Section 15 — Inspection

In-Plant Inspection of Existing Tankage

IPE Engineering Practice IPE-EP-15-4-4

Document number: IPE-EP-15-4-4 · Section: 15 — Inspection

SCOPE

• This procedure defines the requirements and specifies responsibilities for the internal and external visual inspection of plant atmospheric and low–pressure storage tanks.
• A revision bar indicates all changes made to this Revision.

2.0 REFERENCES

The latest edition of the following standards and publications are referred to herein:

STANDARDS AND PUBLICATIONS

DEFINITIONS

For the purposes of this Practice the following definitions shall apply:

• Inspection Authority – An individual appointed or approved by the Owner who is responsible for the Owner’s quality assurance program and has the knowledge and training to resolve issues relating to inspection and quality.
• Integrity Assurance – Both a one time fitness for use analysis for older tanks and a continuing stress reduction effort to assure a tank’s capability to safely operate under all expected conditions.

• PCMS – Acronym for Plant Corrosion Monitoring System, a computer program designed to statistically calculate corrosion rates and next inspection dates for equipment.
• Tank CCE (Common Corrosive Environment or Circuit) – A term used to describe, for the purpose of corrosion rate monitoring, a representative area of a tank shell where the corrosive conditions are expected to be approximately equal, taking into account the corrosive environment (internally and externally). Temperature, material, and compass orientation (South side locations tend toward more aggressive wet and dry cycles in the Northern hemisphere).
• Tank External Inspection – An inspection performed by a qualified inspector while the tank is in or out of service and normally includes external visual assessment of the tank foundation, shell, roof, and all appurtenances of the tank and may also include some external thickness monitoring of the shell or roof.
• Tank Internal Inspection – An inspection performed by a qualified inspector of the tank interior while the tank is out of service and normally includes a representative visual inspection of all internal surfaces of the tank plus thickness measurements of the floor, and possibly the shell and/or the roof.
• Tank Thickness Monitoring Location (TML) – A sample area of a tank’s shell, bottom, or structural support that has been selected and identified for thickness monitoring requirements.

SURVEILLANCE AND INSPECTION PERSONNEL

• Personnel performing periodic tank surveys shall be knowledgeable in tank operations and assigned by the plant management to perform the surveys.
• Personnel performing scheduled tank inspections shall be qualified in accordance with EP 15– 3–1.

ASSIGNMENT OF TANK CCE’S AND THICKNESS MONITORING LOCATIONS (TML’S)

• If tanks are monitored for shell, bottom, roof or area corrosion by the PCMS software program, CCE’s shall be assigned with unique identifiers.
• It is recommended that the tank shell contain a minimum of two CCE’s: one consisting of the bottom shell course, and the second consisting of the rest of the shell.
• Manways, nozzles, piping and fittings may be included with the shell CCE or treated as separate CCE’s according to their vulnerability to corrosion.
• CCE’s may be subdivided or combined as appropriate based on corrosion experience and possibly compass orientation with each tank after review and acceptance of the Inspection Authority.
• To identify representative CCE corrosion rates, thickness monitoring locations (TML’s) shall be strategically selected on the tank. These TML’s shall be adequately identified on the tank and/or on a tank sketch so subsequent readings may be taken at these same locations. (Consider reference coordinates such as height in feet/inches above the ground or a course and circumferential clockwise distance in feet/inches from North or other directional references.)
• Unless otherwise determined by the Inspection Authority, a sufficient number of sets of three TML’s placed one inch, one foot and three feet above the floor shall be located around the shell perimeter to monitor corrosion activity at the base of the shell.

• Initially there shall be no fewer than one set of TML’s for every 10 feet of tank diameter uniformly spaced around the shell circumference.
• The number of TML’s and location of each may be adjusted in order to better monitor conditions after performing each thorough internal inspection of the tank (Add more appropriately placed TML’s as a tank approaches its retirement limit or as significant corrosion occurs).
• For the rest of the shell, TML’s should be strategically located around the circumference at appropriate heights to measure corrosion in these areas (For tanks with circumferential stairs attached, representative shell courses may be monitored along the stairs).
• Consideration for the number and location of these TML’s should be based on the:
• age of the tank,
• type of roof design (floating roof tanks will normally require more TMLs than fixed roof tanks),
• corrosive nature of the contents,
• nature of the sun direction and local environmental conditions on shell corrosion.
• When shells are constructed with more than one thickness of plate, TML’s shall be assigned to each plate thickness.
• TML’s may be added at appropriate locations based on visual inspection if there is reason to believe the existing TML’s are not adequately monitoring the corrosion activity in the tank.

