API 570 Piping Inspection Support in Washington

Short answer: In Washington, API 570 inspection of refinery, terminal and chemical piping is planned, evaluated and signed by the owner's API 570 Authorized Inspector (AI). Atlantis NDT performs the nondestructive examinations behind that plan: ultrasonic thickness readings at condition monitoring locations (CMLs), automated corrosion mapping, profile radiography, guided-wave screening, CUI follow-up and PAUT or TOFD on welds. Atlantis performs the NDE; your API 570 Authorized Inspector remains inspector of record and signs the inspection report.

Washington is one of the few states where API 570 shows up by name in state regulation, not only as the good practice an owner chooses. The Department of Ecology's oil-handling rules require transfer pipelines at large marine and pipeline facilities to be inspected in accordance with API 570, and since December 2024 the Department of Labor and Industries (L&I) has applied a refinery-specific process safety rule that adds formal damage mechanism reviews on top of the familiar mechanical-integrity element. Add five refineries on Puget Sound, a marine climate that keeps insulation wet for much of the year, seismic exposure and a dense pipeline network, and the Washington piping programme looks different from a Gulf Coast one. This hub covers where the piping is, what API 570 asks for, which NDE methods fit, how the state and federal rules divide the work, and what Atlantis hands your AI. To begin, request an NDE scope for your AI's inspection plan.

Where API 570 piping is in Washington

Direct answer: Washington's process piping is concentrated at the four refineries in Whatcom and Skagit counties and the Tacoma refinery, at marine and products terminals around Seattle, Tacoma, Everett and Vancouver, at gas-storage and LNG sites, and at pulp and paper, chemical, food-processing and power plants statewide. Most API 570 circuits sit within a few miles of salt water.

Cherry Point and Ferndale, Whatcom County

BP's Cherry Point refinery near Blaine and the Phillips 66 Ferndale refinery receive crude by tanker and by the Trans Mountain system's Puget Sound line from Canada. Their API 570 programmes cover crude and vacuum transfer lines, FCC and coker piping where present, hydrotreater and hydrocracker reactor effluent systems, sour water and amine circuits, hydrogen and fuel-gas headers, and long dock lines out to the marine piers. Dock piping is a world of its own: salt spray, wind-driven rain, coating breakdown at supports and clamps, and soil-to-air or splash-zone transitions where pipe leaves the trestle. Many owners treat those lines as separate circuits with their own CML density.

March Point, Anacortes, Skagit County

Two refineries share March Point: the Marathon Anacortes refinery and the HF Sinclair Puget Sound refinery. Both have decades of piping history, with service changes, unit revamps and replacements layered over original construction. That history matters for API 570 because corrosion rates depend on consistent CML identification across inspections; where CML numbering changed with ownership or a database migration, the long-term rate can be misleading until the history is reconciled. The 2010 heat exchanger rupture at the Anacortes refinery, investigated by the US Chemical Safety Board, is part of the background to Washington's later rule on damage mechanism reviews.

Tacoma tideflats and Commencement Bay

Par Pacific's Tacoma refinery, bulk-liquid terminals, chemical plants and Puget Sound Energy's LNG facility at the Port of Tacoma share the tideflats. Piping here runs on reclaimed ground with high groundwater, so buried and partially buried lines, sleeves under roads and rail spurs, and soil-to-air interfaces get more attention than at an upland site. Asphalt and heavy-product lines are often heat-traced and insulated, which sets up corrosion under insulation wherever tracing fails or jacketing leaks.

Seattle, Everett and the I-5 corridor

Harbor Island and the Duwamish waterway hold terminals supplying the city, Sea-Tac airport and marine fuelling; Everett has terminal and industrial capacity; and the Olympic Pipeline carries refined products south along the I-5 corridor. Terminal piping between tanks, pumps, manifolds and docks is a typical API 570 population, and its boundary with the regulated pipeline is one of the most important lines to draw on paper (see the regulations section).

Vancouver, Longview and the Columbia River

The Port of Vancouver, Longview and Kalama handle liquid bulk, and pulp and paper mills along the lower Columbia run kraft-process piping for white, green and black liquor, chlorine dioxide and caustic. Owners often apply API 570 principles to these flammable, toxic or corrosive services even when the plant is not a refinery, and they use simpler programmes for utilities and water. Whether a line is in scope is the owner's decision.

Eastern Washington

Spokane and the Tri-Cities hold products terminals, food-processing plants with ammonia refrigeration piping, fertilizer and agricultural chemical sites, and gas compressor and storage facilities. Nuclear plant piping at the Columbia Generating Station and Department of Energy systems at Hanford follow their own in-service rules and are outside this page.

