Unleashing technologies to successfully extract hydrocarbons from new and mature fields is among the challenges facing development in the UK North Sea, where oil and gas production has fallen.

Based on the recent resurgence of activity, as billions are poured into major developments, it is apparent that interest has not waned and operators are up to the challenge. Gaining interest are the waters east of Shetlands and the West of Shetlands region. Companies are actively exploring for new reserves while also working diligently to recover oil from the region’s mature fields. While the UK North Sea has produced about 41 Bboe, estimates show that there are about 20 Bboe more that can be produced.

Figures from the Oil & Gas UK Activity Survey 2013 show that realized capital investment on the UK Continental Shelf (UKCS) jumped from US $5.2 billion in 2003 to $17.3 billion in 2012 and is expected to reach $20.5 billion in 2013.

But production has continued a downward dip that began in 2000. Production of gas, oil, and NGL on the UKCS was 2.25 MMboe/d in 1980 and peaked at 4.5 MMboe/d in 1999, according to data from Oil & Gas UK. However, that number plummeted to 1.8 MMboe/d in 2011.

Overall production of UK crude oil dropped by 14.3% in 2012 compared to the previous year, UK Department of Energy and Climate Change (DECC) figures revealed.

Technical and operational issues at the Buzzard oil field, the UK’s largest producing field in 2012, were partly to blame, according to the US Energy Information Administration. Average production fell about 60,000 b/d short of its production capacity of more than 200,000 b/d.

Gas production also fell, dropping 14.1% in 2012. Contributing to the decline was the March 2012 Elgin gas leak.

The steep production declines were the result of not only operational issues and unplanned outages but also tax changes in the mid-2000s that eroded confidence in the oil and gas sector.

But there is hope for a turnaround. Colossal projects under way targeting heavy oil and gas are signs that the area, with a nearly a half-century-old E&P history, is experiencing a resurrection. It comes after the government initiated tax reforms, which were well received by the industry.

Statoil has maintained confidence in the UK, and its Mariner heavy oil project is among those making big splashes in the North Sea with a planned investment of more than $7 billion. The company is relying on technology to maximize the field’s potential.

Challenge includes taming heavy oil

Deemed one of the largest new offshore developments in the UK in more than a decade, Mariner – located on the East Shetland platform about 150 km (93 miles) east of the Shetland Islands – is expected to produce for 30 years, yielding an average estimated production of about 55,000 b/d from 2017 to 2020.

The UK government approved the field development plan in February 2013, a few months after Statoil made its investment decision on the project. The company anticipates making a final investment decision for the Bressay field, which is near Mariner, at year-end 2013.

Production is set to start in 2017 for the Mariner field, which consists of two shallow reservoir sections – the Maureen formation at 1,492 m (4,895 ft) and the Heimdal at 1,227 m (4,026 ft). The heavy oil has API gravities of 14.2° and 12.1°. The company is using technology and decades of experience to make its latest megaproject a megahit.

“In order to make a successful drainage strategy for Mariner and make it a commercial success, you need to be able to develop and drain both reservoirs,” Morten Ruud, vice president for Statoil’s Western Europe operations, told E&P. “It’s heavy oil, and when you are looking into the heavy oil reservoirs, you automatically have a situation where the water moves more rapidly than the oil. So you need to be able to control the water. You need to be able to develop a drainage strategy so that you are able to control the influx.”

For the Mariner this will include using electric submersible pumps and other methods to better optimize the use of power and get a better flow of crude from the reservoirs to assist with recovery. Plans also include the use of horizontal wells where applicable, gravel packing, and the use of control valves as part of completion. “I think the challenge on Mariner and also on Bressay is that you need a lot of wells,” Ruud added. “In order to make these fields economical, you need to be able to drill a lot of wells.”

The Mariner project calls for more than 140 reservoir targets for production or injection. There will be about 50 active slots, and plans include the use of multibranch technology and sidetracks and the reuse of slots. The concept includes a production, drilling, and quarters platform based on a steel jacket with a floating storage unit, Statoil said.

“When you look at the concept of Mariner and to some extent Bressay, we have for the first four years three drilling units working in the reservoir at the same time,” he said. These include a platform drilling rig, a jackup rig, and an intervention and completion unit, which is comparable to a modified workover rig to do upper completion work.

“We really are putting the efforts of the company into the success of this development,” Ruud said. “By doing it we hopefully can create a legacy that we are proud of and is a complement to society.”

EOR technology drives efforts

BP is relying on its LoSal EOR technology to increase oil recovery for another major development in the UK North Sea, Clair Ridge, which received appraisal program approval in March. The second phase of the project is set to see two bridge-linked platforms installed in 2015 with production expected in 2016. The nearly $7 billion project, in the West of Shetland region, will be capable of producing an estimated 640 MMbbl of oil with peak production expected to be up to 120,000 b/d, BP said.

Overall, the $6.8 billion development at Clair Ridge includes around $120 million for the desalination facilities to create low-salinity water for waterflooding from seawater, BP said in a news release.

“In conventional waterflooding, injected water flows through layers of porous reservoir rock, displacing oil from the injection well to the production well. The pore spaces often contain clays to which oil is bound,” said BP, the operator for Clair Ridge. “LoSal EOR, using reduced-salinity water, releases a lot more of the bound oil and pushes it to the production wells.”

Jackie Mutschler, head of upstream technology at BP, said in the statement, “Oil industry wisdom says you shouldn’t inject anything too ‘fresh,’ or the clays within the oil-bearing sandstones can swell and reduce the ability of the oil to flow.

“So BP looked at the fundamental chemistry [that] makes the oil molecules stick to the rock surfaces in reservoirs. What we discovered is that by reducing the salinity, and hence the ionic concentration of the injected water, more molecules of oil could be released from the surface of the grains of the sandstone rock in which they’re held,” Mutschler said. This enables the oil molecules to be moved to the producing wells.

