BP Exploration (Alaska) Inc. is focused on old fields. The British giant dropped its Alaska exploration program in 2003 to focus on combating production declines from its 13 North Slope fields, including the massive Prudhoe Bay field that underpins the Alaska economy. Those efforts include infill drilling, enhanced oil recovery and a long-term study of the heavy oil potential across much of its holdings.
As an operator in 2012, BP produced some 363,000 gross barrels of oil per day from four North Slope units — Prudhoe Bay, Milne Point, Duck Island and Northstar. Through subsidiaries, BP also operates the Badami pipelines, Endicott pipeline, Milne Point pipelines and Northstar pipelines, and owns the largest share of the trans-Alaska oil pipeline.
BP also operates the federal Liberty unit that remains years from startup.
Prudhoe Bay comes to lifeIn 1959, Alaska became a state and BP opened its local office.
A decade later, BP drilled a confirmation well for the Prudhoe Bay discovery, which launched 44 years of development work. The discovery of Prudhoe Bay is an adventure tale, but what happened next, what continues to happen daily and what BP hopes will happen for the next 50 years or more, is of greater importance to the State of Alaska.
The delineation campaign of 1969 mapped a field stretching 45 miles from east to west along the coastline and 18 miles from north to south. Geologists initially identified four primary reservoirs — the Kuparuk River formation, the Prudhoe Bay group, the Lisburne limestone and the Kekiktuk Conglomerate — but 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, with BP handling the Western Operating Area, WOA, and ARCO Alaska handling the Eastern Operating Area, EOA.
The historic sealifts of 1969 and 1970 brought nearly 250,000 tons of supplies and equipment, including the first of six gathering centers to handle up to 1.8 million bpd. The sealifts continued each open water season through the 1970s, bringing additional items, including components for the “BP-Hilton” and the Central Power Station.
A gravel road built in the 1970s traversed the field. Later, the working interest owners built extensions connecting this spine road to the individual pads. The BP-operated pads in the WOA were lettered while the ARCO-operated pads in the EOA were numbered.
This naming scheme is still used today.
The initial split guaranteed adequate manpower to develop the gigantic field. It also divided operations between the oil reservoir and an offset gas cap overlying it.
Prudhoe Bay unitizationEventually, though, the owners realized they needed to unitize the field.
“The basic reason for ‘unitizing’ the Prudhoe field was to optimize recovery and equitably divide costs among working interest owners and avoid duplication of facilities,” George Abraham, a now-retired BP executive who worked on the Prudhoe Bay Unit Operating Agreement in the mid-1970s, told Petroleum News in 2008. “By limiting surface facilities you would also minimize possible environmental impacts.”
The 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.
The pipeline connected the Prudhoe Bay field to market on June 20, 1977.
“There was friendly competition with ARCO, operator of the eastern side of the field,” former BP production operator Gene Smagge said in 2009. “We were trying to see who could get their oil into Pump Station 1 first. I think we beat them by a shave.”
Prudhoe Bay production topped 1 million bpd 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 11.5 billion barrels through July 2013, according to the AOGCC. Original estimates had pegged total recovery at 9.6 billion barrels.
The production rate was 225,000 bpd at the end of 2012, according to BP. With its associated fields, production was 266,339 bpd in July 2013 and 238,507 bpd in August 2013, according to the AOGCC and Alaska Department of Revenue, respectively.
The sharp drop was due in large part to planned summer maintenance.
Even 45 years after its discovery, Prudhoe Bay remains BP’s primary focus.
The company drilled 45 wells and performed some 1,700 well work jobs at the field in 2012. As of mid-September, BP had completed some 36 wells at the field in 2013.
Capital to improve operationsWith the increasing maturity of the Prudhoe Bay field in the 1980s, the working interest owners launched numerous capital expenditure programs to improve operations.
Those included an expansion of the flowlines connecting wells to the gathering centers, increasing the gas and produced water capacity of the field, tinkering with gas handling to improve productivity and launching enhanced oil recovery efforts such as waterflooding and a miscible injection program aided by a new Central Gas Facility.
Prudhoe Bay also hosted many technologies pioneered (or at least embraced) on the North Slope. Those include multilateral wells, coiled tubing drilling, extended reach drilling and ongoing tests into multistage hydraulic fracturing, but they also include BP field 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.
