Getting heavy

September 1, 2017

Elaine Maslin surveys some of the heavy oil field developments in the UK Continental Shelf, plus some of the technology aimed at unlocking it.

The Pilot area. Image from The Steam Oil Co.

Heavy oil is making an impact on the UK Continental Shelf. This year, EnQuest’s Kraken heavy oilfield came on stream east of Shetland. Meanwhile, Statoil’s Mariner US$7 billion fixed facility heavy oil development is taking shape in the same region (Read: Progressing Mariner).

Relative to existing North Sea heavy oil fields that are already in production, such as Chevron’s Captain field, at API 19.5°, these are heavy fields and there’s a reason they’re only just being developed (based on investment decisions made before 2014).

UPDATE: 20 October 2017, Chevron made FID on a polymer EOR project at Captain. Read more here.

A look at a list the world’s heaviest offshore oil fields offers a telling tale. According to data from industry analysts Wood Mackenzie, a large chunk of the heaviest oil fields discovered offshore to date have not been developed. Those that are being developed have been waiting some time for the technology to be ready to drain them.

This is because heavy oil is heavy work. Heavy oil is measured by its API gravity. The smaller the number, the more viscous the oil, ranging from a thick oil to something more like marmite. Development, offshore, almost always means the need for downhole pumps and diluent injection, and, as in Mariner, heavy well count (100+). Other technologies to aid recovery of this thick liquid are being considered.

The UK’s heavy oil fields

Tudor Rose, an undeveloped UK North Sea field, is one of the five heaviest discovered offshore oilfields, at API 8.5°, according to Wood Mackenzie. It was deemed “sub-economic even at very high oil prices,” by MOL Group in a license relinquishment report last year.

The next heaviest known oil discovery on the UK Continental Shelf (UKCS) is Statoil’s Bressay at API 10.8° (at number 14 in the global rankings). It was once seen as a sister development to the Mariner oil field, but is currently “parked” pending Statoil gaining more experience on Mariner. Associated gas from Bressay had initially been eyed for use for power on EnQuest’s Kraken development.

Xcite Energy had been trying to finance the development of Bentley (16 in the global rankings), also on the UKCS. Bentley was discovered back in 1977, and its API is 11°. To put this in context, says Joao Conde, a production assurance specialist at Aberdeen based Infinity Oilfield Services, Bentley oil is a little like marmite.

The liquidators of heavy oil explorer Xcite Energy have sold the firm to a group of its bondholders, called Whalsay Energy, for US$1. Xcite had hoped to submit its development plan, including use of dual electric submersible pumps (ESPs) and diluent, before then end of 2016, before falling into liquidation, having failed to refinance. Former ConocoPhillips UK and Talisman UK senior executive Paul Warwick is listed as one of Whalsay’s directors, as of 4 July.

Mariner, discovered in 1981, meanwhile is API 13° and contains some 2 billion boe, just a fraction of which will be produced, due to the nature of the oil. Statoil’s Peregrino field, another heavy oilfield produced via an FPSO, offshore Brazil, is API 14.5° (see page 44). Statoil is considering polymer flood on Mariner, but not until it has completed trials of the technology on Peregrino, which itself follows a trial on the firm’s Heidrun field in Norway (OE: May 2017).

EnQuest’s Kraken is API 14°. The field, 125km east of Shetland, or 350km northeast of Aberdeen, is due to comprise a total 25 horizontal wells (14 for production and 11 for injection), with gravel packs and hydraulic submersible pumps (HPSs) in the producers. They are being produced via Bumi Armada’s Armada Kraken floating production, storage and offloading (FPSO) vessel. The pumps, ClydeUnion-branded hydraulic submersible pumps (HSPs), manufactured in Glasgow, Scotland, were supplied by SPX.

The Kraken field, discovered in 1985, spread over 42km at a depth of 1300m below sea level, is expected to hold 128 MMboe of gross 2P reserves. Late June, 13 wells had been drilled and completed to date, comprising seven producers and six injectors.

EnQuests’ Kraken heavy oil floating production vessel. Image from EnQuest.

Liquid properties

One of the problems is that this viscous liquid has properties that can change depending on its environment, i.e. pressure and temperature, as well as how much water is produced with it, which influences emulsion forming, making it harder to move and handle in separate phases, Conde says.

