BP Exploration (Alaska) Inc. shrunk in 2014. The local subsidiary of British giant BP plc started the year as the most active operator on the North Slope, overseeing development at four state units - Prudhoe Bay, Milne Point, Duck Island and Northstar - and the federal Liberty unit, which remains undeveloped.
That changed in April 2014, when BP announced a sale to Hilcorp Alaska LLC. If the deal closes as expected by the end of the year, BP would operate Prudhoe Bay and Liberty and would maintain a 50 percent interest in Liberty and Milne Point, in addition to its pre-existing minority interest in major fields such as the Kuparuk River unit.
“BP will be able to focus on maximizing production from Prudhoe Bay and advancing the Alaska LNG opportunity,” BP Alaska President Janet Weiss said at the time.
The near term work at Prudhoe Bay includes a seismic survey in the north to identify potential opportunities and a coordinated program in the West End, among other projects.
The sale meant a 17 percent reduction in BP’s workforce in Alaska. Of the 475 affected employees, about 200 went to work for Hilcorp and the remainder will be let go in 2015.
A long relationship
The deal was the biggest shake-up of North Slope ownership since the consolidation of properties in the wake of industry mergers and acquisitions at the turn of the last century.
But the deal also re-affirmed a relationship between BP and Prudhoe Bay that has been remarkably stable over the past half century and could remain so for decades to come.
BP opened its Alaska office in 1959 - the year Alaska gained statehood.
A decade later, with its confirmation well for the Prudhoe Bay discovery, BP helped launch the North Slope oil industry. The delineation campaign mapped an oil field stretching 45 miles east to west and 18 miles north to south. Geologists initially identified four primary reservoirs - the Kuparuk River formation, the Prudhoe Bay group, the Lisburne limestone and the Kekiktuk Conglomerate - and later pinpointed heavier oil reserves contained in shallower reservoirs such as West Sak, Schrader Bluff and Ugnu.
The initial development program split the field in half. BP took the Western Operating Area, or WOA; ARCO Alaska took the Eastern Operating Area, or EOA. The split gave each company a manageable workload and divided operations between the oil reservoir and an offset gas cap. But eventually the owners decided to unitize the field to optimize recovery, divide costs more equitably and avoid building unnecessary infrastructure.
Negotiations wrapped up as construction finished on the trans-Alaska oil pipeline, the 800-mile pipeline that carries North Slope crude oil to Valdez for tanker shipments.
Production begins in 1977
The pipeline connected the Prudhoe Bay field to market on June 20, 1977.
Prudhoe Bay production topped 1 million barrels per day in March 1978 and peaked at 1,627,036 bpd in January 1987 before dropping below 1 million bpd in March 1994, according to the Alaska Oil and Gas Conservation Commission. Of the 24 billion barrels of oil in place, its operators had produced some 12.5 billion barrels through July 2014, according to the AOGCC. Original estimates had pegged total recovery at 9.6 billion barrels.
The decades since peak production at Prudhoe Bay have seen reactive and proactive initiatives. In responses to changing production profiles at the field, the working interest owners expanded flowlines between wells and gathering centers, increased gas and produced water capacity at the field and tinkered with gas handling to improve productivity. They also implemented technologies to enhance recovery. Those included waterflooding and miscible injection, and, more recently, multilateral wells, coiled tubing drilling, extended reach drilling and multistage hydraulic fracturing, as well as proprietary technologies such as the Bright Water polymer used to sweep oil from reservoirs and the LoSal technique that uses lower salinity water to improve oil recovery.
BP merged with Amoco in December 1998, and BP-Amoco acquired ARCO the following year. The deals triggered a major rearrangement of North Slope holdings to alleviate the concerns the U.S. Federal Trade Commission. By the time the dust had cleared, BP was the sole operator of the Prudhoe Bay unit, a position it retains today.
IPA activities
Today, the Prudhoe Bay unit is a declining oil field that continues to be the largest single source of the oil production, and therefore the largest source of state revenue, in Alaska.
The Prudhoe Bay unit includes the initial participating areas and a series of satellites.
The initial participating areas produced 218,000 barrels of oil per day and 7.145 billion cubic feet of natural gas per day in 2013, according to a recent plan of development.
