Forties, Ekofisk, Lula and Ghawar are all fields that have helped to shape the fortunes of nations. While two are found in much warmer climates, the other two—Forties and Ekofisk—lie deep below the frigid waters of the North Sea.

For the U.K, the Forties Field was and remains the nation’s largest oil discovery. It is a field that once onstream in 1975 helped to raise the U.K. into an eventual era of better prosperity after the difficult recession years of the 1970s.

With about 5 Bbbl of original oil in place and a massive 2.73 Bbbl of oil produced so far since its startup, the world-class field was operated by BP until 2003 when Apache Corp. purchased a 97.14% interest in the field for $630 million and took over operatorship. Production had dwindled from its huge peak of 500,000 bbl/d in its heyday of 1979 to about 40,000 bbl/d by 2003, with 2.48 Bbbl of oil produced in total at the time of the sale.

Since its purchase of the field, Apache has worked its magic on the whole Forties asset, undertaking a massive renovation of the five production platforms, while later adding a satellite platform and installing new subsea infrastructure. These and many other improvements large and small have dramatically restored and maintained the field’s previously declining production rates, while extending the life of this grande dame of the U.K. North Sea far beyond probably even the wildest dreams of BP’s managers when it first undertook this pioneering project.

Starting over
When it comes to developing a plan, working with a clean sheet of paper—while preferred—is not always possible. For the Apache team, putting together the redevelopment plan for Forties was more than just putting pencil and slide rule to paper. It required a willingness to embrace the radical shift to a fleet-footed international oil company intensely focused on quickly delivering results for its shareholders.

“We always knew what we wanted to do. We had many options, but in the past the money wasn’t always available to spend in the Forties Field and trying to get jobs sanctioned—like wireline intervention or coiled tubing—was difficult,” said Ross Littlewood, production engineering team lead for Apache North Sea.

However, once Apache became involved, fresh investment started flowing into the venerable project, with that process now having seen the operator invest close to $4.6 billion up to the present day.

‘Can-do attitude’
But it was more than just paying out money. According to Littlewood, Apache brought a new way of thinking to the Forties project. “There was the financial change but also more of a ‘can-do’ kind of attitude and a realization that things could be accomplished more quickly than in the past,” he said.

Immediately after the purchase Apache was in charge of operating the field from day one. “We had access to all the old well files, completion diagrams, technical documentation and more,” Littlewood said. “Quite a lot of the BP Forties people transferred across to Apache; we were all eager to begin the rejuvenation process of the field and begin a new chapter in the already-successful history of Forties.”

By combining the wealth of historical information now at their fingertips and new data—like the 4-D seismic surveys Apache conducted—with modern-day tools, the production engineering team was able to get a clearer picture on the direction to take on several issues, with artificial lift being one.

ESP effciencies
“On the production engineering side, we challenged the old way of thinking with the gas-lift wells,” he said. “We saw that by running simulations and by asking questions like, ‘What would be the production benefit of an electric submersible pump [ESP] on this well instead of gas lift?’ or ‘What would be the benefit if we increased the drawdown in this well?’ that we could start to develop an idea of the price of running more ESPs instead of gas lift and what the production benefit of doing so would be.”

ESPs proved to be a highly efficient—but more challenging—path to increased production.

The many teams at work on the Forties project had their own unique mission objectives. For the production engineering team, coaxing more oil from the aging sandstone reservoirs as quickly and efficiently as possible was top priority.

Forties was, of course, originally developed with four platforms (Alpha, Bravo, Charlie and Delta) each with full separation and export pumping facilities. Each platform was standalone and exported oil directly to the Forties pipeline system (FPS). The fifth platform—Forties Echo—was brought online in 1987 and was set up with ESPs in all wells with production manifolded and sent to Forties Alpha for separation and final export pumping. Direct export from each platform into the FPS was discontinued in the mid-1990s, with processed crude from the platforms sent at reduced pressure and combined at Forties Charlie before being boosted in pressure for export into the FPS.

This changed significantly under Apache’s stewardship. For example, Forties Bravo was converted entirely to ESPs. In 2014, installation of the Forties Alpha Satellite Platform (FASP) was completed, providing 18 new well slots, additional liquids processing and gas compression capacity for the original Alpha facility, and extra power generation for the field. There are currently five gas-lifted wells tied into the FASP and more are being drilled using the Rowan Gorilla VII jackup rig, according to Littlewood.

The Rowan Gorilla VII heavy-duty jackup rig drills over the Forties Echo platform, as part of Apache’s constant focus on an active infill drilling program and well workovers. Field production was averaging about 50,000 bbl/d in 2015 as E&P went to press. (Photo courtesy of Apache Corp.)

Increased production
“When Apache came in, we ran more ESPs in the field as we realized the ESPs were able to give us increased production rates over the traditional gas-lift wells,” Littlewood said.

