11. Pipeline Protection Systems

Pipeline integrity for durations well above the nominal 25-35 years of service is an important aspect in any pipeline’s design, construction and operation. Pipelines should not fail during their entire service life because such failures could lead to human and economic costs. As the public’s perception of pipeline failures is (generally) much worse than the actual human and economic failure costs, considerable resources have been dedicated to protect the pipes against any potential damage that could lead to pipeline failure.

As the majority of installed and planned onshore transmission pipelines around the world are steel pipelines, this document will focus on the protection of steel pipes.

In order to ensuring a service life without failure, we need to apply a life-cycle approach to the steel pipe protection, so that we avoid damage and failure during all the steel pipe’s life stages:

Pipe transportation – from pipe mill or coating facility to temporary storage yards or to the right-of-way

Pipe handling – loading, unloading at different locations

Pipeline installation – stringing, lowering in, backfilling

Pipeline service life until decommissioning

The industry has been trying for decades to target the most common causes of onshore pipe damage and failure. In this context, the statistical data available for the onshore transmission pipeline systems – both gas and liquids – show that mechanical impact damage (including third-party damage and construction/repair damage) and external corrosion represent the cause for between half and two-thirds of the reported onshore pipelines incidents and failures*.

Corrosion is an electrochemical phenomenon that leads to the degradation of the steel pipe material and could ultimately cause pipeline failure. There are multiple ways of preventing corrosion or protecting the pipe against it, such as the use of corrosion-resistant alloys, steel pipe design corrosion allowance, external anti-corrosion coatings and cathodic protection (CP) systems. Some prevention and protection systems are called passive systems, such as external anti-corrosion coatings for line pipe (discussed in Section 11.1), the field joint area (Section 11.2) and for other pipeline components such as bends and fittings (Section 11.3), whereas others are considered active prevention and protection systems, such as the cathodic protection systems (discussed in Section 11.8).

Mechanical damage can be sustained when the steel pipe suffers an external impact or penetration from rocks, outcrops, construction equipment (excavators, backhoes, drills), other pipe joints etc. There are multiple ways of preventing mechanical damage and protecting the pipe and its coatings, such as pipeline above-ground markers, call-before-you-dig numbers, sand bedding and padding, concrete coatings, mechanical padding with select backfill etc. The most common mechanical protection systems are reviewed in section 11.4.

Internal coatings are used to increase the flow efficiency for natural gas pipelines and to mitigate corrosion damage to the steel pipe. The most common internal coating systems are reviewed in section 11.5.

More recently, onshore insulation systems have been developed for the external anti-corrosion protection and thermal insulation of pipelines operating at temperatures ranging from 85°C up to 650°C. These systems generally include a corrosion resistant coating, a thermal insulation layer and an outer jacket or protective topcoat and are discussed in Section 11.6.

In order to avoid the floatation phenomenon in onshore wet environments (such as lakes, river crossings or swamps) the industry has developed solutions to mitigate the pipeline buoyancy phenomenon. These solutions

are based on the extensive experience in mitigating the pipeline buoyancy phenomenon offshore and are discussed in Section 11.7.

Finally, as mentioned above, steel pipes and coatings can be damaged during each stage of the supply chain, including pipe handling (loading, unloading) and installation (stringing, lowering in), storage and transportation. Section 11.9 discusses risks and available solutions during these logistic operations.

11.1 Review of Key Mainline External Anti-Corrosion Coatings

The purpose of the mainline external anti-corrosion coatings is to isolate the pipe steel from the external environment (soil, air and water) and thus to protect the steel from corrosion damage that could lead to failure. The mainline coatings protect the whole length of the steel pipe except for the variable-length area where two pipes are joined – this area is usually protected by separate field joint coating solutions (assessed in the next section).

The mainline external anti-corrosion coatings can be categorized using several criteria:Coating materials – powder systems (based on epoxy resins), polyolefin systems (polyethylene, polypropylene), liquid systems, other materials (asphalt, coal tar) Except for the single-layer coatings, all the others usually have a primer layer (closest to the steel), one or more topcoat layer and sometimes an adhesive between two coating layersApplication method – electrostatic spraying, extrusion, liquid spraying, liquid painting, tapewrapping, hybrid application (electrostatic spraying/extrusion)Other categories are starting to be used, based on new criteria such as application temperature ranges, operating temperature ranges etc.The most widely used coatings in the industry are reviewed in the following sections. The list of coatings described below is not exhaustive, as other mainline external anti-corrosion coatings are also used in the onshore pipeline projects, but on a more limited scale. Appendix 11.1 provides a table comparing the strengths and weaknesses of the mainline coatings described below.

11.1.1 Fusion-Bonded Epoxy (FBE)

Fusion-bonded epoxy (FBE) coatings are thin film coatings based on epoxy-resin powder materials. Thickness and other coating configuration requirements can be found in the new EN ISO 21809-2 standard, as well as CSA Z245.20. Most FBE coatings are rated for operating temperatures up to 85°C in dry conditions and 65°C in wet conditions, but new products have been developed and are currently developed for higher operating temperatures.

FBE coatings were separately developed in Europe and North America and are usually applied in specialised coating facilities in powdered form by electrostatic spraying. The pipes are pre-heated and then blast-cleaned. The pipe surface is then inspected for any defects and the pipe is then washed and rinsed. Induction heating then brings the pipe to the temperature required for the spraying of the epoxy powder. The epoxy particles flow, melt and bond to the steel.

The next step is to cool down the pipe through water quenching. Finally, the pipe is inspected for coating defects (known as holidays) and then loaded out for storage.

Fig.1 – Fusion bonded epoxy (FBE) external coating

FBE coatings have undisputed benefits for the users. They offer excellent corrosion protection and excellent adhesion properties. FBE coatings are very flexible, resistant to soil stresses and have good handling characteristics. They are usually used in pipeline projects that have standard requirements – i.e. do not have challenging terrain configurations, soil types, climatic conditions, exposure to water/moisture or harsh storage and handling conditions.

For the external anti-corrosion field joint coatings that are most commonly used with FBE mainline external anti-corrosion coatings please see section 11.2.

11.1.2 Dual-Layer Fusion-Bonded Epoxy (2L FBE)

Dual-layer fusion-bonded epoxy (2LFBE) coatings are also based on epoxy-resin powders. Their thickness and minimum technical performance requirements are standardized in CSA Z245.20. Like the single-layer FBE coatings, most dual-layer FBE coatings are rated for temperatures up to 85°C in dry conditions. Dual-layer FBE coatings are usually made of a fusion-bonded epoxy primer, similar to the coatings in section 11.1.1 and, depending on the targeted application, a tougher FBE topcoat, usually called abrasion-resistant overcoat (ARO), or a high operating temperature FBE topcoat.

The application process for dual-layer fusion-bonded epoxy coatings is very similar to the one for singlelayer FBE coatings, with the two FBE layers being sprayed successively, and also takes place in a specialised coating facility.

Fig. 2 – Dual-layer FBE (2LFBE) external coating

Dual-layer FBE coatings are usually used in specialty applications that require high abrasion resistance, such as horizontal directional drilling (HDD) projects and offer improved handling, as well as higher abrasion and impact resistance than single-layer FBE coatings. Other dual-layer FBE coatings are used for high operating temperature environments where increased flexibility is considered a benefit.

For the external anti-corrosion field joint coatings that are most commonly used with dual-layer FBE mainline external anti-corrosion coatings please see section 11.2.

11.1.3 Three-Layer Polyethylene (3LPE)

Three-layer polyethylene (3LPE) mainline coatings are multilayer anti-corrosion systems consisting of a layer of fusion-bonded epoxy primer, a polyethylene-based adhesive layer and an outer layer (topcoat) of polyethylene. Their thickness and minimum technical performance requirements are the subjects of multiple industry and international standards such as DIN30670, NFA49711, CSA Z254.21 and the upcoming EN ISO 21809-1 (draft). Most 3LPE mainline coatings are rated for operating temperatures of up to 85°C

3LPE coatings are applied in specialised coating facilities. The pipes are pre-heated and then blastcleaned. The pipe surface is then inspected for any defects and the pipe is then washed and rinsed. Induction heating then brings the pipe to the temperature required for the spraying of the epoxy powder of the primer. The epoxy particles flow, melt and bond to the steel. The polyethylene-based adhesive and then the polyethylene topcoat are then successively extruded on the rotating pipe. The next step is to cool down the pipe through water quenching. Finally, the pipe is inspected for coating defects (holidays) and then loaded out for storage.

Fig. 3 - Three-layer polyethylene (3LPE) external coating

Each of the three 3LPE coating layers adds specific technical performance characteristics to the final coating system: the FBE primer offers excellent adhesion to the steel substrate, as well as an excellent corrosion resistance potential; the adhesive bonds the epoxy primer to the polyethylene outer layer; and the polyethylene topcoat offers very good damage resistance, making the whole coating system tougher, more durable and resistant to environment factors such as moisture penetration. 3LPE coatings are used in projects that present technical challenges, such as rough storage or handling conditions, challenging backfill material or harsh climatic conditions.

For the external anti-corrosion field joint coatings that are most commonly used with 3LPE mainline external anti-corrosion coatings please see section 11.2.

11.1.4 Three-Layer Polypropylene (3LPP)

Three-layer polypropylene (3LPP) mainline coatings are multilayer anti-corrosion systems consisting of a layer of fusion-bonded epoxy primer, an adhesive layer and an outer layer (topcoat) of polypropylene. Their thickness and minimum technical performance requirements are the subjects of multiple industry and international standards such as DIN30670, NFA49711, and the upcoming EN ISO 21809-1 (draft). Most 3LPP mainline coatings are rated for operating temperatures of up to 110° C.

The application process for three-layer polypropylene (3LPE) coatings takes place in a specialised coating facility and is very similar to the one for 3LPE coatings – described in section 11.3 – with the epoxy primer being applied by electrostatic spraying on the induction-heated rotating pipe, followed by the application of the adhesive layer and the extrusion of the polypropylene top layer.

Fig. 4 - Three-layer polypropylene (3LPP) external coating

Each of the three 3LPP coating layers adds specific technical performance characteristics to the final coating system: the epoxy primer offers excellent adhesion to the steel substrate, as well as an excellent corrosion resistance potential; the adhesive bonds the epoxy primer to the polypropylene outer layer; and the polypropylene topcoat offers very good damage resistance, creating the most durable and damage-resistant plant-applied external anti-corrosion coating systems. 3LPP coatings are used in projects that present technical challenges, such as rough storage or handling conditions, challenging backfill material or harsh climatic conditions.

For the external anti-corrosion field joint coatings that are most commonly used with 3LPP mainline external anti-corrosion coatings please see section 11.2.

11.1.5 Three-Layer Composite Coatings

Three-layer composite mainline coatings are multilayer anti-corrosion systems. As an example, a threelayer composite coating system currently supplied for onshore pipeline projects consists of a layer of fusion-bonded epoxy primer, a specially formulated polyolefin adhesive layer that achieves a strong chemical bond with the FBE primer and a fused mechanical bond with the topcoat, and an outer layer (topcoat) of polyethylene. The thickness and minimum technical performance requirements of the threelayer composite external coatings are the subjects of multiple industry and international standards such as CSA Z245.21, and the upcoming EN ISO 21809-1 (draft). Existing three-layer composite mainline coatings are rated for operating temperatures of up to 85° C.

Three-layer composite coatings are applied in specialised coating facilities. The pipes are pre-heated and then blast-cleaned. The pipe surface is then inspected for any defects and the pipe is then washed and rinsed. Induction heating then brings the pipe to the temperature required for the spraying of the primer epoxy powder. The epoxy particles flow, melt and bond to the steel. The polyolefin-based adhesive and then the polyethylene topcoat are then successively sprayed on the rotating pipe. The next step is to cool down the pipe through water quenching. Finally, the pipe is inspected for coating defects (holidays) and then loaded out for storage.

Fig. 5 - Example of a 3-layer composite external coating

Each of the three layers of the three-layer composite coatings adds specific technical performance characteristics to the final coating system: the epoxy primer offers excellent adhesion to the steel substrate, as well as an excellent corrosion resistance potential; the adhesive bonds the epoxy primer to the outer layer; and the topcoat offers very good damage resistance, creating a very durable coating system. Like 3LPP and 3LPE coatings, three-layer composite coatings are used in projects that present technical challenges, such as moisture penetration, rough storage or handling conditions, challenging backfill material or harsh climatic conditions.

