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Challenges and NewDevelopments in PipelineCoating Technology

TechnologyTechnology

C ontinuously growing global demand for energy,geographic changes in global economic dy-namics and therefore global oil and gas supplyand demand, and about 6.7% per annum

depletion in world energy production have forcedenhanced exploitation and development in new oiland gas fields and sometimes from entirely new areas.New pipelines need to be constructed to collect theoil and gas from these new sources and transport tothe areas of demand. Examples of the new oil and gassources are frontier gas, deepwater, LNG, tight gas,shale oil and gas, and oil sands, which are oftenlocated in remote and inhospitable locations, or far-ther offshore and deeper under the sea. Transporta-

tion has also become increasingly difficult with moreof the “heavy”, “sour”, “hot”, and “wet” conditionsinvolved in these new fields.

These new drivers for oil and gas pipeline construc-tion present great challenges to pipeline coating tech-nology in order to address requirements in these newconditions and applications which traditional pipelinecoating technologies have not encountered. Water re-sources are also becoming scarce and creating waterstress worldwide, increasing demand in the water pipe-line market. Figure 1 illustrates the total value of globalpipeline coating market and the demand changes ondifferent product types over the period of 2008 to 2011,

The increased demand for new pipelines has provided great challenges andopportunities for improved or new pipeline coating and insulation technologies toaddress many unique requirements in both onshore and offshore applications.This paper highlights some of these challenges and opportunities for improvement,as well as introduces several recent developments of advanced pipeline coatingsolutions for anti-corrosion coatings, protective and weight coatings, thermal flowassurance coatings, internal coatings, field joint and custom coatings.

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based on known pipeline projects actually executed.Figure 2 also shows the estimated distribution of pipe-line coating market, valued by product types in 2010.Going forward, it is estimated that over the next fiveyears, over 215,000 km of pipelines expected to beinstalled globally over the next five years, and offshorepipes will account for 20% of total KM over the 2011-15 period.

Challenges on the Existing Pipeline CoatingTechnologya. Anti-corrosion pipeline coatings

Fusion Bonded Epoxy (FBE) and 3-layer polyolefin(3LPO) (polyethylene PE or polypropylene PP) are cur-rently the most widely used external anti-corrosioncoating systems. Single layer FBE has been more popu-lar in North America, Saudi Arabia and the U.K., duallayer FBE is in favor in Australia, and 3LPO coatingsdominate the rest of the world’s pipe coating market.Over the past 15 years, several incidents of coatingfailures have been reported with massive disbondmentof 3LPO coatings. A lack of consistent coating qualityand performance of FBE and 3LPO was found from oneapplicator to another. If a coating failure is about a singleor dual layer FBE, the cathodic protection can always bethe back-up. In contrast, 3LPO disbondment can cause“shielding” to cathodic protection current and furtherexpose the pipeline to environmentally induced crack-ing. The observed 3LPO disbondment failures haveraised concerns in the industry worldwide about thelong term performance of 3LPO coatings, resulting inseveral initiatives to determine the failure mechanismsand corrective measures.

There is a tendency in the industry to construct muchlarger diameter, raised welded pipelines. An example isthat many trunk lines today are constructed with heavywall and spiral welded pipes. Current pipe weldingtechniques produce welds that protrude up from theexternal surface. With the conventional 3LPO side-wrap extrusion application, protruding weld seams couldcause the formation of “tenting” where voids, separa-tion of coating layers, or discontinuities develop aroundthe weld neck. Accompanying with the “tenting” effectis a significant reduction of the coating thickness acrossthe top of the weld compared with the coating on thebody of the pipe. In extreme cases such a coatingthickness reduction could be as high as 100%. Toensure adequate coating film thicknesses for pipelineprotection, most of today’s international 3LPO coating

specifications allow only 0 to 10% of the coatingthickness reduction over weld seams. This requirementcreates a challenge to conventional 3LPO applications,especially on spiral welded pipes where the coatingthickness has to be increased significantly, resulting indecreased production output, increased coating andapplication costs, and the potential introduction ofseriously high residual stress in the polyolefin layer.

