary design information for the tank. This information includes itemssuch as tank or nozzle diameter and wall thickness, materials, and maximum requiredfill height. This information may be obtained from the Contractor Design Package forthe tank.

3. Identify potential alternatives for making the repair or alteration.

4. Compare each potential alternative that was determined in Step 3 with the pertinentrequirements that are contained in SAES-D-108 and API-653 to determine the needfor repair, replacement, or alteration.

5. Identify the key parameters that will influence the decision for repair, replacement, oralteration. Parameters that must be considered are as follows:

• The time that is available to work and the desired time interval until the nextT&I.

• Extent, location, and severity of the damage.

• Cost of alternatives and the remaining life of the storage tank.

• Operational requirements. These requirements affect both the available time todo the work, as noted above, and the tank alterations that are required to meetany changed operational needs.

6. Select an alternative for repair, replacement, or alteration.

7. Identify the procedures to be followed for the selected alternative.




Work Aid 1B: Inspection Data

The condition of the existing tank must be quantified in order to determine the appropriaterepair or alteration requirements. This condition is determined by inspection personnel duringan OSI and/or a T&I, and it is then documented in the Inspection and History Report. Theinspection data is then used to help in the determination of appropriate repair or alterationrequirements.

If the situation involves a tank shell, proceed to Step 1. If the situation involves a tank shellpenetration, proceed to Step 13.

Tank Shell

1. Are there any distortions in the tank shell, such as out-of-roundness, buckled areas, orflat spots? Quantify their extent and location.

2. Are there any flaws, such as cracks or laminations, in the shell base plate material?Quantify their extent and location.

3. Have any weld flaws been identified? Weld flaws may include the following:

• Cracks

• Lack of fusion

• Rejectable slag, porosity, or undercut

• Arc strikes in or adjacent to the weld

• Corrosion or pitting

Document the type, the location, and the extent of the weld flaws.

4. Have any generally corroded or pitted areas been identified? If "Yes," proceed to Step5. If "No," the inspection data collection for tank shell evaluation is complete.

5. For generally corroded areas, proceed to Step 6. For pitted areas, proceed to Step 12.

6. For each generally corroded area, determine the minimum shell thickness, t2, at anypoint in the corroded area, excluding widely scattered pits. Refer to Figure 2-1 in theclass reference copies of API-653 in Course Handout 1 (see Figure 34).




Figure 34. Generally Corroded Area




7. Use the formula that follows to calculate the critical length, L:

SI Units English Units

L = 33.8 Dt2 L = 3.7 Dt2 Where: L = Maximum vertical length over which hoop stresses are assumed to

"average out" around local discontinuities, mm (in.)

D = Tank diameter, m (ft.)

t2 = Minimum shell thickness at any point in the corroded area, exclusiveof widely scattered pits, mm (in.). Determined from inspection data.

If the calculated value of L is greater than 1 m (40 in.), set the value of L to 1 m (40in.).

8. Determine which vertical plane(s) in the generally corroded area is likely to be mostaffected by corrosion. These vertical planes are the critical planes.

9. Take thickness profile measurements along each critical plane for a distance, L.Obtain at least five equally spaced measurements over the length L. If the corrodedregion is larger than L in the vertical direction, the region must be divided intomultiple sections such that no individual section is larger than L. Each section mustthen be evaluated separately.

10. Calculate the average thickness of each critical plane from the thickness measurementsthat were made.

11. Determine the lowest average thickness in the corroded region, t1, as the smallestaverage thickness considering all of the critical planes. The data collection requiredfor the evaluation of generally corroded areas of a tank shell is complete with this step.

12. For pitted areas, obtain the following information:

• Remaining shell thickness at the bottom of the pits, tpit (see Figure 35).

• The sum of the pit dimensions along any vertical line that extends across thepits. Refer to Figure 2-2 in the class reference copy of API-653 in CourseHandout 1 (see Figure 36).




The data collection that is required for the evaluation of pitted areas of a tank shell iscomplete with this step.

