Erskine performance indicator for other high temperature lines

Dealing with buckling and ratchetting on North Sea lines

Jeremy Beckman
Editor - Europe

The jacket for Texaco's not normally manned Erskine platform, from where a multiphase pipeline will carry HT gas and condensate to Amoco's Lomond platform for processing. [5,719 bytes]

Next month, the North Sea's first high temperature/high pressure (HT/HP) development is due onstream in UK Central blocks 23/6a and b. Texaco's Erskine project took 14 years to plan, due to uncertainties over extreme conditions. But the big unknown is how the multiphase pipeline will bear up in the years to come.

The usual clich? - all industry eyes will be on this project - will apply because if anything, HT/HP progress has been more tentative in Europe than deepwater deals. Elf and Shell, for instance, thought very long and hard about their respective Elgin/Franklin and Shearwater schemes before sanctioning developments early this year.

Doubts over equipment performance in extreme conditions have also impacted conceptual studies. Shell's new ETAP pipe-in-pipe system, just 44 km long, is thought to have taken a year to engineer, compared with just 12 weeks for a routine North Sea pipeline.

It may take a while for any complications to show through on the Erskine line (another pipe-in-pipe system) , such as buckling and ratchetting (common term for progressive yielding of the pipe wall, leading to thinning). Erskine's gas-condensate line is rated up to 150 degrees C. However, upheaval problems have occurred in the North Sea on hot lines at much lower temperatures, such as Shell's Pelican and, it is rumored, Statoil's Tommeliten.

In certain cases, inappropriate trench ing/burial methods are the root cause of upheaval buckling and subsequent failure. For higher temperature pipelines, contractors seem more inclined to use soil for backfilling in preference to rock dumping. But the long-term impact on soil properties of these higher temperature systems is far from established.

HT limits

In an attempt to answer these and other current imponderables, a joint industry project (JIP) was launched this April to examine the limit state design of high temperature pipelines. Numerous studies are being performed over two years at temperatures of 120 degrees, 150 degrees and 200 degrees C by Andrew Palmer and Associates and Advanced Mechanics and Engineering in London, assisted by Cambridge University's Engineering Department.

Backers for the project include Allseas, EMC, and Coflexip Stena Offshore.

Kevin Williams, principal consultant of Andrew Palmer, points out: "As EPIC contractors, pipeline installers have a vested interested in keeping their capex down." Other supporters of the project are Amoco, BP, Shell, and Statoil, plus British Steel and the UK's Health & Safety Executive.

The JIP will attempt to resolve certain factors that come into play during transportation above 100 degrees C. These include:

Requirement to adopt a strain-based methodology for pipelines where the traditional limit on the equivalent stress in the pipeline is replaced by a limit on the strain experienced by the material.
Effect of elevated temperatures on the mechanical properties of the pipeline steel, including carbon steel and corrosion-resistant alloys such as 13Cr and superduplex.
Potential for strain localization on first start-up of the pipeline.
Potential for incremental plastic strains and low cycle fatigue with subsequent cyclic operation of the pipeline.
Use of numerical methods of analysis to simulate the effects of repeated cycles of thermal and pressure loading, especially ratchetting, in areas of nominal and localized strains.

Results from material and compression tests, allied to the engineering analyses, will be incorporated into a hopefully state-of-the art design guide for future high temperature pipelines.

Shell findings

Some oil companies have conducted their own in-house studies. Statoil, which chose a reel-in-reel pipeline for its Gullfaks satellites, has performed corrosion/high pressure tests on 13Cr samples. Shell Expro commissioned a Mexican steel manufacturer to undertake steel composition tests with the aim of achieving improved elasticity at higher temperatures. Other advanced steels or alloys under the microscope are X65 and X70.

At this year's Offshore Pipeline Technology Conference, John Mossman of Shell Expro outlined his company's recent experiences with high temperature subsea pipeline research. Aside from associated design pressures typically above 5,500 psig, he said, there were a host of challenges to surmount.