What API 570 requires, in plain terms

Direct answer: API 570 is the in-service inspection, repair, alteration and rerating code for metallic process piping and its pressure-relief devices. The owner groups piping into circuits, assigns a service class by consequence of a leak, places CMLs where damage is expected, and schedules thickness and external inspection by class and remaining life, or by a qualifying RBI programme. The AI evaluates and signs.

The current edition is API 570 fifth edition, published in February 2024, reissued alongside API RP 574. API's own summary of the update highlights a defined Inspection Supervisor role, stronger requirements for pressure-relieving devices and new rules on deferring inspection repair recommendations. Copies that circulate online are almost always older editions, so set your programme from a licensed current copy. In our own words, the points that shape an NDE scope are these:

• Roles. The code is written for owners who have, or can call on, an authorized inspection agency, a repair organisation, piping engineers, inspectors and examiners. In API 570, the term inspector means the authorized piping inspector. NDE examiners, such as Atlantis technicians, take measurements for the inspector and do not make the evaluation.
• Services in scope. Hydrocarbon, chemical and other flammable or toxic process services are in scope; water, steam, condensate and similar low-hazard services can be included at the owner's option. API 570 does not replace ASME B31.3 for new piping before it enters service.
• Service classes. Class 1 holds services where a leak could quickly become an emergency, such as flammables that auto-refrigerate and light hydrocarbons that flash. Class 2 covers most on-site unit piping, including hydrogen and fuel gas. Class 3 covers flammable services that do not significantly vaporise and many off-site lines. Later editions added Class 4 for low-consequence services.
• Intervals. Thickness measurement is due at the shorter of half the remaining life or the class maximum in the code's table. Industry summaries of current editions give five years for Class 1 thickness and external visual, ten and five years for Class 2, and ten and ten for Class 3, with Class 4 at the owner's discretion; the 1998 second edition used the same Class 1 to 3 values and a three-year thickness maximum for injection points. Confirm current-edition values with your AI before dates are set.
• CMLs and special locations. CMLs are concentrated where API RP 571 damage mechanisms and plant history predict loss: injection and mix points, deadlegs, small-bore connections, CUI-prone insulated lines and soil-to-air interfaces.
• Rates and remaining life. Long-term and short-term corrosion rates come from CML history; the owner and AI normally govern on the higher rate.
• Repairs and rerating. The inspector authorises repairs before work starts, a repair organisation performs them, and the piping engineer is involved in alterations and rerates.

Atlantis can calculate corrosion rates and remaining life from its own thickness data for the AI's review; the interval decision is the AI's and the owner's under the code and Washington rules. Background reading: API 570 code requirements, what triggers an internal piping inspection and API 510 vs API 570.

Marine air, wet insulation and seismic loads: the Washington damage picture

Direct answer: Washington piping programmes are dominated by external damage as much as internal: CUI on insulated and traced lines kept damp by marine weather, atmospheric and splash-zone corrosion on dock lines, soil-side corrosion on tideflat ground, plus the usual refinery internal mechanisms. Seismic flexibility of piping at tanks and docks is now a regulatory topic too.

CUI in a wet climate. Western Washington's long rainy season keeps water in damaged insulation for months. Carbon steel lines operating in the temperature band where CUI is active, intermittently hot lines and lines with failed heat tracing deserve priority. The 1998 edition of API 570 gave target percentages for follow-up NDE at damaged and suspect insulation by class; the current edition and API RP 583 should be checked for the values and approach your AI applies. We supply the follow-up examinations the plan calls for, typically profile radiography, UT at strip-out windows and screening where the AI accepts it.

Dock and trestle piping. Pipe supports, clamps and saddles trap moisture and salt, and coating breaks where pipe meets steel. Visual examination with lifting or UT at support points, combined with corrosion mapping on suspect areas, gives the AI quantitative data rather than photographs of rust.

Refinery internal mechanisms. Puget Sound refineries process Alaska North Slope, Canadian and imported crudes, and their API 571 lists commonly include sulfidation in hot circuits, ammonium bisulfide and chloride corrosion in hydroprocessing effluent piping, wet H2S damage in sour water and amine service, and erosion in slurry and coker lines. Injection points for wash water and inhibitors need dense grids, not single spot readings.

Seismic and settlement. Ecology now requires seismic protection measures for tanks and transfer pipelines at large oil-handling facilities. NDE does not answer a seismic question by itself, but outages that open piping for internal inspection are the natural time to examine supports, flexible connections and nozzle welds where movement would concentrate strain.