Figure 35. Shell Thickness at Bottom of Pit




Figure 36. Sum of Pit Dimensions




Tank Shell Penetrations

13. For existing shell penetrations, obtain the following information:

• Type of penetration (i.e., nozzle, manway, cleanout fitting)

• Location of penetration with respect to elevation and distance to nearby shellwelds or other openings

• Size of penetration

• Thickness of nozzle neck

• Size, thickness, and type of reinforcement

• Deterioration due to corrosion or other defects

14. For the addition of a new shell penetration, obtain the following information:

• Size and type of penetration

• Desired location (i.e., elevation and circumferential position) and distance tonearby shell welds or other openings

• Thickness and condition of the tank shell in the area where the penetration andits associated reinforcement will be welded




Work Aid 1C: Reference to Pertinent Content From SAES-D-108

SAES-D-108 modifies API-653 requirements. This sub-Work Aid contains modificationsthat must be followed with respect to tank shells and shell penetrations. All the API-653requirements must be followed, as provided in Work Aid 1D. Refer to the class referencecopy ofSAES-D-108 in Course Handout 2.

Tank Shells

Confirm that rectangular replacement insert plates that do not intersect with weld seams haverounded corners. The corner radius shall be in accordance with Figure 7-1 of API-653(see Figure 37).

Shell Plate Thickness, mm (in.) Minimum Corner Radius, mm (in.)

≤ 12.7 (0.5)

> 12.7 (0.5)

150 (6)

Greater of 150 (6) or 6t

Figure 37. Minimum Corner Radius of Shell Insert Plates


1. Any reinforcing plate that is to be added to a shell opening must not be added insidethe tank.

2. Completed repairs to any fillet welds must be examined over their complete length bymeans of the Wet Fluorescent Magnetic Particle Method.




Work Aid 1D: Reference to Pertinent Content From API-653

This sub-Work-Aid contains requirements that are contained in API-653 that must befollowed with respect to tank shells and shell penetrations. Refer to the class reference copyof API-653 in Course Handout 1.

If the situation involves a tank shell, proceed to Step 1. If the situation involves a tank shellpenetration, proceed to Step 10.

Tank Shells

1. Shell distortion may be considered acceptable if the deviation from uniform curvatureis within both of the following limits:

• 13 mm (0.5 in.) over a distance of 1 m (36 in.) in a horizontal direction

• 25 mm (1 in.) over a distance of 1 m (36 in.) in a vertical direction

Contact the Consulting Services Department (CSD) if the distortion exceeds either ofthese limits.

2. Weld cracks shall be removed by gouging or grinding to sound metal. The area mustthen be prepared for the weld repair.

3. Slag, porosity, lack of fusion, laminations, and weld undercut must be evaluated byinspection personnel in conjunction with CSD, as appropriate. Unacceptable defectsmust be removed, and the weld must be repaired.

4. Arc strikes that are located in or adjacent to welds must be repaired by grinding and/orwelding. Arc strikes that are repaired by welding must be ground flush with the platesurface.

5. For cracks, gouges, or tears in the shell base plate:

• Grind the defect to a smooth contour with the shell plate surface.

• Add weld overlay if the resulting shell thickness after grinding is less than theminimum acceptable thickness. The minimum acceptable thickness isdetermined as described for the evaluation of generally corroded areas in Step6.

6. Using the procedure that follows, evaluate generally corroded areas in the shell.

a. Determine the specified minimum tensile strength of the shell plate material, T,MPa (psi). Obtain from the original design data or API-650. If the material isunknown, use T = 379 MPa (55 000 psi).




b. Determine the specified minimum yield strength of the shell plate material, Y,MPa (psi). Obtain the yield strength from the original design data or API-650.If the material is unknown, use Y = 207 MPa (30 000 psi).

c. Calculate the maximum allowable stress to be used in the shell thicknessevaluation, S, psi.

• For the bottom and second course, S is the lower of 0.80Y or 0.426T.

• For all other courses, S is the lower of 0.88Y or 0.472T.

d. Use the formula that follows to calculate the minimum acceptable thickness fora welded shell that is no more than 61 m (200 ft.) in diameter. See Step 6g forlarger diameter tanks.


tmin =4.9D H − 0.3( )

SEtmin =

2.6D H −1( )GSE

Where:

tmin = Minimum acceptable shell thickness, mm (in.)

S = Allowable stress, MPa (psi), determined in Step 6c


H = Height from the bottom of the length L of the most severelycorroded area in each shell course to the maximum design liquidlevel, m (ft.)