CORROSION–RATE SHELL EVALUATION

• Corrosion–rate evaluation of existing tank shells is an industry standard option to assist in assuring the integrity of this highly stressed tank component according to API 653, Section 3.3. When used, corrosion–rates shall be determined within five (5) years of tank operation where the corrosion–rate is not known or no product history exists and at the minimum of the quarter corrosion–rate life or 15 year intervals otherwise.
• The shell corrosion–rate shall be calculated for the purpose of determining the next shell quarter–life corrosion–rate evaluation interval date and/or the repair/replacement date.
• Corrosion–rates shall be calculated for each CCE or TML of the shell and its appurtenances plus any special areas determined by the Inspector. The maximum long term or short term rate calculated shall be the basis for determining the next thickness measurement interval for the tank shell.

• If PCMS is used to monitor shell corrosion, thickness readings shall be taken at intervals recommended by the program but shall not exceed dates required by API 653. Values calculated by PCMS may be used for determining the next recommended inspection date.
• If the average minimum thickness of a corroded area, as discussed in API 653 paragraph 2.3.2, is used to calculate the corrosion–rate and the next inspection date, this information shall be so noted in the tank inspection record.
• Tank crawler readings may be used in addition to, or in place of, manual UT measurements from the bottom course to the top course of the tank.
• They shall be made vertically at circumferential locations a maximum of 90º apart using commonly accepted reference identifiers acceptable to the inspection authority.
• When a scan includes a TML site the crawler value may be used in the TML corrosion–rate calculation.
• Regions of the shell which have localized wall loss as determined by internal inspection shall be designated a TML and may use the lowest average thickness calculated per API 653, paragraph 2.3.2 for the purpose of determining the next inspection interval and/or the remaining life.
• The external circumference of nozzle necks shall be ultrasonically scanned for minimum thickness, if practical, otherwise several readings shall be made about the circumference to obtain a minimum value. The location of the minimum value for each nozzle shall be noted on the inspection report.
• Tank thickness readings shall be recorded on a sketch of the tank or other appropriate inspection form that can locate and identify each TML of the tank.

ROUTINE EXTERNAL IN–SERVICE TANK SHELL SURVEYS

• Routine external in–service inspection of working tankage is an industry standard in accordance with API 653, Section 4.3.1. It shall be performed by knowledgeable personnel identified by the Owner at intervals not to exceed one month.
• The routine in–service inspection shall include a close visual inspection of the tank’s exterior surface, checking for: leaks of all kinds from all sources, obvious shell distortion, signs of unusual settlement, severe corrosion of the foundation, paint and coating conditions, insulation system conditions, and appurtenance conditions.

• A signed record of each routine in–service inspection shall be kept. Unless otherwise delegated by the plant management, the Inspection Authority shall verify these records are current for all applicable tankage. All substandard or questionable conditions resulting from these checks will be identified and communicated to the management for investigation.