For the external anti-corrosion field joint coatings that are most commonly used with three-layer composite mainline external anti-corrosion coatings please see section 11.2.

11.1.6 Tape Coatings

Tape mainline coatings are multilayer anti-corrosion systems. As an example, a tape coating system consists of a layer of liquid epoxy primer, an adhesive layer, and an outer layer (topcoat) of polyethylene. The thickness and minimum technical performance requirements of a tape coating system are described in DIN30670. Existing tape mainline coatings are rated for operating temperatures of up to 60°C.

Tape coatings are applied in specialised coating facilities or in the field. The pipes are blast-cleaned, then the pipe surface is inspected for any defects. The pipe is then washed and rinsed. The epoxy primer is usually applied in liquid form (painting, brushing). The adhesive layer is then applied. The polyethylene topcoat tape is finally wrapped on the pipe. Finally, the pipe is inspected for coating defects.

Tape coatings are used in certain markets in projects that need good damage resistance.

For the external anti-corrosion field joint coatings that are most commonly used with tape mainline external anti-corrosion coatings please see section 11.2.

11.2 Field Joint Anti-Corrosion Coatings Selection Guide

High performance pipeline corrosion protection and insulation coatings have been developed to meet the demanding requirements of current pipeline operating and field conditions. A variety of pipelinecoating technologies are available and selection has evolved along geographical lines.

These coating decisions are generally based on the owner-company or engineering company preferences, but also on the pipeline construction and operating conditions. As an example, coating damage is a real concern in regions where limited transportation infrastructure, rough pipe handling, aggressive backfills and high populations are prevalent. This creates the need for robust, multi-layer coatings.

Once the coated pipe is delivered to the right-of-way and pipeline welding begins, then application of the field joint corrosion protection must commence.

There are several types of commercially available external anti-corrosion and insulation field joint coatings. For the purposes of this document, the specific types of field joint coatings have been identified as being most suitable for use with the various mainline coatings.

Aside from the mainline coating compatibility the criteria for determining which field joint coating to use encompass a number of variables. Pipe diameter, operating temperature, construction conditions, backfill, soil conditions and contractor capabilities all affect coating choice. Appendix 11.2 outlines the various mainline anti-corrosion coatings along with the most suitable field joint coatings and relevant standards.

While mainline coatings are applied in consistent factory environments, field joint coatings are applied in a variety of conditions which the photos below depict.

Fig.6 - Application of field joint coating protection in desert conditions

In desert conditions, sand storms and huge day/night temperature fluctuations present special problems.

Fig.7 - Application of field joint coating protection in cold climates

Cold climates require additional equipment and expertise to deal with the low temperature construction conditions.

The paragraphs below provide a brief description of the most common onshore anti-corrosion and thermal insulation field joint coatings in use today.

11.2.1 Fusion Bonded Epoxy (FBE)

Fusion-bonded epoxy (FBE) coatings are thin film coatings based on epoxy-resin powder materials. They can vary in thickness depending on specification and be applied as single layer or dual layer coatings. For the purposes of field joints, FBE is only recommended for use with FBE mainline coatings due to the high pre-heat temperatures required by certain FBE materials, which could damage other types of mainline coatings. Prior to application, the field joint must be blast-cleaned to minimum Sa 2.5 and inspected for soluble salt contamination.

Induction heating is then used to bring the field joint cutback to the temperature required for the application (typically 240ºC) of the epoxy powder which is flocked on using manually held or semiautomatic spray nozzles/application equipment. The field joint is allowed to cool naturally or through water quenching. Finally, the field joint is inspected for thickness and coating defects such as holidays and then readied for burial.

Fig. 8 - Field-applied FBE joint coating

11.2.2 Two-Layer Polyethylene Heat-Shrinkable Sleeve (2LPE HSS)

These types of heat-shrinkable sleeves have been commercially available since pipeline coatings applied in manufacturing plants became commonplace in the early 1960s. They consist of a cross-linked and stretched polyethylene sheet coated with a mastic or butyl-based adhesive resulting in the 2-layer system. The application is direct to metal with surface preparation requirements varying from simple hand wire brushing to commercial blasting. No primers are required.

Application is done by preheating the field joint to a specified temperature (typical maximum of 80ºC), wrapping the sleeve around the field joint, securing a closure strip and heat-shrinking the sleeve using suitable propane or natural-gas-fuelled torches.

Fig. 9 - 2-layer sleeves ready for application

11.2.3 Three-Layer Polyethylene Heat-Shrinkable Sleeve (3LPE HSS)

Three-layer polyethylene heat-shrinkable sleeve systems consist of an epoxy primer and a heatshrinkable sleeve. In rare cases, the epoxy primer can be a fusion bonded epoxy but, more commonly, a 2-component, liquid epoxy. The heat-shrinkable sleeve consists of a cross-linked and stretched polyethylene sheet coated with a hot-melt, hybrid or polyethylene-based adhesive layer depending on the pipeline design service temperature.

The field joint must be blast-cleaned to minimum Sa 2.5 and inspected for soluble salt contamination. If the soluble salt levels are deemed as being too high, then remedial measures to remove the contamination and re-blast will be required.

Application is done by preheating the field joint to a specified temperature, applying the liquid epoxy primer to the steel cutback, force-curing the epoxy primer (typically 90 - 120ºC) then wrapping the sleeve around the field joint, securing a closure strip and heat-shrinking the sleeve using suitable propane or natural-gas-fuelled torches. Preheating and force-curing stages may be done with either induction heating or gas-fuelled torches.

11.2.4 Three-Layer Polypropylene Heat-Shrinkable Sleeve (3LPP HSS)

Three-layer polypropylene heat-shrinkable sleeve systems consist of an epoxy primer and a heatshrinkable sleeve. The epoxy primer is a 2-component, liquid epoxy. The heat-shrinkable sleeve consists of a cross-linked and stretched polypropylene sheet coated with a polypropylene-based adhesive layer. The field joint must be blast-cleaned to minimum Sa 2.5 and inspected for soluble salt contamination. If the soluble salt levels are deemed as being too high, then remedial measures to remove the contamination and re-blast will be required.

Application is done by preheating the field joint to a specified temperature, applying the epoxy primer to the steel cutback, force-curing the epoxy primer (typically heating to 175ºC), then wrapping the sleeve around the field joint, securing a closure strip and heat-shrinking the sleeve using suitable propane or natural-gas-fuelled torches. The force-curing stage must be done with induction heating.

Fig.12 – 3-layer polypropylene sleeve application

11.2.5 Three-layer Polypropylene Field-Applied Systems (3LPP, IMPP, FSPP)

Systems consist of a polypropylene tape or sheet (3LPP Tape), flame-sprayed powder (FSPP) or injection-moulded polypropylene (IMPP). Each of these systems consists of a fusion-bonded epoxy primer, a powder applied polypropylene adhesive and an outer layer of polypropylene applied by wrapping, spraying or injection moulding. All of these systems are applied using specialised application equipment. The methods of application may be proprietary to the service company and generally require specialised equipment and highly-trained applicators.

11.2.6 Adhesive Tape Systems (CAT)

Tape coatings are multilayer anti-corrosion systems. As an example, a tape coating system consists of a solvent-based liquid primer, an adhesive layer, and an outer layer (topcoat) of polyethylene. These systems often use two types of tapes such as a soft first layer for corrosion protection and a tougher second layer for mechanical protection.

11.2.7 100% Solids, 2-Component Liquid Epoxy or Polyurethane (2CLE, 2CPU)

Commonly referred to as “liquids”, most liquid coatings in use for pipeline protection are either 100% solids, 2-component epoxies or polyurethanes. The 2 components are “base (or polyurethane: polyol)” and “cure (or polyurethane: isocyanate)” parts, sometimes referred to as Part A (base) and Part B (cure). The base and cure must be formulated to work together and mixing a base from one manufacturer and cure from another is not possible. The cure component is formulated to impart various cure times depending on type of application and application environmental conditions.

Liquid epoxies are formulated using a variety of epoxy raw materials. A few high performance epoxies have operating service temperatures up to the 130ºC range. Liquid epoxies are applied to field joints of FBE-coated pipelines and appear to be most companies’ choice for pipeline rehabilitation projects. Polyurethane coatings are generally used as pipeline coatings for ambient temperature water pipelines or for lower operating service temperature conditions.

Liquid coatings are usually available in sprayable and brushable formats. The spray versions generally have a much faster set-up time and very limited “pot-life”. The extended pot-life of the brushable version provides adequate time for the applicator to mix and brush-apply the coating onto the pipeline section.

Fig. 13 – Liquid epoxy brush application

11.2.8 Pre-Insulated Pipe Onshore Field Joint Sealing and Corrosion Protection Selection Guide

The purpose of the field applied joint coating system is to maintain the continuity of the mainline coating across pipe connection points. In the case of pre-insulated pipes the field joint coating systems are required to provide not only anti-corrosion continuity but also thermal protection continuity. Moreover, similarly to the mainline pre-insulated coatings, the insulating materials used in the joints usually have to be isolated from the environment and therefore most joint protection systems used with thermally protected pipes are designed to provide sealed, jacketed protection across the adjoining jacketed mainline coated pipes.

The most common insulating materials used on pre-insulated pipes are polyurethane (PU) foams, mineral wools and more recently aero gels. The insulation is either supplied to the field in the form of half-shells or wrap-around blankets or, in the case of PU foams, it can be moulded on the pipe and filled or “foamed” at the job site. The insulation materials are rated through measurable methods such as the thermal conductivity coefficient, compressive strength, density, thermal life expectancy and operating temperature.

The selection of the pre-insulated field joints is governed by the operating environment of the pipeline (ex. above/below ground), geographical location, and operating temperature of the pipeline, pipe diameter, construction conditions, backfill method, soil conditions, contractor’s capabilities and required in-process testing.

The paragraphs below provide a comprehensive summary of the most common pre-insulated pipe field joint coating systems.

11.2.9 Heat-Shrinkable Casing System

The heat-shrinkable joint casing systems consist of an expanded high-density polyethylene (HDPE) casing which is attached to the mainline polyethylene jacket using either a hot melt adhesive or electrofusion process. There are several variations of heat-shrinkable casing systems and they can be categorized using the following criteria:Material type: cross-linked vs non-cross-linked HDPEApplication method: foam-in-place* vs pre-foaming (*casing used as a mould for field-injected PU foams)Casing sealing method: adhesive vs electrofusionSecondary sealing requirement: collar sleeves

The method and complexity of field installation as well as functional performance of the product are unique to each variant of the heat-shrinkable casing system. Appendix 11.2 contains a comparative table describing the strengths and weaknesses of the above described casing systems.

11.2.9.1 Cross-linked Heat Shrinkable Casing Systems

Cross-linked heat shrinkable casing systems are the most technologically advanced joint protection systems used with PU foam based pre-insulated pipe systems. As the name suggests these types of joint systems consist of cross-linked high density polyethylene (HDPE). Cross-linking of HDPE enhances the functional performance of the material and enables fast and simple field application of the product. One of the most notable features of the cross-linked material is its stability in hot climates. Cross-linked heat shrinkable casing systems do not pre-shrink due to the exposure to summer-like conditions as is the case with non-cross-linked casing systems.

There are several variants of cross-linked heat shrinkable casing systems available on the market. Some system designs allow the casings to be used as a mould during field injection of PU foam in addition to performing their primary function of sealing and mechanically protecting the joint. Other options include inspection of the

foam before sealing the joint off (see figure 14 below). There are also systems which allow field testing to verify the seal performance. The seal between the adjoining polyethylene jacket pipes is primarily achieved through hot melt adhesives.

Figure 14. “Foam in place” vs “pre-foamed” pre-insulated cross-linked joint casing systems

The sequence of the application steps for cross-linked joint casing system depends on the type of system: foam in place vs pre-foaming. In the case of foam in place systems, the casing is secured over a joint before the foam is injected into the cavity. The first step of the application includes preparation of the PE surface on the adjoining PE jacket pipes. The second step consists of pre-heating the jacket pipe, using suitable propane of natural-gas-fuelled torches, and wrapping the adhesive around the jacket pipes. The next step consists of centrally locating the casing over the joint and shrinking the applicable sections with suitable torches as described above. Upon verification of the proper installation of the casing, appropriated PU foam material is injected into the cavity formed by the casing.

