API 510 and API 570 are both in-service inspection standards published by the American Petroleum Institute. Both are part of the API ICP (Individual Certification Program). Both deal with pressurized equipment in operating plants. And both are commonly held by the same inspector, which is part of why the confusion between them persists.
The short version: API 510 covers pressure vessels. API 570 covers piping systems. But the boundary between the two, the damage mechanisms they share, and the real-world situations where you need both are worth understanding in detail, especially if you are planning a turnaround, building out an integrity management program, or evaluating what inspection coverage you actually need.
What API 510 Covers
API 510: Pressure Vessel Inspection Code applies to pressure vessels that have been placed in service. The equipment scope includes separators, drums, accumulators, heat exchangers (shell-and-tube), reactors, towers, and columns. This includes any pressure-retaining vessel fabricated to ASME Section VIII, Division 1 or Division 2.
API 510 governs inspection intervals, inspection methods, repair and alteration requirements, and fitness-for-service evaluations for in-service vessels. When a vessel is repaired or altered in service, the repair must be performed per ASME Section VIII requirements and be authorized by an API 510 Authorized Pressure Vessel Inspector.
The standard does not apply to equipment during original construction. That is ASME Section VIII territory and the shop inspector's domain. Once the vessel is stamped and placed in service, API 510 takes over.
API 510 inspections are conducted against ASME Section VIII as the original construction standard. The inspector must understand what the vessel was built to in order to evaluate what is acceptable in service.
What API 570 Covers
API 570: Piping Inspection Code applies to metallic piping systems in process plants, refineries, and similar industrial facilities. The equipment scope includes process piping, injection and disposal piping, utility piping where process contamination risk exists, and risers. The applicable construction codes are ASME B31.3 for process piping, ASME B31.4 for liquid pipeline systems, and ASME B31.8 for gas distribution.
API 570 governs thickness survey intervals, corrosion rate calculations, remaining life assessments, minimum required thickness determinations, and repair authorization for in-service piping. It provides the framework for identifying where in a piping system to measure, how often, and what to do with the data.
The standard is heavily focused on corrosion management, calculating long-term and short-term corrosion rates, projecting remaining life, and determining when to re-inspect based on remaining life fractions.
The Grey Areas: Flanges, Nozzles, and PRVs
In real plants, the boundary between a pressure vessel and its connected piping is not always obvious. The standards are specific about where the boundary falls, and knowing it matters when determining which inspection regime and authorization applies.
Flanges and nozzles on a vessel are part of the vessel under API 510. The nozzle neck, the nozzle flange, and the nozzle-to-shell weld all belong to the vessel scope. The transition to piping scope under API 570 occurs at the first flanged joint beyond the nozzle, or for welded connections, at the first circumferential weld beyond the nozzle.
Pressure relief valves (PRVs) fall within the API 510 framework. API 510 includes requirements for PRV inspection intervals, set pressure verification, and documentation. PRVs are not piping components under API 570. They are pressure-relieving devices subject to their own interval requirements, typically based on service severity and historical performance.
Heat exchanger piping (the piping connecting tube-side and shell-side to process lines) transitions at the first joint as described above. The exchanger body and nozzles are API 510; the piping running to and from it is API 570.
Inspection Intervals
Both standards use similar interval frameworks, and both allow Risk-Based Inspection (RBI) to extend or modify those intervals based on likelihood and consequence of failure.
Under API 510, pressure vessels are subject to external inspection intervals (typically every 5 years maximum without RBI) and internal inspection intervals (typically based on remaining life, half the remaining life, not to exceed 10 years). Vessels with well-characterized corrosion rates and low consequence of failure can have intervals extended significantly under RBI.
Under API 570, piping circuits are categorized by service class (Class 1 for the most severe, Class 3 for the least severe), and inspection intervals are tied to those classes. Thickness surveys on Class 1 piping are required at intervals no greater than 5 years; Class 3 piping can run up to 10 years. RBI can modify these intervals significantly for circuits with low corrosion rates and good history.
The practical implication: both standards reward good inspection data. The more you know about actual corrosion rates in a circuit or vessel, the more defensible an interval extension becomes.
Damage Mechanisms
Many damage mechanisms affect both vessels and piping, which is one of the reasons inspectors who understand one standard tend to understand the other. But the emphasis differs.
Corrosion under insulation (CUI) is a significant focus in both standards. Insulated vessels and insulated piping both accumulate moisture beneath the insulation, and both are prone to external corrosion that can be advanced before it is discovered. The inspection approach (visual with insulation removal, profile RT, or UT mapping) applies in both contexts.
General corrosion, erosion-corrosion, and stress corrosion cracking (SCC) are relevant to both equipment types. High-temperature hydrogen attack (HTHA) and hydrogen-induced cracking (HIC) are typically more prominent damage mechanisms for pressure vessels in hydrogen service. Flow-accelerated corrosion (FAC) is a piping-dominant mechanism. It is driven by turbulence and flow velocity, which is inherent to piping and less common in the relatively static environment of a pressure vessel.
