HIGH TEMPERATURE INSULATED COATING AND CONSTRUCTION METHODOLOGY FOR MACKAY RIVER PIPELINE NACE (Northern Area Western Conference) February 18 - 21, 2002 Edmonton, Alberta

Author
Allan Glowach
GARNEAU INC.

C. Winter
Enbridge Pipelines Inc.
10201 Jasper Avenue
Edmonton, AB Canada T5J 2J9

ABSTRACT

The MacKay River Pipeline is part of the continued oilsands development near Fort McMurray, Alberta.
This heavy oil pipeline provides long-term, cost-effective transportation for production from the MacKay River area. The pipeline is designed to transport bitumen with little or no dilution (dry bitumen). In order to operate without diluent, the bitumen must be heated. Heat must be retained in the pipe using a continuous layer of insulation, which ensures that viscosity remains low. The high operating temperature and the environment through which the pipeline passes, were major challenges encountered during the design and construction phases. This paper focuses on the design, selection criteria, and testing of the coating system and discusses the important aspects of construction.

INTRODUCTION

The MacKay River Pipeline is a 324 mm (NPS 12) insulated bitumen pipeline designed to move dry
bitumen from the Petro-Canada MacKay River Production Facility to the Enbridge Athabasca Terminal, a distance of approximately 35 km (22 miles). At the Athabasca terminal the bitumen will be blended and transported on the Athabasca Pipeline to Hardisty, Alberta. The design capacity of the MacKay River pipeline system is 7,000 m3/day (44,000 bpd).

Environmental and operating conditions of the pipeline posed substantial challenges to the coating
system. An operating temperature of 120°C (248°F) with the possibility of short excursions up to 130°C (266°F) and a design life of 30 years substantially limited the range of feasible coating materials. From an operational standpoint, it was necessary to design a coating system where sufficient heat and product viscosity could be retained to enable a two day shutdown and restart with blended product in the line. The right-of-way, composed of segments of clay and wet (muskeg) terrain, imposed further design constraints upon the coating system. Coating material testing began in October, 2000. Pipe coating began in July, 2001. Construction began in September, 2001 and was virtually completed by mid October, 2001. The pipeline will be in service by the end of the second quarter of 2002 once the pump station, heating equipment, tankage, and associated facilities are complete.

COATING SELECTION

Operational requirements and the environment were key factors influencing the final design of the coating system. Thermal insulation was necessary to meet the heat retention requirement in order to maintain the pumpability of dry bitumen even after a two day shutdown. Because polyurethane foam has relatively low mechanical strength, an external jacket was essential. The outer jacket had to be robust and waterresistant to withstand the demands placed on it by the environment, composed of clay soil, muskeg, and directional drill sections. The possibility of a failure of the shop-applied coating or the field-applied joint coating drove the requirement that the anti-corrosion barrier be suited to immersion service at elevated temperatures. All factors considered, an insulated three-layer coating system was selected.

Historically, there have been similar insulated three-layer coating systems in service around the world
used to transport fuel oils, sulphur, and sour gas. In Europe, district heating systems using an insulated three-layer coating system are not uncommon. Insulated coating systems are also available for on-shore and sub-sea pipeline applications. The operating temperatures of most insulated pipelines in North America are below 110°C (230°F).

There were relatively few options for the anti-corrosion layer, given that it must be able to withstand
immersion conditions at 130°C (266°F). Three-layer polyolefin coating systems, one of the most robust coatings available for immersion service, consist of fusion bond epoxy (FBE) primer, adhesive, and extruded polyolefin (Coating System B of CSA Z245.21-98). Typically, these systems are limited to operating temperatures below 85°C (185°F) for polyethylene (PE) and 110°C (230°F) for polypropylene (PP), though some PP systems are rated considerably higher. PE tapes have been used for insulated pipelines operating up to 95oC (203oF). Common high temperature FBE coatings are designed for use as a primer coat in multi-layer coating systems and are rated for high operating temperatures in dry conditions only. A stand-alone, high temperature FBE coating, which had just become commercially available was utilized as the anti-corrosion layer of choice for the MacKay River Pipeline.

A spray-applied polyurethane foam based on a European District Heating approved product was selected as the insulation for the MacKay River Pipeline. This foam has a well-documented service history at high temperatures similar to project requirements. The foam system used on the European District Heating systems is mold injected. Foam insulation is normally spray-applied in North America, thus some modification of the foam was necessary to speed up the curing process. The foam thickness and thermal conductivity were selected to meet the operational requirement for an unblended shutdown window of two days. This insulation thickness corresponded to an outer jacket temperature of 60°C (140°F).

