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TECHNICAL MODULE ABOVEGROUND STORAGE TANKS DNV B ASE RESOURCE DOCUMENT

API 581, CHAPTER O

DET NORSKE VERITAS

American Petroleum Institute Aboveground Storage Tanks – RBI Module

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CONTENTS 1.

SCOPE ..........................................................................................................................................1 1.1 Overview of Frequency Analysis ............................................................................................1 1.2 Overview of Consequence Analysis .......................................................................................1 1.3 Objective and Overview of Risk Analysis..............................................................................2 1.3.1

Quantitative Risk..............................................................................................................2

1.3.2

Qualitative Risk................................................................................................................2

2.

REQUIRED DATA AND LIMITATIONS................................................................................5 2.1 Limitations................................................................................................................................6

3.

FREQUENCY ANALYSIS METHODOLOGY .......................................................................7 3.1 Base Failure Frequency............................................................................................................7 3.2 Basic Assumptions ...................................................................................................................9 3.3 Soil Side Corrosion Rate........................................................................................................11 3.4 Product Side Corrosion Rate .................................................................................................14 3.5 Determination of Tank Bottom Leak Frequency .................................................................17 3.6 Summary – Leak Frequency Calculation..............................................................................20 3.7 Rapid Bottom Failures ...........................................................................................................24

4.

TANK SHELL LEAK FREQUENCY......................................................................................25 4.1 Failure Frequency...................................................................................................................25 4.2 Tank Shell Excluded ..............................................................................................................26

5.

APPLICATION AND EXAMPLES .........................................................................................27 5.1 Similar Service........................................................................................................................27 5.2 Measured Corrosion...............................................................................................................27 5.3 Repair and Replacement ........................................................................................................28 5.4 Examples – Likelihood Calculation ......................................................................................28 5.5 Likelihood of Failure Calculation – Flow Chart ..................................................................32

6.

CONSEQUENCE ANALYSIS METHODOLOGY................................................................34 6.1 Bottom Leaks..........................................................................................................................35 6.1.1

Foundation Conditions................................................................................................. 35

6.1.2

Three-Dimensional Flow.............................................................................................. 38

6.1.3

Consequence Analysis Methodology ........................................................................... 38

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6.2 Shell and Fitting Leaks...........................................................................................................41 6.3 Rapid Shell and Floor-to-Shell Failures................................................................................41 7.

REPAIR, REPLACEMENT, AND BUSINESS INTERRUPTION COSTS .........................42 7.1 Downtime Consequence Costs..............................................................................................42

8. 9.

CONSEQUENCE CALCULATION SUMMARY..................................................................43 RISK ANALYSIS METHODOLOGY.....................................................................................46 9.1 The Risk Scoring System.......................................................................................................46 9.2 The Risk Matrix......................................................................................................................48 9.3 Risk Calculations....................................................................................................................49 9.4 Steps in Conducting an AST Risk Assessment....................................................................50 9.5 Risk Results ............................................................................................................................51 9.6 Risk Assessment.....................................................................................................................51

10. INSPECTION PLANNING.......................................................................................................53 10.1 Objective .............................................................................................................................53 10.2

Inspection Planning Criteria ..............................................................................................53

10.3

Manual Inspection Planning ..............................................................................................53

10.4

Automated Inspection Planning ........................................................................................53

10.4.1 Inspection (Equipment Level only): ............................................................................. 53 10.4.2 Target (Batch and Equipment Level):.......................................................................... 54 10.4.3 Automated Inspection Planning – In the ABPI RBI Software.................................... 54 11. REFERENCES ...........................................................................................................................57

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SCOPE The Aboveground Storage Tank (AST) Module consists of three parts: (1) Failure Frequency Analysis, (2) Consequence Analysis, and (3) Risk Analysis. The basic approach used in the Aboveground Storage Tank Module is to modify a generic failure frequency for tank bottom failures by a factor related to both the potential degradation occurring in the particular service and the type of inspection performed.