Another trend of design and construction of onshoretransmission pipelines is the use of high strength steels,such as X80, X100, and X120 and of the strain-baseddesign. High strength steels allow the reduction of pipewall thickness which significantly reduces the cost ofpipe transportation to remote areas. Applying a coatingto a high strength steel pipe is however a great chal-lenge. It has been found that the preheating duringconventional FBE/3LPE coating processes would signifi-cantly affect the properties of the high strength steel,causing the steel tensile yield strength to increase but theelongation at yield to decrease which could invalidatethe strain based design. The higher the strength of thesteel, the more negative the impact is. It is thereforerecommended that high-strength steel used for strainbased pipeline design avoid exposure to temperaturesabove 200°C (392°F). This restriction prohibits the useof conventional FBE coating systems which require thepipe to be heated at 230-250°C (446-482°F) to giveoptimal performance, and has prompted the develop-ment of an FBE standalone coating or an FBE primer formulti-layer PE systems that is capable of being appliedat temperatures as low as 180°C (356°F) while maintain-ing the desired performance properties for long termcorrosion protection.

When both pipe material and operating condition oftoday’s pipelines are no longer the same as the old ones,project specification requirements are becoming muchtougher than before. However, anti-corrosion coatingresin materials currently in use are reaching the maxi-mum of their performance potential. In spite of in-creased raw material costs, pipeline coating prices havenot been changed significantly over the past five years.As a result, both commercial and technical properties ofthe conventional pipeline coatings have not changed –even if the expectations have. Coating applicators arefacing increasing pressure to match industrial produc-tion to laboratory precision in order to meet expecta-tions. One example is how to achieve lower porosity,higher cathodic disbondment resistance and hot watersoak resistance, when a much-thicker-than-before FBE

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layer is applied at standard or lower application tem-peratures. Other examples of the issues associated withconventional anti-corrosion coating systems are: enddisbondment of coated pipes during long term storageparticularly in marine and tropical environment, blister-ing of the mainline coating during field applied FBE,coating cracks during field bending at cold tempera-tures or conditions requiring high flexibilities and dam-age of the pipe coating during HDD application.

Pipeline owners and operators, specification engi-neers, inspectors, coating material manufacturers andpipe coating applicators need tocontinue the dialog to anticipateincreased performance require-ments and to develop, do trialand approve the measures andsolutions to meet these chal-lenges. One of these measures isto implement tougher pipelinecoating specifications and select-ing better coating applicators ofhigh quality and good reputa-tions. Tests identified in currentnational, international and com-pany standards and specificationsare often relatively short termand predictive models for longterm performance are not available. Adding to theproblem is that the data on long-term behavior of pipecoating materials, even if available, are often scarce.Therefore, simply designing and qualifying a pipelinecoating or its applicator to just meet the short term andminimum requirements of current standards and speci-fications may not be sufficient An approach which reliesmore on generating data to provide trends in long termbehavior of the pipe coating system should be takenduring coating selection and PQT testing. Better surfacepreparation and coating process control to optimize andstandardize the application parameters should be im-plemented, in order to ensure the long term perform-ance of pipeline coating systems

.b. Protective and weight coatings

Reflecting primarily the increased offshore develop-ment activities and onshore pipeline installation inremote areas, protective and weight coatings made byconcrete command a significantly large portion of theglobal total pipeline coating market and are expected toexperience continuing growth. There are several meth-

ods of applying concrete coatings to a steel pipe coatedwith an anti-corrosion coating and sometimes with alsoa thermal insulation coating. Table 1 highlights the prosand cons of each of these application methods forconcrete coatings. Challenges in concrete coatings areto source/qualify the technically and cost effective ironores or alternative aggregates in order to improve theperformance (e.g. density, weight, or chemical stability)and reduce thickness and/or cost, as well as to reducedusts/dirt during relatively ‘dry’ application particularlyin the case of the impingement process.