QUARTERLY ROOF SURVEYS

• A quarterly roof visual survey of all existing tankage is a company requirement according to EP 15–4–1, Table 2.
• Items to be surveyed shall include such items as listed below:
• Vent screen clean and functioning properly.
• Evidence of failure of the roof support structure.
• Roof plate condition.
• Pressure/vacuum vent operable and screen clean.
• All hatches in proper position and operating properly.
• Gauging equipment operating properly.
• Water or product accumulation on roof.
• Debris on roof that may clog, or have already clogged the roof drain screen.
• Check to see that the non–return (check) valve in the roof drain is clear and free to operate.
• Roof unlevelness that could indicate flooded pontoon(s), some of the roof legs not in proper position, or improper operation of rolling roof ladder or anti–rotation device.
• Visually check pontoon compartments for presence of water or product. Once the pontoons are checked, verify that the pontoon manhole covers are correctly fastened down.
• General condition of roof deck for corrosion.
• Verify that the roof seals are operating freely and have not been damaged.
• Check operation of anti–rotation device to assure it is free to operate and is adequately lubricated.
• Check condition of roof ladder moving parts and assure they are adequately lubricated.
• Check operation of gauging equipment.
• All hatches in proper position and operating properly.
• Verify the integrity of all the grounding straps.
• In addition, the roof drain valve on the shell should be checked to:
• assure it opens and closes properly
• assure that it is in the correct position for operation
• verify the integrity of the drain hose or pipe.
• Verify that all the foam dams are in place and that the drain holes are clear of any debris.
• Verify that the foam piping is in operable condition.

EXTERNAL SHELL INSPECTION

• External visual inspection of all existing tankage is an industry standard requirement according to API 653, Section 4.2.
• It shall be performed, preferably while the tank is in service, at the earliest of a five year maximum interval or at the quarter corrosion–rate life, as specified in EP 15–4–1, by a Qualified Inspector according to API 653, Section 4.10.
• Any special federal jurisdictional requirements must also be satisfied as well as all current inspection suggestions contained in the inspection record.
• The Inspection Authority shall review Table C–1 of Appendix C of API 653 as a guideline for performing the external inspection and shall draw from it the appropriate items for inspection. Below are items that shall be considered for inclusion in the inspection as appropriate.
• The one foot bottom–to–shell area is usually the most highly stressed area of a tank. It must be especially well maintained and any potential problems investigated immediately. Larger tanks usually have higher stress levels and require the highest level of maintenance.
• As a minimum, tank shells shall be visually inspected for:
• Distortion, bulging, blistering and weld appearance. Shell buckling may be due to foundation settling.
• Distortion and corrosion of outside stiffeners and wind girders or cracking of the welds attaching these to the shell, including the shell to roof weld on fixed roof tanks.
• Drain holes in the stiffeners and wind girders should be checked to assure water is not accumulating and causing corrosion on these components.
• Cracking of attachment welds.
• Insulated tanks shall have the insulation and/or shell inspected for the following conditions:
• Evidence of corrosion under insulation.
• Loose or deteriorated insulation and insulation supports.
• Breakage, tears, or other breech of weather proofing that would permit water to penetrate the insulation.
• Protective coatings shall be examined for evidence of deterioration such as chalking, flaking, peeling, or blistering.
• External shell settlement shall be measured in accordance with EP 4–2–10 (consider group– lifting where necessary).
• Tank grounding bolts, bands, straps, and rods shall be examined to ensure they are in good condition and are making good electrical contact.

• Connecting piping shall be inspected for indications of binding or bending that could impose bending moments in shells and shell nozzles that could lead to excessive stresses.
• As a minimum, ladders, walkways, platforms, stairways and handrails shall be inspected for:
• Corroded, bent, broken, or missing structural parts.
• Loose or missing bolting.
• Worn stair treads and rungs.
• Cracked or deteriorated welds especially those intended to provide structural strength and stability.
• Foundations shall be inspected for:
• Evidence of anchor bolt corrosion and distortion.
• Evidence of loose anchor bolt nuts.
• Alignment measurements as necessary.
• See API 653 Section 2.5 for additional information.
• Earthen bases and dike areas of all tanks shall be inspected for:
• Erosion of the base pad and washing out of sand from around and under the floor plate especially at locations where water flooding has occurred (Consider stabilizing the foundation with a chemical gel type grout to stop such washing).
• Condition of the bitumen on the graded portion of the pad.
• Excessive and differential settlement of the shell into the base possibly resulting from foundation hard spots (Consider a low slump grout repair as appropriate).
• Condition of plinth seal between earthen base and floor plate, if present.
• Basins and drains located at the perimeter of the tank shall be inspected for settlement, deterioration, cracking, or other unusual conditions that may affect their performance or the integrity of the tank.
• Cathodic protection systems providing corrosion protection to tank floors shall be monitored to the extent and at intervals recommended in API 651.

