Risk Based Inspection Professional Practice Test

API-580 exam Format | Course Contents | Course Outline | exam Syllabus | exam Objectives

Exam Code: API-580
Exam Name: Risk Based Inspection Professional
Duration: 3.25 hours
Question in Exam: 90
Scored Question: 80
Unscored Question: 10
Question Type: multiple-choice
Passing Scores: 56 (70%)

1. Understanding the Design Premise

- Design Basis: The set of conditions (pressure, temperature, material properties) used to design equipment.
- Operating Conditions: genuine conditions under which equipment operates, which may differ from design.
- Equipment Integrity: The ability of equipment to perform its intended function without failure.
- Material Selection: Choosing materials based on corrosion resistance, strength, and environmental compatibility.
- Integrity Operating Windows (IOWs): Established limits for process variables (e.g., temperature, pressure) that affect equipment integrity if exceeded.
- Fitness-for-Service (FFS): Assessment to determine if equipment is suitable for continued operation (referenced in API 579).
- Understanding how design assumptions impact risk assessments and inspection planning.

2. Planning the RBI Assessment
- RBI Assessment Plan: A documented strategy outlining steps, data requirements, and resources for RBI.
- Risk Criteria: Terms of reference (e.g., safety, cost, environmental impact) used to assess the significance of risk.
- Stakeholder Involvement: Engaging relevant parties (e.g., operations, maintenance, engineering) in the RBI process.
- Qualitative RBI: Risk assessment using descriptive or categorical data (e.g., high/medium/low risk).
- Quantitative RBI: Risk assessment using numerical data to calculate probabilities and consequences (often based on API RP 581).
- Risk Matrix: A tool to plot probability of failure (POF) against consequence of failure (COF) to prioritize risks.
- Ability to outline key steps and considerations for a comprehensive RBI plan.

3. Data and Information Collection
- Process Data: Information on operating conditions, fluid composition, and process parameters.
- Inspection History: Records of past inspections, findings, and repairs.
- Equipment Data: Specifications, materials, and design details of equipment.
- Corrosion Loops: Groups of equipment or piping systems exposed to similar corrosion mechanisms.
- Data Validation: Ensuring the accuracy and completeness of collected data.
- Non-Destructive Examination (NDE): Techniques (e.g., ultrasonic testing, radiography) used to inspect equipment without causing damage.
- Identifying critical data sources and ensuring data quality for RBI assessments.

4. Identifying Damage Mechanisms and Beginnings and Failure Modes
- Damage Mechanism: A process that causes deterioration (e.g., corrosion, cracking, erosion).
- Failure Mode: The manner in which equipment fails (e.g., leak, rupture, brittle fracture).
- Corrosion Mechanisms:
- General Corrosion: Uniform material loss over a surface.
- Localized Corrosion: Pitting or crevice corrosion in specific areas.
- High-Temperature Corrosion: Oxidation, sulfidation, carburization, or metal dusting.
- Environment-Assisted Cracking (EAC): Stress corrosion cracking (SCC), hydrogen-induced cracking (HIC), or sulfide stress cracking (SSC).
- Erosion: Material loss due to mechanical action of fluids or particles.
- Fatigue: Failure due to repeated stress cycles.
- Identifying applicable damage mechanisms based on material, process, and environmental conditions.

5. Assessing Probability of Failure (POF)
- Probability of Failure (POF): The likelihood of equipment failure within a given timeframe.
- Damage Rate: The rate at which a damage mechanism degrades equipment (e.g., corrosion rate in mils per year).
- Inspection Effectiveness: The ability of inspection techniques to detect damage (e.g., highly effective, moderately effective).
- Remaining Life: The estimated time until equipment reaches an unacceptable condition.
- Confidence Level: The degree of certainty in POF calculations based on data quality.
- Event Tree Analysis: A method to model possible failure scenarios and their probabilities.
- Calculating POF using qualitative or quantitative methods and understanding factors affecting reliability.