As newer and larger diameter onshore pipelines arebuilt up in remote areas where tough terrains andclimates such as rocky mountain, steep slope, river androad crossing, wet frozen or silty/clay trench materials,and extremely cold construction weather are often thecase; pipeline integrity for durations above the nominal25-30 years of service becomes an important considera-tion. Corrosion protection has normally been the focusof the pipeline integrity effort, but mechanical protec-tion also needs to be addressed in order to ensure theintegrity of the corrosion protection. Mechanical pro-tection methods commonly used worldwide are sandbedding and padding, mechanical bedding and pad-ding, rock shield materials, and extra thick anti-corro-sion coatings. All of them have faced limitations in thenew pipeline construction conditions. For example,sand bedding and padding is not good with frozenmaterial and in extreme cold conditions. It becomes notpractical on steep slopes (needs breakers) and for riverand road crossings; rock shield materials are not goodfor large size trench materials and for river and roadcrossings. Since 1984, Rock Jacket® - a bendable,

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factory applied reinforced concrete pipe coating systemhas been introduced to provide a unique mechanicalprotection to coated pipes during the entire pipelinetransportation, installation and operation life cycle. Ithas been designed to be buried directly in blasted-outrock trenches without the use of other expensive backfillmaterials and provides pipeline design and installationflexibility in any type of terrain, trench material andclimate without using any additional manpower orequipment. It has the lowest total installed cost andinstallation time among all mechanical protection sys-tems and the lowest impact on the pipeline right-of-wayand the surrounding environment during pipeline in-stallation and life cycle. The product however hastraditionally only been available for application in veryfew fixed factories in North America and Australia andfor pipe diameter below 30” or 762 mm.

c. Flow assurance insulation productsInsulating pipes and structures for onshore and subsea

flow assurance is essential to avoid the possibility of waxand hydrate formation. Many insulation materials havebeen introduced into the market. Variants of thesematerials such as solids, foams and syntactic haveprovided a range of candidate materials with differingproperties for use in the manufacture of commercialinsulation systems to meet a wide range of operationalrequirements (see Table 2). The most commonly usedmaterials in subsea thermal insulation are polyurethanesand polypropylenes; due to their suitability for largescale production, availability of raw materials and sys-tem cost.

For subsea flowlines and risers, ‘dry’ insulation (Pipe-in-Pipe or PiP) and ‘wet insulation’ (single pipe) areavailable. A PiP dry insulation system isa common method of achieving highthermal (low ‘Overall Heat Transfer Co-efficient’ (OHTC) / U values of 1.0 W/m2K or less). The most commonly usedinsulation material used in PiP is poly-urethane foam. With all PiP systems,however, it is important to ensure thatthe structural integrity is maintained forboth installation and operational loadsfor each of the PiP components (ther-mal insulation, linepipe, centralisers,waterstop seals, and loadshares). Wateringress into a PiP system can causecorrosion and also potentially destroy

the whole thermal insulation system. PiP has also higherS-lay & J-lay installation costs. As a result, for longerpipelines, ‘wet’ insulation (single pipe) is increasinglymore cost competitive than PiP and has often been thepreferred choice of thermal insulation. Since the mid1990s, the average length of tie-backs has steadilyincreased, and line burial and electrically heated sys-tems have become more common. In these cases themain workhorse has been polypropylenes but otherthan using lower density foams and syntactic materialsthe material choices have had little change. As offshorepipeline installation in deepwater and ultra deepwaterapplications increases, technical requirements for off-shore thermal insulation will continue along the fol-lowing directions: longer tie-back, lower U value,deeper water depth, and higher operating tempera-tures. The challenge to the industry is to improve theold systems or to develop new insulation materials,and also to have the capability to verify the perform-ance of these improved/new insulation systems fordeepwater offshore applications.

In the case of onshore thermal insulation, the heavy oilsuch as oil sands production in North America haspresented several challenges to associated pipelinecoatings. Pipes insulated thermally with rigid poly-urethane foams have been successfully used for manyyears in the North American oil/gas industry for servicetemperatures of up to 85oC (185oC). However, under-ground pipeline designs for the heavy oil or bitumenmarket are based on operating temperatures in the rangeof 120-150oC (248-302oF), and above ground pipe-lines can be operated at much higher temperatures, thusdemanding new thermal insulation system which arecapable for the high temperatures.

