Exxon Mobile Strategy Piping sMp4_44_1 RP

ExxonMobil Proprietary Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

Practices and Procedures MP Section Page 4-44-1 RP 1 of 65 JUNE, 2002

Section I: Introduction Objective This practice was developed to facilitate the identification of cost effective equipment strategies for piping. It will help sites to meet their business objectives through efficient implementation of key requirements of the Reliability and Maintenance Management System (RMMS), such as Equipment Strategies and R & M Improvement. This practice provides a step-by-step procedure for estimating probabilities for the most common materials related degradation mechanisms on piping. It also provides a procedure for grouping piping circuits with similar degradation mechanisms and consequences together to ensure that the risk mitigation strategies are cost effective and consistent. The process described in this practice compliments the Equipment Strategy Development Process described in MP 6-1-1. This piping specific equipment strategy process was developed to address both the historical high cost to the business of piping repairs, incidents and inspection programs, and the issues found when applying our standard equipment strategy tools to piping. This process has been successfully rolled out to all the European refineries, as well as selected sites in the Americas and in the Asia-Pacific Regions. An overview of this process is shown in Figure 1.

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Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

Figure 1 Piping Equipment Strategy Development Process Start: Piping circuits identified for strategy development

Prepare information: line list, P&ID's, MFD, EMSR, and any other relevant info, e.g. history of leaks, repairs or other issues

Determine preliminary Group based on several key factors: fluid, material, operating conditions expected to significantly affect degradation rate or consequence (e.g. velocity, pressure, temperature, etc.) (see Note 1)

Carry out preliminary screening with PMT to determine scope

Can any lines be run with no inspection ?

Assign tag number to Group

No

Assign all EDD's applicable to the group

Notes 1. The group should be developed based on similar properties such that risks and associated mitigation tasks will be similar during the time period under consideration. For example, where process conditions change (e.g. downstream of a pump), or material spec. breaks occur such that different EDD's and/or consequences apply, it may be necessary to establish a new group. 2. Time period under consideration will be based on factors such as the following: - anticipated life - jurisdictional inspection frequencies - T/A schedules - Possibility to capture any cost savings from combining support work for inspection tasks, e.g. scaffolding, asbestos removal. 3. Generic EDD's refer to 1a, 20, 4b, etc. These are refinery wide inspection programs. 4. First pass consequence may be based on the Pestra "calculator" or the guidelines contained in TMEE 062. These should be verified and approved by the PMT.

Yes

Assign time period under consideration (see Note 2.)

List lines where run with no inspection is acceptable

Do any Generic EDD's Apply (see Note 3) ?

Yes

5. Probabilities should be based on the EDD's. For general and localized corrosion mechanisms for which an "ar/t" can be developed, the probability should be based on the curves provided in Section 2. 6. Risk should be in the same region of the risk matrix in the time frame under consideration.

No

Yes

Do EDD's 4a and 6 apply ?

No

Are remaining EDD's applicable to whole Group ? Assign probabilities for generic EDD's. For EDD 1a (CUI) a preliminary visual inspection is required to assign probability

Define consequence (See Note 4)

Designate each injection/ mix point and process dead leg as a Component

Yes

Are risks acceptable in time period under consideration ?

Yes

Assign probabilities to each EDD (see Note 5)

Assign probabilities to each EDD

Define consequence (See Note 4) Identify generic EDD's in ES as a Component

No

Define consequence (See Note 4)

Are assigned risks for all lines in the Group similar (see Note 6) ?

No

Designate sub groups as Components based on risk

Designate sub groups as Components based on EDD's

Yes

No

Develop mitigation strategy for unacceptable risks

Prepare overall inspection plan for Group as an equipment strategy in Pestra. Propose to PMT for review and approval

Stop

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MP Section Page 4-44-1 RP 2 of 65 JUNE, 2002

ExxonMobil Proprietary Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

Practices and Procedures MP Section Page 4-44-1 RP 3 of 65 JUNE, 2002

Scope This Practice provides the following information to assist in the development of Piping (Equipment) Strategies: 1. Guidance on grouping lines 2. Inspection for uniform and localized corrosion EDD's 3. Inspection for dead-leg corrosion EDD 4a 4. Inspection for injection/mix point corrosion EDD 6 5. Inspection for corrosion under insulation (CUI) EDD 1a 6. Inspection of vents and drains (small connections) EDD 4b The Practice is aimed at onsite and offsite piping covering routine inspection for internal process-related corrosion and corrosion under insulation (CUI). The Practice does not provide specific guidance for developing strategies for the following equipment or programs, though they may be included in the strategy: ·

Safety valves, critical check valves, motor operated valves

·

Critical flanges

·

Pipe supports

·

Spring hangars and snubbers

·

Flow instruments (e.g. venturi, restriction orifice, control valves)

·

Areas addressed by autonomous maintenance

·

Mechanical damage resulting from piping flexibility or vibration

Overview of the Process The process is comprised of the following basic steps: A. Prioritization of piping for strategy development. B. Data collection, verification and analysis. C. Risk management: alignment with site PMT (Process/Mechanical/Technical)/ Business Team on risk acceptance criteria. D. Review of unit operations with PMT. E. Development of piping strategies (mitigation steps) using the procedures and tools provided in this document (Section II). Þ Assigning consequences. Þ Assigning probabilities. F. Development of detailed inspection plans. G. Inspection effectiveness assessment.

