The old adage that oil and water do not mix is probably lost on offshore operators who have to separate hundreds of millions of tonnesof water from the oil they produce every year. It can add up to a bill of tens of millions of pounds.
As the big fields in the UK sector of the North Sea deplete, the water content, or `cuts’, in their wellstreams are increasing: in BP’s Forties field it is 80-90% and the overall picture is not much better.
`We’re producing one and a half tonnes of water for every tonne of oil. Water separation is a major headache,’ says Bryan Taylor, the technical director at the UK Offshore Operators’ Association.
Latest figures from the Department of Trade and Industry put the amount of unwanted water produced by British operators at more than 190 million tonnes a year.
The traditional method of dealing with this is for the processing equipment on deck to separate the water from the oil, clean the water up to the internationally agreed standard of 40 parts per million and squirt it back into the sea.
But future developments will be less amenable to this process: they will either be in water too deep to install conventional fixed platforms, like those to the west of the Shetlands, or involve small oil accumulations that need to be tied back a few kilometres to an existing structure.
Both present difficulties. Floating production systems, whether mono-hulled vessels or tension-leg platforms, have more constraints on topside weight than fixed structures: process equipment on board has to be kept to the minimum. Subsea tiebacks are likely to present a problem, too, as the host platform may not have spare water separation capacity.
Environmental considerations will also put a strain on the traditional approach. While a blanket ban on the disposal of `cleaned’ water is not likely in the near future, oil companies are already feeling pressure to come up with a more acceptably green solution. BP, for instance, considers the practice to be inconsistent with its target of zero emissions to the environment.
The alternative to sea disposal is to reinject the water into the reservoir, but this means installing even more topside equipment and aggravates the difficulties.
Taylor says that apart from re-injection, the other current strategies for limiting the impact of the problem are managing reservoirs better to reduce the water cut in the wellstream and reduce the level of oil in the water.
A better solution would clearly be a separation/re-injection system which could be installed at the wellhead on the seabed. Not only would the problems of topside weight constraints disappear, but operators would no longer have to waste energy and resources pumping large volumes of water up to deck level – a matter of several kilometres in the case of some subsea tiebacks. `Any technology that improves the situation is worth looking at,’ says Taylor.
The offshore industry’s underwater processing efforts have to date concentrated almost exclusively on the separation of gas from oil, but last year a group of big oil companies led by BP set up a joint industry project to develop a configurable subsea water separation system (CoSSWaSS). The other participants were Mobil, Statoil, Texaco, Agip, Elf, Amerada Hess and Norsk Hydro.
The project was initially planned as a three-phase undertaking. The first stage, a concept definition study, was contracted out to Kvaerner Oilfield Products. The second would have comprised the detailed design, fabrication and testing of the system, and the third would have involved an extended trial on a producing field in 1999. The specialist consultancy Offshore Technology Management was appointed to manage the programme.
Within the past three months, however, the scope of the programme has changed. Chris Dudgeon, managing director of OTM, says this followed clear indications that oil companies were pursuing their own pilot subsea water separation schemes. Norsk Hydro will install the first on Norway’s giant Troll field in 1998 or 1999.
`We decided we would do better to apply our efforts to individual system components and subsystems,’ says Dudgeon. `We’ve changed from a pilot testing programme to a managed technology development programme.’
As a result the project has become more open-ended. `We don’t have a particular finish point now.’
The focus is on technology that the oil industry will require for 2000 and beyond – technology to enable subsea separation systems to operate successfully in water depths beyond the reach of conventional platforms. `We’re talking very much the domain of floating platforms,’ says Dudgeon.
The broad challenge is to adapt existing water separation technology into a system that can operate reliably without the need for frequent intervention.
Dudgeon points out that if a separator springs a leak on the deck of a platform, the remedy can often involve `no more than a man tightening the bolts on a flange with a spanner. That’s not quite so easy in a thousand metres water depth.’
One technology that will need to be developed is the subsea metering of oil and water as they emerge mingled in the wellstream. This will be vital for reservoir management. `You do need to know what you’re injecting back into the well,’ says Dudgeon.
Also needed will be flow visualisation techniques and use of multiple separation units, rather than a single large one, to see if they can save space and make maintenance easier.
Two other areas are the distribution of electrical power on the seabed, which GEC-Alsthom is looking at as a separate project, and ways to counteract the external hydrostatic pressure on the separation vessel, which works on internal pressure.
While the structure of the project has changed, Kvaerner Oilfield Products will continue its work on system modelling techniques. Dudgeon says that further contracts will be put out to other engineering companies.
The impact of a successful subsea water separation system is likely to be significant.
Studies by BP and other operators indicate that such a facility would offer big financial benefits in deep-water areas such as the west of Shetlands, the Voring Plateau in Norway and off the coast of West Africa.
Leofric Studd, a senior development engineer at BP who chaired the first phase of the study as originally envisaged, says the cost savings should run into hundreds of millions.
`I don’t think it is putting it too strongly to look at sums of more than a billion dollars over the next 10-20 years for the industry at large,’ he says.
Studd says most of the savings will come from the `de-bottlenecking’ of existing facilities, where further subsea tiebacks to a host platform are constrained by the platform’s water-separation capacity.
A successful subsea separation system could allow small neighbouring accumulations in such circumstances to be developed without the need to install additional host platforms – a proposition which could in itself render many of these small subsea projects uneconomic.
`If you multiply that up for several fields, that’s where the tremendous savings will come from,’ says Studd.