CORROSION RATES AND INSPECTION INTERVALS

PIPING INSPECTION CODE: IN-SERVICE INSPECTION, RATING, REPAIR, AND ALTERATION OF PIPING SYSTEMS

CORROSION RATES AND INSPECTION INTERVALS

Oleh : Bayu Nurwinanto

CMLS (Condition monitoring location)

General

CMLs are specific areas along the piping circuit where inspections are to be made. The nature of the CML varies according to its location in the piping system. The selection of CMLs shall consider the potential for localized corrosion and service-specific corrosion as described in API 574 and API 571. Examples of different types of CMLS include locations for thickness measurement, locations for stress cracking examinations, locations for CUI and locations for high temperature hydrogen attack examinations.

CML Monitoring

Each piping system shall be monitored at CMLs. Piping circuits with high potential consequences of failure should occur and those subject to higher corrosion rates or localized corrosion will normally have more CMLs and be monitored more frequently. CMLs should be distributed appropriately throughout each piping circuit. CMLs may be eliminated or the number reduced under certain circumstances, such as olefin plant cold side piping, anhydrous ammonia piping, clean noncorrosive hydrocarbon product, or high-alloy piping for product purity. In circumstances where CMLS will be substantially reduced or eliminated, persons knowledgeable in corrosion should be consulted.

The minimum thickness at each CML can be located by ultrasonic scanning or radiography. Electromagnetic techniques also can be used to identify thin areas that may then be measured by UT or radiography. When accomplished with UT, scanning consists of taking several thickness measurements at the CML searching for localized thinning. The thinnest reading or an average of several measurement readings taken within the area of a examination point shall be recorded and used to calculate corrosion rates, remaining life.

Where appropriate, thickness measurements should include measurements at each of the four quadrants on pipe and fittings, with special attention to the inside and outside radius of elbows and tees where corrosion/erosion could increase corrosion rates. As a minimum, the thinnest reading and its location shall be recorded. The rate of corrosion/ damage shall be determined from successive measurements and the next inspection interval appropriately established. Corrosion rates, the remaining life and next inspection intervals should be calculated to determine the limiting component of each piping circuit.

CMLS should be established for areas with continuing CUI (Corrosion under insulation, including stress corrosion cracking under insulation), corrosion at S/A interfaces, or other locations of potential localized corrosion as well as for general, uniform corrosion.

CMLS should be marked on inspection drawings and on the piping system to allow repetitive measurements at the same CMLS. This recording procedure provides data for more accurate corrosion rate determination. The rate of corrosion/damage shall be determined from successive measurements and the next inspection interval appropriately established based on the remaining life or RBI (risk-based inspection) analysis.

CML Selection

In selecting or adjusting the number and locations of CMLS, the inspector should take into account the patterns of corrosion that would be expected and have been experienced in the process unit. A decision on the type, number and location of the CMLS should consider results from previous inspections, the patterns of corrosion and damage that are expected and the potential consequence of loss of containment. CMLS should be distributed appropriately over the piping system to provide adequate monitoring coverage of major components and nozzles. Thickness measurements at CMLS are intended to establish general and localized corrosion rates in different sections of the piping circuits. A minimal number of CMLS are acceptable when the established corrosion rate is low and the corrosion is not localized.

A number of corrosion processes common to refining and petrochemical units are relatively uniform in nature, resulting in a fairly constant rate of pipe wall reduction independent of location within the piping circuit, either axially or circumferentially. Examples of such corrosion phenomena include high-temperature sulfur corrosion and sour water corrosion (provided velocities are not so high as to cause local corrosion/erosion of elbows, tees, and other similar items). In these situations, the number of CMLS required to monitor a circuit will be fewer than those required to monitor circuits subject to more localized metal loss. In theory, a circuit subject to perfectly uniform corrosion could be adequately monitored with a single CML. In reality, corrosion is never truly uniform and in fact may be quite localized, so additional CMLS may be required. Inspectors must use their knowledge (and that of others) of the process unit to optimize the CML selection for each circuit, balancing the effort of collecting the data with the benefits provided by the data.

More CMLs (Condition monitoring location) should be selected for piping systems with any of the following characteristics : 

1. higher potential for creating a safety or environmental emergency in the event of a leak.
2. higher expected or experienced corrosion rates.
3. higher potential for localized corrosion.
4. more complexity in terms of fittings, branches, deadlegs, injection points, and other similar items.
5. higher potential for CUI (corrosion under insulation, including stress corrosion cracking under insulation).

Fewer CMLS can be selected for piping systems with any of the following three characteristics : 

1. low potential for creating a safety or environmental emergency in the event of a leak.
2. relatively noncorrosive piping systems.
3. long, straight-run piping systems.