The Prudhoe Bay initial participating areas also produced some 45,000 barrels of natural gas liquids per day in 2013, of which 31,900 barrels per day went to the trans-Alaska oil pipeline and 13,000 barrels per day went to the Kuparuk River unit, according to BP.
Oil production was down 3.1 percent from 2012. BP expects oil production between 168,000 and 209,000 bpd in 2014 with 36,000 to 44,000 bpd of natural gas liquids.
While liquids produced from Prudhoe Bay are shipped to market through the trans-Alaska oil pipeline - 79.3 million barrels worth in 2013, according to BP - gas lives a more complicated life cycle. Of the 2.6 trillion cubic feet of gas Prudhoe Bay produced last year, BP injected 89.7 percent back into the field, used 5.8 percent for operations and used 3 percent for miscible injectant to enhance oil recover. The remaining 1.5 percent includes flared gas and the limited exports and sales to other units and operators.
BP drilled 57 wells and performed some 1,900 workovers in the initial participating areas in 2013 - up from 45 wells drilled and some 1,700 workovers performed in 2012.
In its most recent plan of development for the initial partial participating area, submitted to regulators in April 2014, BP estimated that its drilling activities for this year would be “similar” to last year - with 50 to 60 penetrations split between rotary and coil rigs. The company also forecast “increased” workover activities for the current year, with the work focused primarily on returning shut-in producing and injecting wells to regular service.
In February 2014, Weiss announced a $1.25 billion capital program for Alaska this year. The budget amounted to a 25 percent increase in total spending and a 40 percent in spending aimed at increasing production, including drilling, workovers and “major projects.” Seen another way, BP has committed to spend 90 percent of its profits in Alaska over the next five years, up 60 percent from spending levels in previous years.
“We’re drilling more wells and doing significantly more well work jobs in 2013 than 2012, and plan significantly more in 2014 than 2013,” she said at the time, in a speech to the Anchorage Chamber of Commerce. “We are focusing on light oil development to ensure we have a healthy business to build the more material opportunities upon.”
The near-term capital program also includes funds to bring two rigs to the unit, one by 2015 and one by 2016, which would add between 30 and 40 wells each year, Weiss said.
The Aurora field
The Prudhoe Bay field is part of a larger area called the Greater Prudhoe Bay Area that also includes five satellites: Aurora, Borealis, Midnight Sun, Orion and Polaris.
Mobil Oil Corp. discovered the Aurora oil pool in the northwest quadrant of the Prudhoe Bay field in 1969 and BP brought the field online in November 2000 from the S pad.
As of the end of 2013, BP was developing the Aurora field using 33 wells - 17 producers, 10 water injectors and six water-alternating-gas, or WAG, injectors, according to the 2013 BP annual report. BP drilled the S-110B service well and the S-135 development well at the Aurora field in early 2014, according to AOGCC records.
Of the 200 million barrels of oil in place at Aurora, BP had produced some 37.8 million by July 2014, according to the AOGCC. The field produced an average of 5,913 bpd oil in fiscal year 2013, down from a peak of 14,000 bpd in August 2006.
The primary development work at Aurora involves a tertiary recovery program launched in 2003, where BP alternates cycles of miscible gas injection and water injection.
BP conducted a sizable development program at Aurora in 2011 and much of its recent workload for the field aims to follow up on those activities. The work includes developing an oil accumulation in the southwest corner of the field, adding a production and injection well in the eastern edge of the field and sidetracking several injection wells.
The Borealis field
Mobil Oil discovered the Borealis oil pool along the western edge of the Prudhoe Bay field in 1969. BP brought the field online in 2001 from the Prudhoe Bay L pad, and expanded development to include the V pad in April 2002 and the Z pad in March 2004.
Through July 2013, BP had drilled 56 wells at Borealis - 25 from L pad, 22 from V pad and nine from Z pad, according to a plan of development for the field. AOGCC records indicate no additional wells in 2014 through September. Of the 350 million barrels of oil in place at Borealis, BP had produced nearly 74.7 million barrels through July 2014, according to the AOGCC. Borealis peaked at 38,150 bpd in May 2003, according to the AOGCC, and produced 10,253 bpd in the year ending July 2013, according to BP.
