Green Globes Assessor (GGA)

Correct: According to API 580, while the execution of an RBI assessment can be outsourced, the owner-user remains responsible for the results. A key internal control is the documented validation of the consultant’s work by the facility’s subject matter experts (SMEs). This ensures that site-specific damage mechanisms, process variations, and historical data are accurately integrated into the model, which is essential for the reliability of the risk rankings and subsequent inspection plans.

Incorrect: Reviewing contractual liability is a risk transfer strategy but does not address the technical accuracy of the inspection program or the underlying control failure. Comparing inspection points to API 570 minimums is a deterministic compliance check, whereas RBI is designed to prioritize resources based on risk, which may legitimately differ from standard intervals. Verifying the type of software used is insufficient because API 580 recognizes qualitative, semi-quantitative, and quantitative methods as valid; the integrity of the assessment depends on the quality of the data and assumptions, not just the complexity of the software.

Takeaway: The owner-user must maintain active technical oversight and validation of outsourced RBI assessments to ensure that site-specific risks are accurately captured in the inspection strategy.

Correct: ASME B31.3 is the Process Piping code, which covers a wide range of fluids in process plants. According to the scope defined in Chapter I, it applies to all fluid services in refineries and chemical plants but allows for the exclusion of piping systems where the internal pressure is less than 15 psi (105 kPa), provided the fluid is non-flammable, non-toxic, and not damaging to human tissue, and the temperature is between -29°C (-20°F) and 186°C (366°F).

Incorrect: The suggestion that it covers power generation steam lines is incorrect because those are typically governed by ASME B31.1 (Power Piping). The claim that it is limited to metallic hydrocarbons is false as B31.3 includes non-metallic piping and various utility fluids. Finally, the description of inspection and repair of in-service piping describes the role of API 570, not the construction code ASME B31.3.

Takeaway: ASME B31.3 defines the design and construction requirements for process piping but excludes certain low-risk, low-pressure utility systems and specific categories like power piping.

Correct: API 570 and associated safety standards like API 2009 require that the atmosphere be tested at the specific location where hot work will occur immediately before work begins. Automated building systems or area-wide monitoring are insufficient because they cannot detect localized pockets of flammable vapors or gases that may be present at the point of ignition.

Incorrect: While welder certification is a necessary administrative control, it does not mitigate the immediate physical hazard of an explosive atmosphere. A secondary fire watch is only required if sparks could migrate through wall penetrations, which is not specified as the primary failure here. Permit durations vary by facility policy, but the lack of a pre-work gas test is a fundamental breach of safety protocols regardless of the permit’s length.

Takeaway: A hot work permit is only valid if a localized atmospheric test is conducted at the specific work site immediately prior to the start of work.

Correct: According to API 570, dead-legs are sections of piping that do not have continuous flow. These areas are particularly susceptible to localized corrosion, such as microbiologically influenced corrosion (MIC) or deposit-related corrosion, because the stagnant fluid allows solids to settle and temperatures to fluctuate. Therefore, they must be identified, documented, and included in the inspection plan with specific Thickness Monitoring Locations (TMLs).

Incorrect: Excluding dead-legs to focus on high-velocity zones is incorrect because dead-legs represent a unique and often higher risk of localized failure. Visual inspection alone is insufficient for dead-legs as internal corrosion is the primary threat, and insulation can actually hide external corrosion under insulation (CUI). The requirement for monitoring is based on the risk of the component itself, not a percentage-based trigger from the main header thickness loss.

Takeaway: Dead-legs are high-risk components in a piping system that must be specifically identified and monitored for localized corrosion under API 570 standards.

Correct: API 570 and related safety standards emphasize that hazardous area classifications must reflect the actual, current state of the facility. Because process modifications can change the location or severity of hazardous zones (e.g., changing a fluid’s flash point or increasing pressure), verifying classifications against Management of Change (MOC) records and current conditions is a critical regulatory and safety best practice to prevent accidents during inspection.

Incorrect: Relying on original design drawings is incorrect because it fails to account for subsequent modifications that may have altered the hazardous zones. Applying a universal Class I, Division 1 designation is an inefficient use of resources and does not constitute a precise risk assessment. Allowing non-intrinsically safe equipment based on arbitrary distance rules without a formal gas test or verified classification ignores the specific technical requirements for working in classified areas.

Takeaway: Effective hazardous area management requires the continuous alignment of classification records with actual process configurations to ensure the safety of inspection personnel and equipment.

Correct: According to API 576, the inspection interval for pressure-relieving devices should be based on their performance. If a device is found to be in poor condition, fouled, or fails to pop within the required tolerance, the interval must be reviewed and shortened. This process continues until the records indicate that the device will perform reliably over the specified period.

Incorrect: Upgrading metallurgy is a corrective design action but does not satisfy the procedural requirement to adjust inspection frequency based on observed failure. Extending the interval is incorrect as it increases the risk of undetected failure. Adding a field-lift test is a supplemental check but does not replace the requirement to adjust the primary shop-test interval when a device fails to meet performance standards.

Takeaway: When a pressure-relieving device fails an inspection or test, API 576 requires that the inspection interval be reduced until consistent reliability is established.

Correct: When a spring hanger is bottomed out (or topped out) during operation, it indicates that the piping system is not moving as designed or that the load distribution has shifted significantly. API 570 emphasizes that supports must be functional to prevent excessive stress on the piping and connected equipment nozzles. The inspector must investigate the root cause—such as unexpected thermal expansion, pipe sagging, or external interference—because a bottomed-out support acts as a rigid restraint, potentially causing high stresses and fatigue at terminal points.

Incorrect: Adjusting the load bolts while the system is hot without an engineering analysis could inadvertently transfer excessive loads to equipment nozzles or other supports. Classifying the issue as minor ignores the risk of mechanical failure due to thermal stress, which is a primary concern for high-temperature piping. Replacing springs with rigid supports is incorrect because it eliminates the thermal flexibility required for the system to expand and contract safely, which would likely lead to piping or structural failure.

Takeaway: A bottomed-out or topped-out spring support indicates a loss of piping flexibility that requires a root-cause evaluation of the system’s thermal movement and load distribution.

Correct: Erosion is a mechanical degradation process influenced by fluid velocity, particle impact, and piping geometry. According to API 570 and related damage mechanism standards, reducing the velocity by increasing the pipe diameter or protecting the surface with harder, wear-resistant materials (like refractory linings) are primary methods for mitigating erosion in high-turbulence areas.

Incorrect: External coatings are designed to prevent atmospheric corrosion or Corrosion Under Insulation (CUI), not internal erosion caused by slurry flow. Sacrificial anodes are used for galvanic corrosion protection and have no effect on the mechanical removal of metal by abrasive particles. Increasing the operating temperature may actually increase the rate of corrosion-erosion and does not address the mechanical impingement of the slurry particles.

Takeaway: Effective mitigation of erosion in piping systems requires addressing the mechanical causes, such as fluid velocity and impingement angles, rather than electrochemical corrosion controls.

Correct: According to API 570, rerating a piping system by changing its design temperature or MAWP is only permissible after calculations are performed by a piping engineer or the inspector. These calculations must prove that the system meets the requirements of the original construction code (ASME B31.3) or other applicable standards for the new operating conditions.