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Vol. 16, No. 19 Week of May 08, 2011
Providing coverage of Alaska and northern Canada's oil and gas industry

Fortune Hunt Alaska: ENS pearls about to be strung

Leaseholders prepare to explore, develop eastern North Slope as Badami, Thomson plans solidify

Kay Cashman

Petroleum News

It has been more than 20 years since Division of Oil and Gas officials coined the phrase “string of pearls” for the infrastructure-led exploration of Alaska’s eastern North Slope. It has taken two more decades for the “string” — a metaphor for new pipelines — to come close to making its way from Pump Station 1 of the trans-Alaska oil pipeline at Prudhoe Bay to the Sourdough discovery on the border of ANWR’s 1002 area, some 70 miles east as a goose flies.

The 1002 area is a narrow strip of the coastline of the Arctic National Wildlife Refuge that was set aside for development by Congress because of its hydrocarbon-rich geology. Between it and Endicott are numerous on- and offshore discoveries, several of which are thought to hold upwards of 100 million barrels of oil.

First ‘pearl’ problematic

The first “pearl” on the string, BP’s Badami oil field, came online in 1998, its 22-mile pipeline, or “string,” connecting it to the Endicott field in the Duck Island unit, until then the farthest east development along Alaska’s northern coast.

Although the 35,000-barrel-per-day line was supposed to be nearly filled by 30,000 bpd from Badami at its peak, the line was expandable, and its corridor would allow for a second and larger pipeline if needed.

Within a year of starting production at Badami, BP with several partners was drilling the Red Dog prospect, its next pearl to the east, between Badami and the undeveloped Point Thomson unit, which was operated by ExxonMobil, and of which BP was a sizable owner.

Unfortunately, BP was unable to finish the Red Dog well before the winter drilling season ended.

It was also experiencing serious problems at Badami. While early production had ramped up, as expected, to 18,000 bpd, by early 1999 it had dropped to a mere 3,000 bpd.

One of the challenges in developing the field — a known risk going in and part of the reason the capacity of Badami’s pipeline was reduced from 70,000 to 35,000 bpd — was the question of whether its pockets of oil-bearing sands, or channels, would “communicate” so that oil would move from one to the next and into the vertical wellbores.

Published descriptions of Badami’s Brookian accumulation suggest its reservoirs are complex, consisting of 61 identified fans laid down during seven depositional events, with thin and discontinuous reservoir-quality sands.

Following a series of startups and stops, and a great deal of effort to get the reservoir to perform, BP shut down Badami and its pipeline for the last time in 2007, with production at 900 bpd.

Savant steps in

In 2008, BP entered into an agreement with Savant Alaska, a subsidiary of Denver-based Savant, to bring Badami back into production using horizontal well technology and possibly advanced hydraulic fracturing techniques. Savant and its minority partner ASRC Exploration, agreed to drill two wells in the unit as part of a deal that would eventually give them working interest in key leases and leave BP with an overriding royalty interest. One of the wells was an exploration well in the untested Red Wolf satellite, and the other a new horizontal sidetrack to one of the original vertical producing wells in the unit.

Both wells were drilled and Badami went back online in November 2010. In early April production from five of six wells was at about 1,600 bpd with the last well expected to go online before the end of April.

Savant’s goal is to bring production to 4,000 bpd with those six wells. Its plans include hydraulically fracturing the Killian formation in the vertically drilled Red Wolf well in mid-2011 and improving oil flow in the Brookian by hydraulic fracturing its new horizontal well in 2011 or 2012. (Hydraulic fracturing has been tried before at Badami, but only on vertical wells.)

The powers that be at BP are obviously willing to bet Savant Alaska is going to be successful at keeping the Badami unit in continuous production because last fall BP Transportation (Alaska) filed a tariff revision for the unit’s pipeline with the Regulatory Commission of Alaska that drops the rate from $26.09 to $7.26 per barrel of oil — a rate RCA approved.

Still, $7.26 per barrel is more than the combined cost of shipping oil from Endicott to Pump Station 1 and then down the 800-mile trans-Alaska oil pipeline to Valdez, where it’s loaded on tankers for delivery to the U.S. West Coast. According to Greg Vigil, executive vice president of Savant Alaska, BP’s Badami tariff needs “to be at a level that provides the pipeline owners with enough revenue to cover their expenses, amortize their investment and make a profit.”

