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Vol. 20, No. 47 Week of November 22, 2015
Providing coverage of Alaska and northern Canada's oil and gas industry

The Producers 2015: BP Exploration (Alaska) Inc.

ERIC LIDJI

For Petroleum News

BP opened its Alaska office in 1959, the same year Alaska officially became a state. A decade later, the company drilled a confirmation well for the Prudhoe Bay discovery, which launched five decades of development. The company hopes it can continue for another five decades.

The delineation campaign of 1969 mapped a massive oil field stretching 45 miles from east to west along the North Slope 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 found heavier oil reserves in shallower reservoirs, such as West Sak, Schrader Bluff and Ugnu.

A series of drilling and infrastructure construction projects prepared Prudhoe Bay for development. All those efforts would have been for naught without the construction of the trans-Alaska oil pipeline, which connected the Prudhoe Bay field to market in 1977.

BP Exploration (Alaska) Inc. spent much of the next decade managing its portion of North America’s largest oil field, where production peaked at 1,627,036 barrels per day in January 1987. But the company was also pursuing other North Slope opportunities. BP brought the onshore Lisburne field online in 1982, the onshore Milne Point unit online in 1985, the offshore Duck Island unit online in 1986, the onshore Point McIntyre field online in 1993 and the onshore Badami unit in the eastern North Slope online in 1998.

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 ARCO’s assets in Alaska to Phillips Petroleum Inc.

Following the merger and subsequent divestment, BP underwent a period of expansion across its existing properties on the North Slope. Between 1997 and 2004, the company brought into production the five satellites in the Greater Prudhoe Bay Area - Aurora, Borealis, Midnight Sun, Orion and Polaris - as well as the Niakuk satellite. In 2001, the company brought the offshore Northstar unit into production. In those years, the company also advanced plans for developing heavy oil prospects among its properties and began working on a strategy for the technically challenging Liberty field in the Beaufort Sea.

A period of contraction began in 2003, when BP dropped its exploration program in Alaska to focus on increasing production from existing fields. The exploration program had included investments in the Pete’s Wicked and Placer discoveries, which other smaller operators have since pursued. In 2008, BP partnered with Savant Alaska LLC and ASRC Exploration LLC to bring the troubled Badami unit back into sustained production and eventually sold the field and its associated infrastructure to the two small independents. In 2014, BP sold Duck Island, Northstar and a 50 percent stake in Milne Point and Liberty to independent Hilcorp Alaska LLC in an attempt to focus its attention on Prudhoe Bay and major North Slope natural gas sales. The sale involved a major reduction in workforce, although some former BP employees later joined Hilcorp.

The Prudhoe Bay unit: Initial Participating Areas

After ARCO and Humble Oil drilled the Prudhoe Bay discovery well in 1968, the initial delineation campaign at Prudhoe Bay mapped the largest oil field in North America.

In an attempt to wrangle the massive discovery, the initial development program split the field in half. BP Exploration (Alaska) Inc. took the Western Operating Area, or WOA, and ARCO Alaska took the Eastern Operating Area, or EOA. The split gave each company a more manageable workload and divided operations between the oil reservoir and an offset gas cap. Eventually, the owners decided to unitize the field to optimize recovery, divide costs more equitably and avoid building unnecessary infrastructure. The two regions are currently managed together as the initial participating areas, or IPA.

In early 2014, before her company announced the sale to Hilcorp, BP Alaska President Janet Weiss detailed a $1.25 billion capital program for Alaska. The program amounted to a 25 percent increase in total spending and a 40 percent increase in spending aimed at increasing production through drilling, workovers and major projects. “We’re drilling more wells and doing significantly more well work jobs in 2013 than 2012, and plan significantly more in 2014 than 2013,” Weiss said in a February 2014 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 included funds to bring two rigs to Prudhoe Bay — one by 2015 and one by 2016, which Weiss said would add between 30 and 40 wells each year at the unit.

The current plan of development for the IPA suggests the increase is largely focused on the satellite fields. The drilling activity planned for the IPA in 2015 was similar to 2013 and 2014. But the plan of development shows the oldest commercial operation on the North Slope to be continually declining and yet surprisingly robust for its fifth decade.