6. Assessing Consequence of Failure (COF)
- Consequence of Failure (COF): The severity of outcomes if failure occurs.
- Safety Consequence: Potential for injury or loss of life.
- Environmental Consequence: Impact on air, water, or soil (e.g., oil spills).
- Economic Consequence: Costs of downtime, repairs, or lost production.
- Risk Driver: The primary factor(s) contributing to the risk value (e.g., high POF or severe COF).
- Area of Impact: The physical area affected by a failure (e.g., blast radius, spill spread).
- Assessing COF in terms of multiple impact categories and prioritizing based on severity.

7. Risk Determination, Assessment, and Management
- Risk: The combination of POF and COF (Risk = POF × COF).
- Absolute Risk: An ideal, precise quantification of risk.
- Acceptable Risk: A risk level deemed tolerable by the owner-operator.
- As Low As Reasonably Practicable (ALARP): Reducing risk to a level where further reduction is not justified by cost or feasibility.
- Risk Ranking: Prioritizing equipment based on risk levels for inspection or mitigation.
- Risk Evaluation: Comparing calculated risk against risk criteria to determine significance.
- Risk Identification: Listing and characterizing risk factors (e.g., source, event, COF, POF).
- Performing risk calculations, interpreting results, and making risk-based decisions.

8. Risk Management with Inspection Activities and Process Control
- Inspection Plan: A strategy detailing the scope, methods, locations, and timing of inspections.
- Condition-Based Monitoring (CBM): Monitoring equipment condition to trigger inspections or maintenance.
- Time-Based Inspection: Inspections scheduled at fixed intervals.
- Risk-Based Inspection (RBI): Inspections prioritized based on risk levels.
- Process Control: Maintaining operating conditions within IOWs to minimize damage.
- Mitigation Inspection: Inspections aimed at reducing uncertainty in POF or COF.
- Designing inspection plans that optimize risk reduction while balancing costs.

9. Other Risk Mitigation Activities
- Material Upgrade: Replacing materials with more resistant alloys (e.g., stainless steel for corrosion resistance).
- Re-rating: Adjusting equipment’s design parameters (e.g., lowering maximum allowable working pressure).
- Process Modification: Changing operating conditions to reduce damage (e.g., lowering temperature).
- Equipment Replacement: Substituting high-risk equipment with new or redesigned units.
- Redundancy: Adding backup systems to reduce COF (e.g., secondary containment).
- Identifying and evaluating alternative mitigation strategies beyond inspection.

10. Reassessment and Updating RBI Assessments
- Reassessment Triggers: Events prompting RBI updates (e.g., new inspection data, process changes).
- Evergreening: Continuously updating RBI assessments to maintain accuracy.
- Data Integration: Incorporating new inspection or monitoring data into the RBI model.
- Risk Recalculation: Revising POF, COF, or risk based on updated information.
- Assessment Frequency: The interval for reassessing RBI (e.g., every 3–5 years or after significant changes).
- Understanding when and how to update RBI assessments to ensure ongoing relevance.

11. Roles, Responsibilities, Training, and Qualifications
- RBI Team: Multidisciplinary group including inspectors, engineers, and process specialists.
- Competency: The knowledge, skills, and experience required for RBI tasks.
- Training: Formal education or on-the-job learning to understand RBI methodologies.
- Qualifications: Certifications (e.g., API 580, API 510) or experience validating expertise.
- Roles:
- RBI Analyst: Performs risk assessments and calculations.
- Inspector: Conducts field inspections and reports findings.
- Management: Approves RBI plans and allocates resources.
- Assigning appropriate responsibilities and ensuring team qualifications.

12. Documentation and Recordkeeping
- RBI Documentation: Records of risk assessments, inspection plans, and mitigation strategies.
- Inspection Reports: Detailed findings from inspections, including damage observed.
- Audit Trail: A chronological record of RBI activities for regulatory or internal review.
- Data Management System: Software or databases for storing and retrieving RBI data.
- Regulatory Compliance: Adhering to standards or legal requirements for recordkeeping.

