|Undertaking maintenance painting of offshore oil and gas assets can be expensive and frustrating due to the complexity of the facility, and the highly corrosive nature of the marine and chemical-rich environment (Fig. 1). However, the author’s experiences over many years have shown that there are three simple and synergistic methodologies which — if executed and supported properly — can significantly improve the durability, reliability, cost-effectiveness and performance of on-station structure maintenance.Part 1 of this article (JPCL September 2014) demonstrated how much of the damage to coatings occurs to offshore oil and gas platforms and floating production storage and offloading facilities (FPSOs) during the construction, conversion and/or commissioning phases of getting the asset on-station and working to pump and process oil and/or gas. This part covers some practices that have been found to be useful and effective to deal with the damaged coating systems once the platform or FPSO is in position at the oilfield and to address the other degradation that inevitably occurs throughout its operational life. These practices are not exclusive to offshore assets; they can be applied to onshore structures of all types where aged or damaged coating systems are found.
The Three Pillars of Maintenance Painting Practice
The three-pillar concept suggested here is part of an overarching strategy to paint the right item or surface, at the right time and with the right coating system.
Pillar One: With some regularity, be it annually or bi-annually, commission an on-station coating maintenance repair and touch-up campaign using an experienced and resourced coating application contractor, working to specific directions and instructions on what, when and how to paint.
Pillar Two: Make sure that all corrodible equipment, hardware, structures and components that are supplied to the asset from onshore are properly and fully coated with the right coating system before being shipped. These items are to be protected, packed and handled with care cognizant of the vulnerability of the protective coating system to damage.
Pillar Three: Initiate a program using one or two personnel from the facility’s crew to carry out spot coating maintenance and touch-ups — especially when mechanical items, hardware, structural members, pipe spools or even bolts are fitted or replaced — using a narrow range of multi-purpose coating products that are kept in small kits in the facility’s paint locker. This article discusses how these three processes are interrelated and how they can combine to provide the best asset durability, the best risk management and do so at the lowest practical cost.
Pillar One: Use a Professional Contractor
Too many times the results of inadequate skills, resources or capability employed to plan and carry out coating maintenance duties is evident offshore. This should not be deemed an attack on coating contractors, because they are but a small part of the assembly of skills that it takes to properly perform on-station coating maintenance work. With all due respect, the other participants can be the personnel who carry out the coating condition surveys; those that interpret that information to make priority listings; the specifiers and contract writers who prepare work scopes and develop coating schedules; coating manufacturers or suppliers who may exercise their own agendas on products and systems; the procurement staff that make purchasing decisions on coating suppliers and contractors using price as the single or predominant criterion; the inspectors looking over the work; and last but certainly not least, those employed to manage the SimOps of production, operations and maintenance on a complex offshore oil and gas facility. As is now obvious, the heading above this section is a misnomer: it’s not just the coating application contractor who influences the ultimate quality, efficacy, economy and reliability of on-station coating maintenance. Let’s work our way through the process and see who and what else has influence and why.
Extent and Type of Corrosion vs. Rate of Corrosion
The first and most vital task when structure maintenance is being contemplated is to perform a thorough survey and inspection of the facility, and then to interpret this data to develop a sensible and robust priority listing. Sometimes these tasks fall to the same person; in other cases they are separate. Unless the surveyor is particularly skilled and focused, it is easy for this survey to concentrate on the extent of coating breakdown or the percentage (penetration) of through-section rusting (and these are not the same thing).
The extent of breakdown or the percentage of rusting are less significant than the rate at which breakdown is occurring. Thus, of greater concern is the rate of section loss and when the integrity of the item, member or structure will be at risk. This is because an item of steelwork could be widely rusted but rusting at a rate of little concern or minimal consequence. Coating and structure maintenance should be performed based on need and painting maintenance should — on a well-managed facility — have to compete with other integrity and maintenance issues for funding. Therefore, the need to paint should be directly connected to risk, specifically, the minimization or control of risk. The metric of risk might encompass structural or mechanical integrity, personnel safety, hydrocarbon containment or environmental releases in some order or other depending on the corporate philosophies of the asset operator or the persuasion of the regulator.
