News

We recently surveyed 847 pipeline professionals from across our membership on their perspectives on emerging coating technologies, regulatory trends, and industry challenges. The results provide a fascinating snapshot of where the pipeline coatings community stands — and where it is headed.

Top Findings

Polyurea adoption is accelerating. 73% of respondents report increased use of spray polyurea coatings in the past three years, with 81% expecting further increases in the next three years. Cost reduction (cited by 44%) and proven performance data (cited by 61%) are the top drivers of expanded polyurea adoption.

Digital tools are mainstream. 67% of respondents now use digital inspection data management platforms, up from 38% in our 2020 survey. Inline inspection data integration and AI-assisted defect analysis are the features most in demand from next-generation platform providers.

Workforce development is the top challenge. 78% of respondents identify attracting and retaining qualified coating applicators and inspectors as a significant or very significant challenge — up from 65% in 2020. This finding is driving significant investment in our applicator training program and mentorship initiatives.

Regional Variations

Respondents from the Gulf Coast and Permian Basin show the highest polyurea adoption rates, driven by aggressive soil conditions and robust contractor availability. Respondents from the Northeast and Pacific Northwest show the strongest emphasis on environmental compliance features in their coating specifications, reflecting local regulatory environments.

The full survey report is available to members in our resources library. Join today to access this and hundreds of other exclusive technical resources.

Coating thickness is one of the most fundamental parameters in any pipeline coating specification, yet it is also one of the most frequently debated. Too thin and the coating provides inadequate protection; too thick and costs increase without proportional performance benefit. Arriving at the right thickness specification requires understanding the relationship between film build, physical properties, and service environment.

Minimum Thickness Requirements by Service Environment

For buried onshore pipelines in moderate soil conditions, industry consensus supports minimum polyurea dry film thickness (DFT) of 40–60 mils (1.0–1.5 mm) for mainline sections. For aggressive soils, soil stress environments, or locations with mechanical damage risk, specifications of 80–125 mils (2.0–3.2 mm) are common. Rock ditch and directional drilling applications may specify 125–250 mils (3.2–6.4 mm) of polyurea or a hybrid polyurea/HDPE system.

The Relationship Between Thickness and Holiday Risk

Thinner coatings are more vulnerable to holiday formation during application and installation. Statistical analysis of holiday testing data across hundreds of projects shows that holiday frequency decreases exponentially as DFT increases above 20 mils — with 40-mil coatings showing approximately 80% fewer holidays per linear foot than 20-mil coatings applied under identical conditions.

Measurement and Verification

Dry film thickness is measured using magnetic pull-off gauges (Type 1) or electronic digital gauges (Type 2) per SSPC-PA 2. For thick-film polyurea applications, multiple gauge readings per pipe joint — typically five readings per joint with specific acceptance criteria for individual readings and averages — are required to ensure specification compliance. Download our DFT measurement procedure template to standardize thickness measurement across your projects.

The Fall Technical Conference is less than eight weeks away, and we’re excited to share the final agenda and speaker lineup for what promises to be the most technically substantive event in our organization’s history. This year’s conference theme — “Coatings at the Intersection of Technology and Regulation” — reflects the rapidly evolving landscape facing pipeline coating professionals.

Keynote Sessions

The conference opens with a keynote from Dr. James Harrington of Texas A&M’s Corrosion Engineering Division, presenting findings from a five-year longitudinal study of polyurea coating performance on natural gas gathering systems. His team’s data — covering 47 pipeline segments across seven geologic environments — provides the most comprehensive field-performance dataset on spray polyurea ever assembled.

Technical Session Tracks

This year’s conference features four parallel technical tracks: Advanced Coating Materials, Pipeline Integrity and Inspection, Regulatory Compliance, and Applicator Techniques and Equipment. With 36 technical presentations across three days, attendees can customize their schedule to focus on their area of practice or pursue a broad overview of the industry.

Vendor Exhibition

The exhibition hall will feature 68 exhibiting companies including coating manufacturers, equipment suppliers, inspection technology firms, and engineering consultants. Live equipment demonstrations will be staged in the exhibition hall’s outdoor demonstration area, including a live polyurea spray demonstration on a DN400 pipe mock-up.

Register now — early bird pricing ends in two weeks. Members receive a 20% registration discount. Join today to access member pricing.

The Permian Basin continues to be the epicenter of North American oil production growth, driving a multi-billion dollar wave of pipeline infrastructure investment that is creating significant demand for pipeline coating services across Texas and New Mexico. Understanding the coating requirements specific to Permian Basin conditions is essential for operators and contractors active in the region.

