The offshore industry has always been good at noting milestones. It does not take much legwork to find the details behind the deepest well, the longest pipeline, the heaviest offshore lift, or tallest bottom-founded platform.
So it is not surprising that the first significant long-distance (more than 20 mi) tieback is easy to record. The Troll Oseberg Gas Injection project (TOGI), which Norsk Hydro planned and executed in the early 1990s, is the benchmark by which all of what has gone on in the last 15 years is measured. At 48 km, it exceeded all that had gone before it by tens of kilometres, essentially raising the achievement bar to an impressive height.
And what has followed is impressive. Within half a dozen years, Shell in the US developed the Mensa field, which not only doubled the tieback system to over 100 km, but also was (at its time) the deepest production in the world at 1,645 m. Another five years on, Canyon Express, though it did not extend the tieback distance, took the production depth record to nearly 2,200 m.
It is not just distance and water depth that make these projects exceptional. Norsk Hydro’s Ormen Lange and Shell’s Corrib off Eire will see some of the wildest offshore weather conditions in their construction phase. The subsurface complexity of British Gas’ West Delta Deep marine concession in the Egyptian Mediterranean has required a multi-phase development. While the subsea facilities team views the development as three big structures, the reservoir folk see at least half a dozen subsurface structures.
What has also become an increasingly important element of these developments is their production reliability. All of these long tiebacks deliver natural gas, which is either sold in advance on contract or will feed an LNG facility that requires regular operations to maintain a high level of efficiency. Production shutdowns would cause severe disruption for their customers.
The Saipem 7000 heavylift vessel installs the TOGI template.
But TOGI was an unusual beast in many ways. First, Hydro did not develop it to produce gas for industrial or domestic consumption, but as a pressure support medium for Norsk Hydro’s Oseberg main reservoir. Second, TOGI was not a field on its own, but part of the massive Troll gas field, at that time the biggest offshore gas field (1,300 bcm) in the world, that would not start producing for another five years. Third, it would be the North Sea’s first deepwater development at a time when the industry saw 1,000 ft, or 300 m, as a milestone. Of most significance, though, was that the challenges that confronted the project team were so significant that at least one of the partners did not believe that what was being attempted could be achieved.
From the perspective of 2005, TOGI does not seem that remarkable, but, in reality, so much of what Hydro planned had not been done before that it seems quite amazing that the Troll license group and Norsk Hydro’s management agreed to the development.
The project aimed to provide gas that would be injected to increase recoverable reserves from the Oseberg reservoir by 6-7% or around 75 MMbbl. This may seem to have been a modest goal, considering that Norway was not yet looking at marginal field developments. There were other considerations. This scheme would reduce the number of production wells and eliminate the need to drill 21 water injectors, the latter estimated to cost NKr2.6 billion in money of the day. In addition, unlike injection water, the 30 bcm of gas that Hydro was to inject over 12 years could be recovered at a later date when the Oseberg gas cap was producing.
It was the new subsea technology to be employed at TOGI, though, that the project team must have found daunting. On the positive side, two members of the license group, Shell and Elf, were experienced subsea operators who not only had deployed subsea systems in the North Sea and elsewhere, but who had spent considerable research and development effort on a technology that was key to future production success.
Behind the scenes, the Norwegian Petroleum Directorate provided support as well. The NPD, not unlike Shell and Elf, saw the future in subsea and thought that success here would be an important technology breakthrough. So right it was. At some point before 2010, more than 50% of production on the Norwegian continental shelf will come from subsea wells. NPD Director-General Gunnar Berge has indicated that his organization expects to see an increase in recovery rates from subsea wells. Statoil has already picked up this challenge under its Subsea IOR (improved oil recovery) program.
On TOGI, the subsea control system was at the top of the technology challenge list. Nothing like this - a 50-km remote control tieback - had been done before. Vetco Gray won the subsea control system contract, but the key player was subcontractor Hughes Aircraft in California. New thinking on both software and electronics was required, and Hughes, with its extensive experience in working with the US military, had both.
As part of the test program, Hughes built a 50-km test umbilical. What Hughes achieved with this control system was actually beyond what Hydro required. Having proven that the electronics would work over the 100-km roundtrip, the test team linked up two of the four conductors and proved the technology over 150 km.
Next on the list of technology challenges was the pipeline tie-in, which would be another first for the industry. At that time, no one had done a diverless pull-in of a 20-in. pipeline, and this was one area where the project team and its contractors - here it was Kværner - did not anticipate potential problems.
With few construction vessels capable of the pull-in and a drilling unit on location, the semiPolar Pioneer won the contract for this operation. The semisubmersible carried out the initial pull-in, but when the test team made the connection and tested the line, they discovered a leak. The team subsequently learned that grit had deposited on the surface of the tie-in hub, preventing a proper seal.
An ROV inspection determined the problem, and the team developed a special honing tool to grind the surface of the hub. In a relatively short period of time, the team designed, built, and tested the tool. While this was going on, the team also designed a new sealing ring with somewhat different geometry and sealing areas.
