Of all the companies that maintained some drilling program in Alaska this year, BP Exploration (Alaska) Inc. had the harshest response to the current economic climate.
A number of operators suspended drilling programs entirely for the short term, hoping oil prices would recover. Others scaled back operations. And still others made field-by-field determinations about where to advance and where to retreat while prices remain low.
After several years of increased activity at the Prudhoe Bay unit, BP made several big cuts over the course of 2016. The company announced a 13 percent reduction in workforce in January and increased the cuts to 17 percent in March. Over roughly the same period of time, the company idled four of the six rigs it had operating at the unit.
Those decisions set the table for the three plans of development the company filed over the course of 2016 to describe its recent activities and upcoming plans for the unit: for the Initial Participating Areas, the Greater Point McIntyre Area and the Western Satellites.
All three plans showed the results of the increased development program in 2015 - some more than others - and all three suggested fewer activities across the unit this year.
According to the Alaska Oil and Gas Conservation Commission, BP drilled 52 wells at Prudhoe Bay in 2014 and 75 in 2016. The company had drilled at least 26 in the first six months of 2016, which suggests a drilling program more in line with 2014 levels.
How the reductions will impact production remains to be seen. By the start of 2014, the entire Prudhoe Bay unit had produced 12.41 billion barrels of oil. The unit produced 90.2 million barrels that year and 88.4 million barrels in 2015 for a total of 12.59 billion barrels by the start of this year. In the first six months of 2016, the Prudhoe Bay unit produced 45.1 million barrels, suggesting growth as a result of the 2015 program.
Initial Participating Areas
At the Initial Participating Areas, the largest of the three administrative areas at Prudhoe Bay and the first to report each year, BP told the state it expected to reduce drilling activities to 1.6 rig years in 2016, down from 3.8 rig years in 2015. Seen another way, the company expected to drill some 31 wells or sidetracks this year, compared to 60 in 2015.
BP predicted a slight decline in production to a range of 157,000-196,000 barrels of crude oil and condensate per day in 2016. The company produced some 196,400 bpd in 2015, which fell at the high end of the range of 157,000-200,000 bpd BP had forecast. The company also predicted natural gas liquids production between 36,000 and 45,000 bpd in 2016. That might actually yield an increase over the 38,000 bpd the company produced in 2015, which was also at the high end of a forecast of 31,000-39,000 bpd.
BP had forecast harsher declines - 10 to 30 percent for crude oil and condensate and 2.6 to 24 percent for natural gas liquids - in its original filing, before revising its figures.
The drilling programs in recent years have been spread in clusters across the geographic expanse of the unit. The 2015 program included a cluster into the Sag River formation in the north-central section of the unit, concentrated on the Northwest Fault Block. The cluster included five wells from F-pad, four wells from R-pad, one well from S-pad and an associated well from Drill Site 03. All but one was a sidetrack of an existing well.
The program for this year is also spread across the unit, with a cluster of eight wells planned for Drill Site 03, Drill Site 09 and Drill Site 16 in the southeast of the unit.
The cuts planned for this year include both drilling and maintenance.
BP told the state it intended to drill eight rotary wells this year, down from 19 in 2015, and 24 coiled tubing wells, down from 41 in 2015. Of those wells, only two would be new, or “grassroots” wells, down from eight last year. (The rest would be sidetracks.)
The plan calls for even steeper declines in certain well workover activities, which involve repairing old wells to improve operations. The company is planning rig workover operations at four wells this year, down from 27 last year, although some of that decline can be attributed to the increasing success of non-rig workover operations at the field.
The Initial Participating Areas plan of development yielded another disturbing development. The state required BP to provide information about marketing plans for future natural gas production at the Prudhoe Bay. The company declined. A debate remained unresolved throughout much of the year, prompting concerns of an ongoing legal battle. The state and the company reached an agreement in late September.
Greater Point McIntyre Area
The fields in the Greater Point McIntyre Area have been in a holding pattern in recent years and should remain that way this year, according to a recent development plan.
Future activity in the region depends largely on the results of the North Prudhoe seismic survey. BP completed the offshore portion of the survey in December 2014 and the onshore portion in April 2015 and expects processing to take at least “one to two years.”
The Greater Point McIntyre Area includes six fields. The Point McIntyre and Lisburne fields are the largest, followed by Raven, Niakuk, North Prudhoe Bay and West Beach.
At Lisburne, BP drilled three wells - L1-23, L3-03 and L3-10 - and performed 31 rate-adding non-rig workover projects on 26 existing wells at the field. The company expects to drill two additional wells - L1-13 and L5-12A - during the upcoming period and is considering several additional drilling locations pending the result of those wells.