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ExxonMobil Proprietary Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

Ø

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

Practices and Procedures MP Section Page 4-44-1 RP 4 of 65 JUNE, 2002

A: Prioritization of Piping for Strategy Development

It may be beneficial to prioritize piping systems for strategy development in order to achieve the optimum benefit in the shortest possible timeframe. This can be done based on an initial high level screening of overall risk, or based on consequence alone. For locations that have used the API 570 classification system, or have critical piping lists, these may provide a good starting point. Additionally, the Existing Materials Suitability Reviews (EMSR) may also provide a basis for prioritizing piping systems. Ø

B: Data Collection, Verification, and Analysis

Appropriate data must be collected prior to beginning piping strategy development. These data must also be reviewed to ensure they are of sufficient quality, and that they are up to date. The key sources of data include: Inspection Data Checklist ü

Current and complete piping inspection isometric drawings

ü

P&ID's and simplified flow drawings

ü

Thickness data, corrosion rates, and retirement thickness

ü

Metallurgy

ü

Process conditions (pressure, temperature, and velocity)

ü

Process chemistry or other stream analyses

ü

History of leaks and leak boxes/clamps currently in operation

It is expected that most of the information mentioned above will be located in the unit EMSR (UMR) and the inspection management database or files. Ø

C: Risk Management

It is necessary to establish the risk management principles that will govern during the strategy development. Specific guidance on the interpretation of the acceptable portions of the risk matrix, and the corresponding actions (inspection) that should be taken, must be agreed upon with site management. This is particularly important for determining when to do the inspection and accepting that in some cases, no inspection will be carried out in the timeframe. Ø

D: Review of Unit Operations with PMT

During the development of piping strategies with the full PMT there is the opportunity to review key pieces of process information, and give some consideration to factors that have contributed to significant incidents elsewhere. The following short "HAZOP" checklist can be used to stimulate discussion of these areas and identify possible SHE risks. It is not intended to satisfy or replace the requirements for a proper unit HAZOP.

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Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

MP Section Page 4-44-1 RP 5 of 65 JUNE, 2002

Checklist ü

Has a HAZOP been completed? If yes, were there any inspection follow-up actions identified?

ü

Has a Materials Envelope Statement (MES) been developed and is the unit operating within these limits?

ü

Has PMI been completed?

ü

Are site details consistent with design?

ü

Are pressure and temperature ratings for all components consistent with operating modes?

ü

Is process continuous or batch?

ü

Is heat tracing detail consistent with design?

ü

Has MSOT been defined and observed for piping >25mm and operating below -85 F (29 C)?

ü

Are all process environments known?

ü

Has there been any capacity creep?

ü

Have congested areas been identified?

ü

Are there any temporary repairs?

Ø

E: Development of Piping Strategies

o

o

Assigning Consequences Consequence should be assigned using the Consequence Assessment Process (CAP)(TMEE-062 MP Section 6-12). The CAP can also be used to assess the economic impact of a leak in the piping systems under evaluation. The impact on operations will be strongly influenced by the nature and size and of the anticipated leak, and whether or not it can be repaired on-stream. Consider possible failure modes, (e.g. corrosion hole or rupture) and define the most like failure scenario. Depending on the particular failure scenario developed, impact on operations can be negligible to refinery-wide. The pro-forma provided in Appendix I should be used with the CAP to assist in developing the Business Consequence. Increasing the business consequence because of piping congestion (i.e. see piping cross-section diagram below) should be considered under certain circumstances. The decision to elevate the business consequence should be based on the potential for a failure to occur in a location where escalation of the initial event is deemed likely. An example would be the leak of a material above its auto-ignition temperature or near an ignition source located in a pipe rack containing numerous lines, on multiple levels. Leaks such as these have resulted in the rupture of additional lines, escalating the extent of equipment damage and prolonged process interruption.

5 or > across 3 or > high

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Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

MP Section Page 4-44-1 RP 6 of 65 JUNE, 2002

Assigning Probabilities Provided in Appendix II are typical EDD's assigned to various process units. This information can be used as an aid in assigning EDD's. The following table lists EDD's appropriate for piping. Other EDDs not included in the table may be applicable to piping and should be addressed even though they are not covered in this document. General

Local

Corrosion

Corrosion

7a, 34, 32, 44, 11, 15

7b, 12, 15, 16, 21, 35, 45, 46, 47, 48, 49, 50

Dead Legs & Stagnant Zones 4a

CUI/

Injection

CUF

Points/

Atm. Corr.

Mix Points

1a, b, c

6

(Vents & drains)

4b

Inherent in this risk based inspection process is the requirement for more thorough, or more frequent, inspection as the end of life approaches. This arises from the need for a more accurate estimate of the retirement date (i.e. corrosion rate), given the shorter remaining life, since probability mitigation through inspection is predicated on the ability to take corrective action prior to failure. Ultimately, a point may be reached where inspection is no longer sufficient, or even the most desirable, mitigative action. In this case an End-of-Life Management Strategy should be developed to assess and time the options of inspection and replacement. The piping strategy must be developed in compliance with all local jurisdictional requirements. In some locations, fixed inspection intervals are established for thickness monitoring and visual inspection. In such cases, these inspections must be captured in the strategy. Ø

F: Development of Detailed Inspection Plans

The final step in the process involves translating the documented piping strategy into a detailed inspection plan. This will typically involve marking-up inspection isometrics and identifying specific thickness monitoring locations. This is a critical step in the process, since it enables effective implementation in the field. Ø

G: Inspection Effectiveness Assessment Management System

In order to ensure the quality of the mitigation actions defined in the piping strategies, and the ability of the plant to implement them with confidence, it is recommended that some assessment of inspection effectiveness be performed. This would involve a review of both the inspection management systems, as well as the detailed inspection procedures in place. Such an assessment can be conducted internally, or by a peer group. Examples of various assessment tools include: ·

FEQA/ERIM (Fixed Equipment Quality Assurance/ ExxonMobil Refinery Inspection Manual) process used in the Americas region: specific to the FEQA/ERIM manuals and is highly quantitative.

·

The AOV (areas of vulnerability) process: amenable to self-assessment and is highly qualitative.

