Low-salt solution

June 24, 2014

One of Clair Ridge's jackets is shown on an installation barge in 2013. Photo from BP.

BP applied a “less is more” approach to enhanced oil recovery, and, in doing so, won a Distinguished Achievement Award from Houston’s Offshore Technology Conference. Sarah Parker Musarra reports.

Endless calculations are made to determine how many barrels of oil can be produced in a day to estimate when production will peak, or, even more importantly, when it will begin to peter out.

As greenfields age browner, various enhanced oil recovery (EOR) techniques are trotted out to try to recapture the magic once more. This is especially important since the US Department of  Energy places the percentage of oil recovered from a given reservoir at somewhere in the 20-40% range, with EOR techniques providing an additional 30-60% recovery.

However, when the second phase of the Clair field—known as the Clair Ridge development, located 75km west of Shetland and estimated to recover 640MMbo—begins production in 2016, BP’s reduced-salinity water injection LoSal EOR will be employed to boost oil production from day one.

With this decision, BP is changing the traditional field development model: Production decline is no longer the trigger for EOR.

“There’s a saying the best time to plant a tree was 20 years ago; the second best time is now. A similar principle applies to EOR,” Raymond Choo, deployment manager for BP’s EOR Technology Flagship program, said.

The first of its kind

“It’s groundbreaking. No other company has installed low-salinity water offshore for EOR,” Nnaemeka Ezekwe, BP’s LoSal EOR deployment manager said.

BP estimates that an additional 42MMbo will be recovered from the UK Continental Shelf’s largest undeveloped hydrocarbon resource by using LoSal EOR, part of the company’s suite of Designer Water technologies.

The supermajor was recently honored for Clair Ridge LoSal EOR at Houston’s Offshore Technology Conference in May with its second Distinguished Achievement award in four years.

BP's Quad 204 redevelopment will use a new FPSO and polymer injection is being investigated for EOR. Photo from BP.

Better water through chemistry

One common oil recovery method is water injection or waterflood, which has been used in the industry in various forms since around the 1930s. Water of some sort, typically de-oxygenated, high-salinity water, is commonly injected in drilled injection wells to flood the reservoir, increase pressure in depleting reservoirs, and stimulate production.

However, significant oil was still being left in the reservoir, despite the highsalinity water injection. It’s chemistry, explained Ezekwe. BP examines why the oil molecules would stick to the reservoir’s rock surfaces. With the reduction of salinity, ions are reduced, and more oil molecules are freed.

BP said that LoSal EOR, its designed low-salinity water, positively impacts pore-scale displacement, and pushes this “bound oil” through to the production well by relaxing what the company calls “bridges.” These bridges are actually double-charged, or divalent, ions, such as calcium and magnesium. These ions compress to the surface of clay through electrical forces in presence of highsalinity water.

In reducing the salinity, the bridges expand and relax. Monovalent ions replace the divalent ions, and, free of bridges, more oil molecules can be released.

Seawater has differing levels of salinity, although the Office of Naval Research places the average at around 35,000ppm. LoSal EOR is significantly less; BP quantifies it as a few thousand ppm.

“If you remove most of the salt, you will be able to increase oil production, greatly reduce scaling and reservoir souring risks,” Ezekwe said.

During LoSal EOR’s 2008-2009 field trials at Endicott field in Alaska, oil and water – those two famously incompatible liquids - met with good results: increased oil production similar to that found during LoSal EOR’s lab testing.

BP Chief Operating Officer, Reservoir Development & Technology James Dupree, pictured right, accepts the Distinguished Achievement Award from Offshore Technology Conference chairman Ed Stokes on 4 May 2014. Photo from Barchfeld Photography.

“Low-salinity water was injected in one well, and the incremental oil production observed in another. Endicott proved up the laboratory trials at full scale,” BP said.