That said, the last time BP tried to find farm-in partners for Badami satellites (pre-Savant and minority partner ASRC), it promised to drop the rate to $1 per barrel once throughput reached 18,000 bpd.

Close to settling

Even if Savant is not successful at keeping the Badami unit online, the Badami pipeline would likely be available to transport 10,000 barrels of oil and natural gas condensate starting in 2015-16 from the Point Thomson unit, which has several leases that run along the Staines River, across from the 1002 area.

Too long of a story to tell here, basically the Point Thomson unit was formed in 1977 and is currently bound up in a court fight with the State of Alaska, which is trying to break up the unit and reclaim the acreage.

But even as the legal struggle continues, lawyers for the state and the leaseholders are reportedly drawing close to a settlement — a settlement that will require operator ExxonMobil to finish developing phase one of its 10,000 bpd oil and condensate development, which includes a common carrier 70,000 bpd liquids pipeline to Badami. (A recent Petroleum News story is online at www.petroleumnews.com/pnads/77062310.shtml and a brief history of the unit can be found at www.petroleumnews.com/pnads/12414258.shtml.)

A possible hold up: As of April 10, the U.S. Corps of Engineers was about eight months behind schedule for its record of decision on the environmental impact statement for Point Thomson, which caused the Exxon to change its production start date from 2014 to 2015. Once the decision has been signed — estimated by the agency to occur in March 2012 if there are no other delays — other critical permits should follow within short order.

New unit proposed

In anticipation of all the stars aligning for Point Thomson, one major leaseholder in the area has put together a 200,179-acre unit, Greater Bullen, that includes 68 leases between and south of both Point Thomson and Badami.

A map of the proposed unit, which was filed with Alaska’s Division of Oil and Gas by independent Brooks Range Petroleum Corp. on March 29, can be found online at www.petroleumnews.com/pnfm/GBUExhibitG.pdf.

Greater Bullen working interest owners include Anadarko Petroleum, Arctic Slope Regional Corp., BG Alaska, TG World Energy, Ramshorn Investments and Alaska Venture Capital Group, or AVCG. Brooks Range Petroleum Corp., or BRPC, is the operating arm of the last three companies, a subsidiary of AVCG.

In its unit application BRPC said it has identified “many potential hydrocarbon accumulations and additional prospects” within the unit. The two most notable are Friezen (main prospect in the former 14-lease, 79,508-acre BP Slugger unit) and Red Dog. (Note: BP stopped exploring in Alaska in 2001.)

Depending on the source, Red Dog was estimated to contain 45-85 million (P-50) barrels of recoverable oil. BP estimated Slugger contained some 280 million barrels of oil, but did not quote a number for recoverable reserves.

Initially, BRPC is looking at two 3-D seismic surveys over Greater Bullen, and then, beginning in 2017, drilling a well in each of the unit’s four exploration blocks — north, south, east, west.

Eastern North Slope prospects

A few other eastern North Slope prospects that are likely to be drilled if the Point Thomson development moves forward include the following:

• Kuvlum-Lonestar, actual Kuvlum leases not held. Shell’s 2005 bid for the two Kuvlum discovery leases (with three ARCO wells) just east of Sivulliq was rejected by the feds because the bid was too low. Shell did not bid on Kuvlum leases again, but its undrilled Lonestar prospect is adjacent to Kuvlum leases. Per feds Kuvlum reserves range from 160-300 million barrels of oil.

• Stinson, operated by Donkel Oil & Gas, directly east of Point Thomson, north of ANWR 1002 area in Camden Bay surrounding ARCO Stinson No. 1 discovery well. Per the operator, the Tertiary horizon contains 150 million barrels of oil (probable recoverable reserves) within a single 100-foot thick sand (P90: 80 MMBO; P10: 420 MMBO). Reserves for the basement are currently under assessment.

• Yukon Gold, operated by Savant, and adjacent to ANWR’s 1002 area. Per State of Alaska, recoverable reserves are120 million barrels of oil. Discovery well: 1993 BP’s Yukon Gold No. 1.

Shell is planning to drill up to two Beaufort wells in the open water season of 2012, with or without the Point Thomson pipeline, including its most well known prospect, Sivulliq, formerly named Hammerhead. One of those two wells might be at its nearby Torpedo prospect.



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