Repair & Alteration of Storage Tanks

Engineering Encyclopedia Saudi Aramco DeskTop Standards

Determining Requirements for Repair or Alteration of Storage Tanks

Note: The source of the technical material in this volume is the Professional Engineering Development Program (PEDP) of Engineering Services. Warning: The material contained in this document was developed for Saudi Aramco and is intended for the exclusive use of Saudi Aramco’s employees. Any material contained in this document which is not already in the public domain may not be copied, reproduced, sold, given, or disclosed to third parties, or otherwise used in whole, or in part, without the written permission of the Vice President, Engineering Services, Saudi Aramco.

Chapter : Vessels File Reference: MEX20308

For additional information on this subject, contact J.H. Thomas on 875-2230

Engineering Encyclopedia

Vessels Determining Requirements for Repair or Alteration of Storage Tanks

CONTENTS

PAGE

APPLICATION OF SAES-D-108 AND API-653 TO THE REPAIR OR ALTERATION 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 FOR STORAGE TANK SHELLS AND SHELL PENETRATIONS ........................................ 29 Deterioration of Storage Tank Shells ............................................................................. 29 General Corrosion ....................................................................................................... 29 Pitting Corrosion ......................................................................................................... 30

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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 FOR STORAGE 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

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Effects of Use of Internal Lining or Cathodic Protection Systems................................. 67 Internal Lining............................................................................................................. 69 Cathodic Protection System ........................................................................................ 71 DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR THE ROOFS OF FIXED ROOF AND FLOATING ROOF STORAGE TANKS.............................................................................................................................. 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 FOR SITUATIONS 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

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

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HYDROTESTING REQUIREMENTS THAT ARE SPECIFIED IN SAESA-004 AND API-653 ...................................................................................................... 109 SAES-A-004 Requirements ......................................................................................... 109 API-653 Requirements................................................................................................. 109 WORK AID 1: PROCEDURE FOR DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR SITUATIONS INVOLVING STORAGE 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 Tank Shell Penetrations............................................................................................. 118 Work Aid 1D: Reference to Pertinent Content From API-653 ................................... 119 Tank Shells................................................................................................................ 119 Tank Shell Penetrations............................................................................................. 126 WORK AID 2: PROCEDURE FOR DETERMINING REPAIR OR ALTERATION 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

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WORK AID 3: PROCEDURE FOR DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR THE ROOFS OF FIXED ROOF AND FLOATING ROOF STORAGE TANKS............................................................... 135 Work Aid 3A: Inspection Data.................................................................................... 135 Work Aid 3B: Reference to Pertinent Content From SAES-D-108 ............................ 136 Work Aid 3C: Reference to Pertinent Content From API-653.................................... 136 Floating Roof ............................................................................................................ 136 WORK AID 4: PROCEDURE FOR DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR SITUATIONS INVOLVING TANK SETTLEMENT.................................................................................................... 137 Work Aid 4A: Inspection Data.................................................................................... 137 Work Aid 4B: Reference to Pertinent Content From SAES-D-108 ............................ 141 Work Aid 4C: Reference to Pertinent Content From API-653.................................... 141 Shell Settlement Evaluation ...................................................................................... 141 Bottom Settlement Evaluation................................................................................... 142 GLOSSARY .................................................................................................................... 143

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Vessels Determining Requirements for Repair or Alteration of Storage Tanks

APPLICATION OF SAES-D-108 AND API-653 TO THE REPAIR OR ALTERATION OF EXISTING STORAGE TANKS Prior modules focused on the Saudi Aramco and industry requirements that apply to new atmospheric storage tanks. After a tank has been placed into service, it is treated as an existing tank rather than as a new tank, and different engineering standards are applied to its evaluation. Existing storage tanks may experience various forms of deterioration or changes in application requirements that could result in the need for repair or alteration. The primary engineering 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 and alteration of existing atmospheric storage tanks. SAES-D-108 uses API-653 as the base reference 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 be resolved by the Saudi Aramco Manager of the Consulting Services Department at Dhahran.

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

API-653 applies to carbon and low-alloy steel tanks that were built in compliance with the requirements of API-650, Welded Steel Tanks for Oil Storage, and its predecessor API-12C, API Specification for Welded Oil Storage Tanks. The majority of tanks will be of carbon steel construction.

•

API-653 provides minimum requirements for maintaining the integrity of welded or riveted, nonrefrigerated, atmospheric, aboveground storage tanks after 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 rather than riveted tank construction is now used, many existing riveted tanks are still in service, and they must be maintained in acceptable operating condition. Note that refrigerated, low-pressure, and/or underground storage tanks are not within the scope of API-653. However, many API-653 requirements are general enough to also apply to these other tank types. Thus, API-653 may be used as an information resource and guideline to help develop appropriate inspection and maintenance programs for these other tank types.

•

API-653 covers maintenance inspection, repair, alteration, relocation and reconstruction. This scope ensures that any work activity which could affect a tank's suitability for its intended service is included.

•

API-653 is limited to the foundation, the bottom, the shell, the structure, the roof, attached appurtenances, and nozzles up to the face of the first flange, the first threaded joint, or the first welded-end connection. These components are the primary components that relate to the tank's structural integrity and/or could have a significant environmental impact should their condition not be acceptable.

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•

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 governing document once a tank has been placed into service. Should there be conflicts among the various tank-related design standards, the governing standards hierarchy 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 some API-650 requirements within its procedures. In addition, API-653 requirements still must be considered in new tank design because API-653 requirements can affect several design decisions that must be made. For example, API-653 specifies minimum acceptable bottom plate thickness requirements after a tank has been in service. In certain situations, the minimum acceptable bottom plate thickness may require the use of a thicker bottom plate for a new tank than API-650 requires as a minimum. The thicker bottom plate may be needed in order to have an acceptable tank bottom inspection interval and design life. API-653 is intended for use by qualified engineering and inspection personnel who are experienced 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 requirements for a specific situation, the intent is to provide tank integrity that is equivalent to current API650 requirements. Many owner companies have used internally developed inspection, repair, and maintenance practices prior to the introduction of API-653. Now that API-653 exists, it must be considered by all companies that have atmospheric storage tanks. Companies that have established tank inspection, repair, and maintenance procedures should review them with respect to API-653. Companies that have less formal procedures will be under increased pressure to meet API-653 requirements as a minimum.

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Application of SAES-D-108 and API-653 API-653 is divided into several major sections, and SAES-D-108 modifies several of these sections. The following paragraphs describe the application of several of these sections in general 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 tank suitability for service. In other words, is the current tank integrity acceptable for the intended operation? In addition, will the integrity still be acceptable during the entire next period of operation until the tank is taken out of service again and inspected? An engineering evaluation must be performed when inspection results indicate that a change has occurred from the original physical condition of the tank. Thus, conformance to API-653 requirements means that inspection data cannot just be filed away and forgotten. Inspection data must be evaluated to confirm that the tank integrity is still acceptable for continued service at the intended design conditions. Tank suitability for service also must be assessed when considering a change in service, repairs, alterations, dismantling, relocation, or reconstruction. 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 point where it is no longer structurally sound? Is the bottom in danger of "holing through" and leaking?

•

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

•

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

•

Design metal temperature. Has the tank service changed such that a lower design metal temperature must be considered than was used in the original design?

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•

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

•

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

•

Chemical analysis and mechanical properties of the tank materials. These items will not change since the tank was originally constructed, but these items are factors that must be considered when the structural integrity of the tank is evaluated.

•

Distortions in the shell or roof. These distortions might indicate that there have been problems with excessive internal or external pressures. Such problems could be caused by higher than design filling or emptying rates or by improper vent operation.

•

Changes in operating conditions, such as filling and emptying rates or frequency. 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 of the tank's primary structural components with respect to API-653 acceptance criteria. The primary structural components that are evaluated are those structural components that directly affect 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 contained in API-653 with respect to assessment of the bottom. Saudi Aramco accepts the other API653 suitability-for-service requirements.

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Repairs and Alterations Storage tank repairs are required when the structural integrity of the tank has been reduced to the point where the tank is no longer suitable for the desired service. Typical examples of storage tank repairs are as follows: •

Removal and replacement of material that is required in order to maintain tank integrity, such as portions of the shell, roof, or bottom. This material includes weld 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 following areas: •

Removal and replacement of shell plate material

•

Repair of defects in shell plate material

•

Change of shell height

•

Repair of defective welds

•

Repair of shell penetrations

•

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

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

Removal and replacement of shell plate material

•

Repair of shell penetrations

•

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 that completed fillet weld repairs be examined by wet fluorescent magnetic particle inspection over their full length. Dismantling and Reconstruction There are sometimes situations when it might be advantageous to dismantle an existing storage tank and to reconstruct it in another location. For example, an existing storage tank might 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, rather than construct a new tank. A great deal of cutting and rewelding is required to dismantle and to reconstruct an existing storage tank. The reconstructed tank must have acceptable mechanical integrity for the service conditions, especially with respect to brittle fracture resistance. Fracture toughness and brittle fracture were discussed in MEX 203.02. It is especially difficult to confirm acceptable mechanical integrity if the tank to be reconstructed is more than about 25 years old. The materials that were used to construct old tanks will not meet current fracture toughness requirements, and thus these old tanks are more prone to failure due to brittle fracture. In addition, if the construction material is unknown, it must 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 was constructed with material that does not meet current fracture toughness requirements increases the risk of brittle fracture still further.

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One of the prime factors that initiated the preparation of API-653 was a catastrophic brittle fracture of a fuel oil storage tank that occurred in the late 1980's in the U.S. This failure occurred the first time that the tank was filled after it had been reconstructed, and it resulted in a major fuel oil discharge into a nearby river. Therefore, the reconstruction requirements that are contained in Sections 5, 6, and 8 of API-653 are conservative, especially those requirements 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 and reconstruction. Hot Tapping A "hot tap" or "hot tapping" refers to the procedure that is used to add a new nozzle to a storage tank, pipe, or pressure vessel without taking the storage tank, pipe, or pressure vessel out of service. Adding a nozzle by hot tapping is sometimes advantageous because of operational considerations. Adding nozzles by hot tapping is not an uncommon practice, especially in piping systems. However, since there are inherent risks associated with adding nozzles while a storage tank or pipe is still in service, this procedure should only be used where 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 a flanged end.

•

Pressure-testing the nozzle connection.

•

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

•

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

•

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

•

Closing the valve and removing the hot tap machine.

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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

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

•

•

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

Additional engineering calculations to ensure that the shell thickness is adequate

-

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 may form in this area, and it may be ignited by the heat from the hot tap cutting 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 be done with the tank in service.

-

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

Connection size and shell plate thickness limitations are as provided in Figure 2:

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Connection Size, NPS

mm

Minimum Required Shell Plate Thickness

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 thickness measurements must be made of the tank shell plate where both the nozzle and reinforcing pad welds 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 on the thickness that is required to prevent burning through the plate while the nozzle is welded to the shell. These thicknesses are not necessarily sufficient for the hydrostatic head or other design loads that are imposed on the tank. The shell thickness must be checked separately for these other loads. API-653 requires that shell plate thickness measurements be taken in at least four places along the circumference of the proposed nozzle location. Four locations are adequate for relatively small diameter nozzles in tanks where localized corrosion is not expected. However, more measurements may be required for larger diameter nozzles or in locations where localized corrosion 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 the welds. This minimum spacing requirement is to avoid excessive localized stresses that might develop due to the proximity of geometric discontinuities.

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•

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 met current API fracture toughness requirements. Meeting current API fracture toughness requirements means either that the steel was exempt from impact testing, or that it was impact-tested at the design metal temperature. Steels that are of unknown fracture toughness may be hot tapped if the minimum shell metal temperature during the hot tap meets or exceeds the exemption curve in Figure 7-5 of API-653 based on the plate thickness where the hot tap is being done. In this case, the steel is known to have fracture toughness that is sufficient to not have a brittle fracture while the hot tap is being done.

•

Welding shall be done using low hydrogen electrodes.

