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Vol. 15, No. 7 Week of February 14, 2010
Providing coverage of Alaska and northern Canada's oil and gas industry

Big Risk, Bigger Rewards: Two newcomers with two strategies

Pioneer and Eni both sanctioned nearshore projects in the Beaufort Sea, but took different approaches to development

Eric Lidji

For Petroleum News

As resource basins mature, and production drops, companies can make smaller plays economic by using existing infrastructure — which has excess capacity as production peaks and drops — to bring down costs. That dynamic is just starting to occur on the North Slope of Alaska, which has only been producing oil for around three decades.

Over the past two years, two companies have progressed on projects to the point where they had to make a decision: Rent or own? Is it more economic to use as much existing infrastructure as possible at the risk of ceding control to another company? Or is it better to spend extra money building duplicative facilities in order to keep more control?

The projects are similar and neighboring.

In June 2008, Pioneer Natural Resources brought the Oooguruk unit into production, making the Texas-based company the first independent to operate an oil field on the North Slope. Just a few miles to the east in the waters of the Beaufort Sea, Italian super-major Eni Petroleum is currently working to bring the Nikaitchuq unit into production.

The history and fate of the projects are slightly intertwined. Both date back to exploration work conducted by Armstrong Oil and Gas in the early years of the decade. Eni is a minority partner in Oooguruk and presumably watched the sharing process firsthand. The plays sit side-by-side in the nearshore state-owned waters of the Beaufort Sea.

The companies took different approaches, though. Pioneer decided to negotiate a deal with ConocoPhillips to rent space at existing processing facilities and pipelines. Eni is currently building its own process facilities and pipelines at Nikaitchuq. Both approaches have presented unique obstacles, and both projects have seen unique successes.

Oooguruk hit the “sweet spot”

Alaska is a bit of an oddball in the Pioneer portfolio.

The company lists its anchor prospects as oil and gas fields in Texas, Colorado and Kansas. Outside of the United States, Pioneer operates in Tunisia and South Africa.

Pioneer came to Alaska in 2002 with the goal of making the North Slope a faster place to operate. The company acquired a 70 percent stake in an offshore oil discovery, known at the time as the Northwest Kuparuk prospect, from Denver-based Armstrong Oil and Gas.

Pioneer originally conducted traditional operations in Alaska, a development program backed by an exploration campaign. After several bum winters, though, the company limited its focus in 2007 to developing a few plays, of which Oooguruk is the largest.

Oooguruk is the most expensive project in Pioneer’s portfolio. The project cost around $500 million to bring online, of which Pioneer was on the hook for around $350 million.

Not only did this represent a shift in thinking about the economics of developing a prospect, but also about the day-to-day operations needed to bring a field online.

Before Alaska, Pioneer tended to drill a lot of relatively cheap and predictable wells. Between 1998 and 2000, the company participated in 1,168 wells, 92 percent of which were successful, at a cost of some $867.6 million.

The total cost to bring Oooguruk into production exceeded what the company typically spent at the time in a given year to explore and develop all of its prospects around the world.

Oooguruk also required overcoming many logistical hurdles, first among those the location. To tap the offshore reservoir, the company chose to build a six-acre gravel island in shallow water and tie it back to land with a 12-inch underwater pipeline.

The logistics of running an island posed challenges Pioneer didn’t face anywhere else in the world. For instance, to simply keep the island stocked with people and supplies, Pioneer needed three transportation modes: boats in the summer, trucks to cross the ice in winter and helicopters during the ice-filled “shoulder” seasons of spring and fall.

Pioneer saw Oooguruk as being worth the money and effort, though, because of the potential reserves. By October 2007, as construction of Oooguruk neared completion, Pioneer had booked about 900 million barrels of proven oil equivalent reserves companywide and expected the Oooguruk field to contain 70 million barrels of oil.

“For a company like us, it’s right in the sweet spot,” Timothy Dove, the president and chief operating officer of Pioneer, told Petroleum News about Oooguruk in the fall of 2007.