From Clair to Clair Ridge

At the time of its 1977 discovery through to its 2005 production commencement, Clair, located in around 150m of water, also marked several firsts. It was the biggest field in the UK Continental Shelf, and featured the first steel jacket in the West of Shetland area. It has produced 100MMbo, with production peaking in 2007 at 50,000bo/d.

The Clair Ridge development will consist of two bridge-linked platforms. Pipeline infrastructure connecting it to Shetland is also in the scope of work. The jackets were installed in August 2013; the topsides are planned to be installed in 2016. Peak production is expected to hit 120,000bo/d. The US$7 billion investment includes $120 million for desalination facilities to incorporate LoSal EOR into the development plan.

BP operates Clair Ridge with 28.6% interest. Its partners include ConocoPhillips (24%), ChevronTexaco (19.4%), Shell (18.7%) and Amerada Hess (9.3%).

EOR challenges and opportunities

-Elaine Maslin 

Enhanced oil recovery, or EOR, was described as the holy grail at the DEVEX conference in Aberdeen in early May.

The prize is significant, particularly in the North Sea. There, EOR is attractive because it enables operators to “find” more barrels of oil in a basin in which new discoveries are becoming increasingly small.

In 2012, while annual production was close to 500MMboe, only 150MMboe was approved under new projects and only 50MMboe was found through exploration.

Yet, while EOR might be where the industry can find more barrels more easily, there are also

many challenges, from corporate support for large, costly schemes, which could takes years to pay off, to supply chain and even logistical considerations.

BP has been running EOR projects in the North Sea for a number of decades, including its Distinguished Achievement award-winning LoSal EOR technology. “EOR works in the sub-surface and tends to grow with time,” but, “the size of the prize, and access to infrastructure and injectant supply are critical (to its success),” Euan Duncan, lead reservoir engineer, BP, told a Society of Petroleum Engineers (SPE) talk in Aberdeen in April. “Confidence in the process is also critical.”

Duncan says large projects an long-term outlooks are required to make EOR projects a success. For example, to use polymers for EOR in the UK North Sea, there would need to be major investment in manufacturing capacity, potentially a new plant. It is also crucial that infrastructure—platforms and pipelines—are available and maintained long-term so that EOR projects can be adopted, he says.

BP has used miscible gas, using water alternating gas (WAG) on Magnus (Northern North Sea), Miller (central North Sea).

Miller was the first, starting in 1998, drawing on technology BP had used in Alaska. “Miller had good reservoir properties but also high residual oil saturation,” Duncan said, but the suffered with WAG compressor failures. BP also looked at using CO2 injection on Miller, but it was too late in the field’s life to make the project work economically, Duncan said.

In 1999, BP installed a WAG compressor on the Ula field in the Norwegian North Sea, for miscible gas EOR. The project increased over time, more injectors and wells were added, and it is likely the Ula project will be expanded again in 2019, Duncan said. In 2001, Magnus also had WAG compressors installed and the platform is due to undergo a maintenance campaign in 2016 to extend the facility’s lifetime (OE: October 2013).

“The main lesson for us has been the importance of asset integrity, fiscal relief (tax allowances), and getting the compressors and economics right,” Duncan said. If the industry is to further use EOR, collaboration between operators, to create clusters, enabling large-scale projects, would help, Duncan said. The industry could also draw on initiatives like IFP Energies nouvelles’ EOR Chemical Alliance.

BP’s next EOR schemes are polymer flood on the Schiehallion and Loyal fields, part of the Quad 204 redevelopment, with startup in 2017, and LoSal EOR on Clair Ridge, due on stream in 2016.

To date, there have been limited offshore polymer flood applications, which will mean a learning curve for BP, and the wider industry. Issues around offshore polymer use include making sure there is an adequate supply chain to supply the amount of polymer required and then understanding how best to handle the product, taking it offshore either as powder to be mixed, or ready mixed, and understanding how it behaves during these processes.

BP is also researching brackish water, which is only slightly salty. “Our focus within BP is on water-based EOR, LoSal, and from that other technologies and different waters to inject to influence the pore scale,” Duncan said.