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

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

•

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

•

-

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

-

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

-

Certain unsaturated hydrocarbons, such as ethylene, that may undergo an exothermic decomposition reaction due to the welding or cutting heat that occurs during hot tapping.

Appropriate plans and procedures must be prepared. These plans and procedures must include appropriate design, welding, inspection, and safety requirements.

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•

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 otherwise rendered inoperable.

-

All mixer operations must be stopped.

-

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

•

Turn off all heating coils during hot tapping. Turning off the coils will help to dissipate 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 when welding or cutting is being done. This liquid level will help to dissipate the heat that is generated, and it will help to keep the hot tapping sufficiently below the vapor space.

•

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

Owner companies such as Saudi Aramco typically have their own detailed hot tap procedures and restrictions that build upon the API-653 and API-2201 requirements. Saudi Aramco requirements are highlighted in the section that follows. SAES-D-108 Requirements - SAES-D-108 requires that a stress analysis be performed for hot taps that are larger than 460 mm (18 in.) pipe size. Recall that API-653 minimum acceptable shell thickness requirements stop at this pipe size. Therefore, Saudi Aramco would permit larger diameter hot taps, but they are treated as special cases. The Consulting Services Department should be consulted for these situations. SAES-D-108 refers to Saudi Aramco General Instruction G.I. 441.010, Installation of Hot Tapped Connections, for requirements that are related to installation procedures, organizational responsibilities for various phases of the work, and safety considerations. The detailed emphasis of G.I. 441.010 is on hot taps that are made into piping systems because these comprise the vast majority of all of the hot taps that are made. However, the overall safety and procedural requirements that are contained in G.I. 441.010 apply to storage tank hot taps as well. The paragraphs that follow highlight the primary organizational responsibilities for hot taps. Participants are referred to G.I. 441.010 for detailed information.

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A Saudi Aramco area maintenance or construction organization will typically initiate a request for a hot tap by providing general descriptive information of the requirements on Form A-7627. The initiating engineer will generally serve in a coordination and follow-up role among the appropriate operations, inspection, engineering, and maintenance organizations throughout the hot tap procedural process. The maintenance or construction organization 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 appropriate safety, work permit, and operating procedure requirements. Engineering is responsible for the following: •

Development of the required design details and drawings for the hot tap connection 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 area where the welding will be done.

•

Welding procedure approval.

•

Inspecting the connection before and during the installation for compliance with the specifications.

•

Witnessing and approving the hydrotests of the hot tap valve and the installed nozzle.

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STORAGE TANK INSPECTION INTERVAL REQUIREMENTS Storage tank components will deteriorate to some extent after they have been exposed to the operating conditions. This deterioration must be identified before it affects the structural integrity of the tank so that appropriate repairs and maintenance are done on a planned basis rather than on an unscheduled basis. Storage tanks must be inspected by qualified inspectors at reasonable intervals in order to determine the current condition of the storage tanks and to permit assessment of their suitability for continued service. Tank integrity assessments cannot be made unless tanks are inspected at regular intervals. The sections that follow discuss the primary reasons for inspecting a storage tank, the SAEP-20 requirements for inspection intervals, and the Inspection and History Report that is used to document the tank's condition as determined from inspections that have been done. Reasons for Inspection In order to determine their physical condition and the type, rate, and causes of deterioration that may have occurred, storage tanks are inspected after they have been placed into operation. The information that is obtained from each inspection must be recorded to permit both current evaluation and future reference. Periodic inspection is necessary to determine whether the structural integrity of the tank is still acceptable and whether the tank remains safe for continued operation. Before the condition has deteriorated to the point where leakage of hazardous fluid or other failures occur, trends in tank condition can be identified and appropriate corrective action can be taken. Such leakage or tank failure would cause an unplanned shutdown with consequent disruption in operational plans. Periodic inspection permits the development and execution of a planned maintenance and repair schedule. Corrosion rates and remaining corrosion allowances can be predicted based on the inspection results. This corrosion rate and remaining corrosion allowance information is then used to identify and plan for the necessary materials, labor, time, and costs that are required to keep the storage tank in acceptable operating condition. External inspections may be made visually or with other nondestructive techniques while the tank is in operation and still closed. These operational inspections may identify problems such as the following: •

Leaks

•

Shell distortion

•

Obvious shell settlement or foundation damage

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•

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 the development of appropriate corrective action, it can prevent more extensive damage, and it can 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 are not visible from the outside of the tank. The following are several reasons for doing an internal tank inspection: •

To identify any severe corrosion or leakage of the bottom.

•

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

•

To identify locally corroded areas of the shell that were not identified by any external 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 inspected periodically, and notes many of the types of deterioration that must be considered.

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Figure 3. Inspection Locations and Tank Deterioration

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

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

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

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SAEP-20 Requirements for Inspection Intervals Section 4 of API-653 specifies tank inspection interval requirements for external inspection with the tank in-service and internal inspection intervals with the tank out-of-service. Saudi Aramco terminology for these inspections, as defined in SAEP-20, Equipment Inspection Schedule, 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 than based on API-653 requirements. API-653 also divides external inspection into routine inservice inspection and scheduled inspection. This concept of dividing the external inspection and the general considerations that are contained in API-653 still apply with SAEP-20 inspection interval requirements. Several factors that must be considered in the determination of suitable inspection intervals are 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 the original design, and what has been the actual experience?

•

Corrosion prevention systems. Is there an internal lining or cathodic protection system installed?

•

Conditions at previous inspections. What deterioration was already identified and where was it?

•

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

•

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

•

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

•

Is a leak detection system installed?

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•

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

•

Local jurisdictional requirements. Do local governmental authorities require specific inspection frequencies?

As stated earlier, storage tanks must be inspected at reasonable intervals to determine their current condition and to permit assessment of their suitability for continued service. Saudi Aramco develops tank inspection interval requirements based on procedures that are contained in SAEP-20. SAEP-20 also contains procedures that must be followed to extend or to deviate from the inspection intervals that were originally established, and it assigns implementation responsibilities to specific Saudi Aramco organizational functions. SAEP-20 requires that an Equipment Inspection Schedule (EIS) be developed for tanks that are in the following categories: •

Utilities, production, processing, storage, and transportation of oil, gas, and byproducts.

•

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

•

Critical equipment (i.e., equipment that cannot be inspected by any means except 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 of the Project Record Book. The EIS must be submitted for approval 30 days prior to completion of the facility. The approval process involves Saudi Aramco Project Management, 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.

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SAEP-20 contains procedures that classify fixed equipment, including storage tanks, with respect to Corrosion Service Classes. Table II of SAEP-20 defines four Corrosion Service Classes based on corrosion rate (or special problems). The maximum OSI and T&I inspection intervals are then determined, primarily based on these Corrosion Service Classes, and on other 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 ground on a routine basis by personnel who are familiar with storage tanks but who are not necessarily qualified inspectors. For example, these routine visual inspections may be done by operations or maintenance personnel who must be in the area as part of their primary job function. The intent of the routine inspections is to identify questionable items that should be examined in more detail by qualified inspectors. Formal external inspections must be made by qualified inspection personnel on a scheduled basis. The OSI interval is determined by criteria that are contained in SAEP-20. The required OSI interval is determined based on the anticipated or measured corrosion rates, past experience, and any findings that are obtained from the routine in-service inspections that were 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 provides information that may be used to adjust T&I intervals that were initially specified, if appropriate, based on actual inspection results. OSI can be done at any time. However, based on Table II of SAEP-20, the maximum interval for the initial OSI for tanks will be in the range of 12 to 24 months, based on the Corrosion Service Class of the tank. There is some flexibility in setting this initial OSI interval, and the Area Operations Inspection Unit should be consulted to finalize the initial OSI interval based on the general factors that were previously 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 prior inspections. The maximum subsequent OSI interval that is determined on this basis should be no more than the smaller of one-fourth of the remaining life, or five years.

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Out-of-Service Inspection (T&I) Internal inspection intervals (i.e., T&I intervals) are determined, based on prior corrosion rate experience with other tanks in similar service and experience with the particular tank that is being evaluated if prior inspection data is available. This T&I interval is determined by criteria that are contained in SAEP-20. In most cases, internal inspection intervals are determined based on bottom corrosion rates. The time interval for internal inspection must be set to ensure that the bottom does not thin below values that are specified in API-653 before the next internal inspection. The intent is to prevent a hole in the bottom that would permit even a small leak of liquid from the tank. Bottom leaks can continue for a long time before any 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 inside surfaces 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 to obtain more data to help to set or to adjust subsequent T&I intervals. Saudi Aramco has a great 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-20 to set an I-T&I. The I-T&I interval would then be set at 24 months for all Corrosion Service Classes based on Table I of SAEP-20. The subsequent T&I intervals are based on equipment and service conditions or operating experience, and they are determined by application of the following factors: •

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

•

Service Criteria. The subsequent T&I interval can be no more than that determined 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 of SAEP-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 thickness survey for pitting is passed 6 to 12 months before the start of the scheduled interval.

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Inspection and History Reports Historical inspection records are important because they form the basis for developing a scheduled tank inspection and maintenance program. Section II of API-653 requires that the owner/operator maintain a complete record file for each tank. The record file must include information on construction details, calculations, inspection history, and repair/alteration history. This information helps to determine appropriate inspection intervals based on actual experience, and it identifies any changes that were made to the tank that could affect its structural integrity. In situations where records do not exist for a particular tank, judgments must 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 is done during a T&I, and it forms the basis of the tank's historical records. A typical storage tank Inspection and History Report will include at least the following sections: •

Identification and Documentation Information. This section includes items such 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 as well as the inspection methods that were used (such as visual observations and ultrasonic measurements). The use of any special inspection techniques should be documented. This section also summarizes the tank's history, such as when it was placed into service, when the last T&I was done, and any significant inspection findings or repairs that were made during the last T&I. The Equipment Inspection Schedule (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 he should have identified any operating difficulties that occurred during the last period of operation prior to the T&I. Anything unusual in the operating history should be documented in the report because an operations factor might have contributed to problems that are noted during the inspection. This tank history review should also include whether any problems were found on similar tanks during their T&Is that affected how the current inspection was conducted.

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•

Observations and Recommendations. This section provides the results of the inspection, and it is divided into subsections based on the main tank components (such as shell sections, roof, bottom, nozzles, and foundation). The visual observations of the inspector are recorded for each component, as are 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 identify the locations of the thickness measurements or other observations that are made. Locating the observations and measurements in this manner helps to identify the potential causes of problems, and it highlights areas to inspect during subsequent T&Is. Inspection of the same locations during T&Is helps to establish trends in tank deterioration, especially corrosion.

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

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Inspection and History Reports, cont'd Figures 4 and 5 provide overall formats that summarize the primary sections and information that 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

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Sketch of Tank Shell or Bottom With Thickness Measurement Points Indicated Prepared By Inspector

Thickness Data Point Number

Original Nominal Thickness

Minimum Required Thickness

Measured Thickness

Figure 5. Inspection and History Report Thickness Measurement Data

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DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR STORAGE TANK SHELLS AND SHELL PENETRATIONS This section discusses the evaluation of storage tank shells and shell penetrations of existing storage tanks. In each case, the existing condition of the storage tank is considered together with 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 the tank shell during operation. In order to determine the continued suitability of the tank shell for the intended service, the condition of the tank shell must be quantified by inspection, and it must be evaluated by experienced engineering personnel. The possibility that the tank condition will deteriorate further during the next period of operation must be considered in performing this evaluation. For example, if corrosion has occurred, further corrosion during the next period of operation must be considered. Thus, the current tank condition may be acceptable for the design loads, but future corrosion may make the tank condition unacceptable 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 a corroded tank shell for the hydrostatic head. Other situations will be discussed briefly in later paragraphs. Shell corrosion may be classified as either general corrosion or pitting corrosion. This distinction must be made because a different evaluation approach is used for each type of corrosion. General Corrosion A corrosion site will be classified as general corrosion when the material has thinned in a relatively uniform manner over the area. At a general corrosion site, the main concern is how much thickness has been lost. If too much thickness is removed, the corroded area of the shell can no longer sustain the loads that are imposed during normal operation, and a shell failure may result. Recall from MEX 203.03 that the determination of the required shell thickness is based on both an allowable stress and the imposed hydrostatic head from the stored liquid. Therefore, if the shell corrodes too much, the resulting stresses can exceed the allowable stresses with the original design liquid fill height.

