Using steam to help increase oil recovery, particularly from heavy oil, is a well tried and tested technology, but not quite so offshore. Elaine Maslin looks at a bid to change that.
Images from The Steam Oil Production Co.
Steam flooding and cyclic steam injection have become tried and tested ways to increase oil recovery from oil wells, particularly heavy oil or in the tar sands where a special variant of steam injection known as steam assisted gravity drainage (SAGD), is used.
But, most of the efforts around steam flooding or cyclic steam injection, known as the Huff and Puff method, have been onshore.
Few, to date have tried to take the technology offshore, with the common assumption being that the density of wells required and the heat loss as injected steam travels down the well into reservoirs would be too great.
However, a UK company is now proposing to use steam flood for a field in the UK North Sea, which, if successful, could pave the way to develop other similar fields in the basin.
A Pilot reservoir
The Steam Oil Production Co. has its eyes on the Pilot field, in Promote License P2244 in Blocks 21/27a and 28/2a in the central North Sea, also containing the Pilot South and Harbour (both discovered by Fina in 1989 in excellent quality and permeability Tay Sandstone reservoir) fields and the Pilot Southeast prospect. The license has been appraised by Fina, Venture Production and then EnQuest.
Together, the three discovered fields contain 272 MMbbl proven plus probable oil in place at 12-18°API and 160-900cp reservoir viscosity, and around 3.5-6 Darcies permeability, according to Steam Oil. But, while a horizontal appraisal well in the most viscous region flowed at just under 2000 b/d from a 600-700m-long well, the recovery factor, with long horizontal wells and water injection, would be about 13%, leading to an uneconomic project.
Steam Oil thinks better rates could be achieved using steam flood. The company was set up in early 2014, aiming to initiate the first offshore steam flood in Europe.
Steam Oil founder and CEO Stephen Brown says steam injection in the North Sea actually isn’t as unfeasible as it might sound.
“What attracted us to steam flood was the potential for higher recovery factors,” he says. “Chevron predicts 50-80% [recovery factor using steam flood]. Based on modelling, we are looking at around 60%, achieving about 150 MMbbl production from Pilot.”
Steam flood screening / from the Petroleum Engineering Handbook
Not so deep concerns
One of the key criteria for a steam flood project is depth. If a reservoir is too shallow, it could result in steam blowouts, but if it is too deep, heat loss in the well will reduce the quality of the steam too much. Going too deep will also, in combination with the steam, push the limits of completion components, Brown says. As a result, typically, the depth limit is given at around 3000ft, sometimes a little deeper, he says.
“At 3000ft, typically the reservoir is at 1300psi,” Brown says. “At that pressure the steam temperature will be about 300°C or 600°F. There are a range of components available at that temperature, but you have to be very careful about selection. If you go to 5000ft, we are talking 340°C and you start to run out of completion components.”
But, there is some hope here, as the industry has been developing components for use on steam assisted gravity drainage (SAGD) wells in Alberta and for geothermal wells.
“When we first applied for the license we expected depth to be a big issue,” Brown says. The firm expected they wouldn’t get better than 50% steam quality, by the time it reached the reservoir, from 90% quality, 1500psi steam injected at the surface. But, after winning the license and undertaking heat loss modeling using a CMG Stars simulator, they received some welcome results.
“The results were surprising,” says Greg Harding, the firm’s technical director. “We were only losing 5% of steam quality in the model. We thought there must be some mistake, so we looked around for other information on heat loss and realized a key factor is the rate at which steam is injected. Because the temperature of the steam is set by pressure, that keeps it constant. So you get a broadly consistent loss of heat, regardless of the rate you are injecting down the well.”
The key to injecting at a high rate, and an enabler for this technology offshore, is being able to drill high density horizontal wells, Brown says. On Pilot, you would need 400 conventional wells. Using long horizontal wells, 100m apart, with alternating injection and production wells, you need 40, he says. “Those two things opened up this possibility.”
