News & Articles

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.

Plural-component spray equipment is the backbone of polyurea pipeline coating application. These sophisticated machines — operating at high pressure, elevated temperature, and with chemically reactive materials — require disciplined preventive maintenance to deliver consistent application quality and avoid costly downtime on the job site.

Daily Maintenance Procedures

At the start of each day, technicians should verify that heated hose temperatures are stable and uniform, check all fluid seals and O-rings for signs of wear or material buildup, verify that mix ratio is correct using graduated containers, and test spray pattern on a test panel before beginning production work. Any deviation in mix ratio exceeding ±2% should trigger equipment shutdown and investigation.

Isocyanate Crystallization Prevention

The isocyanate (A) component of polyurea systems will crystallize in cold conditions or upon moisture exposure, blocking filters, screens, and pump components. All equipment should be purged with clean solvent at end-of-day and stored with dry nitrogen blanketing on the A-side reservoir to prevent moisture ingress. A strict temperature minimum of 65°F for equipment storage prevents crystallization during cold weather operations.

Preventive Maintenance Schedule

A comprehensive PM schedule for plural-component spray equipment should include weekly inspection of heated hose elements and thermocouples, monthly replacement of pump packing and check valves, quarterly calibration verification of mix ratio sensors, and annual pump refurbishment by the equipment manufacturer’s certified service center.

Our Equipment Maintenance Library contains manufacturer-specific PM checklists for all major plural-component spray systems. Register for our equipment maintenance workshop to get hands-on training from certified equipment technicians.

Offshore pipeline coatings operate in one of the most aggressive environments on earth — combining seawater immersion, cathodic disbondment, impressed current interference from adjacent structures, mechanical damage from marine traffic and anchor dragging, and (in the splash zone) cyclic wet/dry exposure with UV radiation and wave impact.

Zone-Specific Coating Requirements

Offshore pipelines are divided into distinct environmental zones, each with specific coating requirements. The atmospheric zone uses conventional weathering-resistant topcoat systems. The splash zone — extending from approximately 3 feet above to 3 feet below mean water line — is the most aggressive, requiring immersion-rated systems with exceptional mechanical toughness and CD resistance. The submerged zone relies on protective coatings working in concert with impressed current CP systems, while the buried/touchdown zone must accommodate soil stress without cracking.

Fusion-Bonded Epoxy for Deepwater Applications

FBE remains the dominant coating for deepwater flowlines due to its thin profile (important for concrete weight coat adhesion) and excellent performance under cathodic protection at the mild temperatures found in deepwater environments. Dual-layer FBE systems add an outer toughening layer that provides mechanical protection during J-lay and reel-lay installation.

Polyurea in Offshore Applications

Spray polyurea is increasingly specified for offshore riser coatings, pipeline repair clamps, and splash zone rehabilitation where its rapid cure, high film build, and exceptional CD resistance provide advantages over slower-curing epoxy alternatives. Several major North Sea operators have standardized on polyurea for their splash zone maintenance programs with excellent 10+ year field performance data.

One of the most common challenges faced by pipeline integrity engineers is convincing management to invest in premium coating systems over lower-cost alternatives. The upfront cost difference between a standard epoxy system and a high-performance polyurea application can be significant, but lifecycle cost analysis consistently demonstrates the economic case for premium coatings — if you know how to make it.

Total Cost of Ownership Framework

Total cost of ownership (TCO) for a pipeline coating system must account for: initial material and application costs, inspection and monitoring costs, maintenance coating applications, rehabilitation costs, CP system energy costs (reduced with better coatings), regulatory compliance costs, and risk-adjusted failure costs. When all factors are properly included, premium polyurea systems typically achieve lower TCO than conventional alternatives within 8–12 years of service.

The Value of Extended Service Life

A coating system that extends from a 15-year to a 25-year service life before rehabilitation doesn’t just save 10 years of maintenance — it also defers the significant mobilization and permitting costs of a rehabilitation project, avoids production interruptions, and reduces regulatory scrutiny. When discounted cash flows are modeled properly, the net present value of extended service life is often the single most powerful argument for a premium coating investment.

Risk Reduction Quantification

Modern quantitative risk assessment frameworks allow engineers to assign dollar values to corrosion failure probability reductions. A premium coating system that reduces annual failure probability by 0.1% on a pipeline carrying $500 million of product annually has a quantifiable annual risk reduction value that can be directly compared to the incremental coating cost.

Download our Pipeline Coating TCO Calculator — a member-exclusive spreadsheet tool that guides you through a complete lifecycle cost comparison for your specific application parameters.

We are thrilled to welcome Riverside Pipeline Services as a new Certified Member of the Oil Pipeline Coatings Industry Association. Based in Tulsa, Oklahoma, Riverside brings 22 years of experience in both mainline coating and field joint application across the mid-continent region, with particular expertise in polyurea rehabilitation of aging crude oil gathering systems.

About Riverside Pipeline Services

Founded in 2002 by veteran coating contractor Marcus Trevino, Riverside has grown from a six-person crew to a 180-person organization operating across eight states. The company holds AMPP CIP Level 2 certifications for all field supervisors and maintains an ISO 9001-certified quality management system — qualifications that align perfectly with our Certified Applicator Program standards.

Why Riverside Joined

“We joined because the technical resources and the peer network are genuinely valuable,” said Trevino. “Our engineers are already engaged in the Pipeline Integrity Working Group, and we’re looking forward to the Fall Technical Conference. Being part of this organization tells our clients that we hold ourselves to the highest standards in the industry.”

Welcome, Riverside!

Riverside Pipeline Services is now listed in our Certified Applicator Directory and will be participating in upcoming regional events. If you’re in the mid-continent region and need a qualified polyurea or epoxy pipeline coating contractor, we encourage you to reach out to them directly.

Interested in joining our network? Learn more about membership benefits and the Certified Applicator Program.