Sunday, April 5, 2015

State estimates $150B to treasury if ANWR ever opened

Alaska Contract Staffing
Tim Bradner
Alaska Journal of Commerce

Alaskans have long believed oil discovered in the coastal plain of the Arctic National Wildlife Refuge could help keep the Trans-Alaska Pipeline System operating and also replenish the state treasury.

It may be a pipe dream because the federal government shows no sign of opening the coastal plain to further exploration and Congressional approval is required for any exploratory drilling or leasing.

Interior Secretary Sally Jewell, who denied the State of Alaska’s proposal for new seismic exploration of the ANWR coastal plain and is awaiting the outcome of a court case challenging that decision, wants to make it wilderness, a permanent lockup.

But what if? What if there were exploration, and discoveries? How much oil could there be? State officials told legislators in February the revenue to the state treasury could total more than $150 billion over 50 years.

ANWR’s coastal plain, in the eastern North Slope, is thought by geologists to have the best potential for major discoveries of any unexplored onshore area of the U.S.

Major oil fields have been discovered in the central North Slope, including the very large Prudhoe Bay and Kuparuk River fields. There is potential for further discoveries in this area but they are expected to be smaller.

The southern North Slope, and the huge 23-million-acre National Petroleum Reserve–Alaska on the western Slope, are generally thought by geologists to be prone to natural gas discoveries although some oil will almost certainly also be found.

The most informed estimate on ANWR’s coastal plain area came from the U.S. Geological Survey in 1998, which made a “mean” estimate of 7.7 billion barrels of recoverable oil that could be discovered. “Mean” is basically mid-way between high and low estimates.

Whether oil is really there isn’t known for sure. The USGS worked with data from 1,180 miles of two-dimensional seismic program conducted between 1983 and 1985, plus what is known about the regional geology.

The only exploration well drilled in ANWR, in a 91,000-acre in-holding of private lands owned by Kakovik Inupiat Corp. and Arctic Slope Regional Corp., was drilled in the early 1980s by BP and Chevron Corp., and the results are still secret.

No matter what the drilling showed, development of even these private lands are blocked unless Congress decides to open the rest of the costal refuge.

Still, state legislators in Juneau want to know what Alaskans may be missing out on.

In mid-February, the House Resources Committee asked the state departments of Natural Resources and Revenue to develop the most plausible oil discovery and production scenarios based on that is known, and to derive state revenue estimates from those.

The two agencies presented their results to the committee on Feb. 12.

Paul Decker, acting director of DNR’s Division of Oil and Gas, described ANWR’s regional geology in the so-called “1002” area, a coastal plain area named for the section of the law in which Congress designated for additional study of petroleum resources in the Alaska National Interest Lands and Conservation Act of 1980, the federal law that created the refuge.

Decker said the best prospects for discovery are in the western third of the coastal plain, which state geologists believe to hold the most oil potential. Of the 7.7 billion barrels of resources estimated to be in the 1002 area, 6.4 billion barrels are expected to be in the western third.

That is about five times the oil potential of the eastern two-thirds of the coastal plain.

“The northwestern one-third of the coastal plain is geologically simpler and more favorable to hosting oil accumulations,” Decker told the committee.

The area is also adjacent to state lands across the Canning River where companies have made discoveries at Point Thomson (gas, liquid condensate, and oil), and Sourdough (oil). Oil has also been discovered offshore the 1002 area, with the Kuvlum well in 1993 and “Hammerhead” (where Shell is exploring) in 1985.

Geologists in the division did further analysis, predicting that most of the accumulations that might be discovered would be in the 32 million-barrel range to 256-million-barrel range, but accumulations of 1 billion barrels were also possible.

Based on that analysis, the Department of Revenue developed possible production and oil royalty and tax estimates. Ken Alper, director of the Tax Division, presented the conclusions, assisted by Dan Stickel, assistant chief economist.

The scenario presented by Alper and Stickel would have permission granted by Congress to explore in 2016 and leases issues between 2017 and 2019. Exploration would begin in 2019, with the first field located in 2022, and with its development beginning that same year.

First production would be in 2026. From that point on, the scenario foresees one new field discovered and brought into production every two years so that there would be 25 fields in total developed by 2074. The assumed size of discoveries vary along the lines of the estimates by the Division of Oil and Gas but most of the new fields would be between 64 million barrels and 512 million barrels of recoverable resources.

All prices and costs in the modeling assumed 2015 constant dollars and an oil price of $110 per barrel along the lines of the Revenue Department’s very long-range price forecast (a $90 per barrel case was also considered, however).

The modeling assumes no gas being developed, although surely there would be gas discovered also.

Given these assumptions in the modeling, a “base case” of 7.1 billion barrels of oil developed and produced until 2075 would bring $150.9 billion to the state treasury, although the number could be higher, or lower, depending on the amount of oil found.

The production profile in the base case was about 560,000 barrels per day, with a high case, with more oil discovered, of 760,000 barrels per day and a low case, with less oil discovered, or 350,000 barrels per day.

The required investment by industry would reach $5.75 billion per year in the development, pre-production phase, with continuing investment all through the operating lives of the fields.

Because of tax credits in the current state production tax the state treasury would not begin to experience income net of the tax credits until 2030 or 2031, but revenues would then increase rapidly to a peak of about $4.9 billion per year in 2045.

Revenues would the taper off gradually, but even by 2075, the end of the period modeled, there would still be $3.3 billion per year net to the state treasury.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/March-Issue-3-2015/State-estimates-150B-to-treasury-if-ANWR-ever-opened

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.

Read more: http://www.petroleumnews.com/pntruncate/282100226.shtml

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.

Read More: http://www.petroleumnews.com/pntruncate/186081005.shtml

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.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/March-Issue-2-2015/Hilcorp-Energy-keeps-up-spending-despite-oil-price-slide/