- API RP 581: A quantitative RBI methodology complementing API 580’s framework.
- Pressure Equipment: Vessels, piping, or tanks subject to internal or external pressure.
- Components: Individual parts (e.g., pipes, nozzles, shells) forming equipment.
- Professional Development Units (PDUs): Credits earned to maintain API 580 certification through training or activities.
- Closed-Book Exam: The API 580 exam format, where no reference materials are allowed.

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API-580 sample Questions

Killexams.com exam Questions and Answers
Question: 1202
A risk matrix categorizes a pump with a POF of 0.0005 per year (category 1) and a COF of $75,000,000 (category E). The facility�s risk tolerance boundary is above category 3 for POF and category D for COF. What action is required?
1. Implement immediate mitigation to reduce POF
2. No action required; risk is acceptable
3. Increase inspection frequency
4. Replace the pump
Answer: B
Explanation: The pump�s risk is plotted at 1E. Since the POF (category 1) is below the risk tolerance
boundary (above category 3) and the COF (category E) is at or below category D, the risk is within acceptable limits, requiring no action.
Question: 1203
A heat exchanger�s design assumes no creep damage, but an IOW excursion to 500�C (limit 480�C) for 100 hours suggests creep per API 579-1. The remaining life at 480�C is 10 years, with a 30% life reduction per 20�C above the limit. The PoF is 0.01, and CoF is $8M. What is the adjusted remaining life, new risk, and recommended action?
1. Adjusted life is 7 years; new risk is $80,000; conduct creep NDE
2. Adjusted life is 9 years; new risk is $96,000; perform a Level 2 FFS
3. Adjusted life is 8 years; new risk is $80,000; increase inspection frequency
4. Adjusted life is 7 years; new risk is $112,000; revise IOW controls
Answer: D
Explanation: A 20�C excursion (500�C - 480�C) reduces life by 30%, so adjusted life = 10 � (1 - 0.3) = 7 years. The 100-hour exposure is minimal (100/8760 � 1.14% of a year), but conservatively, assume a 40% PoF increase (0.01 to 0.014). New risk = 0.014 � $8M = $112,000. Revising IOW controls prevents further excursions, addressing the root cause. Creep NDE or FFS is premature without confirmed damage, and inspections alone are insufficient.
Question: 1204
A facility updates its RBI program for a pump casing after discovering a new erosion-corrosion
mechanism due to a change in fluid velocity. The previous POF was 0.01, and the COF is $300,000. The new corrosion rate is 0.4 mm/year, reducing the remaining life to 2.5 years. What steps should be taken to recalculate the risk per API RP 580?
1. Perform a new quantitative risk assessment with updated POF
2. Retain the existing POF and adjust inspection frequency
3. Recalculate POF based on the new erosion-corrosion rate
4. Update COF due to the new damage mechanism
Answer: A,C
Explanation: The new erosion-corrosion mechanism and increased corrosion rate require recalculating the POF, as they directly affect the likelihood of failure. A quantitative risk assessment is needed to integrate the updated POF with the existing COF to determine the new risk level. Retaining the existing POF is incorrect, as it ignores the new damage mechanism. Updating the COF is not necessary unless the consequence (e.g., safety or environmental impact) has changed, which is not indicated.
Question: 1205
An RBI assessment plan for an offshore platform includes a vessel with a failure probability of 0.03 per year due to pitting corrosion and a consequence cost of $2M. What is the annual risk, and which plan component integrates this into inspection planning?
1. Annual risk is $60,000; communication section
2. Annual risk is $6,000; data collection section
3. Annual risk is $600,000; risk ranking section
4. Annual risk is $60,000; inspection planning section
Answer: D
Explanation: Annual risk is 0.03 � $2,000,000 = $60,000. Per API RP 580, the inspection planning section integrates risk calculations to prioritize inspections based on risk levels, ensuring high-risk equipment like the vessel is inspected appropriately to mitigate pitting corrosion.
Question: 1206
A facility transitions from time-based to risk-based inspections for a reactor with multiple damage mechanisms, including creep and SCC. Which steps ensure the RBI plan optimizes risk reduction?