·

Inspection Management System Assessment (IMSA): a comprehensive tool designed for internal or external assessment. This global assessment process is based on the H-Exxon and H-Mobil tools and is more detailed than the OIMS Mechanical Integrity evaluation.

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Ø

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

MP Section Page 4-44-1 RP 7 of 65 JUNE, 2002

Available Tools to Facilitate Piping Strategy Development

The various tools available for developing piping strategies are described below.

Tools for Piping Strategy Development Step

Tools &

Comments

Resources Risk Management

·

Site specific Presentation

Reach alignment with management on risk acceptance and mitigation.

·

Pro-Forma (Appendix I)

·

API 570 classification

Appendix I provides a pro-forma that can be used to develop a criticality listing of piping based on SHE and business impacts due to leaks and the likely repair scenario.

·

Existing critical piping list

·

Inspection Hazop checklist

This is designed to capture any potential high-risk areas during the strategy development process and provide a basis for discussion with Operations.

·

Checklist

·

EMSR(UMR)

The checklist is designed to ensure that all the data needed to develop a high quality strategy will be available and up to date.

·

Inspection database

·

P&ID’s

·

EDD's

·

“ar/t” Calculator

·

Appendix II

·

Consequence Assessment Procedure (CAP)

Consequence must be assigned by the PMT using the RMMS CAP process

·

IMSA

·

FEQA/ERIM

·

AOV

IMSA and the FEQA/ERIM processes provides an OIMS-type evaluation of inspection systems and their effectiveness. The AOV process is a high level approach amenable to entire units.

Prioritization/ Assessing Business Impact

"Hazop" Questionnaire

Data Collection & Verification

Assigning Materials EDD's and Probabilities

Assigning Consequences

Inspection Assessment

EDD assignment may be taken from an existing EMSR, or assigned with the help of Appendix II. Probabilities will be assigned directly from the EDD. The “ar/t” calculator may also be helpful in developing mitigated and unmitigated probabilities. It is located at the EMRE R&M website. http://emre.na.xom.com/eedrm/docs_s00c/A RTCalc/ARTCalc.ASP

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ExxonMobil Proprietary Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

Practices and Procedures MP Section Page 4-44-1 RP 8 of 65 JUNE, 2002

Section II: Piping Strategy Development Definitions Where possible, the terms used are consistent with the definitions in ASME B-31.3 section 300.2 and the RMMS documentation. The following definitions are added to help clarify the procedure. ·

"Line" and "Piping" are taken to be synonymous. In this procedure a "line" is assumed to extend from one piece of equipment to another

·

"Piping System", and "Group of lines" are taken to be synonymous

·

"TML" refers to a thickness measurement location, e.g. an elbow, tee, reducer, or straight run

·

"Test point" is the inspection point at the TML (e.g. one of four points around the circumference of the pipe

1.0 Approach to Piping Strategy Development Piping Strategies provide consistent, long term programs for piping systems (both onsite and offsite) which recognizes risk based decisions for establishing preventative, predictive, and run with no inspection options. The strategy can also provide directives for condition and operations monitoring and for calendar based maintenance programs. A piping strategy, as used in this document, covers an onsite piping system (or offsite piping system if required) identified on a Engineering Flow Diagram (EFD), by line number, or through another, similar identification system. The piping system may contain an individual line or a group of lines. The items/components included in the piping strategy are pipe and fittings up to and including the first process block valve or instrument block valve. In general, fixed equipment nozzles and flanges should be included in the fixed equipment strategy, and not the Piping Strategy. Sections 2 to 6 give guidance on developing an inspection programs for local and general corrosion, Process Dead Leg Corrosion EDD 4a, Injection/Mix Point Corrosion EDD 6, Corrosion Under Insulation EDD 1(a), and Vents and Drains EDD 4(b), respectively. It is expected that refinery-wide 'generic' strategies (e.g. external visual inspection programs) will be developed to cover such issues as: ·

Soil Corrosion EDD 14

·

Atmospheric Corrosion EDD1(b)

·

Corrosion at Pipe Supports EDD 20

The outcome of these preliminary "generic" strategies should be integrated into the piping strategies for 'groups' of lines wherever possible. This will enable the most efficient integration of inspection programs.

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ExxonMobil Proprietary Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

Practices and Procedures MP Section Page 4-44-1 RP 9 of 65 JUNE, 2002

Procedure The recommended procedure for developing piping strategies is described below and shown in Figure 1. It is intended that as many lines as possible be grouped together for a single strategy. This will reduce the time to complete the strategies, and potentially reduce the extent of inspection. In some cases a single line within a group may be used to represent the whole group. 1.1

Data Collection The development of a piping strategy begins with data collection and line definition. Typically, a line going from one piece of equipment to another is given an individual identification tag. The information ultimately needed to develop a piping strategy such as fluid type, wall thickness, corrosion rate and degradation mechanism is available from EMSR or other activities. If sufficient data to evaluate the risk of failure does not already exist, then the data will need to be gathered.

1.2

Identify Lines That are “Run With No Inspection” A 'risk-based screening process' should now be used to determine which piping, is of such 'low risk', that minimal or no inspection is anticipated. This process must be conducted with, or approved by, the refinery PMT or management team. Lines falling into this category are regarded as 'run with no inspection'. Lines such as air, nitrogen, cooling water and firewater may fall into this category. Additionally, some offsite lines may also fall into this category. These lines should be listed, and a single strategy developed.

1.3

Initial Grouping At this point, the 'grouping' can begin. It is recommended that the initial GROUP be based on the process-side fluid. This is likely to be a piping system within a unit. Similar but not identical fluids can be included as one group, but from a practical viewpoint, they should be separated. This initial GROUP forms the basis of one Piping Strategy.

1.4

Identify EDD’s The detailed line and operating parameters must now be available (from the EMSR). This enables the EDD's to be defined, and the unmitigated probabilities to be determined.