1.1

Overview of Frequency Analysis The estimation of a component’s leak frequency is found, for most items, using a modifying factor to adjust a base (generic) failure frequency. This modifier is referred to as the modifying factor. In mathematical terms, the leak frequency is found using the following expression: Leak Frequency = Base Failure Frequency × Modifying Factor Equation 1-1

When necessary, leak frequencies are combined to produce an overall equipment spill frequency. The scenarios in the risk model dictate how to combine component frequencies for an item. For each component, the likelihood of various hole sizes is required as input to the risk analysis for each scenario. As a result, the fraction of leaks of a given size are also derived as part of the frequency analysis. 1.2

Overview of Consequence Analysis The consequence of a spill is measured in dollars and consists of environmental clean-up costs, environmental penalties, repair costs, and lost opportunity costs. Total Cost = Environmental Clean-up Costs + Environmental Penalties + Repair Costs + Lost Opportunity Costs Equation 1-2

The basic approach to estimating the environmental clean-up costs of a scenario is to add the cost for the various clean-up methods needed to remediate a spill. For instance, if a spill leads to groundwater contamination, the components of the cleanup may consist of soil remediation onsite, soil remediation offsite, and groundwater clean up. Each component has a Clean-Up Factor (CUF) that is based on the location of the spill and the type of material spilled. The unit of measure for the CUF is dollars per barrel ($/bbl). In mathematical terms, the cost for each component of the environmental clean-up operation is expressed as follows: Environmental Clean-Up Cost = Volume × CUF Equation 1–3

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The costs for environmental penalties, repair costs, and lost opportunity costs are input by the user. 1.3

Objective and Overview of Risk Analysis The overall objective of this technical module is to develop a practical risk assessment process applicable to Aboveground Storage Tanks (ASTs) to assist in the selection of control measures to prevent liquid releases. To satisfy this objective, both a quantitative scoring system and a risk matrix were developed to estimate and display risks and to assist the user in selecting control measures. Some typical control measures might include inspections, internal lining, and repair/replacement of the tank bottom.

1.3.1 Quantitative Risk One way to portray risk quantitatively is to produce a point-estimate of risk from the consequence-frequency data pair. This is usually done by multiplying the likelihood and consequence data points together to produce a measure with units of “consequence per year.” The mathematical expression for this score is as follows: Risk = Likelihood × Consequence Equation 1–4

Multiplying likelihood and consequence together is convenient because it reduces the risk measure to a single point. The single risk point is often referred to as the expected value of risk for a scenario, and it can be thought of as a probability-weighted consequence estimate. 1.3.2 Qualitative Risk The above method portrays risk in quantitative terms. As an alternative, risk could be represented in qualitative terms, such as a low, medium or high risk. The qualitative assessments of likelihood and consequence can be assigned to categories. For instance, a low probability might be placed in Category 1, and a medium consequence might be assigned Category C. These values can then be displayed in a matrix. Figure 1-1 shows a risk matrix displaying five levels of likelihood and five levels of consequence.

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5 4 3 Plot of a scenario with a rating of C-1

2 1 A

B C D CONSEQUENCE

E

Figure 1-1: The Five-By-Five Risk Matrix

Risk increases from the lower left corner to the upper-right corner of the matrix. So, E-5 would be the highest risk point on the matrix, and A-1 would be the lowest. Levels of risk can be expressed in a matrix by assigning risk-levels to the various squares in the matrix. It is important to note that assigning risk-levels to squares on the matrix is a reflection of the company’s policies and attitudes about risk acceptability. Many companies choose not to assign levels of risk within a matrix. If a company assigns does so, then decisions can be made regarding the disposition of various scenarios. Figure 1-2 provides an example of risk-levels assigned in a five-by-five matrix.

medium-high risk

5

high risk

4 3 2 low risk

medium risk

1 A

B

C D CONSEQUENCE

E

Figure 1-2: Risk Matrix Showing Levels of Risk

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The matrix shown in Figure 1-2 portrays risk as neutral to likelihood or consequence. For instance, risk point C-1 has the same level of risk as A-3. To reflect aversion to one of the two elements of risk, the risk levels represented by the shaded areas are shifted, as shown in the figure below. In Figure 1-3, an aversion to consequence is shown by assigning a higher risk level to higher consequences for some levels of likelihood.