Inspector beware: the priority of what to paint, when and how should be driven by the risk to that item, structure or surface from a loss of functionality or integrity caused (primarily) by section loss. This is seldom directly assessable by estimating the visual extent of corrosion or coating breakdown, so it means looking deeper and considering the future consequences that could arise from corrosion causing section loss on the items being scrutinized.
Many surveyors and inspectors tasked with undertaking condition surveys might have trouble articulating or identifying the difference between the extent of breakdown or corrosion and the rate at which section loss is happening, or will happen. Technically, the extent of breakdown or corrosion can be assessed at a single point in time; for example, x percent of the total surface areas is given to a rusted condition and y percent still has paint present (where x plus y equals 100) based on a simple two option demarcation. Rate of corrosion, however, brings in a time factor. Therefore an item would theoretically need to be assessed at different dates in order to determine the rate of change. With some experience and focus the simplistic criterion of how widely something is rusting (or showing coating breakdown) can be relegated to a lower importance than an estimate of how rapidly the corrosion is occurring and when the consequences of that may become intolerable.
It helps to understand that corrosion on the surface of carbon steel can be partly protective, in its own right, of the underlying metal. By definition, corrosion (rust) is a compound of iron (Fe) and oxygen (O) in one or usually more of the various forms of iron oxide and oxide-oxyhydroxides, for example, Fe O, Fe (OH)2, Fe2O3, Fe3O4 and so on. These oxidized states of iron are more stable and have less potential to further oxidize than the parent metal. The quite benign and stable nature of iron oxide is one of the main reasons why it is such a very common pigment in paint and coatings. By way of analogy, rust on steel is not like cancer in the human body. It doesn’t have to be totally eliminated for the durability of the asset to be reasonably protected. Consequently, the presence of corrosion product does not necessarily imply that a deleterious amount of metal section loss has occurred, and may help to slow down the rate of further corrosion by acting as a scab over a potential breakdown zone.
As a general rule of thumb, higher priority scores for coating maintenance should be assigned to items and surfaces where the risk of repair scope creep and the consequences of coating failure or loss of containment and/or function are highest; not the items where the amount of work to perform to correct the breakdown or corrosion is greatest.
A Stitch in Time Saves Nine: Counterintuitively, it is also helpful to assess items or surfaces on the basis of where the consequences of a delay in undertaking maintenance would be worse. This is the old and meritorious saying “a stitch in time saves nine” approach. The underlying logic is that items or surfaces with just a small amount of apparent breakdown are sometimes better candidates for some spot repair or perhaps overcoating before the extent of surface preparation becomes too high (i.e., after more breakdown occurs). This scenario should be compared to where another item has already badly broken down to the point where a wide scale or total area surface preparation is required, but where the repair scope cannot increase even if postponed. An example could be a structure that evidences widespread rust-through of the coating but where the rusting process is slow and poses no imminent threat to structural integrity. So, if a full 100 percent blast was thought necessary as the next maintenance step — yet that surface preparation intensity doesn’t change if the work is delayed for a few more years (it will still require a 100 percent blast) — then there is little consequence to the delay thus allowing other more vulnerable items, where a delay does have scope escalation ramifications, to be elevated in priority.
Another principle that should influence work scopes and priorities is opportunism, particularly relating to access. If some areas of the facility can be made accessible with minimal disruption of ongoing oil production (with all the incumbent work permit conflicts), it sometimes makes sense to group together the work scopes on a number of adjacent items and complete all of them contemporaneously.
Collectively, these somewhat disparate influences should be collated to come up with a recommended priority schedule for tackling the coating maintenance work in the best order, remembering that the priority should be focused on risk (structural and integrity), not appearance. When surveyors and inspectors make priority rankings based on the visually dominant criterion of extent of breakdown, the wrong items may unwittingly be selected for maintenance attention.
Twilight Zone or Feathering Zone: The next item to address is which surface preparation and coating system combination to use and what extent of activity to perform. Based on many maintenance campaigns for spot painting the following procedure is suggested.