Extruded PE is a relatively low cost material, which has excellent properties including water resistance,
toughness, impact resistance, and strength. As a result, extruded PE has become an industry standard for protecting foam insulation. Outer jackets are composed of extruded PE, with the option of a PE tape innerwrap between the foam insulation and extruded PE. The PE tape tends to improve the impact and handling resistance of the outer jacket. The PE tape is joined to the extruded PE outer jacket with an adhesive layer or by way of heat fusion. A range of PE types are available for extrusion from low density PE to high density PE (HDPE). HDPE has the highest tensile strength and hardness. HDPE is the
material of choice except for winter construction where the temperature may dip below –30°C (-22°F) at which point the impact resistance and elongation at break decrease significantly. At ambient temperatures of –40°C (-40°F) HDPE may crack when subjected to slight impact or pipe movement. Low or medium density PE is recommended for winter construction. Since the MacKay River Pipeline construction was scheduled for late summer/ early fall construction an outer jacket consisting of a PE tape innerwrap heat fused to extruded HDPE was chosen.

Shop-applied Coating:
Based on a review of existing insulated three-layer coating systems and consultation with a third-party
consultant, a base coating system was proposed for the shop- and field-applied application. Qualification and quality assurance tests were defined for each of the three layers as well as the overall, composite system. Specific coating materials were then selected in cooperation with two coating applicators. The following system was proposed:

Shop-applied Coating Qualification:
Once coating materials were selected the two applicators prepared and tested lab panels. The following qualification tests were performed on the lab panels:

• cathodic disbondment tests according to CSA Z245.20-98 test procedures at temperatures up to 95°C (203°F) for periods up to 56 days;
• adhesion tests according to CSA Z245.20-98 test procedures at temperatures up to 95°C (203°F) for periods up to 56 days;
• thermal oxidative aging tests in which coated bars bent according to CSA Z245.20-98 test procedures to 2.5° per pipe diameter length, oven aged at 120°C (248°F) for periods up to 56 days, and then inspected for cracks;
• impact resistance tests according to CSA Z245.20-98 (1.5J at –30°C (-22°F));flexibility tests according to modified CSA Z245.20-98 tests on new FBE and oven-aged FBE at 120°C (248°F) for periods up to 56 days and then bent to 2.5° per pipe diameter length; and
• glass transition temperature according to CSA Z245.20-98 test procedures must be above 130°C (266°F).
  
  

• core density according to EN 253 had to conform to limits set by the manufacturer;
• compressive strength according to ASTM D1621 test procedures on new foam and foam ovenaged at temperatures up to 120°C (248°F) for periods up to 56 days to exceed full load expected to be transferred from the pipe to the soil;
• thermal conductivity (K factor) according to ASTM C518 in new condition and after being oven-aged at 120°C (248°F) for periods up to 56 days to be below a certain limit ensuring that the outer jacket temperature does not exceed 60°C (140°F) when the pipe is coated with 50 mm (2 in.) of foam;
• closed cell content according to ASTM D2856 in new condition and after being oven-aged at 120°C (248°F) for periods up to 56 days;
• glass transition temperature determination; and
• thermogravimetric analysis (TGA) analysis;
  
  

• ring and ball softening temperature of adhesive layer according to ASTM E28 (if used);
• tensile strength of outer jacket at room temperature according to ASTM D638;
• elongation at failure of outer jacket at room temperature and –30°C (-22°F) according to ASTM D638;
• flexibility of outer jacket at –30°C (-22°F) according to CSA Z245.21-98;
• adhesion of PE tape to foam (peel strength at room temperature); and
• adhesion of outer jacket to PE tape according to CSA Z245.21-98 (peel strength at room temperature).