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Pitting Corrosion Pitting corrosion is when the material has been removed in a very localized area, giving a crater-like appearance to the surface. Pits can be very deep or shallow and be of varying diameters. Pitting is not of great concern as a threat towards the overall integrity of the shell unless the pits are present in close proximity to each other and unless they are very deep and extensive. However, pits can result in local leaks if they progress through the entire shell thickness. Tank Shell Evaluation Evaluation of shell corrosion consists of determining if the current condition of the shell is adequate for the tank service. If a change in tank service is being considered, the shell must be evaluated for the new service conditions. For example, if the stored liquid will be changed to one with a higher specific gravity, the higher specific gravity must be considered in the evaluation. The evaluation must consider all anticipated loading conditions and load combinations, not necessarily just the hydrostatic pressure load. These conditions are the same conditions that were originally considered when the tank was designed (refer to MEX 203.03). The evaluation must also consider any future corrosion that may take place until the next T&I. Consideration of any future possible corrosion helps ensure that the tank will be structurally 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 shell stresses within allowable limits.

•

The tank may need to be retired.

When the current shell condition is found to be unacceptable, which option is taken depends on the extent of repairs that are required, the available time to make the repairs, and the cost of such repairs. Actual Thickness Determination Ultrasonic (UT) measuring devices determine the thickness of the shell over a small area that is covered by the UT transducer. UT measurements are satisfactory for determining the overall shell thickness in the area of the transducer, but the transducer area is too large for satisfactory determination of the shell thickness for pitting types of corrosion. Therefore, a pit gauge is used to determine the amount of penetration (i.e., depth) in a corrosion pit. A pit

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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.

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A general UT thickness survey of a tank will typically require a minimum of three readings on 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 areas that obviously have extensive corrosion. For the corroded areas, the thickness readings are taken by means of a grid pattern that is placed over the area in order to permit detailed evaluation. The amount of inspection can be increased further, if appropriate, based on the initial evaluation results. The minimum thicknesses that are found from the UT survey may be used directly in the shell integrity assessment. As long as use of the minimum thicknesses does not result in the need for either repairs or a fill height restriction, there is no incentive to inspect or evaluate the shell further. However, API-653 permits a less conservative but technically acceptable approach 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 integrity assessment. The basic concept that is employed here is that thicker areas in a corroded region serve to reinforce areas that are more corroded. An analogy is the use of excess metal that is available in a pipe or pressure vessel shell as reinforcement of a branch connection. Work Aid 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 that must be satisfied for pits to be considered "widely scattered." The rationale here is that as long as the pit depth and spacing are within the stated limits, they will not decrease the structural integrity of the tank shell. If the pits cannot be considered "widely scattered," they must 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 the minimum required thicknesses in order to determine if the actual shell thicknesses are acceptable. Work Aid 1 contains the procedure for calculating the minimum required thicknesses. The following paragraphs highlight several considerations with respect to this procedure. •

Unlike API-650, API-653 uses a slightly more conservative allowable stress basis for the bottom and second courses than for the upper courses. Recall from MEX 203.03 that for the design of a new tank, the shell plate allowable stress (design or hydrotest case) is only a function of material specification and is not based on a consideration of what shell course the plate is in. This increased conservatism in API-653 is due to the generally more complex stress distribution in these lower courses that is not being accounted for in the evaluation. In spite of this, the API-653 allowable stress basis is slightly more liberal than API-650 in order not to be overly conservative while still being safe.

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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 allowable stress that corresponds to a relatively weak carbon steel. Thus, if there is no documentation that a stronger material was actually used, a significant fill height restriction might be required even if there has been no corrosion. •

The original weld joint efficiency must be used in the thickness calculation procedure. However, if the original weld joint efficiency is unknown, a very low weld joint efficiency of 0.7 must be used. Here again, use of this low weld joint efficiency could result in a significant fill height restriction even without corrosion. API-653 permits making a distinction between areas that are near welds and those areas that are away from welds with regard to the use of weld joint efficiency in the shell evaluation. A weld joint efficiency of 1.0 may be used when evaluating corroded areas that are far enough away from welds. Therefore, use of the original joint efficiency (or 0.7 if unknown) when evaluating corroded areas that are located away from welds is too conservative and not required. If use of the weld joint efficiency is a significant factor for a particular tank, additional inspection data that locates corroded regions with respect to tank shell welds could be helpful.

•

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

•

If the relatively simple hand calculation procedures that are contained in API653 find that the tank is unacceptable, API-653 permits the use of the "design by analysis" approach that is contained in Section VIII, Division 2, Appendix 4 of the ASME Code. This approach requires detailed computer calculations and more thickness inspection measurements to accurately model the corrosion as well as to categorize and to evaluate the stresses. However, a tank that is found to be unacceptable by the simple procedures is often found to be acceptable when the Division 2 procedures are used.

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

Figure 6. Localized Shell Corrosion

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Minimum Thickness Calculation for Riveted Tank Shell All new tanks that are designed and constructed in accordance with API-650 are of welded construction. However, there are many older tanks that are still in service and that are of riveted construction. In these older tanks, the individual shell plates are attached to each other by rivets, as illustrated in Figure 7.

Figure 7. Riveted Shell Construction

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As shown in Figure 7, two shell plate attachment details were used in riveted shell construction. 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 placed both inside and outside of the shell such that the shell plates are located between the butt straps, 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 determined during detailed engineering based on the required design loads. The shell thickness for riveted tanks is evaluated through use of the same minimum thickness formula 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 are within 150 mm (6 in.) of rivets. These rivet joint efficiencies are based on both whether the joint 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 allowable stresses that are specified in API-653 must be used if calculated rivet joint efficiencies are used. 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 current fracture toughness requirements. Therefore, the design details and installation procedures that are used for any welded repairs or alterations must be carefully reviewed to ensure that they do not increase the risk of brittle fracture.

•

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

Other Shell Evaluations The calculations that have been discussed thus far consider only liquid loading. Liquid loading is generally the limiting factor in tank shell evaluations. However, API-653 requires the evaluation of other loads in accordance with the original construction standard. These other loads include the following: •

Wind-induced buckling

•

Seismic loads

•

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

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•

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 are considered in the evaluation. CSD should be consulted as needed for assessment of these other 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 amount of required repair implies that the defect is small.

•

If a replacement plate is required to repair the defect, the replacement plate is no larger than 300 mm (12 in.) on any one side. This amount of repair is considered to be small.

Work Aid 1 defines criteria for when repairs must be done and requirements that must be met for 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

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The need to repair minor defects such as those listed above, is determined on an individual basis. If the defects are located in areas of the shell where the plate thickness exceeds the thickness required by the design conditions, grinding the defects to a smooth contour without further repair is permissible. This grinding is done in order to minimize localized stress concentration effects that are due to any abrupt geometric changes that are associated with the defect. In situations where grinding thins the plate to an unacceptable level (i.e., thinner than is required to resist the design loads), weld metal must be added to repair the defect. A qualified 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 replacement insert plates that are more than 300 mm (12 in.) on a side in order to restore the tank to the required structural integrity. The most common situation where this amount of repair is required is if there is extensive general corrosion or severe pitting. Other possible major shell defects include excessive shell distortions or laminations. Work Aid 1 defines criteria for when 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 the repairs must restore tank integrity, the repairs themselves must not make the existing tank integrity worse, and current API-650 requirements must be met to as great an extent possible in making the repairs. The paragraphs that follow highlight several of the primary requirements regarding the repair of major shell defects. •

The replacement plate material, welding and welder qualifications, and welding consumables must meet current API-650 requirements. These requirements ensure that all new components and welding have the same integrity as in current new tank construction. The primary concern is to not increase the risk of 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 new welds too close to each other. Weld shrinkage stresses could become excessive and lead to excessive distortion if the welds are too close together.

•

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

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•

Minimum distances are specified between the new replacement plate welds and the existing welds that are in the shell. Acceptable distances between welds are based on shell plate thicknesses, and different distances are specified for each type of shell weld (i.e., vertical, horizontal, shell-to-bottom, or radial bottom plate welds). The intent of these minimum distances is to minimize the effect that 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 are required. When weld repairs are required, the defective area must be completely removed, a suitable 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 a weld or not. However, a root-cause assessment is more important for a weld defect because the cause might be less obvious. The primary questions that must be answered in doing a root-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 defect influences 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 tank operation? For example, a lack of penetration or weld undercut is an original fabrication defect. A crack could be an original fabrication defect as well. However, a crack could also be caused by excessive local loads, such as loads from a piping system or excessive settlement.

•

How extensive is the defect and where is it? For example, cracks will almost always 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 is thick enough for the imposed loads. Less than full penetration at a weld may also not require repair if the weld is at a high enough elevation in the tank shell such that the actual weld thickness is sufficient for the imposed loads.

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Alteration of Shells to Change Height It is sometimes desirable to increase the existing shell height in order to increase storage capacity of the tank. Increasing the shell height is permissible as long as the following items are considered in the evaluation. •

The existing shell course thicknesses must be evaluated for acceptability based on 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 not been significant corrosion or where the originally supplied plate thicknesses exceeded those that were required. However, from a practical standpoint, it would 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 seismic loads. A higher shell for a floating roof tank makes the shell more prone to wind-induced buckling. Therefore, the existing wind girder design must be checked. A higher shell also increases the maximum tank overturning moment due to wind or maximum seismic loads.

•

All design and installation details must meet the same requirements as for the repair 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.

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Figure 8. Sample Problem 1 Tank

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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 following deterioration was found and was noted in the Inspection and History Report that was prepared: •

There is an area of almost uniform corrosion in the bottom shell course. The thickness 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 an elevation of 5 ft. above the bottom of the tank. The thickness readings were made along a length of 28 in.

•

A single deep pit is located in the third shell course and is 4 ft. below the top of the course. The pit measures 0.5 in. deep and is approximately 0.5 in. in diameter. 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 same design 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 is required.

•

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.

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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 acceptable for averaging. L = 3. 7 Dt2 D = 100 ft. t 2 = 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 measurements were 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 corroded region, tmin. t min =

2.6D(H − 1)G SE

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

(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 shell has adequate thickness in this corroded area today. But what about future corrosion in the 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 based on the desired T&I interval of 10 years. It must also be confirmed that this 10 year interval is no more than half the remaining tank life. Based on the previous results, it is clear that the (tmin + CA) criterion is the governing case. First calculate the remaining corrosion allowance. CA/remaining = 0.722 - 0.56 = 0.162 in. Re maining Life =

CA / remaining CorrosionRate

=

0.162 0.00467

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.

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•

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. t min =

(2.6)(100 )(41− 1)(0. 85) (28 320 )(0. 85)

= 0.367 in. 0.5 = 0. 0333 in. /year The pitting rate was 15 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. 0.5t min + (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 of the shell must be repaired. There is no reason to also check the pit using the "half remaining life" criterion because the pitted area has already failed the first evaluation criterion. Because there is only one isolated pit, a weld overlay repair is sufficient. A qualified weld procedure and welder must be used to make this repair.

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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 in Work 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 a new feature that requires a nozzle, or to replace a deteriorated nozzle. The following are several examples of when a new shell penetration is required: •

The tank service may change to one that requires heated storage rather than ambient temperature storage. In this case, nozzles are required to add either heaters or steam circulation pipes.

•

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

•

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

A new or replacement shell penetration will typically be added during a T&I. Penetrations may also be added by hot tapping, if they are not flush type connections, as long as the requirements 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 are significant economic incentives to hot tap. In all cases, new or replacement shell penetrations must either meet API-650 or API-653 requirements. This requirement ensures that the new penetration itself meets current integrity requirements and will not adversely affect the structural integrity of the existing tank shell and associated shell welds. It is especially important to meet the requirements for minimum distance between new and existing welds and to meet the nozzle reinforcement requirements.