When the surface preparation is being performed — assuming in this instance that it is being done with power tools, and also that the existing sound coating between the spots is still serviceable — confine the area being cleaned to the zone of breakdown only and just out to the sound coating edge, i.e., don’t keep extending the spots unless the adjacent coating is unsound. The aim is to keep the surface preparation (and the priming) within strictly controlled geographic limits. Importantly, the surface preparation ought not to include feathering the edges of the existing coating as this will stress the bond at the critical point: the juncture where the coating has been fractured and where the bare substrate is exposed. By all means, ensure that the edge that has been reached is sound, but then stop there. The only areas where some feathering might be considered, is where an adverse aesthetic situation might exist in highly visible areas. In a nutshell, there are few of these on an offshore structure. Simply, the extra time and effort to perform a low-yielding task like feathering edges would be better spent on actual surface preparation on other breakdown zones.
Achieving an excellent degree of surface preparation quality is usually not worth the extra effort and expense. Experience indicates that 80 percent of the value of surface preparation for spot coating maintenance is achieved with maybe 35 to 40 percent of the effort. Achieving the balance of the value will take about twice as long for the last 20 percent of value. Moreover, the effective labor cost offshore is very high by the time everything is rolled up. So spending about three times the man-hours on surface preparation per effective square meter is not good economy.
Another difficulty is the differentiation between zones of breakdown that look the same or similar to the coating contractor, often on adjacent items, some of which need attention and others that don’t. For example, a badly rusted section on a pipeline containing pressured hydrocarbons and an identical zone of corrosion on a deadleg support stool might both appear to need preparing and painting, yet the risk to integrity of the two could not be more disparate. This can literally mean that coating maintenance in a specific area of the facility does not actually address all the zones of breakdown, sometimes much to the dismay of the non-coatings people on board. The reasoning for intentionally omitting some zones needs to be explained to the coating contractor and to production and operations personnel.
It is important to try and lower the amount of soluble salt contamination, specifically ionic materials such as sodium and chloride, to a level as low as possible before coating surfaces with good surface tolerant coating materials. Very good durability can be achieved without over-preparing the substrate to a pristine condition. There is a trade-off between the extent of surface cleanliness and the amount and type of coating applied for the same achievement of durability.
When painting, the primer coat needs to be applied just to the spot-cleaned areas and out onto the sound coating film by no more than about 20 to 25 mm (0.75 to 1 inch). Painting farther out onto the sound, intact adjacent coating is not recommended, even if another spot repair zone is proximate. At this stage, just paint the bare spots and very carefully brush around the juncture between the bare substrate and the edge of the adjacent sound coating to bind in the exposed coating edge. This ensures further film build with the subsequent coats is added just on the areas that have had the steel substrate exposed. If adjacent spot-prepared areas are joined up with the primer it will not be possible to tell exactly where the bare substrate was with all subsequent coating applications, and staying focused on where the bare steel areas were actually located is extremely important to maximize productivity and durability, and to optimize the use of labor and paint. Many painters may have to be retrained so as to adopt these important aspects because their work history likely involves feathering edges, extending the paint coverage too far with successive coats, joining adjacent spots together and brushing out or rolling the coating so it looks good to the detriment of film build and durability.
Another reason to concentrate on painting just the spots is to avoid adding extra film build, and hence stress, to the adjacent sound coating that already has its full quota of film build. In essence, adding further paint build to a sound and functional film is not only wasteful of paint, but could risk film integrity if the cumulative stresses get too high.
Carefully brushing the primer around the edge of the adjacent coating will sometimes cause the edges to curl up slightly as the primer cures. This is permissible and only if it splits open or becomes intolerable, should it be cut off with a sharp broadknife and reprimed, otherwise it may be just overcoated. Offshore, painting is for performance and durability, not aesthetic appeal.
When the primer and subsequent coats are being applied, it is important to ensure that an adequate and appropriate film build is achieved for each coat applied. Too often spot and patch painting occurs where the extensive effort of surface preparation is not matched with enough of the right paint film build. The theory in play is that in many ways, a slight shortfall in the absolute achievement of surface preparation quality can be compensated by extra film build (providing the right generic type of coating is used and is tolerant of a higher film build). Remember, the cost of a 4 liter (1 gallon) tin of paint is only a fraction of a painter’s effective cost per hour, so make sure the paint application is performed in a manner that guarantees enough of the coating film is applied on all areas being painted. By comparison, paint is cheap in this situation. As with the avoidance of feathering during surface preparation, the aesthetics of the paint application are not critical if the priority is protection. This means that brushing out the wet coating so it looks good is not as important as getting the film build everywhere it is needed and only where it is needed.
