API 570 Piping Inspection Support in Texas

Short answer: API 570 inspection of in-service process piping in Texas is planned, evaluated and signed by the owner's API 570 Authorized Inspector (AI). The work behind it is mostly nondestructive examination: ultrasonic thickness readings at condition monitoring locations (CMLs), profile radiography of small-bore lines and insulated spots, guided-wave screening of long runs, and phased array or TOFD on welds of concern. Atlantis NDT performs that NDE. Atlantis performs the NDE; your API 570 Authorized Inspector remains inspector of record and signs the inspection report.

Texas holds more miles of refinery, petrochemical and gas-processing piping than any other state, and the piping is where most leaks start. Vessels and tanks get the headlines, but a refinery unit typically has far more piping circuits than vessels, and each circuit carries dozens of CMLs, injection points, deadlegs and small-bore connections that need data at every interval. This hub explains where that piping sits in Texas, how API 570 organises it, which NDE methods fit Texas service conditions, which regulators draw lines around it, and how Atlantis feeds clean, code-traceable data to your AI. If you already have a circuit list, request an NDE scope for your AI's plan.

Where API 570 piping is in Texas

Direct answer: Texas API 570 piping is concentrated in five belts: the Houston Ship Channel and Galveston Bay, the Beaumont-Port Arthur Golden Triangle, Corpus Christi and the Coastal Bend, the Freeport-Brazosport chemical complex, and the gas-processing plants of the Permian Basin and Eagle Ford. Each belt has its own damage mechanisms, so each needs a different inspection mix.

Houston Ship Channel, Pasadena, Deer Park, Baytown and Texas City

The Ship Channel is a continuous band of refineries, olefins crackers, polymer plants and specialty chemical units stretching from Pasadena through Deer Park and La Porte to Baytown, with ExxonMobil Baytown, the Deer Park refinery and the Texas City refineries as anchors. Process piping here spans everything API 570 covers: crude overhead lines with ammonium chloride and HCl dewpoint corrosion, hydroprocessing effluent lines with ammonium bisulfide, sour water and amine piping, alkylation unit acid lines, hydrogen and fuel-gas headers, and flare headers that run for miles. Interconnecting pipe racks between plants, product transfer lines to the terminals, and the NGL fractionation and storage hub at Mont Belvieu add long, insulated runs where corrosion under insulation (CUI) is the dominant threat.

Beaumont, Port Arthur and Orange

The Golden Triangle carries some of the largest refining capacity in the country, including the Motiva Port Arthur and ExxonMobil Beaumont refineries, Valero and TotalEnergies at Port Arthur, chemical plants along the Neches River and Sabine-Neches Waterway, and LNG export capacity at Golden Pass and the Port Arthur LNG project. Coker units bring erosion-corrosion in transfer lines and thermal-cycling concerns, sulfur recovery brings sulfidation and wet H2S, and LNG plants bring stainless and low-temperature carbon steel piping where chloride stress corrosion cracking under insulation and cold-service CUI change the inspection plan.

Corpus Christi, Ingleside and the Coastal Bend

Corpus Christi combines refining (Flint Hills Resources, Valero and Citgo), the Cheniere Corpus Christi LNG terminal, crude export docks at the port and Ingleside, and pipelines bringing Permian crude to the coast. Salt-laden air and high humidity make external corrosion at pipe supports and CUI at damaged jacketing a standing item, and long dock and terminal headers mean inspection teams spend as much time on the transition from plant piping to marine transfer lines as on the units themselves.

Freeport, Brazosport, Chocolate Bayou and Victoria

The Freeport complex, Freeport LNG, and chemical plants around Chocolate Bayou, Point Comfort and Victoria run chlor-alkali, ethylene, propylene oxide, polymer and specialty chemical piping. Caustic and chloride services push the method mix toward crack detection: PT and PAUT on stainless welds, and attention to caustic stress corrosion cracking at hot spots and steam-traced lines.

Permian Basin, Eagle Ford and East Texas gas processing

Around Midland, Odessa, Pecos, Reeves County and across the Eagle Ford, cryogenic gas plants, amine treaters, compressor stations and NGL handling facilities form a widely spread piping population. Sour gas, CO2 and produced water drive wet H2S cracking, CO2 corrosion and under-deposit attack in low-flow sections. Many operators here run API 570 programmes with a small inspection team covering several plants, which is exactly where packaged circuit data from an outside NDE contractor saves the AI time. Inland chemical and manufacturing sites around Dallas-Fort Worth add smaller, mixed piping populations under the same code.