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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 not have one already. Reinforcement plate addition may be necessary to resist the imposed hydrostatic loads or piping loads.

•

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

In each case, it is preferable that the modified shell penetrations meet current API-650 requirements. These requirements include the minimum reinforcement area and the minimum permitted spacing between adjacent welds. However, Saudi Aramco’s normal practice is not to mandate that shell penetrations be elevated in order to meet API-650 reinforcement and elevation requirements. Instead, CSD has analyzed each case in order to ensure safe design and 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 an existing nozzle. In each case, the new reinforcing plate must be split into two pieces in order to fit over the neck of the existing nozzle, and the plate is then fillet welded to the tank shell and nozzle neck. Each reinforcing plate piece is drilled with a telltale hole that permits pressure testing the reinforcing plate welds. The detail that is shown in Figure 9 is acceptable as long as the distance between the reinforcing plate weld to the shell and the shell-to-bottom weld does not violate the API-650 minimum spacing requirements between adjacent welds. The "tombstone type" reinforcement that is shown in Figure 10 is required for nozzles where the reinforcement plate weld to the shell would be too close to the shell-to-bottom weld. The "tombstone type" reinforcement plate extends down to the tank bottom (or annular plate) and is welded to both the bottom (or annular plate) and the shell.

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Figure 9. Reinforcement Plate Added to Nozzle

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

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

The existing reinforcing plate may be trimmed to increase the space between the welds provided that the modified reinforcement plate detail meets API-650 requirements. The trimming must be done carefully in order not to damage the shell plate. The attachment weld for the portion of the reinforcement plate that is removed must also be removed by gouging or grinding. Most situations cannot be handled in this manner because there will not be enough reinforcement left after the trimming is done.

•

The existing reinforcing plate may be completely removed and then a new reinforcing plate can be added. The conceptual details that are used for this option are the same as for adding a new reinforcement plate as shown in Figures 9 and 10. Again, the shell plate must not be damaged and the existing reinforcement plate welds must be removed. This option is acceptable as long as the distance between the nozzle centerline and the new tank bottom is not less than what is required for an API-650 "LowType" nozzle (see Table 3-8 of API-650).

•

The last option that may be considered is to relocate the existing nozzle to a higher position on the shell in order to meet the minimum weld spacing requirements. This relocation is done by cutting the shell section that contains the nozzle and its reinforcing plate and raising the entire assembly to the correct elevation. Figure 11 illustrates this option.

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

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Figure 11. Raising Nozzle Assembly

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DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR STORAGE TANK 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 made during a T&I. The bottom condition is then evaluated using Saudi Aramco and API requirements to determine if the bottom is acceptable for continued operation. Work Aid 2 contains 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 to the extent that significant repairs are required. Corrosion not only affects refinery storage tanks, but corrosion also affects storage tanks that are in production, terminal, pipeline, and marketing 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 of bottom 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 a coarse (greater than 19 mm [3/4 in.] size) and poorly meshed aggregate is used in the tank pad. Figure 12 illustrates the corrosive action that may occur around aggregate. There is a low 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 between adjacent locations along the bottom establishes an electrochemical potential and results in pitting-type corrosion, which is known as oxygen concentration cell corrosion.

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Figure 12. Oxygen Concentration Cell Corrosion Water acts as an electrolyte in the process of oxygen concentration cell corrosion. Moisture may be present on the underside of the bottom plates due to tank settlement, poor tank pit drainage, 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 tank bottom. The resistivity of the soil also affects the rate of corrosion because the soil is part of the electrical circuit. Treated crushed-stone foundations, oiled sand, and compact hot asphalt road mix have high resistivities and also limit the presence of water on the underside of the tank bottom. However, other foundation pad materials may have low resistivities. Low resistivities increase the chance for current flow and accelerate the rate of corrosion. This oxygen cell pitting corrosion is extremely aggressive and can hole through a tank bottom in only a few years.

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The underside of the bottom plates may also experience corrosion if the tank pad materials contain chemical contaminants that have highly corrosive sulfur compounds. This situation would 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 cause external corrosion. This type of corrosion frequently takes the form of a general metal thinning. 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 can occur between double bottoms, between nearby structures and the tank bottom, or between active and noble areas of the same tank bottom. Stray electric currents may also be a source of 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 on the 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 with sulfur compounds and produces an acidic condition. The acidic condition promotes corrosive attack. 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 tanks with each new batch of oil or product that enters the tank. Gasoline and other nontreated light products do not normally contain acidic impurities, such as 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 can migrate to the bottom water layer and induce a small, but overall uniform, corrosion rate of approximately 0.025 to 0.05 mm/yr. (1 to 2 mil/yr.). The considerable distance from the vapor space, that is the oxygen supply, to the bottom brine layer limits the oxygen concentration. 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 surface deposit (e.g., mill scale) or a crevice exists on the metal surface and creates an area of low oxygen concentration. The internal side of tank bottoms usually experiences this corrosion due to deposited wax or other debris. The accelerated pitting that results may occur at rates of 0.5 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-reducing bacteria 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 "knife edge" corrosion can cause severe metal loss, especially if a bottom coating that has been applied has failed in the area of the weld.

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Minimum Thickness for Tank Bottom Plate Leaks from the tank bottom are not acceptable because the leaking liquid will proceed directly into the foundation and eventually migrate further away from the tank. If these leaks are left unattended for an extended period of time, the leaking liquid could eventually undermine the foundation and lead to a more serious bottom failure that results in more severe leakage. In any case, even small hydrocarbon or chemical leaks result in environmental pollution concerns that cannot be ignored. Unfortunately, a tank bottom may have been leaking into the 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 entire floor should be visually examined for holes, cracked welds, and any areas that were previously repaired. All floor seams and the bottom-to-shell junction weld should be tested using 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 pattern to identify thinned areas. Additional readings should be made near any thinned areas that are found, or other regions where increased corrosion may be expected (such as near the sump or shell), to better define the situation. As previously discussed and illustrated in Figure 13, bottom plate corrosion may include general corrosion and pitting corrosion. In most cases, general corrosion will occur on the topside while pitting corrosion may occur on both the topside and underside.

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To = Original Plate thickness Figure 13. Bottom Plate Corrosion Bottom plate thickness measurements must be made in sufficient quantity and accuracy to be able to assess the current condition of both the topside and underside with respect to general corrosion and pitting-type corrosion, and to determine the general corrosion rate and pitting rate. The remaining bottom thickness must be quantified and compared to allowable limits that are specified in API-653. The minimum permitted bottom plate thicknesses are not based on any stress criteria. The minimum permitted thicknesses are intended to provide a safety margin before "holing through" the bottom, and assume that the bottom is still supported uniformly. Any condition of nonuniform support or settlement, and its impact on required thickness, must be evaluated separately.

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Work Aid 2 provides the procedures and requirements to follow when the condition of an existing tank bottom plate must be evaluated. The paragraphs that follow highlight several aspects of bottom evaluation. Bottom Thickness Calculation API-653 permits two alternative methods for quantifying the remaining thickness of a tank bottom: the deterministic method and the probabilistic method. Deterministic Method - The deterministic method requires that the remaining bottom thickness, as calculated by two different equations, be at least equal to the minimum thickness that is required by API-653. Both equations consider the original bottom plate thickness, general corrosion, topside and underside pitting (average and maximum), corrosion rate, and pitting rate. In each case, the equation starts with the original plate thickness, subtracts thinning that has occurred already, subtracts further thinning that is expected to occur until the next 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 pitting is combined with the maximum depth of underside pitting. The second equation combines the maximum depth of internal pitting with the average depth of underside pitting. Thus there is a tacit assumption that the location of the deepest internal pit will never coincide with the location of the deepest underside pit. This separation between the two deepest pits cannot be guaranteed, but it is a reasonable assumption to use for overall evaluation purposes. Work Aid 2 is based on this evaluation approach. API-653 does not specify the inspection procedures that must be used, nor their extent, to determine the values that are needed to solve these equations. The inspection details are left up to the owner. Probabilistic Method - The probabilistic method is a statistical analysis of the thickness data that are obtained from inspection measurements. The objective of this method is to predict the remaining minimum thickness of the bottom based only on sample scanning measurements, not extensive measurements, and then to determine whether the minimum thickness will be less than the API-653 minimum acceptable value. The intent of this approach is to reduce the amount of inspection time that is needed, and to predict the worst possible 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 too thin, it does not locate where the thinnest areas are. Thus, if a problem is predicted, a more extensive inspection of the tank bottom is still required to develop specific repair requirements.

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Overall Evaluation Considerations As previously stated, API-653 does not specify the extent of inspection that is needed to satisfy the evaluation requirements nor the inspection procedures that must be followed. The tank owner must develop the specific procedure and data collection details that he feels are sufficient to satisfy API-653 requirements. There are conflicting aspects to this determination. Sufficient measurements must be made to quantify the maximum pitting and general corrosion that has taken place and to develop reasonable average values. This requirement tends toward increasing the extent of inspection that is done in order to maximize confidence in the data that is collected and the evaluations that are made. However, the time and cost that are associated with the inspection increase as the extent of the inspection increases. A balance must be made that provides sufficient confidence in having defined the actual condition 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 the overall condition of the bottom. The initial screening usually includes visual, ultrasonic, pit gauge, and Magnetic Flux Exclusion (MFE) measurements. More detailed follow-up inspections are then made, as required, based on the initial inspection results. The following outlines 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 deep underside pits.

-

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

-

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

-

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

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

How many measurements are necessary to determine the average amount of general corrosion and internal pitting? Will measurements be made in each plate or in randomly selected areas throughout the bottom?

•

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

•

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

•

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

Minimum Thickness for Annular Plate Ring As discussed in MEX 203.03, butt-welded annular plates are required for particular situations based on local load and stress distribution considerations. Examples of where annular plates are 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 this region of the tank is relatively complex. Therefore, API-653 thickness acceptance criteria are more conservative for an annular plate than they are for the rest of the tank bottom. The minimum thickness criteria for annular plates are based on the following factors:

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•

•

Product specific gravity -

If the product specific gravity is less than 1.0 and the annular plate was not required for seismic considerations, its minimum acceptable thickness is the value that is specified by Table 2-2 of API-653 plus corrosion allowance. The minimum acceptable annular plate thickness specified by Table 2-2 is based on the thickness and stress in the first shell course.

-

If the product specific gravity is 1.0 or greater, the minimum acceptable annular plate thickness is the value that is specified in Table 3-1 of API650, plus corrosion allowance.

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

If the thickness acceptance criteria are not met, API-653 permits performance of a detailed stress analysis in an attempt to confirm the acceptability of a thinner annular plate for the specific 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 analysis must consider the extent and location of the corrosion, the degree of foundation support, and the applied loads. A Division 2 analysis might be advantageous if the API-653 acceptance criteria would require extensive annular plate replacement.

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Requirements for Repairs to Bottom Bottom plate repair or replacement must be done if the condition of the bottom does not meet the 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 bottom plates.

•

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 appropriate corrective action can be taken.

The specific approach that is used depends on the extent of the deterioration as well as on cost and time. Installation of an internal lining or cathodic protection system are other options that may be considered if general corrosion or pitting corrosion is excessive. However, these options address the entire bottom rather than just a portion of it, and are actually bottom enhancements rather than repairs. These two options will be discussed in a later section of this module. Any cracks or leaks that are found in bottom plate lap welds or in the shell-to-bottom fillet weld must be weld repaired. The cause of such cracks should be determined and corrected so that 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 or lap-welded patch plates. The choice between these two options is based on the depth and size of the areas that are to be repaired. Weld overlay is used for relatively small and scattered corroded or pitted areas, and patch plates are used for larger areas.

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Bottom plate repairs are required only to the extent that is necessary to satisfy the API-653 minimum thickness requirements, as described in Work Aid 2. Parameters that form part of the 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, an iterative approach may be used to determine the extent of repairs that are required based on their effect on the evaluation parameters. For example: •

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

•

If general internal corrosion is a problem, determine how much new plate must be added to decrease the average internal corrosion enough for the remaining thickness to be acceptable.