Browning’s Observation: Less is more: As most oil and gas offshore structures currently in use would have employed epoxy coatings as the primary generic material on their topside systems, the spot-repair products are probably best to be epoxies also. (For a given thickness high-build vinyls are arguably superior barriers than epoxies to oxygen and moisture permeability — as their many decades of use offshore proved — but their use with epoxies in mixed systems is potentially problematic.) As a result, high-build, surface-tolerant epoxies have greater utility as on-station maintenance coatings, perhaps in combinations with a zinc-based primer and high-build polyurethane topcoats (if color is important).
For offshore maintenance painting where the prepared surface is predominantly free of organic paint material — even if there are some oxides or remnants of corrosion products left on the substrate — and except where water ponding or a long time-of-wetness is possible or likely; zinc-rich primers, preferably epoxy zinc-rich materials, are advised. It is not necessary to employ a zinc-rich coating that contains extremely high loadings of metallic zinc, such as 90 percent of zinc by weight. One reason is that they can be too weak cohesively when overcoated with thick-film topcoats. A lower zinc level in the mid-80 percent range has a better balance of resin to pigment and doesn’t lose out on the ability to provide a satisfactory level of galvanic protection for the initial few months before this starts to fade. It is widely understood that zinc-based primers have a resistance to residual soluble salt contamination around seven or eight times that of other purely barrier coatings.
If using a zinc-rich primer is not desired or suitable, as in the case where a water ponding risk exists, then epoxy materials used direct-to-metal would be satisfactory. A good quality aluminum-pigmented, high-solids, solvent-based, surface-tolerant epoxy is a very good product choice. What these lose in galvanic capability as compared to a good zinc-rich primer, they make up for in permeability resistance and undercutting resistance, especially if the formulation uses a high-quality aluminum-flake pigment at an appropriate pigment volume concentration (PVC).
Usually it will take a sequence of coating layers — often three or four — to be carefully applied to achieve the required film build and protection on the spot treated areas. The same diligence needs to be observed with all of the coating layers applied after the primer, i.e., with strictly controlled geographic limits of painting, cleanliness between coats and attention to film-build achievements for each and every layer. A contrast of colors must always be used for successive coats to ensure full coverage. The aim is to achieve a high integrity coating over each spot area or zone of painting that achieves a full-system dry film thickness (DFT) of around 18 to 20 mils (450 to 500 microns). This DFT of a reputable surface-tolerant epoxy, applied in a sequence of coating layers (and certainly not as a single- or two-coat application) should comfortably have the potential to provide a good term of durability even if the absolute surface preparation quality of an oxide-free substrate was not achieved.
In this context, the painting is normally favored to be left as non-contiguous spots, unless there is a very good reason why a unifying topcoat should be applied such as a maritime safety directive or regulation. Examples of this are rare though, covering only specific areas of the platform or vessel such as the helicopter deck. A functional paint job that ends up looking like a spotted dog is perfectly acceptable on a producing oil platform or FPSO, providing the paint is in exactly the right places and will provide the durability desired.
If it is decided to apply an overall topcoat (aged systems of sound, weathered coating may need a tiecoat and a topcoat), no painting beyond the immediate zone of the spot-repaired areas should occur until the required minimum DFT has been achieved on all the spot-coated areas because once a full coat of anything has been applied, the locations of spot repair zones where the DFT could be low will then be indistinguishable.
There are certain items that should not normally be painted. This isn’t absolute but there is little benefit, for example, in spending valuable time and effort doing surface preparation and painting operating handwheels or levers on valves or actuators. If they finally corrode to the point of being unserviceable, they can easily and cheaply be exchanged for new. Likewise, the expensive time and effort required to clean and paint bolts offshore is wasteful. Bolts are cheap and if corroded to the point where they are not functional — and they have to be severely corroded on the heads and nuts before the bolt shank loses tension — simply spin them out and replace them. That said, if some extensive surface preparation has been performed on a valve body or pipe spool in and around the associated bolts or studs, then it is worth painting the bolts at the same time. Otherwise, do not clean and paint bolts alone and don’t resort to replacing corroded mild steel or galvanized bolts with stainless steel thinking a better lifespan will result.