G = Highest specific gravity of the tank contents. If future hydrostatictesting of the tank must be considered, use G = 1.

E = Weld joint efficiency of the original tank design

E = 0.7, if original weld joint efficiency is unknown

E = 1.0 if the corroded area is away from welds by at least the greaterof 25 mm (1 in.) or twice the plate thickness




e. The generally corroded area is acceptable if both the equations that follow aresatisfied.

t1 ≥ tmin + CA

t2 ≥ 0.6 tmin + CA

Where:

tmin = Minimum acceptable shell thickness as calculated in Step 6d,mm (in.).

t1 = Lowest average thickness in the corroded region as calculated inStep 11 of Work Aid 1B, mm (in.).

t2 = Minimum shell thickness at any point in the corroded areaexclusive of widely scattered pits, mm (in.). Determined frominspection data.

CA = Corrosion allowance that is required until the next T&I, mm(in.). Determine from inspection data, maximum calculatedcorrosion rate, and the desired interval until the next T&I.

CA = (Maximum Corrosion Rate) x (Desired T&I interval).

MaximumCorrosionRate =Original Thickness in Corroded Area − t2( )

Years in Service

f. As a final check, it must also be confirmed that the T&I interval is no greaterthan half of the remaining tank life (based on the general corrosion).

(1) Using each equation that is in Step 6e, calculate the remaining corrosionallowance, CA/remaining, mm (in.).

CA/remaining - 1 = tmin - t1

CA/remaining - 2 = 0.6 tmin - t2

CA/remaining = the smaller of CA/remaining - 1 or CA/remaining - 2




(2) Determine the Remaining Life from the following equation:

RemainingLife =CA /remaining

Maximum CorrosionRate

(3) The T&I interval (based on the general corrosion) can be no longer thanhalf of the Remaining Life.

g. If the criteria in Step 6e and Step 6f are not satisfied, the following options areavailable:

• Reduce the fill height, H, until the equations are satisfied.

• Repair the corroded area. See Step 9.

• Reduce the inspection interval enough so that the CA is reduced to thepoint where the equations are satisfied and where the interval is no morethan half the predicted remaining life.

• Using the Variable Design Point Method of API-650 to calculate theminimum required thickness, evaluate the corroded area again. SeePara. 2.3.3.2 of API-653. The Variable-Design-Point Method wasdiscussed in MEX 203.03.

• Using the ASME Code Section VIII, Division 2, "Design By Analysis,"evaluate the corroded area again. See Para. 2.3.3.5 of API-653.

• A combination of two or more of the above options.

h. If the tank is over 61 m (200 ft.) in diameter, use the Variable-Design-PointMethod of API-650 to calculate the minimum required thickness. TheVariable-Design-Point Method was discussed in MEX 203.03. The variablesthat are to be used are as defined in Para. 2.3.3.1 of API-650. Then, proceed asin Steps 6e through 6g.

i. If the shell is riveted rather than welded, refer to Para 2.3.4 of API-653 forrequirements for the calculation of tmin.




7. Using the procedure that follows, evaluate pitted areas in the shell.

a. Calculate tmin as in Step 6.

b. Widely scattered pits may be ignored if the conditions that follow are met.

• The remaining shell thickness at the bottom of the pit, tpit, must satisfythe following equation:

tpit ≥ 0.5 tmin + (Pitting Allowance)

The Pitting Allowance should be determined based on the maximumpitting rate and the desired interval to the next T&I.

(Pitting Allowance) = (Maximum Pitting Rate) x (Desired T&I Interval)

MaximumPittingRate =MaximumPit Depth

Years in Service

• It must also be confirmed that the T&I interval is no greater than halfthe remaining tank life (based on the pitting).

- Calculate the Remaining Pitting Allowance, mm (in.)

Remaining Pitting Allowance = (tpit - 0.5 tmin)

- Determine the Remaining Life from the following equation:

RemainingLife =RemainingPitting Allowance

MaximumPitting Rate

- The T&I interval (based on the pitting) can be no longer thanhalf the Remaining Life.

• The sum of the pit dimensions along any vertical line that extendsacross the pits must not exceed 50 mm (2 in.) in any 200 mm (8 in.)length(see Figure 36).

c. If the pitted area does not satisfy the requirements in Step 7b, the pits cannot beignored. The pitted area must then be evaluated as a generally corroded region,and the procedure contained in Step 6 must be used.