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d. Internal coatings:Traditionally the most commonly used internal coat-

ings used for natural gas flow efficiency application aresolvent based epoxy coating with a low solids content(60% or lower). The trend of the industry, particularly inEurope, is to use high solids or even 100% solidscoatings for natural gas transmission, as an attempt toreduce the VOC (volatile organic compound) in theformulation and during coating application. Comparedwith the conventional solvent based coating, high solidsand 100% solids internal coatings can provide a pipesurface of over 20-50% smoother. This significantlyreduces turbulence and allows natural gas to flow moreefficiently. As a result, additional pipeline operatingcost savings can be achieved through the use of thesecoatings over the pipeline design life, a very smallportion of which can cover the initial additional costsassociated the new product. Another benefit is a moreglossy appearance which helps visual inspection.

However, adopting these high solids or 100% sol-ids coatings often require increased application equip-ment, capital investment, enhanced surfacepreparation requirements for better wetting and flow,and more technical experience and training on appli-cation. It is necessary to carefully qualify such highsolids or 100% solids coating based on actual plantapplication equipment and process conditions. Long-term evaluation testing after exposure to field condi-tions might be needed in order to ensure theperformance of the coatings.

In addition to natural gas flow efficiency application,new internal coatings are needed to address the in-creasingly demands for coating systems which havecorrosion resistance, abrasion and wear resistance,and high temperature resistance, due to the fastergrowth in the construction of pipelines for water injec-tion or transmission, CO2, wet gas, sour gas, oil sands,and coal seam gas.

e. Field joint coatings and custom coatingsTypical pipeline field joint coating systems include

liquid coatings, FBE, heat shrinkable sleeves, andinjection-molded PP/PE/PU systems. Among otherthings, the field joint coating systems have to provide:long-term anti-corrosion and/or thermal insulationperformance; excellent bonding to the steel substrate;compatibility with the mainline coating system; easyapplication/installation in any conditions and loca-tions, and short application/installation cycle time.

Field joint coatings are often perceived as the weakestlink in pipeline coating systems for corrosion protec-tion. This reflects the difficulties and challenges en-countered during the field joint coating selection andapplication in today’s pipeline construction:1. The urgent needs for better and careful designs in

order to qualify/select/apply/inspect a fit-for-pur-pose field joint coating;

2. The increasingly tougher pipe substrate and con-struction conditions (i.e., heavy-wall and large pipediameter, high strength steel, flexibility requirements,fast throughput), and

3. The impact of field application process control onthe final quality of the coating system (i.e., theenvironmental and weather conditions, applicationequipment, skills and experiences of field applica-tors/inspectors, etc.)

Figure 3 illustrates blistering of mainline FBE film fromthe cut back areas during FBE field joint application.Blistering occurs when the force of abrupt vapor expan-sion of moisture absorbed in the FBE film exceeds theadhesive strength of the FBE film, due to uneven heatingprofile and too high heating rate during the FBE fieldjoint application.

Figure 4 shows the field joint work on offshorepipes of the Pluto LNG Project in Western Australiausing Polypropylene Injection Moulded Field Joint(IMPP) technology. It was an engineering challengeas it was the largest project scope ever specifiedusing IMPP in the world. Approximately 4500 fieldjoints were successfully insulated with an extrudedvolume of 70 liters of molten PP per field joint and

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with a maximum cycle time of 7 minutes per fieldjoint– an industry first. The IMPP concept is based onthe technology of having flowlines coated with afully fused material over the full length that canwithstand elevated temperatures, deepwater, andmaintain its properties with regards to corrosion andinsulation. The Allseas vessel “Audacia” laid thepipes using an S-lay installation method. One of thechallenges of using the IMPP system on S-lay bargesis the criticality of cycle times and the layout ofconveyors and tensioners onboard in the firing line.The IMPP field joint equipment was specifically re-designed to accommodate the setup of the vesselalong with a recess into the thick insulated joints toavoid damage by conveyors.

While induction heat pipe bends require a customcoating for onshore pipeline construction, subsea oiland gas production systems require even more complexcoating which calls for complicated custom coatingsolutions. A significant component of the subsea pro-duction systems are various steel piping structures thatgather the oil and gas from the wellheads, transfer themto the transmission pipelines or to production platforms,inject water for enhanced recovery, etc. These pipingstructures include, among other things, pipeline endterminations (PLETs), pipeline end manifolds (PLEMs),spools, goosenecks, jumpers, trees, manifolds, etc. Thesesteel piping structures must be protected against corro-sion and/or thermally insulated after the fabricationoperations in order to avoid creating corrosion-proneareas or cold spots in the subsea production system. Thecustom coating systems for the subsea production sys-

tems have to provide:a) Long-term anti-corrosion and/or thermal insulation

performanceb) Excellent bonding to the steel substratec) Easy post-coating access to all the subsea structure’s

elements – valves, etc. andd) Easy application/installation in any conditions

and locations.The custom coatings for subsea structures shall be

applied under quality controlled conditions and usingadvanced process technology, often requiring high effi-ciency thermal insulation systems with optimum thick-nesses in order to ensure easy installation and excellentlong-term thermal insulation performance.

