Keeping seawater in its place - Scandinavia Offshore
  from: Offshore Engineer
  by: Terry Knott
  Friday, August 26, 2005

Development is under way in Norway of a new subsea system which can both treat and inject seawater at the seabed for enhancing oil recovery from reservoirs. Terry Knott reports.

But now the next logical evolutionary step is moving closer to reality whereby the seawater would not have to make the lengthy return journey via the topsides for treatment. Instead the treatment processes would be performed alongside the injection pump at the subsea wellhead, giving operators flexibility in the optimal siting of subsea injection wells and removing the constraints imposed by the number of well slots available on the platform.

Known as SWIT - subsea water injection and treatment - the concept for the new system originated in Stavanger-based engineering company Sørco, as the company's technology manager, Dave Pinchin, explains.

'SWIT is a method of bringing together a set of existing proven technologies into a single all-electric subsea unit. The idea of treating seawater on the seabed is not new, but it has generally been accepted that taking water at the seabed level could result in high solids in the intake if the seabed was disturbed, for example by currents or storms, which would lead to poor quality water reaching the reservoir. In addition, the water treatment processes traditionally used on topsides - typically coarse and fine filtration, electrochlorination and deaeration - are by their nature complex and are perceived to require hands-on control and maintenance. The treatment methodology we have devised and patented, and notably the water intake technique, are the key to overcoming this move to the seabed.'

Sørco - whose expertise lies primarily in topsides processing - began pursuing the idea about two years ago. Soon after, the company teamed up with Poseidon Group in Stavanger to bring onboard the requisite subsea knowhow.

This summer the two set up a new company, Well Processing, to take the concept forward.

Relocating water treatment to the seabed brings several advantages, say the companies. Water injection flowlines from the host platform are eliminated, and with SWIT sitting directly above the optimum injection point, the wells can be vertical, reducing drilling costs.

The SWIT unit, which interfaces directly onto any standard subsea tree, will be installed as part of the well completion. The unit contains the seawater treatment stages which are designed as modular components to enable them to be retrieved to the surface and replaced using ROV and light service vessel.

Those stages address treatment issues including solids control, reservoir souring and scale prevention.

'Inorganic solids, such as sand and silt, do not get taken in to the system, so we don't need fine filters,' Pinchin points out. 'The intake design is patent pending and we are not revealing too much at the moment, but suffice it to say that it is designed to take advantage of Stokes Law and the predicted settlement of particles down to about 35 microns in size. The intake deign creates a very low water velocity and a long pathway, so particles have time to drop out long before they reach the pump.'

Current industry thinking about injected water quality has shifted over recent years, moving from rigorous standards such as removing 98% of all solids particles greater than 2 microns in size, to a looser specification accounting for other reservoir issues such as thermal fracturing, a trend which is in support of the SWIT methodology.

Organic solids in the seawater are taken care of by continuous chlorine dosing to provide bacterial protection all the way to the reservoir. The chlorine is generated from seawater by an electrochlorinator - according to Pinchin, subsea electrochlorinators are proven technology in the submarine defence world.

Chemical dosing to control biological slime can be achieved by 'shock treatment'. To achieve this on a periodic basis, the treated seawater is diverted over solid chemical bricks which dissolve in the flow, or over chemicals in gel form which have high active ingredient content.

When it comes to the issue of downhole corrosion, Pinchin acknowledges SWIT will require operators to think in terms of using corrosion resistant materials in the injection well completion tubing.

'Standard topsides practice to combat corrosion is to remove oxygen from the seawater by deaeration, an operation needing large process vessels and the subsequent application of chemical oxygen scavenger - even so, sampling of treated injection water has demonstrated that it picks up corrosion products from the flowlines on its way to the well, so SWIT would at least avoid this situation. However, it is a fact that the seawater we take in will still contain a few parts per million of dissolved oxygen, even in deep water locations, and mixed with the chlorine this would be corrosive, hence the need for corrosion resistant tubing. But as the wells will be vertical rather than long and deviated, the extra cost will be offset.'

At the heart of SWIT will be two subsea injection pumps - one duty, one standby - already proven in operation and available from several manufacturers. The pumps and valve actuators within the subsea unit will be electrically operated, supplied with power through a single high voltage cable from the host facility - typically at 3000V topsides and transformed down at the subsea unit. The cable, which could be branched to feed several units, would also carry control and monitoring signals between platform and SWIT. The use of costly umbilicals to convey chemicals and hydraulic fluid to the wellhead is therefore avoided, along with minimising any necessary topsides modifications.

An actual SWIT unit is yet to be built and tested, says Pinchin, but the first steps toward that goal are being taken now with a feasibility study being funded by ConocoPhillips for potential use of SWIT in the operator's Ekofisk field. The Ekofisk South development plan is considering the installation of a new platform on this sizeable reservoir which requires significant water injection volumes, and could be served by a collection of SWITs around the field rather than multiple injection wells extending from the platform. A typical SWIT could deliver around 200m³/h of treated seawater, which means three units could meet a 100,000b/d water injection demand. 'The economic case for SWIT is attractive,' adds Pinchin. 'We expect the cost of a unit to be in the region of NKr50 million plus the cable cost. Given that many small satellite reservoirs are only achieving oil recovery rates around 33%, and that SWIT could push this up to say 50% through optimally positioned water injection, payback period could be as short as six months.'

The ConocoPhillips study phase, currently focused on a single SWIT and supply cable, is scheduled to conclude in November this year. Funding has already been secured from the Norwegian Research Council (Petromaks) for subsequent string testing of hardware components. Well Processing is now actively seeking additional financial support from operators with a view to getting a SWIT on the seabed in 2007. OE

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