medium-high risk

5

high risk

4 3 2 low risk

medium risk

1 A

B C D CONSEQUENCE

E

Figure 1-3: A Risk Matrix Showing Consequence-Aversion

When compared to the unbiased matrix in Figure 1-2, note that risk point C-1 is assigned a risk level of ‘medium,’ rather than ‘low.’ Other blocks on the matrix are changed to reflect an aversion to consequence in Figure 1-3.

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2.

5

REQUIRED DATA AND LIMITATIONS The basic data listed in Table 2-1 is the minimum required to determine a modifying factor for thinning when a corrosion rate has not been established by one or more effective inspections. Table 2-1: Basic Data Required for Bottom Leak Analysis

Basic Data Age (years)

Bottom External Corrosion Rate (mpy) Bottom Internal Corrosion Rate (mpy) Bottom Thinning Type (Widespread or Localized)

Bottom Type Cathodic Protection Inspection Rating Category Internal Lining Age (years) Internal Lining Needed Number of Inspections Operating Temperature (°F) Soil Resistivity (ohm–cm) Tank Drainage Tank Pad Tank Steam Coil Heater Thickness (mils)

Water Draws

API 581 Appendix O.doc

Comments The number of years that the equipment has been exposed to the current process conditions that produced the corrosion rate used below. The default is the equipment age. However, if the corrosion rate changed significantly, perhaps as a result of changes in process conditions, the time period and the thickness should be adjusted accordingly. The time period will be from the time of the change, and the thickness will be the minimum wall thickness at the time of the change (which may be different from the original wall thickness). The expected or observed corrosion rate for a “typical” tank under “average” conditions, i.e. neither highly susceptible to corrosion nor especially resistant to corrosion. The expected or observed internal corrosion rate of the tank bottom. Determine whether the thinning is widespread or localized for inspection results of effective inspections. Widespread corrosion is defined as affecting more than 10% of the surface area and the wall thickness variation is less than 50 mils. Localized corrosion is defined as affecting less than 10% of the surface area or a wall thickness variation greater than 50 mils. Single or Release Prevention Barrier (RPB). The existence of a cathodic protection system for the tank bottom, and the proper installation and operation of such a system, based on API 651. The rating category of each inspection that has been performed on the equipment during the time period (specified above). Based on the installation date, or the last date of lining rehabilitation. Yes or No. Is a lining needed to protect the tank bottom and shell from the corrosive nature of the product? The number of inspections in each rating category that have been performed during the time period (specified above). The highest operating temperature expected during operation (considering both normal and unusual operating conditions). Soil resistivity under the tank or dike field. (A common method of measuring soil resistivity is described in ASTM G 57.) The effectiveness with which rain water is drained away from the tank, and prevented from collecting under the tank bottom. The type of material upon which the tank rests. In the case of a tank supported on a ring wall, the material used for fill inside the wall. Yes or No. If a steam coil heater is utilized, the internal corrosion is adjusted upwards slightly due to extra heat, and the possibility of steam leaks. The actual measured thickness upon being placed in the current service, or the minimum construction thickness. The thickness used must be the thickness at the beginning of the time in service reported below. Water draws when consistently used can greatly reduce the damaging effects of water at the bottom of the tank.

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2.1

6

Limitations The following limitations apply to this technical module. •

The module is only applicable for aboveground atmospheric storage tanks with carbon steel floors.