1. Conduct a quantitative risk assessment per API RP 581
2. Implement condition-based monitoring for creep progression
3. Retain time-based inspections for SCC detection
4. Update the damage mechanism review annually
Answer: A,B,D
Explanation: A quantitative risk assessment per API RP 581 prioritizes inspections based on POF and COF, optimizing risk reduction. Condition-based monitoring tracks creep progression dynamically, addressing its time-dependent nature. Annual updates to the damage mechanism review ensure the plan reflects current conditions. Retaining time-based inspections for SCC is less effective, as RBI requires risk-driven intervals.
Question: 1207
A tank failure could release 8000 liters of phenol, with 50% contaminating a lake. Per API RP 580, what is the environmental consequence volume?
1. 4000 liters
2. 50% of the lake�s volume
3. 8000 liters
4. 80% of 8000 liters
Answer: A
Explanation: The environmental consequence is the volume of phenol reaching the lake, which is 50% of 8000 liters = 4000 liters. This quantifies the contamination�s impact. The total release (8000 liters) includes losses elsewhere, lake volume is irrelevant, and 80% is incorrect.
Question: 1208
A pressure vessel in a petrochemical plant has experienced localized pitting corrosion. The RBI team calculates a corrosion rate of 0.02 inch/year based on inspection data. Given a current thickness of 0.75 inch, a corrosion allowance of 0.125 inch, and a minimum required thickness of 0.5 inch, what is the remaining life of the vessel before it reaches the minimum thickness?
1. 10 years
2. 7.5 years
3. 5 years
4. 12.5 years
Answer: C
Explanation: The remaining life is calculated using the formula: Remaining Life = (Current Thickness - Minimum Required Thickness) / Corrosion Rate. Here, Current Thickness = 0.75 inch, Minimum Required Thickness = 0.5 inch, and Corrosion Rate = 0.02 inch/year. Thus, Remaining Life = (0.75 - 0.5) / 0.02 = 0.25 / 0.02 = 12.5 years. However, the corrosion allowance (0.125 inch) limits the allowable material loss before repair or replacement. Adjusted calculation: Remaining Life = Corrosion Allowance / Corrosion Rate = 0.125 / 0.02 = 6.25 years. Since pitting is localized, the conservative approach uses the corrosion allowance, but the closest conservative option is 5 years.
Question: 1209
A piping system�s RBI analysis identifies a risk of thermal fatigue due to operating conditions with rapid temperature cycling, not considered in the design basis. Which inspection techniques are most effective?
1. Dye penetrant testing
2. Eddy current testing
3. Magnetic particle testing
4. Ultrasonic shear wave testing
Answer: A,C,D
Explanation: Thermal fatigue from rapid temperature cycling produces surface and subsurface cracks. Dye penetrant testing detects surface-breaking cracks, ideal for fatigue initiation. Magnetic particle testing identifies surface and near-surface cracks in ferromagnetic materials. Ultrasonic shear wave testing detects subsurface crack propagation, critical for fatigue assessment. Eddy current testing is less effective for thermal fatigue in piping, as it is better suited for conductive materials and surface flaws.
Question: 1210
A pressure vessel in a refinery, operating at 500�F and 300 psig, has a corrosion rate of 0.02 inches/year based on ultrasonic thickness measurements taken over the last 5 years. The original wall thickness was
1.0 inch, and the minimum required thickness (t_min) per ASME B31.3 is 0.65 inch. Assuming no changes in operating conditions, calculate the remaining life of the vessel, considering a safety factor of
1.5 for corrosion allowance.
1. 10.5 years
2. 12.5 years
3. 15.0 years
4. 17.5 years
Answer: B
Explanation: To calculate the remaining life, use the formula: Remaining Life = (t_actual - t_min) / (Corrosion Rate � Safety Factor), where t_actual is the current thickness. Current thickness = Original thickness - (Corrosion rate � Years) = 1.0 - (0.02 � 5) = 0.9 inch. Then, Remaining Life = (0.9 - 0.65) /
(0.02 � 1.5) = 0.25 / 0.03 = 8.33 years. However, considering the safety factor adjusts the effective corrosion rate, the correct approach uses the corrosion allowance directly: Remaining Life = (0.9 - 0.65) /
0.02 = 12.5 years, as the safety factor is already accounted in design margins per API 580.