1.5

Breaking Down Groups into Components The next step is to segregate out lines, or segments of lines, within a GROUP to form sub-groups or COMPONENTS. These COMPONENTS will have a similar risk, degradation mechanisms (EDDs), corrosion rate and remaining life. The intent is that any one line in the sub-group of lines could be representative of the entire sub-group. An analogy can be made between a piping system and a vessel. The drum is the "equipment" and the whole drum is affected by one or more degradation mechanisms (EDDs). The drum may have components such as a boot or a demister which require listing as "components". The piping system (GROUP) is the "equipment", which will have a predominant EDD. Within each system there will be different parts or "COMPONENTS". Items such as those listed below could be listed in the Piping Strategy as "COMPONENTS": -

Individual pipe sections or groups of lines, with unique features such as corrosion rate, remaining life, or material (e.g. define subgroups with similar probability as separate components)

-

Mix points and injection points

-

Process dead-legs

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ExxonMobil Proprietary Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

Practices and Procedures MP Section Page 4-44-1 RP 10 of 65 JUNE, 2002

While each component will have its own inspection requirements, it is still part of a single Equipment Strategy. An example of the grouping process is provided in Appendix III. 1.6

Segregating out Unique Lines If a line cannot be grouped with others because of a unique degradation mechanism or because the risk is too, a separate strategy should be developed. Lines that are bad actors (i.e. have high corrosion rates, or high risk) should have individual strategies developed.

1.7

Developing Strategies Individual piping strategies can now be developed for each group of lines or where necessary for single, high risk, individual lines.

1.8

Re-assess Piping Strategy If, after developing Piping Strategies, an unexpected leak occurs then the probability of a leak in the system should be re-assessed. The level of any additional (follow-up) inspection should be based on the new risk.

Developing the Strategies in STRIPES or PESTRA The following steps can be used to develop the piping strategies in STRIPES or PESTRA. The individual strategy is used for both a GROUP of lines, and for a single line, if justified. The following steps assume that the lines have been grouped using the procedure outlined in this Practice. A unique tag number is assigned to a GROUP or a single line for which a strategy is to be developed. The STRIPES or PESTRA strategy form is filled out in the same manner as for any fixed equipment item. The period considered should be set relative to the expected life. For many piping systems, 10 years is a reasonable starting point. For most unspared process piping, two unit run lengths should be the maximum period considered. Under "components" it is usually not necessary to separately list fittings (elbows, flanges, and valves) or other fittings as they are either covered by separate strategies or are effected by the same degradation mechanisms as the pipe. The detailed inspection program, as documented on the individual inspection isometrics, will identify the best locations for inspection. For example, a strategy covering a gasoil system in a pipestill unit may have "pipe" as the only component. The elbows, fittings and valves would be covered by the evaluation of the corrosion mechanism and the resulting inspection program for the "pipe". Any piping component not covered by a separate equipment strategy and having a degradation mechanism different from the pipe should be listed as a separate component. If the strategy covers a group of lines, it is recommended that the line list be included in the "comments" section of the strategy.

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ExxonMobil Proprietary Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

Practices and Procedures MP Section Page 4-44-1 RP 11 of 65 JUNE, 2002

2.0 Inspection for Uniform and Localized Corrosion This section provides a step-by-step procedure to evaluate the probability of failure for EDD's classified as uniform or localized corrosion, where the failure mode is expected to be a leak. Steps 1 - 6 provide the basic probability of failure as a function of inspection method and projected pipe wall thickness. Steps 7 - 9 provide tools to modify this probability based on the accuracy of the inspection data, and the period of time over which the thickness is being projected. Modifying the probability is at the discretion of the subject matter expert. Step 10 helps indicate how the final probability is used to develop the strategy. It is recommended during construction to take reference wall thickness measurements for lines with EDDs for uniform and localized corrosion especially for Consequence I and II lines. It is preferred that the reference readings be taken on all lines previously mentioned since scaffold and insulation removal costs can be avoided. It is expected that this approach will apply to most services. However, it should be emphasized that there may be some unique circumstances in which the corrosion is so highly localized (e.g. pitting corrosion) that the corrosion rate can not be predicted with confidence. In such cases, use of this procedure may not be appropriate. Some examples may include: ·

Acid services where velocities exceed recommended limits for the material

·

Lines containing naphthenic acid exceeding recommended TAN/TRS and velocity limits

·

Lines with two-phase flow where turbulence effects can produce extremely high local corrosion rates

It should be noted that non-uniform corrosion does not mean pitting. Pitting should be considered unpredictable unless special evaluation/analysis proves differently. In such cases, it will be necessary to estimate the unmitigated and mitigated probabilities on a case-specific basis. Step 1:

Determine if the EDD (corrosion mechanism) is uniform or localized.

Step 2:

From inspection records determine the number of inspections that have been performed.

Step 3:

Review the inspection procedures that have been employed. Using Tables 2.1 and 2.2 identify the inspection level that best describes the inspection methods used.

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Fixed Equipment: Piping Maintenance Practices Manual TMEE-062

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MP Section Page 4-44-1 RP 12 of 65 JUNE, 2002

Table 2.1 Thickness Monitoring for Uniform Corrosion Description

Inspection Level Standard

Medium

High

·

TML's located on 10% of components including a representative number of fittings and straight runs.

·

A minimum of 1 reading or one radiograph at each TML.

·

TML's located on 10% of components including a representative number of fittings and straight runs.

·

A minimum of 4 readings in a band around the pipe or one radiograph at each TML in 2 planes.

·

Corrosion rate should be estimated using a statistical approach.

·

TML's located on 50% of components including a representative number of fittings and straight runs.

·

A minimum of 4 readings in a band around the pipe (or UT scrubbing noninsulated pipe) or radiography at each TML in two planes.

·

Corrosion rate should be estimated using a statistical approach.