CMLS can be eliminated for piping systems with any of the following characteristics :

1. extremely low potential for creating a safety or environmental emergency in the event of a leak.
2. noncorrosive systems, as demonstrated by history or similar service; and
3. systems not subject to changes that could cause corrosion as demonstrated by history and/or periodic reviews.

Every CML should have at least one or more examination points identified. Examples include :

1. locations marked on un-insulated pipe using paint stencils, metal stencils, or stickers.
2. holes cut in the insulation and plugged with covers.
3. temporary insulation covers for fittings nozzles, etc.
4. isometrics or documents showing CMLS.
5. radio frequency identification devices (RFID). 

Careful identification of CMLS and examination points are necessary to enhance the accuracy and repeatability of the data.

Corrosion specialists should be consulted about the appropriate placement and number of CMLs for piping systemssusceptible to localized corrosion or cracking, or in circumstances where CMLs will be substantially reduced or eliminated.

Inspection Intervals 

If RBI ( risk-based inspection)  is not being used, the interval between piping inspections shall be established and maintained using the following criteria : 

1. corrosion rate and remaining life calculations.
2. piping service classification.
3. applicable jurisdictional requirements.
4. judgment of the inspector, the piping engineer, the piping engineer supervisor, or a materials specialist, based on operating conditions, previous inspection history, current inspection results, and conditions that may warrant supplemental inspections. 

The owner/user or the inspector shall establish inspection intervals for thickness measurements and external visual inspections and, where applicable, for internal and supplemental inspections.

Thickness measurements should be scheduled at intervals that do not exceed the lesser of one half the remaining life determined from corrosion rates or the maximum intervals recommended in Table. Shorter intervals may be appropriate under certain circumstances. Prior to using Table, corrosion rates shall be calculated.

Table contains recommended maximum inspection intervals for Classes 1, 2 and 3 of piping services, as well as recommended intervals for injection points and S/A interfaces. Maximum intervals for Class 4 piping are left to the determination of the owner/user depending upon reliability and business needs.

The inspection interval shall be reviewed and adjusted as necessary after each inspection or significant change in operating conditions. General corrosion, localized corrosion, pitting, environmental cracking, and other applicable forms of deterioration mentioned in Section 5 shall be considered when establishing the various inspection intervals.

CUI (corrosion under insulation, including stress corrosion cracking under insulation) Inspection.

Inspection for CUI shall be considered for externally-insulated piping in areas or temperature ranges that are susceptible to CUI. CUI inspections may be conducted as part of the external inspection. If CUI damage is found during spot checks, the inspector should inspect other susceptible areas on the equipment.

Although external insulation may appear to be in good condition, CUI damage may still be occurring. CUI inspection may require removal of some or all insulation. If external coverings are in good condition and there is no reason to suspect damage behind them, it is not necessary to remove them for inspection of the equipment. CUI damage is often quite insidious in that it can occur in areas where it seems unlikely.

Considerations for insulation removal are not limited to but include :

1. history of CUI for the specific piping system or comparable piping systems.
2. visual condition of the external covering and insulation.
3. evidence of fluid leakage (e.g. stains or vapors).
4. whether the piping systems are in intermittent service.
5. condition/age of the external coating, if known.
6. evidence of areas with wet insulation.
7. the type of insulation used and whether that insulation is known to absorb and hold water.

Piping Service Classes 

General

All process piping systems shall be categorized into different piping classes. Such a classification system allows extra inspection efforts to be focused on piping systems that may have the highest potential consequences if failure or loss of containment should occur. In general, the higher classified systems require more extensive inspection at shorter intervals in order to affirm their integrity for continued safe operation. Classifications should be based on potential safety and environmental effects should a leak occur.

Owner/users shall maintain a record of process piping fluids handled, including their classifications. API 750 and NFPA 704 provide information that may be helpful in classifying piping systems according to the potential hazards of the process fluids they contain.

Class 1

Services with the highest potential of resulting in an immediate emergency if a leak were to occur are in Class 1. Such an emergency may be safety or environmental in nature. Examples of Class 1 piping include, but are not necessarily limited to those containing the following.

• Flammable services that can autorefrigerate and lead to brittle fracture.
• Pressurized services that can rapidly vaporize during release, creating vapors that can collect and form an explosive mixture, such as C2, C3, and C4 streams. Fluids that can rapidly vaporize are those with atmospheric boiling temperatures below 50 °F (10 °C) or where the atmospheric boiling point is below the operating temperature (typically a concern with high-temperature services)
• Hydrogen sulfide (greater than 3 % weight) in a gaseous stream.
• Anhydrous hydrogen chloride.
• Hydrofluoric acid.
• Piping over or adjacent to water and piping over public throughways (refer to Department of Transportation and U.S. Coast Guard regulations for inspection of over water piping).
• Flammable services operating above their auto-ignition temperature. 