The initial participating areas produced 203,700 barrels per day of crude oil and condensate, 6,931 million cubic feet per day of natural gas and 39,900 bpd of natural gas liquids in 2014, according to BP. Those figures are all down from 2013, when BP produced 218,000 bpd of crude oil and condensate, 7,145 million cubic feet of natural gas and 45,000 bpd of natural gas liquids from the IPA.

The company expects IPA liquids production to fall again this year. The current forecast predicts crude oil and condensate production between 157,000 and 200,000 bpd and natural gas liquids production between 31,000 and 39,000 bpd.

The company drilled 54 penetrations in the IPA in 2014 — eight grassroots wells and 46 sidetracks. The sidetracks included 16 rotary and 30 coiled tube rig penetrations. The company also performed 1,650 well workover jobs, including 416 “rate adding jobs.”

Drilling figures were down from 2013, when BP drilled 57 penetrations in the IPA and performed approximately 1,900 well workover jobs, including 300 “rate adding jobs.”

Current plans

This year, BP expects a “similar” level of drilling activity with a “slightly different mix” of wells — between 13 and 20 penetrations using a rotary rig and between 35 and 40 penetrations using a coiled tubing rig. The workover program is also expected to be “similar” to last year, with 20 to 30 wells. A map of “drilling candidates” includes one new well, eight rotary sidetracks, 14 coiled tubing sidetracks and eight rigged workovers.

The capital projects under evaluation this year largely serve to optimize operations.

One project would upgrade the seawater systems used to process and inject water into the gas cap and other areas of the field to maintain pressure and increase production rates.

Another project would replace the gas-powered compressors at all three Prudhoe Bay flow stations with electric-powered compressors better suited for the current production profile of the field. BP sanctioned the project in 2012 and replaced the compressor at Flow Station 1 in 2014. The company never completed the other two projects and now intends to re-bid the construction contracts this year for replacement in 2016 and 2017.

Perhaps the biggest development on the horizon for the IPA — albeit so far on the horizon it may never come to pass — is the possibility of major natural gas sales. The company currently uses a small amount of Prudhoe Bay gas for operations and re-injects the majority to maintain field pressure. In July 2015, BP formally asked the Alaska Oil and Gas Conservation Commission to increase the amount of gas the company is allowed to withdraw from the field and allow the company to inject carbon dioxide instead. The current restrictions date to 1977, when the company was preparing for initial oil sales.

The company believes an increased offtake allowance is a crucial prerequisite for conducting major natural gas sales from the North Slope. The current AK LNG project calls for moving approximately 3.5 billion cubic feet per day with 75 percent coming from Prudhoe Bay. Under that program, BP would need to withdraw approximately 3.3 bcf per day from the field to meet its commitments to the pipeline project and satisfy its operational needs. The current limit is 2.7 bcf per day.

The Prudhoe Bay Unit: Western Satellites

In addition to the main Prudhoe Bay field, the unit area includes five satellites clustered mostly along its western edge: Aurora, Borealis, Midnight Sun, Orion and Polaris.

The Aurora field

Mobil Oil Corp. discovered the Aurora oil pool in the northwest corner of the Prudhoe Bay field in 1969, although BP brought the field online from S pad in November 2000.

As of July 2015, the Aurora field had 33 wells — 18 oil producers and 15 water-alternating-gas injectors, according to the most recent annual report. At the start of 2014, the field had 17 producers, 10 water injectors and six water-alternating-gas injectors.

Of the estimated 200 million barrels of oil in place at Aurora, BP had produced some 39.46 million barrels through June 2015, according to the company. The field averaged 4,305 barrels of oil per day in the year ending June 30, 2015, down from an average of 4,655 bpd in the previous year and down from a peak of 14,000 bpd in August 2006.

During the recently completed year, BP drilled three new production wells at the Aurora field. The S-42A sidetrack will replace the S-108 producer, which BP plugged and abandoned after finding collapsed tubing and casing during a workover. The S-44A sidetrack is north of the existing S-101 injector, which was also repaired this year. BP expects to bring those two wells into production by the end of the year. The S-135 well was brought online in October 2014 at an initial rate of 884 barrels of oil per day.

The company said it is using geologic models to evaluate additional wells for future drilling during the coming year, including a potential producer to accompany the existing S-107 injector and a potential injector to accompany the existing S-105 producer.