NDE methods for API 570 work in Washington

Direct answer: UT thickness at CMLs carries the programme; corrosion mapping covers injection points and support contact areas; profile RT covers insulated small-bore and deadlegs; guided-wave screening covers dock and road-crossing runs; PAUT or TOFD examines welds; and MT, PT and VT finish the external picture.

Washington is an NRC Agreement State, and the Department of Health's Office of Radiation Protection licenses industrial radiography. RT on Washington sites is performed only by crews licensed for that work in Washington; we confirm licensing and exclusion-zone arrangements during scoping. Method choice follows the damage mechanisms in the circuit, as described in our API 571 damage mechanisms guide.

How Atlantis supports your Authorized Inspector

Direct answer: We deliver the NDE part of the AI's inspection plan: Level III-reviewed procedures, examinations by ASNT SNT-TC-1A certified technicians, readings checked against history before demobilising, and a digital report organised by circuit and CML. We are not an Authorized Inspection Agency and we do not supply API-certified inspectors.

1. Scope from the plan. Circuits, isometrics, CML locations, damage mechanisms, methods and coverage come from the AI's plan, including any circuits the owner's damage mechanism review has added or changed.
2. Procedures. An ASNT NDT Level III prepares or reviews each technique against the owner's specification, including high-temperature UT limits, profile RT technique for insulated lines and wet-weather surface preparation.
3. Fieldwork. Crews are mobilised to your site; the schedule is agreed during scoping around permits, unit status and weather.
4. Data QA. Readings are compared with the previous survey before the crew leaves; unexpected loss, inaccessible CMLs and mismatched IDs are re-shot or flagged.
5. Report. CML readings, C-scans, radiographs, guided-wave results with follow-up, calibration records and technician certifications, delivered in our digital reporting platform.
6. AI evaluation and sign-off. The AI reviews rates, remaining life and next dates, decides on repairs and signs.
7. Next interval. The same CML identifiers and reading patterns carry forward so the next survey compares like with like.

Keeping NDE separate from evaluation is useful in Washington, where both Ecology and L&I may ask how a piping decision was reached: the AI holds independent, traceable data and owns the judgement. Risk-based inspection and fitness-for-service assessments are performed by the owner's engineers or a specialist using our data; Atlantis does not offer them. More on our scope: API 570 piping NDE support and piping circuit and CML inspection.

Washington regulations that sit on top of API 570

Direct answer: Three layers apply. L&I enforces process safety management under chapter 296-67 WAC, with a refinery-specific Part B effective December 2024. Ecology's facility oil-handling rules require transfer pipelines to be inspected to API 570. The Utilities and Transportation Commission (UTC) and PHMSA regulate pipelines beyond the plant. Confirm current requirements with each agency.

L&I process safety management, including refinery Part B

Washington runs its own occupational safety State Plan, so PSM at refineries and chemical plants is enforced by L&I under chapter 296-67 WAC rather than federal OSHA. Its mechanical-integrity element mirrors 29 CFR 1910.119(j): written procedures, inspection and testing of piping systems following recognised and generally accepted good engineering practice, documented results and correction of deficiencies. For most owners, API 570 is that practice. In December 2023 L&I adopted Part B of the chapter for petroleum refineries, effective 27 December 2024. Part B adds requirements such as damage mechanism reviews for each process, a hierarchy of hazard controls analysis, root cause analysis and process safety culture assessment, with phased completion deadlines; published summaries describe half of the damage mechanism reviews being due within three years and all within five. Confirm the dates and content with L&I. For piping, a damage mechanism review typically changes which mechanisms each circuit is screened for, which in turn changes CML placement, methods and coverage. NDE data from previous surveys is one of the inputs those reviews rely on, and new NDE is often how their conclusions are verified.

Ecology: transfer pipelines under chapter 173-180 WAC

At the large oil-handling facilities Ecology classifies as Class 1 facilities, chapter 173-180 WAC distinguishes process piping, meaning piping within refining units, unit-to-tank and tank-to-tank piping, from transfer pipelines, which move oil to or from a tank vessel or a transmission pipeline. WAC 173-180-340 requires transfer pipelines to be inspected in accordance with API 570, citing the 2016 edition with its 2017 and 2018 addenda, or another standard Ecology approves. The rule also addresses bare buried pipelines, for which it sets thickness and corrosion-rate assessment at the more frequent of half the remaining life or five years, plus cathodic protection on coated buried lines, pipeline maps, leak detection and, since the 2023 amendments, seismic protection measures for existing transfer pipelines by a deadline tied to the next scheduled internal API 570 inspection. Because the rule names an older edition, facilities usually write procedures that satisfy both that edition and current practice; Ecology decides how its reference is applied. Dock lines are the obvious example: on a refinery pier the same steel may be a transfer pipeline to Ecology, plant piping to L&I and outside PHMSA's pipeline rules, all at once.