•

Product is assumed to be hydrocarbons (gasoline, diesel oil, crude oil, fuel oil, etc.). The representative fluids that can be assigned are: Table 2-2 Available Representative Fluids ABI RBI Fluid Group

AST fluid description

API RBI Type fluids included

C6-C8

Gasoline

Gasoline, Naphtha, Heavy Naphtha, Light Straight Run, Heptane *EE; HF; PO; EEA; Methanol; Styrene; Aromatics

C9-C12 and C13-C16

Diesel Oil

Diesel, Kerosene

C17-C25

Fuel and Crude Oil

Jet Fuel, Atmospheric Gas Oil, Typical Crude, Vacuum Column Top, Light Vacuum Gas Oil *Acid (Low, Med and High)

C25+

Asphalt

Residuum, Heavy Crude, Heavy Vacuum Gas Oil

*EG; EO (*) Denoted items are liquid groups that are not specified under any of the default hydrocarbon groups in the API RBI Software (November 2001), but based on the viscosity @75°F can be associate to the listed group – the most conservative (lowest) viscosity value is used (gives the highest consequence). Reference GPSA and ‘Perries Handbook of Chemical Eng’. for Viscosity values.

•

Failure mechanism is generally assumed to be corrosion thinning from product and soil side. The one exception is that brittle fracture of the shell, or shell to floor joint, is included. Failure mechanisms such as cracking and bulging are not considered.

•

Vapor space corrosion is not specifically addressed since it does not generally lead to a loss of containment. Repair costs and lost opportunity costs can be included by adding a separate line in the AST Risk Scoring Table (Table 9-1).

•

Consequence does not consider Toxicity and Fatality issues. The consequence and risk are expressed in US$. The cost contributors to the risk are Financial Risk and Environmental Clean-Up. The Financial Risk is the accumulated cost related to Equipment Damage, Outage time (lost business opportunities), Repairs and Environmental Penalties.

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3.

FREQUENCY ANALYSIS METHODOLOGY

3.1

Base Failure Frequency The base failure frequency for the leak of a tank bottom was derived primarily from an analysis of the American Petroleum Institute publication A Survey of API Members’ Aboveground Storage Tank Facilities, Health and Environmental Affairs Department, July 1994. The analysis focused on the ASTs that were operated at refineries across the United States during 1983-1993. Sixty-one refineries provided data on over 10,000 storage tanks – which represents over 80% of all such tanks operated by refineries in the United States. Figure 3-1 shows the number of tanks of each size included in the survey.

NUMBER OF TANKS 3000 2500 2000 1500 1000 500 0 1,000

10,000

50,000

100,000

> 100,000

CAPACITY (BARRELS) Figure 3-1: Survey of Storage Tanks

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One of the most significant findings of the survey was that tank bottom leaks contributing to soil contamination had been cut in half in the last five years compared to the first five years covered by the survey. This was attributed to an increased awareness of the seriousness of the problem, and to the issuance of the API 653 standard for aboveground storage tank inspection. Table 3-1 shows the highlights of the survey results. Table 3-1: Summary of Survey Results Population Description Number of Percent with Number with Tank Years * Bottom leak frequency tanks leaks in bottom leaks in bottom in (1988 – 1993) in last five years last five years Tanks < 5 years old

466

0.9%

4

2330

1.7 × 10 -3

Tanks 6 – 15 years old

628

3.8%

24

3140

7.6 × 10 -3

Tanks > 15 years old

9204

3.8%

345

46020

7.5 × 10 -3

51490

7.2 × 10 -3

All tanks in survey 10298 3.6% 373 * Tank years = number of tanks × average number of years in service

A bottom leak frequency of 7.2×10-3 leaks per year was chosen as the base leak frequency. Although the leak frequency data in Table 3.1 indicates that tanks less than 5 years old have a much lower leak frequency, it was decided to use the whole survey population in setting the base leak frequency. The age of the tank is elsewhere accounted for in the model since the percent wall loss is a function of the tank age, corrosion rate, and original wall thickness. The percent wall loss is the basis of the modifier on the base leak frequency. Thus a very young tank with minimal corrosion will have a frequency modifier less than one which will lower its leak frequency accordingly. The survey did not report the size of leaks, but an informal survey of sponsors for the API RBI project indicated that leak sizes of up to ½" in diameter would adequately describe the vast majority of tank bottom leaks. Rapid bottom failures (or failures at the bottom/shell interface) although rare, do occur. Based on DNV’s experience and the experience of the committee members, an expected frequency distribution of each leak size is presented in Table 3-2. Table 3-2: Base Leak Frequencies for Tank Bottom Hole sizes