Also during the year, BP repaired the suspended S-104 injector, converted the S-128 water-alternating-gas injector to miscible injectant and conducted a hydraulic fracturing operation on S-129, which yielded a post-frack production rate of 2,486 barrels per day.

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.

As of July 2015, the Borealis field had 57 wells — 25 from L pad (the same as last year), 22 from V pad (the same as last year) and 10 from Z pad (one more than last year), according to the most recent plan of development. Of the estimated 350 million barrels of oil in place at Borealis, BP had produced 77.8 million through June 2015, according to the company. Borealis produced 8,768 bpd during the year ending June 30, 2015, down from 9,932 bpd the year before and a peak of 38,150 bpd in May 2003.

During the previous year, BP repaired two wells at V pad and equipment associated with one well at Z pad and began preliminary maintenance on a well with communication issues. The company is planning to begin miscible injection at a well on Z pad.

The company also finished reprocessing the S3 3-D seismic survey earlier this year.

This year, the company is evaluating potential infill opportunities at Z pad.

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. As of July 2015, Orion had 49 wells — 25 from V pad (the same as last year), 23 from L pad (the same as last year) and one new injector drilled from Z pad. Of those 49 wells, 12 are active multi-lateral producers and 34 are active injectors.

Of the 3.2 billion barrels of oil in place at Orion, BP had produced 32.1 million through June 2015. Orion produced 4,693 bpd in the year ending June 30, 2015, down from 5,483 bpd the previous year and down from a peak of 14,460 bpd in June 2007.

While BP did not drill at Orion this past year and has no plans to drill this coming year, the field is part of a larger regional endeavor to economically develop viscous oil. Orion produces from the same viscous Schrader Bluff formation present at the Milne Point unit to the north and portions of the ConocoPhillips-operated Kuparuk River unit to the west.

Many projects underway at Orion are related to the viscosity of its oil. For example, BP is currently studying ways to improve Gathering Center 2 to better accommodate viscous oil. The facility was designed for light oil and improvements in 2012 and 2013 to improve solids handling have “not yielded the desired level of improvements,” according to the company. Similarly, BP conducted geomechanical studies and enhanced dynamic models this year to better understand “subsurface uncertainties” related to viscous oil.

Those efforts are expected to continue this year, as is an ongoing program to reduce the rate of downtime for viscous wells, which has hit 50 percent in some sections of the field in recent years. For years, the company has been considering a multi-stage trial to better understand the project but has deferred the project “due to the current business climate.”

Another deferred project at Orion is the proposed I pad.

While BP had originally expected to bring the pad online by 2006, the company has since deferred the project twice: first until 2010 and currently until as late as 2020. The program presents considerable technical challenges but has also been at the center of political debates over the past decade. The two deferrals followed changes to the state oil production tax by the Murkowski and Palin administrations and was a prominent point of discussions during legislative hearings over then Gov. Sean Parnell’s tax code changes.

In its previous plan of development, BP told state officials that the original location for I pad had “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. While that problem had a solution, the company also said the future of I pad “depends upon finding ways to more efficiently execute the project and reduce project uncertainty and risks.”

This year, BP said the future of I pad “will be informed by the results of sand control technology in the Schrader Bluff formation. If a trial of sand control technology is successful, the learnings will be considered in Orion development planning.”

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.

As of July 2015, Polaris had 28 wells — 21 from W pad and seven from S pad, the same number as last year. Of the estimated 1 billion barrels of oil in place at Polaris, BP had produced 18.7 million barrels through the end of June 2015. The field produced 3,890 barrels per day in the year ending June 30, down from 4,080 bpd the previous year and a peak near 7,000 bpd.

While BP drilled no Polaris wells last year and is planning none for this year, the company is dealing with many of the same issues occupying its attention at Orion.

And just as sand control technology is holding up the proposed I pad development at Orion, it is also holding up a proposed expansion of the S pad and M pad at Polaris.

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 July 2015, BP had drilled six wells at E pad. The most recent was an injector drilled this year and was the first new well since 2001. Of an estimated 100 million barrels of oil in place at Midnight Sun, BP had produced some 20.4 million barrels through June 2013. Production is now 964 bpd, down from 1,106 last year.

After drilling the extended-reach P1-122i miscible injectant well at the Midnight Sun field earlier this year, BP said it has no plans for drilling activity during the coming year.