Handrails are another item where enormous effort can be spent cleaning, preparing and painting. Sometimes some small spot repairs are warranted, but if the workscope rises too high, it is usually cheaper and more durable to fabricate and coat new handrail assemblies onshore and fasten them into place as like-for-like replacements. Lighter metalwork members, for example, deadlegs under pipe spool supports have little consequence and would have to lose an enormous amount of their section to corrosion before their integrity were threatened.
Finally, ensure access for structure maintenance is provided by those operating the facility into the locations where the priority demands are highest. SimOps in hazardous zones often mean that production and operations don’t want to have painters working where access conflicts with other trades exist. A situation recently occurred on an FPSO offshore northwest Australia where a three month offshore maintenance painting campaign that was intended by the integrity managers to focus on corroding hydrocarbon lines and rusted and pitted decks over crude oil tanks, the painters were pushed away from these zones by production and operations controllers, so instead they spent about three months sanding, feathering and painting the exterior of the accommodation block. The work they did looked beautiful, but nothing was done to improve the integrity of the pipelines and tank deck. The campaign was wasted as it failed to achieve its objectives.
Pillar Two: Onshore-Supplied Items and Equipment
Offshore oil and gas facilities have a high collective maintenance requirement. The whole plant works hard 24 hours a day, 365 days a year. Valves, pumps, motors, actuators, pressure sustaining valves (PSVs) and myriad other proprietary items have only a finite life when working offshore and have to be replaced with some regularity. As subsea fields change in flow rate and yield, it is often required to make adjustments or new additions to the piping, reticulation and drains running to and from the various vessels and equipment. Typically, these items are supplied from an onshore supply base and shipped out to the facility for onsite installation. Thus, there is usually a steady stream of proprietary items and equipment; and purpose-fabricated items, structures, assemblies or equipment making its way offshore.
Proprietary equipment such as pumps, motors, valves and cabinets usually have a manufacturer-furnished paint finish. Unless these individual items are specifically and exclusively used for offshore service — which is rare — their standard paint system will have minimal durability in a severe marine environment and is often just for product or manufacturer differentiation. If the operating lifespan of these items is short (for factors other than corrosion) then it possibly makes no sense to augment the existing paint finish or to insist that the items are supplied with a bespoke offshore-rated protective coating system. Otherwise, if the lifespan and functionality of the item can or will be compromised (if the effects of corrosion prevail over its mechanical, electrical and/or hydraulic end-of-life) then improving the coating system will have some distinct durability and financial benefit. The latter should ideally be performed onshore before the hardware is shipped to the facility. Reinstating the manufacturer’s glossy appearance to the item is not the aim here. Adding some compatible and functional additional film build is.
Even a simple alkyd-based, semi-decorative paint system on a pump, valve, PSV or actuator can be augmented with a surface-tolerant epoxy to a reasonable DFT without too much difficulty and expense if this is performed onshore before shipping. The cost and logistics can be offset by a dramatic improvement in durability if this policy is adopted for all possible proprietary items. An urgent breakdown might require procuring and expediting an item that can’t be painted in time, but with proper planning, most pieces could and should be pre-painted.
With some negotiation and foresight, it may be possible to get the original equipment manufacturer to prepare and coat his items in the factory with the facility’s designated offshore-rated protective coating system. There are realistic durability-related benefits that can arise from this.
Choose Wisely – Part A: With structural items and pieces, some shocking examples have been seen on a variety of offshore facilities where newly fabricated and onshore-coated structures and pieces have been shipped with totally inadequate coating systems for offshore duty (Fig. 2). Every offshore facility operator has in-house coating specifications, or at least they use generic systems detailed by a reputable coating supplier. When large-scale projects for supply of fabricated members are underway, in most cases the correct coating system for the service exposure gets identified and detailed on the drawings or included in the coating specification. For smaller projects, however, where a few members or pipe spools are to be fabricated and supplied, it seems that the link to the desired coating system often gets lost, perhaps because too many people involved don’t sufficiently understand the corrosion and durability consequences. Arguably, they think “painting is just the final color” so it doesn’t get or retain the right attention. This is probably not helped by the contractual supply chain where the painting contractor is a subcontractor to a steel fabricator who might himself be a subcontractor to the equipment supplier. This makes the link from the purchaser and specifier (the facility operator) to the painter, quite tenuous or indeed, non-existent. The net result can be that the painter himself makes a choice about what he thinks the steelwork warrants, gets it to the right sort of color and ships it out.