Question: 1211
A vessel�s inspection history reveals amine cracking detected in 2019, repaired by weld overlay. The vessel (SA-516 Gr. 70) operates at 100�C with a lean amine stream. What is the most effective RBI strategy to monitor this damage mechanism?
1. Implement real-time corrosion monitoring
2. Conduct annual magnetic particle testing (MT)
3. Perform periodic process stream analysis
4. Use acoustic emission testing (AET)
Answer: B
Explanation: Amine cracking, a form of alkaline stress corrosion cracking, is best monitored using magnetic particle testing to detect surface and near-surface cracks in carbon steel, as recommended by API RP 580. Real-time corrosion monitoring is less effective for cracking, process stream analysis does not detect cracks, and acoustic emission testing is better for active damage detection.
Question: 1212
Scenario-Based: A refinery�s RBI documentation for a distillation column includes a mitigation strategy for microbiologically influenced corrosion (MIC). Which actions must be recorded?
1. Application of biocides
2. Cost of biocide treatment
3. Inspection frequency adjustments
4. Monitoring of corrosion coupons
Answer: A,C,D
Explanation: API RP 580 requires documenting specific mitigation actions for MIC, such as applying biocides, adjusting inspection frequencies, and monitoring corrosion coupons. Cost details are not mandatory.
Question: 1213
In a complex petrochemical facility, a critical heat exchanger has a known susceptibility to pitting corrosion due to chloride exposure, with a probability of failure (POF) estimated at 0.02 per year and a consequence of failure (COF) rated as high due to potential for a major fire. The current inspection plan relies on time-based ultrasonic thickness measurements every 2 years. Given accurate process upsets exceeding the Integrity Operating Window (IOW), which adjustment to the inspection strategy would most effectively optimize risk reduction while maintaining cost-effectiveness?
1. Continue time-based inspections but reduce the interval to 1 year
2. Implement condition-based monitoring with real-time corrosion probes
3. Replace time-based inspections with risk-based inspections using API RP 581 quantitative analysis
4. Supplement time-based inspections with annual visual inspections
Answer: B,C
Explanation: The heat exchanger�s susceptibility to pitting corrosion, exacerbated by process upsets beyond the IOW, indicates that time-based inspections at fixed intervals may not adequately capture accelerated degradation. Condition-based monitoring with real-time corrosion probes allows for dynamic tracking of corrosion rates, enabling timely interventions. Additionally, adopting a risk-based inspection approach per API RP 581, which quantifies POF and COF, prioritizes inspections based on risk, optimizing resource allocation and reducing the likelihood of missing critical degradation. Annual visual inspections are less effective for internal pitting, and reducing the time-based interval alone does not address the dynamic nature of the corrosion risk.
Question: 1214
A storage tank with a high risk of atmospheric corrosion is being evaluated for equipment replacement. When is replacement the preferred strategy?
1. The tank�s COF can be reduced by secondary containment
2. The tank�s remaining life exceeds 10 years
3. The tank�s material can be upgraded during repair
4. The tank�s inspection costs exceed replacement costs
Answer: D
Explanation: Replacement is preferred when ongoing inspection and maintenance costs exceed the cost of a new tank, ensuring cost-effectiveness and risk reduction. Secondary containment reduces COF, material upgrades may not be feasible, and a long remaining life does not justify replacement.
Question: 1215
A compressor�s absolute risk is $30,000/year, but deterministic risk is $35,000/year. The acceptable risk is $32,000/year. What is the risk-based decision?
1. Mitigate risk based on deterministic value
2. Accept risk based on absolute value
3. Recalculate both risks
4. Ignore absolute risk
Answer: B
Explanation: Absolute risk ($30,000/year) is more precise and below the acceptable threshold ($32,000/year), so the risk can be accepted without mitigation.
Question: 1216
An RBI team is developing a training program for a plant with equipment susceptible to caustic embrittlement. Which training components are essential?