New Pipeline Coating Solutions to Meet NewChallengesa. Anti-corrosion pipeline coatings

Figure 5 shows a new high performance compositecoating (HPCC®) used for arctic construction of a 36”pipeline with X100 and X120 steel in Northern Al-berta, Canada. The all powder components of themulti-layer polyethylene coating and its unique coat-ing application method provided excellent conform-ity to raised welds and achieved a uniform coatingthickness coverage along the weld seams. The newcomposite coating with a FBE primer applied at lowapplication temperatures down to 190°C (374°F) hasbeen used in several critical high strength and strain-based design pipeline (X100 and X120 steel) projectsin North America.

Figure 6 shows RPE® - the latest anti-corrosion pipecoating industry which is based on a FBE basecoat and

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an outer layer of reinforced polyethylene by chemicalcross-linking. In contrast to conventional 3LPE sys-tems, the RPE coating has no adhesive layer. At a totalcoating thickness of 2 mm or less, RPE is 2.5 to 3 timesmore impact resistant than a 3.5 mm thick 3LPE at23oC and remains its good impact resistance andflexibility even at -60oC. The tough coating has suchhigh bond strength and hardness that a normal peeltesting cannot be preformed and only the use of achisel could remove it from the FBE base coat, thuspreventing the two layer composite coating from dam-age during handling and installation, as well asdelamination and loss of adhesion.

The great majority of regular FBE powders in themarket prior to 2000 have a glass transition tempera-ture Tg around 100°C. The maximum operatingtemperature for standard alone FBE pipeline coat-ings is specified to be 60°C by major pipeline own-ers. The commonly recommended maximumoperating temperature is 85oC and 110oC (230oF)for a standard 3LPE system and for a standard 3LPPsystem, respectively. Recently several coating manu-facturers have developed high Tg FBE resins andmajor FBE coating suppliers have formulated highTg FBE coatings for higher than 60°C operatingtemperatures. Consequently, these high Tg FBE pow-ders are also recommended as a primer for 3LPPsystems with higher than 110oC operating tempera-tures. Since high Tg FBE coating materials becamecommercially available recently; they do not have along track record in the field and they have to gothrough a critical qualification process prior to be-ing used. The industry is currently discussing rel-

evant standards and testing technique to qualifyhigh temperature FBE and polypropylene materialsfor operation temperatures up to 150°C. Figure 7shows a set up for elevated temperature cathodicdisbondment.

As more and more pipeline constructions occur inremote areas, pipe coated at either end of the valuechain is the optimum location from the clients’perspective and therefore mobilization of a pipecoating plant has become popular. Figure 8 showsa Brigden™ plant – the industrial first “plug-and-play” modular mobile pipe coating technology.The mobile coating plant is designed, fabricated,and installed in plug-and-play modules, with theability to manufacture a full range of anti-corrosionand flow assurance pipe coatings. Raw materialsstorage, maintenance, quality control and testingfacilities are all fully integrated. This mobile facilitycan be located in-country, near a pipe mill or close

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to an oil and gas field to streamline project logistics,improve safety and reduce costs of handling andtransporting pipe. Brigden ships in standard ISOcontainers and takes only six weeks to assemble andbe fully operational.

b. Protective and weight coatingsAdvances in application technology development

have recently made Rock Jacket® - the bendable,compression wrapping applied reinforced concretepipe coating available for pipe diameters up to 36”or even 48” through a unique portable plant opera-tion. The plants can be mobilized in a short periodof time to anywhere worldwide in order to meetspecific project requirements and to significantlyreduce pipe transportation and handling costs. TheUS$12 billion PNG LNG project by Esso HighlandsLtd in Papua New Guinea has used the new Mobi-lized Rock Jacket® technology for the onshore sec-tion of the 900 km (560 miles) pipelines ofpredominantly 32” and 34” pipes. Figure 9 shows apipe protected with Rock Jacket® being bent at thePNG LNG project site.