A procurement method that has a robust process of identifying the right coating system to use for each item or member, ensures this is priced into the project quote, keeps the drawing and coating system requirements inseparably linked and has a reliable method to ensure that each item is inspected at each appropriate stage of surface preparation and coating application; has the ability to significantly extend the durability of the member or piece. The long-term rewards for this are large and worthwhile.
Importantly, no item or member should leave the painting contractor’s workshop to be sent offshore until it has been progressively and finally inspected by a qualified and experienced coatings inspector who understands exactly what protection method and achievements are required.
The next shortfall relates to a systemic problem seen with packing and protecting the coated items at the painter’s yard or the fabricator’s premises to prevent damage to the coating occurring through every stage of handling until the pieces arrive offshore. It seems few people appreciate the fragility of the finished paintwork and most fail to provide even the most basic care and protection. For instance, it is common to have the flanged faces on pipe spools fitted with plywood discs affixed with electrical cable ties or perhaps bolts. This is generally fine to protect the machined face, but what about the edges of the flange which have been dutifully painted? This where the pipe spool sits when placed, dropped or dragged on the ground or deck and damage seems to be inevitable. This damage is absolutely preventable (Figs. 3 and 4).
Shipping items to an offshore facility involves a lot of handling from the first pickup from the painting contractor’s workshop to craning the pieces into laydown once offshore and then erecting these into position. The benefits to the long-term durability and the reduction in costs from finding a way to get these items out to the facility with minimal damage to the applied coating is immense, yet too often, this is very poorly performed. In addition, all packing and protection materials need to be kept intact and prevented from getting wet so atmospheric-grade coating systems are not subject to immersion-like conditions. This can also occur if water ponding is allowed to occur in steelwork sections when in transit or laydown. It goes without saying that soft slings should be used on coated pieces rather than steel chains, meaning crane operators and dogmen should be instructed about how to avoid damage while lifting and loading coated items.
The last aspect to discuss on the topic of onshore-coated items is site touch-up after installation and commissioning. The task of installing newly supplied equipment, structures or hardware is not finalized until the coating touch-up has been fully completed. The final sign-off, therefore, should not occur until the protective coating’s integrity and appropriateness has been verified.
On multiple Australian FPSOs a disproportionate amount of the coating maintenance workload is due to inadequately coated onshore-supplied items, pieces and prefabricated structures that are a fraction of the age of the parent facility. Yet the corrosion on these items is far more advanced in its extent and rate of breakdown. This burden is being unnecessarily added to that of the rest of the facility at an on-station cost per square meter that could easily be a full order of magnitude greater than what it takes to prepare and properly paint the same item onshore.
There are large and measureable savings and great benefits to durability that can and will result from making sure that the right coating system, to an inspected quality level, is applied to each and every item that is supplied to the offshore platform or vessel, whether this is a proprietary item or a fabricated member; and ensuring that an adequate and effective level of protection results through each stage of consigning, shipping, offloading, cranage, laydown, installation and coating touch-up. The aim is to make sure that the future burden of offshore coating maintenance is not increased by the incorporation of onshore-supplied items or members. These new items should be expected to be maintenance-free for a suitable honeymoon period and unless they are at, or close to, optimal condition when installed offshore, they merely add to the future maintenance burden of the facility.
Pillar Three: Crew Touch-Ups and Maintenance
The third item in the recommended methodology list is minor coating touch-ups that are performed on a more sporadic basis as opposed to the larger dedicated painting maintenance campaigns described earlier, that are better performed by professional coating contractors.
Usually, manned offshore platforms and FPSOs have at least two full crews who typically work swing shifts of several weeks each, in rotation. Strangely, there is a reluctance to assign personnel to tasks that include — even part time — performing same basic coating maintenance. Notwithstanding, the potential benefits from this, in conjunction with the two other pillars of coatings attention, can be significant.
If the facility has to rely on organized and formal campaigns with an on-station coating application contractor to perform repainting and coating maintenance at intervals of, say, once a year or biannually, then there is a very good chance that the total workload will exceed the capacity of this resource. It helps enormously to have a small but responsive ability to carry out localized spot painting or touch-up, especially for tasks such as coating repairs after the installation of new or replacement hardware, valves or pipe spools. With respect to how many onshore-coated items and members suffer damage during packing, shipping, craneage, laydown and installation; having a member of the facility’s crew who can perform the final coating touch-up without waiting many months for a contractor to mobilize can reduce the size and complexity of the touch-up and increase the performance of the repairs.