UTC pipeline safety, PHMSA and the plant fence

The UTC's pipeline safety programme inspects intrastate natural gas and hazardous-liquid pipelines and acts as PHMSA's interstate agent in Washington, with enforcement on interstate systems referred to PHMSA. The state's 2000 Pipeline Safety Act followed the 1999 Olympic Pipeline rupture in Bellingham, and Washington has kept an active programme since. The federal hazardous-liquid rule (49 CFR Part 195) excludes in-plant piping at refineries and certain terminal transfer piping, so piping inside the fence stays under API 570 and PSM while the regulated pipeline follows Part 195, and gas lines follow Part 192. LNG facilities such as the Tacoma plant are subject to the federal LNG rule (49 CFR Part 193) for the regulated portions. Launchers, receivers, meter stations and first block valves are where the operator should document the boundary. Pipeline-side NDE is covered on our pipeline inspection page.

Boilers, pressure vessels and storage tanks

L&I's boiler programme covers boilers and unfired pressure vessels, not process piping, and Ecology's facility rule requires storage tanks to be inspected to API 653. Neither sets API 570 intervals, but vessel and tank outages usually share windows and scaffolding with piping work, so plan them together. See the companion hubs for API 510 pressure vessel inspection in Washington and API 653 tank inspection in Washington.

Planning around turnarounds, rain and fish windows

Direct answer: Schedule insulation stripping and external CUI work for the drier months from late spring to early autumn, run on-stream CML and mapping surveys year-round, book turnaround NDE early because the Puget Sound refineries draw on a limited regional pool, and coordinate dock work with marine traffic and in-water work windows.

• Summer dry season: insulation removal, recoating and CUI follow-up, because open insulation in November rain creates new CUI. This is also when most dock trestle access is planned.
• Year-round on-stream work: CML thickness surveys, injection-point mapping, guided-wave screening and profile RT on hot or insulated lines.
• Pre-turnaround: on-stream UT and mapping so replacement spools and repair procedures are ready before the outage.
• Turnaround: PAUT or TOFD on repair and tie-in welds, profile RT on small-bore, internal visual where lines are open, baselines on new piping, and support and flexible-connection checks tied to seismic work.
• After events: walkdowns after windstorms, flooding on the tideflats or a felt earthquake, with targeted NDE where the AI asks for it.

Work over or beside water may involve marine permits and in-water timing restrictions set by state and federal agencies; the owner's environmental team usually knows these windows well before inspection planning starts.

API 570 piping inspection support across Washington

Direct answer: Atlantis supports API 570 programmes from Blaine to Vancouver and east to Spokane. Crews are mobilised to your site and the schedule is agreed during scoping; the Seattle pages below give more detail on regional services.

• Seattle, Everett and central Puget Sound: piping inspection in Seattle, corrosion inspection in Seattle and pipeline inspection in Seattle.
• Related equipment on the same sites: pressure vessel inspection in Seattle and tank inspection in Seattle.
• Cherry Point, Ferndale and Anacortes: refinery unit, dock and transfer-pipeline work; send the site address and orientation requirements with the circuit list.
• Tacoma tideflats: refinery, terminal, chemical and LNG-site piping on reclaimed ground.
• Vancouver, Longview and the lower Columbia: terminal and pulp and paper piping.
• Spokane and the Tri-Cities: terminals, ammonia refrigeration and agricultural chemical piping.

Statewide services are on NDT inspection services in Washington; Level III procedure work is on NDT consulting in Washington; and for technician skills see ASNT NDT training in Washington.

Keeping piping history usable

Direct answer: A corrosion rate is only as reliable as the readings behind it. We keep your circuit and CML numbering, record the reading pattern, instrument and calibration for each CML, and deliver data that loads into your inspection database, with optional digital twin and ERP views.

Washington refineries have changed owners and names several times, and their inspection databases often hold readings from several contractors. When a reading pattern or location differs from history, we flag it rather than let it produce a misleading rate. New CMLs added after a damage mechanism review are photographed and described so the next crew finds the same spot. Results can be viewed in a digital twin of the unit or dock, and certificates, calibrations and work orders can be tracked in our inspection-management ERP. Sample layouts are on NDT report templates, and construction-code background is in ASME B31.3 explained.