API-653 defines the critical zone of a tank bottom as within the annular plate ring, within 300 mm (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 are complex in nature. These complex stresses are due to both bending of the tank shell caused by the hydrostatic head and differential shell and/or bottom settlement. Because this area is critical, no welding, welded-on patch plates, or weld overlays are allowed within the critical zone 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 annular plate under the bottom shell course must be cut out and a new plate must be installed. This plate replacement has less detrimental impact on the local stress distribution than if repairs are done by localized weld repair or by the patch plate.

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As previously noted, a stress analysis may be used in an attempt to demonstrate that a locally corroded 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 or annular ring replacement would otherwise be required. When it is necessary to weld a new annular plate or bottom plate to an existing shell plate of unknown fracture toughness, increased attention must be paid to the weld procedures and inspection procedures that are used. The weld details and weld procedures must minimize the risk 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 local stress intensification. Fillet welds are normally shaped such that their leg lengths are equal. A fillet weld that has one leg longer than the other leg (e.g., 2:1 or 3:1) has a lower stress intensification factor, and thus a lower local stress, than an equal-leg fillet weld. A brittle fracture will normally initiate at a stress intensification point. Reducing the local stress reduces the brittle fracture risk.

•

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

•

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

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Figure 14. Elongated Fillet Weld

Figure 15. Temper-Bead Welding Use of a combination of repair or bottom replacement options is commonly required to solve a remaining thickness problem. If the extent of required repairs becomes too large, a completely new bottom must be installed. The bottom repair versus replacement decision is made on an individual basis based on cost comparisons and schedule considerations.

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Replacement of Entire Bottom An entire tank bottom may require replacement if corrosion is so extensive that the bottom cannot be repaired economically. A second bottom may also be required if a tank is being modified in order to add secondary containment and leak detection capability. The following summarizes API-653 requirements and additional information for installing a replacement bottom over an existing bottom. •

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

•

A cushion of noncorrosive material such as sand, crushed stone, gravel, or concrete must be used between the old and new bottoms (illustrated in Figure 16). This cushion will typically be 75-100 mm (3 - 4 in.) thick. An oiled sand mixture is often used for this purpose to reduce the likelihood of underside corrosion. This cushion provides uniform support of the new bottom and transmits the applied weight loads to the original bottom and underlying foundation pad.

•

A uniform slot is cut in the shell parallel to the tank bottom as shown in Figure 16. The cut edges of the shell are to be ground, and the new bottom or annular ring plates are passed through this slot and outside the shell. The new plates are 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 entire shell at once. The shell will typically be cut such that uniformly spaced, relatively short sections of the shell remain uncut to provide support for the upper shell. The remaining uncut shell sections are cut after adjacent new bottom sections are installed.

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Figure 16. Slotted Shell for New Bottom Installation

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•

The potential for galvanic corrosion should be addressed by removing the old tank bottom or by the installation of a cathodic protection system (noted in Figure 16). If the old bottom is left in place, install a liner on it prior to installing the fill material in order to prevent galvanic coupling between the two bottoms. In situations where a new bottom must be installed, it may be worthwhile to also consider the installation of a secondary containment and leak detection system as well. In addition to detecting and containing any bottom leaks that might occur, such a system provides another advantage. API-653 permits the bottom plate to corrode to a thickness of 1.25 mm (0.05 in.), rather than the normal 2.5 mm (0.1 in.), when a secondary containment and leak detection system is installed.

•

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

•

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

•

New bearing plates for floating roof support legs and for fixed roof support columns must be installed. Again, this requirement is no different from the requirements 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 to lessen future corrosion problems in an existing storage tank. A lining or CP system may be installed as part of the original installation of a new storage tank or as part of a maintenance program when excessive corrosion is found in an existing tank. A properly designed, installed, and maintained internal lining will prevent any future internal corrosion or pitting. Therefore, when calculating the minimum remaining bottom plate thicknesses in an API-653 evaluation, the internal corrosion rate and pitting rate parameters will be zero. Eliminating future corrosion or pitting in this manner reduces the extent of repairs that are required to make the bottom acceptable. A properly designed, installed, and maintained cathodic protection system prevents any future underside 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 this manner reduces the extent of repairs that are required to make the bottom acceptable. Saudi Aramco DeskTop Standards

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

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Internal Lining A glass-reinforced plastic (GRP) lining is the type that is most commonly used to protect tank bottoms from internal corrosion. A GRP lining is an effective and economical method for reinforcing and corrosion-proofing new and deteriorated tank bottoms. This versatile repair method is adaptable to both welded and riveted construction, and it offers important advantages 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 method an acceptable tank bottom repair and enhancement technique. GRP lining involves the application of either a glass-reinforced epoxy resin or glassreinforced polyester resin directly over the existing bottom. The term GRP is sometimes used interchangeably with FRP (fiber reinforced plastic). The reinforcement or filler material may be 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 are distributed 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 alternative to 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 the point where its minimum remaining thickness is at the API-653 limit, or will reach that limit before the next T&I, and internal corrosion or internal pitting is a major factor that has caused that bottom deterioration.

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

GRP linings are not suitable in situations where serious structural weakening due to general corrosion loss has damaged the mechanical integrity of the tank bottom. Although properly designed and installed GRP linings can have sufficient 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 tank bottom.

•

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

•

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

•

GRP lining applications and repairs should only be undertaken if a qualified contractor with demonstrated experience and expertise in GRP lining technology is available.

•

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

•

While GRP linings are useful for tank bottom repairs, the linings are not suitable to deter soil-side corrosion. If aggressive soil-side corrosion is a problem, a cathodic protection system should be installed to supplement the lining.

SAES-H-101, Aramco Paints and Coatings Systems, provides specifications for acceptable coating systems, as well as installation and inspection requirements for these coatings. Saudi Aramco DeskTop Standards

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Cathodic Protection System Cathodic protection is a technique that is used to reduce electrochemical corrosion. The goal of a cathodic protection (CP) system is to force sufficient electric current onto a structure to halt or reverse any discharge of corrosion current from the structure. CP systems for aboveground storage tanks are installed to protect the sketch plate or annular plate and the bottom from soil-side corrosion. These CP systems are generally effective and are relatively low in cost when compared to tank bottom repair or replacement. CP should be considered when a tank bottom has corroded to the point where its minimum remaining thickness is at the API-653 limit, or will reach that limit before the next T&I, and external corrosion or pitting is a major factor. Design and installation of CP systems is complex and should follow the requirements that are specified 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 systems will be contracted to outside firms, some knowledge of CP is required to evaluate proposed designs and assure correct maintenance. The two most common causes for failed CP systems are poor electric current distribution (which relates to system design), and lack of proper maintenance. There are two types of CP systems: sacrificial anode and impressed current. The following material briefly discusses these two types. When either of the two types are installed on double-bottom tanks or tanks that have impermeable plastic membranes, special considerations are involved. Double bottoms or impermeable membranes will shield the protective 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 difference between two dissimilar metals when exposed in soil or water. When the two metals are electrically connected, the more anodic material is allowed to corrode or is "sacrificed," and the 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 lower maintenance needs than impressed current systems. However, the electric current availability of sacrificial anode systems is limited by the electrical potential difference that naturally occurs between the tank bottom metal and the sacrificial anode material. Sacrificial anodes are generally alloy metals of magnesium, zinc, or aluminum that limit the electrical potential difference 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 and corrosion protection. The anodes should be geometrically placed around the tank that is to be protected. An example of such an arrangement is shown in Figure 17. As a rule, sacrificial anode systems do not produce sufficient corrosion protection for tanks that are larger than 10 m (30 ft.) in diameter.

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Figure 17. Typical Sacrificial Anode System

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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 the tank bottom. An impressed current system has the advantages of being able to produce the large driving electrical potential and high electric current output that are needed to satisfactorily protect large diameter tank bottoms. Electric current can also be increased or decreased as any variation in need occurs. Impressed current systems generally require a higher capital investment and maintenance level than sacrificial anode systems for small tanks, but cost less for larger tanks. Several different designs of impressed current systems are possible. The particular design that is selected often depends on the soil profile and the surrounding structures. Impressed current anode materials range from scrap iron to impregnated graphite, platinized titanium, 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 and water 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 AA036355. SAES-X-600 requires that the anodes be no more the 20 m (60 ft.) apart center-to-center, and that the anodes be between 5 m (15 ft.) and 10 m (30 ft.) from the tank wall. SAES-X-600 also requires that tanks that are 10 m (30 ft.) in diameter and greater have reference electrodes buried under their bottom plates. The required number and location of the reference electrodes are specified based on tank diameter. Figure 18 is an outline drawing of a typical distributed impressed current system.

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Figure 18. Typical Impressed Current System

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Sample Problem 2: Evaluating Tank Bottom Remaining Thickness Bottom plate thickness measurements have been made during the T&I of a 100 ft. diameter fixed roof tank. The results of these measurements and other data, as documented in the Inspection 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 large number of shallower pits scattered throughout the tank bottom. All the deep pits are outside the critical zone of the bottom. The data on the pits are as follows: -

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 depth of 0.119 in.

-

One pit approximately 30 ft. Southwest of the center of the tank has a depth of 0.096 in.

-

One pit approximately 26 ft. Southeast of the center of the tank has a depth 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 internal pitting 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.

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Evaluate the inspection data for the bottom and determine if any repairs are required. If repairs are required, determine what should be done. Solution Work Aid 2 is used to solve this problem. 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. StPm 0.202 = = 0.0202 in. /yr. N 10 UPm 0.004 UPr = = = 0.0004 in./ yr. N 10 GCm 0. 05 GCr = = = 0.005 in. /yr. N 10 StPr =

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 = T o − 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.

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Because both MRT1 and MRT2 are well under the acceptable value of 0.1 in., bottom plate repairs are required. In examining the calculations, the two biggest factors that influence the MRT calculations are the 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 an internal 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 four deepest 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 and the pit repair reduces the average internal pit depth that remains, MRT1 does not have to be recalculated. In summary, the four deepest pits in the tank bottom should be repaired by weld overlay, and an internal lining should be installed, in order to make the bottom acceptable.

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DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR THE ROOFS OF 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 permitting hydrocarbon leakage from the tank. These deteriorated conditions can also decrease overall tank safety by making the tank more prone to a fire that is caused by a lightening strike. If deterioration is allowed to progress to an extreme state, the roof could experience a significant structural failure that is caused by the applied loads. Work Aid 3 provides procedures that may be used to evaluate the condition of existing tank roofs. The paragraphs that follow provide additional background information and guidance. The primary factor that must be considered in all tank roof evaluations is corrosion. The condition 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 where water can collect. If the tank stores hydrocarbons that produce corrosive vapors, corrosion will also tend to be severe near roof openings where the corrosive vapor can flow out of the tank (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 the outside of the tank shell. However, additional safety precautions are required to ensure that inspection personnel are not injured while working around deteriorated areas of the roof. For example, the following safety precautions should be followed: •

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

•

Gas tests should be made before inspection is begun, especially for floating roofs. Respirators should be worn or be readily available, depending on the test results.