Shopping for kit
The Steam Oil Production Co. has assessed what it would need in terms of topside equipment. They approached Cleaver-Brooks, a boiler manufacturer in the US which supplies SAGD projects in Canada, which suggested Steam Oil use an industrial water tube boiler, which can be quite compact. A 364,000lb/hr boiler, weighing 250-tonne, including ancillary equipment, could produce 25,000 b/d steam, Brown says. This would be instead of once-through steam generators typically used in tar sands heartland Alberta, Canada.
To produce the steam, water treatment facilities would also be needed, so Steam Oil went to Aquatech, which supplies mechanical vapor compression equipment for Mukhaizna heavy oil project in Oman, onshore. Aquatech advised Steam Oil to use reverse osmosis or similar, which is what BP is using on Clair Ridge for their fresh water, Brown says.
To get water pure enough – with solids content at less than 10ppm – they would need two passes through reverse osmosis and then using electrodeionization (EDI). This would mean lifting 300,000 b/d sea water, taking it from 35,000 ppm to c. 3000 ppm in the first stage, then 300 ppm in the second stage and to <10 ppm in the EDI, with 120,000 bbl water left. Once turned into steam and injected, the reservoir could then produce 80,000 b/d water and 35-40,000 b/d oil, Brown says. The water treatment equipment would weigh less than 200-tonne and adding both this and the steam generation equipment would only add 10-15% to the project’s cost, Brown says. To house the equipment, and to enable intensive drilling and ability to access pumps in wells, etc., Steam Oil is looking at a fixed well head platform with dry trees.
Steam Oil is also looking to deploy autonomous inflow control valves (AICVs), to optimize the flood. “The 1500m-long wells will be 100m apart, pushing a pillow of steam across from one well to the other,” Brown says. “But, it won’t go in a straight line. It will wobble, with steam breakthrough in one area before another. To maximize recovery we want to shut off that break through point as soon as possible and it looks like the AICV is promising technology to do that.” Steam Oil has been looking at Norwegian firm Inflow Control’s AICVs, which were initially designed for to control gas coning in the Troll field offshore Norway.
Tried and semi-tested
While steam flood is certainly not common offshore, it has been tried. In Lake Maracaibo, Venezuela, steam boilers on barges inject steam on a Huff and Puff basis.
In Bohai Bay in China, CNOOC has also used Huff and Puff on a number of fields and they have also been mixing combustion products with the steam, to increase the recovery, Brown says.
Offshore Congo, Perenco has been using steam on the Emeraude field in 65m water depth. Total had a pilot in the 1980s, then Perenco built a platform and steam flooding started in a number of wells, but there seems to have been limited success, possibly due to the nature of the reservoir there, Brown says.
Brown says the Pilot field is very much like Shell’s Schoonebeek field which stretches across the Dutch and German border, where it is operated by Wintershall and called Emlichheim. It is at a similar depth, 3500ft, and 3 Darcies permeability. Shell is using a similar well pattern as that planned for Pilot, but, at Schoonebeek the reservoir is more faulted and pressure depleted, Brown says.
While Steam Oil has a broad plan in place, Brown says there could be optimizations, such as recycling the produced water and capturing heat from it, to reduce energy input.
“One of the things we want to do is make the process as efficient as possible,” Brown says. “We are currently predicting we are going to have about 2.5-3 bbl of steam per barrel of oil extracted and the reality is that makes the economics work. But, if we can reduce that steam oil ratio it would improve the economics.” The ratio is typically 2.5-5 on SAGD projects, he says.
There are also additional techniques, like those being tried in China and Canada, to add non-condensable gas, such as methane or nitrogen, to reduce the ratio to 1.5, or use a solvent like propane or butane, which would help mobilize the oil, with the added benefit of helping product transport downstream.
But, these optimizations are further down the process for Steam Oil. The young company with a big vision is now looking to work with partners to bring its idea to reality. We look forward to seeing the results.