The Prudhoe Bay unit: Greater Point McIntyre Area

BP Exploration (Alaska) Inc. appears to be postponing any major development decisions in the Greater Point McIntyre Area until the results of a recent seismic survey can be processed, according to plans of development submitted to the state in late June 2015.

The Greater Point McIntyre Area incorporates six fields on the east side of Prudhoe Bay — Point McIntyre, Lisburne, Niakuk, North Prudhoe Bay, Raven and West Beach. The region produces little oil compared to the Prudhoe Bay unit as a whole, in part because the region is aging and in part because development drilling has been minimal in recent years. The future of the region depends largely on the results and effectiveness of the large and multi-year North Prudhoe 3-D seismic program completed earlier this year.

According to BP, it should take one or two years to process the results of the survey, which means any resulting development drilling is likely many years away. Until then, aging fields will continue to decline and suspended fields will remain out of production.

Through July 2015, the GPMA had produced more than 726 million barrels.

The Lisburne field

ARCO Alaska discovered the Lisburne field in the northeast corner of the Prudhoe Bay region in 1969 and brought it online in 1982. In the year ending March 31, 2015, Lisburne produced 1.7 million barrels of liquids at an average rate of 4,800 bpd — down from 2.4 million barrels at a rate of 6,400 bpd the previous year.

The main Lisburne Production Center at the aging field is currently gas constrained, which, because of the high gas-to-oil ratio of many wells at the field, impacts oil production. One strategy BP uses to manage this problem is suspending certain wells for days or even weeks after several days of production, which the company has said will often result in lower gas-to-oil ratios when wells are eventually returned to production.

Earlier this year, BP began drilling the L3-03 well at Lisburne and plans to drill two more development wells — L3-10 and L1-23 — through the remainder of the year. The results of those wells will determine the drilling program for the end of this year and next year.

In the early 1990s, the Prudhoe Bay working interest owners expanded the Lisburne Production Center to accommodate fluids from nearby Point McIntyre and Niakuk.

Through July 2015, Lisburne had produced more than 166 million barrels.

The Point McIntyre field

ARCO and Exxon discovered Point McIntyre in the coastal section of Prudhoe Bay in 1988 with the Point McIntyre No. 3 well. The field came online in 1993 and peaked at 172,995 bpd in December 1996. In the year ending March 31, 2015, Point McIntyre produced 5.94 million barrels of liquid hydrocarbons at a rate of 16,370 bpd — down from 6.79 million barrels at a rate of 18,520 bpd the previous year. “Long-term oil production is expected to continue to naturally decline from current rates due to increasing water cuts and gas-oil ratios,” BP wrote in its development plan.

Through July 2015, Point McIntyre had produced more than 457 million barrels.

The Niakuk field

Sohio discovered the Niakuk oil pool in 1985 and it came online in April 2004. Niakuk production fell dramatically last year. In the year ending March 31, 2015, the field produced 372,000 barrels of liquids at an average rate of 1,020 bpd — down from 844,000 barrels at an average rate of 2,300 bpd the previous year.

Through July 2015, Niakuk had produced more than 94.2 million barrels.

Raven, West Beach, North Prudhoe

The three other fields in the Greater Point McIntyre Area are significantly smaller.

In the year ending March 31, 2015, Raven produced 60,000 barrels of crude oil, condensate and natural gas liquids at an average rate of 170 bpd — down from 110,000 barrels at an average rate of 3,100 bpd during the previous year. Given that the lone producing well at the Raven field “still produces effectively,” according to BP, the company has no plans to sidetrack it during the upcoming year.

Through July 2015, Raven had produced nearly 3.1 million barrels.

ARCO discovered West Beach and North Prudhoe Bay in the 1970s.

The lone producing well at North Prudhoe was suspended in February 2000 because of safety concerns related to a technical problem. An attempt to return the well to production in 2005 failed. A recently completed evaluation of the well yielded no immediate plans to return it to production, according to BP, but the company believes the results of the seismic campaign could present other development options at the field.

Through July 2015, North Prudhoe Bay had produced nearly 2 million barrels.

West Beach production was suspended in 2001 because declining reservoir pressure and increasing gas-to-oil ratio challenged the economics of the field. Since then, BP has undertaken numerous studies of the field to determine whether it might one day produce again. The future of the field now depends largely on the results of the seismic survey.

Through July 2015, West Beach had produced nearly 3.4 million barrels.



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