•

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

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Fixed Roofs Corrosion is the principal cause of deterioration of fixed roofs. Tanks that store "sour" crudes are especially vulnerable to internal corrosion on the underside of the roof. Tanks that are located 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 support columns, rafters, girders, plugged pressure-vacuum vents, and defective welds. Causes and Rates of Internal Corrosion - Corrosion on the underside of fixed roofs results from the condensation of vapors that are contained in the tank. This type of attack can appear as general corrosion or pitting corrosion. Internal roof corrosion has only been observed in tanks that store "sour" crudes or distillates that contain free H2S. The corrosivity on the underside of a tank roof is generally low in the absence of both air and H2S in the vapor space. However, internal roof corrosion becomes considerable when both H2S and air are present in the vapor. The roofs of tanks in "sour" crude service can have a life of about 2 to 12 years before small holes may develop from internal corrosion. The long-term corrosion rates correspond to about 0.5 to 3 mm/yr. (20 - 120 mils/yr.). The corrosion rate is not necessarily a function of the total sulfur content in the crude, but rather of the concentration of free H2S in the crude oil or distillate. Cases have been reported where severe vapor space corrosion occurred in tanks with 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 roofs but is generally not severe. Tanks that are located near marine environments might experience substantial metal loss due to atmospheric corrosion caused by chlorides that are naturally present in their environment. Corrosion under insulation that is installed on tank roofs presents a more serious problem because metal loss can be very rapid and severe. Unfortunately, corrosion under insulation cannot be detected by visual examination or by nondestructive testing methods without removing insulation. This type of corrosion depends on the penetration of water or water vapor into the insulation system, and subsequent retention of the water in the insulation. All common types of insulation, including mineral wool, glass fiber silicates, foam glass block, polyurethane foam, and phenolic foam block, have been involved in such corrosion.

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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 junction included a 75 mm (3 in.) vertical rim around the junction. This rim retained rainwater that passed through 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. The organic materials that are used to caulk metal jackets dry out and crack with age. The cracked caulk permits water ingress if the caulk is not maintained. In addition, metal jackets may not be sealed properly at openings into the tank when the jacket is installed. Solar radiation can also degrade the weather barrier or vapor barrier and make the barrier less able to prevent the entry of water underneath.

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Thickness Measurements - When the tank is in-service, visual checks should be made for external corrosion of the roof plates. If the tank is insulated, the condition of the insulation should 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 small portions of the insulation for further investigation of its condition and that of the roof plates underneath. Atmospherically degraded insulation should be removed to minimize fire hazards, as well as the potential for severe corrosion of the roof. Degraded insulation can become a considerable fire hazard for tanks that store low-flash-point products. Visual in-service checks for corrosion should be supplemented by ultrasonic thickness checks of the roof plate. Specific experience will dictate the number and location of roof thickness measurement points. When the tank is out-of-service, detailed external and internal visual inspections will indicate if there are any areas of significant corrosion that require closer investigation. If internal scaffolding will not be used, it may be necessary to cut inspection openings in the roof plates in order to inspect the roof support structure. Evaluation of Fixed Roof Corrosion - Work Aid 3 contains a procedure that may be used to evaluate corrosion in fixed roofs. If significant corrosion has occurred in roof support structural members, stress calculations must be made to confirm that the support structure still meets API-650 allowable stress limits. Floating Roofs Causes and Rates of Corrosion - Inasmuch as the roof of a floating roof tank rests on the liquid that is stored in the tank, underside corrosion of the roof is usually slight. Metal loss at corrosion rates of 0.3 mm/yr. (12 mils/yr.) or less are typical on the underside of floating roofs that are in gasoline blending, light naphtha, and virgin naphtha services, especially on pontoon rim plates that extend to the liquid level. Use of mechanical mixers or jet mixers in such cases increases the liquid circulation velocity and can accelerate corrosion of the steel that is in contact with the liquid. In isolated cases, severe corrosion has occurred on the underside of the roof plate lap joints where moisture and other corrodants can accumulate in the crevices that are formed by the lap joints.

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Atmospheric corrosion on the topside of external floating roofs is common because the relatively horizontal roof surface tends to collect particulate contamination from the air, and the rainwater run-off is too slow to effectively remove the contamination. Depressions or irregularities in the roof surface will retain moisture, and then the moisture can penetrate any coating that is installed on the roof (e.g., paint) and establish corrosion cells. As the moisture finally 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 and subsequently 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 salt water cooling towers, rapid atmospheric corrosion of tank roofs can occur. In most other areas, however, external corrosion of floating roofs is not severe. Inspection for Roof Corrosion - Visual in-service checks will locate areas of especially severe 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 corroded areas of the roof should be examined for evidence of leaks. The condition of the paint on the roof will provide a good indication of any potential roof corrosion problem. Tank roofs generally require more frequent repainting than tank shells because weathering of the paint system is more severe on the roof due to its exposure to sunlight and the presence of pools of water. 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 for grooving, pitting, and corrosion because this area is prone to corrosion due to the liquid-vapor interface. The interior of the pontoons on double deck roofs is another location that should be inspected for corrosion. Recommended retirement thicknesses for floating roof deck plates and pontoons are dictated by structural requirements. Work Aid 3 contains a procedure that may be used to evaluate corrosion in floating roofs. Pontoon rim thickness requirements are generally governed by buckling stability or stress considerations based on the design rainwater load. These considerations are a function of tank diameter. If corrosion significantly reduces the rim thickness, a buckling and stress analysis may be required, and CSD should be contacted.

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Repair Requirements for Fixed Roofs The primary concern with roof plate thinning is to ensure that there is still adequate vapor tightness 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 of explosions 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 amounts of rainwater and locally high corrosion. Excessively thin, holed through, or buckled areas of the roof plate are typically repaired by lap-welded patch plates. Depending on the extent of the deteriorated area, these patch plates may be welded over the existing roof plates, or the existing roof plates may be removed and replaced by new plates. Repairs or alterations to the roof support system must meet API-653 requirements. 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-shell junction. If a frangible joint is required, any repairs that are made must ensure that the frangible joint requirements are still met. Specifically, too large a repair weld violates the frangible joint requirements. If significant deterioration has occurred within an unexpectedly short period of time, the root cause should be determined before the repair requirements are finalized. For example: •

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

•

If severe topside corrosion occurred, was this corrosion due to inadequate inspection and maintenance procedures?

•

Has the tank service been changed to one where internal corrosion is a more significant 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 roof deck or pontoons permit stored liquid to get on the deck or into the pontoons. Pontoon damage can also permit rainwater to get into the pontoon. This pontoon damage reduces the floatation capability of the roof and must be repaired.

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External floating roofs of large diameter tanks are sometimes prone to rippling when wind blows across the deck. Large diameter tank roofs are also prone to pontoon buckling due to excessive rainwater accumulation on the center deck. The wind rippling can crack the center deck welds and/or make the roof prone to sinking by rocking the roof to the point where some stored liquid gets on top of the deck. Pontoon buckling can reduce the roof stability and flotation capability, and make the roof prone to sinking as well. If these problems are encountered, it may be necessary to add circumferential stiffening rings to the deck or pontoon 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 is acceptable. Such repairs might include replacement or patching of corroded or excessively deformed deck plates, repairs to corroded or excessively deformed deck plates, or repairs to corroded or cracked deck plate lap welds.

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Criteria for Repair or Replacement of Floating Roof Seals Floating roof seals will deteriorate with time due to abrasion with the tank shell, ambient conditions, and attack by the stored liquid. When repair or replacement alternatives are being considered, the selection of the seal material that is used must take into consideration the liquid that is being stored. If the stored liquid has changed since the original tank construction, it may be necessary to change the seal material or seal design in order to achieve adequate service life. Rim-mounted primary mechanical shoe seals and toroidal seals can often be repaired or replaced with the tank in service. No more than one quarter of the seal should be removed from an in-service tank at one time. This limitation minimizes evaporation losses and reduces the danger to workers. Temporary spacers must be used to keep the roof centered during seal replacement. Primary seal systems that are mounted partly or fully below the rim usually cannot be removed with the tank in-service. In-service repairs must normally be limited to replacing the primary seal fabric in these cases. Rim-mounted or shoe-mounted secondary seals and weathershields may be installed, repaired or 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 action can be taken. The following requirements must be met: •

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

•

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

•

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

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

Adjust the hanger system on primary shoe seals.

•

Add foam filler in toroidal seals.

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•

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

•

Replace all or part of the primary seal system, along with possible installation of 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 are used for external floating roofs. Because the internal floating roof is protected from the ambient environment, factors that can cause deterioration of external floating roofs (e.g., wind and rainwater accumulations) are not relevant for internal floating roofs. The following briefly summarizes the primary items on internal floating roofs that must be inspected 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 cracked welds. Any suspect welds should be vacuum box tested and repaired as needed.

-

For bolted roof construction, such an accumulation may be due to loose bolts and clamps. These bolts and clamps should be tightened as needed.

•

The pontoons should be checked for tightness to confirm that the roof flotation capability is maintained.

•

Roof support legs should be checked for corrosion and repaired or replaced as needed.

•

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

•

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

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DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR SITUATIONS THAT 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 and construction, tank shell and/or bottom settlement may still occur over a period of time after the tank has been placed in service. Therefore, shell and bottom settlement must be evaluated as part of the periodic tank maintenance activity to determine if any corrective action is required. The types of shell and bottom settlement that may occur must first be understood in order to make these evaluations. The sections that follow review the principal types of settlement 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 are illustrated in Figure 21. In uniform shell settlement the shell remains level as it settles. This type of settlement does not introduce significant stresses or distortions in the tank shell or bottom and does not necessarily require correction. Problems that can be caused by uniform shell settlement and possible corrective actions are as follows: •

Blockage of surface water drainage from the tank pad into the diked area may result in water retention at the tank shell. Water retention can be corrected by regrading the tank pit such that water cannot accumulate near the tank. If this problem is not corrected, it can cause localized tank corrosion in the lower portion of the bottom course and annular plate and sketch plate area.

•

Differential settlement between piping supports and the connecting tank nozzle may cause overstress of the pipe or tank nozzle. This problem is usually corrected by adjusting the pipe supports.

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Figure 21. Uniform Shell Settlement

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

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Figure 22. Planar Tilt Settlement

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Differential Shell Settlement - Differential shell settlement is when the bottom of the shell is no longer in either a level or tilted plane. API-653 also refers to differential shell settlement as out-of-plane deflection. With differential settlement, the shell undergoes different amounts of settlement at different points around its circumference. This settlement usually does not damage the tank structure as long as the settlement is minor and there is adequate support under the shell. The amount of differential settlement is defined as the deviation between the actual 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 of the 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. Differential settlement can cause the same problems as planar tilt settlement. In addition, differential settlement may cause the shell to buckle or cause the shell-to-bottom area to become overstressed. Figure 24 illustrates the potential problems that may result from differential shell settlement.

Figure 23. Settlement Readings Showing Differential Shell Settlement

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Figure 24. Effects of Differential Shell Settlement

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Evaluation 32-SAMSS-005 requires that shell settlement measurements be made before, during, and after hydrostatic testing of newly constructed tanks. The purpose of these measurements is to determine if the settlement that occurs during the initial filling of the tank is within acceptable limits. Shell elevation measurements will then be made periodically during the life of the tank to determine if any unexpectedly large settlements occur. The interval between elevation measurements is determined based on the results of these measurements. If no settlement problems are indicated, elevation measurements will typically be made during each T&I. Shorter settlement measurement intervals are used if initial measurements indicate that there might be settlement problems. Tank elevation measurements will not disrupt operations because 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 be affected by future ground settlement due to the tankage. This permanent bench mark permits an accurate measurement of tank shell settlement over a period of years.

Figure 25. Tank Shell Settlement Measurements

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Reference points are established on the tank shell by welding nuts or similar steel objects to the tank shell. The reference points are located 100 mm (4 in.) above the bottom edge of the bottom shell course at equal distances around the circumference of the tank. One reference point is located at the catch basin. The minimum number of reference points depends upon the diameter of the tank. API-653 requires that at least 8 reference points be used, and that the 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 from the 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 differential shell settlement (i.e., out-of-plane deflection). The API-653 evaluation basis is contained in Work 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 first be converted to out-of-plane deflections around the tank circumference. This data conversion is typically done using a computer program and subtracts the uniform and planar tilt settlement components from the total settlement measurements. If the measured differential shell settlement exceeds the API-653 acceptance basis, CSD should be contacted before any action is taken to relevel the tank. Further evaluations are typically made to determine if the settlement has caused any damage or operational problems to the tank. Experience has shown that excessive differential shell settlement will typically cause shell distortion before any failure will occur. A detailed stress analysis may also be done to help make a decision. Releveling a tank can be expensive and could cause more problems than it solves if it is not done properly.