What API 570 requires, in plain terms

Direct answer: API 570 is the in-service inspection, repair, alteration and rerating code for metallic piping and its pressure-relief devices. The owner groups piping into circuits, classifies each by leak consequence, places CMLs where damage is expected, and inspects at intervals set by service class and remaining life. The AI authorises repairs and signs the results.

The current edition is API 570, fifth edition, published by the American Petroleum Institute in February 2024, with API RP 574 (inspection practices for piping components) reissued alongside it. API describes the fifth edition as adding an Inspection Supervisor role, strengthening pressure-relief device requirements and setting rules for deferring inspection repair recommendations. API 570 is copyrighted; your programme should work from a licensed copy (see api.org), and older editions circulating online are not current. What follows is a plain-language summary, not code text.

• Circuits. Piping is grouped into circuits of similar material, process conditions and expected damage, so one set of findings can be applied across the circuit.
• Service classes. Each system is classed by the potential safety and environmental consequence of a leak. The highest class covers services where a leak could cause an immediate emergency, such as flammable services that can auto-refrigerate and cause brittle fracture, rapidly vaporising light hydrocarbons, high-H2S gas, hydrofluoric acid and piping over public roads or water. The middle class covers most unit process piping (hydrocarbons that vaporise slowly, hydrogen, fuel gas, natural gas). The lower class covers services that do not vaporise significantly, such as distillate and product lines to storage. Later editions added a fourth class with inspection at the owner's discretion.
• CMLs. CMLs are placed where the damage mechanisms identified for the circuit (with API RP 571 and RP 574) are expected to act. More CMLs go where leak consequence is high, corrosion is high or variable, localised corrosion is possible, or the geometry is complex (deadlegs, injection points, mixing points, CUI-prone areas, soil-to-air interfaces, spec breaks). Fewer go on long, straight, non-corrosive runs.
• Intervals. Thickness measurement intervals are set at the shorter of half the remaining life (calculated from the corrosion rate) or the maximum the code's interval table gives for that class, and external visual inspections are set by class. An owner may instead set intervals with a documented risk-based inspection (RBI) programme meeting the code's conditions.
• Special cases. Injection points, deadlegs, small-bore and auxiliary piping, CUI, soil-to-air interfaces and buried piping each have their own inspection guidance.
• Repairs and rerating. Repairs and alterations are authorised by the inspector before work starts and carried out by a repair organisation; alterations and rerates also involve the piping engineer. New-construction requirements come from ASME B31.3, which API 570 does not replace.

Because the numbers matter and are copyrighted, here they are with their source edition stated plainly. The second edition (1998), which is publicly filed with the US Nuclear Regulatory Commission and is not the current edition, set these maximum intervals:

Industry summaries report the same class structure in recent editions, with the added Class 4 left to the owner. Confirm every figure against the fifth edition before you set an interval; the interval decision belongs to the AI and the owner under the code and jurisdiction, never to the NDE contractor. Corrosion rates come from CML readings: a long-term rate from the baseline and a short-term rate from the last two readings, with the governing rate used for remaining life. Atlantis can calculate those figures from its thickness data for the AI's review. For what forces a closer look at a circuit, see what triggers an internal inspection under API 570, and for the code overview, API 570 piping inspection code requirements.

NDE methods for API 570 work in Texas

Direct answer: UT thickness at CMLs is the backbone of every Texas piping programme. Profile RT covers small-bore piping and insulated spots, guided-wave testing screens long runs and road crossings, automated corrosion mapping covers injection points and elbows, and PAUT or TOFD handles welds. Method choice follows the circuit's damage mechanisms.

Two Texas-specific notes. First, high-temperature lines are common, so we plan high-temperature couplants, delay-line probes and temperature correction during scoping rather than discovering the problem on the rack. Second, radiography in Texas is performed by crews licensed for industrial radiography through the Texas Department of State Health Services radiation control programme (Texas is an NRC Agreement State), and RT scope is planned around exclusion zones and unit operations. Guided wave is screening only: it tells the AI where to look, and quantitative UT or RT then measures what is there. Damage mechanisms are explained in our API 571 damage mechanisms guide.

Injection points, deadlegs, small-bore piping and CUI on the Gulf Coast

Direct answer: On Texas refinery and chemical units, most unexpected piping failures come from four places: injection points, deadlegs, small-bore connections and corrosion under insulation. API 570 gives each its own guidance, and each needs a different NDE approach, so we scope them as separate items rather than as extra CMLs.