Perhaps the biggest changes at Prudhoe Bay yielded the least physical evidence.
In December 1998, BP merged with Amoco to create one of the largest oil companies in the world. The following year, BP-Amoco acquired ARCO. To satisfy the U.S. Federal Trade Commission, BP agreed to sell all ARCO’s Alaska assets to Phillips Petroleum.
The deal left BP as the sole operator of the Prudhoe Bay unit, a position it retains today.
To satisfy the State of Alaska, BP also signed the Charter for the Development of the Alaskan North Slope, which prevented any company from having too large a footprint, and set out terms for how the operators would accommodate each other and smaller players.
The Prudhoe Bay satellitesPrudhoe Bay is bigger than the Prudhoe Bay field.
The Greater Prudhoe Bay Area includes the Prudhoe Bay field and five satellites: Aurora, Borealis, Midnight Sun, Orion and Polaris. The nearby Greater Point McIntyre Area includes the Point McIntyre field and four satellites: West Beach, North Prudhoe Bay, Niakuk and Raven. The facilities in the region also handle the Lisburne field.
While Prudhoe Bay dwarfs those fields, they are each large by any standard except the North Slope. Without Prudhoe Bay, though, none would have justified development.
The Aurora poolMobil Oil Corp. discovered the Aurora oil pool in the northwest quadrant of the Prudhoe Bay field in 1969 with the Mobil-Phillips North Kuparuk State No. 26-12-12 well.
It took until November 2000 for BP to bring the field online from the S pad.
By 2013, BP was developing Aurora using 33 wells — 17 producers, 10 water injectors and six water-alternating-gas, WAG, injectors, according to the 2013 BP annual report.
Of the 200 million barrels of oil in place, BP had produced some 34 million by June 2012, according to its most recent plan of development. Aurora production peaked at 14,000 bpd in August 2006 and averaged 7,500 bpd in 2012, according to BP.
Aurora produces from the Kuparuk formation.
The primary development work at Aurora concerns a tertiary recovery program launched in 2003, where BP alternates cycles of miscible gas injection and water injection.
While BP drilled a production well at Aurora as recently as 2010 and an injection well the following year, the company had no development drilling planned at Aurora for 2013.
The Borealis and Orion poolsAlso in 1969, Mobil Oil discovered the Borealis oil pool along the western edge of the Prudhoe Bay field with the W Kuparuk St 3-11-11 well into the Kuparuk formation.
BP brought the field online in May 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.
By 2013, BP was developing Borealis using 50 wells — 31 producers, nine water injectors and 10 WAG injectors, according to the 2013 BP annual report.
Of the 350 million barrels of oil in place, BP had produced some 69 million barrels of oil equivalent through 2012, according to BP. Borealis peaked at 38,150 bpd in May 2003, according to the AOGCC, and produced 10,000 bpd in 2012, according to BP figures.
Mobil Oil discovered the Orion oil pool in 1968 with the Kuparuk State No. 1 well and BP confirmed the accumulation in 1998 with the Northwest Eileen 2-01 well.
The Orion pool is in the northwest corner of the Prudhoe Bay unit. Brought online in April 2002, Orion produces from the same viscous Schrader Bluff formation present at the BP-operated Milne Point unit to the north and the ConocoPhillips-operated Kuparuk River unit to the west, and is part of joint efforts to expand production of heavier oil.
BP originally developed Orion from its V pad and expanded development to include L pad in mid-2004. As of the end of 2012, BP was developing Orion from 43 wells — 12 oil producers, 20 water injectors and 11 WAG injectors. The two pads pushed production to a peak of 14,460 bpd in June 2007. Of the 3.2 billion barrels of oil in place at Orion, BP has produced 27 million barrels of oil equivalent through 2012 at a rate of 6,000 bpd.
As with all heavier reservoirs on the North Slope, Orion (and Borealis, which it overlaps) is thought to be a crucial component for maintaining production for decades to come.
Proposed I padThe efforts at Orion and Borealis concern a proposed 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.