The first thing needed is for one or two able crewmen to operate some simple surface preparation tools, typically pneumatic-driven power tools or similar, and to mix and apply a short list of coating touch-up materials. It is not expected that these people should have access to, or operate, complex abrasive blasting or ultra-high pressure (UHP) waterjetting equipment — a short selection of power tools that are capable of producing an SSPC-SP 3 (Power Tool Cleaning) or an SSPC-SP 15 (Commercial Grade Power Tool Cleaning) cleanliness standard is all that is required. This means that only some very basic trade training is probably all that is needed to provide the skills and understanding that these designated crewmen should have.
Besides some training in knowing when the climatic and substrate conditions are suitable for final surface preparation and coating application, the other skills needed are how to mix and apply a multi-component catalyzed coating product properly. Most people, if they had a modicum of interest in undertaking some coating maintenance, could be taught these skills in a day or two with the right teacher.
A strategy already developed and instigated on a number of Australian FPSOs is to use only two or three different coating materials to do almost all of the onboard coating maintenance with crew members. To facilitate this, the ship’s locker was emptied of most of the old, mismatched, large kit sized, out of use-by-date paint and coating materials, and was restocked with a short list of coating materials supplied only in small packs. These materials typically consist of one zinc-rich epoxy primer, a surface-tolerant catalyzed epoxy in a few different colors (including an aluminum version), and some acrylic-modified high build polyurethane, again in just a few basic colors. The intention is that 95 percent or more of all coating touch-up needed to be done by the crew can be done with these two or three products used universally all over the facility’s topsides.
Choose Wisely – Part B: As many of the good surface-tolerant epoxy coatings have a mix ratio of 4A-to-1B, one facility’s progressive coating supplier agreed to put 600 mL of Part A for a surface tolerant epoxy in a 1.0L paint can, and 150 mL of Part B curative/convertor in a 250 mL can. The painter simply opens and stirs one can of Part A and opens one can of Part B, pours it into the larger can and voilà! This assures that the mix ratio is correct every time. There is plenty of room inside the 1.0 L can to accommodate both components and some thinners without spilling during mixing and application. The painter takes the mixed paint and a brush or roller and heads off to do the spot painting. When the items or areas are painted, the unused mixed paint, the brush or roller are simply thrown into the appropriate waste bin. There is no using $5 of solvent to clean a $2 brush. If two or three colors of the same surface-tolerant epoxy are stocked, the Part B curative is usually common to all. The same small kit provision is made for a zinc-rich epoxy primer and a couple of basic polyurethane topcoat colors. This means a very small inventory of onboard paint stocks.
With same basic guidance and training and a clear and logical wall chart for area-of-use information and thinner reference, there is little chance that the crew painters can go too far wrong in selecting, mixing and applying these few material types to most atmospherically exposed surfaces all over the offshore facility. There should be a “no large can” policy in the ship’s paint locker; the only containers larger than 4 liters would be for solvent. Small kits such as described are slightly more expensive and not all manufacturers are happy to oblige with these special drawdowns, but the avoidance of waste, the chance of disproportioned mixes being all but eliminated, and the improved logistics and ease of mixing much offset a slight increase in the paint price. The reason this concept was established was because there were too many examples on a number of offshore facilities where the wrong coating, mismatched components or unconverted product was used.
Some real examples demonstrate this. One FPSO had some beautifully painted replacement pipeline valves. The color was brilliant, the gloss dazzling and the coverage and brushwork was excellent. Further research revealed that all of this person’s paintwork was done with an architectural alkyd gloss, i.e., house paint (Fig. 5). Searching afield, scores of deck spot repair zones that had been diligently power tool cleaned, “treated” with a phosphoric acid rust convertor and then primed with an alkyd primer and an alkyd gloss were seen. This looked absolutely great, for a few months. Then the rust started pouring through again. Not good!