API 581 Appendix O.doc

Percentage

Frequency (per year)

Small Bottom Leak (≤½”)

99.72%

7.20 × 10 -3

Rapid Bottom Failure

0.28%

2.00 × 10 -5

Total

100%

7.22 × 10 -3

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3.2

9

Basic Assumptions The approach used for ASTs applies to aboveground storage tanks subject to damage from both internal and external corrosion. Widespread and localized corrosion (which includes pitting and erosion-corrosion) are within the scope of the module. The modifying factor assumes that the thinning mechanism has resulted in a constant rate of thinning/pitting over the time period defined in the basic data. The likelihood of failure is estimated by examining the possibility that the corrosion rate is greater than expected. The likelihood of discovering these higher rates is determined by the number and type of inspections that have been performed. The more thorough the inspection, and the greater the number of inspections, the less likely is the chance that the corrosion rate is greater than anticipated. Figure 3-2 shows a flow chart of the steps required to determine the leak frequency modifying factor for tank bottoms. These steps are discussed in Sections 3.3 – 3-6, along with the required tables. Note: If the corrosion rate from an A or B Level inspection varies significantly from that predicted by the model (as shown in the flowchart on Figure 3-2), then the measured corrosion rate should take precedence. The model can then be recalibrated by adjusting the base corrosion rates so that the model agrees with the measured corrosion rate.

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Soil Side

Product Side

- Average time to leakage - Thickness - "Default" = 5 mpy

Establish Base Corrosion Rate for Soil Side Corrosion (5 mpy)

Establish Base Corrosion Rate for Internal Bottom Corrosion (2-5 mpy)

Resistivity, See Table 3.4

Adjust for Soil Conditions (0.66-1.5)

Adjust for Internal Lining (0.3-1.75)

Lining needed? Applied according to API 652? See Table 3.12

Tank Pad Type, See Table 3.5

Adjust for Tank Pad Material (0.7-1.5)

Adjust for Lining Age (0.66-2.5)

Lining age? Applied according to API 652? See Table 3.13

Drainage, See Table 3.6

Adjust for Drainage (1.0-1.4)

Cathodic Protection, See Table 3.7

Adjust for Cathodic Protection (0.33-1.0)

Adjust for Operating Temperature (1.0-1.4)

Bulk Fluid Temperature, See Table 3.14

Bottom Design, See Table 3.8

Adjust for Bottom Type (1.0-1.4)

Adjust for Steam Coil Heater (1.0-1.15)

Use of Steam Coil Heater, See Table 3.15

Bulk Fluid Temperature, See Table 3.9

Adjust for Operating Temperature (1.0-1.4)

Adjust for Water Draws (0.6-1.0)

Water Draw, See Table 3.16

Calculate Modified Soil Side Corrosion Rate (Always Localized)

Product Side CR Type is Widespread

Calculate Modified Product Side Corrosion Rate (Widespread or Localized)

Is Product Side Bottom Corrosion Widespread or Localized?

Sum Corrosion Rates

- Inspection Data - BS&W - pH, etc. - See Table 3.10

Product Side CR Type is Localized Use the Greater of Corrosion Rates

Calculate ‘ar/t’ for looking up Modifying Factor in Table (3.18)

Figure 3-2: Flow Chart to Determine Modifying Factor for Tank Bottoms

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3.3

11

Soil Side Corrosion Rate Establish Base Corrosion Rate for Under Bottom (External) Corrosion The base corrosion rate is the expected or observed corrosion rate for a typical tank under average conditions, i.e. neither highly susceptible to corrosion nor especially resistant to corrosion. A base corrosion rate of 5 mpy might be typical. The base corrosion rate is founded on the conditions stated in Table 3-3. Table 3-3: Summary of Conditions for Soil Side Base Corrosion Rate Factor

