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Volume 10 Number 11 - November 2010

Reprinted from

Covering the

Oil and gas transmission pipelines are critical elements of infrastructure in the transportation of fuel. They supply not only energy and power to many countries,

but in many cases are key strategic elements in sustaining economic growth and development. As such, they are precious resources. Given then that pipelines generally operate in harsh environments, there is a powerful argument for providing them with effective protection to ensure their operational effectiveness over the medium to long-term.

The capacity, as well as operation and pumping costs of a gas pipeline, can be adversely affected by the roughness of the internal surface of the steel pipe and the build-up of corrosion products. The concept of internally lining gas pipelines was first developed in the 1950s. The application of a two-component epoxy coating to the internal surface of gas pipelines provided enhanced flow of gas, corrosion protection in storage, optimum commissioning and reduced operational costs.

External coating systems have also been designed to form a barrier between the metal surface of the pipe and the surrounding environment, Since its introduction in the 1960s, single-layer fusion bond epoxy (FBE) has proven its capability as an external pipe coating and is now the most commonly used pipeline coating in North America, preventing the build-up of aggressive corrosion-causing compounds.

Over the past 40 to 50 years, therefore, international oil and gas companies have grown to recognise the many benefits of internally and externally coating oil and gas pipelines and, indeed, it has become standard industry practice.

The diversified technology company, 3M, pioneered the use of both the internal flow coating and FBE, supplying the former for more than 170 000 km and the latter for more than 135 000 km of pipeline worldwide.

WORLD’S PIPELINES

Craig Thomas, Corrosion Protection Products, 3M United Kingdom plc, describes how pipeline coatings are evolving to meet the

future needs of the oil and gas industry.

– inside and out

Increased flow of gas - increased throughputIncreases in capacity of 14 – 21% and even higher are possible with internally coated pipelines, according to research carried out by a number of oil and gas companies.1 Yet it is generally accepted that even a mere 1% improvement in throughput provides the financial justification for internal coating.

Data is readily available to illustrate that a reduction in surface roughness leads to increased flow capacity. One of the conclusions that can been drawn from a study of a 530 km section of the GasAtacama Pipeline in South America carried out by Zamorano (2002) is that the capacity of the coated section was considerably greater (at high pressure) than the uncoated section.

Y Charron et al (2005) also drew attention to the fact that “the use of relatively smooth (internal pipe) coatings provides a considerable saving in capital and operating costs compared to relatively rough coatings” and concluded that the savings would be even greater at a higher pressure. It was also cited that drag reduction techniques for the transportation of gas “are limited at the present time to the use of pipe internal coatings.”

Those improvements in capacity are now the norm as the long and successful working relationships between pipe coaters and manufacturers have resulted in the ability to create very high standards of smoothness inside pipelines.

Corrosion protection in storageThe degree of debris cleaned from an uncoated pipeline can vary depending on a number of factors. Several examples have been reported, concluding that up to 150 000 kg of debris can be cleaned from an uncoated pipeline measuring 250 km in length.

When uncoated pipelines are flooded with sea water, the extent of corrosion can be considerable. John Grover of BJ Process & Pipeline Services stated in a 2006 report that an estimated 157 000 kg of corrosion debris was removed from a 161 km section of 36 in. diameter pipe with a wall thickness of 14.3 mm only three months after total immersion in tropical sea water. He also said that: “Internal coating should be considered (for gas pipelines) not just on the merits of flow efficiency, but also for corrosion protection and ease of cleaning and drying.”2

The design parameters of subsea pipelines can vary hugely as can the environmental and sea conditions in which they are laid. Consequently, the provision of other specific case study data is difficult from the point of view of a pipe coatings manufacturer. Nevertheless, it is possible to give an appreciation of the order of magnitude of corrosion debris that could be formed from a larger (370 km x 48 in. diameter) thicker-walled (25.4 mm) uncoated offshore pipeline after a period of six months; it having been fully flooded with sea water. It can be estimated using the same rates of corrosion and identical engineering calculations as above, that five to six times the weight of corrosion products might have to be removed by pigging due to pre-commissioning.

However, as increasingly stringent regulations governing the disposal of scale and rust debris into the sea/environment are

Figure 1. 44 in. steel pipe internally coated with 3M Scotchkote Epoxy Coating EP2306 HF for the Langeled gas pipeline.

Figure 2. 48 in. steel pipe coated internally with 3M Scotchkote Epoxy Coating EP2306 HF (75) for supply into the Netherlands.

Figure 3. Steel pipe coated with a 3M Scotchkote Internal Flow Coating, creating a smooth, low friction surface.