GENERAL ROOF INSPECTION

• Roof Inspection performed by an Authorized Inspections shall be performed at least as frequently as the External Inspection discussed in Section 10 of this Practice.
• In addition to inspecting the items checked during the quarterly surveys, the following items shall also be inspected:
• Condition of the roof support legs, pins, and sleeves.

• Paint condition/corrosion of roof, including random thickness measurements of the roof plates. At least two thickness readings should be taken in each quadrant (For cone roofs, it is suggested one be taken one third and one two thirds the distance from the peak to the edge of the roof). Extreme care should be taken when climbing onto fixed roofs that may be corroded to the point they may not support a person’s weight.
• Excessive scale accumulation on the roof that may be indicative of significant corrosion occurring to the inside of the shell. Also check for any continuing vertically scribed lines that may indicate possible catastrophic cutting of the shell (Such grooving may be obscured by scale).
• Flat or distorted areas, bulging, blistering.
• Weld cracking in roof plates and attachments to the roof.
• Operation and condition of ladder, rollers, track and guardrails.
• Operation and condition of anti–rotation device.
• Any evidence that the roof is binding as it rises and falls during normal tank operation.

ROOF SEAL INSPECTION

• Periodic primary and secondary seal gap measurement of floating roof tanks is a Federal, State, and/or local jurisdictional requirement.
• Federal requirements are provided in 40 CFR Ch 1, Subpart K.
• Primary and secondary seal gap measurements shall be performed at least as frequently as required by the appropriate authority.

INTERNAL INSPECTION

• Internal inspection of existing tankage is an industry standard requirement primarily to determine the condition of the tank bottom and the other essential items as appropriate, according to API 653, Section 4.4. It shall be conducted within ten (10) years of tank operation when bottom corrosion experience or rates are not known and at intervals not to exceed 20 years if projected bottom corrosion–rate thicknesses do not reach the minimums of API 653 Table 4–1. Tanks may be operated down to the thicknesses specified in Table 4–1.
• The Inspection Authority shall review Table C–2 of Appendix C of API 653 as a guide line for performing internal inspection and shall draw from it the appropriate items for inspection. Below are items that shall be considered for inclusion in the inspection as appropriate.
• The one foot bottom–to–shell area is usually the most highly stressed area of a tank. It must be especially well maintained and any potential problems investigated immediately. Larger tanks usually have higher stress levels and require the highest level of maintenance.
• Shells, nozzles, and shell welds shall be inspected for the following conditions:
• Localized corrosion, pitting, and erosion.
• Blistering, bulging, buckling, or distortion.
• Cracking.
• When primary seals gap measurements, required by jurisdictional or federal regulations, cannot be measured during external inspections, they shall be performed during the internal inspection of the tank.
• Ultrasonic thickness measurements shall be taken of all apparently badly corroded areas of the roof and supporting structures.
• Unlined tank floors shall be inspected for evidence of corrosion and weld deterioration and cracking. All significant results shall be made part of the permanent record.
• The tank floor shall be inspected thoroughly over its entire area as follows:
• Close examinations shall be made of wet areas as possible indicators of through holes.
• Extensive UT thickness readings shall be taken of the floor. Areas indicating significant wall loss shall be carefully examined to define extent and severity of the loss.
• A floor scanner instrument may be used to measure or identify thin areas of the floor. For scanners utilizing the magnetic principles, a threshold thickness scanning limit shall be set at the greater of 1/2 the original nominal thickness of the floor plate or 0.150 inches. 100% of the area below the threshold limit shall be evaluated with ultrasonic thickness scanning.
• Other methods of locating leaks or thin areas are acceptable provided they have a proven record of success either in other plants or in verifiable demonstrations in other Owner plants.
• If leakage is suspected, at the discretion of the Inspector, the tank floor plate lap welds and annular plate butt welds may be vacuum box tested as follows:
• A minimum of –2 psig vacuum shall be maintained for 15 seconds at each spot tested.
• The leak testing solution shall be a commercially available product used exclusively for leak testing.
• For floors without double bottoms or secondary containment, coupons may be removed at the Inspector’s discretion in order to examine the condition of the underside of the floor or to verify indications from other inspection methods. Any coupons removed shall be taken at least twelve inches away from the floor to shell welds, annular plate to floor welds, or insert plate to floor welds, unless otherwise approved by an engineer competent in tank design.