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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 to a soft spot or void in the foundation. Voids in the foundation may occur when settlement has occurred and the tank has been jacked for repairs. After the jacking operation, the foundation must be refilled with a grout material to fill in the vacant spaces. However, no technique can guarantee that the vacant spaces are entirely refilled. Therefore, after jacking operations, it is not unusual for voids to exist in the foundation. Tunneling under a tank to inspect bottom plates, or leakage through a bottom plate that softens or disperses pad material, are other mechanisms that can also cause voids in the foundation. The bottom plate is not designed to support the tank contents without being uniformly supported from underneath by the foundation. Therefore, a localized weakness in the foundation soil can cause overstress in the bottom plates and result in a bottom plate weld failure. If the foundation in the area of the weld failure is unstable or poorly drained, the resulting leak can wash out a considerable portion of the foundation and lead to a major tank bottom failure. Figure 26 illustrates localized bottom settlements that may result from soft spots or voids in the foundation.

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Figure 26. Localized Bottom Settlement In addition to localized bottom settlement that can occur away from the tank shell, localized settlement can occur near the shell of a tank. Localized bottom settlement that occurs near the tank shell is normally accompanied by shell settlement, and the two settlements should be considered together.

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

Figure 27. Center-To-Edge Bottom Settlement

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On tanks that are less than about 50 m (150 ft.) in diameter, excessive bottom settlement is likely to buckle the shell. On tanks that are over about 50 m (150 ft.) in diameter, frictional drag is a bigger factor and excessive settlement is more likely to overstress the bottom plates before noticeable shell buckling occurs. In tanks that are built on poor foundations, the failure of a bottom weld can lead to catastrophic foundation washout. However, if the tank foundation was preloaded and complies with Saudi Aramco design requirements, center-to-edge settlement should not be a problem. Combined Bottom and Shell Settlement - Bottom settlement will normally occur in combination with one or more types of shell settlement. Differential settlement of the shell of a large diameter tank relative to its bottom can result in significant radial pull on the bottom plates by the shell. This type of settlement is illustrated in Figure 28. The difference in settlement between the shell and bottom must be absorbed over a very short distance in the bottom plates at the tank edge. The resulting excessive distortion of the bottom plates, that must 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

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Evaluation Although excessive bottom settlement occurs less frequently than shell settlement, bottom settlement can result in greater damage and much higher releveling costs. At the same time, it is more difficult to determine bottom plate settlement patterns while the tank is under hydrotest or in service. Because of the greater risks associated with bottom settlement, bottom elevation patterns are sometimes monitored while the tank is in service in locations where sub-soil conditions are doubtful or unsatisfactory. In these situations, important data points can be checked by dropping 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 cone roof tank are a strong indication that excessive bottom settlement may have occurred. In addition, excessive shell settlement indicates a strong possibility of excessive bottom settlement as well. In most situations, bottom elevation measurements to determine settlement patterns will only be made when the tank is taken out of service for a T&I. API-653 contains recommended locations for bottom settlement measurements, as shown in Figure 29. Closer measurement spacing (75 - 150 mm [3 - 6 in.] apart) should be used in areas where the bottom elevation changes rapidly, especially close to the shell.

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Figure 29. Bottom Settlement Measurement Locations

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

Depth of depression (or the height of the bulge) in the tank bottom. Note that local 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 (or bulged) area.

•

An assumption that the bottom plate lap welds are made with a single weld pass.

If the measured bottom plate settlement exceeds the API-653 acceptance basis, CSD should be contacted before any action is taken to repair or relevel the bottom. The API-653 evaluation basis is relatively conservative, and it may be worthwhile to do a detailed stress analysis to determine the actual situation if extensive repair or releveling is required. The API-653 basis is especially conservative if the bottom plate lap welds are made with two or more 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 before unacceptable damage and tank leakage occurs. Because significant time is required to properly plan, evaluate, and execute settlement corrections, the decision to relevel cannot be taken lightly. Improper releveling can cause as much or more damage to the tank than the settlement that it is meant to correct. The paragraphs that follow describe the primary considerations 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 of the shell, releveling the entire shell, or releveling both the entire shell and the tank bottom as well. The extent of releveling should be minimized consistent with fixing current problems and minimizing the probability of needing future releveling. In many cases, releveling only part of the shell is necessary. In these cases, the low points of the 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, local overjacking of the shell in areas of poor soil may be desirable. When overjacking is specified, it should be done so that the resulting radial displacements of the shell will not cause floating roof binding or gaps between the floating roof and shell. Calculation procedures are available that predict the amount of radial shell displacement for specified changes in shell elevation.

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Techniques - The most common technique for releveling a tank shell is to lift the shell with hydraulic jacks and pack selected materials beneath the bottom and annular plates. Two basically different procedures for tank jacking are widely employed: jacking against the tank shell and jacking from beneath the bottom or annular plates. When jacking against the tank shell, jacking lugs or brackets are welded to the tank shell around its periphery as close to the bottom or annular plate as possible. Figure 30 illustrates the details for typical jacking lugs. A compact hydraulic jack (or a pair of jacks) is placed on a timber footing at each bracket location, and the tank is gradually lifted to a height that is equal to the jack stroke (generally 100 mm [4 in.]). Timber beams or steel shims are then used to temporarily support the tank shell while the jack is released, and additional timber beams are placed between the jack and the foundation. The entire process is repeated until the tank shell is level and at the required elevation.

Figure 30. Typical Jacking Lugs

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Depending on the jacking system, the jack spacing, and the shell thickness, externally mounted jacks can impose significant stresses on the tank shell. Therefore, it is important that the shell stresses be checked and any necessary strengthening measures carried out before jacking is begun. The major advantage of jacking against the shell when compared to jacking from beneath the bottom or annular plates is that disturbance to the existing foundation is minimal. Because the jacks are not beneath the shell, placement and compaction of select backfill is more uniform 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 the annular plates is the welding that is required to attach the brackets to the shell and to provide any necessary shell reinforcement. This welding can also build up residual stresses in the shell and possibly cause brittle fracture, particularly in older tanks where steels with poor fracture toughness were often used. On newer tanks that are constructed of high strength steel, 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 a jacking 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 jacking frame. A typical jacking frame is illustrated in Figure 31. The frame is equipped with slender jacking shoes that are shaped so that they can be easily slipped beneath the tank shell. The frames are spaced every 3 to 4.5 m (10 to 15 ft.) around the tank periphery. The tank can be jacked to a maximum height of 300 mm (12 in.) with this method. No welding to the tank shell is required, and the jacking frames are reusable. Due to the size and shape of the jacking shoe, there is little disturbance to the existing foundation. The disadvantages of this method are 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, this method cannot be used for all tank releveling needs.

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Figure 31. Typical Jacking Frame Figure 32 illustrates pits that may be excavated beneath the bottom or annular plates to provide space for placing hydraulic jacks. Jack spacing depends on the size of the tank and the 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 the required jack spacing. After placing the jacks, the tank is lifted to the desired height by utilizing timber cribbing. The jacking pits are then backfilled after the tank is lowered onto the newly releveled foundation pad. Localized settlement over the jacking pit areas can cause additional stresses in the annular plates and shell. Therefore, it is important to minimize these settlements and resulting stresses by keeping the size of the jacking pits as small as possible. Only high quality fill such as crushed stone should be used, and the fill should be properly compacted by means of rams and 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 loading after it is compacted.

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Figure 32. Typical Jacking Pit The actual jacking operation should be accomplished using a predetermined procedure that considers the following factors: •

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

•

Localized sections of differential settlement should first be jacked to a planar position. The remaining tank shell can then be jacked to a level position, as required.

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•

Some overjacking may be done when further settlement can be anticipated and predicted.

•

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

•

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

•

When simultaneously lifting at multiple locations, all jacks should be connected to a single hydraulic line and pump. Hydraulic connections to the jacks should include a safety system to prevent jack failure in case of a pump or 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, the shell begins to lift the bottom plates at the first row of roof support legs. If the shell has to be raised further, it will be necessary to release the loads from these legs with temporary roof supports. Removing the load from these legs is accomplished by welding temporary brackets to the inside of the shell to support the outer periphery of the pontoon.

Bottom Releveling Considerations and Techniques Considerations - When the bottom must be releveled, the following items should be considered as possible options: •

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

•

Lift the entire tank and relevel the affected area. Coarse sand or gravel should be 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.

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•

Add a second pass to the bottom plate fillet welds in the affected area. Prior to adding the second pass, the original fillet welds must be sand blasted and cleaned 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 less commonly used methods. Selection among any of these releveling techniques, or a combination of them, should be based on an economic evaluation. Pressure grouting of tank bottoms is appropriate for correcting settlement in localized areas of the bottom plates. In this technique, grout is injected under pressure between the bottom plate and the foundation pad, not directly into the pad. Pressure grouting has proven to be successful at many installations. A wide variety of grout mixes are offered by contractor specialists. All of these mixes include various materials and additives that improve pumpability and flow characteristics. For tank bottom releveling, a low compressive strength is a desirable characteristic of the grout, because a low compressive strength minimizes hard spots 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 the entire tank off its foundation and relevel and reshape the entire pad. When this technique is used, the entire tank is jacked up and cribbed to a height that provides headroom for motorized dumpers and small bulldozers. Mechanical equipment is then used to relevel and reshape the entire foundation with sand, gravel, and crushed stone. The tank is again jacked clear, cribbing removed, and jacks released to set the tank back on the new pad. This technique has proven to be successful on numerous tanks for correcting extensive bottom settlements. 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 repaired foundation.

•

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

•

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

All of these techniques have been successfully used. The choice of the specific technique to use 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.

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Sample Problem 3: Determine the Need for Corrective Action Based on Tank Settlement Measurements Shell settlement measurements were made of a 100 ft. diameter floating roof tank. The shell elevation measurements that were noted in the Inspection and History Report have been converted to out-of-plane deflections, and these deflections are shown in Figure 33. The following 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

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Solution Work Aid 4 is used to solve this problem. There are more than the minimum required number of settlement measurement points. Now, confirm that the settlement measurements were not made too far apart. πD N π (100 ) L= = 26. 2 ft. 12

L=

Because this is less than 30 ft., the spacing between the measurements is acceptable. Now determine the maximum permitted out-of-plane deflection. S= S=

11 L2 Y 2EH 11 × 26 . 2 2 × 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 the permitted value of 1.14 in., no action is required.

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HYDROTESTING REQUIREMENTS THAT ARE SPECIFIED IN SAES-A-004 AND API-653 All new storage tanks are hydrotested as a final means to demonstrate their structural integrity before the tanks are placed into service. There are no mandatory requirements for periodic re-hydrotesting of storage tanks to demonstrate their continued reliability unless changes have been made that could affect their structural integrity. API-653 specifies situations when an existing 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 with regard to hydrotesting existing atmospheric storage tanks. The majority of the hydrotesting requirements that are contained in SAES-A-004 have more direct applicability to piping systems, pressure vessels, and other pressurized equipment. However, SAES-A-004 also contains general procedural and personnel-safety related requirements that are applicable to hydrotesting existing storage tanks. Areas within SAES-A004 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 storage tank for the following situations (unless exempted by other criteria): •

A reconstructed tank

•

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

The hydrotest must be held for 24 hours.