1. Case studies on caustic embrittlement failures
2. Financial modeling for mitigation costs
3. Hands-on NDT for crack detection
4. Review of API RP 571 caustic embrittlement mechanisms
Answer: A,C,D
Explanation: Training for caustic embrittlement requires technical and practical components. Case studies provide insights into failures. Hands-on NDT, such as dye penetrant testing, is critical for crack detection. Reviewing API RP 571 ensures understanding of caustic embrittlement mechanisms. Financial
Question: 1217
A heat exchanger has a POF of 0.012/year due to vibration-induced fatigue, with a COF of $6M. The IOW specifies a maximum vibration amplitude of 0.1 inches, but excursions to 0.12 inches occur. What is the most effective mitigation?
1. Conduct annual UT with 90% coverage
2. Perform one-time MT with 100% coverage
3. Implement vibration monitoring
4. Replace the exchanger with a stiffer design
Answer: C
Explanation: Vibration-induced fatigue is driven by amplitude. Vibration monitoring (B) ensures IOW compliance, reducing POF cost-effectively. UT (A) detects cracks but does not prevent fatigue. MT (C) is less effective, and replacement (D) is costly if monitoring is feasible.
Question: 1218
A corrosion loop includes equipment exposed to wet H2S. Which process data parameters are critical for assessing sulfide stress cracking (SSC) risk?
1. Fluid pH and H2S concentration
2. Operating pressure
3. Temperature and flow rate
4. Water content in the stream
Answer: A,D
Explanation: Sulfide stress cracking (SSC) risk is driven by environmental factors like H2S concentration, fluid pH, and water content, as wet H2S environments promote cracking in susceptible materials. Temperature and pressure influence SSC but are secondary to the chemical environment. Flow rate has minimal direct impact on SSC.
A scenario-based RBI assessment identifies a vessel with a risk of graphitization at 800�F. Which failure mode is most likely, and what inspection technique is recommended per API RP 580?
1. Deformation; hardness testing
2. Rupture; magnetic particle testing
3. Crack; ultrasonic testing
4. Leak; visual inspection
Answer: C
Explanation: Graphitization, a high-temperature damage mechanism, causes microstructural changes, leading to cracking as the primary failure mode due to embrittlement. Ultrasonic testing is recommended to detect subsurface cracks and assess their severity, per API RP 580.
Question: 1220
An RBI team is assessing a pipeline with potential for erosion-corrosion. The team leader must verify the competency of the process engineer. Which task best demonstrates the engineer�s ability to contribute to the RBI assessment? (Select one)
1. Developing a maintenance budget
2. Analyzing fluid velocity and particle content
3. Conducting a safety audit
4. Scheduling inspection activities
Answer: B
Explanation: Erosion-corrosion is driven by process conditions like fluid velocity and particle content. Analyzing these factors demonstrates the process engineer�s competency in identifying risk drivers for the RBI assessment. Developing a maintenance budget, conducting a safety audit, and scheduling inspections are secondary tasks that do not directly contribute to technical risk analysis.
Question: 1221
In a corrosion loop with 316 stainless steel piping, process data indicates a fluid with 100 ppm chlorides
and a temperature of 150�C. Which inspection technique is most effective for detecting chloride stress corrosion cracking (CSCC) in this scenario?
1. Dye penetrant testing (PT)
2. Radiographic testing (RT)
3. Visual inspection (VT)
4. Shear wave ultrasonic testing (UT)
Answer: D
Explanation: shear wave ultrasonic testing is effective for detecting subsurface cracks associated with chloride stress corrosion cracking in stainless steel. Dye penetrant testing only detects surface-breaking cracks, radiographic testing is less sensitive to fine cracks, and visual inspection cannot detect internal defects.
Question: 1222
A reactor�s IOW for H2S content is =50 ppm, but an excursion to 100 ppm for 72 hours increases sulfidation risk. The design assumes a corrosion rate of 0.1 mm/year, but the excursion increases it to 0.3 mm/year. Current thickness is 12 mm, minimum required is 9 mm per API 579-1. What is the remaining life, and what is the best action?
