Saturday, March 7, 2015

Beechey’s fate unclear; State termination proceedings began last year; BRPC wants to consolidate prospects

Eric Lidji
For Petroleum News

The state is considering the fate of the Beechey Point unit.

The Alaska Department of Natural Resources started termination proceedings for the North Slope unit last September, although it agreed to reconsider after operator Brooks Range Petroleum Corp. made a case for maintaining the unit in the Gwydyr Bay region.

Then-Commissioner of Natural Resources Joe Balash initiated the termination proceedings in September 2014, saying the Alaska-based company had failed to meet certain work commitments in its initial five-year plan of development and failed to meet any of the conditions for justifying an extension. In addition to obvious conditions like sustained oil or gas production or ongoing exploration activities, those conditions include having a well certified as capable of producing hydrocarbons in commercial quantities.

With no such certified well at the unit, Balash believed termination was justified.

The company disagreed. In a late September 2014 letter, Vice President for Exploration Larry Vendl named two certified wells within the unit boundaries. He asked for a chance to negotiate a plan of development that would allow the company to continue exploration and development activities. The company could start as early as 2015, Vendl wrote.

Wells on leases

The leases included in the Beechey Point unit undeniably include two wells certified as capable of producing hydrocarbons in commercial quantities: Gwydyr Bay South No. 1 from 1974 and North Shore No. 1 from 2008. Both wells, though, were drilled before the state approved the Beechey Point unit in mid-2009. To the state, that made them irrelevant for extending the terms of the unit. To the company, it made no difference.

Of particular interest is North Shore No. 1, which was the first well Brooks Range Petroleum drilled in Alaska. The state certified the well in July 2008, approved the Beechey Point unit in August 2009 and asked the company to apply for a recertification by August 2010. To Brooks Range Petroleum, this “redetermination requirement” represented a changing standard. No other operator had been asked to perform a similar task, according to the company, which asked the state, in July 2010, to reconsider.

The state never responded, according to the company. The debate may be more than merely an administrative debate, though. In his September 2014 letter, Balash wrote, “It is my understanding that the well is physically incapable of producing hydrocarbons.”

New plan wanted

Brooks Range Petroleum now wants to negotiate a new plan of development, citing its commitment to the project thus far. The company said it had spent more than $85.5 million exploring the region to date and had begun permitting for a proposed North Shore Development Project. The company also applied to form an initial participating area. The state had yet to rule on the application when the termination proceedings began.

What the company failed to do was drill all the exploration wells required by the unit agreement. The agreement required Brooks Range Petroleum to drill at least one well in two different exploration blocks by December 2010 and December 2012, respectively.

The company only met the first work commitment. The state subsequently extended the deadline for the second commitment until 2014, which the company also missed.

In October 2014, Balash agreed to reconsider the termination. His decision came shortly before the election of Gov. Bill Walker, which prompted a turnover of many cabinet-level positions, including the Department of Natural Resources. The new commissioner, Mike Myers, inherited the matter and had yet to issue a decision by early March.

A decade of work

Although recently sold to a multiparty joint venture, Brooks Range Petroleum Corp. started its life as the operating arm of the Alaska Venture Capital Group, which came to Alaska in 1999 to pursue sizeable oil fields passed over by the major oil companies.

The Gwydyr Bay region north of Prudhoe Bay fit the bill.

The company acquired leases through a 2001 land swap with Phillips Petroleum and arranged an exploration program. The program collapsed under the weight of various logistical problems. Still intrigued, the company acquired the acreage again in 2005.

Brooks Range Petroleum commissioned a two-well exploration program in early 2007.

North Shore targeted Ivishak

The 10,319-foot North Shore No. 1 well targeted an oil accumulation in the Ivishak formation first tested by Mobil Oil with the Gwydyr Bay South No. 1 well in 1974. The well encountered “approximately 70 feet of oil-charged Ivishak sandstone formation.”

The 11,348-foot Sak River No. 1 followed up on a prospect previously included in the BP-operated Sak River unit. The well proved to be a dry hole, although the results were intriguing enough for the joint venture to consider returning to drill a sidetrack.

That winter, the company also commissioned a 130-square-mile 3-D seismic survey, which “identified two small satellite prospects to North Shore No. 1 that can be reached from the North Shore No. 1 drilling pad,” according to a former partner on the project.