8. Evaluate the acceptability of corroded or pitted regions for loads other than thehydrostatic head, as appropriate. This evaluation would consider loads such as fromconnected piping systems, wind, or temperature over 93°C (200°F). Consult CSD asappropriate.

9. Corroded or pitted areas of shell plate that are unacceptable may be repaired by eitherweld overlay or by cutting out the corroded section of shell and replacing the removedsection with new material. Use weld overlay only for relatively small corroded areas.In either case, welding requirements that are contained in Section 9 of API-653 mustbe met.

The requirements that follow shall be met when a replacement shell plate is used forrepair.

a. Plate material must meet current API-650 requirements.

b. The minimum plate thickness shall meet the requirements in Para. 7.2.1 ofAPI-653. The replacement plate thickness will typically equal the thickness ofthe plate as originally constructed.

c. The replacement plate may be:

• Circular

• Oblong

• Square with rounded corners, or rectangular with rounded corners,except when an entire shell plate is replaced

d. The minimum dimension of a replacement shell plate shall be the greater of300 mm (12 in.) or 12 times the thickness of the replacement plate.

e. Acceptable replacement plate details are shown in Figure 7-1 of API-653(see Figure 38).

f. Minimum weld spacing requirements shall meet Figure 7-1 of API-653(see Figure 38).

g. Shell replacement plates shall be welded with butt-welded joints with completepenetration and complete fusion.




Minimum weld spacing between edges (toes) of weldsfor thickness of replacement shell plate, t, mm (in.)

Dimension t ≤≤ 12.7 (0.5) t > 12.7 (0.5)

B

H

V

A

150 (6)

75 (3)

150 (6)

300 (12)





Figure 38. Acceptable Shell Replacement Plate Details





10. For existing shell penetrations, use the available inspection data and take the followingaction:

• Determine if the installation details conform to the requirements of the originalconstruction standard. Items to check would include the amount and type ofreinforcement, and the distance to the other welds or to adjacent penetrations.If the original construction standard is not known or is unavailable, use thecurrent revision of API-650 as a basis for comparison. If the details do notconform, contact CSD to determine appropriate action.

• Flaws other than corrosion (such as weld cracks, lack of fusion, gouges) shallbe treated in the same manner as if these flaws were found on the shell. SeeSteps 2 through 5.

• Evaluate as follows the corroded regions within the nozzle itself, or within itsreinforcement region on the shell:

- Compare the amount of corrosion that has taken place with theoriginally specified corrosion allowance. If no corrosion allowance wasspecified, or if the originally specified corrosion allowance has beenexceeded, refer the situation to CSD for review.

- Determine how much of the originally specified corrosion allowanceremains. If the remaining corrosion allowance is at least equal to thecorrosion allowance that is required until the next T&I, the corrosion isacceptable. If the remaining corrosion allowance is not acceptable,either the T&I interval must be reduced or the nozzle must be repaired.

11. When existing shell penetrations must be repaired:

• All repairs must comply with API-650 requirements. If this repair involvesshell repair also, the requirements that are contained in Step 9 shall be met.

• Reinforcing plates that must be added to unreinforced nozzles or to address acorrosion problem must meet all API-650 dimensional and weld spacingrequirements. See Figures 7-2 and 7-3 of API-653 for acceptable details andweld size requirements.




12. For new shell penetrations that are added during a T&I, design and installation detailsshall meet either API-650 requirements or the requirements that are contained in Para.7.7.2 of API-653.

13. For new shell penetrations that are added by hot tapping, design and installation shallmeet SAES-D-108 and API-653 requirements.

14. When existing shell penetrations must be altered:

• Details of the alteration must comply with API-650 requirements, including theminimum reinforcing area and minimum distance between adjacent welds.

• Refer to Para. 7.8.2 of API-653 for alteration requirements that may applywhen a new tank bottom is installed above an existing bottom.




WORK AID 2: PROCEDURE FOR DETERMINING REPAIR OR ALTERATIONREQUIREMENTS FOR STORAGE TANK BOTTOMS

The procedures that are contained in this Work Aid may be used to determine the appropriaterepair or alteration requirements to be used for storage tank bottoms. The class referencecopies of API-653 and SAES-D-108 shall be used with this Work Aid. These referencedocuments are contained in Course Handouts 1 and 2, respectively. All needed tankinspection data may be obtained from the Inspection and History Report.