The company believes it will be able to produce about 42 MMbbl more of oil using this method compared to conventional waterflooding.

Other projects gain steam

Clair Ridge is one of several projects in the West of Shetlands region, where activity has ramped up in the past year. First oil production is expected from Nexen’s $3 billion Golden Eagle project in 2014. With an initial gross production of up to 70,000 boe/d, the development is expected to yield an estimated 140 MMboe gross of proved and probable reserves over 18 years.

BP’s Quad 204 redevelopment project will make way for a new FPSO unit to replace the Schiehallion FPSO and extend the existing subsea system with 15 new flowlines and 21 new risers, BP said. The project includes adding 14 wells to the existing 52. The FPSO unit and subsea structures are anticipated to commence production by 2017.

FEED work for Chevron’s Rosebank discovery, 129 km (80 miles) northwest of the Shetland Islands in 1,115 m (3,658 ft) of water, began in July 2012, and a final investment decision is anticipated in 2014. The project includes an FPSO vessel, production and water injection wells, subsea facilities, and a gas export pipeline. It is expected to produce 64,000 bbl of liquids and 42 MMcf of gas daily, Chevron said.

Incentives play important role

These projects represent several major undertakings under way in the UK North Sea. Many of these, including Chevron’s Rose-bank and Lochnagar discoveries, stand to benefit from tax breaks that were introduced by the UK in 2012. The incentives aim to increase investment in the UK North Sea while also creating jobs in the region.

In September 2012 the UK government revealed that some brownfields would be shielded from part of a supplementary tax charge on companies as encouragement to maximize investments in existing fields and infrastructure on the UKCS. The tax allowance would shield companies from the 32% supplementary charge rate on up to $400 million of income for qualifying brownfield projects or $800 million for projects in fields paying the petroleum revenue tax.

Other incentives also have been introduced, and steps have been taken to give tax relief.

“The introduction of targeted tax allowances over the last four years to promote the development of a range of difficult projects, coupled with the groundbreaking commitment to provide certainty on decommissioning tax relief, has prompted global companies and independent businesses alike to take a fresh look at the UK as an investment destination,” Oil & Gas UK CEO Malcolm Webb said in the organization’s activity survey. “More oil and gas reserves are now deemed commercially viable for development, and this is reflected in the 28 projects that were submitted to the DECC and given development approval in 2012 – almost double those in 2011.” Incentives play an important factor in investment decisions by companies. These can either make or break projects.

In the survey Webb said much of the production decline – 30% over the last two years – was because of “damage done to investor confidence by numerous adverse tax changes in the mid-2000s…. This led to only 14 new fields being brought onstream in 2011 and 2012, typically averaging 15 MMboe in size and therefore replacing less than half of what was produced in those years.” A tax increase in 2011, for example, gave Statoil reason to stop and contemplate further action on the Mariner and Bressay projects. But the moves by the UK government since then appear to have restored fiscal certainty for the region. “I think the fact that the UK government has been willing to engage in negotiations with the operators and license groups to find solutions has been seen as very positive,” Ruud said.

Outlook remains positive

In a written statement to Parliament in June, UK Secretary of State for Energy and Climate Change Edward Davey said the government has an excellent relationship with the oil and gas industry through its PILOT partnership, which has addressed the challenges of the past decade. Today’s challenge calls for an in-depth review, though, which prompted him to call on Ian Wood, retired chair of Wood Group, to lead a review of the UK North Sea with a goal to give recommendations on how to improve recovery of oil and gas.

The review will analyze the licensing regime, infrastructure, production efficiency, exploration efforts, and EOR techniques among other areas. Publication of the findings is anticipated in the fall, with a final report and recommendations expected in early 2014.

“While investment levels are rising and the near-term prospects for the [UKCS] are strong, it is one of the most mature offshore basins in the world and therefore faces unprecedented challenges that require new thinking,” Davey said in the statement. “For example, declining exploration and production rates, aging infrastructure, declining production efficiency, and the risk of premature decommissioning of key infrastructure all need to be addressed if we are to extract the maximum economic benefit for the UK.”

Oil & Gas UK predicts production will rise to about 2 MMboe/d by 2017. Thirty new fields could go onstream within the next two years.

Seismic projects target North Sea

Seismic companies are stepping up efforts in hopes of unlocking potential in the central North Sea. CGG is conducting a prestack depth migration processing project to upgrade its Cornerstone 3-D long-offset dataset using its multilayered tomography technology, TomoML.

TomoML will be used to “build a more accurate TTI anisotropic velocity model, calibrated with over 120 wells throughout the central North Sea and also will benefit from CGG’s latest ghost compensation processing technique to extend the frequency bandwidth and improve the resolution of this conventionally acquired data, providing a contiguous, broadband, depth-migrated dataset,” CGG said in a news release.

“Q30PH7 is being acquired using BroadSeis with BroadSource, CGG’s broadband source, to extend the Cornerstone CNS 3-D dataset by 5,500 sq km [2,124 sq miles] in quadrants 29, 30, and 38,” CGG said. “The objective is to better image the thin and complex formations of the southern margin of the Central Graben, from the Carboniferous-Permian section through the Jurassic and up to the shallower Paleogene targets.” In addition, the company’s Q30PH8 3-D seismic program will target HP/HT reservoirs in the deep part of the Central Graben. “This survey will be tailored to optimize the imaging of both deep and shallow targets,” CGG said.

Additional seismic activity is expected from Dolphin Geophysical, which announced in June that it secured a 3-D seismic survey contract from a client in the North Sea. Plans call for the use of the high-capacity 3-D vessel, M/V Polar Duke, starting in August for about five weeks, according to the press release.

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