“While Forties Echo was purely ESPs, the other platforms were mainly gas-lift wells. And then the drilling spread from Echo onto the other platforms in the Forties Field, plus running more ESPs, that’s when we started to increase the production rates from about 40,000 bbl/d up to about 75,000 bbl/d.”

The combined impact of an active program of infill drilling, workovers and facilities upgrades had managed to increase production from 40,000 bbl/d in 2003 to a peak of 81,000 bbl/d by 2008, with an annual average production that year of 61,700 bbl/d. The annual average production in 2014 was 49,000 bbl/d, while year-to-date production in 2015 was about 50,000 bbl/d, Littlewood said.

“One of the great things with the ESPs was that the pumps were able to provide really high production rates,” Littlewood said. “Depending on the well, if you were to run a gas-lift completion with the gas that we had available for artificial lift, then you could have possibly produced 5,000 bbl/d to 6,000 bbl/d. If you were to install an ESP into that well, we’d get 8,000 bbl/d to 9,000 bbl/d of fluid, including water. You can start to see straight away the benefit of running ESPs.”

Sand-control challenge
“We installed a lot more ESPs into newly drilled wells and even worked over some of the gas-lift wells and installed ESPs,” he said. “But one of the problems from doing that is the Forties reservoir produces quite a lot of sand, and generally ESPs don’t like sand. We started to get quite a lot of ESP failures due to sand blockages and erosion.”

The impact of sand production on well productivity can be highly variable. As a result of a sand control review, the focus on selecting the correct sand control method and improving job execution increased, with the company bringing in an in-house expert to manage the work. In addition, advancements in ESP design and deployment were made.

“We improved the specification of the ESPs, for example, using better materials, more bearings, higher spec motors and better electrical cables,” Littlewood said. “It also led to the drilling team installing more sand control in the ESP wells. Then with that we were able to more than double the runlife of our ESP wells.”

In addition to its distinction as the largest oil field in the U.K. Continental Shelf, the Forties is the largest field produced by ESPs in the North Sea, according to Littlewood.

“When Apache took over as field operator we had maybe seven or eight ESPs online. Now, we have more than 60,” he said. “We really have capitalized and realized the benefit of ESPs. From the early days we looked at the old production data and said, ‘Right, if we had an ESP in this well, what would it produce?’ We just brought it forward from there basically.”

Facilities upgrade
As part of the facilities upgrades in the early 2000s, the original power generation from multiple standalone generators distributed around the platforms was replaced by two turbines on Forties Alpha and Charlie.

Electrical power and fuel gas are redistributed among the platforms as necessary via the Apache-installed subsea power and gas lines. This power and gas ring main allowed the company to simplify facilities as well as increase efficiencies.

“To begin with the Forties Field was shutting down every couple of days,” Littlewood said. “You were frequently in some sort of recovery mode. The efficiency of the platforms was low due to lots of older equipment. With the new power and gas ring, we were able to simplify by removing the older equipment. We started to see platform efficiencies increase. That’s been one of the huge success stories of Apache.”

Since 2003 when Apache took over, operational efficiency has been raised from 70% to 93.5%, according to Littlewood. “For what is effectively the oldest field in the U.K. North Sea, it’s one of the most efficient because of the money that’s been invested and because of the equipment and project work that’s been carried out,” he said. “Installing new power generation and then the power ring main have been a key part of that.”

Future plans
In September 2011, Apache purchased the Beryl Field asset from Exxon Mobil for a reported $1.75 billion and set about applying the template for its success at Forties to that field. But their attention remains just as focused on continuing to run Forties as efficiently as possible.

“These days Forties produces about 53,000 bbl/d typically, and that’s dropped from about 75,000 bbl/d to 80,000 bbl/d that we were doing five to six years ago,” Littlewood said. “We do not produce sufficient gas from the oil that we’ve produced to run all our power machinery or the turbines that use the gas as fuel, which means we have to supplement this by burning some diesel. Diesel is expensive. It is difficult to get a supply vessel sailing out to the platform to refuel—there is a big cost associated with that.”

The discovery of the Aviat shallow gas field in 2010 provided the Apache team with an opportunity to cut those diesel costs. “The Aviat gas field will be tied back to the Forties Alpha platform. It will provide fuel gas to the platforms to make sure we can burn our own gas as fuel and not have to rely on diesel or imported gas, which you then have to pay a premium,” Littlewood said.

Aviat is yet another example of how Apache continues to innovate on one of the North Sea’s oldest producing fields, following on from other satellites it has tied in to Forties since the acquisition and which are still producing such as Maule and Tonto (3.7 MMbbl of oil produced so far) and Bacchus (10 MMbbl of oil produced so far).

Forties, a field of undeniably venerable age, looks set to keep producing for many years to come.

Comments