A problem well thought through
  from: Offshore Engineer
  by: Terry Knott
  Thursday, November 01, 2001

Shell Expro’s Shearwater field returned to production recently following a lengthy investigation into the failure of one of its wells. Terry Knott was invited to talk to the operations team to learn more about the causes and solutions emanating from the realms of metallurgy.

As the largest high pressure/high temperature (HP/HT) offshore field and facilities in production at that time, the £874 million Shearwater project, backed by licence co-venturers Shell, ExxonMobil and BP, had been a focus for technologies developed to handle unusually demanding reservoir conditions (OE April 1999) – 1000bar and 180°C, with hydrogen sulphide, carbon dioxide and a high salinity aquifer. But despite the many technical advances achieved, one relatively small though vital manufacturing detail, invisible to the naked eye, was destined to bring the giant HP/HT installation to an unexpected halt.

‘The field had come on stream on 9 September last year, and five of the platform’s six wells had been commissioned,’ says asset manager Mike Rodgers. ‘However, not all of these wells were in operation, due to teething problems with topsides equipment elsewhere on the platform. During commissioning of one of the wells, SW08 – the first to be drilled – we had detected a very small leak between the ‘A’ and ‘B’ annuli and had consequently closed in the well for monitoring and further investigation once it had cooled down, while we proceeded to commission the other wells and address the remaining topsides issues.’

Then, on 10 November, with SW08 still closed in, a rapid rise in pressure occurred inside the 97/8in production casing (see diagram page 15). The first alarm came with the automatic closure of the subsurface safety valve (SSSV), normally held open by hydraulic control line. Almost immediately, the pressure in the annulus rose from a few bars to 785bar.

A fracture in the production tubing was immediately suspected. As gas was bled from the well, the pressure declined, indicating that if indeed it was a fracture, it was located above the closed SSSV, installed at 531m inside the 5000m deep well.

‘The pressures experienced were well within the design capability of the Shearwater wells,’ adds Rodgers. ‘Throughout the project, safety had always been the primary driving force, and consequently there was no doubt that SW08 would have to be killed. Once that was done we would be able to enter the well and pull the production tubing to determine what had occurred.

A ‘three pronged attack’ was developed for dealing with the problem well. The SW08 well would be killed by pumping heavy mud down the production tubing and annulus, using a stimulation vessel. Local kill facilities would also be brought to the wellhead platform to act as a contingency backup. And a drilling rig would be required to enter the well to set a permanent plug and pull the production tubing.

The other wells which were in operation were closed down over a period of days. At the time of the pressure rise, three wells were in production: one was shutdown at the time, while two remained exporting through a single production train, reducing inventory and closing the system down gradually to prevent hydrate formation. Shearwater ceased to export gas and condensate on 15 November.

Schlumberger’s Big Orange stimulation vessel was available in the market at that time. Over the next two weeks, the vessel’s pumps were upgraded to deliver 1000bar pressure, while Shell, its co-venturers, and service providers devised a plan to kill the well in consultation with the UK’s Health & Safety Executive.

‘The mud pumping operation was carried out in three phases,’ explains Mike Marray, Shell Expro’s head of well engineering. ‘The closed-in pressure below the tubing retrievable sub surface safety valve was 790bar and we began the well kill by pumping in 100 barrels of base oil. This was followed by 375 barrels of kill weight ceasium formate brine. The base oil was needed to absorb and displace the reservoir gas which would otherwise have percolated through the ceasium formate during the killing operation. The final phase was 425 barrels of kill weight oil-based mud. After displacing this the well was hydrostatically dead.’

The kill operation was completed on 24 November 2000. During this period extra pumps and more heavy mud were shipped out to the field and installed on Shearwater’s wellhead platform, as an independent system ready to kill other wells had that been required.

With SW08 now rendered hydrostatically stable, the well was ready for entry to pull the suspected failed tubing. Drilling jackup Mærsk Endurer was chosen for the job – the HP/HT rig had drilled all of Shearwater’s wells, the crew was familiar with Shearwater’s operations, and the jackup’s footprints were still present in the seabed. But the rig had moved and was already at work in Shell Expro’s Skiff field in the southern basin, work which had to be suspended. The operation to bring the jackup to the central North Sea in mid-winter was delayed by bad weather, resulting in Mærsk Endurer not being positioned over the wellhead jacket until the beginning of February this year.

‘We considered many possible explanations for the tubing failure during this period,’ says Marray. ‘One of them focused on the small leak we had found in the production casing earlier. We devoted considerable effort to confirm whether chlorides present in the mud in the ‘B’ annulus could corrode the tubing having passed through the leak in the production casing. Or maybe the leak was just a red herring in this situation.’

