Optimizing options

Late life production optimization is hard, but interesting, according to those tackling the issue. Elaine Maslin provides an overview of recent trends.

As natural production rates wane and assets start to age, optimizing production rates offshore becomes a key challenge for operators, not least in the North Sea.

Some 50% of UK North Sea facilities are at or beyond their design life. Barrels of oil are getting harder and more expensive to extract and the basin has seen production efficiency rates fall from an average 81% in 2004 to 60% in 2012, according to figures from the Department of Energy and Climate Change (DECC).

According the production efficiency task force, led by industry/government group Pilot, in 2013, individual operator production efficiency rates ranged from 35% to 90% (the higher rate achieved by Apache North Sea, which is on track to reach 94% in 2014).

According to North Sea independent EnQuest’s North Sea President Neil McCulloch, the industry should be “shocked, depressed and embarrassed” by the low average rate.*

But, the emerging trends on how operators approach optimizing production operations on their assets diverge, Offshore Network’s Offshore Production Optimisation conference heard in Aberdeen in November.

EnQuest, whose production efficiency rate is in the top quartile of the Pilot production efficiency task force rankings, is focusing on investment, empowering asset “owners,” then sharing results.

On the other hand, Nexen Petroleum UK, a CNOOC subsidiary, has focused on organizational change, recently introducing an across-discipline and across-asset approach in its business, following initial efforts focused solely on its Buzzard facility.

Meanwhile, oil major BP is using its computing power to employ a system modeling and optimization approach, which is calls its Modeling-Based Optimization System (MBOS) program.

Offshore Norway, Germany-headquartered operator Wintershall has increased production on Brage through investment, in the asset, but also on seismic and infill drilling. It is now looking to see where is can improve its maintenance program.

EnQuest’s Kittiwake platform in the North Sea.  Photo from EnQuest.

EnQuest

EnQuest has invested and is continuing to invest in its assets, which it took over in 2010, as well as drilling new wells, according to McCulloch. Last year, as a result, EnQuest achieved 83% production efficiency across its North Sea portfolio. In 2014, year to date, it is 90%.

“Despite the age of our asset base (about two thirds of EnQuest’s assets are beyond their design life), we’ve maintained a largely flat operating cost over four and a half years,” McCulloch says. Since taking over the Kittiwake platform in March this year, the firm has more than doubled production and halved operating costs per barrel, he said, with more still to come from the asset.

“We believe that high production efficiency is no accident,” McCulloch says. “Part of it is capital investment. We invest and we see the results. It is also an intense focus on operational delivery and results. It is a relentless focus in operations and projects, on things such as production efficiency and life extension. Every day offshore the out-put production is a result of all the inputs. It is how the operators and their supply chain go about their daily business – hourly, weekly, yearly. We all have to look at that. One of our philosophies is minimizing waste and controlling our costs and also fundamentally maintaining the integrity of our assets, that’s extremely important to us.”

EnQuest has seen 84% production growth on the Thistle platform since it took the facility, and a tranche of others including the Heather platform, in 2010, from a Lundin and Petrofac joint venture.

First, production from Thistle, which is 275mi north east of Aberdeen, in 161.5 water depth, was in 1978, with a planned 25-year operating life. Up to the end of 2013, Thistle had produced 10MMbbl. EnQuest has since added 20MMbbl of reserves to Thistle through drilling and a late life extension project, McCulloch said.

The project, called LLX, saw £170 million spent extending the facilities on Thistle, shooting new seismic, reactivating the drilling rig and investing in the well stock. The firm also invested in making sure electrical submersible pumps got reliable power and brought the platform’s controls systems “into the 21st century.”

When EnQuest acquired Thistle it was producing about 3000bbl. Enquest increased that to about 18,000 and now it is at about 10,000, McCulloch says. “Ninety percent of that production is from wells we have done something with – whether it is an intervention, a workover or a new well or if we have added an ESP,” McCulloch says.

EnQuest is planning to the same on its Heather, from which it has just completed the first couple of workovers in about 10-11 years.

Nexen

Nexen has been using the Choke model, set out by BP in SPE paper 36848, to capture losses data and move forward to improve efficiency. The choke model looks at four main elements – reservoir, wells, plant and export systems, says Dennis Johnston, production engineer, Nexen.

Part of the problem, Johnston says, is that operators do not always understand their efficiency rates. How operators assess what they are doing to reduce losses is not always clear either, with no real system to close loops on losses identified, other than action-based systems, with loss entries often not reviewed diligently and different shifts having different views.

Nexen has been investing in its surveillance and extracting more data, as well as building digital oil fields to help process the data, to better understand its losses. Nexen is also performing more process trials, to determine capacity where it is uncertain what is possible.

But, the firm is also adapting its organization. “Mostly we have the tools and technology to optimize production better. But we are not using it in the best way,” Johnston says. “We have set up a new multi-disciplinary optimization group, which is coming into effect right now, fully focused on measuring losses and how to optimize them across assets. It is a reorganization in Nexen, moving from asset-based support groups to functional support groups.”

Nexen is also developing a step-up culture for staff to “own barrels,” he says. “Quite often people don’t recognize they can influence barrels can be added,” Johnston says. Nexen is also focusing on competences and training. Control room operators have been rotated through a gas lift awareness course, for example. “We also have an opportunity register. Investments that might debottleneck operations and across asset and discipline, such as well intervention,” Johnston says.

BP

BP also has a multidisciplinary production enhancement team, but it has gone a step further, creating a modeling-based system optimization program, which it calls MBOS, to improve optimization.

“In 2013 we set the challenge, are we optimized? We needed to do something differently,” says Gillian Goby, production enhancements team leader, BP.

“The first step was to enhance the tool set we had and the final step was to find new ways of working,” she says. “The application itself is automated, creating a simulation every week, as a minimum, as well as when it is needed. The simulation shows teams what the optimum production could be on the asset, this is then compared to the actual output, and the gap identified and actions drawn up to close the gap. You have to be skilled to build MBOS application, but for the end user it is easy to use.”

“We do now have a tool to measure if we are optimized,” she adds. “We believe we are optimizing production by 1-4%. MBOS is also good for modeling ‘what if’ scenarios and more and more engineers out-with the immediate team are coming to us with these.”

Wintershall

Wintershall, like EnQuest, took over an asset that had already been producing for a number of years. The firm took over operatorship of the northern Norwegian North Sea Brage platform, its first operated producing asset, in 2013.

The firm initially focused on investment, debottlenecking, and technical integrity on Brage, says Alv Bjørn Solheim, technical director and deputy managing director, Wintershall. Work included infill drilling, but because drilling from the Brage facilities was restricted to within 9300m, the firm is assessing a subsea template for new production wells in the north of the field.

Drilling would then be via a rig in the field and the one of the Brage facility, Solheim says. Wintershall shot new seismic over the area this summer and will look to start execution phase in 2016, with marine operations in 2018, and first oil in 2019. But, the new subsea template project will be dependent on project economics, which are marginal, he says.

Control systems on Brage also needed changing and work to “shape-up” the platform needed to be done. Longer term, “We want more collaboration, gluing together the onshore and offshore via video conference and modern technology, Solheim says.

“We are also looking into the maintenance system, all the critical maintenance that we have and the frequency of the maintenance. It was put in place in 1993, or even 1992, when the platform was built, and has not been looked at since then. “Late life is a hard life but it is also exciting.”