Work Aid 2A: Inspection Data

The condition of the existing tank bottom must be quantified in order to determine theappropriate repair or alteration requirements. This condition is determined by inspectionpersonnel during a T&I, and then documented in the Inspection and History Report. Theinspection data is then used to help determine appropriate repair or alteration requirements.

1. Refer to Work Aid 1A for general procedural steps that are also applicable to theevaluation of tank bottoms.

2. Is there any general internal corrosion? If there is, quantify its extent and location.

3. Is there any internal pitting? If there is, quantify its depth and location.

4. Is there any underside pitting? If there is, quantify its depth and location.

5. Is there an internal bottom lining installed? If yes, determine its thickness and designdetails.

6. Does the tank have a cathodic protection system installed?

7. Does the tank have a leak detection and secondary containment system installed?

8. Have any cracks or leaks been identified in the shell-to-bottom weld or in any otherbottom plate welds? If yes, quantify their extent and location.




Work Aid 2B: Reference to Pertinent Content From SAES-D-108

SAES-D-108 modifies API-653. This sub-Work Aid contains modifications that must befollowed with respect to tank bottoms. All other API-653 requirements must be followed asprovided in Work Aid 2C. Refer to the class reference copy of SAES-D-108 in CourseHandout 2.

1. Use the following procedure to determine the minimum bottom plate thickness.

a. Perform thickness scanning of the bottom to obtain an overall view of itscondition and identify areas with potential corrosion.

b. Perform additional thickness readings in those areas with potential corrosionproblems. Identify areas that have thickness readings that are less than 2/3 ofthe original plate thickness or that have extensive pitting.

c. If further corrosion investigation is required, coupons (i.e., sample plates) maybe cut from the bottom plates. The minimum coupon size is 30 x 30 cm (12 x12 in.). A minimum of four coupons shall be chosen by the designatedinspector. Coupons shall not be cut from within the "critical zone" of thebottom.

2. If the entire tank bottom must be replaced, the new bottom must be installed above theoriginal bottom if this is the first time that the bottom is being replaced. Subsequentbottom replacements must be made at the same elevation as the first replacementbottom. The existing cushioning material that is located between the existing bottomand the new bottom must be completely replaced.

3. Completed repairs to any fillet welds must be examined over their full length by theWet Fluorescent Magnetic Particle Method.




Work Aid 2C: Reference to Pertinent Content From API-653

This sub-Work Aid contains requirements that are contained in API-653 that must befollowed with respect to tank bottoms. Refer to the class reference copy of API-653 inCourse Handout 1.

1. From the available inspection data, determine the following:

a. Average depth of general corrosion area, GCa, mm (in.)

b. Average depth of internal pitting measured from the original bottom platethickness, StPa, mm (in.)

c. Maximum depth of internal pitting, StPm, mm (in.). Note that the value that isused for the initial evaluation is based on the inspection data. Subsequentevaluations may be made based on the maximum internal pit depth that wouldstill remain after any repairs that are done.

d. Average depth of underside pitting, UPa, mm (in.)

e. Maximum depth of underside pitting, UPm, mm (in.)

f. Maximum depth of general internal corrosion, GCm, mm (in.)

g. Maximum internal pitting rate, StPr, mm/year (in./year)

StPr =StPm

N

Where: N = Number of years that the tank has been inservice

StPr = 0 if an internal bottom lining is (or will be)installed

h. Maximum underside pitting rate, UPr, mm/year (in./year)

UPr =UPm

N

UPr = 0 if the tank bottom is (or will be) cathodically protected




i. Maximum general corrosion rate, GCr, mm/year (in./year)

GCr =GCm

N

GCr = 0 if an internal lining is (or will be) installed

2. Determine the desired maximum T&I interval for the tank, Or, in years.

3. Use the following formula to calculate the minimum expected remaining thickness atthe next T&I, based on average internal pitting and maximum underside pitting.

MRT1 = To − GCa − StPa − UPm − StPr +UPr + GCr( )Or

Where: MRT1 = Minimum remaining thickness at the next scheduled internalinspection due to average internal pitting and maximumexternal pitting, mm (in.)