While Pioneer complained about the shifting tax regime in Alaska — during the years it took Pioneer to bring Oooguruk online, the state went through three fiscal systems — it took advantage of a new exploration incentive that earned it $75 million in early 2008, several months before the company produced any oil-based revenue in Alaska.

Looking for facility access

To get all that Oooguruk oil to market, though, Pioneer needed processing facilities to separate the stream of oil, gas and water coming up from the wells, and pipelines to ship the processed crude to the trans-Alaska oil pipeline more than 50 miles to the east.

The cost to build those facilities is partly what kept previous companies from developing Oooguruk. Even at 70 million barrels, the remoteness and expense of a nearshore prospect in northern Alaska made the project uneconomic as a standalone venture.

Those costs could be reduced or eliminated by piggybacking on existing infrastructure, renting capacity from nearby pipelines and processing facilities already in operation.

For Pioneer, the closest facilities sat onshore at the Kuparuk River unit. That meant the independent needed to strike a deal with ConocoPhillips, operator of Kuparuk.

State and industry officials anticipated this problem as early as 1999, with the release of the Charter for the Development of the North Slope. The document came after industry wide mergers and acquisitions at the end of the century shook up field ownership, prompting concern among state officials about issues such as access to existing facilities.

The charter contained a section devoted to facility access. In it, the state claimed the authority to require facility owners to let third parties have access to existing infrastructure.

The producers didn’t comment on the state’s claim, but also said they would not “unreasonably withhold their voting support as facilities owners for allowing nearby satellites to have access to existing unit facilities on reasonable commercial terms.”

In other words, they agreed to be cooperative.

Landmark report

The general agreement still left the problem of nagging details, though, and so in May 2004 the state released a landmark report on facility sharing across the North Slope.

The report inventoried the existing infrastructure, measured the current capacity of each unit, and looked ahead to what capacity might be in the future, as the profile of existing fields changed. It also listed the concerns that could prevent sharing on the North Slope.

At the time of the report, Kuparuk presented some immediate capacity challenges. The 23-year-old field no longer produced oil at full capacity for the processing facilities, leaving some space for Pioneer to rent, but the facilities remained at “capacity limits” for water, total liquids and natural gas — and capacity in the Kuparuk pipeline was “nearly full.”

The liquids capacity problem is not uncommon, and can be solved by “back out,” where a third party compensates a facility owner for oil or gas not produced as a way to free up capacity. Facility owners take less productive wells offline, allowing room for processing oil from a newer field where wells are producing less water, and are compensated for backing those wells out of production.

The 2004 report also noted that several standard agreements already existed at Kuparuk, setting out rough guidelines for how third parties could process oil, gas and water at the Kuparuk facilities, and also get supplies of injection water, electricity and other needs.

These “ballots” formed the basis of an early facilities sharing agreement between Winstar Petroleum, a small independent, and the Kuparuk River unit. While that agreement was finalized, it was never put into use because Winstar never sanctioned production.

The challenges of sharing

Once Pioneer sanctioned Oooguruk it became the first company in Alaska to try to negotiate a facility sharing agreement that would eventually be put to use.

Pioneer and ConocoPhillips reached an “agreement in principle” as early as the fall of 2006, but claimed that the state deliberations over the production tax system forced them to reconsider the terms of the agreement in the fall of 2007. The companies finally announced a deal in March 2008, with first oil at Oooguruk less than six months away.

Under the agreement, oil from Oooguruk would flow through a gathering line to Kuparuk River unit drill site 3H, then on to a Kuparuk River unit processing facility. From there, it would go to Pump Station 1 and the start of the trans-Alaska oil pipeline.

Almost immediately, the challenges of sharing facilities became public.

Pioneer shut down production within weeks of bringing Oooguruk online because of planned maintenance at Kuparuk facilities. In March 2009, Pioneer shut down production again because maintenance cut the company off from the water supply it used for injection.

In both cases, the company called production losses “insignificant.”

Another problem came in the form of tax payments.

With the sharing arrangement, the state began measuring Kuparuk production levels by subtracting Oooguruk production amounts from the combined production from both fields, making the larger field dependent on accurate measurements at the smaller field.

Pioneer also began looking for solutions.

