A Deep Dive Into Subsea Coatings

I was recently approached by a fellow coating inspector who had applied for a position with a leading oil company as a SURF coating inspector [Subsea production equipment such as Umbilicals, Risers and Flowlines]. Unfortunately, the gentleman had no prior experience with subsea wet insulation and was enquiring about the inspection requirements for these systems as opposed to conventional paint systems. There is little I could say that would prepare the inspector for the position as, simply put, subsea insulation systems are a far cry from the norm! (My advice was, “If you don’t know what you are inspecting, then I would give the position a pass.” However, whether he took my advice remains between the gentleman and the potential employer.)

This did get me thinking, though, about subsea coating inspection and how little is actually understood about it.

Wet Insulation Systems—A ‘Dark Art’

You see, wet insulation systems have been considered something of a dark art for many years, and it is only recently that standards have been introduced for acceptance and rejection criteria.

Although subsea Insulation systems have been around for 20-plus years, they are constantly evolving to meet industry demands. Additionally, in recent years there have been some major turnarounds in regard to material development, engineering and subsequent inspection protocols.

As the search for oil and gas continues with increased exploration, oil and gas operations are moving into ultra-deep water and tapping reservoirs at more challenging depths with far greater pressures and higher temperatures. This has led to a rapid evolution in wet insulation technology and, subsequently, increased inspection demands for wet insulation application.

However, believe me when I say that subsea thermal insulation systems are not simple conventional coating systems by any stretch of the imagination.

The philosophy of inspection criteria and even the purpose of the system are completely different from the norm, and few inspectors are really familiar with the inspection parameters, the acceptance and rejection criteria, or even the application methods of these innovative coatings.

Understanding Expectations

Subsea insulation systems can be either wet (exposed to the surrounding seawater) or dry (protected from seawater by a jacket or external pipe), so you will often hear the terms “wet insulation” and “dry insulation.” Few inspectors are really familiar with the inspection parameters, the acceptance and rejection criteria, or even the application methods of these innovative coatings.

We have to remember that the main purpose of these systems is to reduce thermal losses in the pipeline, maintaining temperature and flow assurance from the reservoir to the surface (topsides or onshore) in order to preserve the operational integrity of the production system. The subsea insulation system maintains the production stream temperature above the hydrate formation and wax deposition temperatures. Thus, any failures such as cracks, disbondment or hydrolysis, which could substantially influence the subsea system’s operational philosophy, are greatly reduced. Simply put, without insulation the cold seawater would rapidly cool down the fluids, and hydrate/wax formation would make it impossible for a safe flow of oil and gas. Wax deposition and wax gelation are two potentially catastrophic issues in crude oil and gas condensate systems that can render a pipeline unusable.

Performance Requirements

With this in mind, the need to handle production with far greater pressures and higher temperatures in extremely cold waters demands robust systems with superior thermal conductivity properties. Extended subsea equipment life and optimised flow of hydrocarbons from reservoir to surface are essential.

In order to maintain oil temperature and enable product flow during production and shutdowns, more reliable, cost-efficient, safe and lower-risk thermal insulation is required. As a result, insulation systems have evolved to offer improved properties—such as increased mechanical strength and reduced heat transfer—that ultimately reduce thermal conductivity and make deep-water hydrocarbon recovery feasible. 

In addition to having excellent thermal insulation properties, materials need to protect against corrosion, resist seawater and impacts, be in compressible yet flexible at the water depths encountered, and not degrade during the life of subsea projects—which is often 20 to 25 years or longer.

Not a small order!

Wet Insulation Technology

Because of the criticality of maintaining product flow, subsea wet insulation technology has seen significant advancements over recent years.

These systems have been developed to insulate the high-pressure/high-temperature (HP/HT) equipment and architecture used in deep-water production infrastructure and tiebacks, i.e., umbilical s, risers, flowlines, PLET (pipeline end termination), FLET (flowline end termination), PLEMs (pipeline end manifolds), etc. The main purpose of these systems is to reduce thermal losses in the pipeline, maintaining temperature and flow assurance from the reservoir to the surface in order to preserve the operational integrity of the production system. As a consequence of their direct exposure to seawater, subsea “wet” insulation systems on subsea trees, manifolds, risers and jumpers are amongst the most affected by thermal conductivity. Because of the significant thermal gradient between the production stream and undersea environment, subsea insulation systems are constantly trying to inhibit the natural heat transfer.There are three main approaches to insulate flowlines for deepwater operations:

1. Pipe-in-Pipe
2. Wet Insulation
3. Flexible Pipe

Pipe-in-Pipe

Pipe-in-pipe consists of inner and outer steel pipes with an insulating material in the annular, or void, space between the pipes. (This was the more widely used system in the early years of insulating coatings).