To = Original plate thickness, mm (in.)

Other parameters are as defined in Steps 1 and 2.

4. Use the following formula to calculate the minimum expected remaining thicknessuntil the next T&I, based on maximum internal pitting and average underside pitting:

MRT2 = To − GCa −StPm − UPa − StPr + UPr + GCr( )Or

Where: MRT2 = Minimum remaining thickness at the next scheduledinternal inspection, due to maximum internal pitting andaverage external pitting, mm (in.)

Other parameters are as defined in Steps 1, 2 and 3.




5. Determine the minimum acceptable values of MRT1 and MRT2 as follows:

a. The minimum acceptable values of MRT1 and MRT2 are shown in Figure 39for bottom plates, which are not annular plates.

Tank Bottom/Foundation Design Minimum Acceptable MRT1and MRT2, mm (in.)

No means for detection and containment of abottom leak

2.5 (0.1)

Means to provide detection and containment if abottom leak

1.25 (0.05)

Applied tank bottom reinforced lining over 1.25mm (0.05 in.) thick, in accordance with API RP652

1.25 (0.05)

Figure 39. Bottom Thickness Acceptance Criteria

b. The minimum acceptable values of MRT1 and MRT2 for butt-welded annularplates shall be in accordance with Para. 2.4.8 of API-653. See Figure 40.




First Shell Course Stress in First Shell Course, psi

Nominal Thickness, <24 300 <27 000 <29 700 <32 400

t, in. Required Annular Plate Thickness, in. (1), (2)

t ≤ 0.75 0.17 0.20 0.23 0.30

0.75 < t ≤ 1.00 0.17 0.22 0.31 0.38

1.00 < t ≤ 1.25 0.17 0.26 0.38 0.48

1.25 t ≤ 1.50 0.22 0.34 0.47 0.59

t > 1.50 0.27 0.40 0.53 0.68

Notes:

1. For liquid specific gravity less than 1.0.2. Add specified corrosion allowance to specified thicknesses.

Figure 40. Minimum Required Annular Plate Thicknesses

6. Are the bottom (and annular plate) thicknesses, MRT1 and MRT2, in accordance withthe acceptance criteria that are contained in Step 5? If both MRT1 and MRT2 meetthese criteria, the tank bottom (or annular plate) thickness is acceptable without furtherrepair; proceed to Step 8. If one or both of these thicknesses are not acceptable,proceed toStep 7.

7. If Step 6 has found that the bottom and/or annular plate thickness was not acceptable,examine the individual terms in the MRT1 and MRT2 equations to determine whichfactor(s) needs to be reduced in order to increase the calculated thickness to anacceptable level. Items that may be considered, alone or in combination, are asfollows:

• Install an internal lining that is at least 1.25 mm (0.05 in.) thick and meets APIRP 652, if one is not currently installed. Installation of a lining will reduce StPrto zero, and it will allow MRT1 and MRT2 to be as low as 1.25 mm (0.05 in.).

• Install a cathodic protection system if one is not already installed. A properlyinstalled and maintained cathodic protection system will reduce UPr to zero.




• Weld overlay repair or use lap-welded patch plates to reduce the maximum andaverage remaining internal pit depths (StPm and StPa respectively).

• Install lap-welded patch plates in areas of general corrosion in order to reducethe average general corrosion that remains in the tank (GCa).

• Replace the entire bottom with a new bottom.

The exact approach to take depends on the extent of repairs that are required, the cost,the available time, and the requirements and limitations that are contained in API-653with respect to bottom repairs.

8. If cracks or leaks were found in the shell-to-bottom weld or in the bottom plate lapwelds, these defects shall be weld repaired.

9. All tank bottom weld repairs must meet the welding requirements that are contained inSection 9 of API-653.

10. Portions of a tank bottom may be repaired by weld overlay or lap-welded patch plateswithin the following restrictions:

a. No welding, welded-on patch plates, or weld overlays are permitted within thecritical zone, except for welding of the following:

- Widely scattered pits

- Cracks that are in the bottom plates

- The shell-to-bottom weld

- Where the bottom or annular plate is being replaced

The critical zone is defined by API-653.

b. If more extensive repairs are required within the critical zone than the repairsthat are listed in Step 10a, the bottom plate (or annular plate) under the bottomshell course must be cut out and a new plate must be installed. Weld spacingrequirements must meet Para. 3.1.5.4 and Para. 3.1.5.5 of API-650.

c. The repair of sumps that are located within the critical zone shall be inaccordance with Step 10b.