While BP has also cited technical challenges through the years, those delays have largely concerned the changing fiscal systems in Alaska over the past decade. BP deferred I pad for the first time in early 2005, after then-Gov. Frank Murkowski proposed combining Prudhoe Bay and its satellites for tax purposes, which would have increased the tax rate for the smaller fields. BP deferred I pad development again in early 2008, just months after then-Gov. Sarah Palin approved ACES, the Alaska’s Clear and Equitable Share production tax increase.
In early 2011, I pad emerged as a crucial point of discussion in debates over House Bill 110, Gov. Sean Parnell’s revision to the production tax code. In hearings and speeches around that time, BP and ConocoPhillips executives both pointed specifically to I pad as an example of the short-term investment opportunity that lower taxes could facilitate.
An I Pad could access between 69 million and 144 million barrels of recoverable oil at Orion and between 2.7 million and 3.9 million barrels of recoverable oil at Borealis, according to state estimates. In its most recent development plans, BP proposed work to bring northwest Orion into production, but deferred northwest Borealis. Considering the size discrepancy between the fields, BP wants to develop Orion and Borealis together, but because Orion is more technically complex, it felt the need to defer both projects.
The state approved the 2013 plan for Orion, but rejected the Borealis plan. The issue of I pad is almost certain to emerge when BP submits its 2014 development plans this fall.
The Polaris fieldThe Polaris oil pool is another remnant of the early days of Prudhoe Bay delineation.
BP discovered the pool in the western end of the Prudhoe Bay field in 1969 with the North Kuparuk State 26-12-12 well into the shallow and viscous Schrader Bluff and Ugnu formations, and brought the field online in 1999 from W pad and S pad.
Through 2012, BP had developed the field from 26 wells — nine oil producers, 15 water injectors and two WAG injectors. Of the 1 billion barrels of oil in place at Polaris, BP had produced 13.4 million barrels through 2012, at a 2012 rate of some 5,238 bpd.
BP drilled its most recent Polaris wells in 2011.
While BP planned no Polaris drilling in 2013, the company is appraising a program to expand its S pad and M pad to better access oil reserves in the northern part of the field.
The Midnight Sun fieldBP discovered the Midnight Sun field in 1997 with the Sambuca No.1 well.
Midnight Sun began producing from the Kuparuk formation in October 1998. BP is developing the field from two producers and three injectors at E pad at the center of the northern edge of the unit. The most recent of those wells was drilled in 2001.
Of the 100 million barrels of oil in place at Midnight Sun, BP had produced some 19 million barrels through 2012, but production is currently some 1,000 to 1,500 bpd.
Currently, 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 told the state it might someday sidetrack existing wells to improve recovery as waterflooding matures.
The Lisburne fieldThe Greater Prudhoe Bay Area covers the five satellites on the western side of Prudhoe Bay. On the eastern side, BP also operates the fields in the Greater Point McIntyre Area.
The largest of those is Lisburne.
ARCO Alaska discovered the field in the northeast corner of the Prudhoe Bay field in 1969 with the Prudhoe Bay State No. 1 well and production began in 1982. Through the end of 2012, BP had developed the field through 46 wells — 39 oil producers, three gas injectors and four water injectors. Of the 2.4 billion barrels of oil in place, BP had produced some 178 million barrels of oil equivalent through 2012, according to its annual report. Production peaked at 47,600 bpd in mid-1987 and in 2012 was around 6,000 bpd.
The Lisburne reservoir is beneath the Prudhoe Bay reservoir in a tight formation of limestone and dolomite. The geology continues to present challenges for BP. The Lisburne wells have a high gas-to-oil ratio, which BP combats by cycling wells through several days of production followed by several days or weeks of suspending production.
The Point McIntyre and Niakuk fieldsIn the early 1990s, the Prudhoe Bay working interest owners expanded the Lisburne Production Center to accommodate fluids from nearby Point McIntyre and Niakuk.
ARCO and Exxon discovered Point McIntyre in the coastal section of Prudhoe Bay in 1988 with the Point McIntyre No. 3 well into the Kuparuk River and Kalubik formations.
The field came online in 1993 and peaked at 172,995 bpd in December 1996.
Of the 880 million barrels of oil in place, BP had produced some 454 million barrels of oil equivalent through 2012, at a 2012 rate of some 18,000 bpd, according to BP. The two gravel drill sites accommodate 64 wells — 47 oil producers, one gas injector, 12 water injectors and four WAG injectors, according to the company.