In the case of the pre-foamed joint casing systems, the foaming of the cavity is completed as the first step of the system application. Removable external moulds are used to form the foaming cavity. The casing is applied after the foam is inspected and the application of the casing follows the same general steps as the foam in place systems.

Fig.15 - Typical pre-insulated pipeline joint coating operations

11.2.9.2 Non Cross-linked Heat Shrinkable Casing Systems

Non cross-linked heat shrinkable casing systems consist of expanded polyethylene tubes. Most projects involving these casing systems use them as moulds during field injection of PU foam in addition to their primary function of sealing and mechanically protecting the joints. Application of this type of casing is relatively slow, compared to cross-linked casing systems, and therefore shrinking of the entire casing (as is the situation with the pre-foamed casing systems) is impractical. Additionally, these casings have a tendency to pre-shrinking on the pipes when exposed to summer temperatures. Pre-shrinking makes the casings unusable as they cannot be moved over the joint. Another shortcoming of the non-crosslinked casing systems is their inability to maintain geometrical conformance to the shape of the pipe they embrace. To counter the relaxation of non-cross-linked casing systems, heat-shrinkable cross-linked collar sleeves are used on both ends of such casings.

The application of a non-cross-linked casing starts with the preparation of the PE surface on the adjoining PE jacket pipes. The second step consists of pre-heating the jacket pipe, using suitable propane or natural-gas-fuelled torches, and wrapping the hot melt adhesive around the jacket pipes. Alternatively, instead of preheating the adjoining PE jacket pipes and applying the adhesive strips, electro-fusion system components are wrapped around the adjoining jacket pipes. The next step consists of locating the casing over the joint and shrinking the applicable sections with suitable torches as described above. In the case of electro-fusion systems, after the shrinking step, the sides of the casing are then fused with the adjacent jacket pipes. Upon verification of the proper installation of the casing, an appropriate amount of PU foam material is injected into the cavity formed by the casing.

Fig.16 - Non-cross-linked joint casing systems with protective collars.

11.2.9.3 Heat-Shrinkable Sleeve Systems

Heat-shrinkable sleeve systems consist of cross-linked and stretched polyethylene sheets coated with adhesive layers. These systems are only applied on joints which have been pre-foamed using external removable moulds or where PUF half shells are used to provide the insulation at the joints. The application consists of pre-heating the adjoining polyethylene jacket pipes, wrapping the sleeve around the pipe, securing a closure strip and heat-shrinking the sleeve with suitable propane or naturalgas-fuelled torches.

Compared to casing systems, heat-shrinkable sleeve systems provide inferior mechanical protection continuity for pre-insulated pipe joints.

Fig.17 - Cross-linked heat-shrinkable sleeve installed on a pre-foamed joint of a PUF pipeline

11.3 Bends and Fittings

Bends and fittings are typically protected from external or internal corrosion by liquid coatings such as polyurethane or epoxy, or by polyolefin coatings applied by two different processes. These components are coated individually and the process is usually referred to as ‘custom coating application’.

The two processes employed for the application of polyolefin coatings are fluidised bed or flock spraying onto hot surfaces.

In the fluidised bed coating process, after pre-heating, the item is dipped into a bed of fluidising powder. This bed consists of two compartments, one on top of the other. The upper, larger compartment contains the coating powder. The lower compartment, or "plenum chamber", is a reservoir for pressurised air. A porous membrane, sometimes called a diffuser, separates the two compartments. Usually the membrane is made of canvas or a high quality filter paper. The porosity of the membrane is critical to the quality of the fluidisation of the powder. Compressed air is forced into the lower compartment. It diffuses through the membrane and moving upwards, still under pressure, passes between the fine powder particles that are contained in the upper compartment. As a result, the bulk density of the powder is reduced and this permits the preheated metal object to be lowered easily, without any resistance, into the now "fluidised" bed of powder. The powder behaves like a liquid and continues to do so, as long as the air is forced into the lower plenum chamber.

By careful agitation or controlled movement of the hot metal object underneath the surface of the "fluid" powder, the cold powder comes into contact with every point of the hot metal and fuses onto it. A thickness of between 300 and 750 microns is suggested in order to achieve the optimum potential of the coating material. Thicknesses outside the recommended range may be detrimental to the coating. Thicknesses above 1500 microns are to be avoided. The benefits of this process include: 100% coating efficiency; faster cycle times than other application processes; thicker coating providing functional protection, longer life, impact resistance but with higher material usage and superior edge coverage. However, this application process requires capital to be invested in the fluidised bed unit.

Flock spraying is sometimes called "powder spray coating". This method consists of blowing powder through a suitable spray gun onto metal items that have been preheated to a predetermined temperature. The powder hits the hot metal and sticks to it, where it melts and gradually fuses to form a homogenous coating. This method of powder application is particularly suited to coating large or oddshape objects, which would otherwise be impractical to process by the fluidised bed process. Flock spraying has the added benefit that more than one coat of powder can be applied, if the metal object is carefully re-heated before re-spraying. This process can be repeated several times, if necessary, in order to build up and achieve the desired coating film thickness. This method is used for the application of 3 layer polyolefin coatings where FBE, adhesive and top coat layers can be successively applied. Maximum thickness is limited by the application method to not more than 2mm. Other benefits of this application process include: recycling of the coating material is possible; no major investment in equipment. However, this process has a lower coating efficiency than the fluidised bed process. The steps of a typical custom coating process are detailed in Appendix 11.3.

11.3.2 Internal Protection of Bends and Fittings

The use of internal coatings for corrosion protection, electrical isolation and deposit mitigation is a common industry practice. A wide variety of pipeline components such as elbows, bends, valves, pig launchers, and isolation spools are manually coated using spray and/or flocking guns.

A wide variety of liquid or powder coating materials are employed. Careful selection of the coating material based on the intended service environment is essential in order to ensure proper coating adhesion and a long service life of the component. Some liquid coatings can cure at ambient temperatures which makes them useful for large surface applications such as tanks and vessels. Powder coatings require factory-applied coating

application because of the temperatures involved, but generally provide better chemical and temperature resistance versus typical liquid systems.

Fig 18 Internal Coating Materials for Immersion Service

A variety of internal coatings are used for corrosion protection in continuous immersion service. Coatings which cure by chemical reaction (for example epoxy, polyester, polyurethane and coal tar epoxy coatings) have proven to be the most durable materials.

Over the last 20 years epoxy based coatings have proven themselves to be very successful in immersion service. The success of fusion bonded epoxy (FBE) coatings is rooted in their excellent chemical resistance and long service life. FBE coatings are powder materials that are applied to a heated surface allowing the powder to melt and flow. Typically a liquid primer is first applied to allow for the maximum level of adhesion of the overall coating system to the metal substrate. During the ‘curing’ process, the primer and top coat react together and chemically cross-link, yielding a single system well adhered to the metal surface. In order to ensure proper application of FBE coatings the surface preparation is very important. The first step is to thermally clean the component to be coated at temperatures of up to 399°C. The part is then grit blasted with blast media, such steel grit or aluminium oxide. The blasting is done to a NACE # 1 White Metal Finish (SSPC 5), the aim being to obtain a surface structure (anchor pattern) rough enough to allow excellent mechanical adhesion and a surface clean enough to allow excellent chemical adhesion by the primer system.

Chemistry Characteristics

Epoxy Temperature limit 225ºF (107ºC), the amount of flexibility and temperature resistance are inversely related. Inherently have a fair amount of chemical resistance.

Phenolic Temperature limit 400ºF (204ºC), high abrasion and temperature resistance along with good chemical resistance. Can be brittle.

Epoxy Phenolic Temperature limit 250ºF (121ºC), produces a middle-of-the-road coating with good flexibility, temperature resistance, and chemical resistance.

Epoxy Novolac Temperature limit 400ºF (204ºC), excellent chemical resistance (generally better than straight phenolic), temperature resistance and flexibility close to a phenolic coating.

Table 1 Main internal coating systems for bends and fittings

11.3.3 Substrate Suitability for Custom Coating – General Guidelines

Not all substrates are suitable for the application of internal coatings. An assessment of the metal substrates suitability for coating should be done using DIN 14879-1:2005. The material to be coated should be free of all sharp edges and corners that could interfere with the coating’s ability to provide adequate physical coverage, and the metal substrate must be easily accessible to hand tools in order for proper surface preparation. Any weld beads must be ground smooth, providing a surface where an adequate anchor profile can be generated for proper coating flow and adherence. In order to obtain the desired anchor pattern (a surface roughness profile between 25-80 microns) the metal substrate requires blasting, usually with steel grit or aluminium oxide. Critical to the success of a coating system will be the ability to overcome the dimensional limitations and geometry of the material to be coated. All surfaces must be accessible not only for proper grit blasting but also for hand-held coating guns as well as proper quality control measurements.

Some coating applications call for thermal cleaning for the purpose of eliminating organic deposits, at elevated temperatures in excess of 370°C. Care should be taken with corrosion resistant alloys (CRA), as they could possibly suffer from some level of embrittlement after thermal cleaning. Other special tubulars i.e. nonmagnetic drill collars, cannot be thermally cleaned without changing the metallic surface structure. These special substrates are instead chemically cleaned prior to the coating application.

Fig 19. Metal Substrates Not Suitable for Custom Coating

Spiral & Weld Imperfections

Burrs & Longitudinal Chamfer

Weld Seam & Surface Imperfections

11.4 Mechanical Protection Selection Guide

As mentioned earlier, mechanical impact damage is one of the most common causes of onshore pipeline incidents. Pipelines thus need mechanical protection in order to avoid or reduce the damage from impacts. The mechanical protection need for each onshore pipeline project has to be addressed, whenever possible, at an early stage in the design and/or construction of the pipeline in order to ensure the integrity of the corrosion protection system(s) and thus the long-term pipeline integrity.

All the most common external anti-corrosion and insulation plant and field-applied coatings have an embedded basic mechanical protection potential coming from the intrinsic damage resistance of the raw coating materials. Multi-layer external coatings have been developed to specifically improve the basic mechanical protection potential of the single-layer external coatings. However, the basic mechanical protection potential that can be obtained at a reasonable total installed cost, even by using multi-layer external anti-corrosion coatings such as those detailed in section 11.1, is rather limited, especially during potential high-impact activities such as backfilling. For example, field trials have shown that even with the most impact-resistant coating systems, the maximum size of the backfill material that could be used during standard backfilling should be no more than 5-6 cm in diameter *2.

Therefore, the onshore pipeline industry has focused on developing supplementary mechanical protection systems that increase the damage resistance of the pipe and pipe coating during the various stages of their life-cycle.

In this context, as mechanical impacts from different sources can happen at any time during the life of a pipe joint, the supplementary mechanical protection systems can be categorized based on the time horizon of their protection:Protection during transportation – separation pads etcProtection during handling (loading in and out) and storage – protection pads, sand berms, wood pads etc.Protection during installation (lowering in, backfilling) – sand padding, concrete coatings, nonwoven geotextiles etc.Protection during pipeline’s service life – above-ground pipeline markers, coatings, concrete slabs etcWhole pipe life-cycle protection – including all stages above – selected plant-applied concrete coatings

The existing supplementary mechanical protection methods and systems can also be separated in several categories based on their location relative to the pipe:Above-ground systems – pipeline markers, ‘call-before-you-dig’ numbers, separation or protection pads etcBuried trench protection systems – tunnels, concrete slabs, steel plates or wires that protect or deny access to the pipeline trench etcBuried pipe protection systems – can be either protection systems that protect just part of the diameter or length of the pipe (such as foam pillows, sand bags etc) or systems that protect the whole diameter and length of the pipe (such as plant and field-applied coatings, sand padding, select backfill [mechanical padding], non-woven geotextiles, rock shield materials etc)

Supplementary mechanical protection systems can also be categorized based on the location where the protection is applied – in a specialised facility or in the field by a specialised contractor.

Based on these categories, for the purpose of this document, we are going to focus on the systems that protect the whole diameter and length of the pipe – the buried total pipe protection systems, both plantapplied and applied in the field.

The most widely used buried total mechanical protection systems in the industry are reviewed in the next sub-sections. Note that the list of systems described below is not exhaustive, as other systems are also used in onshore pipeline projects, but on a more limited scale.