"Whether or not there is considered to be a surplus of thermal energy in the fluids will determine whether or not the designer is at liberty to reduce the temperature of the fluids at the wellhead. Such temperature reduction devices, however, are likely to incur overall extra costs and introduce operational constraints. It is possible that the least-cost design will be the most technically challenging."

Various thermal functional requirements need to be met, he added. These concern:

Minimum arrival temperature (dictated by downstream process needs and fluid properties, e.g. wax or hydrate limits).
Maximum arrival temperature (dictated by mechanical design limits, and cooldown duration, as in after an unplanned shutdown).

Each of the above criteria must be satisfied for the range of anticipated flows and fluid compositions and possibly also for well testing.

On embarking on conceptual design, Mossman advised, a key decision is whether the fluids should be cooled prior to entry into the pipeline. If this is the case, the design needs to be robust throughout its projected life taking into account all predicted production uncertainties such as rates, water cut, temperature as well as the impact on the cooling spool of fouling, internal flow regime, and burial. The high probable cost of the cooling device can be offset against less costly insulation systems that come into play through employing a lower pipeline design temperature.

Cooling of fluids brings potential advantages, including a reduced penalty through de-rating steel strength (resulting in thinner wall thickness for hoop stress calculations). But there are also disadvantages in including a cooling spool, said Mossman, such as an extra constraint in the form of a self-imposed lower allowable entry temperature to the pipeline proper.

"Even if a cooler is to be installed such that a pipeline entry temperature of, for example, 100 degrees C can be prescribed, there are still some hot pipeline issues to be addressed in the design, such as strain localization, upheaval/lateral buckling. If a cooler is not installed, entry temperature into the pipeline may be around 150 degrees C. There is no commercially available coating/insulation system, he pointed out, that will perform satisfactorily at that temperature. The only alternative currently is the pipe-in-pipe, but even here practical thermal design limits are not established.

Weld ductility

Shell Expro has implemented its own test procedure concerning the adequacy of weld ductility in a strain-based HT pipeline design. A recent full-scale test was devised on the premise that the pipeline had been laid by the reel method, and was therefore subjected to a large strain cycle, including a peak strain of 1.6%. To simulate the cyclic operated loads foreseen over the design life, an estimated 250 normal shutdown load cycles were included, on top of a few high pressure shutdowns.

The pipe tested was 25% Cr super duplex, with a D/t of 17. It had an SMYS (0.2% offset) of 550 N/sq mm at room temperature. Length of the specimen was 1.2 meters. A full circumferential weld in its center contained flaws deliberately induced during welding, namely:

Root concavity of 1.5 mm deep, 50 mm long.
Lack of root fusion 2 mm deep, 50 mm long.
Cap undercut of 1.5 mm deep, 50 mm long.
Lack of side well fusion 3 mm deep, 50 mm long.

"Monitoring of defect growth during the test was by ultrasonics.," says Mossman. "Pauses were taken after 100 and 250 cycles. At the end of the test, the welds were broken open at very low temperatures (liquid nitrogen) to reveal the defects and to visually confirm the amount of fatigue growth. No growth was visually detected by the test lab, however subsequent detailed microscopic examination has revealed that a small amount of fatigue crack growth has probably taken place at two of the initial surface-breaking (root) defects.

"The test demonstrated that the weld had sufficient ductility as insignificant growth took place at the flaws. The small growth observed did not result in flaws that would become unstable under maximum operating loads."

Mossman concluded that the adhesion of strain gauges to super-duplex material is problematic - it appears an awkward substrate, compared to carbon steel. Also, the accuracy of UT inspection in super-duplex remains questionable. Finally, the intentional creation of flaws by a welder appear to be cumbersome and unpredictable - next time, spark erosion might be considered.

Pipe-in-pipe

Currently, available coatings for HT pipelines include organic polymer systems, but these need to be tested for long-term phenomena such as thermal creep and hydrolysis, said Mossman. Silicon-based inorganic systems could work well in combination with another insulation system, but are likely to be expensive. A cheaper alternative, where significant insulation is not needed, could be bare pipe with cathodic protection, perhaps using thermally sprayed aluminum for added corrosion protection.