In another classic example, after a large number of rusty column and vessel bases on a process deck were inspected, a good quality surface preparation and coating system consisting of multiple layers of surface-tolerant epoxy was duly specified. A few months later the inspector returned to the FPSO to find a carefully applied coating that had been cut-in neatly around the prepared deck areas in dozens of separate locations. This work had obviously taken many weeks to perform, however, something looked decidedly wrong. The coating film was mostly glossy, but it was also partly wrinkled with embedded dust. A close inspection proved that the painter had applied multiple layers of high-build polyurethane topcoat direct to the spot-cleaned steel, but all of it unconverted. It was Part A only (Fig. 6, p. 56)! It had surface dried but was still cheesy and un-catalyzed right through the film down to the substrate. Sadly, all of this crewman’s effort was completely in vain.
From the sublime to the ridiculous there is only one step.
The three pillars or strategies outlined herein are complimentary. If applied together they have the ability to help facility operators stay ahead of the workload of coating maintenance and corrosion control due to atmospheric corrosion on offshore assets, improve the reliability of the work performed and achieve must better cost-effectiveness. However, they would likely be of little overall benefit if performed alone or in isolation.
To set priorities for coating maintenance based on risk, rather than visual extent of corrosion is the important first step to be understood, and actioned. Performing deep maintenance campaigns using skilled, resourced and experienced coating application contractors who are tasked with following the priority plan and undertaking the surface preparation, cleaning and coating application in exactly the right manner is vitally important to ensure that the right surfaces and items are coated at the right time with the right coating system. Ideally, on an established facility, undertaking an annual on-station campaign with a good contractor working to a good plan can make some positive progress. However, to maximize the value and return from this work, the contractor needs access to the designated areas to execute the priority ranking. This only comes from cooperation from production and operations, who often see painting crews as disruptive.
To ensure that the collective forward burden of coating maintenance is not increased, all corrodible items, structures, controls, equipment and piping that are shipped to the offshore platform or vessel from an onshore supply base, should have an appropriately chosen and diligently applied, undamaged and intact coating system by the time the hardware reaches the facility. After installation and commissioning, all damage and compromises to the coating, howsoever caused, should be fully repaired to achieve full functionality. Attention to all aspects that can influence this can pay large dividends.
Finally, there is a need for an on-station resource to be able to carry out minor coating repairs and touch-ups. It is suggested that this is best accommodated by having one or two members of the facility’s crew skilled and equipped to carry out these tasks using a few hand-held surface preparation tools and a short list of widely compatible coating materials that are stowed in the paint locker in small kits. The work by these crew members is not designed to replace the more formal maintenance campaigns undertaken by the separately mobilized coatings contractor, but to augment these resources.
If organized and managed effectively, these three pillars can work synergistically to reduce risks, maximize durability and reduce the costs of offshore coating maintenance.
The author is indebted to the late Mark S. Schilling for his valuable input, advice and counsel in preparing this and the earlier Part 1 to this article.
About the Author
Mark Dromgool is the managing director of KTA-Tator Australia Pty Ltd, based in Melbourne, Australia. He has been continuously active in the protective coatings industry for 37 years. Dromgool’s experience includes 10 years as a coating application contractor and about seven working for two of the largest protective coating suppliers in Australia and New Zealand. In 1994, he formed KTA-Tator Australia as a protective coating engineering, inspection and consulting company.
Dromgool is a long-standing member of SSPC and NACE, and is former president of the Blast Cleaning and Coating Association (BCCA) of NSW. He has written and published many papers on coatings and linings and has lectured widely at local and international conferences. In 1996 and again in 2007, he was the recipient of the JPCL Editor’s Award for papers entitled “Maximizing the Life of Tank Linings,” and “Epoxy Linings – Solvent-Free But Not Problem-Free,” respectively. In 2006, Dromgool was awarded the John Hartley Award for Excellence by the BCCA of NSW.
Dromgool has qualifications as a mechanical engineer; is an ACA Certified Coatings Inspector; a NACE-accredited Protective Coating Specialist; an SSPC-accredited Protective Coating Specialist and a NACE-Certified Coatings Inspector – Level 3.
Learn more about the Three Pillars of Maintenance Painting Practice. Visit www. paintsquare.com/offshore for sidebars explaining what not to paint and dos and don’ts for contractors.
Article by Mark B. Dromgrool
KTA-Tator Australia Pty Ltd
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