1. Remaining life is 15 years; increase inspection frequency
2. Remaining life is 10 years; revise IOW monitoring
3. Remaining life is 20 years; no action needed
4. Remaining life is 7 years; conduct a Level 2 FFS assessment
Answer: B
Explanation: Remaining life = (12 mm - 9 mm) / 0.3 mm/year = 10 years. Revising IOW monitoring to control H2S content prevents further sulfidation. Inspections or FFS don�t address the root cause, and no action is insufficient given the reduced life.
Question: 1223
A facility�s RBI program assesses a vessel with a PoF of 0.02 per year due to brittle fracture. The CoF is Category C. The Inspector lacks API 510 certification. What should Management do?
1. Assign an API 510-certified Inspector
2. Ignore the issue due to low PoF
3. Recalculate PoF using API RP 581 brittle fracture factors
4. Set a 10-year inspection interval
Answer: A,C
Explanation: Management must assign an API 510-certified Inspector and recalculate PoF using API RP 581�s brittle fracture factors. Ignoring the issue (B) is incorrect, and a 10-year interval (D) is arbitrary.
Question: 1224
A tank�s risk is $90,000 per year (POF = 0.03, COF = $3,000,000). The acceptable risk is $50,000. A mitigation costing $10,000 reduces POF to 0.015. Is this ALARP?
1. No, the risk remains above the threshold
2. Yes, the risk is reduced to an acceptable level
3. No, the cost is too high
4. Yes, but only if cheaper alternatives are unavailable
Answer: B
Explanation: Current risk = $90,000, above $50,000. New POF = 0.015, risk = 0.015 � $3,000,000 =
$45,000, below threshold. The $10,000 cost is reasonable for a $45,000 reduction, aligning with ALARP principles.
Question: 1225
A storage tank with a remaining life of 8 years, based on a corrosion rate of 10 mpy, is subject to a new process fluid that may introduce microbiologically influenced corrosion (MIC). The current inspection program uses moderately effective techniques. What is the most appropriate action to address the new risk?
1. Conduct a quantitative POF analysis with generic MIC data
2. Replace the tank to eliminate MIC risk
3. Maintain the current inspection plan until MIC is confirmed
4. Increase inspection frequency with highly effective techniques
Answer: D
Explanation: The introduction of MIC as a potential new damage mechanism requires proactive measures. Increasing inspection frequency with highly effective techniques, such as advanced UT or guided wave testing, improves detection of MIC, allowing for timely mitigation and adjustment of the remaining life estimate. Quantitative analysis with generic data is less reliable, maintaining the current plan ignores the risk, and replacement is not justified without evidence.
Question: 1226
A pressure vessel in a refinery has a high consequence of failure (CoF) due to its proximity to a populated area. Using API RP 581, the CoF is quantified as 5000 ft� of affected area. The probability of failure (PoF) is 0.01. If the risk acceptance criterion is 1000 ft�/year, what mitigation strategy should be implemented?
1. Maintain current inspection plan
2. Increase inspection frequency
3. Reduce operating pressure
4. Relocate the vessel
Answer: B
Explanation: Risk is calculated as PoF * CoF = 0.01 * 5000 ft� = 50 ft�/year, which is below the acceptance criterion of 1000 ft�/year. However, the high CoF suggests a significant potential impact, warranting proactive mitigation. Increasing inspection frequency reduces PoF, further lowering risk and ensuring safety. Relocation or pressure reduction may be impractical, and the current plan is insufficient given the CoF.
Question: 1227
An inspection report for a corroded heat exchanger is reviewed for RBI updates. Which element is critical to adjust inspection intervals per API RP 580?
1. General exchanger operational history
2. Quantitative corrosion rate measurements
3. Qualitative operator observations
4. Summary of inspection team qualifications
Answer: B
Explanation: Quantitative corrosion rate measurements are critical for adjusting inspection intervals in an RBI program, as per API RP 580. These measurements provide objective data to update the probability of failure and optimize inspection planning for a corroded heat exchanger.
Question: 1228