BP launched a tertiary recovery program at Borealis in June 2004. As with the work at Aurora, the program alternates cycles of miscible gas injection and water injection.
Since completing an expansion of Z pad in 2011, BP has drilled two producers and two injectors from the field and intends to another producer and injector by early next year.
The Orion field
Mobil Oil discovered the Orion oil pool in the northwest corner of the Prudhoe Bay unit in 1968. BP confirmed the accumulation in 1998 and brought the field online in 2002.
BP originally developed Orion from its V pad and expanded development in mid-2004 to include L pad. Through June 2013, BP had drilled 48 wells at Orion - 25 from V pad and 23-from L pad, although the company also uses facilities at W-Pad and Z pad to develop the field, according to the most recent plan of development for Orion. The company had not drilled at Orion in 2014 through September, according to the AOGCC.
Of the 3.2 billion barrels of oil in place at Orion, BP had produced 30.4 million through July 2014 at a 2013 rate of 6,396 bpd. The field peaked at 14,460 bpd in June 2007.
Orion produces from the same viscous Schrader Bluff formation present at the Milne Point unit to the north and the ConocoPhillips-operated Kuparuk River unit to the west, and the field is part of larger joint efforts to expand the production of heavier oil.
What about I pad?
The futures of Borealis and Orion have long included an I pad.
BP originally expected to bring the pad online by 2006, but later deferred those plans until the 2010 timeframe and subsequently deferred them again until as late as 2020.
BP has cited technical challenges through the years, but the delays were largely the result of the frequently changing fiscal systems in Alaska over the past decade - BP deferred I pad development after then-Gov. Frank Murkowski proposed combining Prudhoe Bay and its satellites for tax purposes and deferred development again after then-Gov. Sarah Palin approved the Alaska’s Clear and Equitable Share production tax increase.
The proposed I pad also emerged as a crucial point of discussion in debates over Gov. Sean Parnell’s recent revision to the production tax code. In hearings and speeches during those debates, executives from both BP and ConocoPhillips pointed to I pad as an example of the short-term investment opportunity that lower taxes could facilitate.
Those changes are now law and I pad appears to be progressing, although slowly.
According to the most recent plan of development, the original location for I pad “proved to be unfeasible” because it was “constrained” by a Milne Point road to the west, a large lake to the east and a subterranean ice lens to the north. BP told the state that it had found an alternative site to the north, which could be accessed from the Milne Point road.
In late 2012, BP conducted vegetation mapping and soil studies for the pad and a proposed pipeline corridor that would connect I pad to facilities at Z pad and L pad.
That said, BP told the state that the future of I pad “depends upon finding ways to more efficiently execute the project and reduce project uncertainty and risks.” Ongoing studies in the northwest corner of Prudhoe Bay in 2013 and 2014 include artificial lift, alternative completion designs for wells targeting viscous oil, optimizing pad designs and mapping the N-Sands in the region. All those activities are relevant to I pad, according to BP.
Specifically, BP is using those studies to create a “project concept” that would be reviewed, developed and refined, and also integrated into larger West End projects.
A “generic” timeline given to the state suggested first oil remains many years away.
An I Pad could access 69 million to 144 million barrels of recoverable oil at Orion and 2.7 million to 3.9 million barrels of recoverable oil at Borealis, according to the state.
The Polaris field
BP discovered the Polaris oil pool in the western end of the Prudhoe Bay field in 1969, while delineating the field, and brought the field online in 1999 from W pad and S pad.
Through June 2013, BP had drilled 28 wells at Polaris - 21 from W pad and seven from S pad. AOGCC records indicate that BP had not drilled any wells at the field in 2014 through September. Of the 1 billion barrels of oil in place at Polaris, BP had produced 17.3 million barrels through July 2014 at a 2013 rate of 5,079 bpd.
BP planned no Polaris drilling for 2013 or 2014. A proposal to expand S pad and M pad to better access oil reserves in the north of the field remains in “the appraisal stage,” according to the company. BP is merging the program with its larger West End initiatives. The $3 billion program would add the first new Prudhoe Bay well pad in more than a decade, expand the two existing pads, debottleneck facilities, increase flowline capacity and add surface facilities, according to Weiss. The entire program could add 130 wells and some 200 million barrels of new resources starting in 2018, Weiss said.