*2 For some examples of such field trials, please see Optimization of Pipeline Coating and Backfill Selection, Espiner R., Thompson I, Barnett J, NACE, 2003 and other similar sources listed in the section’s Bibliography11.4.1 Concrete Coatings

Concrete coatings were created to offer supplementary mechanical protection to the pipe and pipe coating. When applied in a specialised coating plant, concrete coatings are the only mechanical protection systems in the industry that protect the pipe during the whole pipeline construction process (transportation to ROW, temporary storage, handling, stringing, lowering in, backfilling) and the entire pipeline service life.

Concrete coatings can be plant-applied (through side-wrap, spraying or impingement processes) or applied in the field – as form-and-pour or moulded concrete and are covered by the EN ISO 21809-5 (draft) standard. All concrete coatings are reinforced by either wire mesh, rebar cages or different types of fibres. While the reinforced concrete coating covers the pipe length, its field joint areas are protected by either field-applied reinforced concrete, wire-reinforced polyethylene open-cell sheets or wood slats. Some concrete coatings are wrapped in a perforated polyethylene outer tape that prevents concrete spalling and allows curing (the PE tape can then be removed at the customer’s demand). The minimum thickness of the concrete coatings is 6-7 mm (fibre-reinforced concrete), while the maximum that can be applied is 150 mm for the side-wrap process and

around 200 mm for the impingement and form and pour processes. Some of the fibre and wire mesh reinforced concrete coatings with a thickness of up to 25 mm are bendable according to the industry specifications – 1.5° per pipe diameter. Some of the fibre-reinforced and higher thickness concrete coatings are not bendable, reducing their ability to follow the terrain configuration in the field.

Fig. 20 - Bendable plant-applied concrete coating

Concrete coatings offer some of the highest mechanical protection among the existing systems whilst taking up little space. A 25 mm wire mesh reinforced concrete coating, for example, offers the equivalent impact protection of a layer of 300 mm of sand padding. Some concrete coatings are capable of resisting penetration from trench bottom outcrops, if specific point loading parameters supplied by the applicators are satisfied.

If available in the project’s region, concrete coatings offer the highest flexibility to pipeline designers and contractors, as they have no limitations of use in terms of terrain configuration (they work very well on steep slopes), trench material type (large rocks) or climatic conditions (very cold climates), as all the other systems have. When applied in a plant, the concrete coatings do not delay the construction of the pipelines and do not require additional material, equipment or manpower on the right-of-way. On the other hand, while reducing other pipeline construction costs, concrete coatings increase the weight to be transported and handled to and on the right-of-way. Non-bendable concrete coatings are also less useful, as the coated pipe cannot follow the terrain configuration. Field-applied concrete coating is slow, can delay the pipeline construction and usually cannot offer the quality guarantee of a plant-applied coating.

11.4.2 Sand Padding

Sand bedding and padding is one of the most frequently used supplementary mechanical protection system during the last decades. This system only protects the pipe against impacts during its lowering in, trench backfilling and during its service life after installation.

Sand padding is applied in the field. After the pipeline trench is opened, sand or fine gravel is brought in using sand trucks, usually from a commercial sand pit in the region. The fine material is dumped next to the trench. A first layer of sand, the sand bedding – usually 20-30 cm thick – is then placed on the trench bottom for protection against rock or other hard outcrops. The pipe is then lowered in and another layer of sand or other fine material is placed (padded) around and on top of the pipe – usually another 20-30 cm on top of the pipe. The trench backfill is finished with some of the material excavated from the trench and the topsoil. Finally, the surplus spoil – the original trench material displaced by the imported sand/fine gravel, such as shot rock, cobbles, boulders – is usually removed from the right-ofway and disposed of – at a cost – at a different location.

The sand padding provides adequate mechanical protection to the pipe and pipe coating and, by changing the thickness of the top sand layer can withstand backfill impacts from virtually any size of trench material. Sand also offers a certain degree of protection against penetration from trench bottom outcrops, as long as there is sufficient sand to ensure outcrops are not in direct contact with the pipe.

Sand padding has some limitations in terms of climatic conditions – sand can freeze in large chunks in cold weather, making padding more difficult or impossible. Its protection can also be impaired by sand washouts on steep slopes or in other draining areas.

Sand padding needs additional material (sand), equipment (sand trucks, padding machines), additional manpower (truck drivers, one bedding team after the trenching team and one padding team after the lower-in team), space (sand truck access and sometimes temporary sand dump areas) on the right-ofway and adds surplus trench material disposal costs.

11.4.3 Select Backfill (Mechanical Padding)

The select backfill method (also called mechanical padding) was created to offer mechanical protection to the pipeline by taking advantage of the local material that was excavated at the opening of the trench. This method protects the pipe only during its lowering in, trench backfilling and during its service life after the installation.

The select backfill (mechanical padding) is applied in the field. The local material excavated at the opening of the trench is fed into the mechanical padding machine, where it is screened based on size. The finer material is then placed under, around and on top of the pipe for protection against large backfill materials – the layer under and on top of the pipe are each usually 20-30 cm thick. The trench is then closed by adding the remaining larger size trench material and the topsoil.

Fig. 21 – Mechanical padding machine

The select backfill method provides adequate mechanical protection to the pipe and pipe coating and, by changing the thickness of the top padding layer can withstand backfill impacts from virtually any size of trench material. The biggest advantage of this system is that only the original trench material is used, and there is no requirement for imported fine materials (sand etc). Select backfill has the best results with dry granular trench materials.

The performance of this system is reduced in regions with wet, silty or clay trench materials. There are some limitations in terms of climatic conditions – mechanical padding is more difficult when trench materials are frozen. This system is also not very practical on steep slopes or areas with reduced or no right-of-way access for equipment.

Mechanical padding needs additional equipment (mechanical padding machines), additional manpower (padding machine operators) on the right-of-way, as well as additional time for setting up and demobilizing the padding machines.

11.4.4 Rock Shield and Non-Woven Geotextile Systems

Rock shield materials are polyethylene or PVC-based solid sheets or open-cell extruded pads; nonwoven geotextiles are needle-punched polypropylene fibre-based rolls. These materials are designed to protect the pipe and pipe coating against damage during pipe lowering in, trench backfilling and during the pipeline’s service life after installation.

Rock shield and non-woven geotextile materials are installed on the pipe in the field outside the trench, in a spiral “cigarette” wrap application using tape or Velcro to secure the seam. Smaller diameter pipes can be longitudinally wrapped. Rock shield materials are available in rolls of various styles, sizes, thicknesses (usual

range 6-11 mm per layer for rock shield and 4-14 mm per layer for non-woven geotextiles) and technical performance properties.

Fig. 22 – Non-woven geotextiles installed on pipe

Rock shield and non-woven geotextile materials offer good mechanical protection to the pipe, especially in gravel/small cobble trench materials: according to the suppliers, the strongest multi-layer non-woven geotextiles can withstand impacts from backfill material up to 10 cm in diameter without any damage (holidays) to the anti-corrosion coating or the pipe. They do not protect against penetration from trench bottom outcrops and have to be combined with other systems (sand) in order to create some degree of protection.

Rock shield and non-woven geotextile systems will not provide adequate mechanical protection in rocky trenches and with largebackfill material. A rock shield could produce cathodic protection system shielding if it is not an open-cell material, while, based on the information available from the industry, the impact of the non-woven geotextiles on the cathodic protection system is unclear and needs further research.

Installation of rock shields or non-woven geotextile materials could slow down the pipeline construction and needs additional material (rock shield, geotextile sheet), manpower (field installation crew) on the right-of-way, and sometimes other mechanical protection systems (sand, select backfill). Costly wastage can also arise if the rock shield sheet width does not match the pipe diameter. The protection efficiency will be dependent on the quality of the field installation crew’s work.

11.4.5 Mechanical Protection Selection Guidelines

In order to make the most informed choice for the supplementary mechanical damage prevention and protection of the onshore pipelines, the parties involved should use the following categories of selection criteria:

Technical performance criteria – such as time horizon of the protection (e.g. is this whole lifecycle protection or just protection during installation?); impact resistance during backfill (maximum allowable backfill size); resistance to penetration (from trench bottom etc); flexibility (impact on pipe cold bending); impact on the cathodic protection system etc.Pipeline design and constructability criteria – such as limitations in terms of trench material, terrain configuration, harsh climatic conditions; right-of-way allowance and access limitations; increased contractor risk (additional equipment and manpower needed, construction delays, potential future remediation cost risk etc); regulatory limitations (pipeline operator specifications, government/industry standards and regulations) etc.Environmental criteria – minimum impact on the right-of-way and surrounding environment during pipe transportation, handling, installation and service life – impact can be measured by vegetation loss, increased erosion potential, volume of excavated and landfilled trench material, fauna and flora disturbance etc.Economic criteria – system availability in the region; total installed cost (including the material supply cost, but also all the direct and indirect mechanical protection installation costs)

Please find in Appendix 4 a table comparing the discussed supplementary mechanical protection systems based on the criteria listed above.

In terms of selection methodology, based on the criteria categories above, and if the basic mechanical protection provided by the external anti-corrosion coatings is not enough for the needs of a pipeline project, the stakeholders can take a three-step approach in selecting the optimal supplementary mechanical protection system or combination of systems (as some of the systems discussed above can be combined for increased mechanical protection):Shortlist the preferred supplementary mechanical protection systems or combinations of systems based on the pipeline project specifics and on technical, design, constructability and environment impact criteria – see table in Appendix 1 for helpOnce the most interesting systems or combinations of systems are selected, check the availability of those systems in the project’s region or in a region with easy logistic access to the project’s regionChoose among the available short-listed systems or combinations of systems the option with the lowest total installed cost or the best cost/benefit ratio

The selection of the supplementary mechanical protection solution should be done, as the selection of the mainline and field joint coatings, as early in the pipeline design and construction as possible, in order to ensure consistent and cost-effective corrosion and mechanical protection for the pipeline.

Although the general technical performance of the different supplementary mechanical protection systems is well understood in the industry, we recommend that further research be done to clarify some technical performance aspects such as the comparative resistance of the different systems to penetration from outcrops in the trench bottom, re-validate the maximum backfill size that is allowed for the different systems and the impact of increasing pipeline operating temperature on the performance of the different mechanical protection systems.

11.5 Internal Coating

11.5.1 Internal Coatings’ Purpose

Internal coatings are used to increase the flow efficiency for natural gas pipelines and to mitigate corrosion damage to the line pipe. Internal plastic coatings (IPC) have a very low surface roughness in relation to the steel pipes they protect. This impacts pipe hydraulics and provides a surface change that will aid in the mitigation of organic and inorganic deposit formation, increasing the economic justifications for using IPC.

The surface finish of an internally plastic-coated pipe has a fraction of the surface roughness of bare pipe, reducing the friction generated at the surface during product flow. The usage of IPC in gas pipelines have shown a reduction in friction coefficient of up to 50% resulting in a transmission increase of 15 to 25% (2) (4). The potential pipeline transmission increases are more pronounced in smaller sized pipes, as well as systems with higher Reynolds numbers where flow is turbulent.

Fluid flow is characterized as laminar, or turbulent with most gas pipeline having turbulent flow conditions. Even for systems which are characterised by turbulent flow conditions, a minute laminar (sub) layer exists at the pipe wall, and the extent of the laminar sub layer is dependent upon the surface roughness of the pipe surface. Under laminar flow conditions, fluid and particle movements are more predictable. The greater the laminar sub layer extends into the pipe ID the less friction is a factor on produced flow. In uncoated pipe the surface will have a greater physical roughness which will increase turbulence leading to greater friction being generated during flowing conditions. The overall effect of this friction will vary based on the type of product being transported and the rate of flow. Hydraulic modelling software is now available to conduct simulations inputting varying surface roughnesses in an effort to identify any possible increases in product throughput and also for research into the modelling of multiphase flow that is becoming ever more important as large offshore developments call for the pumping of gas, and oil/water emulsions in pipelines over extended distances.

Internal plastic coatings aid in maintaining fluid purity by mitigating product interaction with the bare steel substrate which can lead to harmful reaction products. They also aid in the prevention of organic and inorganic deposits adherence (3). Deposits of corrosion by-product, water born scales and microbiological ‘biofilms’ are usually encountered in low spots of the pipeline, i.e. road crossings, or at the foot of a mountain and can result in premature pipeline failure due to corrosion (mostly localised pitting corrosion).