Injection points. Wash water in crude overheads, ammonium polysulfide and wash water in hydroprocessing effluent, caustic and corrosion-inhibitor injections are all injection points in API 570's sense. The fourth edition (2016) recommended treating each as its own circuit, starting upstream at the greater of 12 inches or three pipe diameters and extending downstream to the lesser of the second change in flow direction or 25 feet beyond the first change, with CMLs at the expected impingement point; confirm the current wording in the fifth edition. We cover those circuits with grid UT or automated corrosion mapping rather than spot readings, because localised attack between spots is the usual failure.

Deadlegs. Blanked branches, bypasses around control valves, spare pump piping, level bridles, relief-valve headers, vents and drains collect water, solids and corrosive salts. The code advises tracking potentially corrosive deadlegs as separate circuits and checking horizontal ones in all four quadrants. Small deadlegs suit profile RT; larger ones suit scanning UT. Texas freeze events, including February 2021, are a reminder that water-filled deadlegs and instrument connections can also split from freezing.

Small-bore and auxiliary piping. Connections of NPS 2 and below, socket welds and threaded fittings near compressors and pumps fail from vibration fatigue as often as from corrosion. Radiography is the code's preferred method for insulated small-bore piping and threaded connections; we add VT of bracing and PT on socket welds where the AI asks.

CUI. Insulated carbon and low-alloy steel operating in the temperature range where CUI is active, plus cyclic and dual-temperature service, is the biggest external threat on the humid coast. The code requires an external visual check for CUI on susceptible systems, then follow-up NDE or insulation removal targeted by class. We support that with profile RT, UT at inspection ports, guided-wave screening where geometry allows, and UT prove-up after stripping.

How Atlantis supports your Authorized Inspector

Direct answer: We take the circuits, CMLs and methods from the AI's inspection plan, prepare procedures under ASNT Level III oversight, examine with ASNT SNT-TC-1A certified technicians, QA the data against history, and deliver a digital report organised by circuit and CML. The AI evaluates and signs. We are not an Authorized Inspection Agency and we do not supply API-certified inspectors.

Plenty of firms on the Gulf Coast sell the AI and the crew as one package. Atlantis deliberately sells only the NDE behind the inspection. Your AI, whether employed by the owner, an owner-user inspection organisation or a third-party agency you already use, receives independent data with procedures and certifications on file, and keeps full control of evaluation. The workflow is the same for a hundred circuits in a Pasadena turnaround or one compressor station in Pecos:

1. Scope from the plan. Circuit list, isometrics with CML locations, inspection type and damage mechanisms come from the AI. We confirm how, not what.
2. Procedures. UT thickness, corrosion mapping, profile RT, guided-wave, PAUT and TOFD techniques are written or reviewed by an ASNT NDT Level III against the owner's specification.
3. Examinations. Crews mobilise to your site; the schedule is agreed during scoping around permits, unit status and access.
4. Data QA. Readings are compared with the previous interval before we leave; apparent thickness growth, sudden rate jumps and missing CMLs are flagged for re-shoot.
5. Digital report. Circuit and CML IDs that match your database, readings, C-scan maps, RT images, guided-wave screening results with follow-up, calibration and instrument records and technician certifications, in Atlantis's digital reporting platform.
6. AI evaluation and sign-off. The AI reviews the data, sets corrosion rates, remaining life and next inspection dates, and signs.
7. Reuse. The same circuit and CML structure is reused at the next interval so rates are like-for-like.

Where the owner's engineers run an RBI programme or need a fitness-for-service assessment on a thinned line, our thickness maps and flaw sizing feed those studies; the assessments are performed by the owner's engineers or a specialist, not by Atlantis. See API 570 piping NDE support and piping circuit and CML inspection for detail.

Texas regulations that sit on top of API 570

Direct answer: Texas has no state law that sets process-piping inspection intervals. The controlling requirement is federal: OSHA Process Safety Management, 29 CFR 1910.119(j), with API 570 as the RAGAGEP most owners adopt. At the plant fence, the Railroad Commission of Texas and PHMSA take over for regulated pipelines, so knowing the boundary matters.