11. If the entire bottom must be replaced, the requirements that are contained in Para.7.9.2 of API-653 shall be met.




WORK AID 3: PROCEDURE FOR DETERMINING REPAIR OR ALTERATIONREQUIREMENTS FOR THE ROOFS OF FIXED ROOF ANDFLOATING ROOF STORAGE TANKS

The procedures that are contained in this Work Aid may be used to determine the appropriaterepair or alteration requirements to be used for fixed roof and floating roof storage tanks. Theclass reference copies of API-653 and SAES-D-108 shall be used with this Work Aid. Thesereference documents are contained in Course Handouts 1 and 2, respectively. All needed tankinspection data may be obtained from the Inspection and History Report.


The condition of the existing tank roof must be quantified in order to determine theappropriate repair or alteration requirements. This condition is determined by inspectionpersonnel during a T&I, and it is then documented in the Inspection and History Report. Theinspection data is then used to help determine appropriate repair or alteration requirements.

1. Refer to Work Aid 1A for general procedural steps that are also applicable to theevaluation of tank roofs.

2. Is there any corrosion of roof support structural members on the inside surface of theroof? If there is, quantify its extent and location.

3. Is there any external corrosion of the roof surface? If yes, quantify its extent andlocation.

4. Are any roof welds cracked or have other weld defects been identified? If yes,quantify their extent and location.

5. Has any distortion or other structural damage been noted in any roof supportmembers? If yes, quantify its extent and location.





SAES-D-108 modifies API-653. The only modification that may be applied to tank roofs isthat completed repairs that have been made to fillet welds must be examined over their fulllength by the Wet Fluorescent Magnetic Particle Method.


This sub-Work aid contains requirements that are contained in API-653 that must be followedwith respect to tank roofs. Refer to the class reference copy of API-653 in Course Handout 1.

1. If roof support structural members have corroded, determine if the extent of corrosionhas exceeded the original corrosion allowance or if it will exceed it before the nextT&I. If the corrosion is too much, the structural integrity of the roof support systemmust be evaluated. Refer the situation to CSD.

2. Verify that no portion of the roof plates has corroded to an average thickness that isless than 2.3 mm (0.09 in.) in any 645 cm2 (100 in.2) area. Using lap-welded patchplates that are at least 4.8 mm (0.188 in.) thick, repair corroded areas as necessary.

3. If the roof is a fixed roof, the evaluation is complete. If the roof is a floating roof,proceed to Step 4.

Floating Roof

4. Verify that the roof plates and pontoons do not have cracks or punctures. Repair orreplace sections that have cracks or punctures, as needed.

5. Evaluate areas of the roof that exhibit pitting to determine whether the pitting willproceed through the roof prior to the next T&I. Repair or replace any areas that arelikely to pit through the roof.

6. Verify that the roof support systems, perimeter seal systems, and appurtenances (suchas roof rolling ladder, anti-rotation devices, water drain systems, and venting systems)do not require repair or replacement. Repair or replace, as needed.

7. If corrosion has occurred in the pontoon rims, contact CSD inasmuch as a stress and/orbuckling analysis may be required. If the rim is less than 2.5 mm (0.1 in.) thick, itmust be replaced with at least 4.8 mm (0.188 in.) thick plate. However, thicker platemay be necessary, depending on the tank size and the results of the stress and/orbuckling analyses.

8. If the perimeter seal requires repair or replacement, this shall be done in accordancewith Para. 7.12 of API-653.




WORK AID 4: PROCEDURE FOR DETERMINING REPAIR OR ALTERATIONREQUIREMENTS FOR SITUATIONS INVOLVING TANKSETTLEMENT

The procedures that are contained in this Work Aid may be used to determine the appropriaterepair or alteration requirements to be used for situations that involve tank settlement. Theclass reference copies of API-653 and SAES-D-108 shall be used with this Work Aid. Thesereference documents are contained in Course Handouts 1 and 2, respectively. All needed tankinspection data may be obtained from the Inspection and History Report.