The leak did indeed turn out to be a red herring, but it was not until the Mærsk Endurer isolated the reservoir and pulled the production tubing that the operator could really begin to understand what had caused the problem. After much careful planning and preparation, the tubing was withdrawn from the well in April to reveal that the Inconel 718 tubing hanger had failed.

‘Our first reaction was positive,’ notes Rodgers. ‘We now knew exactly where the failure was and that any repeat in other wells would not result in a containment issue. The question now was why had this extremely tough material failed?’ To answer that question the Shearwater co-venturers embarked on a thorough investigation, backtracking through the manufacturing and testing history of Shearwater’s wells.

As a critical component, the tubing hanger had been subjected to rigorous inspection onshore under controlled conditions before being installed in the well, as part of the supplier’s contract. Now, working with metallurgists from The Welding Institute in Cambridge, the Shearwater team determined that the Inconel did indeed meet all the mechanical properties specified for the duty. But close scrutiny of the material’s microstructure revealed evidence of hydrogen embrittlement. However, also present was some delta phase material in the structure, a feather-like effect among the grains created prior to forging which is normally removed in the subsequent heat treatment stage during manufacture. While delta phase material can be accepted in some environments it is believed to predispose the Inconel to hydrogen embrittlement and is therefore unsuitable for downhole use.

Checks for other delta phase Inconel components followed, testing a spare Shearwater tubing hanger and other Inconel components of the production tubing pulled from the well, including the SSSV and production packer. No evidence of delta phase was found.

Next came checks on the heat treatment process, carried out by specialist subcontractors to the supplier. This should have removed the delta phase from the metal. It was discovered that the tubing hangers for wells 1, 5 and 7 and the spare tubing hanger had been heat treated in the same batch by one company, while wells 4, 8 and 9 had gone through batch heat treatment at a second company. Comparing the detailed temperature data for wells 1 and 8, the two batches showed there were differences in procedure, leading the team to question whether wells 4 and 9 could also contain delta phase Inconel in the way well 8 had done.

The two wells were checked in situ employing a technique used by The Welding Institute. The well was entered through the ‘A’ annulus outlet valves in the wellhead, giving access to the neck of the tubing hanger. Air-driven tools were used to polish the material in the hanger and then etch it. An imprint of the etching was made using a thin acetate film and this was studied microscopically. The tests revealed that delta phase was also present in these two hangers.

‘It appears that the actual failure of the metal can occur when three factors are present together,’ says Rodgers. ‘Delta phase, hydrogen atoms and high stresses in the metal, although these conditions are difficult to replicate precisely in the laboratory. Now we know that we must check for delta phase in Inconel in future.’

The heat treatment process for the three hangers did not eliminate the delta phase. Additionally, in well SW08, average atomic hydrogen concentrations were found to be around 4ppm, higher than the usual concentration of 1ppm or less normally found in Inconel. The higher concentration may be attributable to the copper plating process of threads in the hangers, a conventional process used on downhole components to prevent threads galling, which in non-delta environments does not lead to problems. The delta and hydrogen together almost certainly contributed to the rapid failure of well SW08.

It is not known when the Inconel first cracked, but the load supported by the hanger – some 150t – would have finally become too great for the imperfect metal to remain intact, leading to complete failure.

To remedy the situation for Shearwater, Shell Expro plans to replace the failed hanger and the two suspect ones. They will conform to a new specification prepared by the investigation team.

‘Obtaining large volumes of Inconel and machining this takes time, so this will not be a quick solution,’ observes Marray. ‘We are considering this to be a base case while more work continues on understanding delta phase in these conditions. We may have to modify this plan in time.’

At the end of June, Shearwater was bought back on stream through well SW01, followed by 7 and 5, while the other three wells remained closed. Although the platform experienced a recent shutdown due to a damaged flare tip, production has now climbed back up to over 40,000b/d condensate and almost 6 million m3/d sales gas. Mærsk Endurer, under contract until next July, remains on station and will side track well SW08 from a depth of around 4000m before the end of this year.

‘The drilling and completion phase at Shearwater was best in class but unfortunately production has been disrupted by metallurgical component failure,’ concludes Rodgers. ‘The safety of our team and the installations has been at the forefront of our decision-making as we addressed the technical challenge and will continue to be the case as we move forward. Much has been learned from this for the whole industry and we are now on track to have all six wells in operation at full capacity by spring of next year, if not sooner.’ OE