E&P goes green

Elaine Maslin

May 1, 2017

Elaine Maslin looks at efforts to breathe new life into old oil and gas platforms, such as refitting for renewable energy, while also cutting CO2 emissions and cost.

An illustration of the Win Win (wind-powered water injection) project.
 Image from DNV GL.

Combined forces – the push to decarbonize and an industry with offshore facilities coming ever nearer to the ends of their lives – has provoked some innovative thinking.

On the one hand, renewable technologies could help to decarbonize offshore oil and gas production, while on the other, decommissioning could be an opportunity to breathe a second life into offshore facilities, geared towards a greener economy.

Such ideas – and combinations of them – were discussed at the Offshore Mediterranean Conference (OMC) in Ravenna, Italy, late March, with Eni often leading the charge.

“Things will never be the same as they were before,” says Innocenzo Titone, conference chairman.

“In the transition (to a cleaner economy) the oil and gas industry has a role to play. No transition will be achieved without integration of renewables and fossil fuels, specifically gas.” Such moves may be made compulsory in future legislation.

As part of the 2015 Paris Climate Conference (COP21) agreement, ratified last year, Italian major Eni committed to peddling renewables in addition to hydrocarbons. It’s not a new goal – many oil firms, in fact, dove into renewables in the past only to let programs slide as oil prices rose. Donato Azzarone, vice president of energy solutions, renewables energies at Eni, points out that renewables have been considered in the exploration and production space for some time: solar-diesel power hybrid electrical submersible pumps have been used onshore Egypt, solar powered steamflood has been deployed, and wind turbines have been providing power on platforms.

Ben Oudman.
Photo from DNV GL.

DNV GL’s Ben Oudman calls such an idea “late life greening.” Another example of this is the Leman Echo facility in the southern North Sea, which used to be a gas processing platform. As the reservoir has dwindled, so has its use, but it is still a gas receiving facility. “NAM (a Dutch operator) decided to strip it down and install a large solar array,” Oudman says. “It will be unmanned and all the energy for the gas transfer will be from solar power with diesel generation as a back-up,” he says. This reduces CO2, although this is mostly from cutting helicopter rides, it also boosts health and safety, as it is unmanned, and decarbonizes the existing activity, he says.

Eni CEO Claudio Descalzi says that Eni is weighing the use of renewables on oil and gas facilities. He points to how much power – from gas – is used to run offshore platforms and that this could come from renewables, instead of by burning gas or diesel. Higher rates of return on renewable power generation could also be achieved if combined with upstream, he says, not least because gas otherwise used for power generation could be sold instead.

“In the Mediterranean, we have 110 platforms, (some) installed 50-60 years ago. They are old, but we don’t want to scrap them,” he adds. “We want to transform their use, using solar, marine and wind energy. We are investing, in some cases, in pilots to test the use of all these different energies together. Use what we have and create new sources of energy.”

Italian Economic Development Minister Ivan Scalfarotto also says that facilities off the Adriatic coast could be reused for wind and solar energy, or for monitoring the marine environment, seismic, tourism or wireless transmission.

The prize

DNV GL says that by taking various measures, oil and gas firms could reduce their CO2 footprints cost effectively, on average, by 29% – offshore Norway at least, which already has a tax on CO2 and therefore is perceived to be progressive in this space, said Liv Hovem, senior vice president Africa and Europe, DNV GL Oil & Gas at OMC. In greenfield projects, where opportunities to introduce new technologies – such as renewables, combined heat and power, carbon capture and storage and others – are easier, this could be 35%. With 75% of oil production in 2040 predicted to be from new fields, this could mean a huge CO2 emission reductions in new fields globally, she said.

DNV GL has produced a tool to assess the opportunities, using what it calls a marginal abatement curve (MAC). This considers the cost per tonne of CO2 of a measure and the overall CO2 emission reduction. The firm assessed 28 different CO2 reduction measures, from carbon capture and storage to alternative power and reducing flaring.

But, Hovem said that it is not just about adding new technologies, it’s about how you operate a platform. “Power management and performance monitoring are promising quick win measures,” she says. Reducing flaring, subsea processing and heat recovery are other shorter term wins. There’s also an opportunity to use a hybrid system where turbines, which operate more efficiently at maximum load, could be complimented by battery technology, allowing a reduction in turbine capacity.


Another angle of Win Win. Image from DNV GL.

One option is to use floating wind turbines to power subsea facilities, such as subsea water injection, specifically. DNV GL completed a feasibility study, with input from ExxonMobil, Eni and Statoil, on such a concept, based on a site in the North Sea. DNV GL targeted a 44,000 b/d concept, which would traditionally require a 3MW gas turbine on a platform. Replacing the 3MW gas turbine power would require a 6MW wind turbine, she says.

In DNV GL’s concept, all the water injection equipment would be housed on a floating platform, which would also support the 6MW turbine. This would include a microgrid, to even out the power supply to control the water injection rate, as well as satellite communication, and four batteries for power storage, to be drawn down when production isn’t high enough. The battery power would only be for keeping the onboard equipment on standby and communications systems running when the turbine isn’t generating electricity.

According to analysis by DNV GL, if there are prolonged periods where the wind isn’t strong enough to produce power, it wouldn’t be damaging to have a period where water injection is inactive. The platform would also have a riser (for lifting water for re-injection), a water filtration system and a pump for injection.