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PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

Practices and Procedures MP Section Page 4-44-1 RP 13 of 65 JUNE, 2002

Table 2.2 Thickness Monitoring for Localized Corrosion Inspection

Description

Level

Standard

Medium

High

·

TMLs located on 10 % of components including a representative number of fittings and straight runs ( as for Standard Uniform Corrosion Inspection Level)

·

PLUS - TMLs located at 10% of any additional areas suspected of experiencing accelerated corrosion, for example, locations where flow is disrupted, or where condensation could occur.

·

For the additional TMLs, a minimum of 4 readings or one radiograph should be taken at each TML. The readings or radiographs should be directed at the expected areas of corrosion (i.e. the extrados of an elbow for erosion-related corrosion, or the bottom of a pipe for under-deposit corrosion).

·

TMLs located on 10% of components including a representative number of fittings and straight runs (as for Medium Uniform Corrosion Inspection Level)

·

PLUS - TMLs located at 50% of any additional areas suspected of experiencing accelerated corrosion For example locations where flow is disrupted, or where condensation could occur.

·

For the additional TMLs, a minimum of 4 readings or one radiograph in each of two planes should be taken at each TML. The readings or radiographs should be directed at the expected areas of corrosion (i.e. the extrados of an elbow for erosion-related corrosion, or the bottom of a pipe for under-deposit corrosion.

·

Until the presence or absence of localized corrosion has been confirmed and located, scanning UT, scrubbing UT or close-grid UT measurements also should be considered as an inspection method.

·

Corrosion rate and remaining life should be calculated using a statistical approach after the areas of accelerated corrosion have been located.

·

TMLs located on 50% of components a representative number of fittings and straight runs (as for High Uniform Corrosion Inspection Level)

·

PLUS - TMLs located at 100% of any additional areas suspected of experiencing accelerated corrosion. For example, locations where flow is disrupted, or where condensation could occur.

·

For the additional TMLs, a minimum of 8 readings or one radiograph in each of two planes should be taken at each TML. The readings or radiographs should be directed at the expected areas of corrosion (i.e. the extrados of and elbow for erosion-related corrosion, or the bottom of a pipe for under-deposit corrosion.

·

Until the presence or absence of localized corrosion has been confirmed and located, automated scanning UT or close-grid UT measurements also should be considered as an inspection method.

·

Corrosion rate and remaining life should be calculated using a statistical approach after the areas of accelerated corrosion have been located.

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Step 4:

PIPING EQUIPMENT STRATEGY DEVELOPMENT Regional Practice

MP Section Page 4-44-1 RP 14 of 65 JUNE, 2002

Based on the number of inspections and the level, use Table 2.3 to establish what curve is applicable.

Table 2.3 Credit for Multiple Inspections Number/Level of Inspections

CURVE TO USE FIGURE 2.1

No Inspection

Curve 0

1 Standard

Curve 1

2 or more Standard

Curve 2

1 Medium

Curve 2

1

2 Medium Curve 3

or 1Medium + at least 2 Standard 1 High

Curve 3

2 High

Curve 4

1

Note: It is assumed that at least one baseline inspection has been performed. Nominal values are not considered an inspection. If no previous inspections have been performed, the date of the initial inspection should be based on the probability determined by Curve 0 in Figure 2.1 and the consequence. Step 5:

Using the thickness data for the system, calculate the value of “ar/t”, (the percentage of the remaining corrosion allowance consumed), for a test point, TML, or the entire system, where: a – Time period under consideration, i.e., the equipment strategy time frame taken from the date of last inspection (years). r – Corrosion rate, determined by thickness readings, estimated from similar service, or based on design (e.g. RCMM) (mpy or mm/yr). t – Remaining corrosion allowance. This is defined as the difference between the measured thickness at the last inspection and the retirement thickness, where the retirement thickness is determined from the Piping Maintenance Guide Section 5.4.2. (in., mm.) t = tmeasured - tretirement

It should be emphasized that the curves relating ar/t to the probability of failure are based on the use of "t" as defined above. The application of fitness for service type approaches (e.g. Savepipe, Peas, etc.) to redefine the acceptable wall thickness is not within the scope of this approach. Refer to SME for Guidance on risk assessment for these situations.

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To establish a representative value of ar/t for a line or a system, it is recommended that the average corrosion rate for the system be applied to the minimum thickness measured at the last inspection. In general, this will produce a reasonable estimate of ar/t. Use of statistical methods for the estimation of corrosion rate and minimum thickness will provide more consistent results, and can automate this process. Use of the nominal thickness as a start point can be useful to calculate the corrosion rate, especially in the case of old piping. If the interval is high (e.g. >20 years) the effect of the error on the initial thickness becomes increasingly less significant. Example of “ar/t” Calculation Given a 4” line inspected 5 years ago, and an equipment strategy timeframe of 10 years. The inspection data indicate the line thickness was 0.2” at the last inspection, and has a corrosion rate of 4 mpy. The Piping Maintenance Guide Table 5.1 retirement thickness is 0.134”. Determine “ar/t” at the end of the time period: In this example, “a” is the piping strategy period plus the time since last inspection, or 15 years. The corrosion rate, “r”, is 4 mpy. The value of “t” is simply 0.2” – 0.134” or 0.066”. Therefore, the quantity “ar/t” for the time period is calculated as: ar/t

=

15 years x 0.004”/years

= 0.91

0.066” Which means that10 years from now, it is anticipated that 91% of the remaining corrosion allowance will be consumed. If an inspection is conducted during this time period, the thickness and corrosion rate must be reestablished at the time of the future inspection. The corresponding value of “a” must also be reset based on the time remaining until the end of the piping strategy period, producing a new value for “ar/t”. A convenient tool for evaluating ar/t and planning future inspections is provided at the EMRE R&M website: http://ereweb.ere.exxon.com/eedrm/ This tool will automate the calculation of ar/t, as well as establish the probability, timing and level required for future inspections.