A weight coating for an offshore pipeline does nothave to be of concrete. Each offshore pipeline projecthas unique product qualifications that require de-tailed analysis, customized design and close cus-tomer contact to satisfy specific project specifications.The development of Pluto LNG project consists ofsubsea wells tied into one subsea manifold and onepigging manifold in approximately 830 m waterdepth. Two 27 km long, 20” (508 mm) productionflowlines transport the gas to a riser platform in 85 mwater depth. A 36” (914 mm) export trunkline is to

be used to transport the gas from the platform to theLNG plant. A 6” (168 mm) platform MEG line com-pletes the system. A control umbilical will link thesubsea system to the platform with satellite commu-nications to shore. For the Pluto LNG flowlines,there was a need for a pipeline insulation system thatincluded weight coating to provide negative buoy-ancy for a large pipe diameter and a rough surfacefor the outer shield to improve safety and handling.The product shown in Figure 10 consisted of astandard 3-Layer Polypropylene (3LPP) coating formechanical and corrosion protection. The next fourlayers included alternating layers of Thermotite®Deep Foam (TDF) polypropylene insulation materi-als and a specially formulated weight coating ofheavy aggregates and solid polypropylene. With alarge pipe diameter of 20” and individual insulationlayers between 20 and 25 mm thick, the system hadto be both thermally efficient and have sufficientweight to meet negative buoyancy requirements. Toincrease the density of the system, two layers of aheavy aggregates-polypropylene blend were de-signed and extruded onto pipe. This material wassuccessfully extruded to a density of 2000 kg/m3. Inaddition to the added density, the outer shield orseventh layer, was machine tooled to roughen up thesurface to improve safety and reduce slippage.

c. Flow assurance insulation productsThe heavy oil such as oil sands production in

North America has presented several challenges toassociated pipeline coatings. Pipes insulated ther-mally with rigid polyurethane foams have beensuccessfully used for many years in the oil/gas indus-try for service temperatures of up to 85oC. Under-

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ground pipeline designs for the heavy oil or bitumenmarket are however now based on operating tem-peratures in the range of 120-150oC, and aboveground pipelines can be operated at much highertemperatures, demanding for thermal insulation athigher temperatures. Figure 11 illustrates severalpipeline coating products recently developed andselected by the North American industry to protecta range of pipelines, from flowlines and gatheringlines connecting to the wellhead to large diametertransmission pipelines bringing processed oil andgas to the market. These products include not onlythe traditional anti-corrosion coatings such as FBEand the industry leading Yellow Jacket® two layerpolyethylene coating for small diameter gatheringand transmission lines, the traditional and new mo-bilized Rock Jacket® protective coatings, but alsothe thermal insulation product line to which twonew high temperature insulation products Insul-8®HT and Insul-8® AG are added. Insul-8® HT is aspray applied polyurethane foam coating developedfor external protection of buried and above groundpipeline for operating temperatures up to 150oC.Insul-8® AG is a newly developed pre-insulatedpipe insulation system used for above ground steampipelines for operating temperatures up to 650oC,using Aspen Aerogel’s Pyrogel® insulation materialprotected by an outer layer aluminum sheath.

Offshore pipelines in deepwater and ultradeepwater applications demand new pipelinecoatings and particularly new thermal insulationproducts for flow assurance. The most commonlyused thermal insulation materials in subsea pipe-

lines are polyurethanes and polypropylenes. Anew revolutionary subsea thermal insulation sys-tem, Thermotite® ULTRATM has recently been in-troduced to the industry to deliver optimalperformance in any depth of water for operatingtemperatures up to 120oC. The new product featuresspecially designed styrenic polymer blends and al-loys. Compared to the commodity polypropylenesystems, Thermotite® ULTRATM offers improvedinsulation properties at a reduced insulation layerthickness, extending cool-down period (the time ittakes for heavy oil to solidify after the oil flow is shutoff) and improving seabed stability in flowlines. Italso contains no glass microspheres which are oftenincorporated within the commodity polyurethaneand polypropylene insulation to resist the externalhydrostatic pressure of the pipes, thereby simplify-ing production processing and eliminating the riskof decreased thermal performance due to glass break-age. Figure 12 shows the cutback section of a pipeprotected with Thermotite® UltraTM.