Class 2

Services not included in other classes are in Class 2. This classification includes the majority of unit process piping  and selected off-site piping. Typical examples of these services include but are not necessarily limited to those containing the following :

• on-site hydrocarbons that will slowly vaporize during release such as those operating below the flash point.
• hydrogen, fuel gas, and natural gas.
• on-site strong acids and caustics. 

Class 3

Services that are flammable but do not significantly vaporize when they leak and are not located in high-activity areas are in Class 3. Services that are potentially harmful to human tissue but are located in remote areas may be included in this class. Examples of Class 3 service include but are not necessarily limited to those containing the following :

• on-site hydrocarbons that will not significantly vaporize during release such as those operating below the flash point.
• distillate and product lines to and from storage and loading.
• tank farm piping.
• off-site acids and caustics. 

Class 4

Services that are essentially nonflammable and nontoxic are in Class 4, as are most utility services. Inspection of Class 4 piping is optional and usually based on reliability needs and business impacts as opposed to safety or environmental impact. Examples of Class 4 service include, but are not necessarily limited to those containing the following :

• steam and steam condensate.
• air.
• nitrogen.
• water, including boiler feed water, stripped sour water.
• lube oil, seal oil.
• ASME B31.3, Category D services.
• plumbing and sewers.

Assessment of Inspection Findings 

Pressure containing components found to have degradation that could affect their load carrying capability [pressure loads and other applicable loads (e.g. weight, wind, etc., per API 579-1/ASME FFS-1)] shall be evaluated for continued service. Fitness-For-Service techniques, such as those documented in API 579-1/ASME FFS-1, Second Edition, may be used for this evaluation. The Fitness-For-Service techniques used shall be applicable to the specific degradation observed. The following techniques may be used as applicable.

To evaluate metal loss in excess of the corrosion allowance, a Fitness-For-Service assessment may be performed in accordance with one of the following sections of API 579-1/ASME FFS-1. This assessment requires the use of a future corrosion allowance, which shall be established.

• Assessment of General Metal Loss—API 579-1/ASME FFS-1.
• Assessment of Local Metal Loss—API 579-1/ASME FFS-1.
• Assessment of Pitting Corrosion—API 579-1/ASME FFS-1.

To evaluate blisters and laminations, a Fitness-For-Service assessment should be performed in accordance with API 579-1/ASME FFS-1. In some cases, this evaluation will require the use of a future corrosion allowance, which shall be established.

To evaluate weld misalignment and shell distortions, a Fitness-For-Service assessment should be performed in accordance with API 579-1/ASME FFS-1.

To evaluate crack-like flaws, a Fitness-For-Service assessment should be performed in accordance with API 5791/ASME FFS-1.

To evaluate the effects of fire damage, a Fitness-For-Service assessment should be performed in accordance with API 579-1/ASME FFS-1.

Piping Stress Analysis (Analisis Piping Stres)

Piping shall be supported and guided so that : 

• its weight is carried safely.
• it has sufficient flexibility for thermal expansion or contraction, and.
• it does not vibrate excessively.

Piping flexibility is of increasing concern the larger the diameter of the piping and the greater the difference between ambient and operating temperature conditions. 

Piping stress analysis to assess system flexibility and support adequacy is not normally performed as part of a piping inspection. However, many existing piping systems were analyzed as part of their original design or as part of a rerating or modification, and the results of these analyses can be useful in developing inspection plans. When unexpected movement of a piping system is observed, such as during an external visual inspection the inspector should discuss these observations with the piping engineer and evaluate the need for conducting a piping stress analysis.

See API 574 for more information on pressure design, minimum required and structural minimum thicknesses, including formulas, example problems and default tables of suggested. 

Piping stress analysis can identify the most highly stressed components in a piping system and predict the thermal movement of the system when it is placed in operation. This information can be used to concentrate inspection efforts at the locations most prone to fatigue damage from thermal expansion (heat-up and cooldown) cycles and/or creep damage in high-temperature piping. Comparing predicted thermal movements with observed movements can help identify the occurrence of unexpected operating conditions and deterioration of guides and supports. Consultation with the piping engineer may be necessary to explain observed deviations from the analysis predictions, particularly for complicated systems involving multiple supports and guides between end points.

Piping stress analysis also can be employed to help solve observed piping vibration problems. The natural frequencies in which a piping system will vibrate can be predicted by analysis. The effects of additional guiding can be evaluated to assess its ability to control vibration by increasing the system’s natural frequencies beyond the frequency of exciting forces, such as machine rotational speed. It is important to determine that guides added to control vibration do not adversely restrict thermal expansion.