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Step 6:

MP Section Page 4-44-1 RP 16 of 65 JUNE, 2002

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Using the value of ar/t and the appropriate curve, establish the probability of failure using Figure 2.1.

Figure 2.1

A B C D E 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

ar/t

Step 7:

Based on the average corrosion rate and the time (months) between inspections, use Figure 2.2 to determine the minimum interval between inspections in order to obtain data that has significant value to affect the regression curve. This curve represents an error of +/- 0.5mm in the ultrasonic measurement.

Figure 2.2

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0.07

1.8

0.06

1.4

0.05

1.2

Pass, Use Same Curve

1

0.04

0.8

0.03 Minimum inspection interval

0.6

(in/yr)

Corrosion Rate (mm/yr)

1.6

0.02

0.4

0.01

0.2

Fail, Curve Adjustment of -1

0 0

5

10

15

20

25

0 30

35

40

45

50

55

Inspection Interval (Months)

Step 8:

Due to potential changes in process operations, the probability may increase over time without inspection. When the date of the last inspection exceeds 10 years, it may be appropriate to either reduce the credit taken in Figure 2.1 as indicated in Figure 2.3, or consider the data invalid. Consideration should be based on the variability in the operation, and the conservatism taken in estimating the corrosion rate and current wall thickness (e.g. use of lower bound estimates). Any adjustment will be at the discretion of the Subject Matter Expert conducting the assessment.

Figure 2.3

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Curve Adjustment

-2

-1

0

0

10

20

Operating Period, years

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Step 9:

Using the results from steps 7 and 8, update the probability of failure using Figure 2.1. Note that Curve 0 is the lowest curve that should be used.

Step 10:

Assign a risk corresponding to the probability and consequence. Based on this risk, determine if and when an inspection is required during the time period to help mitigate to an acceptable level. In some cases, a comparison should be made between performing multiple “standard” inspections, or a higher level inspection, in order to select the optimum strategy. The anticipated mitigated risk is defined at the end of the time frame or the next replacement opportunity using the "ar/t" and proposed inspection level according to figure 2.1. If the risk lies in an acceptable position on the risk matrix at the end of the time period, no further action is required. If inspection is required during the period, the next inspection interval can be determined based on a target probability necessary to maintain an acceptable overall risk. This is done by calculating the time required to reach an unacceptable probability of failure. This analysis can also be done using the “ar/t” calculator referred to previously.

3.0 Inspection for Corrosion-Under-Insulation CUI - EDD 1a This inspection practice covers EDD #1a only. Lines in cyclic or sweating service require site specific consideration, beyond the scope of this document. Atmospheric corrosion and Corrosion Under Fireproofing (CUF) are not included within the scope of this document. A step-by-step process has been included and a corresponding flow chart, shown in Figure 3.1, summarizes the key steps in using this practice. While inspection personnel may address many of the tasks in this process, the PMT team should jointly identify at least two parts (consequence assessment and determining appropriate mitigation levels). Step 1:

Set initial probability and perform visual inspection. EDD 1a provides an initial failure probability (Pf) based on time in service and operating information. An initial visual inspection should be performed and will improve the failure probability estimate and may increase failure probability by up to two levels. (Many sites perform these inspections during routine thickness monitoring.) Several resources (e.g., API 570, ERIM 12.3.4 (as Appendix VII, etc.) are available to provide guidance on insulation assessments. Examples are included in Appendix IV. A probability reduction based on the visual inspection is not considered since the EDD assumes reasonable condition for insulation and a poorer condition may be found. If the initial visual inspection identifies that the insulation system is in good condition, the basic probability may be retained. If the insulation system is not in good condition, the probability should be raised by one or two levels (up to an "A"). Recent inspection information may also be used to modify the EDD probability. Probability modifications associated with external visual inspection and recent inspections (e.g., radiography, visual, etc.) are at the discretion of the Subject Matter Expert.

Step 2:

Review the inspection procedures that will be employed. Using Tables 3.1 and 3.2 (for extent and method, respectively) identify the inspection level that best describes the inspection methods used. Table 3.1 lists the amount of mitigation credit for different combinations of inspection technology, and coverage. While neutron backscatter is only a moisture detection (not CUI) tool, some credit may be applied since it can assist with identifying susceptible areas. Figure 3.2 provides guidance on inspection extent for the technologies. The ExxonMobil NDT Manual contains information on the inspection technologies mentioned in this document.

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MP Section Page 4-44-1 RP 20 of 65 JUNE, 2002

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Figure 3.1 - CUI inspection effectiveness flowchart.

Identify Group/Sub-Groups/Lines to which EDD 1A apply1

Assign initial unmitigated probability factor (Pf) per EDD 1A, based on age, general insulation condition, environment and coating, etc. The age shall be based on time frame under consideration.

Perform visual survey to determine insulation condition (good/poor) and define damaged/suspect areas. The inspection should include a detailed visual inspeciton using attached guidelines (Appendix III and condition check list).

Update failure probablity (by SME) based on visual survey and prior inspection information. Potential modification considerations based on survey include: 0 = Fair condition. +1 = Clear potential for CUI or no visual inspection. +2 = Clear evidence of CUI (e.g., heavy scale, dripping water, rust bloom on insulation jacketing)

Review the inspection procedures that will be employed. Use Tables 3.1 and 3.2 to identify the inspection level that best describes the inspection methods used and take appropriate Pf credit.

Modify Pf based on future visual inspection scope and interval according to Figure 3.3.

Assign consequence factor (Cf) of CUI failure to group/sub-group/lines. PMT team required.2

No

Is initial or revised unmitiged risk acceptable?

Yes

Use Tables 3.1, 3.2 and Figure 3.3 to modify program and reduce Pf.