According to Jerry Franklin, a spokesman from Dow Hyperlast:

In the early years Pipe-in-Pipe insulation accounted for approximately 90 percent of subsea insulated flowlines. Flexible pipe and wet insulation accounted for the balance. Today the formula is reversed, with an estimated 90 percent of installed flowlines consisting of wet insulated pipe.

Wet Insulated Flowlines

A wet insulated flowline is a steel pipe with a surrounding layer of exposed composite insulation. This approach consists of only the carrier pipe and insulation material (with and without a thin corrosion coating, usually fusion bonded epoxy [FBE]). The insulation is directly exposed to seawater, thus it is possible for water to diffuse into the insulation. This insulation may be solid polymers or foams. Syntactic foam uses small hollow glass microspheres dispersed throughout the polymer matrix. Chemical foams use additives dispersed in the polymer that decompose and produce gasses to make a foam structure. The aim in all cases is to reduce density to improve insulation value.

Insulated Flexible Flowlines

An insulated flexible flowline is a composite structure with a core of helically wound steel and extruded plastic layers and insulation added in the form of flexible wrapped syntactic insulation. Although very expensive to produce, the benefit is they are very flexible and in some circumstances can be reused.

Specifying a System

Clearly wet insulation is now leading the field for subsea insulation and the preferred method of selection for insulating subsea equipment. However, specifying subsea insulation systems is by no means an easy feat. 

Because of the significant thermal gradient between the production stream and undersea environment, subsea insulation systems are constantly trying to inhibit the natural heat transfer.

A spokesman for Shawcor, a leading supplier of subsea wet insulation products, puts it rather well. Project manager Marcos Mockel states: Specifying wet pipe insulation is not a simple process because each field setting and well operation has its own construction demands. We find that wet insulated flowline is the system of choice for the vast majority of projects because of its installation efficiency and effectiveness, but the final decision is always determined by field infrastructure, line length, U-value requirements, and the overall design structure of the field, and not by depth alone.

And I have to concur there are so many design factors of the material to take into consideration for manufacturers for example:

• Thermal conductivity Dry – ASTM C518 
• Thermal conductivity Wet – ASTM C518
• Heat capacity – ASTM E1269
• Thermal diffusivity (Dry) – ASTM E1461
• DSC Specific gravity – ASTM D792
• Compressive strength – ASTM D575
• Tensile strength – ASTM D412
• Tensile elongation – ASTM D412
• Poisson’s ratio – ASTM E132
• Mechanical testing – ASTM D638

These are just some of the properties that a material is tested upon; there are, of course, more. Materials must go through endless rigorous inspection and testing, and inspectors are required to know and understand the inspection requirements, techniques, test methods, associated standards, and acceptance and rejection criteria for prequalification testing (PQT), etc. Inspectors are required to know and understand the inspection requirements, techniques, test methods, associated standards, and acceptance and rejection criteria for pre-qualification testing (PQT), and more.

Now, we must remember that the main purpose of these systems is to reduce thermal conductivity. As stated by Adam Jackson of RAE Energy Norway:

Thermal loss is calculated in terms of U-value and expressed as Watts/sq m Kelvin (W/m2K). The heat transfer coefficient required for a particular system is based upon multiple factors including but not limited to:

• Water temperature.
• Well output temperature.
• Flow rate, and flowline length and diameter.

An insulated flowline that meets the target U-value for a given location and operating scenario will limit heat loss of transferred products to an acceptable temperature differential from the reservoir to the surface thus reducing hydrate formation and wax deposition.

The benefits of this are rather simple to understand particularly, from a Capex (capital expenditure) and Opex (operating expense) perspective.

Material Selection

Wet insulation systems used on subsea pipelines are mainly polyurethane or polypropylene based. There are also products based on epoxy, polyether, phenolic, silicone, rubber and specialized polymers. They are mostly used for the insulation of such as jumpers, risers and complex subsea equipment.