After drilling a well and a sidetrack at Point McIntyre in 2012 and early 2013, BP is now 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 with the Niakuk No. 5 well into the Kuparuk formation. The field came online in April 2004 and production peaked at 37,172 bpd in September 1996, but has since dropped off considerably. The two pads at Niakuk currently accommodate some 19 wells — 13 oil producers and six water injectors.
Of the 400 million barrels of oil in place at Niakuk, BP had produced some 94 million barrels of oil equivalent through 2012, at a 2012 rate of some 2,800 bpd.
The nearby Raven field produced some 470 bpd in 2012, almost entirely from one producer supported by a water injector. BP said it has no immediate plans for Raven.
ARCO discovered the remaining Greater Point McIntyre fields — West Beach and North Prudhoe Bay — in the 1970s, but both fields are currently shut-in for low production.
The Milne Point unitTo the northwest of Prudhoe Bay, the Milne Point unit primarily produces from the Kuparuk oil pool, but also from the heavier Sag River, Schrader Bluff and Ugnu pools.
The history of the Milne Point unit can be divided into three periods: the slow decade following its discovery, the active decade after BP became the operator and the present.
Standard Oil Company of California discovered the four Milne Point horizons in 1969 with the Kavearak Pt. No. 32-25 well, according to the AOGCC, but Conoco Inc. delineated and developed the field in 1980 and brought it online in November 1985.
With the low oil prices of the late 1980s, Conoco suspended production from January 1987 until April 1989. The field peaked at 20,000 bpd in the early 1990s, but had declined to 17,000 bpd by the time BP took over the unit in early 1994, according to the AOGCC.
BP quickly built the F pad in the northern end of the unit and the K pad in the southeastern end of the unit, which pushed production to 52,900 bpd by July 1998.
To better understand the offshore and nearshore potential of the Kuparuk reservoir, BP commissioned a seismic program in late 2012 covering some 90 square miles.
Heavier oil tantalizingWhile BP acquired Milne Point for the lighter oil Kuparuk reserves, the three prodigious heavier oil reserves have since proved tantalizing.
Conoco spent $130 million building four pads and drilling 22 wells at Schrader Bluff in the early 1990s, bringing the field online in March 1991 at 3,700 bpd, but production from the shallow formation was down to 2,850 bpd by the time BP took over the unit in early 1994, according to the AOGCC. After several years of drilling without greatly improving production, BP announced a plan in 1997 to develop the Schrader Bluff pool with seven new or expanded pads, 75 miles of new pipeline and some 300 wells.
By 2001, BP said its ambitious program had “proved to be uneconomic.” Instead, the company expanded conventional drilling at E pad, H pad and J pad, which lifted production to 12,000 bpd by April 2002, and built S pad in the south of the unit.
The biggest challenges at Schrader Bluff are the viscous oil and sandy formation, but BP found that horizontal drilling, jet pumps and waterfloods were useful in both regards.
This work helped Schrader Bluff production peak at 23,922 bpd in October 2003.
For 2013, BP planned to drill four Schrader Bluff infill wells originally planned for 2012 — one producer and three injectors — and four Kuparuk coil sidetrack wells, but AOGCC records through mid-September showed no wells completed at Milne Point.
Sag, Ugnu challengingConoco tested the Sag River starting in 1980, but BP brought the field into production in 1995. The Sag River is the deepest of the producing intervals at Milne Point, and therefore the oil is lighter than at Schrader Bluff and Ugnu, but the high gas-to-oil ratios and poor pump performance have challenged production. Despite some occasional spikes through the years, average annual production has remained less than 700 bpd.
The Ugnu pool — a 20 billion barrel reservoir overlying portions of the Prudhoe Bay, Kuparuk River and Milne Point fields — is an even tougher nut to crack than the Schrader Bluff, but underpins long-term hopes for the heavy oil potential of the region.
Starting in 2007, BP launched a pilot program at S pad to test various techniques for producing this heavy oil. The first, called CHOPS, or cold heavy oil production with sand, produces oil-saturated sand and heats the mixture at the surface to separate the oil from the sand. BP also began evaluating an alternate method involving horizontal wells.
