Engineering Inspection

Why Inspection Programs Exist

Equipment failure in oil and gas operations does not typically announce itself. Corrosion, erosion, cracking, and fatigue accumulate over time at rates determined by fluid chemistry, operating pressure, temperature cycling, and original fabrication quality. By the time a failure becomes visible, the degradation has usually been progressing for months or years.

A structured engineering inspection program uses non-destructive testing methods and recognized industry standards to measure the actual condition of your pressure vessels, piping systems, and storage tanks at regular intervals. It produces quantitative data — measured wall thickness, corrosion rates, crack depth — that supports fitness-for-service determinations, remaining life calculations, and maintenance prioritization decisions based on engineering analysis rather than assumption.

For Texas operators, inspection programs also carry direct regulatory significance. OSHA's Process Safety Management (PSM) standard and EPA's Risk Management Program (RMP) both require mechanical integrity inspection programs for covered facilities. API inspection standards are widely referenced in permit conditions and insurance requirements. Operating without a documented inspection program is an exposure on multiple fronts.

API Inspection Standards

API 510 — Pressure Vessel Inspection

API 510 governs the in-service inspection, rating, repair, and alteration of pressure vessels. It defines inspection intervals based on corrosion rate data, prescribes the inspection methods appropriate for different damage mechanisms, and establishes the qualifications required for inspectors and the documentation that must be maintained. For upstream and midstream operators, covered vessels typically include separators, treaters, scrubbers, and process vessels operating above atmospheric pressure.

API 570 — Piping Inspection

API 570 covers the in-service inspection, rating, repair, and alteration of metallic piping systems. Piping is the most extensive and often the most neglected asset class on oilfield facilities — it spans large areas, contains a large number of components (flanges, elbows, tees, reducers), and is subject to both internal corrosion from process fluids and external corrosion from soil contact and atmospheric exposure. API 570 inspection programs identify thinning, cracking, and corrosion under insulation (CUI) before a line fails.

API 653 — Aboveground Storage Tank Inspection

API 653 governs the inspection, repair, alteration, and reconstruction of aboveground storage tanks built to API 650. Tank floor corrosion is the primary concern — floor plates corrode from both the stored product side and the soil side, and because the floor is inaccessible during normal operation, the degradation can advance to a through-wall condition before it is detected. API 653 inspection intervals and minimum acceptable thickness calculations give operators a defensible basis for determining when a tank floor needs repair or replacement.

Non-Destructive Testing Methods

Non-destructive testing (NDT) allows inspectors to measure the condition of equipment without removing it from service or cutting it open. The selection of NDT method depends on the equipment type, the damage mechanism being evaluated, and the access available. Common methods applied in oilfield inspection programs include:

• Ultrasonic Testing (UT): Measures wall thickness and detects internal flaws using high-frequency sound waves. The most widely used method for corrosion assessment on vessels, piping, and tanks. Automated scanning (PAUT, TOFD) provides higher resolution data for critical components.
• Magnetic Particle Testing (MT): Detects surface and near-surface cracks in ferromagnetic materials. Used on welds, nozzles, and areas where fatigue or stress corrosion cracking is a concern.
• Liquid Penetrant Testing (PT): Identifies surface-breaking cracks and porosity on non-magnetic components including stainless steel and alloy materials.
• Radiographic Testing (RT): Produces images of internal weld and component conditions. Used for weld quality assessment and detection of volumetric flaws.
• Visual Testing (VT): The baseline for all inspection programs — systematic visual examination of accessible surfaces, coatings, supports, and external conditions.

Risk-Based Inspection

Risk-based inspection (RBI), as defined in API 580 and 581, prioritizes inspection resources based on the consequence and likelihood of failure for each piece of equipment. Rather than inspecting everything on the same calendar-driven schedule, RBI directs more frequent and thorough inspection to equipment whose failure would have the greatest consequence — in terms of safety, environmental impact, and production loss — and to equipment where the probability of failure is elevated based on damage mechanism analysis.

For operators managing large equipment populations across multiple facilities, RBI produces inspection programs that are both more cost-effective and more protective than uniform-interval approaches. It also creates a documented, auditable rationale for inspection decisions that satisfies OSHA PSM and EPA RMP mechanical integrity documentation requirements.

Corrosion Monitoring Programs

Periodic inspection provides a snapshot of equipment condition at a point in time. Corrosion monitoring provides continuous or frequent-interval data that tracks how quickly degradation is progressing, giving operators real-time corrosion rate information to inform treatment chemical programs, inspection interval adjustments, and remaining life estimates.

Tektite designs and manages corrosion monitoring programs using corrosion coupons, electrical resistance probes, and ultrasonic monitoring points. Where appropriate, we integrate IIoT-enabled continuous monitoring sensors that transmit wall thickness data without requiring a technician to visit the location for each reading. Corrosion monitoring data feeds directly into the inspection program and supports ongoing fitness-for-service assessments.