First, the company got state officials to approve a new metering system. For the first time, the Alaska Oil and Gas Conservation Commission approved the use of multiphase flow meters. These meters allow producers to measure oil, gas and water rates coming from a well without having to separate the three-phase stream into its individual parts.

Multiphase flow meters use nuclear detectors and are expensive, but ultimately pay off because they require less space and maintenance than traditional gravity separators.

Second, Pioneer plans this year to look for an independent source of water to supply Oooguruk injection wells to keep from having to be dependent on ConocoPhillips.

Why it was worth the work

The hassle appears to have been worth it for Pioneer.

When it picked up the prospect and decided to develop it, Pioneer estimated the reserve potential at Oooguruk to be between 70 million and 90 million barrels of oil equivalent. That oil sat in two main pools, the Kuparuk pool and the deeper and larger Nuiqsut pool.

Once Pioneer began drilling, though, it increased that estimate. In February 2009, Pioneer announced that the recoverable reserves at Oooguruk could be as much as 40 percent more than expected: between 120 million and 150 million boe. On top of that, the company said it had only booked 10 million barrels of oil from its Alaska operations.

In addition to the increased resource potential, Pioneer announced that Oooguruk was performing better than expected in the short run. The initial wells at Oooguruk produced at 7,000 barrels per day, compared to the 5,000 bpd the company originally estimated.

This production gave Pioneer a revenue stream as oil prices tanked at the end of 2008, and when the company began scaling back its global operations, it spared Oooguruk.

In late 2008 and early 2009, as oil prices fell more than $100 per barrel, Pioneer cut back from 29 rigs to three rigs across its portfolio, and said it wouldn’t resume normal drilling until prices hit $60 per barrel for oil and $6 per thousand cubic feet for natural gas.

Those cuts included postponing plans to drill an appraisal well at the Cosmopolitan unit in the Cook Inlet basin of Southcentral Alaska, but the cuts did not include Oooguruk.

Speaking in Anchorage in January 2009, Jay Still, executive vice president of domestic operations for Pioneer, said Oooguruk made the cut because it came online in June, before markets crashed, because Arctic projects are more difficult to stop and start up again quickly, and because Pioneer at the time favored oil investments to gas projects.

A new approach to development

With Oooguruk development moving ahead as planned, Pioneer announced a new approach to developing the field in June 2009, a year after bringing the field into production.

Pioneer planned to drill horizontal lateral wells in the second and third quarters of 2009 to fracture and stimulate the Nuiqsut formation, the deeper of the two Oooguruk pools.

By November, Pioneer said Oooguruk production was averaging 6,000 bpd, and said it expected production to increase 10 percent between the fourth quarter of 2009 and the fourth quarter of 2010, according to Scott Sheffield, chairman and chief executive officer.

Sheffield said Pioneer wants to expand Oooguruk vertically by developing shallower oil deposits and horizontally by reaching out farther from the island. Pioneer expects to drill extended reach wells that go out about 18,000 feet to a depth of about 8,000 feet.

Eni decides to build instead

Just to the east, Eni Petroleum is taking a different approach to nearshore development.

Eni came to Alaska in August 2005, purchasing North Slope holdings from Armstrong Oil and Gas. Those included both onshore and offshore prospects, and for nearly two years the Italian company pursued both avenues. In 2007, though, Eni shifted from exploration to development, focusing its time and resources on the Nikaitchuq prospect.

Eni already owned a minority share of the offshore field, and picked up the remaining 70 percent from independent Kerr-McGee in April 2007, giving Eni complete ownership.

The differences between Eni and Pioneer, its partner at Oooguruk, are important.

Pioneer is among the largest independents in the country, but still a small company by oil industry standards. Eni, on the other hand, is one of the biggest companies in the world.

In 2008, Eni produced around 1.8 million barrels of oil equivalent every day from projects on six continents, earning the company some $12.6 billion (8.83 billion euro).

Eni operates fields in Norway, giving it some Arctic experience, enough to make the company cautious about how it approached Nikaitchuq. The moves Eni made in 2007 and 2008 suggest the company saw the offshore venture as being an inherently risky one.