Undesirable bacteria such as acid-producing bacteria (APB) and sulphate-reducing bacteria (SRB) associated with water transmission pipelines form dense ‘biofilms’ which can result in pitting corrosion of line pipe. The biofilm provides a habitat for the microorganisms, providing shelter from bulk fluid movement and contact with most surfactant biocides able to effectively kill off the bacteria. Biofilm deposits can require extensive pipe pigging operations in addition to costly biocide treatments in order to control corrosion. The material composition of the surface has little effect on the biofilm development (5) or adhesion to the substrate, bacteria will secrete polysaccharides and attach to metals as well as to plastics. The smooth surface (roughness) of coated pipe will however expose these microbiological deposits (biofilms) to a much higher degree of sheer stress from the bulk fluid movement compared to bare pipe. The higher surface roughness of uncoated pipe helps shield the bacteria from the bulk fluid movement, enhancing growth conditions for bacterial colonies. Coated pipe also provides an effective barrier (barrier coating) against the detrimental and corrosive effects of contact with the bacteria metabolic byproducts such as H2S and/or acids.

In water-injection systems where produced water from various formations and/or other sources such as river water or seawater are mixed, the potential for the development of scale deposits in the pipeline line is a possibility. Coatings can also provide benefits for production systems which are prone to have scale deposits forming on the pipe surface. As in the case of bacteria, the low surface roughness of coated pipes exposes the scale to higher sheer stress from the bulk fluid movement, additionally the coated surface provides reduced mechanical binding locations for the crystal lattice of the developing scale. Improved fluid purity will also increase the service life of pumps while reducing their power requirements (6) and resulting in cleaner filtration units.

Additional benefits of using internal flow coatings include: corrosion protection of the pipe during storage prior to installation; improved pigging conditions; faster drying times; and improved conditions for visual inspection of the internal surface of the pipe walls. Pipe storage periods prior to construction should be kept to a minimum as studies (1) have shown that the surface roughness of bare pipes will increase during storage due to surface corrosion. The high surface gloss of most internal plastic coatings are an excellent aid in the visual inspection of the pipe interior prior to line commissioning, while the smooth coating surface finish aids to extend the life of pipeline pigs during production/clean-up operations.

The application of internal plastic coatings involves several surface preparation steps. Initially there will be a thermal cleaning step or chemical wash to remove any organic species that might be on the pipe’s internal surface. The next step will include some level of grit blasting of the pipe’s internal surface to a cleanliness level specified by the coating manufacturer/applicator. During the surface preparation of the pipe, all mill scale and metallic deposits are removed from the pipe ID; removal of this debris following the hydro testing of the pipeline would be extremely expensive. During hydro testing the water used is usually chemically treated so as not to cause corrosion or have water-borne bacteria becoming sessile and adhering to the new pipe.

Studies have shown that the typical payback for the internally coated pipe investment is between three to five years, based purely on pipeline hydraulic improvements (8). Plastic coatings can reduce the pressure drop in pipelines, and have been shown to allow the operator to use a smaller ID line pipe while still maintaining the same throughput as with a larger diameter internally-bare pipe (9). One additional economic benefit of using coated line pipe is the reduction in power consumption required to move the gas and/or liquids from one end of the line to the other. In countries such as Norway, over 30% of the produced gas is used in offshore power generation that is required to fuel the compressors used for the export gas pipeline.11.5.2 Main Internal Coating Systems

Cement Lining

Cement mortar lining (CML) is a centrifugally-applied continuous lining of dense Portland cement mortar with a smooth and uniform finish. These products were developed to provide an economical form of internal corrosion and abrasion protection for oilfield tubulars and line pipe. CML is used primarily in water injection and disposal lines. These products are also suitable for potable water lines but should not be specified for lines where hammer conditions or fluid pH below six (acidic condition) exist.

The lining provides economical and lasting protection against the corrosive effects of saline solutions and other types of industrial liquids and wastes. It has excellent structural and spall-resistant properties.

This is a proven technology with over a century of use in municipal water mains and water service lines. The system is compatible with other external coatings. Extruded polyethylene external coating may be applied over CML pipe provided the steel is not heated rapidly by more than 80°C during the coating process. Cement is alkaline in contact with water which reduces the corrosion impact to the metal substrate under the cement mortar. Cement mortar however has restrictions with regards to water fluid speeds and reduces the pipe ID to a larger extent than FBE coating systems would. Cement also has a higher surface roughness compared to FBE and promotes microbiological growth to a larger extent, furthermore the degree of flexibility of cement mortar lined pipe and impact resistance is inferior to FBE type of linings.

Fusion Bonded Epoxy

Typically when fusion bonded epoxy (FBE) is referenced, it is assumed to be for the external protection of line pipe. There are a wide array of FBEs, primed and unprimed, that have proven to be successful in the area of corrosion protection, hydraulic improvement and deposit mitigation for the internal of line pipe. FBE is a plant-applied thermoset lining for steel pipes where internal corrosion protection or a smooth surface is required. This lining reduces friction costs and compression costs, and provides a clean internal surface along with corrosion protection. As with internal plastic coatings, FBE has been used since the early 1960s. FBE coatings are used extensively in the oil and gas industry for the coating of line pipe, valves, fittings and for downhole materials such as tubing and casing. The fusion bonded epoxy coating systems are applied at what is called the “cladding temperature” of the powder. The cladding temperature is the point at which the powder will melt and flow allowing it to adhere to the preprepared (grit-blasted and/or thermal-cleaned surfaces). Powder coating systems are applied in a one layer process as opposed to liquid coating systems which can be applied in numerous, thin layers with an intermediate drying/baking cycle between each layer. As opposed to cement linings, FBEs are thick film coatings usually with a Dry Film Thickness (DFT) of less than 400 microns. Advantages of FBE coatings are their adhesive properties, their chemical resistance, their high degree of flexibility and good impact resistance. Drawbacks of FBE coating systems are the high degree of surface preparation required for their application as well as a curing temperature in excess of 200°C, all of which requires ‘shop applied’ coating application.

Polyamide Coatings

Internal coatings based on polyamide chemistry are defined as thermoplastics. Unlike thermoset materials, thermoplastics do not undergo a final curing step at elevated temperatures. Instead, these materials are applied at very high temperatures and are then led through a controlled cool down process that will vary depending on the type of polyamide and the desired final properties. Due to this, heatresistant polyamide powder coatings are primarily plant-applied coating systems. Polyamide coatings have advantages over FBE coating materials due to a higher degree of flexibility and less damage experienced from mechanical impact. Polyamide coatings generally require a liquid epoxy or phenolic primer in order to ensure good adhesion.

Flow Efficiency Coating

Flow efficiency coatings (FEC) are thin film epoxy coatings applied in natural gas pipelines to smooth the internal pipe surface for improved flow. Application of FEC replaces the internal rough surface of a steel pipe with a smooth surface finish which reduces friction and turbulence to increase flow efficiency. This may allow for use of a smaller diameter pipe or lower compression requirements resulting in reduced capital and operating costs. After application of FEC, the clean internal surface of the pipe provides corrosion protection prior to installation and allows for easier visual inspection. The cleaner surface reduces the cost and effort of drying the pipe after hydrostatic testing.

Anti-Corrosion for Potable Water – Epoxy LiningOne type of internal coating system for potable water applications is a 100% solids, two component, and solvent free, high build epoxy lining used to provide corrosion protection for the internals of steel pipes in potable water applications. BS6920 and ANSI/NSF 61 are local standards for potable water, and can also be used for other applications including raw water, process water, sewage, wastewater, crude oil, and white oils. These standards usually call for testing of the applied coating material with regards to taste, smell, microbiological growth and possible leaching out of heavy metals and/or solvents. Coatings used for potable water handling must be solvent free in an applied form and are used on valves, fittings, tanks and elbows as well.

These products are designed for high build, single coat applications by airless spray equipment.

Performance PropertiesThese products are allowed to cure to form a hard and glossy surface film with excellent resistance for a wide range of aqueous chemicals including potable water, effluents, raw water, process water, sewage, crude oils, and white oils. These products exhibit excellent adhesion on correctly-prepared steel surfaces. They are compatible with most readily-available field joint coating systems such as heatshrinkable sleeves, liquid epoxy, FBE and polyurethane coatings.

Easy ApplicationThese products are suitable for application as a single coat system, using both standard and/or plural component airless spray equipment. They are capable of being applied by roller or brush for small applications and repairs.

Environmentally SafeWith a 100% by volume solids, zero volatile organic compound (VOC) formulation, these products are designed to meet strict health, safety and environmental standards. They eliminate solvent emissions, explosion risk and fire hazard and are designed to eliminate the risk of solvent retention which can influence water quality and coating defects.

Anti-Corrosion for Potable Water - FBE Powder Coatings

Another type of internal coating is the FBE system. FBE powder coatings have been used in the pipeline industry for more than 40 years. These powder coatings contain no solvents and are 100 % solid without any dangerous raw materials.

FBE powder coatings meet a lot of standards around the world like DIN/ISO/EN, GSK, AWWA and drinking water approvals such asUBA-Guideline, GermanyACS, FranceWRAS, United KingdomKIWA, NetherlandsBelgaqua, BelgiumNSF 61, USA

The purity of the water for human consumption is the highest priority for the companies involved in the supply chain of manufacture and management of the mains distribution systems. Therefor the control of the products used in the industry must also be of the utmost importance.

In Europe the control of materials used is normally determined through government departments or independent test institutes or a combination of both. In certain cases only raw materials that are on a “positive” list can be used in a fusion bonded epoxy formulation. In this case the powder manufacturer would also be audited on a regular basis and samples taken from production of FBE products to confirm they continue to meet the approval documentation.

In the case of the KIWA or NSF drinking water approval the control of raw materials is very strict, with the chemical composition of individual raw materials assessed to ensure the products conform to their requirements.

In addition to these regulations further testing is performed on the growth of microorganisms on materials intended for use in drinking water. In particular the FBE technology has been tested in Germany by the Hygiene-Institut des Ruhrgebiets for examination and assessment following the regulations of the DVGW (German Association of Gas and Water) technical rules, method W 270. The test is targeted at determining any signs of bactericidal or fungicidal properties of the FBE-coated surface. The FBE technology has been tested to and meets the requirements of this specification with documentation available.

Anti-Corrosion for Potable Water – Polyurethane Lining

Polyurethane-based products are 100% solids, either one or two component systems, 1:1 mixed by volume, high performance, high build, fast set, aromatic and rigid polyurethane lining. They have been specifically designed as corrosion and abrasion resistant coating for long term protection of water pipe internals. They should comply with the requirements of NSF/ANSI 61 standard for potable water and AWWA C222 standard. They can also be used for other applications including raw water, process water, sewage, and wastewater.

Excellent Performance PropertiesPolyurethane based systems cure to form a very hard and tough surface film with excellent resistance to abrasion, impact, chemical attack, and cathodic disbondment. They exhibit excellent adhesion on correctly-prepared steel and ductile iron surfaces. The application of a primer is not necessary. They are compatible with most readily available field joint coating systems such as heat-shrinkable sleeves, liquid epoxy, FBE, and polyurethane coatings.

All Temperature Cure and Unlimited Film BuildPU can be cured at almost any ambient temperature. These products have a very fast curing time and are therefore applied using plural component spray equipment. The unlimited film build can be achieved in a single coat multi-pass application. The end result is a thick, impervious, and holiday-free internal coating film within minutes of spray application. Inspection and quality testing can be made within 30 minutes and pipes can be put into service within hours.

Environmentally SafePU is a 100% solids system, being free of solvents and VOCs, and is designed to meet strict health, safety and environmental standards. The product contains only pure resins and the finished coating is safe for drinking water and food contact.11.5.3 Coating Qualification Testing

Regardless of the purpose of an internal plastic coating in a pipeline application, the coating must be ‘fit for purpose’. For example, it must have sufficient resistance against delamination, swelling and disbonding in its intended environment. Advances in coating chemistry and technology over the last decade have led to the usage of coated line pipe in environments where this was previously not feasible. Oil and gas fields with service temperatures in excess of 120°C, and extreme chloride concentrations in excess of 160,000 ppm, coupled with substantial concentrations of sour gas are not uncommon any more.