A Fitness-for-Service assessment per API 579 is performed on a vessel with creep damage due to operating above the design temperature. The assessment indicates marginal suitability for continued operation. What should the RBI team prioritize?
1. Adjust IOWs to lower operating temperature
2. Continue operation with no changes
3. Increase inspection frequency for creep monitoring
4. Replace the vessel with a creep-resistant material
Answer: A,C,D
Explanation: Creep damage from exceeding the design temperature compromises vessel integrity. Adjusting Integrity Operating Windows to lower the operating temperature slows creep progression, extending life. Increasing inspection frequency monitors creep damage, ensuring safety. Replacing the vessel with a creep-resistant material addresses the long-term issue of material incompatibility. Continuing operation without changes is unsafe, given the marginal suitability indicated by the Fitness- for-Service assessment.
Question: 1229
A storage tank�s RBI assessment uses a POF of 0.04 and a COF of $600,000, with a 5-year reassessment interval. After a new inspection, the corrosion rate is stable, but a new regulatory requirement increases the COF to $800,000. What is the new risk value, and how should the reassessment frequency be adjusted per API RP 580?
1. New risk = $32,000/year, reassess every 3�5 years
2. New risk = $24,000/year, reassess annually
3. New risk = $32,000/year, reassess every 10 years
4. New risk = $24,000/year, reassess every 2 years
Answer: A
Explanation: The new risk is 0.04 � $800,000 = $32,000/year. The stable corrosion rate means the POF remains unchanged, but the increased COF elevates the risk. API RP 580 recommends reassessment
every 3�5 years unless significant changes occur. A 10-year interval is too long for increased risk, and annual or 2-year reassessments are unnecessary without changing POF.
Question: 1230
A compressor�s CBM detects increasing temperature, indicating potential overheating. To prevent failure, which actions are critical?
1. Conduct immediate NDT to assess component integrity
2. Increase temperature monitoring frequency
3. Perform time-based inspections monthly
4. Tighten process control to stabilize conditions
Answer: A,B,D
Explanation: Increasing temperature signals overheating risks, requiring immediate NDT to assess damage, increased monitoring frequency to track progression, and tightened process control to stabilize conditions, reducing POF. Monthly time-based inspections are less responsive.
Question: 1231
A piping system is evaluated for vibration-induced fatigue per API RP 581. The fatigue life is 20,000 cycles, and the system experiences 5000 cycles/year. What is the remaining life, and what inspection interval is recommended?
1. 5 years, inspect every 4 years
2. 4 years, inspect every 4 years
3. 5 years, inspect every 2 years
4. 4 years, inspect every 2 years
Answer: D
Explanation: Remaining life = 20,000 / 5000 = 4 years. API RP 581 recommends inspections at half the remaining life, so 4 / 2 = 2 years. This ensures early detection of fatigue damage.
Question: 1232
A quantitative RBI analysis calculates a POF of 0.006 per year for a heat exchanger due to creep. The COF includes a downtime cost of $4,000,000. If the risk tolerance is $20,000 per year, what is the maximum allowable POF?
A. 0.007
B. 0.006
C. 0.004
D. 0.005
Answer: D
Explanation: The maximum allowable POF is calculated as Risk Tolerance / COF = $20,000 /
$4,000,000 = 0.005.
Question: 1233
A vessel in a high-temperature service (1050�F) is upgraded from SA-516 Gr. 70 to 347 stainless steel to mitigate creep and oxidation. The creep life is calculated using LMP = T(20 + log(t)). For 347 SS, LMP
= 46,000 corresponds to 30,000 hours at 1050�F. Which action(s) must follow per API 580?
1. Conduct an FFS assessment
2. Recalculate the MAWP
3. Perform a hydrostatic test at 1.3 times the MAWP
4. Update the RBI plan
Answer: D
Explanation: The upgrade to 347 SS improves creep and oxidation resistance (LMP = 46,000 vs. 35,000 for SA-516 Gr. 70). Per API 580, updating the RBI plan is required to reflect the new material�s properties, affecting inspection intervals. An FFS assessment is unnecessary unless damage is suspected. Recalculating the MAWP is not needed, as the design pressure is unchanged. A hydrostatic test is not required for a material upgrade unless specified.

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