Glass microspheres are the hollow displacement fillers of choice for syntactic foams because they offer excellent strength, low density and uniform properties. These low-density hollow microspheres reduce both the weight and thermal conductivity of the pipe coating.

The first syntactic foams were made with polymer or plastic beads; however, the plastic beads were proven to be structurally weak, limiting the depth at which that type of syntactic foam wet insulation could be used. This led to the research and development for a stronger microsphere capable of withstanding the pressures at water depths up to 3,000 meters.

Chemically foamed polymers rely on the strength of the polymer itself to avoid collapse. Depending on water depth and temperature of the produced fluid, the maximum water depth is usually limited to around 500 meters. It is widely accepted that the root cause of most subsea pipeline and insulation failures can be attributed to mistakes in material selection and application and at interfaces such as field joints or construction joints where materials may be mismatched.

This has led within the industry to a significant demand for greater technical knowledge and understanding of thermal insulation systems and inspection regimes. The most common failures in wet insulation are from cracks and material collapse due to compression. Cracks are often the product of inappropriate application of materials or a lack of flexibility of the insulation material and can, in some cases, propagate down to the corrosion coating resulting in spalling and inducing corrosion. Subsequently, when a material is not strong enough to resist compression and collapse, its thermal conductivity increases and its ability to insulate decreases.

Standards and Specifications

An international ISO standard—ISO 12736.2014 Petroleum and natural gas industries – Wet thermal insulation coatings for pipelines, flow lines, equipment and subsea structures—describes the mimimum requirements for qualification, application, testing, handling, storage and transportation of new and existing wet thermal insulation systems for pipelines, flowlines, equipment and subsea structures.

The inspector needs to be aware and familiar with a variety of application methods, such as extrusion, casting and molding, and straight wet application. This recently developed and published standard references different polymer types such as polyurethane and polypropylene. The American Petroleum Institute (API) has also recently published it recommendations: RP 17U Recommended Practice for Wet and Dry Thermal Insulation of Subsea Flowlines and Equipment. Additionally, there are various major company standards and specifications in this field for the qualification and testing of different thermal insulation systems.

Overall Knowledge and Insight

So, how are these products applied? Application depends on a number of factors, such as the material type, subsea equipment type, geometry of the structure, etc. For example, on subsea equipment, wet insulation predominates due to the complex shapes involved; materials such as liquid syntactic polyurethane (PU) is commonly used due to ease of processing and moldability. On straight pipe, extruded systems such as polypropylene are used due to the speed, cost and ability to design appropriate systems. This means the inspector needs to be aware and familiar with a variety of application methods, such as extrusion, casting and molding, and straight wet application. How many have this experience?

Taking into consideration the technologies involved in these sophisticated systems, more is expected in the requirements of a subsea coating inspection and the inspectors. However, I have to ask: Are there many individuals capable of inspecting these complex systems?

At a minimum, inspectors should be able to:

• Understand the differences between different insulation systems and generic types;
• Understand subsea specifications and standards;
• Have an understanding of application methods, mold setup, etc.;
• Identify common failures and defects;
• Understand subsea specifications and ITP (inspection test plan) and test methods;
• Be familiar with PQT (prequalification test) requirements;
• Be familiar with product curing times in order to conduct inspection during application and curing phases; and
• Know how to document and report findings identifying coated areas and status of completion. (This would require an understanding of subsea equipment).

These are just some of the basic requirements; however, there are more, of course.

Additional Resources

As you can see, subsea insulation and its subsequent inspection is an extremely intricate and complex technology. There is no wonder that subsea insulation was often referred to as the dark arts of protective coatings for subsea applications.

There is a lot of knowledge out there and technical papers published that can be of great use, and, fortunately, manufacturers are extremely helpful in getting you up to speed on their products’ expectations and limitations. For any inspector who wants to learn more about this field, I would advise you obtain as much information as possible in regard to subsea products, applications, standards and inspection requirements prior to commencing a project you know little about.

The subsea insulation industry is constantly adapting and evolving in order to meet increasing industry demands. Inspectors need to be aware of these changes, as I am afraid that what was in vogue yesterday may not be the trend today.

The author would like to thank Barry Turner, Pipeline Coating Consultant for his contribution to this article.

By Lee Wilson, C-Eng, FICorr,

www.corrtechltd.com