When choosing the qualification tests to be used for the testing of the most appropriate coating system it needs to be kept in mind that the coating standards used for ID coatings originated from the external coating business. The confusion is amplified by the extensive number of ANSI, AWWA, API, NACE, DIN and ASTM standards that are associated with coatings and paint. These may not be suitable for internal coatings. Care has to be taken that these standards are not confused with one another and the testing during fit for purpose trials is relevant to the system in question.

The coating material under consideration should be tested for its resistance in its intended environment. It has to be kept in mind that most test work relating to internal plastic coatings is derived from external coating test procedures. As such there are several tests which, while appropriate for external coating systems, provide little beneficial data regarding the performance of an internal coating in a particular environment. One such test is the salt spray resistance test (discussed in API RP 5L) for coating systems designed for immersion services. Another test that will not provide a realistic view of coating performance in a line pipe application is the 90° degree impact testing which was used in the past to expose brittle coatings that were susceptible to disbonding. Given the nature and direction of flow through a pipeline, 90° impact angles are not representative of potential coating damage to the internal surface.

General environmental parameters such as temperature and pressure are important variables for the coating selection, especially when it comes to immersion service in sour environments. As the temperature increases resistance to H2S generally decreases, these effects and results are best evaluated in an autoclave test series. For sour-service environments it is advisable to conduct autoclave testing simulating the field conditions with regards to gas compositions, pressures, temperatures, and if applicable, reconstituted field/formation waters can be used. These tests are conducted according to NACE TMO185 “Evaluation of Internal Plastic Coatings for Corrosion Control of Tubular Goods by Autoclave Testing”. The test coupons from the autoclave testing can then be used to test for the adhesion of the coating material prior to and following exposure to the corrosive environments. An appropriate test for adhesion is according to ASTM D4541-02 “Standard Test Method for Pull-off Strength of Coatings using Portable Adhesion Testers”. The possible formation of blisters, classified according to ASTM D-714 “Standard Test Method for Evaluating the Degree of Blistering of Paints”, following autoclave testing indicates loss of adhesion to the steel substrate. In the past internal coatings have failed due to different rates of thermal expansion and contraction between coating and the metal substrate. This could be due to simple temperature gradients between day and night-time or large temperature differences between pipe ID and OD.

Another important test indicating coating ‘flexibility’ is the Mandrel Bend Test (ANSI/AWWA P213-07), the coating requires sufficient flexibility to resist cracking and disbonding of the coating during pipe laying operations.

11.6 Insulation

Onshore pipelines may require anti-corrosion coatings, insulation and internal coatings to maintain product flow, UV protection (for above-ground lines) or protective and weight coatings for rocky areas, river and lake crossings.

Onshore insulation systems available today have been developed for external protection and insulation of pipelines operating at temperatures ranging from 85°C up to 650°C. Systems generally include a corrosion-resistant coating, a thermal insulation layer and an outer jacket or protective topcoat.

11.6.1 Onshore Insulation Systems

Onshore insulation systems are moulded and/or spray-applied polyurethane foam coatings developed for external protection of buried or above ground steel and plastic pipe. The polyurethane foam provides a cost-effective alternative for preventing hydrate formation in gas pipelines, maintaining viscosity of hot oil lines and providing freeze protection for water and sewage lines. Systems use a multi-layer coating consisting of an anti-corrosion layer, thick polyurethane foam and a polyethylene outer water barrier. The compressive strength is high to resist damage from handling and burial. The polyethylene jacket may also be formulated for cold weather installation. For systems up to a maximum operating temperature of 85°C, tape and primer may be applied as an anti-corrosion undercoat. For higher temperatures up to 110°C, fusion bond epoxy is used as the anticorrosion layer.

11.6.2 Onshore Insulation to 150°C

High temperature systems use spray-applied polyurethane foam coating developed for external protection of buried or above ground steel pipe. The polyurethane foam provides a cost-effective alternative for maintaining the viscosity of hot oil lines, diluent bitumen and hot bitumen lines to a maximum service temperature of 150°C. It consists of a high-temperature fusion bond epoxy anticorrosion layer which has also been rated for up to a maximum service temperature of 150°C under insulation. A sprayed-on low density polyurethane foam offers excellent insulation characteristics for extended service life at high temperatures. The thickness and compression strength can be tailored to match the pipeline project requirements. The foam is protected by an extruded high-density polyethylene jacket that provides excellent mechanical protection to prevent damage and moisture ingress into the system. The system is designed to be installed in environments down to a temperature of -40°C.

This high temperature system provides a watertight barrier. The polyurethane foam reduces heat loss to prevent hydrate formation in gas pipelines and helps to maintain viscosity in hot oil lines. An optional design for further protection against temperature loss is the application of heat tracing channels.

11.6.3 High Temperature Systems to 650°C

In addition to existing coating solutions, new products are being developed to address new requirements for abrasion resistance, higher operating temperatures, and installation in extreme cold temperatures to serve the oil sands and Arctic regions.

Pre-insulated pipelines are used to transport both high and low temperature mediums where maintaining pipeline temperature is important. Applications range from low temperature LNG pipelines to high temperature bitumen pipelines. The pipelines consist of an inner carrier pipe covered in an insulating material and jacketed externally for protection and integrity.

Pre-insulated pipe systems for above-ground pipelines reduce project costs and improve schedules for construction of in-situ oil sands production installations. Pre-insulating pipes prior to shipping to construction sites should reduce field labour and is more time efficient than insulating pipes at congested, space-constrained construction sites.

Very high temperature systems are required for above ground piping for thermal recovery operations where operating temperatures are 650°C such as: hot oil and bitumen, steam lines and hot process water lines. These systems consist of wrapped aerogel insulation blanket and an aluminium cladding for weather proofing. Aerogel insulation offers very high thermal insulation efficiency resulting in reduced insulation thickness compared with other alternatives such as rock wool or calcium silicate. Corrosion protection is not required.

11.7 Buoyancy Control Systems

Virtually all onshore pipelines have to cross aquatic environments – rivers, channels, lakes, fjords or narrow sea gulfs, bays and channels – along their route. Sometimes, their route goes through semiaquatic environments, such as swamps, marshes, or permafrost. In all these environments, if the pipeline is not buried in solid ground, it will tend to move from its design position and float towards the surface. This phenomenon – identical to the one occurring in offshore environments – can affect any pipeline crossing an onshore wet environment. Moreover, it is more frequent in large diameter pipelines and in pipelines transporting gas. As the pipeline moves from its design position, this creates buckling or even rupture risks. Of course, an easy solution for the floatability/buoyancy issue would be to increase the wall thickness of the steel pipe; however, this solution is very expensive, so that the industry has researched other cheaper but effective solutions for pipeline buoyancy mitigation. Therefore the industry has developed similar solutions for the onshore wet environments, based on the extensive experience in mitigating the pipeline buoyancy phenomenon offshore, as well as other onshore pipeline construction techniques used for crossing or avoiding obstacles.

In order to avoid the floatation phenomenon in onshore wet environments, the industry uses three main types of approaches:Wet environment aerial crossing – the pipeline is installed from the beginning at a safe distance over the wet environment area. This is usually done by using existing road/railway bridges to carry the pipeline or install a dedicated bridge for the pipeline over the river, lake or swampy area. This approach has the advantage of minimizing the wet environment disturbance, but exposes the pipeline to potentially damaging weather-related factors – UV degradation, impacts, floods etc.Wet environment under-crossing – the pipeline is installed from the beginning at a safe distance under the wet environment area – under the river or lake bed. This is usually done by using horizontal directional drilling (HDD) techniques. This approach has the advantage of minimizing the wet environment disturbance, but will not solve the problem in certain types of onshore wet environments, such as marshes or permafrost, where the thickness of the wet layer is too high creating technical challenges for installing the pipelinesBuried pipeline – the pipeline is installed at the bottom of the wet environment – sometimes a trench is prepared to receive the pipeline – and then buried (by rock dumping etc). The advantage of this approach is that it reduces the risk of the pipeline floating to the surface. However, the effectiveness of this method is dependent on the quality of the burial operation – strong river currents, suboptimal trench cover material or incorrect burial could, for example, lead to the pipeline being uncovered and starting to float. Moreover, this approach is rather ineffective in marshes or permafrost areas where the thickness of the wet layers is high.Buoyancy control systems - the main purpose of these systems is to avoid the above-mentioned risks by creating negative buoyancy that will counter the floatation effect described above and will thus allow the pipeline to stay in the design position. The advantage of these systems is that most of them are effective in onshore wet environments where other approaches show limited results, such as marshes, swamps or permafrost. Some of them also offer supplementary mechanical protection against potential impacts from ship anchors, rocks, etc. Their main weakness is that the relative instability of some of them (such as aggregate-filled bags) means they cannot usually be used for environments such as rivers, lakes, sea channels etc.

The review in this section is going to focus on the buoyancy control systems. The first buoyancy control systems were developed in the early part of the last century, when two cast iron half shells were bolted together around the pipe. Cast iron weights were then replaced by the less expensive and easier to manufacture cast concrete weights – set-on or bolt-on. The concrete weight coatings have been developed during the second part of the century to become the main buoyancy control system in the industry. Finally, during the 1990s, aggregate-filled envelopes were developed for use in regions where the other systems could not be used. The most widely used buoyancy control systems in the industry today are reviewed in the following sections. Note that the list of systems described below might not be exhaustive; other systems could be used in onshore pipeline projects, but on a more limited scale.

11.7.1 Concrete Weight Coatings

Concrete weight coatings have been developed and used for more than 40 years to provide negative buoyancy to pipelines crossing onshore wet environments. Just like the concrete coatings for mechanical protection, previously when applied in a specialized coating plant, the concrete weight coatings are the only buoyancy control systems in the industry that also offer supplementary mechanical protection to the pipe and an anti-corrosion coating during the whole pipeline construction process (transportation to ROW, temporary storage, handling, stringing, lowering in, backfilling) and the entire pipeline service life.

Concrete coatings can be plant-applied (through side-wrap, spraying or impingement processes) or applied in the field – sprayed or form-and-pour (moulded) concrete, and are covered by the new EN ISO 21809-5:2010 international standard. All concrete coatings are reinforced by wire mesh, rebar cages or different types of fibres and use a dry concrete mix (5-7% water) to allow for the pipe to be handled right after the application of the concrete. Their required 28-day compression strength is in the 40-50 MPa range. Some concrete coatings are wrapped in a perforated polyethylene outer tape that avoids concrete spalling and allows curing (the PE tape can then be removed). Other concrete weight coatings are cured allowing the concrete to cure naturally outdoors through accelerated curing using steam. The field joint area is usually protected by fast-setting reinforced concrete that is applied by specialised contractors in the field.

Compared to the mechanical protection concrete coatings, concrete weight coatings are thicker and heavier. Concrete weight coatings are usually 50-75 mm thick, although the maximum thickness that can be applied is 150 mm for the side-wrap process and around 200 mm for the impingement and form-and-pour processes. The negative buoyancy potential is given by the high density of the concrete weight coatings – between 1800 and 3700 kg/m3 – which is usually obtained by using heavy natural aggregates (iron ore, barite) or industrial by-products (such as different types of heavy slags) in the concrete mix. Concrete weight coatings are generally not bendable, reducing the capability of the pipeline to follow the terrain configuration.

Fig. 23 – Plant-applied concrete weight coating

If available in the region where the pipeline is built, concrete coatings offer the highest flexibility to pipeline designers and contractors, as they have no limitations of use for negative buoyancy applications and can be used in any type of onshore wet environment from rivers to permafrost. Another advantage is that the concrete weight coatings offer not only negative buoyancy, but also mechanical protection against potential impacts. Finally, the concrete weight coatings’ long-term stability is another strong point – the pipeline operators can be sure that the concrete weight coatings will remain in place (if correctly applied) around the pipe for the entire service life of the pipeline, which is not always the case with other onshore buoyancy control systems that can slip away from the pipe or move along it, causing pipeline stability issues. A factor that has to be taken into account is that the plant-applied concrete weight coatings increase the weight that has to be transported and handled to and on the right-of-way, thus slightly increasing the project costs. Field-applied concrete coating, although having a neutral impact on the logistic costs, is a relatively slow process and can delay the pipeline construction process. Finally, using concrete weight coatings, applied in a plant or in the field, could be challenging in some remote ROW areas with difficult or restricted access.