• The annular plate and floor to shell weld shall be inspected carefully and thoroughly to assure sufficient plate thickness and weld integrity. Any unusual conditions or deterioration shall be noted and appropriate measurements taken.
• Floor sumps shall be closely inspected for possible corrosion (both top side and bottom side), cracking, or other unusual conditions that may cause leakage.
• The bottom plate minimum thickness for tanks without secondary containment shall be calculated as described in API 653, Section 2.4.7 and compared with Table 4–1 in API 653 for determining suitability for continued service.
• If the deterministic method is used, both MRT1 and MRT2 shall be calculated and the lowest value shall be utilized for determining the suitability of the floor for continued use.
• If a probabilistic method is used for determining the minimum thickness, the results for this calculation shall be demonstrated to be consistent with the deterministic method discussed above.
• The bottom plate minimum thickness for tanks built with secondary containment to the requirements of EP 4–2–7 shall be calculated as above except the values for the underside pitting depths and rates (UPa, UPm , and UPr ) may be assumed to be equal to 0.0.
• Tank linings and coatings shall be examined for evidence of deterioration such as delaminating within the coating or to the substrate, chemical attack, peeling, flaking, and blistering.
• Internal tank settlement monitoring shall be performed in accordance with EP 4–2–10.

TANK REPAIRS AND ALTERATIONS

• Tank repairs and alterations shall be performed in strict conformance with the requirements of API 653 and EP 9–1–5.
• The Inspection Authority may determine appropriate routine repairs.
• Any inspection findings, which in the opinion of the Inspection Authority, are unusual, or near the limits of acceptable tank design, shall be brought to the attention of personnel experienced in the design or analysis of tanks for evaluation and possible repair recommendations.

FINAL INSPECTION

• Upon completion of any required repair work, the tank shall receive a re–inspection of all work to ensure the completeness and adequacy of repair prior to closing. Inspection criteria shall be based on the applicable design or construction code.
• During closing, a responsible personnel shall inspect the tank to ensure that the proper closing procedure is followed.
• The Inspector shall determine if a partial or complete hydrostatic test is necessary per API 653, Section 10.3 and shall witness or designate a witness for the final pressure test of the tank. The date, hydrotest duration, hydrotest result(s), witness(es) name(s), test medium, and fill height in feet and inches shall be recorded in the inspection record.
• When a full hydrostatic test is performed on a tank, shell settlement measurements shall be performed per the requirements of EP 4–2–10.

INTEGRITY ASSURANCE

• Integrity assurance is a one–time fitness for use analysis for older tanks with limited history and then a continuing stress reduction effort to prevent or identify unnecessary stress conditions that may develop over time for all tanks.
• The one–time fitness for use analysis for older tanks with limited historical information must include the following areas of investigation:
• Consult available records for each tank and categorize according to potentially vulnerable types. All vulnerabilities must be investigated until no doubt remains regarding the tank integrity.
• Identify tanks that may have been originally constructed or undergone shell, bottom, or appurtenance repairs or replacement where the design or construction quality is unknown. Additional information regarding questionable tank integrity may become evident during consultation with field personnel or those familiar with a tank’s history. Of special concern are:
• Tanks constructed prior to 1961 when integrity standards were lower.
• Tanks constructed prior to 1961 and having shell plates thicker than 1/2” for embrittlement reasons.
• Tanks fabricated of ordinary structural steel, such as A–7, for embrittlement reasons.
• Tanks that have been rebuilt or have had repairs in critical locations.
• Tanks without evidence of the API symbol of adherence to API design criteria and those of unconventional design.
• Tanks whose product temperatures may range above 200ºF and/or are subject to frequent thermal cycling.
• Tanks whose contents (such as heavy oil stocks) may result in the deterioration of construction materials.
• A careful one–time external field inspection survey must then be conducted by an inspector familiar with tank construction to further identify any existing potentially questionable conditions. Evaluate:
• Weld appearance. Seam peaking or banding, general undercutting (say 1/64” for vertical seams and 1/32” for horizontal seams) should be evaluated for possible repair.
• Poor appearing shell–to–bottom welds.
• Pad or patch plates or other permanent shell attachments that may be welded across or near vertical tank shell seams or that may overlap or have their welds touch.
• Pad plates or tank shell cut–outs that may have square corners rather than a 3” or larger radiused corners.
• Two or more vertical seam welds that are in–line.
• Wind girder splice joints that may be near vertical weld seams (because a crack could run from a girder joint into the shell seam).
• All other tank appurtenances and attachments that do not appear conventional.
• All questionable conditions uncovered must be corrected or a program developed to satisfy concerns for integrity.
• A record of the conclusions reached during this integrity survey and analysis must be reported and made a part of the tank’s historical record.
• To assure the integrity of all tanks to perform safely under all expected service conditions, a continuing emphasis on stress reduction must accompany all construction and maintenance decisions made.