OSHA PSM 1910.119(j). The mechanical integrity element explicitly covers piping systems, including valves, relief and vent systems. It requires written procedures, inspection and testing that follow recognised and generally accepted good engineering practice (RAGAGEP), frequencies consistent with manufacturers' recommendations and good engineering practice and more frequent where operating experience warrants, documentation of each inspection (date, who performed it, equipment identifier, description and results), and correction of deficiencies. OSHA's 2015 RAGAGEP memorandum treats the "shall" provisions of an adopted code as mandatory and expects departures from "should" provisions to be documented. Texas has no state OSHA plan for private employers, so federal OSHA enforces directly. EPA's Risk Management Program, 40 CFR Part 68, mirrors the mechanical integrity element for Program 3 processes.

Railroad Commission of Texas and PHMSA. The Railroad Commission's pipeline safety programme acts for PHMSA on intrastate gas and hazardous-liquid pipelines, including regulated gathering lines in the Permian and Eagle Ford, under 49 CFR Parts 192 and 195 and the Commission's own rules. Part 195 excludes in-plant piping at refining, manufacturing and storage facilities, and certain transfer piping on terminal grounds, so the same pipe rack can contain API 570 piping on one side of a valve and DOT-regulated pipeline on the other. We work to the operator's documented boundary and keep the two datasets separate. For pipeline-side work, see pipeline inspection services.

Sour gas facilities. Permian and East Texas operators handling hydrogen sulfide also work under the Railroad Commission's H2S safety rule (Statewide Rule 36), which drives contingency planning and materials selection; it does not set API 570 intervals, but it does shape access permits and the PPE our crews arrive with. Confirm current requirements with the Commission.

TDLR and TCEQ. The Texas Department of Licensing and Regulation's boiler programme covers boilers, not process piping. TCEQ air permits and leak detection and repair (LDAR) programmes influence when lines can be opened and how leaks are reported but do not set inspection intervals. Insurers frequently ask for evidence of API 570 compliance during engineering surveys.

Planning around turnarounds, hurricanes and heat

Direct answer: Most API 570 thickness work can be done on-stream, so the best Texas programmes finish CML surveys, corrosion mapping and guided-wave screening months before a turnaround and use the outage only for what needs the line open or cold. Hurricane season and summer heat shape the field calendar.

• Six to twelve months out: on-stream UT at CMLs due in the next window, corrosion mapping of injection points, guided-wave screening of racks and crossings, so replacement spools can be ordered.
• Pre-turnaround: PAUT or TOFD on welds of concern and profile RT on small-bore and deadlegs, so repair procedures are approved before the unit comes down.
• Turnaround: insulation stripping and UT prove-up of CUI findings, examination of repair and replacement welds, and baseline readings on new spools.
• After start-up: first readings on new or changed-service piping, which older editions required within a few months of service where no rate data existed; check the current edition.

Coastal sites schedule around the June-to-November hurricane season, including post-storm external inspections of flooded racks, insulation and supports. Permian sites contend with distance and summer surface temperatures, which favour combining several plants per mobilisation and planning high-temperature UT in advance.

API 570 piping inspection support across Texas

Direct answer: Atlantis supports API 570 programmes across Texas, with city pages for Houston, Beaumont, Corpus Christi and Dallas and support in the Permian. Crews are mobilised to your site; the schedule is agreed during scoping.

• Houston and the Ship Channel: piping inspection in Houston, pipeline inspection in Houston and third-party inspection, with refining towns Deer Park, Baytown and Galveston.
• Beaumont and Port Arthur: piping inspection in Beaumont, corrosion inspection and third-party inspection.
• Corpus Christi and the Coastal Bend: piping inspection in Corpus Christi, corrosion inspection, weld inspection and third-party inspection.
• Dallas-Fort Worth: piping inspection in Dallas, pipeline inspection in Dallas and Fort Worth third-party inspection.
• Permian Basin and Central Texas: gas-plant and compressor-station piping around Midland, and Austin.

The same Texas sites carry vessels and tanks too: see API 510 pressure vessel inspection in Texas and API 653 tank inspection in Texas, or the full method range at NDT inspection services in Texas. For teams building in-house NDE skills, see ASNT NDT training in Texas.

Piping data that survives the next interval

Direct answer: API 570 runs on trends, so CML naming and data structure matter as much as the readings. We keep your circuit and CML numbering, record instrument, probe and calibration per reading, and deliver data that drops straight into your inspection database, with an optional digital twin.