11.7.2 Cast Concrete Systems

Cast concrete systems were developed to replace the earlier cast iron bolt-on weights that were more expensive and more difficult to manufacture. Although there are many variations of cast concrete buoyancy control systems, one can divide them in two main categories based on their installation method:

Set-on (saddle-type) cast concrete systems – these systems are built as a single-piece of cast concrete that is lowered on the pipeline at pre-determined distances. Because of their shape, they are sometimes called doghouse weights. The set-on systems sit on the top of the pipeline, with their sides straddling the pipe like a saddle. These systems tend to be used in semi aquatic environments, such as marsh or permafrost areas, as their relative instability on the pipe creates challenges for use in river or lake crossingsBolt-on (half-shell) cast concrete systems – these systems are made of two cast concrete halfshells that are installed on the pipeline at pre-determined distances. The two half-shells are bolted together, usually using steel bolts, or strapped on the pipe, and cover the whole circumference of the pipe. These systems are used more often for aquatic environments, such as river and lake crossings, as their stability on the pipe is better than that of the set-on systems.

Fig. 24 – Set-on cast concrete weight

Cast concrete systems are usually manufactured in a specialized facility and based on the specific requirements of the project – level of negative buoyancy needed, pipe diameter etc. They are always steel rebar reinforced and the concrete mix usually includes special sulphate-resistant cements that are suitable for construction applications in wet environments, as well as heavy aggregates for increasing the buoyancy control potential. They do not have limitations in terms of pipe diameter and – especially for the heavier ones – have handles provided for lifting and handling during transportation and installation. Because the contact between the pipe and the cast concrete can damage the anticorrosion coating of the pipe, the pipe itself or both, all the cast concrete systems have a protective lining installed at the interface between pipe and concrete. These linings are made of materials such as rubber, neoprene or non-woven geotextile fabrics.

Cast concrete systems are used in regions where concrete weight coatings are not available or are available at a much higher cost. Their main advantage is that they can be built by any cast concrete manufacturer, even having minimum previous experience in the pipeline construction industry. The quality of their long-term buoyancy control is dependent on the quality of their installation on the pipeline by the field crews of specialized contractors. Moreover, the installation of some of these systems – done on the right-of-way – can be slow, such as the bolting on of the concrete weights underwater by diver crews. Set-on cast concrete systems are inherently less stable and therefore cannot be used in most aquatic environments. Even the bolt-on systems can become unstable or move due to strong water currents or other external impacts (ship anchors etc). Finally, cast concrete systems present a risk of damaging the pipe and its anti-corrosion coating during the installation – for example, the risk of a cast concrete weight falling on the pipe – and later, during the service life, especially if the concrete system moves from its designed place.

11.7.3 Aggregate Envelope Systems

Aggregate-filled envelope systems have been developed during the 1990s as a new method for solving the floatability issue in onshore wet environments. These systems have quickly carved a market niche for themselves as solutions of choice in regions where the restricted access does not allow for the use of concrete-based buoyancy control systems or where these systems have a much higher cost.

The aggregate envelope systems, or saddle weight bags, are usually strong membranes made of materials such as non-woven geotextile fabric, with one or more compartments that are filled with sand or local aggregates and then placed on the pipeline for buoyancy control. The industry has developed different versions of these systems that can replace the two main categories of cast concrete systems; there are strap-on versions that are replacing the bolt-on cast concrete systems and set-on versions that are replacing the set-on cast concrete systems.

Fig. 25 – Aggregate-filled geotextile envelope system

Just like any of the competing systems, the aggregate envelope systems have some strong points and some weaknesses. The aggregate-filled envelope systems are less expensive on a total installed coat basis compared to the cast concrete or concrete weight coating systems. This cost advantage comes mainly from the fact that the transportation costs are lower – only empty saddle bags have to be transported to the ROW, where they are then filled with local material. The use of locally available filler material (sand, natural aggregates) also reduces the costs, compared to concrete systems. Their installation is also simpler and quicker than that of cast concrete systems. Aggregate envelope systems also conform better to the bottom of the pipeline trench and do not require a deeper trench like some of the cast concrete systems. They do not need a protective liner as the cast concrete systems do. Finally, they can easily be transported to restricted access areas where other systems cannot be transported and extra bags left after the installation can be returned or easily stored and retained for the next project. Although the aggregate envelope systems can easily be used in semi-aquatic environments (marshes, permafrost), they are more challenging and slow to install than cast concrete systems in aquatic environments (such as rivers and lakes). Their stability in areas with strong water currents or other potential impacts is also questionable. Installation teams have to pay extra attention to the handling and installation of the

saddle bags, in order to avoid rendering them useless through tearing or shredding. Finally, the efficiency of these systems will always be dependent on the quality of the installation process in the field, which cannot always be guaranteed.

11.7.4 Steel Screw Anchors

An emerging technology used for pipeline buoyancy control is screw anchors. Screw anchors are steel shafts with helices welded to them that are literally ‘screwed’ into the soil beneath the pipeline. One anchor is installed on each side of the pipeline, and then connected over the top of the pipeline with a saddle which will allow the anchors to resist the uplift forces on the pipeline.

This technology was used extensively in North America in the late 1960s, but was phased out and traditional concrete buoyancy control methods took over. It re-emerged in the 1990s in North America as pipeline owners and contractors performed value engineering analysis, and studied ways to reduce the ever-escalating costs of pipeline construction. Since that time, they have been used extensively in North American and Asia, as well as South America, Africa, and Europe. There are several steps involved in the design of a proper screw anchor buoyancy control system:Identify pipe characteristics, and safety factor requiredGather data on soil parameters (where feasible) or define assumptions for soil conditions (often in conjunction with contractor or screw anchor supplier)Calculate maximum allowable centre to centre spacing of anchors along the pipeline, taking into account soil strength, anchor strength, allowable pipe stresses, and pipeline deflection

Fig. 26 – Pipeline with steel screw anchors

Generally cost effective on pipelines with an outside diameter of 300 mm and larger, a screw anchor buoyancy control system can offer cost savings over concrete weight coatings or cast concrete systems. Cost savings are obtained through relatively large spacing between anchor sets along the pipeline length. This results in less material, transportation, and construction costs. The quality of screw anchors’ long-term buoyancy control is dependent on the quality of their installation on the pipeline by the field crews. Moreover, the installation of

some of these systems – done on the right-of-way – can be slow, especially if installation has to be done underwater. Screw anchors do not offer any mechanical protection for the pipe and its anti-corrosion coating against impact and penetration damage from external sources (ship anchors etc). Finally, additional padding has to be inserted between the steel connection on top of the pipe and the pipe itself to avoid any damage to the anti-corrosion coating and the pipe. Screw anchor systems also present a risk of damaging the pipe and its anti-corrosion coating during the service life if the anchors move from their designed place.11.7.5 The Optimal Buoyancy Control System – Selection Guidelines

In order to minimize the risks for the stakeholders involved in an onshore pipeline project, the buoyancy control approach has to be discussed as early as possible during the early stages of the project. In order to choose the optimal buoyancy control system(s), the parties involved have to use criteria that are similar to those used for the other pipeline protection systems.Technical performance criteria – in the case of buoyancy control systems, the most important technical performance criteria will be the ability of the buoyancy control system to reach and maintain the required level of negative buoyancy over the entire service life of the pipeline. The stakeholders will have to assess if the selected systems have to fulfil other needs, such as the need for mechanical protection against various types of impacts.Design and constructability criteria – based on the specifics of the project, it is possible that some of the buoyancy control systems could not be used, due, for example to the limited access to the right-of-wayEnvironmental impact criteria – the stakeholders will be interested in selecting the buoyancy control system that will minimize the overall environmental impact of the project, such as habitat loss for aquatic fauna and flora, disturbance of environmentally-sensitive areas (marshes and permafrost) etc.Economical criteria – the stakeholders will assess the availability of different buoyancy control systems in the project’s region and will compare the total installed cost of each system; the stakeholders will be interested in selecting the system that offers the optimal level of buoyancy control with the lowest total installed cost. The total installed cost will include not only the purchase price of the buoyancy control systems, but also the direct and indirect installation costs – such as additional transportation and handling costs, additional manpower and equipment needed for installation, installation time etc.

11.8 Cathodic Protection

Typically, an external pipeline corrosion protection system consists of two components – the coating and the cathodic protection (CP) system. Corrosion takes place when electrons are removed from the metal at the anode area on the pipe surface and consumed by the reaction at the cathode with oxygen or hydrogen.

For corrosion to take place there must be:Anode (corroding area)Cathode (protected area)Electrically conductive metallic path connecting the anode and the cathodeIonically conductive electrolyte immersing the anode and cathode

There can be various causes of corrosion including:Differential Aeration Cells: A pipe installed under a paved road in compact soil reduces the amount of oxygen at the pipe whereas as pipe in nearby ditches may be in aerated soil. Corrosion takes place in the pipe beneath the road.Dissimilar Soils: In soils that are more conductive, corrosion takes place along those sections of the pipe.New / Old Pipe: New pipe used to replace a section of line becomes the anode and corrodes, protecting the old sections.

11.8.2 Purpose / Objective of the CP System

The anodic or corroding areas and the cathodic or protected areas on a pipeline are commonly on the same surface but separated microscopically. The coating system is the primary barrier against environmental corrosion while the CP system is a secondary defence to protect areas of the pipe that become exposed due to scratched, missing or damaged coating. CP is typically used to prevent corrosion at any weak areas in the coating such as field joints or damaged spots.

CP is fundamental to preserving a pipeline's integrity by replacing the electrons generated by the normal corrosion process. CP controls corrosion by supplying an external direct current that neutralizes the natural corrosion current arising on the pipeline at coating defects. CP prevents corrosion by converting all of the anodic or active sites on the metal surface to cathodic or passive sites by supplying electrical current from an alternate source. The current required to protect a pipeline is dependent on the environment and the number and size of the coating defects. The greater the number and size of coating defects, the greater the amount of current required for protection.

11.8.3 Available Cathodic Protection Systems

There are two main CP methods of providing protection against external corrosion – the impressed current and the galvanic protection methods.Impressed Current Cathodic Protection

Impressed current CP describes the case in which the electric current for protection is provided by an external power supply. This type of system uses a ground bed and an external power source to impress current onto the pipeline. For a buried, onshore pipeline, a generator or a local utility provides the electricity. Commercially supplied AC is converted to DC. The system uses an anode bed and an external power source to impress current onto the pipeline. Impressed current protection involves connecting the metal to be protected to the negative pole of a direct current (DC) source, while the positive pole is coupled to an auxiliary anode. Electrons are introduced into the pipe and leak out at the bare areas where the cathodic reaction occurs. Impressed current CP is rarely used in subsea pipelines.

The ground bed is important for the effectiveness of the impressed current systems. It transfers current from the source through the ground to complete the circuit with the pipeline. One of the most common ground beds is the horizontal type with anodes installed with a backhoe at a depth below the frost level in the soil.

Galvanic-Anode Cathodic Protection

Subsea pipelines are commonly protected by galvanic anodes. This method employs the basic conditions needed to produce an active corrosion cell: an anode, cathode, electrically conductive pathway and electrolyte; and a difference in energy level between anode and cathode. The flow of current through the electrolyte is always from the anode to the cathode. Wherever electrical current leaves the anode to enter the electrolyte, small particles of iron are dissolved into solution, causing pitting at the anode. Wherever the current enters the cathode, hydrogen gas is formed on the surface and the cathode is preserved and protected from corrosion. If one of the conditions above is removed, corrosion cannot continue. It is the removal of one of the conditions, to reduce or interrupt the flow of current, which is the basis for CP.

For ground installations, the electrolyte is the moisture of the soil. The anode is a material having a more electronegative potential than steel. Typically, it is made from materials such as aluminium, zinc, magnesium or alloys of those metals. When the materials used as anodes are mechanically coupled to steel with an attachment wire, the steel pipe becomes the cathode. Subsequently, a current flows, and the anode corrodes to provide electrons that protect the pipeline.

CP trades corrosion on the pipe for corrosion on the sacrificial anode. The driving voltage (the difference in potential between the anode and cathode when coupled together in a corrosion cell) is limited with galvanic anodes; the amount of current that can be delivered tends to be low. Galvanic anodes are normally used in low resistivity soils to provide current to pipes having an excellent coating.