Combining small prospects

The results of that initial season started the company along its current path - finding a way to string together several marginally economic prospects into a single, profitable development. An early partner described the strategy as “establishing a threshold” for development. Potential solutions included two production pads or extended reach drilling.

Brooks Range Petroleum re-entered North Shore No. 1 in early 2008 to test the Ivishak and the shallower Sag River formations. The Ivishak flowed at 2,092 barrels of oil per day. A mechanical problem down hole compromised the Sag River test, although the partner estimated that an unencumbered test could have flowed at 1,000 barrels per day.

That summer, the joint venture acquired the nearby Pete’s Wicked prospect from Pioneer Natural Resources Inc. BP discovered the prospect in 1997 and Pioneer acquired it in a 2003 lease sale. The acquisition provided an additional opportunity for bundling several prospects together.

A legal dispute among partners prevented drilling in early 2009. The following winter, Brooks Range Petroleum drilled the Sak River No. 1A sidetrack and the North Shore No. 3 delineation well. The company suspended both wells at the end of the drilling season.

Sak River 1A wet

“Sak River No. 1A was truly an exploration project with a pre-drill risk factor of 1 in 5, unfortunately the well encountered mainly water from the Kuparuk formation,” Brooks Range Petroleum Chief Operating Officer Bart Armfield wrote in a completion report for the season, which was published after a mandatory two-year delay. Although the company had plugged and abandoned the original Sak River No. 1 well, it suspended the sidetrack, which would allow it to be used for providing pressure maintenance for future wells in the Sag River formation. The company said it was considering plans for a second sidetrack, which would aim for an “up-dip target of the Kuparuk,” Armfield wrote.

North Shore No. 3 “identified a common oil/water contact between the Sag and Ivishak formations and presents a reduced reserve base for the North Shore development,” Armfield wrote, adding that the company had now discovered reserves at North Shore No. 1, North Shore No. 3 and Pete’s Wicked, which would guide future activities.

With its attentions increasingly devoted to the Mustang development, just west of the Kuparuk River unit, Brooks Range Petroleum has yet to return to the Beechey Point unit.

The original unit covered some 52,876 acres north of Prudhoe Bay. The unit contained five exploration blocks. In September 2012, the company relinquished some 42,119 acres on the western side of the unit, leaving a seven-lease unit covering some 10,757 acres.

‘Close proximity’

The challenge at Beechey Point remains the same, according to Vendl.

“The potential for successful exploration and development in this area requires the compilation of several prospects with known reservoir reserves in close proximity to one another,” Vendl wrote in his letter. “The smaller prospects need to be a part of a larger program; each independent prospect does not support an economic development model.”

The current strategy involves combining the prospects of various operators in the region, including the East Shore prospect at Beechey Point, the ConocoPhillips-operated Kup Delta lease and the UltraStar Exploration-operated Dewline unit, all of which are located on adjacent leases (see map). At the time of the letter, in September 2014, Brooks Range Petroleum was involved in discussions with both ConocoPhillips and UltraStar, according to Vendl.

Another option, Vendl noted, would be to expand the 3-D seismic survey BP Exploration (Alaska) Inc. is commissioning for the northern end of Prudhoe Bay, including Beechey Point. “We continue to pursue the availability of the contractor to include the (Beechey Point unit) leases so that we can determine the full potential of the Kup Delta and (Beechey Point unit) eastern area, including the Dewline unit,” Vendl wrote in his letter.

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Mustang under way; Alaska company drilled initial injection well in January, planning two more

Alaska Contract Staffing
Eric Lidji
For Petroleum News

The Mustang development is under way. Brooks Range Petroleum Corp. began drilling its first development well at the North Slope field in early January using Nabors rig 16E. The approximately 9,300-foot SMU-M02 well is a directional injection well to support Southern Miluveach unit production.

The well is the first in a three-well development program planned for this winter. The next two, SMU-M03 and SMU-M04, will be horizontal production wells. The Alaska Oil and Gas Conservation Commission issued a drilling permit for SMU-M03 on Feb. 13.

The Mustang field is the initial development project at Southern Miluveach, which sits along the southwestern border of the Kuparuk River unit, north of the Tarn satellite.

The program is aimed at bringing the field into production by April 2016. In a plan of development submitted to the Alaska Division of Oil and Gas in the latter half of 2014, Brooks Range Petroleum described plans to drill as many as 13 wells during 2015.