The most favored insulation solution for high temperatures is the pipe-in-pipe, first tried in the North Sea in Total's Dunbar export pipeline. As Mossman pointed out, the pipe-in-pipe allows the atmosphere inside the annular space to be adjusted, thereby achieving optimally low heat transfer. It also results in a stiffer overall pipeline which is less prone to upheaval or lateral buckling.

This is the solution Shell has just chosen for its ETAP HT pipeline in the Central North Sea. The 44-km line, under construction at Kvaerner Oil & Gas' Methil yard in Scotland, comprises an insulated 10-in. carbon steel product pipe encased in a 16-in. carbon steel carrier pipe. Each of the 1,800 individual assemblies will be 24.4 meters long, weighing around 10 tons.

Texaco's Erskine multiphase pipeline to Amoco's Lomond production platform is a thermally insulated pipe-in-pipe system designed to prevent hydrate formation under low flow conditions, and to achieve increased throughput. Erskine contains 330 bcf of gas and 75 million bbl of condensate, with an anticipated wellhead pressure of 730 bar. With pressures this high, production is being choked at the wellhead. The wellstream will be piped from a not-normally-manned installation on Erskine to the Lomond platform 30 km to the north, which also contains a new module dedicated to processing Erskine's fluids.

McDermott-ETPM (MET) installed the pipeline in August 1996 using the laybarge DLB-1601. Its successful project tender, awarded in September 1995, was formulated with Mentor Project Engineering. This covered a pipe-in-pipe system laid on the seabed with no added pre-engineered thermal buckling mitigation systems.

British Steel's Hydrotherm system was chosen for the thermal insulation package. The system consists of hollow alumina silicate microspheres contained in an annulus between an outer sleeve pipe and an inner flowline pipe. MET described this system and the project 's progression in another paper at the Offshore Pipeline Technology Conference.

"The inner flowline is butt-welded in the normal manner. The field joint is insulated and the outer sleeve pipes are then joined by means of a sliding steel collar, which is welded into place," the paper stated. "The annular space within the onshore field joint is insulated with Rockwool, and contains a steel bracket which is clamped to the flowline and abuts the sleeve pipe forming a lay stop. This is a means of transferring lay tension from the sleeve to flowline during installation. The offshore joint for completion on the lay barge is similarly a sliding collar concept filled with preformed Rockwool half shells."

The flowline is made from seamless EEMUA 166 grade EP450 carbon steel, specified for sour service, while the sleeve pipe is made to EEMUA 166 Grade EP415, 24-in. by 11 mm WT.

Full-scale impact tests on the Hydrotherm system, including a completed field joint, demonstrated that integrity would be retained in the event of trawlerboard impact, thus supporting the case for non-trenching of the pipeline.

The pipeline was laid in a snake configuration to promote lateral displacement at predetermined locations, thereby relieving compressive thermal axial forces. Amplitude of the configuration from the nominal centerline is 75 meters, with a half wavelength of 3 km. Curvature at the apex is 2,000 meters. Detailed finite element analysis of the route bends was performed., with the compliancy of the combined section verified by various theoretical and analytical tools. Under axial loading, the bend apex displaces at a worst case condition by approximately 15-20 meters laterally.

Peak stresses of around 300 Mpa are predicted in both the sleeve pipe and flowline. Bending moment at the apex of the bends is predicted at around 40% of the installation bending moment, The corresponding strain in the fillet weld is around 0.5-1%.

Ratchetting was also checked. Most of the displacement is recovered on unloading. On subsequent cycles, the displacement is constant and the cumulative fatigue damage due to the number of cycles is low.

According to MET, with the pipe-in-pipe, external corrosion protection need only be applied to the outer sleeve pipe, hence the protection system only needs to accommodate ambient temperature conditions. Due to the aggressive nature of the product stream, corrosion inhibitor will be continuously injected into the pipeline at Erskine. At both ends of the pipeline, risers are connected by flanged expansion offsets. Both risers and spools are also pipe-in-pipe, insulated by Hydrotherm microspheres and Rockwool.