Base Corrosion Rate Conditions

Soil Resistivity

Moderately corrosive (1000-2000 ohm-cm)

Tank Pad Material

Continuous asphalt or concrete

Tank Drainage

Storm water does not collect around base of tank

Cathodic Protection

None or not functioning

Bottom Type

Single Bottom

Bulk Fluid Temperature

Below 75°F

Adjust for Soil Conditions The resistivity of the native soil beneath the tank pad can affect the corrosion rate of the tank bottom. The resistivity of the tank pad material may be higher than the existing surrounding soil. However, corrosive soil beneath the high resistivity tank pad material may contaminate the tank pad fill by capillary action1. Thus, resistivity of the surrounding native soil may be used to determine the likelihood of corrosion on the tank bottom. Table 3.4 gives corrosion rate adjustment factors for soil resistivities. A common method of measuring soil resistivity is described in ASTM G 57. If the soil resistivity is not known, then assume moderately corrosive soil (adjustment factor equals 1). An adjustment factor of 1 should be used for tanks with RPBs, since RPBs effectively prevent the contamination of the tank pad material by the native soil. Table 3-4: Native Soil Resistivity Adjustment Resistivity (ohm-cm)

Potential Corrosion Activity

Adjustment Factor

10000

Progressively Less Corrosive

0.66

Tank with RPB

1

1

See API RP 651, Section 5.3.1

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Adjust for Tank Pad The type of pad or foundation that the tank rests upon will influence the corrosion rate. The adjustment factors are assigned in a similar manner to those for the native soil beneath the tank pad. Table 3-5 gives corrosion rate adjustment factors for tank pads. Table 3-5: Tank Pad Adjustment Type

Adjustment Factor

Soils with high concentrations of salts

1.5

Crushed limestone

1.4

Native soil

1.3

Construction grade sand

1.15

Continuous asphalt

1

Continuous concrete

1

Oil sand

0.7

High resistivity, low chloride sand

0.7

Adjust for Drainage Rainwater collecting around the base of the tank can greatly increase corrosion. Table 3-6 gives corrosion rate adjustment factors for drainage conditions. The adjustment is made so that storm water collecting around a tank will cause the base corrosion rate to increase by 40%. Good drainage is considered normal, so the multiplier is set to 1 if water does not normally collect around the base of the tank. Table 3-6: Tank Drainage Adjustment Type of Drainage

Adjustment Factor

Storm water usually collects around the base of the tank

1.4

Storm water does not usually collect around the base of the tank

1

Adjust for Cathodic Protection Cathodic protection is one of the primary methods used to avoid corrosion of tank bottoms from the soil side. However, the system must be installed and maintained properly. Table 3.7 gives corrosion rate adjustment factors for cathodic protection. The factor is established so that the most credit is given for a properly functioning cathodic protection (CP) system in accordance with API 651, but no penalty is assessed for lack of CP. This assumes that the base corrosion rate is for systems without cathodic protection.

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Table 3–7: Adjustment for Cathodic Protection Functional Cathodic Protection in Place?

Adjustment Factor

NO

1

YES (not per API 651)

0.66

YES (installed and maintained per API 651)

0.33

Adjust for Bottom Type, Single or RPB Tanks with properly installed release prevention barriers (RPBs) tend to have bottom corrosion rates comparable to those with a single bottom. Both tanks with a single bottom and those with RPBs installed according to API 650 have an adjustment factor of 1 while a tank with a non-API 650 RPB is given an adjustment factor of 1.4. Adjustments for bottom type are provided in Table 3.8. Table 3–8: Adjustment for Bottom Type Bottom Type

Adjustment Factor

RPB (not per API 650)

1.4

RPB (designed and maintained per API 650)