The Mustang project includes a gravel pad, a gravel access road connecting to the existing road grid at the Kuparuk River unit and a standalone production facility. The road and pad were completed last year. Construction of the facilities is running concurrently with the initial drilling operations. The Alaska Industrial Development an Export Authority is helping to finance both the early infrastructure and the facilities.

The all-season road means Brooks Range Petroleum can continue work beyond winter.

The company expects the approximately 40 million barrel oil field to initially produce between 8,000 and 10,000 barrels per day, which would leave considerable room at the 15,000-barrel-per-day processing facility to accommodate future developments nearby.

Last year, a joint venture comprising Thyssen Petroleum USA, the JK Group and Magnum Energy Partners acquired ownership of Brooks Range Petroleum from Alaska Venture Capital Group LLC and Ramshorn Investments Inc. The joint venture also acquired with a 90 percent interest in the Alaska holdings of the two former owners.

Fairway under way

The Mustang development will be the first in the region between the Kuparuk River unit and the Colville River unit, which is colloquially known as “the billion-dollar fairway.”

The optimistic name reflects the advantages of operating in a region with considerable transportation and processing infrastructure, which is a rarity on the North Slope.

A standalone processing center in the region could improve the economics of other projects in the fairway. Brooks Range Petroleum operates the nearby Putu and Tofkat units and, until its recent termination, the Kachemach unit. ASRC Exploration LLC operates the Placer unit. Repsol E&P USA Inc. is exploring on leases to the north. Royale Energy Inc. intends to drill exploration wells on leases to the south as early as 2016.

Quick turnaround

After more than a decade of exploration activities, including three prolific drilling seasons, Brooks Range Petroleum farmed-in the North Tarn prospect in early 2010.

Over the 2011 and 2012 exploration seasons, the company drilled the North Tarn No. 1 exploration well, the North Tarn No. 1-A sidetrack and the Mustang No. 1 delineation well. The wells tested the Brookian formation and deeper Kuparuk formation.

The company initially expected to find some 6 million barrels of oil in the Kuparuk formation. Instead, the wells proved an estimated 44 million barrel resource, according to an independent audit by the global consulting firm DeGolyer and MacNaughton.

The larger discovery prompted the company to seek alternative ways to finance a development program, including AIDEA and the recently formed joint venture. The region is also thought to hold considerably reserves in the Brookian formation, although the more complication geology will likely delay development for some time.

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Hilcorp Energy keeps up spending despite oil price slide

Thoughtful Thursdays
Tim Bradner
Alaska Natural Resource Month

Hilcorp Energy continues to grow its Alaska business despite the slump in oil prices. The company has increased its Alaska production and plans additional investments of $300 million to $350 million this year in spite of the skid in prices, Hilcorp President and CEO Greg Lalicker told state legislators Feb. 24 in Juneau.

The company’s Cook Inlet production has reached about 40,000 barrels of oil equivalent per day, or boe/day, a measurement includes crude oil and natural gas values expressed, in energy content, as barrels of oil.

Meanwhile, Hilcorp’s acquisition of interests in three North Slope producing fields last November has added another 20,000 boe/day, Lalicker said.

Alaska now contributes 60,000 boe/day to the company, or about 40 percent of Hilcorp’s total production, he said.

Hilcorp is the nation’s largest privately-owned independent producer and specializes in buying mature producing properties and rejuvenating them to add production.

The company also has to deal with some of the problems that come with acquiring older production properties, however. On Saturday, Feb. 28, a breach occurred in a 10-inch production line in the Milne Point field, one of the older North Slope fields where Hilcorp is now operator, resulting in a spill of undetermined size.

Four adjacent production pads were shut in while response crews struggled through blizzard conditions. A plug was inserted in the pipe and spill cleanup operations were underway March 1 as the weather improved.

Meanwhile, a bypass line was installed to reestablish the flow of oil through the pipe, eliminating the danger of a freeze-up and adding additional protection against a further spill. Production was restored to normal levels the same day.

So far, Cook Inlet has been a success for Hilcorp. Before the company purchased the aging Inlet producing properties from Chevron Corp. and Marathon Oil in 2012 and 2013, production averaged about 18,000 boe/day.

By January 2014, after two years of new investment and intense activity, production had reached 32,000 boe/day. By July it had passed 40,000 boe/day, according the materials Lalicker presented to state legislators.