Kerr-McGee saw it that way as well. The company asked the state to expand the Nikaitchuq unit to include the neighboring Tuvaaq unit, nearly doubling the size of the prospect, and also asked for royalty modification during periods of lower oil prices.

Kerr-McGee failed to convince the state on both accounts, but Eni succeeded.

The expanded Nikaitchuq protected more of the resource by unitization. Eni estimated that Nikaitchuq contained 180 million barrels of recoverable reserves from two formations, including one with heavier, and therefore more expensive, oil. The royalty modification protected Eni through the long timeline for developing a project in Alaska.

Under the agreement, the royalty rate on oil produced from several leases rises and falls on a sliding scale connected to the delivered price of Alaska North Slope crude oil.

Up to an inflation-adjusted price of $42.54 per barrel, Eni pays 5 percent royalties to the state. As oil prices increase, so does the royalty rate, topping out at 16.667 percent, the original royalty rate attached to most leases in the unit. The scale is based on a Minerals Management Service program for deepwater federal leases in the Gulf of Mexico.

Those two requests suggest Eni felt the resource at Nikaitchuq wasn’t large enough to justify development, and that, even with the expanded unit, the resource wouldn’t be profitable without some financial incentives should the price of oil fall after production began.

This might be because Eni is building its own production facilities at Nikaitchuq, rather than following Pioneer’s lead and renting space at existing facilities. While expensive, those facilities will give Eni more freedom at Nikaitchuq than Pioneer has at Oooguruk.

The move is unprecedented. Once completed, Eni’s facilities will be the first on the North Slope not operated by the major leaseholders BP, ConocoPhillips and Exxon Mobil.

A quick start, then delays

In January 2008, Eni sanctioned a $1.45 billion development plan for Nikaitchuq.

Eni decided to take a dual approach to developing the field, drilling both from an artificial island built in the Beaufort Sea, and from an onshore pad at Oliktok Point.

The plans included a 3.8-mile subsea pipeline connecting the island to a processing facility at Oliktok Point capable of treating as much as 40,000 barrels of fluid per day, and a 14-mile pipeline connecting that facility to the ConocoPhillips-owned Kuparuk network, which would in turn deliver the fluids to the trans-Alaska oil pipeline.

Even though independent processing facilities promised more control, the decision to build rather than rent forced Eni to deal with its own unique set of challenges.

In early 2009, Division of Oil and Gas Director Kevin Banks told Petroleum News that Eni planned to put the brakes on Nikaitchuq, slowing development from the “fast track” to a “normal pace,” which would delay startup of the oil field by six months to a year.

Although Eni made no public statement, rumors around the oil patch suggested that the company got nervous because of low oil prices and the weak economy at that time.

Those claims didn’t entirely hold up, though. The royalty modification protected Eni during stretches of lower oil prices. As for the weak economy, the well-capitalized mega-major did not need to rely on tight credit markets to move ahead on spending plans.

In addition, Eni wasn’t going on a companywide cost cutting spree.

The company ultimately asked for more time to develop Nikaitchuq. The state approved the request, but noted in its ruling that Eni decided to delay development not only because of the weak economy and the drop in oil prices, but also because the company missed the window to barge “processing and operations modules” to the North Slope.

Eni was building those facilities in Louisiana, not Alaska, and according to the state, Hurricane Ike caused a “work stoppage” at the Louisiana fabrication yard where the construction was taking place. Because of the seasonal restrictions, companies have a brief window each summer to sealift material to the North Slope.

“A variety of factors, including but not limited to schedule delays, not meeting sealift deadlines, capital constraints and fabrication delays have caused Eni to change the pace of development for the Nikaitchuq unit from an accelerated pace of development to a more normal pace,” the company said in a plan of development filed in July 2009.

Even with those delays, though, Nikaitchuq is moving at a quick pace for Alaska.

Eni has already built several gravel pads, a subsea pipeline connecting the offshore and onshore facilities and part of an overland pipe to feed Nikaitchuq oil into the Kuparuk pipeline. Eni also drilled its first production well, which now only awaits facilities.

As a result, Eni now expects to start producing oil from Nikaitchuq by the end of 2010.

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