Texas plants often hold piping history from several contractors, with renumbered CMLs, isometrics that no longer match the field, and readings taken at different points within the same examination circle. That is where false corrosion rates come from. We record the minimum reading and the reading pattern used at each CML, flag locations we could not reach and why, and note insulation, temperature and surface condition. Results can be linked to a digital twin of the unit so the AI sees circuits in 3D, and teams that manage certificates, calibration and work orders can use our inspection-management ERP. Formats are shown on NDT report templates; for how API 570 sits beside construction rules, see ASME B31.3 explained and API 510 vs API 570.

What to send us for a Texas quote

Direct answer: Send the circuit list and isometrics with CMLs, the last API 570 report and thickness history, the AI's plan, access and temperature details, and dates. We reply with questions or a scope, and a quote within 24 hours once we have what we need.

1. Circuit list with line numbers, service class, material, size and schedule, and design and operating conditions.
2. Isometrics showing CMLs, injection points, deadlegs and small-bore connections.
3. The most recent API 570 report and thickness history by CML.
4. The AI's inspection plan and the damage mechanisms of concern (CUI, wet H2S, ammonium salts, caustic, erosion, vibration).
5. Access: rack heights, scaffolding or rope access, insulation removal, surface temperatures.
6. Dates, turnaround windows and site requirements (TWIC for port facilities, site orientation, H2S training).

Send us your circuit list and we will come back with questions or a scope.

Frequently asked questions: API 570 in Texas

Who can perform an API 570 piping inspection in Texas?

An API 570 Authorized Piping Inspector directs and signs the inspection, usually employed by the owner-user, an owner-user inspection organisation or an inspection agency. The NDE within it is performed by qualified examiners certified under their employer's written practice. Atlantis performs that NDE and hands the results to your AI; we do not act as the inspector of record.

Does Texas law require API 570 piping inspections?

Not through a state piping statute. For processes covered by OSHA PSM, 29 CFR 1910.119(j) requires piping inspection following RAGAGEP, and API 570 is the practice most owners adopt. DOT-regulated pipelines beyond the plant boundary follow 49 CFR 192 or 195 under the Railroad Commission and PHMSA instead.

How often does process piping need inspection under API 570?

Thickness intervals are the shorter of half the remaining life or the class maximum in the code's table, and external visual inspections are set by class. The 1998 edition gave five years for Class 1 thickness and ten for Classes 2 and 3; confirm the current fifth-edition table. An RBI programme can set different intervals.

What NDE methods are used for API 570 inspections?

UT thickness at CMLs, automated corrosion mapping, profile radiography, guided-wave screening with UT follow-up, PAUT and TOFD on welds, MT, PT and VT. The circuit's damage mechanisms decide the mix.

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: your AI receives procedure-controlled data with certifications attached and makes every evaluation decision.

Can you inspect piping while the unit is running?

Yes. CML thickness surveys, corrosion mapping, guided-wave screening, profile RT and external VT are normally done on-stream. Hot lines need high-temperature probes and couplant, which we plan during scoping.

Where is the boundary between API 570 piping and a PHMSA pipeline in Texas?

49 CFR Part 195 excludes in-plant piping at refining, manufacturing and storage facilities and certain terminal transfer piping, so those stay under API 570 and PSM. Regulated pipelines are inspected under federal and Railroad Commission rules. The operator documents the boundary; we follow it.

Can guided-wave testing replace CML thickness readings?

No. Guided-wave testing is a screening method: it flags areas of metal loss over long lengths, and quantitative UT or RT then measures them. It is valuable on racks, crossings and sleeved sections where direct access is hard.

What certifications do your NDE technicians hold?

Technicians are certified under an ASNT SNT-TC-1A written practice and work under ASNT NDT Level III oversight. Certificates and vision records are included with the report for your AI and PSM auditors.

Do you perform RBI or fitness-for-service assessments on piping?

No. We supply the thickness maps and flaw data those studies use. RBI (API 580/581) and fitness-for-service (API 579) assessments are performed by the owner's engineers or a specialist firm.

Do you offer API 570 certification training?

No. Atlantis trains NDT personnel to ASNT SNT-TC-1A only. For the API inspector route, see the API inspector career guide; for NDE skills, see ASNT Level III training.

How quickly can you mobilise to Houston, Beaumont, Corpus Christi or the Permian?

We quote within 24 hours once we have the scope information. The mobilisation date is agreed during scoping around your permits, unit status and turnaround schedule.

Next step

If CMLs are coming due or you want on-stream data before a turnaround, book a scoping call. For a full circuit package, get a quote within 24 hours. Atlantis performs the NDE; your API 570 Authorized Inspector remains inspector of record and signs the inspection report.

More Atlantis NDT services in Texas

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

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