Jarle Hvidsten and Ole Petter Nipen, Baker Hughes
End-of-life assets have become a much-debated topic in the past few years, not least because many are now operating far beyond their originally expected lifespan. Decommissioning includes the removal of end-of-life production wellheads – as well as non-productive exploration wellheads – unless special dispensation to leave them in-situ is granted.
Facing uncertain times once more, operators are naturally looking for ways to control those costs. In the North Sea, several older wells that had been temporarily abandoned with the intention of being removed at a later date – when the capital would hopefully be available – have now reached that ‘later date’ when no more delay is possible. This has led the operators of these fields to search for additional efficiencies.
The costs of wellhead removal largely derive from the complexity of the conventional means of carrying it out. Take a traditional abrasive water-jet cutting system: it will require a team of six to eight people operating a high-pressure system in a high-risk environment. The equipment itself can weigh between 50 and 60 tons and take up to 1,500-2,000 sq ft (139-186 sq m) of space. Such is the extent of the deck spread on the transporting vessel that it leaves little room onboard for the removed wellhead.
All this increases the costs: the two days needed at the quayside just to bring onboard and interface all the equipment; the multiple voyages needed to remove multiple wellheads; the hours involved in planning and coordination of all the moving parts – not to mention the carbon emitted during each voyage. What’s more, the tools themselves can be extremely energy intensive: 1,000 horsepower to operate the equipment spread is common.
Then there are the circumstances where abrasive water-jet cutting systems simply cannot be used at all. Where the wellhead concerned is installed at a depth greater than 366 m (1,200 ft), the surrounding water pressure renders the pressure cutter all but useless. In these cases, a mechanical cutting system is necessary. This cannot be deployed from a vessel. Instead, a drilling rig, with all its associated costs, is needed. Typically, a rig-based deployment will take more than twice as long as a vessel-based deployment – and can increase the cost by a factor of 10 or more.
As with many of the changes seen in the past decade, this is an area where smart thinking, innovative technology, and close relationships between suppliers and operators can challenge established ways of working and deliver newer, simpler and more cost-effective solutions.
Working closely with an operator in Norway, Baker Hughes began looking for ways to combine the deepwater capabilities of a mechanical cutting system with the cost advantages of vessel-deployed abrasive waterjet cutting methods. The overall goal was not just to match existing capabilities of both, but to create a new solution that improved on their results.
The team turned to its existing three-knife, hydraulically operated multi-string cutter, which has extensively been deployed for rig-based casing cutting operations. To make it compatible with vessel-based deployment, Baker Hughes’ experts developed a simple subsea system, to be deployed in conjunction with an ROV, a connector and the industry-proven mechanical cutter – and named it Terminator. The prototype was trialed at a testing facility in a Norwegian fjord before the operator deployed the new system on a remote abandoned exploration well in the North Sea.
The advantages of the new approach were immediately clear. Like its rig-based counterpart, the cutter can cut through multiple strings of casing or large-diameter strings safely and quickly, and it can be used for any application where rotation and pressure can be applied but requires only 100 horsepower to do so. Instead of relying on power supply from a rig, the system is driven by the ROV hydraulics, which immediately eliminates the need for any extra downlines, hoses or cables – and the associated risk of them becoming entangled.
Once the system is deployed overboard, no additional equipment remains on the deck, the small surface footprint is leaving room for multiple wellheads if needed. The ROV then guides the cutting system into the well where the connector latches on to the wellhead to be removed. The ROV will power the hydraulic motor that can rotate the cutter and adjust the pressure to the knives’ actuator to make the cut. As a result, the system only requires two people to operate it.
The new system can take as little as 35 minutes to complete the wellhead cut. A pressure drop confirms when the full circumferential cut has been completed, to ensure that no uncut areas remain and to make it easier to recover the pipe. The conductor and spudcan can then be removed in the same sequence from the same vessel if surface handling allows. The total operation can take less than three hours. In fact, the time savings start even earlier: once the subsea engineer has secured any necessary permits to remove the wellhead, it can be just a matter of hours before all the equipment is loaded and on its way.
Systems such as this can be used in shallow waters, but the particular challenges of a deepwater environment mean this is the area in which new solutions can create the biggest positive impact.
Removing wellheads at the end of their exploratory or production life is inevitable. It is an issue that touches on many of the industry’s key concerns – complexity, carbon emissions, compliance, and of course safety – at a time when new cost constraints are causing operators to re-calculate the financial merits of extending the working life of aging assets.
Over the past decade or so, the oil and gas industry has seen new and innovative technologies apply to operations. Some have been tweaks at the edges. Some have been totally transformative. But as this kind of solution shows, successful innovation is really about re-thinking the old ways of doing things and finding consistent and concrete improvements to familiar and fundamentally necessary processes like this.