November Reprinted from World Pipelines

being applied, it has become industry practice is to blast clean the pipe and apply the internal flow coating prior to the pipes leaving storage for transport to the pipeline site.3 This prevents rust from reforming, thus eliminating the need for additional pre-commissioning work, which can be very substantial in terms of time and cost, particularly for pipes stored in a marine environment.

Faster commissioning (inspection)Internally coated pipework also dries quickly after hydrostatic testing, thus providing easier and faster commissioning of the line. Testing and any robotic inspection procedures are also greatly simplified by the improved mobility of the equipment travelling down an internally coated pipe. These points reduce the risk of unnecessary and costly delays in the budgeted transmission date and, arguably, justify the cost of internal coating on this point alone.

Statoil reported in 2005 that it made the decision to apply an internal epoxy coating - 3M Scotchkote Epoxy Coating EP2306 HF (formerly Copon EP2306 HF) to the Langeled gas pipeline in order to increase transport capacity and reduce pig wear. The company also claimed that the amount of millscale and corrosion products, which would have required pigging, was reduced. Statoil also stated that pigging distances of up to 800 km could be feasible, when carefully designed pigs were used in combination with a smooth internal surface created by the internal flow coating.

Statoil also reported that internal coating of the line also allowed the pipeline to dry faster after dewatering, leaving less free water in the pipeline due to the smooth action of the pigs.

Reduced energy costs in pumping and compressor stationsAnother important factor to which an internal flow coating can make a significant difference is pumping/compression costs, which are significantly reduced during the lifetime of the pipeline. These reduced energy costs can provide a financial payback within three to five years of service. It may also be possible to achieve further savings by reducing the number of compressor stations, or compressor size and capacity.

The Zamorano (2002) study also concluded that fuel gas costs for the compressor stations alone, which were situated along the 1200 km length of the GasAtacama Pipeline (20 in. OD), were 26.9% lower on the coated section than the uncoated.

Another example has been given by Shell Global Solutions, which reported in 2005 that it had had positive experiences with the use of internal flow coatings and the associated CAPEX savings. The example Shell cited related to a 250 km pipeline. For uncoated pipe with an assumed surface roughness of 50 µm, a pipe diameter of 26 in. is required, whereas for a pipe lined with an internal flow coating with a surface roughness of 10 µm, a 24 in. OD pipe is sufficient. This represents a potential cost saving of 5% and an implied CAPEX saving of some 2 - 3% on total pipeline cost. The latest internal flow coatings, such as those manufactured by 3M, have a surface roughness of 1 - 3 µm.

The following economical and technical benefits can aso be achieved:

x Low capital cost.

x Reduced commissioning costs.

x More effective pigging/scraping.

x Sealed surface – product purity.

x Diverse pipeline use – easier product switch.

x Rapid payback.

x Reduced valve maintenance.

x Minimal sidewall deposition.

x Improved flow pattern.

x Simple application.

In short, solvented, thin-film epoxy flow efficiency coatings have served pipeline operators very well for several decades. However, their high volatile organic compound (VOC) content is increasingly considered environmentally undesirable and ultimately unsustainable. But the advent of a new generation of ‘high solids’ (reduced solvent content) and 100% solids flow coatings - all fully approved to international standards - enables the environmental impact of internal coating processes to be minimised without compromising coating performance. Higher solids coatings have also shown the unexpected benefit of reducing the surface roughness of internally coated pipe and thus providing better performance.

Figure 4. Factory application of 3M Scotchkote Fusion-Bonded Epoxy Coating.

Figure 5. Pipe coated with 3M Scotchkote Fusion-Bonded Epoxy Coating 206N being transported by rail to site.

November Reprinted from World Pipelines

External protectionHere are some of the features and benefits of fusion-bonded epoxy coating to protect against external corrosion of the pipe.

The main ways to protect underground pipelines from corrosion are external coatings and cathodic protection. According to J. Alan Kehr, a leading American expert on pipeline coatings, external pipe coatings are “intended to form a continuous film of electrical insulating material over the metallic surface to be protected.4 The function of such a coating is to isolate the metal from direct contact with the electrolyte, interposing a high electrical resistance so that electrochemical reactions cannot occur.”

FBE coating systems are highly effective in the prevention of under film corrosion; they offer excellent barrier properties. Kehr states that the oxygen permeability of FBE is less than 20% that of polyethylene (PE). On the one hand, FBE is subject to a higher rate of moisture permeability. On the other, PE carries a much lower moisture transmission rate than FBE, but at a higher oxygen/chloride rate. But when FBE and PE are used together, their properties can work in tandem to create a highly effective barrier.