As offshore pipeline and production systems moveinto deeper waters and more extreme conditions,operators must strive to eliminate environmentaland safety risks wherever possible – while alsomeeting production and efficiency goals. During thedevelopment and qualification of insulation systemsfor subsea oil and gas pipelines it is important tounderstand and quantify the behavior of the insula-tion under service conditions experienced in subseaenvironments. Figure 13 shows the largest and mostadvanced simulated service vessel (SSV) in the in-

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dustry launched by ShawCor in May 2011 in To-ronto, Canada. The SSV is capable of simulatingwater depths to 3,000 m and temperatures up to180°C, and can accommodate pipe samples up to 6m long with diameters up to 910 mm (36") – includ-ing field joints and custom fittings to simulate real-life requirements. As shown in Figure 14, the SSV isdesigned to accurately simulate subsea conditionsusing controls and instrumentation. Precise meas-urement of thermal properties is made across thewhole pipe length using multiple heat flux sensorsgives accurate measurement of cool-down and U-value, even at low internal pipe temperatures. Real-time data collection allows for determination ofsystem performance during the test cycle.

d. Internal coatingsIn the case of internal coating for natural gas flow

efficiency application, it is important to determinethe effect of coating thickness and different blastfinishes on coating roughness. As shown in Figure15, the coating roughness of a solvent- free coatingincreases with the decrease of coating thickness.However, it can be concluded that there is nosignificant effect of blast cleanliness on coatingroughness when analyzed with the standard devia-

tions. The consistency of roughness is greatly af-fected by the thickness. It is important to note that atthe applied coating thickness of 2.0-2.5 mils (or 50-63µm), the coating surface roughness of the solvent freecoating can be as low as 1.1 µm. This is about 9-10times lower than the typical surface roughness rangeof 9-12 µm achieved by commonly used solventbase coatings. A very smooth internal coating sur-face can significantly reduce turbulence, allowingnatural gas to flow more efficiently and thus reducingoperation costs of the pipeline.

New water pipe coatings are also developed toaddress the new challenges. Oil sands deposits mustbe strip-mined or made to flow into producing wellsusing in-situ techniques that reduce the oils viscosityusing steam and/or solvents. These processes use agreat deal of water and require new water pipelineconstructions in tough environments. When mostdesign engineers in North America are using 50years to be their benchmark for “desired” waterpipeline design life, the current industry standardsfor water and wastewater pipelines are weak orundefined to secure the achievement of the 50 to100 years of design life target. Therefore, the inter-ested parties are currently working together to de-

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velop tougher qualification testing protocols andimply tougher performance and application require-ments on protective coatings. One of the examplesis that Southern Nevada Water Authority has re-cently formed a qualification program to qualifypolyurethane and epoxy coatings for their proposed456 km, 30’ to 84” Groundwater Development Pipe-line Project – the largest water pipeline project everin the U.S. history. The qualification program has setup many tough performance requirements with whichsome of commodity coating products may not beable to meet. It is expected that more new or im-proved pipeline coating products will be introducedand implemented to the water pipeline sector, justcontinuously being the same for oil/gas pipelines.Figure 16 shows WaterGuard® PU, a high perform-ance, 100% solids, potable water grade, structuralpolyurethane coating specially designed for waterpipeline application.

e. Field joint coatings and custom coatingsHistorically, the major problems associated with

field-applied girth weld joint coatings were directlyrelated to if and how a suitable field joint coating isselected and qualified, the sensitivity of prevailingenvironmental and application conditions such assubstrate cleanliness and preparation, and field ap-plication technique and process control. While oiland gas pipeline coating factories have been devel-oped to apply advanced coatings to strict specifica-tions, industrial standards and specifications forfield joint coatings have not received the sameemphasis. The increase in use of advance pipelinecoatings has heightened the need for field jointcoating systems to match the quality and perform-ance properties of factory-applied mainline coat-ings. This begins first to ensure the technicalspecification requirements for field joints are con-sistent with the ones for the mainline coating sys-tems, and then to ensure these requirements aredelivered under the field environmental and appli-cation conditions through various qualification meas-ures. These measures include APS – ApplicationProcedure Specification, PQT – Procedure Qualifi-cation Trials, PPT – Pre-Production Trial, and appli-cator certification, as outlined in ISO 21809-3:2008standard. Another key approach is to reduce thelevel of manual operation and thus human errors byutilizing well-equipped application tools and proc-

ess during the field joint coating installation. Figure17 shows the world’s first automatic heat shrinkablesleeve HSS installation unit. The entire HSS installa-tion is completed by the machine.