Francesca Feller, senior consultant, DNV GL, points out that, from 2020, wind turbines will be rated 10MW (210m-diameter, 50MW annual production) and higher. Today, alongside the 6MW turbine, all other elements of such a system are available or being tested.

Economically, such a system could work, but it depends on the site and specific project demands, Feller says. DNV GL has run a simulation using real North Sea wind data and found it would be able to maintain injection above a minimum requirement. An indicative life cycle cost would see US$3/bbl saved over 20 years, she says. On top of that, 17,000-tonne of CO2 emissions would be averted.

In a case where the injection is a longer distance from a platform facility, the benefit would be greater, she says. Retrofit applications, where an existing platform hasn’t been fitted with injection facilities, could also be a positive case, she says. A possible phase two of the project will be to test the concept.

Weighing the options

Working for DNV GL in the Netherlands, Oudman says there’s an opportunity to use some of the hundreds of facilities in the North Sea for renewables – or other purposes, such as aquaculture or even tourism (something perhaps more likely offshore Italy) – even when facilities are past their oil or gas producing lives. In fact, he suggests, the timing could be good to coincide with and enhance the renewable wind build out.

Oudman says that existing facilities could be reused for power-to-gas facilities – i.e. turning excess wind power into hydrogen or even synthetic methane. This would see wind power used, at times of low demand (where it is otherwise unused), to create hydrogen.

“There is a huge amount of decommissioning that is going to take place in the North Sea in coming decades: 600 platforms, 5000 wells, 10,000km of pipelines. This has an estimated cost of $32-42.6 billion (€30-40 billion). As a replacement for fossil fuel production, a huge amount of offshore wind will be installed in the same basin – 50-100GW. In parallel will be decommissioning in oil and gas and a build-up in renewables.”

In the Dutch sector, there are 163 platforms (10 of which are oil facilities) and 2000km of pipelines, often in just 30m water depth. On average, facilities are 25 years old, Oudman says. “Just for the Dutch industry, the cost estimate for decommissioning is $5.3 billion (€5 billion) until 2050.” Meanwhile, some 3.5GW of offshore wind capacity is due to be installed between now and 2023, at a cost of about $2.1-3.2 billion (€2-3 billion). “So there’s (a combined) €8 billion ($8.5 billion) spending on decommissioning and build-up in renewables,” Oudman says.

Currently, the Netherlands is focused on Round Two projects, but further rounds will be closer to where many of the offshore oil and gas facilities are.

“It is difficult to store electricity, so if you use it to make hydrogen it could also make synthetic methane; you could avoid the cost of putting electric cables to shore,” Oudman says. “You just put in what you need with the cables, the rest is brought to land (as hydrogen) with offshore pipelines. There is significant cost to be saved if you can repurpose an asset, assuming it has enough life [left] for the job in the jacket and pipelines.”

Oudman says that transporting gas is more efficient than transporting electricity. Comparing the BritNed interconnector and the Balgzand Bacton Line pipeline, which cost similar amounts to install, Oudman says the first, an electric system, costs $245/kW (€230/kW) per 100km while the second, a gas pipeline, has an equivalent $11/kW (€11/kW) per 100km. Put another way, he says replacing a 500km onshore transmission link with a pipeline with hydrogen would offer equal returns (synthetic methane would be cash negative, however). “If you can use hydrogen for transport and shipping, that’s where you can find a positive business case,” he says. DNV GL looked at a case study, using a 3.5GW wind farm. It assessed that of the 3.5GW some 400-600MW, or a sixth of the capacity, could be used to generate hydrogen or synthetic methane with a positive return.

He also says another possibility is producing ammonia using the excess wind power, bringing it ashore as a liquid. Transporting the hydrogen or ammonia by ship would also offer flexibility of where it is sold, he says.

Oudman also highlighted a project to create an offshore energy hub, which would involve creating artificial islands, supporting offshore wind – as a transmission hub and a platform – as well as fish farming, pumped hydro-storage, and power-to-gas. Dutch transmission firm TenneT and Danish national transmission firm Energinet have been looking at the North Sea Offshore Power Hub concept and signed a memorandum of understanding last year to investigate the concept. It would incorporate 458GW pumped hydro-storage, “vast power-to-gas potential” using existing infrastructure and a wind farm on a ring dyke forming the island, Oudman says. It would link all wind farms planned for 2030.

If this isn’t feasible, facilities, the jackets at least, could be left in place as havens for marine life, for both current inhabitants and future marine life. This is an option being taken by Engie and state participant EBN offshore the Netherlands (OE: December 2016). Two platforms will be left in place and monitored over 10 years as a trail type of rigs-to-reef project.

The bigger picture

There’s also a bigger, ocean economy picture, points out professor Roberto Danovaro, of Marche Polytechnic University in Ancona, Italy. He told OMC, in light of moves by the Organisation for Economic Co-operation and Development to focus on a sustainable economy of oceans, and other efforts towards sustaining marine biodiversity: “Now is the time to look at these structures in a new perspective. We know decommissioning will happen globally. There are three main problems: the cost; the question whether it is absolutely needed to protect the marine environment; and are these structures useful to the marine environment.”

Finding an alternative use could be an answer, he suggests. This could be using platforms as (marine) reserves, for CO2 storage, aquaculture, etc. It may mean a case-by-case analysis of each platform, because each has a different habitat, which he admits would be complex. He proposes an ecosystem-based deepsea strategy, which is being developed under the Merces Project. (merces-project.eu)

“Reuse is useful, but any strategy we use must be based on monitoring,” he adds, something that industry could help with.