1

Single bottom

1

Operating Temperature Adjustment The operating temperature of the tank may influence external corrosion. Below 75°F, the factor is neutral (1). For temperatures between 75°F and 150°F, the factor is 1.1. If the average operating temperature is between 150°F and 200°F, the factor is 1.3. For temperatures between 200°F and 250°F, the factor is 1.4. Above 250°F, the factor returns to 1. Table 3.9 gives corrosion rate adjustment factors for bulk fluid temperatures. Table 3–9: Adjustment for Fluid Temperature

API 581 Appendix O.doc

Bulk Fluid Temperature (°F)

Adjustment Factor

≤ 75

1

76 – 150

1.1

151 – 200

1.3

201 – 250

1.4

>250

1

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American Petroleum Institute Aboveground Storage Tanks – RBI Module

3.4

14

Product Side Corrosion Rate Establish Base Corrosion Rate for Product Side (Internal) Corrosion Tank bottoms can corrode from the inside of the tank as well as the outside. Base corrosion rates for product side corrosion can be obtained from previous internal inspection data, or may be assumed to approximate the corrosion in the lower inch or two of the shell, if significant bottom sediments and water (BS&W) are present. For dry product tanks, the internal corrosion can be insignificant. Table 3.10 shows the suggested base corrosion rates. Table 3–10: Product Side Base Corrosion Rates Product Condition

Base Corrosion Rate (mpy)

Dry

2

Wet

5

A summary of the conditions assumed for the product side base corrosion rate is given in Table 3.11 below. Table 3–11: Summary of Conditions for ‘Base’ Product Side Corrosion Rate Factor

Base Corrosion Rate Conditions

Internal lining

Internal lining not needed for corrosion protection and none applied

Bulk fluid temperature

Below 75°F

Steam coil heater

No

Water draws

No (Water draws conducted neither weekly nor after every receipt)

Adjust for Internal Lining (Coating) To protect the tank bottom from internal corrosion, a lining may be needed. A lining is a coating bonded to the internal surfaces of a tank to serve as a barrier to corrosion by the contained fluids. If an internal lining is needed, the adjustment factor is 1.15, if not, the factor is 1. If the required lining is applied in accordance with API 652 then there is a further reduction to 0.5 as shown in Table 3.12. The table also shows the benefit of applying an internal lining when none is required (0.3 – 0.6) and the demerit of failing to apply a lining when needed (1.75). Further adjustment is made based on the age of the lining, as illustrated in Table 3.13a. If there is no lining, then Table 3.13a is ignored and only one adjustment factor is used – either 1 or 1.75 from Table 3.12. If a Liner is applied, the lining factor is set to 1 and the Liner adjustment factor is derived form table 3.13b

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Table 3–12: Internal Lining (Coating) Adjustment Is internal lining needed for corrosion protection?

Adjustment Factor

YES (but no internal lining or unknown)

1.75

YES (internal lining applied, but not according to API 652)

1.15

YES ( internal lining applied per API 652)

0.5

NO (and no lining applied)

1

NO (internal lining applied anyway but not according to API 652)

0.6

NO (but internal lining applied according to API 652)

0.3

* To determine the need for internal bottom lining, see API Recommended Practice 652.

Table 3–13a: Lining (Coating) Age Adjustment Lining Application and Age

Adjustment Factor

Lining applied per API 652 > 20 years – limited or no data to assess lining condition

2.5

> 20 years – data to demonstrate that lining is in good condition

1

10 – 20 years

1

< 10 years

0.66

Lining not applied per API 652 > 10 years – limited or no data to assess lining condition