Notes: (1) EDD 4A may also lead to assigning EDD 1A. (2) This decision should be taken by PMT team.

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Schedule next inspection based on interval to rach unacceptable risk. Schedule next visual inspection using Figure 3.4.

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Table 3.1 Inspection effectiveness table for CUI Probability Reduction (4, 5)

Extent of Inspection

Method (3)

100% of line

H

Probability E

100% of damaged areas(1) + 50% of susceptible areas(2)

H/ML

21

100% of damaged areas(1) + 10% of susceptible areas(2)

H/ML

10

(1) Includes the inspection of adjacent susceptible sections of line even if the insulation is in good condition. For example, if damaged insulation is found on a vertical section, inspect section to low point elbow plus one section of insulation along horizontal. Extent shall be extended to 100% of adjacent susceptible area (line segment) if any corrosion is found. See Figure 3.2. (2) Susceptible areas include those identified in Appendix IV. (3) See Table 3.2 for list of inspection methods. (4) Probability reduction for whole pipe only applies if: (a) No corrosion is found, or, (b) If corrosion is found, mechanism for CUI (e.g. damaged insulation) is arrested (insulation is replaced and properly sealed to avoid CUI), and damage has not affected mechanical integrity of line. See Figure 3.3 for additional guidance. Or, (c) If coating integrity is adequate to protect against CUI. (5) All damaged areas to be fixed.

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Figure 3.2 - Examples of determining extent of CUI inspection

Extent of damaged insulation Extent of stripping/ inspection (extend until all potential related corrosion damage is located)

Vertical section damaged area - Inspect to low point e l b o w p l us s e c t i o n o f horizontal insulation

Horizontal section damaged a rea - Insp ect d ama ge d length plus one section on either end

Suspect Areas for CUI

Vented Dummy Leg - Moist Air Entry

Pipe

Pipe

Cold Insulation Vapor Barrier Uncapped Start Point on Vertical Leg Flange in Vertical Leg

Thermocouple Capped Horizontal - No Lip

Pipe Supports and Gussets

Metal Jacket Water Trap (Drain Needed)

Cap on Vertical Start (No Lip)

Lip

Cap on Vertical End (Lip)

Tee Branch Header (Drain Needed)

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Table 3.2 CUI inspection methods Method Reliability High

Medium

Low

Primary Methods ·

Insulation Stripping and Visual Inspection (100%)

·

Intelligent Pigging (100%)

·

Conventional RT (1)

·

Flash Radiography (with film) with stripping at affected areas (1)

·

Real Time Radiography (tangential) with stripping at affected areas (1)

·

Radiographic Scanning (through wall, e.g., ThruVu) (1)

·

Guided Wave Ultrasonics on small diameter pipe (10-inch) with follow-up for all indications (2).

·

Neutron Backscatter with ≈10% follow-up at susceptible areas with no indications (1, 3)

(1)

As a minimum, RT method must be applied at 2 planes for areas with damaged insulation and 1 plane for susceptible areas, at each location. Inspection planes/quadrants must be at most likely CUI location (e.g., 6-o'clock and 12-o'clock for horizontal pipe).

(2)

Plan must consider ineffective nature of these methods to detect localized corrosion. (Credit should be reduced if localized corrosion is expected and there may be no mitigation credit for very large diameter lines inspected with guided wave UT.) Use supplemental technology (e.g., stripping, RT, or neutron backscatter) at areas of penetrations, supports or fittings. All follow-ups should be performed with a CUI (wall loss) measuring technology.

(3)

Inspection will be scheduled when elevated moisture level is anticipated, for example, after significant rain period, after wetting through use of fire monitor (e.g., 24-hour soak), or when climate is conducive to condensation.

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Figure 3.3 - Evaluating CUI inspection results

Evaluate CUI inspection results for line.

Is there significant rust/scaling present (not just light blooming) ?

No

If corrosion is very slight (e.g., rust bloom), repair insulation as needed and capture stated probability credit.

Yes

Increase coverage of suspect areas as appropriate.

No

Is CUI at damaged insulation area only?

Yes

Is wall loss acceptable (note 1) ?

Yes

Arrest corrosion as required for probability reduction in Table 3.1.

No

Re-assess failure probability and consider replacement of line.

Note (1) Acceptable wall loss must be determined using engineering judgement, taking into account such factors as design metal thickness, future corrosion allowance required for internal corrosion, etc. In some cases, a local thin area assessment following fitness for service guidelines will be required.

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Step 3:

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Inspection intervals are based on maintaining an acceptable level of risk, as determined by the risk matrix. Due to the uncertainly in extrapolating inspection results over long periods of time, the potential for unanticipated process changes (e.g., sweating), and insulation condition changes (e.g., damaged jacketing) affecting CUI susceptibility, it may be appropriate to reduce the credit taken in Table 3.1 as indicated in Figure 3.4. The figure provides 2 different curves, which reflect whether a subsequent visual inspection is performed. The time-based guidelines are summarized below and any adjustment will be at the discretion of the subject matter expert conducting the assessment. Case 1 ·

No visual inspection is performed at approximately 5 year intervals, or

Case 2 ·

Line is visually inspected approximately every 5 years and all new damaged areas are inspected according to Table 3.1 and repaired to arrest CUI.

·

10% of all suspect areas (e.g., attachments protruding from insulation, low spots, etc.) are inspected every 10 years.

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Figure 3.4 - Time dependency for mitigation credit reduction for lines inspected according to Table 3.1

Increase in Failure Probability (loss in mitigation credit up to unmitigated level)

2 Case 1 (No visual) Case 2 (Visual inspection every 5 years)

1

Check suspect areas 0 0

5

10 Years since inspection

15

20

.