Custom coating application for complex structuresis traditionally a material over-wasted process. Thiscan be changed with the computer aided design CADand 3D modeling (Figure 18). 3D modeling givesaccurate volumes of material required to achieve theoptimum coating and insulation thicknesses, revealsmould patterns, and helps out insulation executionstrategy. The technique has been very effective insubsea thermal insulation for complicated structuressuch as jumpers, trees, manifolds.

ConclusionNew pipeline coating technology requirements

are driven by: construction in frontier environments;

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new developments in steel technology; pipe layingin deeper environments; higher operating tempera-tures; concern for the environment; tighter regula-tion/specification/legislation; pipelines carryingincreasingly aggressive materials, under harsher con-ditions, through more difficult environments, andcustomers’ increasing interest in higher perform-ance and further cost reduction. These requirementshave provided great challenges and opportunities forimproved or new pipeline coating and insulationtechnologies to address many unique requirementsin both onshore and offshore applications. To meetthese challenges and requirements is not an easytask, but has been and will be possible through thejoint efforts of all interested parties, as demonstratedby the unique and advanced pipeline coating prod-ucts outlined in this paper for anti-corrosion, protec-tive and weight, thermal flow assurance, internal,field joints and custom coating applications.

References1. J. Westood, “Macro Factors Driving the Global

Oil & Gas Industry & The Subsea PipelinesSector”, Toronto, July 13, 2011

2. K.K. Tandon, G.V. Swamy, and G. Saha, “Per-formance of three layer polyethylene coatingon a cross country pipeline – a case study”,14th International Conference on Pipeline Pro-tection, BHR Group, Barcelona, Spain, Octo-ber 29-31, 2001

3. G. Portesan, J. Taves, and G. Guidetti, “Cases ofmassive disbondment with three layer PE pipe-line coatings”, Cathodic Protection and Associ-ated Coatings, CEFRACOR, EFC Event nr254,Aixd-en-Provence, France, June 6-7, 2002

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5. B. Chang, D. Wong, A. Kehr, et al, “Residualstresses in 3LPO external pipeline coatings –disbondment and cracking”, 18th InternationalConference on Pipeline Protection, BHR Group,Antwerp, Belgium, November 4-6, 2009

6. D. Melot, “Pipeline coatings within TOTAL: Feed-back and perspectives”, AMI Pipeline Coating 2009Conference, Vienna, Austria, January 26-28, 2009

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Coatings”, NACE Corrosion 2010, San Antonio,Texas, USA., March 14-18, 2010

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9. K. Watson and M. Davadass, “Engineering ofSpecifications: Lofty Ideals or Attainable Tar-gets Using Current Materials”, AMI PipelineCoating 2011 Conference, Vienna, Austria, Feb-ruary 7-9, 2011

This publication thanks Dr.Shiwei William Guan for providingthis article. Dr. Shiwei WilliamGuan has over 27 years of experi-ence in corrosion engineering and

coating technology, receiving his B.Eng. andM.Eng. degrees from China, and a Ph.D. degreein Materials Science and Corrosion fromMcMaster University in Canada. He is Chair ofNACE International TG265 for two layerpolyolefin pipe coatings, Chair of NACE TG353for multi-layer polyolefin pipe coatings, andChair of NACE TG281 for field applied poly-urethane coatings. He is an Executive Memberof Singapore Corrosion Society and a memberof the Editorial Advisory Board of the interna-tional journal “Anti-Corrosion Materials andMethods”. Dr. Guan is a NACE InternationalCertified Coating Inspector Level III and a CIPinstructor. He is currently in charge of strategicmarkets and technology in Asia Pacific forBredero Shaw.

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