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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 sizable portion of the shell. Examples of "major" work that would require re-hydrotesting are as follows: •

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

•

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

•

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

•

Complete or partial (over half of the weld thickness) removal and replacement of more than 300 mm (12 in.) of vertical shell plate weld or radial weld that joins 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 also frequently causes problems with regard to water disposal if the hydrotest water becomes contaminated with remnants of the tank contents. Therefore, Para. 10.3.2 of API-653 indicates that re-hydrotesting after major repairs or alterations is not required, provided that specific exemption criteria are met. The exemption criteria are based on the following factors: • • • •

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 or alterations that are done are not likely to increase the risk of a brittle fracture in the tank. A re-hydrotest is not required for these low-risk situations. Participants are referred to API-653 for the specific exemption requirements. SAES-D-108 adds to the API-653 re-hydrotest requirements. Para. 10.3.1 specifies that the maximum tank shell stress during the re-hydrotest must be limited to 90% of the specified minimum yield strength of the material. The maximum shell stress must be based on the actual shell thicknesses that were measured during a shell inspection. Saudi Aramco DeskTop Standards

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WORK AID 1: PROCEDURE FOR DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR SITUATIONS INVOLVING STORAGE TANK SHELLS AND SHELL PENETRATIONS The procedures that are contained in this Work Aid may be used to determine the appropriate repair or alteration requirements to be used for storage tank shells or shell penetrations. The class reference copies of API-653 and SAES-D-108 shall be used with this Work Aid. These reference documents are contained in Course Handouts 1 and 2, respectively. All needed tank inspection 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 or alteration 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 an Inspection and History Report to determine the current condition of the tank shell or shell 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 items such as tank or nozzle diameter and wall thickness, materials, and maximum required fill height. This information may be obtained from the Contractor Design Package for the tank.

3.

Identify potential alternatives for making the repair or alteration.

4.

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

5.

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

The time that is available to work and the desired time interval until the next T&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 to do the work, as noted above, and the tank alterations that are required to meet any changed operational needs.

6.

Select an alternative for repair, replacement, or alteration.

7.

Identify the procedures to be followed for the selected alternative.

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Work Aid 1B: Inspection Data The condition of the existing tank must be quantified in order to determine the appropriate repair or alteration requirements. This condition is determined by inspection personnel during an OSI and/or a T&I, and it is then documented in the Inspection and History Report. The inspection data is then used to help in the determination of appropriate repair or alteration requirements. If the situation involves a tank shell, proceed to Step 1. If the situation involves a tank shell penetration, proceed to Step 13. Tank Shell 1.

Are there any distortions in the tank shell, such as out-of-roundness, buckled areas, or flat 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 Step 5. 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 any point in the corroded area, excluding widely scattered pits. Refer to Figure 2-1 in the class reference copies of API-653 in Course Handout 1 (see Figure 34).

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Figure 34. Generally Corroded Area

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7.

Use the formula that follows to calculate the critical length, L: SI Units L = 33.8 Dt 2 Where:

English Units L = 3. 7 Dt2

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, exclusive of 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 (40 in.). 8.

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

9.

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

10.

Calculate the average thickness of each critical plane from the thickness measurements that were made.

11.

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

12.

For pitted areas, obtain the following information:

distance, L. the corroded divided into section must

•

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 the pits. Refer to Figure 2-2 in the class reference copy of API-653 in Course Handout 1 (see Figure 36).

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

Figure 35. Shell Thickness at Bottom of Pit

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Figure 36. Sum of Pit Dimensions

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Tank Shell Penetrations 13.

14.

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 shell welds or other openings

•

Size of penetration

•

Thickness of nozzle neck

•

Size, thickness, and type of reinforcement

•

Deterioration due to corrosion or other defects

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 to nearby shell welds or other openings

•

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

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Work Aid 1C: Reference to Pertinent Content From SAES-D-108 SAES-D-108 modifies API-653 requirements. This sub-Work Aid contains modifications that must be followed with respect to tank shells and shell penetrations. All the API-653 requirements must be followed, as provided in Work Aid 1D. Refer to the class reference copy of SAES-D-108 in Course Handout 2. Tank Shells Confirm that rectangular replacement insert plates that do not intersect with weld seams have rounded 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)

150 (6)

> 12.7 (0.5)

Greater of 150 (6) or 6t

Figure 37. Minimum Corner Radius of Shell Insert Plates

Tank Shell Penetrations 1.

Any reinforcing plate that is to be added to a shell opening must not be added inside the tank.

2.

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

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Work Aid 1D: Reference to Pertinent Content From API-653 This sub-Work-Aid contains requirements that are contained in API-653 that must be followed with respect to tank shells and shell penetrations. Refer to the class reference copy of API-653 in Course Handout 1. If the situation involves a tank shell, proceed to Step 1. If the situation involves a tank shell penetration, proceed to Step 10. Tank Shells 1.

Shell distortion may be considered acceptable if the deviation from uniform curvature is 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 of these limits. 2.

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

3.

Slag, porosity, lack of fusion, laminations, and weld undercut must be evaluated by inspection personnel in conjunction with CSD, as appropriate. Unacceptable defects must 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/or welding. Arc strikes that are repaired by welding must be ground flush with the plate surface.

5.

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

6.

•

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 the minimum acceptable thickness. The minimum acceptable thickness is determined as described for the evaluation of generally corroded areas in Step 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 is unknown, use T = 379 MPa (55 000 psi).

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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 thickness evaluation, S, psi.

d.

•

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.

Use the formula that follows to calculate the minimum acceptable thickness for a welded shell that is no more than 61 m (200 ft.) in diameter. See Step 6g for larger diameter tanks. SI Units t min =

English Units

4. 9D(H − 0. 3) SE

t min =

2.6D(H − 1)G SE

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

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

D

= Tank diameter, m (ft.)

H

= Height from the bottom of the length L of the most severely corroded area in each shell course to the maximum design liquid level, m (ft.)

G

=

Highest specific gravity of the tank contents. If future hydrostatic testing 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 greater of 25 mm (1 in.) or twice the plate thickness

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e.

The generally corroded area is acceptable if both the equations that follow are satisfied. 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 in Step 11 of Work Aid 1B, mm (in.).

t2

=

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

CA

=

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

CA

=

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

Maximum CorrosionRate = f.

(Original Thickness in Corroded Area − t 2 ) Years in Service

As a final check, it must also be confirmed that the T&I interval is no greater than half of the remaining tank life (based on the general corrosion). (1)

Using each equation that is in Step 6e, calculate the remaining corrosion allowance, 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

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(2)

Determine the Remaining Life from the following equation: Re maining Life =

(3) g.

CA / remaining Maximum CorrosionRate

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

If the criteria in Step 6e and Step 6f are not satisfied, the following options are available: •

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 the point where the equations are satisfied and where the interval is no more than half the predicted remaining life.

•

Using the Variable Design Point Method of API-650 to calculate the minimum required thickness, evaluate the corroded area again. See Para. 2.3.3.2 of API-653. The Variable-Design-Point Method was discussed 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-Point Method of API-650 to calculate the minimum required thickness. The Variable-Design-Point Method was discussed in MEX 203.03. The variables that are to be used are as defined in Para. 2.3.3.1 of API-650. Then, proceed as in Steps 6e through 6g.

i.

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

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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 satisfy the following equation: tpit ≥ 0.5 tmin + (Pitting Allowance) The Pitting Allowance should be determined based on the maximum pitting rate and the desired interval to the next T&I. (Pitting Allowance) = (Maximum Pitting Rate) x (Desired T&I Interval) Maximum Pitting Rate =

•

Maximum Pit Depth Years in Service

It must also be confirmed that the T&I interval is no greater than half the 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: Re maining Life =

•

c.

Remaining Pitting Allowance MaximumPitting Rate

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

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

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

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8.

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

9.

Corroded or pitted areas of shell plate that are unacceptable may be repaired by either weld overlay or by cutting out the corroded section of shell and replacing the removed section 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 must be met. The requirements that follow shall be met when a replacement shell plate is used for repair. a.

Plate material must meet current API-650 requirements.

b.

The minimum plate thickness shall meet the requirements in Para. 7.2.1 of API-653. The replacement plate thickness will typically equal the thickness of the 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 of 300 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 complete penetration and complete fusion.

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

t ≤ 12.7 (0.5)

t > 12.7 (0.5)

B

150 (6)

Greater of 250 (10) or 8t

H

75 (3)

Greater of 250 (10) or 8t

V

150 (6)

Greater of 250 (10) or 8t

A

300 (12)

Greater of 300 (12) or 12t

Figure 38. Acceptable Shell Replacement Plate Details

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Tank Shell Penetrations 10.

11.

For existing shell penetrations, use the available inspection data and take the following action: •

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

•

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

•

Evaluate as follows the corroded regions within the nozzle itself, or within its reinforcement region on the shell: -

Compare the amount of corrosion that has taken place with the originally specified corrosion allowance. If no corrosion allowance was specified, or if the originally specified corrosion allowance has been exceeded, refer the situation to CSD for review.

-

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

When existing shell penetrations must be repaired: •

All repairs must comply with API-650 requirements. If this repair involves shell 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 a corrosion problem must meet all API-650 dimensional and weld spacing requirements. See Figures 7-2 and 7-3 of API-653 for acceptable details and weld size requirements.

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12.

For new shell penetrations that are added during a T&I, design and installation details shall 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 shall meet 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 the minimum reinforcing area and minimum distance between adjacent welds.

•

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

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WORK AID 2: PROCEDURE FOR DETERMINING REPAIR OR ALTERATION REQUIREMENTS FOR STORAGE TANK BOTTOMS The procedures that are contained in this Work Aid may be used to determine the appropriate repair or alteration requirements to be used for storage tank bottoms. The class reference copies of API-653 and SAES-D-108 shall be used with this Work Aid. These reference documents are contained in Course Handouts 1 and 2, respectively. All needed tank inspection 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 the appropriate repair or alteration requirements. This condition is determined by inspection personnel during a T&I, and then documented in the Inspection and History Report. The inspection 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 the evaluation 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 design details.

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 other bottom plate welds? If yes, quantify their extent and location.

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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 be followed with respect to tank bottoms. All other API-653 requirements must be followed as provided in Work Aid 2C. Refer to the class reference copy of SAES-D-108 in Course Handout 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 its condition and identify areas with potential corrosion.

b.

Perform additional thickness readings in those areas with potential corrosion problems. Identify areas that have thickness readings that are less than 2/3 of the original plate thickness or that have extensive pitting.

c.

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

2.

If the entire tank bottom must be replaced, the new bottom must be installed above the original bottom if this is the first time that the bottom is being replaced. Subsequent bottom replacements must be made at the same elevation as the first replacement bottom. The existing cushioning material that is located between the existing bottom and the new bottom must be completely replaced.

3.

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

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Work Aid 2C: Reference to Pertinent Content From API-653 This sub-Work Aid contains requirements that are contained in API-653 that must be followed with respect to tank bottoms. Refer to the class reference copy of API-653 in Course 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 plate thickness, StPa, mm (in.)

c.

Maximum depth of internal pitting, StPm, mm (in.). Note that the value that is used for the initial evaluation is based on the inspection data. Subsequent evaluations may be made based on the maximum internal pit depth that would still 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: service StPr installed h.

N

=

Number of years that the tank has been in

=

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

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

UPm N

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

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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 at the next T&I, based on average internal pitting and maximum underside pitting. MRT1 = To − GCa − StP a − UPm − (StPr + UPr + GCr )Or Where:

MRT1 =

Minimum remaining thickness at the next scheduled internal inspection due to average internal pitting and maximum external 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 thickness until the next T&I, based on maximum internal pitting and average underside pitting: MRT2 = T o − GCa − StPm − UPa − (StPr + UPr + GCr )Or Where:

MRT2

=

Minimum remaining thickness at the next scheduled internal inspection, due to maximum internal pitting and average external pitting, mm (in.)

Other parameters are as defined in Steps 1, 2 and 3.

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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 39 for bottom plates, which are not annular plates.

Tank Bottom/Foundation Design No means for detection and containment of a bottom leak

Minimum Acceptable MRT1 and MRT2, mm (in.) 2.5 (0.1)

Means to provide detection and containment if a bottom leak

1.25 (0.05)

Applied tank bottom reinforced lining over 1.25 mm (0.05 in.) thick, in accordance with API RP 652

1.25 (0.05)

Figure 39. Bottom Thickness Acceptance Criteria b.

The minimum acceptable values of MRT1 and MRT2 for butt-welded annular plates shall be in accordance with Para. 2.4.8 of API-653. See Figure 40.

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Engineering Encyclopedia

Vessels Determining Requirements for Repair or Alteration of Storage Tanks

First Shell Course Nominal Thickness, t, in.

Stress in First Shell Course, psi