Both coating systems proposed by each applicator were qualified on lab panels according to the requirements originally set out with select modifications. Test pipe was then coated by the two applicators during plant trials. Ring samples were taken from the production pipe and the above qualification tests were performed on each ring sample as well as the following tests on the composite
coating system:

The FBE was qualified based on modified CSA Z245.20-98 cathodic disbondment and adhesion tests at
temperatures up to 95oC (203oF), not at the design temperatures of 130oC (266oF). The only way to perform the 130oC (266oF) tests would be in a pressurized container (autoclave) and the results would be difficult to interpret since there is little experience with this type of test and realism of the test would be questionable. In the case of an outer jacket failure, any moisture will be, in theory, driven out of the insulation covering the FBE at temperatures above 100oC (212oF), validating the 95oC (203oF) tests. A glass transition temperature in excess of 130oC (266oF) provided additional confidence.

Full-scale bend tests to up to of 1.5o per pipe diameter length, the maximum allowed by CSA Z662-99,
were performed on production pipe coated by both applicators at temperatures below -25oC (-13oF).
Examination of the field bent pipe revealed that the outer jacket was free of cracking, the foam insulation had not been crushed, the PE tape to extruded PE layer was intact, and the foam insulation remained bonded to the FBE. The foam experienced cracking during the bending of pipe coated by both applicators. Later fit-for-service testing was performed to check to see whether insulation cracks
significantly increased the surface temperature. Results revealed only a modest temperature increase of 5oC (9oF) at the surface with a 3 mm wide cracking extending to the pipe surface when the pipe was heated to 115oC (239oF). Despite these results it was decided not to perform field bending of insulated pipe. Pipe to be bent in the field was delivered coated with FBE only. In the field the pipe was bent, coated with foam by sequential foam injection, and then coated with a spray-applied polyurea coating.

Field-applied Joint Coating:

Liquid epoxy (novalac epoxy resin) and powder fusion bond epoxy were considered for the anti-corrosion layer on field joints. The liquid epoxy had a number of advantages over the powder FBE including a lower preheat temperature, a simpler application procedure, and a lower cost.

Polyurethane foam insulation at the field joints may be installed by foam injection method or by use of
pre-cut half shells. Half-shells require considerable time and manpower to cut the foam shells to fit each joint and there are gaps in the insulation layer. Besides increased sleeve temperature during operation, gaps allow a direct path for water to reach the anti-corrosion layer in the case of a field joint failure. The injection method is a process whereby polyurethane foam is injected into a mold mounted over the girth weld. Following injection, the foam subsequently expands to completely fill the void. This method was selected, because the foam bonds to the shop-applied foam forming a complete seal and the foam has a formulation similar to the shop-applied version with comparable thermal conductivity and compressive strength.

A variety of heat shrink sleeves were considered for application over the field injected polyurethane foam. Initially, leak testable (casing) sleeves used in European District Heating systems, a proven technology, were assessed. A double-layer sleeve and conventional (wrap-around), single-layer sleeves were also considered. Each type of sleeve from various manufacturers was demonstrated and the final decision was to use a single-layer sleeve. The material costs, installation times, and complexity were considerably higher for double-layer and leak testable sleeves. The single-layer sleeve performance was considered adequate, though increased attention to training and inspection was necessary during installation.

The final field joint coating system was composed of the following:

Field-applied Joint Coating Qualification:

The manufacturer applied liquid epoxy to lab panels and an approved third-party lab performed the
following tests:

The liquid epoxy did not meet the 2.5° flexibility requirements. However, it did pass the 1.0 – 1.5° per
pipe diameter length tests, which is an acceptable level of flexibility for a field joint coating.

The formulation of the field-injected polyurethane foam was similar to the shop-/ spray-applied version, except that there was less catalyst, slowing the cure process. The foam could be poured into the mold and flowed to the bottom of the mold before expanding to fill the cavity. Spray-applied foams are quicker reacting in order to prevent the foam from running off the pipe. The field-injected insulation underwent qualification testing in the manufacturer's lab as per the shop-applied foam qualification test requirements.

The heat shrink sleeves were assessed based on the following criteria:

Acceptable modes of failure included a cohesive failure over the PE and the adhesive bond to foam
exceeding foam strength.