Single-layer FBE and three-layer polyolefin (3LPO) are considered to be the most commonly used external pipe coatings in the world. Use of dual-layer FBE coatings has also increased in recent years on account of their combined properties. Three-layer FBE also has its place in the pipe coating industry portfolio, as it can fulfil a number of environmental requirements.

Single-layer FBESingle-layer FBE has proven performance in both onshore underground and offshore subsea environments. It has proven to be an effective corrosion-resistant barrier for line pipe, field joints, fittings and bends. Since its first use in New Mexico in 1960, FBE coating has remained the external pipe coating of choice in North America. The benefits of a single-layer coating system are excellent adhesion to steel; non-shielding to cathodic protection (CP); good resistance to biological, insect, termite and root attack; ease of installation; good abrasion and gouge resistance; and good impact resistance.

Dual-layer FBESince their introduction in 1991, dual-layer powder coatings have also gained popularity for use with pipelines operating at a high temperature. A relatively low-cost solution, the coating is not only non-shielding to CP, but is also resistant to damage - almost on a level with three-layer polypropylene (3LPP) and three-layer polyethylene (3LPE).

In 1998, this system was enhanced through the optional addition of an abrasion-resistant outer (ARO) coating to provide a tough outer layer when the pipe was to be installed by means of directional drilling.

Dual-layer FBE offers the excellent performance and installation characteristics of single-layer FBE, but also provides superior damage resistance with only a minimal reduction in flexibility.

Three-layer PE or PP coatingsThe 1980s saw the introduction of three-layer PE or PP coatings in Europe. They comprise (1) a FBE primary coating, (2) Polyolefin-adhesive or tie-layer and (3) Polyolefin topcoat and are based on earlier single- and two-layer systems.

The thick layer of polyolefin, which provides a high level of damage resistance, is deemed to facilitate installation under conditions of a harsh environment or inexperienced handling in the factory or on-site. The other benefit of a three-layer system is its performance under conditions of elevated service temperature; here the low moisture permeation rate of the polyolefin’s topcoat is key.

Naturally, there is a trade-off between the increased cost of the three-layer system and the potential savings from for example reduced use of graded or imported backfill material.

ConclusionBoth internal and external coatings for pipelines are now standard practice with the economic benefits well catalogued by thorough scientific research on a number of different installations.

What is certain is that coatings technology - in many cases led by 3M - is constantly evolving to provide better protection as the oil and gas industry is forced to explore and produce from ever more difficult reserves and demanding environments; environments that will provide ever more challenges for pipeline designers, manufacturers and operators. Replacing a corroded length of pipe may be relatively easy above ground in the Middle East; at a mile below the Gulf of Mexico it is a different matter altogether!

References1. FASOLD, H-G., and WAHLE, H-N., Einsatz neuartiger elektronischer Duck- und

Temperatur-Meßgeräte bei Feldgmessungen in Ferngasnetz, gwf Gas-Erdgas 133/Nr. 3 (1992). SINGH, G., and SAMDAL, O., ‘Economic Criteria for Internal Coating of Pipelines’, 7th International Conference on Internal and External Protection of Pipes, London, England (21 - 23 September 1987). KUT, S., ‘Liquid Internal and External Pipe Coatings for the Oil and Gas Industry’. Petrotech 2001 – 4th International Petroleum Conference, New Delhi, India (9 - 12 January 2001). FOGG, G. A., and MORSE, J., ‘Development of a New Solvent-Free Flow Efficiency Coating for Natural Gas Pipelines’. Rio Pipeline 2005 Conference & Exposition, Rio de Janeiro, Brazil (17 - 19 October 2005). THOMAS, C., ‘The Inside Track’, World Pipelines, August 2006. THOMAS, C., ‘Subsea Coating Successes’, World Pipelines, April 2007.

2. GROVER, J., ‘Mitigating Threats: Strategies in Managing Offshore Pipelines’, Pipeline (Dubai) Magazine, October 2006. GROVER, J. L., ‘The Impact Of Offshore Pipeline Installation And Pre-Commissioning On Future System Integrity’, OSEA Production Conference, 7 December 2006.

3. The Food and Environment Protection Act (FEPA) 1985. The Coastal Protection Act (CPA) 1949. The Petroleum Act 1998. Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter, 1972 and 1996.

4. KEHR, J ALAN, RAU MARTIN and SIDDIQUI EMRAN, ‘Fusion-Bonded Epoxy (FBE) and Dual-Layer FBE Materials Provide Enhanced Performance For Pipeline Installation’, ASME India Oil Gas Pipeline Conference, New Delhi, India (16 - 18 March 2009).

3M and Scotchkote are trademarks of 3M Company.

November Reprinted from World Pipelines