HSPs or ESPs are used, which require power, and diluent injection can be done, increasing process and import requirements, says Niki Chambers, production assurance specialist at Infinity. Water separation and handling, especially in a brownfield scenario, being able to blend oils, and managing unplanned shut downs are further challenges. Chambers says fluid monitoring will become more important, yet many flow meters aren’t good with heavy oils.

Despite the challenges, there’s a lot of heavy oil out there and there are those who see an opportunity, including the UK’s regulator, the Oil and Gas Authority (OGA).

According to a Society of Petroleum Engineers Distinguished Lecturer Program presentation by retired Shell executive Johan van Dorp, there’s 10 trillion stock tank oil in place resources in the world, with current global heavy production is about 10 MMb/d, with 2 MMb/d from thermal (steam based) production.

The OGA sees heavy oil as an opportunity. “The recent success of the Kraken heavy oil field coming onstream shows what can be done. Indeed, the OGA believes that Kraken, and the Statoil Mariner field, have the potential to open up additional heavy oil opportunities in the North Sea,” the OGA told OE. It is focusing on promoting new technologies and technology sharing, and the formulation of area plans to capitalize on nearby infrastructure to help promote heavy oil development, with the Quad 9 area in the North Sea seen as a key area of potential.

But, the OGA cautions that current oil prices do pose a challenge, “so sharing technologies and identifying the most cost-effective ways to investigate and tap heavy oil potential will be even more crucial in the short term.”

Of the some 360 discovered but unsanctioned small pools (fields under 50 MMbbl) on the UK Continental Shelf, many are heavy oil, Chambers says. Technology, such as HSPs, enhanced oil recovery (EOR) techniques like polymer, or steam flood, mostly used onshore, are some of the options which could help improve recovery rates, she says.

Steam and other alternatives

UK based independent, the Steam Oil Co., holds a northern North Sea license containing the Pilot field, which it hopes to develop using steam injection – something few, to date, have tried offshore (OE: December 2015). Pilot, a discovery with API 12-18°, and the nearby Pilot South and Harbour fields, contain 272 MMbbl proved plus probable oil in place, says the company. While recovery rates using traditional technology would be low and uneconomic, steam flood would offer much higher recovery rates – up to 60% – thinks the company. And it says it wouldn’t be that difficult, because the reservoirs are quite shallow.

Still, the challenges of producing and injecting steam offshore are significant. Another firm thinks it might have an alternative.

Working with the University of Strathclyde, Glasgow, Aberdeen-based Cavitas, founded in 2015, has created a device which can be deployed downhole to generate heat fluid within injection and production wells.

The thermal heavy oil recovery (Thor) system uses a rotor within a housing to heat fluid or steam inside the wellbore of injection wells and can be used as a bypass fluid heater.

The Cavitas device would be a sealed unit and filled with a high temperature fluid (oil). This fluid would be heated by the rotation of the rotor and in do so it would heat the external body of the device. It would be powered by a suitable motor (electric or hydraulic). Injection water flowing past the device would be heated by thermal conduction, resulting in hot water/steam being injected into the reservoir, lowering oil viscosity, increasing mobility and avoiding the losses associated with conventional topside thermal EOR.

For a production well, a Cavitas generator would be incorporated into a downhole artificial lift device, such as an ESP or HSP). It would “fit seamlessly” within the completion and draw rotational power from the HSP/ESP. There, it would act in the same way as the device used for injection, this time heating production fluid as it passed over the device, prior to its entry into the HSP/ESP, lowering viscosity and increasing production.

Traditionally, steam flood using gas/oil powered boilers is used for heavy oil production onshore. Due to size and intensity of this activity, it’s not been used offshore. “We won’t have the output of the massive steam plants, but because our device is efficient and the losses are downhole anyway it doesn’t need the same output,” Cavitas says. “Our research in conjunctions with a UK Heavy Oil operator has shown that even small injection rates of heated fluid/steam (c.500-3000 b/d) can have a huge production upside.”

Onshore, efforts are looking into using liquid or condensing solvents, to shift heavy oil (including as a way to make steam flood assisted gravity drainage more efficient), but also electrical heating. Both of these are being demonstrated, says van Dorp. The latter – electrical heating – includes formation heating, in various forms, including; using a heating element down hole (thermal condition, like Cavitas); using electrodes in separate holes to conduct current and make heat; induction downhole; and high-frequency radio frequency.

Read more:

The North Sea gets steamy

Sticky business

Progressing Mariner



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