“Our business strategy is straightforward. We buy old producing assets, we figure out how to operate them most efficiently and we find ways to increase production. We don’t just cut costs. We find ways to produce more,” Lalicker said.

Hilcorp is now applying a similar strategy on the North Slope. In November it took ownership of the Northstar, Endicott and Milne Point producing fields after purchasing them from BP last November. Liberty, a non-producing offshore discovery, was included in the purchase.

Hilcorp now owns 100 percent of Northstar and Endicott and 50 percent of Milne Point, but Hilcorp is operator in all three fields.

The company’s immediate focus is on Milne Point, Lalicker said, because there are a larger number of wells there than at the Northstar and Endicott fields.

Hilcorp’s strategy of doing aggressive workovers on older wells should have immediate benefits in production at Milne Point, he said.

Hilcorp has already put one workover rig to work at Milne Point and is now constructing a new workover rig for the field that will be shipped to the North Slope in late summer, he said.

The company is taking a cautious approach, however, in developing Liberty, a nonproducing offshore deposit also purchased from BP in November. Hilcorp owns 50 percent of Liberty with BP owning the other half, with Hilcorp as operator.

Hilcorp presented a possible development plan to the U.S. Bureau of Ocean Energy Management but the company is still studying the project, Lalicker said.

“We haven’t sanctioned development. It’s still up in the air,” he said. “We need to do a lot more on the development plan before we start pouring money into Liberty.”

Liberty is about five miles offshore in federally-owned submerged lands beyond the state’s territorial limit, with the U.S. BOEM as the managing agency.

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Saturday, February 28, 2015

DOI wants operation plan, relief well rig for exploration drilling

Alaska Contract Staffing
Alan Bailey
Petroleum News

The Bureau of Safety and Environmental Enforcement and the Bureau of Ocean Energy Management, the two agencies within the Department of the Interior responsible for oversight of U.S. outer continental shelf oil activities, have released proposed new regulations for exploration drilling in federal waters of the Beaufort and Chukchi seas.

The agencies have been developing the regulations in the aftermath of the Deepwater Horizon disaster in the Gulf of Mexico - the draft regulations had been under review by the White House Office of Management and Budget since August and were released on Feb. 20. The regulations are subject to a 60-day comment period that will begin following publication in the Federal Register.

“The Arctic has substantial oil and gas potential, and the U.S. has a longstanding interest in the orderly development of these resources, which includes establishing high standards for the protection of this critical ecosystem, the surrounding communities, and the subsistence needs and cultural traditions of Alaska Natives,” said Secretary of the Interior Sally Jewell. “These proposed regulations issued today extend the administration’s thoughtful approach to balanced oil and gas exploration in the Arctic, and are designed to ensure that offshore exploratory activities will continue to be subject to the highest safety standards.”

Performance-based and prescriptive

Interior says the new regulations contain a combination of performance-based and prescriptive standards that cover all phases of offshore exploration in the Arctic.

The proposed rule includes requirements that an offshore operator file an integrated operations plan for proposed drilling operations; that the operator of a drilling project has available a capping stack and containment dome for dealing with an out-of-control well; and that the operator has available a second rig for the drilling of a relief well, should a well loss-of-control incident arise.

“This proposed rule is designed to ensure safe energy exploration in unforgiving Arctic conditions,” said BSEE Director Brian Salerno. “It builds upon our existing Arctic-specific standards and experience with previous operations offshore Alaska, encourages further development of technology, and includes rigorous safeguards to protect the fragile environment.”

“As we make the vast majority of the Arctic oceans offshore Alaska available for oil and gas leasing, we have an obligation to provide the American people with confidence that these shared resources can be developed responsibly,” said BOEM Director Abigail Ross Hopper.

The regulations specifically relate to exploration drilling, rather than the drilling required for oilfield development or maintenance.

During a Feb. 20 news conference Salerno said that a final version of the regulations will not be completed before this summer’s Arctic offshore drilling season and will not, therefore, apply to Shell’s planned exploratory drilling in the Chukchi Sea this year. But, Salerno commented, provisions within the regulations draw heavily on requirements that were set during Shell’s 2012 Arctic drilling operations, on lessons learned from those operations and on discussions held with Shell regarding its 2015 plans. Thus, if Shell does drill in 2015, the company will need to comply with some new requirements that correspond to features of the new regulations, Salerno said.