The condition of the existing tank bottom and shell must be quantified with respect tosettlement. This condition is determined by inspection personnel during a T&I, and thendocumented in the Inspection and History Report. The inspection data is then used to helpdetermine whether shell or bottom releveling is required.

1. Refer to Work Aid 1A for general procedural steps that are also applicable to theevaluation of shell and bottom settlement.

2. For the shell elevation measurements, confirm the following:

• There are at least 8 measurement points around the shell circumference

• The maximum distance between the measurement points is 9.1 m (30 ft.)

3. Confirm that the shell elevation measurements have been converted to out-of-planedeflection readings. This measurement conversion removes the uniform settlementand rigid body tilt of the tank from consideration in the settlement evaluation.Reference Figure B-3 of API-653 (see Figure 41).




Figure 41. Graphical Representation of Tank Shell Settlement




4. If bottom settlement or bulging has been identified, confirm that the followinginformation has been obtained:

• Location of depression or bulge

• Settlement depth or height of bulge compared to the adjacent area of thebottom, B, see Figure 42

• Radius of the largest circle that can be inscribed within the bulged or depressedarea, R, see Figure 42




Figure 42. Bottom Settlement Measurements





SAES-D-108 modifies API-653. However, in the case of tank shell and bottom settlement,there are no modifications to API-653. If settlement measurements for a particular tankexceed the API-653 allowable limits, the Consulting Services Department (CSD) should becontacted.


1. If shell settlement is to be evaluated, proceed to Step 2. If bottom settlement is to beevaluated, proceed to Step 6.

Shell Settlement Evaluation

2. Confirm that at least 8 evenly spaced shell elevation measurement points were used. Ifnot, more elevation measurement points are required.

3. Confirm that the maximum arc length between shell elevation measurement points is9.1 m (30 ft.). If there is a greater distance between points, more elevationmeasurement points are required. The arc length between measurement points may becalculated as follows:

L =πDN

Where:

L = Arc length between shell elevation measurement points, m (ft.)


N = Number of measurement points

4. Calculate the maximum permitted differential shell settlement (i.e., out-of-planedeflection) as follows:

SI or English Units

S =

11L2Y2EH




Where:

S = Maximum permitted shell deflection (out-of-plane deflection), m (ft.)

Y = Shell material yield strength, MPa (psi)

E = Young's Modulus of Elasticity for the shell material, MPa (psi)

H = Tank height, m (ft.)

5. If any out-of-plane deflection measurement is greater than the maximum permittedvalue that was calculated in Step 4, the settlement must be referred to the assignedspecialist in the Consulting Services Department (CSD) for further evaluation. Referto Figure B-3 in API-653.

Bottom Settlement Evaluation

6. If differential bottom settlement that is adjacent to the shell, or localized depressed orbulged areas in the tank bottom, do not satisfy the following equation, the settlementshall be referred to the assigned specialist in CSD for further evaluation. Refer toFigure B-4 through B-7 in API-653.


B ≤ 30.83R B ≤ 0.37R

Where:

B = Depth of the depression or height of the bulge, mm (in.)

R = Radius of depression or bulge, m (ft.)

7. If the bottom of the tank is below grade, appropriate corrective action must be taken inorder to regrade the pit and avoid rainwater accumulation near the tank.




GLOSSARY

alteration Any work on a tank that involves cutting, burning, welding, orheating operations, if that work changes the physicaldimensions and/or configuration of the tank.

hot tap A procedure for the installation of a nozzle in the shell of atank while the tank is in service.

I-T&I interval The initial interval between new or rebuilt equipmentcommissioning and the first T&I overhaul.

Performance Alert The service class of equipment that requires more attention andintense monitoring than the next service class, Class 1, that isbased on corrosion rate only.

reconstruction The work that is necessary to reassemble a tank that has beendismantled and relocated to a new site.

repair Any work that is necessary to restore a tank to a condition thatis suitable for safe operation.

T&I Test & Inspection. The main purpose of the T&I is toguarantee the mechanical integrity, operation and safety of theplant/structure. This is primarily accomplished by thoroughinspection and testing by plant inspection personnel.

T&I interval The time between scheduled T&I equipment downtimes.

Documents

Saudi Aramco Repair Alteration of Storage Tanks