Following the launch of a $100 million testing facility, BP brought a horizontal heavy oil test well into operation in April 2011. This initial well surpassed expectations, as did the first CHOPS well completed in late 2012, but BP believes it needs to demonstrate the long-term viability of the program and to better manage the costs of heavy oil production before Ugnu can become a regular component of the North Slope production picture.
To date, BP has drilled four test wells, two nearly vertical and two horizontal.
Of the 8.9 billion barrels of oil in place at the Milne Point unit, BP had produced 308 million barrels of oil equivalent through 2012, at a 2012 rate of 17,000 bpd.
The Duck Island unit
The other fields in the BP portfolio are all offshore.
The earliest developed among those is the Duck Island unit, better known by the name of its largest field: Endicott. The unit also includes the Eider and Sag River North participating areas.
Sohio Alaska Petroleum Co. discovered the Endicott oil pool in 1978 with the Sag Delta No. 4 well and tested it the following year with a well into the Kekiktuk formation.
After building two compact gravel islands connected to shore by a causeway — the first offshore oil producing islands in the Arctic — BP brought Endicott online in July 1986.
Endicott peaked at some 104,000 bpd between November 1987 and October 1993, but the field had declined to 30,450 bpd by February 2001, according to the AOGCC.
In 1998, while developing the northwest corner of Endicott, BP discovered the Eider oil pool in the Ivishak formation. While production hit 6,244 bpd by February 1999, it soon dropped precipitously. BP suspended production from October 1999 to May 2000, and again in June 2007. Except for a six-day test in December 2009, it has remained offline.
The current development work at Endicott involves enhanced oil recovery using miscible water-alternating-gas injections. BP may bring its Bright Water technology to the field, according to the most recent development plan. BP also suggested it might work over wells or drill sidetracks this year, but had not permitted any wells as of mid-September.
Of the 1 billion barrels of oil in place at Endicott, BP had produced 487 million barrels of oil equivalent through 2012 at a 2012 rate of only 9,000 bpd. The field is developed with 80 wells — 55 oil producers, four gas injectors and 21 water injectors.
Of the 14 million barrels of oil in place at Sag River North, BP had produced 9 million barrels of oil equivalent through 2012 at a 2012 rate of 1,000 bpd.
The Northstar unit
After breaking an Arctic offshore barrier with Endicott, BP pushed farther with Northstar, the first Arctic field to be developed from an island connected to the shore only by pipeline.
Instead of the causeway used to connect Endicott to land, BP installed a buried subsea pipeline at Northstar, a technique later replicated at the Oooguruk and Nikaitchuq units.
Shell Western E&P Inc. discovered Northstar in 1984 with the BF-47 No. 1 well and BP constructed its five-acre gravel island in the winter of 1999 and 2000. After coming online in November 2001, production quickly rose, peaking at some 69,000 bpd by 2004.
The Northstar unit primarily produces from the Ivishak and the Shublik formations, but in recent years BP also began developing two smaller reservoirs called Fido and Kuparuk. BP is currently seeking participating areas for both reservoirs. With the unit split between state and federal leases, participating areas have caused problems in the past, such as a recent dispute between the state and minority partner Murphy Oil Corp.
Of the 310 million barrels of oil in place at Northstar, BP had produced 156 million barrels of oil equivalent through 2012 at a 2012 rate of 8,000 bpd. The field is developed with 23 wells — 15 oil producers, six gas injectors and two water injectors.
Endicott and Northstar set the stage for another offshore venture: the Liberty field.
After drilling Liberty No. 1 on a federal lease situated six miles offshore in the Beaufort Sea, BP announced a 100 million barrel oil discovery in 1997. Seeing Northstar as a model, BP initially planned to develop Liberty from a standalone gravel island connected to shore by a subsea pipeline, but the company ultimately decided to drill ultra-extended reach wells — some as long as eight miles — from the existing Endicott facilities.
To accommodate this boundary-pushing proposal, BP commissioned a massive drilling rig from Parker Drilling Co. The rig components arrived in Alaska in 2009, but BP suspended the project in November 2010 while it conducted an engineering review and ultimately BP cancelled the project — at least “in its current form” — in early 2012.
Having already spent more than $1 billion on Liberty, BP is still actively considering alternative ways to develop the field, including its original idea of a gravel island. The company must submit a new development plan to federal regulators by the end of 2014.