Integrated operations plan

The purpose of the integrated operations plan, which, according to the proposed regulations, an Arctic offshore operator would have to file with Interior at least 90 days prior to filing an exploration plan, is to provide government agencies with early information about what an operator intends to do and to stimulate early discussions about the operator’s intentions. “The whole purpose behind the operational plan is to provide early indications of how an operator proposes to approach a drilling season,” Salerno said.

The integrated operations plan would include information such as proposed vessel and equipment specifications; the schedule of operations; the drilling program objectives and timeline; contractor management arrangements; and plans for the preparation and deployment of spill response assets. The plan would not require formal agency approval, as is needed for an exploration plan.

Salerno said that the proposed regulations require that a company conducting drilling operations in the Arctic outer continental shelf has available in the Arctic the appropriate systems needed for the capping of a well following a loss-of-control incident, and for the containment of spilled oil, should the capping system fail. A capping stack, for sealing the wellhead, must be available for transfer to the well site within 24 hours of an incident, while cap-and-flow and containment systems, for gathering spilled oil and transferring the oil into surface vessels, must be available within seven days.

Salerno said that, given the remote nature of the Arctic, it would not be acceptable for an operator to contract the use of capping and containment systems that are stationed in the Gulf of Mexico.

Relief well capability

One particular feature of the proposed regulations is the mandating of a second drilling rig for the drilling of a relief well following a loss-of-control incident - a relief well is a secondary well drilled after a well blowout, to enable cement to be injected into the problem well bore, to permanently seal the well. The need for the rig and the need for a time window before the onset of the winter to drill a relief well add significant cost to an Arctic drilling operation. In a presentation to the Office of Management and Budget Shell argued there has been no recorded instance of a relief well bringing a well blowout under control, and that new well capping technology, coupled with improved well integrity management, can effectively reduce the probability of a loss of well control.

“We understand that the same-season relief rig is somewhat controversial,” Salerno said. “From our perspective that sets a level of protection for the Arctic that is necessary.”

Interior is also insisting that an operator has available sufficient mechanical oil recovery equipment to recover all oil spilled in a worst case spill scenario, even although there are alternative techniques, such as in-situ burning and dispersant use, that could be employed if appropriate.

And during drilling operations, it will be necessary to test the well blowout preventer every seven days rather than every 14 days, as is mandated elsewhere.

The discharge of drilling waste into the ocean has in the past proved controversial, especially in the context of Arctic offshore drilling. The proposed regulations would prohibit the discharge of any petroleum-based drilling mud and associated cuttings and would also give Interior’s regional supervisor the discretion to ban the discharge of water based mud.

And during drilling operations an operator must transmit drilling data to an onshore location, and make the data available to BSEE on request.

Varied responses

Shell, in its response to the proposed regulations, said that it supports regulations that further its concern about safety and environmental protection.

“We support regulations that further these imperatives in the Arctic, provided they are clear, consistent and well-reasoned,” said Shell spokeswoman Megan Baldino in a Feb. 23 email. “While we review the draft Arctic regulations put forward by the Department of Interior, we will continue to work with federal agencies, the State of Alaska, local communities, and contractors to develop a 2015 drilling program that achieves the highest technical, operational, safety and environmental standards.”

U.S. Sen. Lisa Murkowski, R-Alaska, chair of the Senate Committee on Energy and Natural Resources, said on Feb. 20 that she was still reviewing the proposed regulations and that she wants to evaluate what impact the regulations may have on the economic development of Alaska’s vast resources.

“Given the opposition this administration has shown so far to responsible resource development, I’m reserving judgment until it’s demonstrated that these regulations will not unnecessarily block investment,” Murkowski said. “If this administration is truly committed to developing our Arctic resources then it is imperative that the Interior Department provide clear direction to Shell and the other leaseholders in the region on how they can proceed.”

Environmental organizations praised the tightening of drilling regulations for the Arctic offshore while also expressing concern about the risks associated with drilling for oil in Arctic conditions.

“We applaud the government for recognizing that existing oil and gas regulations are not adequate,” said Susan Murray, Oceana’s deputy vice president, Pacific. “The new rules clearly are needed and are an improvement, but they do not ensure safe and responsible operations in the Arctic Ocean. There is no proven way to respond to a spill in icy Arctic waters and, as Shell unfortunately demonstrated, companies simply are not ready for the Arctic Ocean.”

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