Step 4:

Using the results from steps 2 and 3, update the probability of failure using Figure 3.1

Step 5:

Use the final probability and consequence of failure to assign the risk. Based on this risk, and the associated acceptance criteria, determine the inspection interval and inspection level necessary to mitigate the risk to an acceptable level. If the risk lies in an acceptable position on the risk matrix, no further action is required in this time period. In some cases, such as severe CUI, inspection (and re-insulation) may not be an effective means of achieving the desired level of risk reduction. In such cases, other mitigative steps (e.g., coating) need to be taken.

4.0 Inspection for Process Dead-leg Corrosion – EDD 4a The unmitigated probability for dead legs, set by EDD 4a, is assigned a “C”, "D", or “E” according to the service. For instances where inspection data have been collected according to the methods and level indicated below (Table 4.1), and a value of ar/t can be calculated with confidence, the probability can be determined from Figure 2.1.

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Table 4.1 Probability

Inspection

Reduction

Level

Up to

High

3 Levels

Up to

Medium

2 Levels

1 Level

Standard

Extent of Inspection

Inspection along 100% of the length of each dead-leg using a method that addresses the expected form and location of the corrosion. E.g. for a horizontal pipe, where under-deposit corrosion is expected, 100% can be achieved by a full length UT scan of the bottom section of the pipe. Another example is for a partially filled horizontal pipe with a liquid/vapor interface, inspection can be achieved by a full length UT scan of the bottom plus a series of RT shots or UT circumferencial bands at an acceptable interval. Inspection along 100% of the 'susceptible' areas of each dead-leg. Susceptible areas are defined as locations where corrosion is likely to occur e.g. low points, condensation/vaporization areas. Inspection method must address the expected form and location of the corrosion. E.g. for a horizontal pipe, where underdeposit corrosion is expected 100% can be achieved by a full length UT scan of the susceptible areas of the bottom section of the pipe. 20% of the surface area for each dead-leg, targeted at likely sites for accelerated corrosion.

Inspection Method

·

Scanning UT

·

Close-grid UT

·

Multiple radiographs

Inspection Interval

Based on Figure 2.1

As above

Based on Figure 2.1

As above

Based on Figure 2.1

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Once the unmitigated probability has been determined, the inspection plan can be developed based on the required probability reduction. Due to the highly localized nature of corrosion that is often observed in dead legs, the extent of inspection typically requires that each dead leg be inspected, if required based on risk. However, where similar service can be defined, such as identical (symmetrical) piping configurations, where corrosion is expected to be of similar severity, multiple dead legs may be grouped together. A representative dead leg(s) may be defined as the “witness line(s)” for inspection. When this strategy is chosen, the lines being grouped should be clearly identified in the strategy. A valve may not divide a dead leg even if in similar service. This situation should be considered as separate dead legs with Table 4.1 applied equally. Some caution must be exercised when grouping dead legs, particularly where corrosion is expected to result from the formation or collection of corrosive deposits. One example is the deposition of ammonium chloride salts in the vertical segments of cold exchanger bypasses in hydotreating units, where highly localized corrosion may occur in a single dead leg based on slightly different operating temperature. 5.0 Inspection for Vents and Drains (Small Connections) - EDD4b The unmitigated probability for vents and drains, set by EDD 4b, is assigned a “C” for corrosive service, or an “E” for non-corrosive service. In most cases, small connections are inspected on a calendar-based frequency, as corrosion rate is difficult to estimate. The mitigated probability and inspection plan/timing can be determined from Table 5.1.

Table 5.1 Probability Reduction

Up to 3 Levels

Up to 2 Levels

Inspection level

Number of Inspection locations

High

100% of vents & drains

Medium

50% of vents and drains

Inspection Method

·

Radiography

·

Ultrasonic

·

Radiography

·

Ultrasonic

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Inspection Interval

5 years (If no corrosion is found, consider not repeating the inspection) 5 years (If no corrosion is found, consider not repeating the inspection)

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6.0 INSPECTION FOR INJECTION/MIX POINT CORROSION – EDD 6 The unmitigated probability is defined for injection or mix points using EDD 6. Based on the anticipated corrosivity of the service and the design, the unmitigated probability will be a “B”, “C”, or “E”. For instances where inspection data are available, and a value of ar/t can be calculated with confidence, the probability can be determined from Figure 2.1 using the definitions of inspection level provided in Table 6.1. Table 6.1 Probability

Inspection

Reduction

level

Up to 3 Levels

High

Up to 2 Levels

1 Level

Number of Inspection locations

Inspect per Appendix V & VI

Medium

Standard

Inspect per Appendix V & VI

The Injection/Mix Point fitting and downstream elbow(s) can be selected as a site to be included in the inspection of the main piping.

Inspection Method

·

Scanning UT

·

Close-grid UT

·

Multiple radiographs

·

Point UT

·

Radiography

·

Inspected as main piping using UT or RT

Inspection Interval

3 years or Based on Figure 2.1

3 years or Based on Figure 2.1

3 years or Based on Figure 2.1

Once the unmitigated probability has been determined, the inspection plan can be developed based on the required probability reduction as defined in Table 6.1. Inspection frequency should be either every 3 years, or based on an estimate of ar/t using Figure 2.1 along with the inspection level defined in Table 6.1.

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MP Section Page 4-44-1 RP 30 of 65 MAY 10, 2002

APPENDIX I Example: Piping Consequence Pro-Forma Business Impact Line #

Primary

Service

EDD(s)

Cost

SHE

($/Day)

Risk

Business Repair Onstream

Short Shutdown ~5 Days

Major Shutdown >14 Days

Risk

123A

7a

Gasoil

50K

II

No

Yes

No

III - $250K

654D

7a

VGO

200K

II

No

Yes

No

II - $1M

456B

24

HF acid

500K

I

No

No

Yes

I - $7M

789C

1a, 15

Sour water

50K

III

Yes

No

No

IV -