The Midnight Sun field
BP discovered the Midnight Sun field at the center of the northern edge of the Prudhoe Bay unit in 1997 and brought the field online from the E pad in October 1998.
Through June 2013, BP had drilled five wells at E pad, the most recent in 2001. The company had not drilled any wells in 2014 through September, according to the AOGCC.
Of the 100 million barrels of oil in place at Midnight Sun, BP had produced more than 20 million barrels through June 2013 but production is currently below 1,000 bpd.
BP is exclusively using water injection to enhance oil recovery at Midnight Sun, in part because the company has yet to build a miscible injection line to the field. While BP has no drilling planned for Midnight Sun, the company has recently told the state it might someday sidetrack existing wells to improve recovery as waterflooding matures.
In October 2014, BP announced plans to drill the P1-122i well at the Midnight Sun field in January 2015. The extended-reach miscible injectant well would support enhanced oil recovery operations at two existing production wells at Midnight Sun
The Lisburne field
On the east side of the unit, the Greater Point McIntyre Area incorporates the Point McIntyre field and four satellites: West Beach, North Prudhoe Bay, Niakuk and Raven.
The facilities in the region also handle Lisburne, which ARCO Alaska discovered in the northeast corner of the Prudhoe Bay field in 1969 and brought online in 1982.
In the year ending March 2014, Lisburne produced some 6,400 bpd of oil, some 660 barrels of natural gas liquids per day and some 124.1 million cubic feet of natural gas per day, according to BP. Cumulatively through July 2014, the field had produced 164.7 million barrels of oil, according to the AOGCC.
According to AOGCC records, BP did not drill at Lisburne in 2014, through September.
The primary activities at the Lisburne field in recent years have involved injection programs to improve recovery. In its most recent plan of development, BP said it was considering several “possible” drilling locations for 2015 but offered no details.
The GPMA satellites
The five other satellites in the Greater Point McIntyre Area are small, produce little oil compared to the unit and have had relatively little development drilling in recent years.
But BP is holding out hope that its recently launched North Prudhoe onshore and nearshore 3-D seismic program will uncover opportunities for investment at these fields.
The two-season seismic program is beginning with nearshore work this year and will advance inland next year to cover some 190 square miles altogether. “Based on preliminary data, it would enable 55 million barrels of new resources and 30 new wells with the potential development,” Weiss said in her February 2014 announcement.
The Prudhoe Bay working interest owners expanded the Lisburne Production Center in the early 1990s to accommodate fluids from nearby Point McIntyre and Niakuk.
ARCO and Exxon discovered Point McIntyre in the coastal section of Prudhoe Bay in 1988. The field came online in 1993 and peaked at 172,995 bpd in December 1996.
The field produced 18,520 barrels of liquids per day in the year ending March 2014.
After drilling a well and a sidetrack at Point McIntyre in 2012 and early 2013, BP began evaluating additional sidetracks, potentially in the north and southeast, two areas the state added to the Prudhoe Bay unit and the Point McIntyre participating area in June 2009.
Sohio discovered the Niakuk oil pool in 1985 and it came online in April 2004.
The field produced 2,300 barrels of liquids per day in the year ending March 2014.
The nearby Raven field produced some 310 bpd of oil in the year ending March 2014, almost entirely from one producer supported by a water injector.
BP said it has no immediate plans for Raven.
ARCO discovered West Beach and North Prudhoe Bay in the 1970s.
The West Beach field had produced 3.37 million barrels of oil by the time BP suspended production in 2001 because declining reservoir pressure and increasing gas-to-oil ratio challenged the economics of the field. Over the intervening years, BP has undertaken numerous studies of the field to determine whether it might one day produce again.
ARCO shut-in the sole North Prudhoe Bay well in February 2000 because the well continued to produce proppant from a fracture stimulation, which posed safety risks, according to the company. BP has said it “may” launch an evaluation of the area this year “to assess the remaining reservoir potential and options for future development.”