Permian Basin Soil Conditions and Coating Selection

Permian Basin soils present a challenging corrosion environment characterized by high chloride content, variable pH from alkaline carbonates to acidic gypsiferous soils, and elevated soil resistivities in arid surface layers contrasted by highly conductive briny subsurface formations. These conditions strongly favor high-build polyurea coatings with excellent dielectric strength and resistance to alkaline disbondment over conventional epoxy alternatives.

Extreme Temperature Cycling

The Permian Basin experiences some of the most extreme daily temperature cycles in North America — from below-freezing winter nights to 110°F+ summer days in shallow buried conditions. Coatings must accommodate thermal expansion and contraction without developing fatigue cracks over decades of service. High-elongation polyurea formulations with elongation values above 400% are specifically recommended for this application environment.

Contractor Capacity in the Region

The Permian boom has strained coating contractor capacity throughout the region, with lead times for qualified applicators extending to 8–12 weeks on major projects. Our Certified Applicator Directory currently lists 14 qualified contractors operating in the Permian Basin region, all holding current AMPP certifications and our organization’s quality audit documentation.

Our members regularly submit technical questions through the Ask the Expert portal. Here we’ve compiled the most frequently asked questions from professionals new to the pipeline coating industry, along with answers from our Technical Advisory Panel.

Q: What’s the difference between polyurea, polyurethane, and polyaspartic coatings?

A: All three are isocyanate-based coating systems, but they differ in their resin chemistry and resultant properties. Polyurea uses amine-terminated resins and cures very rapidly (seconds to minutes) regardless of humidity. Polyurethane uses hydroxyl-terminated resins and is moisture-sensitive, with longer cure times. Polyaspartic is a subclass of polyurea using aspartic acid ester amines, offering slower cure times (minutes to hours) for better open-time control and improved UV stability. For pipeline coatings, pure polyurea and polyaspartic hybrids are the most common choices.

Q: Why does my polyurea coating have pinholes after application?

A: Pinholes in freshly applied polyurea are almost always caused by solvent or moisture outgassing from the substrate. If the substrate contains moisture or residual solvent from a primer, rapid polyurea gel time traps the gas as pinholes. Solutions include allowing adequate primer flash-off time, confirming substrate moisture content with a moisture meter, applying a thin mist coat before the full build coat, or switching to a slower-gel formulation that allows outgassing before the film skins.

Q: How do I choose between NACE SP 10 and NACE SP 6 for my polyurea application?

A: The choice of blast standard depends on the coating system’s requirements and the service environment. Spray polyurea coatings for buried pipeline service typically require Near-White Metal Blast (NACE SP 10) to maximize adhesion and CP compatibility. For above-grade maintenance applications with less severe service conditions, Commercial Blast (NACE SP 6) may be acceptable with the appropriate primer system. Always follow the coating manufacturer’s technical data sheet requirements as the minimum standard.

Have a question for our Technical Advisory Panel? Submit it through our Ask the Expert portal — members receive priority responses within 48 hours.

API 5L — the American Petroleum Institute’s specification for line pipe — defines the material requirements for pipelines used in the oil and gas industry. While API 5L is primarily a steel specification, understanding its implications for coating selection and application is essential for pipeline engineers specifying coating systems for new construction or rehabilitation.

Steel Grade and Coating Adhesion

Higher-strength API 5L grades (X70, X80, X100) used in modern high-pressure pipelines present specific surface chemistry considerations for coating adhesion. The higher carbon equivalent of these steels can affect wettability and adhesion of certain coating systems, particularly in the presence of hydrogen evolution during cathodic protection. Specifying appropriate surface preparation standards and primer systems is critical for high-strength line pipe.

Weld Zone Coating Considerations

Girth weld zones present the most challenging coating environment on a pipeline. The heat-affected zone (HAZ) creates microstructural changes in the steel that can affect blast profile and adhesion. The weld cap geometry creates coverage challenges for automated coating systems. And weld residual stresses interact with coating systems under operating conditions. Field joint coating systems — typically spray polyurea — must be qualified specifically for weld zone application.

Mill-Applied vs. Field-Applied Coatings Under API 5L

API 5L permits both mill-applied and field-applied coatings, but establishes different quality requirements for each. Mill-applied FBE and three-layer systems benefit from controlled factory conditions, automated application, and 100% inspection. Field-applied coatings for field joints and repairs must compensate for variable conditions through robust operator training, equipment maintenance, and quality control procedures.