Understanding the process stream, its chemistry, temperature, velocity, and phase, determines which damage mechanisms are active. The API 571 Damage Mechanisms Affecting Fixed Equipment document is the reference for both API 510 and API 570 inspections.
When You Need Both
On most real process units, you need both because the units contain both vessels and piping, and they are connected. A separator has inlet and outlet piping. A heat exchanger has connected process lines. A column has overhead piping, bottoms piping, and multiple side draws. Treating the vessel and its connected piping as separate problems under separate inspection programs without communication between those programs creates gaps.
Turnaround planning is the most obvious case. A unit turnaround involves internal inspection of pressure vessels (API 510), thickness surveys and inspection of piping circuits (API 570), PRV testing, and often repair and alteration work on both. Coordinating that work under a single inspector holding both certifications, or a consulting firm with both capabilities, reduces handoff errors and simplifies authorization.
Plant integrity programs have the same requirement. A comprehensive integrity management program covering all fixed equipment in a unit cannot treat vessels and piping as independent silos. The damage mechanisms interact, the inspection data from piping circuits informs corrosion rate assumptions for connected vessels, and the risk prioritization needs to be done across the whole unit.
Most competent in-service inspectors working in oil and gas hold both API 510 and API 570. Hiring two separate inspectors for the same unit, one for vessels and one for piping, duplicates mobilization cost, creates coordination overhead, and introduces the risk of inconsistent fitness-for-service conclusions on connected equipment.
How the Certification Works
API 510 and API 570 are separate certifications administered through the API ICP program. Each requires a separate examination. Both examinations cover the applicable inspection code, the reference construction standard (ASME Section VIII for API 510; ASME B31.3, B31.4, B31.8 for API 570), and API 571 damage mechanisms.
Both certifications are renewable every 3 years through documented inspection experience and continuing education. There is no requirement to hold one before the other, and many candidates sit both exams in the same cycle.
Holding both certifications under one inspector eliminates the need for two separate contractors on a turnaround or integrity program, and ensures that the person authorizing repairs on a vessel and the person authorizing repairs on its connected piping are working from a consistent understanding of the equipment history and service conditions.
API 510 vs API 570: Side-by-Side
| API 510 | API 570 | |
|---|---|---|
| Equipment covered | Pressure vessels: separators, drums, heat exchangers, reactors, towers, columns | Piping systems: process piping, injection piping, utility piping, risers |
| Construction code reference | ASME Section VIII (Div. 1 and Div. 2) | ASME B31.3, B31.4, B31.8 |
| Inspection interval basis | Remaining life (internal); 5 year max external without RBI | Service class (1 to 3); 5 to 10 year max without RBI |
| Damage mechanism emphasis | HTHA, HIC, SCC, CUI, general corrosion | FAC, erosion-corrosion, CUI, SCC, general corrosion |
| NDE focus | Internal surface, weld examination, thickness mapping | Thickness surveys at TMLs, CUI inspection, weld examination |
| Repair authorization | API 510 Authorized Inspector sign-off required | API 570 Authorized Piping Inspector sign-off required |
| RBI applicability | Yes, API 580/581 framework | Yes, API 580/581 framework |
FAQs
Can one inspector hold both API 510 and API 570 certifications?
Yes. Many inspectors working in oil and gas, refining, and petrochemical facilities hold both. They are separate exams and separate certifications, but the experience base and technical knowledge required overlaps significantly. Holding both is standard practice for inspectors working on process units where vessels and piping coexist, which is nearly every assignment.
Where exactly is the boundary between API 510 and API 570 scope on a pressure vessel?
The boundary is at the first circumferential weld beyond the nozzle for welded connections, or at the first flanged joint beyond the nozzle for flanged connections. Everything from that point back toward the vessel, including the nozzle, the nozzle-to-shell weld, and the nozzle flange, is part of the vessel under API 510. Everything from that point outward toward the rest of the piping system is piping scope under API 570.
Which exam is harder: API 510 or API 570?
Difficulty is subjective and depends on the candidate's background. API 510 candidates who have not worked extensively with ASME Section VIII often find the construction code reference material demanding. API 570 candidates who are less familiar with corrosion rate calculations and remaining life methodology find that material challenging. Both exams are open-book, both allow the applicable code documents and API 571, and both reward inspectors who have actually worked with the equipment rather than studied exclusively from textbooks.
Do I need both API 510 and API 570 coverage for a turnaround?
For most process unit turnarounds, yes. A turnaround involves internal inspection of pressure vessels and inspection of piping circuits, plus PRV testing and often repair work on both. If your turnaround scope includes both vessels and piping, and virtually all of them do, you need inspection authorization under both standards for the respective equipment types. Using one inspector who holds both is the most efficient approach.
Does API 510 or API 570 apply to heat exchanger tube bundles and piping?
The heat exchanger shell, channel, nozzles, and heads are pressure vessel components covered under API 510. The tube bundle itself is internal to the vessel and inspected as part of the API 510 scope. The piping running to and from the exchanger, connecting it to the rest of the process unit, is piping scope under API 570, starting at the first joint beyond the nozzle as described above.