The test team carried out all of this work in 1989, which proved not to have any impact on the project schedule, as it was done in the development drilling period in 1990. In fact, the field came onstream in early 1991, ahead of schedule.
At the time of TOGI, the term flow assurance had not yet come into the offshore parlance. This was another area of concern then, just as it is now on all deepwater and long-distance tieback projects. The development team spent considerable time and money carrying out studies and simulations of the flow over the 48-km distance.
The big concern was over condensate dropout and potential for the formation of very big slugs and their effect on the riser at the host facility. The result was the design and installation of one of the biggest slug catchers ever put on an offshore platform. At the time, it may have been the biggest.
The final key technology issue had to do with sand production. The test team was concerned about the impact of high-speed sand on the christmas tree internals, and Hydro, as operator, wanted to know if sand was being produced. An acoustic sand detector was developed that would sense 1 cu mm of sand per cu m of gas.
There were other technical issues of less concern that Hydro had to deal with, but none proved to be a showstopper on this project. The field operated for 12 years without a shutdown with wells that averaged 2,600 cm/d, an almost unheard level for subsea gas wells before this project. The industry saw it as a breakthrough for subsea technology.
The success of the TOGI system encouraged operators to take the plunge into long-distance tiebacks. Just two years later, Arco developed the Orwell gas field in the UK sector, 40 km from its host facility on the Thames complex. It would be another four years, though, until the next big leap came.
The same year as Orwell, Shell acquired Mississippi Canyon blocks 686 and 687 from Pennzoil, Arco, and Amoco to complete a five-block complex that makes up the Mensa field, first discovered in 1987. Shell must have gleaned something from its experience at TOGI, although initial references to the basis for the Mensa design only mention Popeye. It may be coincidental that Shell decided on a subsea system for Mensa the same year that TOGI came onstream and addressed many of the same issues that Hydro confronted at TOGI.
This is, without doubt, a very different concept. TOGI was a five-slot template/manifold, while Mensa is a three-well offset cluster development, because the wells were to be some distance - all roughly 8 km - from the commingling manifold.
As Mensa was more than twice as far (109 km) than TOGI from its host facility at West Delta blocks 143, Shell saw flow assurance as an even bigger concern, particularly because the main field pipeline was only 12 in.
To prevent hydrate formation in the manifold and pipeline, Shell elevated each of the three 6-in. infield flowlines off the seabed with 15 lift frames installed at 150-m intervals to allow the wellstream to cool to seabed temperature and allow water dropout - and thus potential hydrates - to form upstream of the manifold and be dealt with by glycol injection.
The other issue in common with TOGI was the potential for erosion at the tree caused by high speed sand entrained in the gas. Shell decided to employ an FMC split tree, which would allow the top section of the tree to be removed and replaced while the master valve remained in situ. This proved not to be a roaring success.
When the system came onstream in July1997, the top section of the tree on the A-1 well reportedly flew off. It was later shown that the connector ring that held the two parts of the tree together had failed, sending FMC off to check on the metallurgy of the rings. While this problem was overcome and the field eventually came onstream, this tree design was never used again.
Since that time, Shell has expanded the field with the addition of a fourth well to keep production up at 8,500 cm/d and boost total expected recovery to 22 bcm.
It would be another five years before another LDT caught the attention of the offshore industry.
Canyon Express, like Mensa before it, would be notable for more than technical milestones.
There had not been an offshore development before in which three operators with three different fields linked up to use the same pipeline system to make their individual fields economically viable. This marked a level of cooperation hardly even seen in the offshore sector.
Artist�s impression of the TOGI system.
The only comparable level of cooperation was in the UK sector in the late 1990s, when BP and Shell joined forces for the ETAP regional complex, although BP probably could have gone it alone without the benefit of the Shell subsea tiebacks. Getting two operators to cooperate can be difficult, but three just seems improbable.
But that is what happened. BP (King’s Peak), Elf (Aconcagua), and Marathon (Camden Hills) agreed to develop these three gas fields as one using twin 12-in. flowlines tied back 90 km to new platform Canyon Station, which would provide gas compression facilities and a methanol recovery unit.
Each of the fields is in waters beyond 2,000 m, but Camden Hills took the prize, if for only two years, as the deepest production in the world at 2,195 m.
There has been a progression on this series of LDTs, although whether it qualifies as an advance depends on one’s perspective. TOGI started out with a 20-in. production line. While there were concerns about hydrates, their formation in such a big pipeline seems less likely. At Mensa, Shell opted for a single smaller (12-in.) line with a mitigation scheme to avoid hydrate formation in and downstream of the gathering manifold. At Canyon Express, twin flowlines provided an alternative export route and prevented three disparate fields with as many as 10 wells from being shut-in all at once.
From three landmark projects, five operators, and a number of different technical solutions, the long-distance tieback, which has advanced from 50 km to 100 km and soon to 150 km, is now a regular feature of the subsea development landscape. There is more yet to come.