• Any changes noted in the conditions of the tank whether they may be in the shell, floor, foundation, roof, roof support structure, or other parts of the tank shall be evaluated per the requirements of API 651, 652, 653, 650, or 620, whichever is applicable to determine if the tank is suitable for continued service and project a date for subsequent inspection.

RECORDS AND DOCUMENTATION

• All external and internal inspection findings and repairs shall be reported and maintained in permanent records that shall provide an accurate history of each tank inspected in accordance with the following:
• Inspection findings shall be reported either on a sketch of the tank or an inspection form.
• Inspection findings shall be reported relative to their location in the tank.
• Inspection findings shall be reported in sufficient detail to permit relocation and evaluation of the reported condition.
• Corrosion–rate calculations and maximum inspection intervals or their basis (such as a PCMS report) shall be made part of the permanent record.
• Repair documentation shall contain sufficient detail to include the date the repair occurred, materials used, welding procedures used, examinations and testing performed and their results.
• Additional notes, sketches, or documents shall be appended to the tank inspection report, if required, to more fully describe the inspection findings or repairs performed.

RESPONSIBILITIES

• It is the responsibility of the Plant Inspection Authority or his delegate to:
• Serve as Final authority on all matters concerning inspection, including final acceptance.
• Assign personnel associated with the Inspection Operation.
• It is the responsibility of the Maintenance Supervisor or his delegate to:
• Open and prepare a tank for inspection, including flushing and otherwise cleaning the tank to the Inspector’s approval.
• Notify the Inspector when a tank is ready for internal inspection.
• Support any required maintenance operation involving cleaning, repairing, or altering.
• It is the responsibility of the Inspector to:
• Locate TML’s on the tank. Monitor corrosion rates and evaluate the need for reducing or increasing the number to provide adequate information on shell or bottom corrosion–rates.
• Perform a cursory inspection to determine if cleaning is needed to achieve a satisfactory thorough inspection.
• Evaluate inspection findings, and provide evaluation of potential repairs.
• Perform external and internal inspection of the tank and components in accordance with this Practice.
• Perform or supervise the taking of ultrasonic thickness readings of the tank shell, bottom, roof, and other components.
• Mark the tank shell to permit positive location of inspection findings.
• Supervise the removal of bottom coupons and perform coupon evaluation.
• Provide a marked up sketch of the tank or a completed report form indicating inspection findings and the location of findings.
• Observe all required repairs and alterations.
• Perform a final inspection of the tank before closing.

• Observe or delegate the observation of the closing and final pressure testing of the tank, if required.
• Report any unusual conditions to management that may require engineering evaluation.
• It is the responsibility of the Nondestructive Testing Technician to:

Perform and report ultrasonic (including thickness measurements), liquid dye penetrant, radiographic, magnetic particle, or other NDE methods according to testing company’s approved procedures.

• It is the responsibility of the Operations Department Representative to:
• Evaluate and approve tank area for safe entry according to plant safety procedures.
• Determine cleanliness for satisfactory operation of tanks, and sign off for closing tanks.
• Witness closing of tank manways.

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