11.8.4 Anode Material Selection

Zinc has been in use as a sacrificial anode for longer than aluminium and is considered the traditional anode material. However, aluminium has several advantages as a sacrificial anode material and is now the material of choice (magnesium can be used for onshore pipelines but is not efficient for subsea pipelines because it corrodes rapidly in seawater and only provides about half the electric current for CP). Aluminium is capable of delivering more current in seawater and has higher a current capacity, so a lower consumption rate. Thus a smaller mass of aluminium anode will protect the same surface for a given period of time as compared to a zinc anode. This leads to greater economy and improved performance in using aluminium as opposed to zinc. Moreover, the effect of operating temperature on the anode materials is very important. Zinc anodes alloy contains small quantities of iron which leads to intergranular corrosion. Aluminium is also usually preferred to zinc because it is less expensive.

The temperature will have an important impact on the electrochemical capacity – as seen below the anode current capacity decreases as the temperature increases, reducing the CP effectiveness.

11.8.5 Cathodic Protection System Design

The goal of CP system design is to provide the minimum potential that provides CP. A potential above that level increases the cost and the electrical stress across the coating and may lead to cathodic disbondment.

The galvanic anode system should be designed such that a sufficient current is provided to the pipeline to maintain the required potentials throughout the design life. There are two different kinds of galvanic cathodic protection available. Below is an overview of both, together with the benefits and limitations of each method.

Bracelet Anodes

Today, almost all new pipelines installed are equipped with bracelet anodes. Two different kinds of materials are normally used: aluminium and zinc. Bracelet anodes are cast as two halves that fit together around the pipe. If there is no weight coating, the anodes are profiled with tapered ends, otherwise with shouldered ends when a weight coating is used.

Bracelet anodes may be fitted to the pipe as it is laid or retrofit anodes may be attached to the pipeline once it is in place. Retrofit anodes have the benefit of being separated from the pipeline and so are not exposed to elevated temperatures.

The anodes are electrically connected to the pipeline by copper braided wire (pigtails), one end connected to the steel insert and the other brazed or welded to the pipeline.

Square shouldered bracelet anodes are typically used on pipe that has a concreted weight coating.

Tapered anodes are designed to be installed on pipelines with only a corrosion or insulation coating. It is to protect the bracelet anodes during the pipe-laying process, and stopping them snagging on the rollers used on the vessel firing line and stinger.

Even with these tapered designs, non-weight coated pipelines can still suffer anode damage, which can in turn cause coating damage. Several methods are being used to combat this problem such as polyurethane tapers or mounting both halves of the bracelet on top of the pipe thus avoiding contact with the stinger during pipe laying.

Retrofit Anodes

Retrofitting is normally used for the installation of additional anodes when a CP system is not adequate, or for extending the design life of the CP. It is also possible to use a retrofit system when it is not possible to use anode bracelet, for example where the temperature of the pipeline would render bracelet anodes ineffective. Finally, a retrofit CP survey is usually less expensive and easier to undertake.11.8.6 Coating breakdown factor

The purpose of a protective coating on the pipeline is to restrict the access of oxygen to the pipeline and thus reduce the current demand. For CP design it is assumed that the protective coating is 100% effective except at areas of coating breakdown. The bulk of the protection current passes through the coating because all organic coatings are permeable to oxygen to some extent. When the oxygen arrives at the steel surface, it will remove electrons. This appears as a current flux through the coating. As the coating ages, the resistance to permeation decreases and a higher oxygen flux occurs resulting in a higher current flow through the coating. The final coating breakdown has a higher value than the mean coating breakdown. This means that the coating will protect the pipeline less, and will be more prone to external corrosion.

11.8.7 Total net anode mass

The total net anode mass corresponds to the weight of anodes which must be used to provide sufficient potential protection to the pipeline over its life. The total net anode mass is directly related to the anode utilization factor and the electrochemical capacity of the material used. For example, as zinc and aluminium do not have the same properties, the total net mass required may change considerably. The table below shows the difference between materials for a pipeline with no external coating.

11.8.8 Anode utilization factor

The anode utilization factor is required because it is not possible to obtain 100% utilization of the anode material. Anodes are made by casting the anode material in a steel former. During fabrication the anode corrodes down to the inner ligature of the casting around the former, meaning the anode material loses electrical connectivity with the former, thus rendering a percentage of the anode unusable.11.8.9 Anode Numbers

The required number of anodes is calculated from the weight of each individual anode as a function of the total net mass demand. So if, we are using lighter anodes the number of anodes required will increase.

Because it is necessary to respect a maximum distance between anodes (see section 11.8.5), it is important to find a compromise concerning the number of anodes. Using fewer anodes will reduce the cost of installation but may not provide sufficient current along the pipeline, whereas using a large number of anodes will provide sufficient current, but result in a higher installation cost.

The number of anodes is also dependent of the final individual anode current output and the demand for cathodic protection of a pipeline section. This will usually provide a lower anode numbers. But in order to have sufficient protection, the required number should satisfy both criteria.11.8.10 Cathodic Protection Surveys

Periodic inspection of the pipeline CP system is necessary to ensure that the system is functioning correctly. There is no corrosion allowance provided for external corrosion. A common approach is to inspect the pipeline shortly after installation, usually within the first year of service to ensure that the anodes are functioning and, then to resurvey about halfway through the design life of the CP system. The long delay from initial to second survey is acceptable because the coating on the pipeline should remain intact and the anodes are designed for protection of a significantly deteriorated coating.11.8.11 Overprotection

Overprotection refers to the use of excessively high potentials to protect the pipeline. High potential can become a problem if the spacing between ground beds is too great or when poorly-coated lines are electrically connected to well-coated pipelines. Calculations take into account factors such as pipe resistance, soil resistivity, coating conductance and potential limitations to determine the spacing that meets the CP criteria without causing excessive potential near the ground bed. It may also be necessary to insulate segments with poor coating quality from those with good coating quality. Proper CP design should minimize overprotection.Conclusion

The industry has come a long way in ensuring the integrity of pipeline projects. However, as the pipeline sector is growing further, challenges are born from the complexity of the new pipeline projects – more extreme climatic conditions, populated areas, longer pipelines, etc – and from the new pipeline operation requirements – increasingly high or low operating temperatures, higher pressures, new products transported through pipelines etc. Innovation is thus needed to continue to ensure the integrity of new pipelines and to maximize their transportation potential.

Therefore nowadays the companies in the pipeline industry pay equal attention to all the aspects of pipeline integrity during all the stages of the supply chain, as well as during the pipeline installation and service life. The keyword for the future in this field is innovation - new coating materials, new coating systems, new application processes - and new holistic approaches to make the pipelines safer and more efficient.

Appendix 11.1.1 Comparison of Mainline External Anti-Corrosion Coatings

Coating System National/ International Standard

Strengths Weaknesses

Single-layer Fusion-Bonded Epoxy (FBE)

CSA Z245.20 EN ISO 21809-2

Excellent corrosion resistanceDoes not shield CP systemHigh adhesion limits damaged areas

Low impact resistance results in considerable damage during pipe handling, storage, transportation and installationHigh moisture absorption and permeation especially at high temperaturesAffected by UV during storage

Dual-Layer Fusion-Bonded Epoxy (2L FBE)

CSA Z245.20 Depending on the topcoat selection, very good abrasion and damage resistance – ideal for special applications such as HDD – or very good performance in high operating temperature environmentsExcellent corrosion protection

Low flexibilitySensitive to steel surface preparation and conditionHigh moisture absorption and permeation especially at high temperaturesAffected by UV during storage

3-Layer Polyethylene (3LPE)

DIN 30670NFA 49 711CSA Z245.21EN ISO 21809-1 (draft)

Excellent handlingSuperior low temperature flexibility and impact resistanceExcellent corrosion resistanceExcellent moisture resistance

Prone to thinning across raised weld seamsSide extrusion prone to delaminations and voidsSensitive to steel surface preparation and conditionMinimum thickness constraints

3-Layer Polypropylene (3LPP)

DIN 30670NFA 49 711EN ISO 21809-1 (draft)

Excellent handlingExcellent impact resistanceExcellent corrosion resistanceExcellent moisture resistance

Prone to thinning across raised weld seamsSide extrusion prone to delaminations and voidsSensitive to steel surface preparation and conditionMinimum thickness constraints

3-Layer Composite Coatings

CSA Z245.21EN ISO 21809-1 (draft)

Excellent handlingExcellent corrosion resistanceExcellent low temperature impact resistance and flexibilityExcellent moisture resistanceExcellent raised weld coverage

Thickness constraintsSensitive to steel surface preparation and condition

Tape Coatings DIN 30670 Good corrosion resistanceGood impact resistance

Prone to delaminations and voidsProtection is dependent on the quality of the installation crew (if installed in the field)

Appendix 11.1.2 - Field Joint Coating Selection Table

Mainline Coating Most Common Field Joint Systems

Alternate Field Joint Systems

Relevant Standards and Specifications*

Fusion-bonded epoxy (FBE)

Fusion-bonded epoxy (FBE)2-Component liquid epoxy (2CLE)

3-Layer heat-shrinkable sleeve (3L HSS)

1, 2, 7, 8, 9, 10, 12

Dual-layer FBE (2L FBE)

2-Layer fusionbonded epoxy (2L FBE)3-Layer heatshrinkable-sleeve (3L HSS)

2-Component liquid epoxy (2CLE)

2, 4, 7, 8, 9, 12

3-Layer polyethylene (3LPE)

<50ºC - 2-Layer heat-shrinkable-sleeve (2L HSS)>50ºC - 3-Layer heat-shrinkable-sleeve (3L HSS)

Adhesive tape systems (CAT)

1, 3, 4, 5, 7, 9, 12

3-Layer polypropylene (3LPP)

3-Layer polypropylene heatshrinkable-sleeve (3LPP HSS)3-Layer polypropylene tape (3LPP Tape)

Injection-moulded polypropylene (IMPP)Flame-sprayed powder (FSPP)

1, 4, 6, 7, 9, 12

3-Layer composite 3-Layer polyethylene heat-shrinkable sleeve (3LPE HSS)

Flame-sprayed powder (FSPE)

1, 4, 7, 9, 12

Tape <30” diameter - adhesive tape systems (CAT)>30” diameter - 2-layer polyethylene heatshrinkable sleeve (2LPE HSS)

2-Layer polyethylene heatshrinkable sleeve (2LPE HSS)3-Layer polyethylene heatshrinkable sleeve (3LPE HSS)

1, 4, 7, 9, 11, 12

* Standards and Specifications:

1. ISO/FDIS 21809-3:2008(E) Petroleum and natural gas industries — External coatings for buried or submerged pipelines used in pipeline transportation systems — Part 3: Field Joint Coatings

2. CSA Z245.20, External fusion bond epoxy coating for steel pipe

3. CSA Z245.21, External polyethylene coating for pipe

4. EN 12068 Cathodic Protection - External Organic Coatings for the Corrosion Protection of Buried or Immersed Steel Pipelines Used in Conjunction with Cathodic Protection - Tapes and Shrinkable Materials

5. NFA 49-710, Steel tubes. External coating with three polyethylene based coating. Application through extrusion.

6. NFA 49-711, Steel tubes. External coating with three polypropylene layers coating. Application by extrusion.

7. DNV-RP-F102 Pipeline Field Joint Coating and Field Repair of Linepipe Coating

8. NACE RP0105-2005, Liquid-Epoxy Coatings for External Repair, Rehabilitation, and Weld Joints on Buried Steel Pipelines

9. NACE RP0303-2003, Field-Applied Heat-Shrinkable Sleeves for Pipelines: Application, Performance, and Quality Control

10. NACE RP0402-2002, Field-Applied Fusion-Bonded Epoxy (FBE) Pipe Coating Systems for Girth Weld Joints: Application, Performance, and Quality Control

11. AWWA C209 Cold-Applied Tape Coatings for the Exterior of Special Sections, Connections, and Fittings for Steel Water Pipelines

12. AWWW C216, Standard for Heat-Shrinkable Cross-Linked Polyolefin Coatings for the Exterior of Special Sections, Connections, and Fittings for Steel Water Pipelines

Field Joint Coating Selection for Polyurethane Foam Coated Pipeline Systems

Appendix 11.1.4 - Supplementary Mechanical Protection Systems Selection Table