COATING PROCESS

The FBE was applied in accordance with the requirements of CSA Z245.20-98. Immediately prior to
FBE coating application, the pipe surface was abrasive blasted to SSPC-SP10, near-white, treated with a phosphoric acid wash, rinsed, dried, and heated with combination of induction coils and a propane-fired oven. Following FBE application it was quenched and inspected for holidays. Holidays were repaired with the approved field joint liquid epoxy. The pipe was then temporarily stockpiled in the yard. Prior to application of the foam insulation and the outer jacket, the FBE was again holiday tested for any discontinuities. Pipes with defects were set aside and repaired. Pipe free of holidays was cleaned of any foreign matter that would be deleterious to the adhesion of the foam to the FBE. The pipe was preheated with an induction coil and then the coating flame oxidized to ensure adhesion of foam to FBE. The polyurethane foam insulation was sprayed onto the pipe. As the foam cured, it was wrapped with PE tape, and then PE was extruded over the tape. The bond between the PE tape and extruded PE was achieved by heat fusion. The pipe was quenched and the foam cutback area was holiday inspected and repaired as necessary.

A number of quality assurance (QA) tests were performed throughout production. The QA tests performed on each layer include:

1. Anti-corrosion coating:

2. Insulation:

3. Outer jacket:

No QA tests were performed on the composite system.

PIPE STORAGE AND HANDLING

The pipe was coated in two steps. First, the pipe was coated with FBE then stockpiled. Subsequently the pipe was coated with insulation and an outer jacket. In order to minimize the number of FBE repairs, numerous precautionary measures were undertaken in handling the pipe. Once the pipe was completely coated, pipe ends were covered with plastic bags to protect the exposed insulation from the elements and to maintain internal cleanliness of the pipe. Pipe was then transported to the stockpile using a loader with wide, padded forks to avoid damage to the coating (i.e. crushing). The pipe was stacked four tiers high on sawdust filled bags.

The pipe was transported from the applicator’s facility to the site by trucks. A crane was used to load
pipe onto truck trailers, which were stacked no more than four tiers high. Short joints were placed on the top two tiers. During transport the front end of each load was tarped to ensure that the end bags survived the journey.

CONSTRUCTION

The field application of a three-layer coating system is quite involved. To ensure that field joint coating
proceeds smoothly, it is important that the prospective contractors understand the entire scope of work, the properties of all coating materials, and overall job complexity during the bid stage. Once the contract has been awarded, a pre-job meeting, where the contractor demonstrates the field joint application on a number of girth welds, is also recommended. The pre-job meeting makes certain that all installation details have been worked out improving the chances of a successful job from the perspective of both the contractor and the owner. Field training, provided by the manufacturers of each coating layer, is indispensable.

Pipeline construction on the MacKay River Pipeline began in mid September and was nearly completed
by mid October. Field training was provided at the beginning of construction. Each worker involved in
the field coating process was trained and certified by the coating manufacturers. Only workers with
certification were allowed to apply the field joint coating.

The steps in the field joint coating process consisted of:

Welders were required to use pads to protect the FBE from damage caused by weld spatter as this can be problematic to repair especially if damage is adjacent the polyurethane foam. Welders were encouraged to protect the polyurethane foam during preheating and welding to avoid igniting the polyurethane foam.

The width of heating device used to preheat the girth weld area should be considered when determining the length of the polyurethane foam cutback. If the exposed girth weld area is shorter than the width of standard heating equipment, specially designed heating devices may have to be constructed or an alternate heating system used. Induction coils and catalytic heaters offer a number of advantages over a propane torch. Benefits include elimination of damage to the polyurethane foam (charring) and FBE, prevention of contamination of the substrate prior to liquid epoxy application, reduction of flash rusting; and ensuring that the pipe preheat temperature is evenly distributed around the pipe circumference.

On the MacKay River Pipeline project, the foam cutback was specified as 75 mm (3 in.) nominal, which
did not provide enough space for standard induction coils or catalytic heaters. As such, the following
procedure was used for field-coating application: preheat the girth weld with propane torches; abrasive blast to SSPC-SP10, near-white; reheat the girth weld with propane torches due to rapid cooling of the steel; brush blast the girth weld to remove contaminants and flash rusting caused by reheating; brush off the girth weld; and apply the liquid epoxy. This procedure was not optimal as the abrasive blasting and coating operation were never more than one joint apart. In order to achieve reasonable liquid epoxy cure times it was important that the steel be hot, but not so high as to damage the coating or cause vaporization of harmful vapours. Pipe adjacent to the girth weld acted as massive heat sinks cooling the girth weld area and leading to extended epoxy cure times. In order to improve the process, entire welded sections of pipe were preheated by blowing hot air in one end.