1.5

> 10 years – data to demonstrate that lining is in good condition

1

5 – 10 years

1

< 5 years

0.87

Table 3–13b Liner (FRP Type) Age Adjustment Liner Age and Condition

Adjustment Factor

< 10 years OR Good Condition

0.2

10 – 20 years OR Fair Condition

0.33

> 20 years OR Poor Condition

1

Fiberglass Liners If an internal liner (e.g. fiberglass or FRP Type liner) is applied rather than a lining (coating) then a different approach is used since the liner also provides a second barrier to a leak. The adjustment factors from Tables 3.12 and 3.13a are set to 1. The final bottom leak frequency, as calculated in Section 3.5, is multiplied by a factor that is dependent on the condition of the liner. If the liner is in good condition (or 20 years old) the factor is 1. Operating Temperature Adjustment The operating temperature of the tank may influence internal corrosion. Below 75°F, the factor is neutral (1). For temperatures between 75°F and 150°F, the factor is 1.1. If the average operating temperature is between 150°F and 200°F, the factor is 1.3. For temperatures between 200°F and 250°F, the factor is 1.4. Above 250°F the factor returns to 1. Table 3.14 gives corrosion rate adjustment factors for bulk fluid temperatures. Table 3–14: Adjustment for Fluid Temperature Bulk Fluid Temperature (°F)

Adjustment Factor

≤ 75

1

76 – 150

1.1

151 – 200

1.3

201 – 250

1.4

>250

1

Steam Coil Heater Adjustment If a steam coil heater is present, the internal corrosion rate is adjusted upwards slightly due to extra heat, and the possibility of steam leaks from the internal coil. Table 3.15 gives corrosion rate adjustment factors for steam coil heaters. Table 3–15: Steam Coil Heater Adjustment Does tank have a steam coil heater?

Adjustment Factor

YES

1.15

NO

1

Adjust for Water Draws Water draws when consistently used can greatly reduce the damaging effects of water at the bottom of the tank. To receive the full benefit, water must be drawn weekly or after every receipt. Table 3.16 shows the adjustment factors for water draws. Table 3–16: Water Draw Adjustment Are water draws conducted either weekly or after every receipt?

API 581 Appendix O.doc

Adjustment Factor

NO

1

YES

0.6

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American Petroleum Institute Aboveground Storage Tanks – RBI Module

3.5

17

Determination of Tank Bottom Leak Frequency Estimate Internal and External Corrosion Rates The internal and external corrosion rates are estimated by multiplying the base corrosion rate by the respective adjustment factors. This will produce two separate corrosion rates that are combined as described below. It is assumed that the soil side corrosion will be localized in nature while the product side corrosion will be either widespread or localized. Combine Corrosion Rates If the internal corrosion is widespread in nature, the corrosion areas will likely overlap such that the bottom thickness is simultaneously reduced by both internal and external influences. In this case, the internal and external rates are additive. For pitting, the chances are low that internal and external rates can combine to produce an additive effect on wall loss. In this case, the user chooses the greater of the two corrosion rates as the governing rate for the proceeding step. Inspection Rating Category Inspections are rated according to their expected effectiveness at detecting corrosion and correctly predicting the rate of corrosion. Table 3.17 provides inspection ratings for different inspection activities for the soil side and product side of the tank bottom. The guidelines are to be applied twice, once for the soil side, and once for the product side.

API 581 Appendix O.doc

11 October 2001

American Petroleum Institute Aboveground Storage Tanks – RBI Module

18

Table 3–17: Guidelines for Assigning Inspection Rating – Tank Bottom Soil Side

Inspection Rating Category A

• •

• • • • •

Commercial blast Effective supplementary light Visual 100% (API 653) • Pit depth gauge 100% vacuum box testing of welded joints Lining or Liner: • Sponge test 100% • Adhesion test • Scrape test B • Floor scan 50+% & UT follow-up • Brush blast OR • Effective supplementary light • EVA or other statistical method with • Visual 100% (API 653) floor scan follow-up if warranted by • Pit depth gauge the result Lining or Liner: • Sponge test >75% • Adhesion test • Scrape test C • Floor scan 5-10+% plates; • Broom swept supplement with scanning near shell • Effective supplementary light & UT follow-up; Scan circle and X • Visual 100% pattern • Pit depth gauge • Progressively increase if damage Lining or Liner: found during scanning • Sponge test 50 – 75% • Hammer test • Adhesion test • Cut coupons • Scrape test D • Spot UT • Broom swept • Hammer test • No effective supplementary lighting • Flood test • Visual 25-50% Lining or Liner: • Sponge test