What to send us for a Washington quote

Direct answer: Send the circuit list and isometrics, the last API 570 report, the AI's plan, insulation and access details, whether any lines are Ecology transfer pipelines, and your dates. We reply with questions or a scope, and a quote within 24 hours of having what we need.

1. Circuit list with service class, material, size, schedule, temperature and pressure.
2. Isometrics with CMLs, injection points, deadlegs, small-bore connections and insulated or traced sections marked.
3. The last API 570 report and thickness history, or confirmation that this is a baseline.
4. The AI's plan and damage mechanisms of concern, including any outputs of a Part B damage mechanism review.
5. Which lines are transfer pipelines under chapter 173-180 WAC, and which are dock or over-water lines.
6. Access, scaffolding, insulation, permits and dates.

Send us your circuit list and we will scope the NDE against your AI's plan.

Frequently asked questions: API 570 in Washington

Who performs API 570 piping inspection in Washington?

The owner's API 570 Authorized Piping Inspector, employed by the owner or an inspection agency, directs the inspection, evaluates results and signs. Qualified examiners take the measurements. Atlantis performs that NDE and delivers documented results to your AI, who remains inspector of record.

Does Washington law require API 570?

In part. Ecology's rule requires transfer pipelines at Class 1 oil-handling facilities to be inspected to API 570 (2016 edition with addenda) or an approved alternative. Elsewhere, L&I's PSM rule requires recognised good engineering practice, which is usually API 570. Confirm obligations with Ecology and L&I.

What is a damage mechanism review under Washington's refinery PSM rule?

Part B of chapter 296-67 WAC requires refineries to review, process by process, which damage mechanisms can affect equipment, including piping, on a phased schedule. The results often change CMLs, methods and coverage in the API 570 plan. Atlantis supplies NDE data, not the review itself.

How often does refinery piping need inspection under API 570?

Thickness at the shorter of half the remaining life or the class maximum, and external visual by class, unless a qualifying RBI programme sets the interval. The 1998 edition gave five years for Class 1 thickness; confirm current-edition values with your AI.

Is dock piping a pipeline or plant piping?

It can be both. Ecology treats lines moving oil to or from a vessel as transfer pipelines inspected to API 570, while PHMSA's rules generally exclude in-plant and terminal transfer piping. The operator documents where each boundary sits.

Who regulates pipelines in Washington?

The UTC inspects intrastate gas and hazardous-liquid pipelines and acts as PHMSA's interstate agent; PHMSA enforces on interstate systems. Plant piping stays under API 570 and PSM.

How do you handle CUI in western Washington's wet climate?

Following the AI's plan, we perform profile RT, UT at inspection windows and screening on insulated lines in the susceptible temperature range, and we recommend stripping work in drier months so new damage is not created.

Is Atlantis an Authorized Inspector?

No. We are not an Authorized Inspection Agency and we do not supply API-certified inspectors. That keeps the NDE independent of the evaluation, which is what your AI and the regulators expect.

Who licenses industrial radiography in Washington?

The Department of Health's Office of Radiation Protection, under Washington's NRC Agreement State programme. RT on Washington sites is performed only by crews licensed in Washington.

What certifications do your technicians hold?

ASNT SNT-TC-1A certification under our written practice, with ASNT NDT Level III oversight. Certificates and calibration records come with every report.

Do you provide RBI, fitness-for-service or API 570 training?

No. RBI and FFS are performed by the owner's engineers or specialists using our data, and we train only to ASNT SNT-TC-1A. For the API route see the API inspector career guide; for NDE skills, ASNT Level III training.

How quickly can you mobilise to Anacortes or Tacoma?

We quote within 24 hours of receiving the scope information; mobilisation is agreed during scoping around permits, unit schedules and weather.

Next step

For CMLs coming due, a transfer-pipeline survey, CUI follow-up or turnaround NDE, get a quote within 24 hours or book a scoping call. Atlantis performs the NDE; your API 570 Authorized Inspector remains inspector of record and signs the inspection report.

More Atlantis NDT services in Washington

• NDT training and certification in Washington
• Level III consulting in Washington
• NDT inspection services in Washington
• API 653 storage tank inspection support in Washington
• API 510 pressure vessel inspection support in Washington
• Practical NDT simulator in Washington

Part of the wider piping circuit inspection service at Atlantis NDT.