The injection of foam into the molds proved relatively trouble free. Once the liquid epoxy had cured and was holiday free, steel molds were mounted over the girth weld. If moisture was present on the girth weld, it was wiped dry as isocyanate in foam reacts with water. The polyurethane foam was injected into the mold by timing or counting the number of pump strokes. The steel molds were treated with a siliconebased release agent. The amount of release agent used was minimized as any residue adversely affects adhesion of the shrink sleeve to the PE overlap and polyurethane foam.

Once the foam insulation had cooled and cured the mold was removed and the insulation was inspected for defects. The PE overlap was abraded to improve sleeve adhesion and to remove all traces of foam adhering to the PE. The PE overlap area was preheated to the minimum preheat temperature recommended by the sleeve manufacturer. Heating of the polyurethane foam was minimized to avoid damaging and reduce off gassing of the polyurethane foam. Adequate and even preheating of the PE overlap area was critical to ensure that the hot-melt adhesive used on the sleeve was activated. Sufficient rolling during the sleeve application was required to ensure all entrapped gases were removed.

Drill sections over 500m (1640 ft) in length were required to cross major waterways and several roads. Edge protectors were applied to the leading edge of all shrink sleeves to lower the risk of sleeve damage. The diameter of the drill bore was oversized to lessen the possibility of damage. All directional drills were deemed successful as the coating on the lead joints pulled beyond the exit were in good condition and resistance-to-ground measurements taken at each crossing revealed high resistance.

Valves and fabricated bends were coated in the shop with the liquid epoxy approved for girth welds by
plural-component spray application. Above ground portions of the valves were painted with an epoxy
phenolic paint. These items were coated in the field with polyurethane foam using a sequential injection molding process and were subsequently coated with a spray-applied polyurea coating.

Repairs to the outer jacket and heat shrink sleeves were dependent upon the size of the defect. The PE outer jacket was abraded prior to applying the repair material. Repairs under 50 mm x 50 mm (2 in. x 2 in.) were repaired using a PE repair patches, ensuring an minimum overlap of 75 mm (3 in.). Heat shrink sleeves were used to repair any larger defects. Prior to lowering the pipe in the ditch the outer jacket was carefully inspected for damage and repaired as required.

CATHODIC PROTECTION

Mainline and station piping will be protected with cathodic protection (CP) using impressed current upon completion. Studies have shown that the PE outer jacket and insulation may limit the effectiveness of CP systems. PE is known to shield CP under certain conditions not to mention a large ohmic drop is experienced across polyurethane foam insulation. The CP system will provide protection in damaged areas where the CP current is not shielded. Where the CP current is shielded, the anti-corrosion layer is designed to protect the pipeline.

Qualified CP inspectors were selected to evaluate coating damage at directional drill sites, install CP test facilities, and collect information for the CP system final design and installation. Their inspection duties included the following:

The final CP design will cover the cathodic protection system size and location, HVAC testing and
mitigation, foreign crossing testing and mitigation, equipment installation, a static and energized survey, and a final report.

OPERATION

A comprehensive integrity management plan is in place to ensure that safe operation and integrity of the pipeline is maintained from start up to deactivation of the line. The plan includes monthly CP system maintenance inspection and annual surveys. The pipeline will be internally inspected within 10 years of installation. Based on operations, coating integrity, and the internal inspection results, an appropriate internal inspection interval will be established and continually adjusted throughout the life of the pipeline.

CONCLUSIONS

An innovative coating system was developed to meet the demanding requirements for transportation of dry bitumen through muskeg areas of northern Alberta. The coating system was developed in close
cooperation with consultants, coating applicators, material manufacturers, and suppliers. The material
selection process took into consideration: the pipeline operational requirements; operating temperatures up to 130°C (266°F); environmental conditions composed in part of muskeg; coating application process in shop and field; reparability; and material costs. An assessment of existing material testing procedures was performed and a number of standard qualification tests were modified to qualify coating materials. A robust, cost-effective coating system was selected. While historical performance information is not yet available, it is expected that long-term monitoring will validate the design and application of the insulated three-layer coating system used on the MacKay River Pipeline.

REFERENCES

1. Performance of Pipeline Insulation Systems in Arctic Conditions, Mike Alexander (Garneau Inc.) and
Carmine D’Agostino (Nova Chemicals), Nov. 4, 1997.
2. Pipeline External Corrosion Management and Construction Methodology for Athabasca Pipeline, A.A. Castro, W.J. Kresic, and B.R. Scott (Enbridge Pipelines Inc.), Mar. 10, 1999.