Last month (October 2017), Chevron approved plans for a commercial polymer EOR project on its UK North Sea Captain heavy oil field. Elaine Maslin looks at the broader prospects for EOR projects on the UKCS.
For many fields on the UK Continental Shelf (UKCS) the clock is ticking. The basin has been producing oil and gas for some 50 years and many facilities are reaching the end of their lives.
The average UKCS recovery factor from oil fields is projected to be about 46% at end of field life, which leaves significant potential to be tapped – if enhanced oil recovery (EOR) technology can be harnessed in time.
Use of EOR technology has been on the radar for some time. It was highlighted by the government-industry PILOT project, and then also the 2014 Wood Review – a report that set out what the UK North Sea industry needs to turn itself around and maximize its remaining potential.
Screening by the PILOT work group found a theoretical maximum (un-risked) total 6 billion boe EOR potential on the UKCS. The group’s view was that the economic (risked) EOR potential was between 10-20% of the maximum (un-risked) amount, i.e. 600-1200 MMboe. Furthermore, the economic (achievable) EOR potential for the top 20 fields alone equated to 500 MMboe, which is comparable in size to the top 20 new projects that had their field development plans (FDPs) approved over the six-year period from 1998-2013.
The Oil and Gas Authority (OGA), set up on recommendation of the Wood Review, has taken up the mantle, with polymer-based EOR at the top of the agenda. The OGA has set a goal to “drive economic development of 250 MMboe incremental reserves” primarily through polymer EOR over the next decade. Proven offshore operation of low salinity EOR is next on the hit list, followed by a next generation of EOR technologies, such as miscible has injection using CO2.
In 2014, at $100/bbl, EOR projects were more attractive. However, today’s low oil prices have impacted how much cash operators have for these schemes. They come with brownfield modifications costs and the challenge of accessing natural gas or CO2 for injection.
BP’s Glen Lyon FPSO, pre-fitted with polymer EOR equipment. Image from BP.
There are currently just two active EOR schemes in the UK North Sea: a hydrocarbon miscible gas injection scheme at BP’s Magnus field and Chevron’s polymer EOR scheme on the Captain field (OE: May 2017). The Captain EOR project is designed to increase field recovery by injecting polymerized water into the Captain reservoir. The scope of stage 1 of the project includes six new polymer injection wells and brownfield modifications to platform facilities. A final investment decision was made on 20 October 2017. Stage 2 would expand polymer injection to the full field and is dependent on the results from stage 1.
BP is also working to bring its Clair Ridge project online next year, which will see the world’s first offshore low salinity EOR scheme (OE: June 2014), and other projects are at presanction stages of evaluation, such as BP’s polymer project at Quad 204 (OE: September 2015) and Statoil’s potential polymer flood project on the Mariner heavy oil field (OE: May 2017). BP has made a pre-investment in tanks and pumps on the new-build Glen Lyon floating production unit, which came onstream in May, but the project is subject to partner sanction, according to the OGA’s EOR Strategy document.
The potential for use of EOR technology for heavy oil recovery has also been seen on Quad 9 (home to the Kraken, Bressay, Bentley, Mariner, Harding and Gryphon fields), meanwhile, the Steam Oil Production Company has been assessing steam flood technology for heavy oil fields in the central North Sea (OE: December 2015). Another technique “out there” is thermally active polymer.
As OE went to press, the OGA published a report; Polymer Enhanced Oil recovery – Industry lessons learned, supported by BP, Chevron, Shell and Statoil. It says polymer EOR can be economic and that there are there are six fields where there are plans to implement polymer EOR, potentially delivering some 194 MMbbl of incremental reserves. This represents an incremental recovery factor of 5%.
It recommends standardizing a suite of experiments that should be consistently applied and available to all, to assess the compatibility and polymer selection to aid screening work.
Dave Puckett, the OGA’s senior reservoir engineer, says that, as well as working on existing projects, field development plans are also being screened for their inclusion of EOR technologies.
“The challenge is the capex and opex prices of different EOR technologies,” Puckett says. Indeed, a report by petroleum economist Alex Kemp from the University of Aberdeen from 2015 suggested that tax incentives might be needed to encourage EOR projects (OE: April 2015).
“In the longer-term, it’s our hope CO2 becomes achievable,” Puckett says. “CO2 is very good for miscible gas injection, but the economics are challenged and we don’t have a source of CO2 at the moment.” The OGA is seeking the government’s view on carbon capture and storage (CCS) (last year the UK government dropped a significant CCS project). Norwegian plans to shipped captured CO2 offshore could also improve this situation.
Thermally active polymer could be used as an alternative to workovers, Puckett says, by using a small amount of treatment to block off water cut in a specific area. So-called Bright Water is a form of this technology. Another technology, which is the subject of a joint industry project (JIP) supported by the OGA, is carbonated water, which contains the gas used to makes oil more mobile in water that is injected. “It changes the way the gas is pumped into the pore space,” Puckett says. “The CO2 comes out of the water and into the oil and the oil then becomes lighter and easier to move.”
Other JIPs supported by the OGA include a low salinity water injection project at Heriot-Watt University and the Dolphin JIP with France’s IFPEN. This project has been running for three years already and is now entering a second phase, looking at the effect of chemical EOR (polymer or surfactant) on the water cycle in the reservoir, i.e. how they behave in flowlines, the reservoir and production equipment. The project has been looking at fields in Brazil and onshore Europe, but the second phase will include a UK North Sea field, too.
Meanwhile, the University of Warwick is involved in a project with SNF to find a way to measure the molecular weight of polymer in a solution.
There are clearly challenges to implementing these technologies, from cost to more practical considerations, including facilities not being designed in the first place to be able to accommodate EOR related equipment. Subsea completions, if not designed similarly, will also be a challenge, Puckett says. Having a good understanding of the subsurface, usually by having performed water flood for a number of years, is also important, he says. If CO2 EOR is used, it brings with it corrosivity, which will be a challenge.
Having said that, BP is going straight into LoSal EOR on its Clair Ridge field, an extension of the producing Clair field, such is its confidence in the technology. This will have the benefit of having dry oil for longer, Puckett says, which in turn reduces H2S and sulfate scale issues, because clean water has been injected from day one.
But, it’s not just about the individual technologies. Combining these technologies could enhance recovery further. To help companies understand the opportunities and challenges, the OGA is putting together a “starter pack,” to help others not already involved in assessing EOR technologies understand some of the risks associated with polymer EOR. This was due to be published in summer this year.
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