The Lisburne field produced some 5,800 barrels per day of crude oil, condensate and natural gas liquids in the year ending March 31, 2016 - up from 4,800 bpd during the same period in 2015 and down from 6,400 bpd during the same period in 2014.
Lisburne produced some 117.3 million cubic feet of gas per day during the reporting period - up from 91.4 mmcfpd in 2015 and down from 124.1 mmcfpd in 2015. Most of the gas produced at Greater Point McIntyre is re-injected to improve oil production.
Those rates yielded a gas-to-oil ratio (standard cubic feet divided by stock tank barrels of oil) of 20,071 in 2016, 19,224 in 2015 and 19,269 in 2014. The high and increasing ratio impacts oil production, as ambient temperatures in the region influence the efficiency rates of compressors that determine oil off-take rates, according to the company.
One strategy BP is using to reduce the gas-to-oil ratio and increase oil production involves intermittent production cycles, rather than continuous production. Certain wells are produced for several days at a time followed by days or even weeks of being shut-in.
Activity at the other fields in the Greater Point McIntyre Area depends partially on the results of the seismic survey. Point McIntyre produced 15,410 barrels of liquids per day in the year ending March 31, 2016, down from 16,370 bpd in the 2015 period and 18,520 bpd in the 2014 period. The field produced 62.5 billion cubic feet of gas during the 2016 period, down from 69.6 bcf in the 2015 period and 62.4 bcf during the 2014 period.
The Niakuk field produced 1,110 barrels of liquids per day during the 2016 period - up from 1,020 bpd during the 2015 period and down from 2,300 bpd during the 2014 period.
Niakuk produced 800 million cubic feet of gas during the 2016 period - up from 300 mmcf during the 2015 period and down from 1 bcf during the 2014 period.
While BP reported no drilling activity at either field in the 2016 period, the company described an “active” non-rig workover program at both fields. The company performed one rigged project at the Point McIntyre field to repair a casing leak at the P1-14 well and restore the well to normal injection in March 2016, and seven projects at Niakuk.
The Raven field produced 130 barrels of liquids per day during the 2016 period - down from 170 bpd during the 2015 period and 310 bpd during the 2014 period. The field produced 730 million cubic feet of gas during the 2016 period - up from 590 mmcf during the 2015 period and up from 700 mmcf during the 2014 period.
The North Prudhoe Bay field and the West Beach field have been shut-in since February 2000 and January 2001, respectively. Restarting North Prudhoe Bay production would require repairs to its sole production well and overcoming geological challenges in the Ivishak and Sag River formations, according to BP. Restarting production at West Beach would require an internal pipeline integrity inspection, according to BP. In both cases, the seismic survey could potentially hasten development work by reducing technical risks.
Western Satellites
Unlike the production declines at the Initial Participating Areas and the Greater Point McIntyre Area, BP reported increased oil production at four of the five Western Satellites - Aurora, Borealis, Midnight Sun, Orion and Polaris - at the Prudhoe Bay unit.
The increases came from a combination of drilling activity at a few fields and maintenance activities at the other fields. Whether those activities can continue at a time when the company is reducing both its workforce and its drilling plans in response to depressed oil prices remains to be seen. The longer-term projects required for maintaining growth at the western satellites appear to be on hold for another year.
As has been the case for years, the plans offer little progress on several big projects, such as construction of a proposed I pad or an expansion of the existing S pad and M pad, all of which are on hold until a sand control trial can be completed at Z pad. Additionally, BP is continuing to search for ways to improve the sand handling capacity of Gathering Center 2, which was created to handle lighter oil than is currently being produced.
Aurora produced 6,303 barrels of oil per day between July 2015 and June 2016, up from 4,305 bpd during the 2014-15 cycle and 4,655 bpd during the 2013-14 cycle.
In the final months of 2015, BP drilled the S-42A producer to replace the abandoned S-108 producer and the S-44A producer north of the S-101 injector. This year, BP undertook two big development projects. In the first quarter, the company hydraulically fractured the S-135 well. The well produced 3,587 bpd after the operation, compared to 836 bpd in the most recent test before the operation, according to the company. In the second quarter, the company drilled the S-112L1 lateral to support S-42A. The lateral failed to reach its target. BP converted the well and a portion of the lateral to injection.
BP provided no specific development program for the coming year, aside from mentioning plans to continue well work as needed and considering future drilling targets.
Borealis production fell during the year, although the rate of decline slowed from 2015.
The field produced 8,517 barrels of oil per day during the 2015-16 cycle, down from 8,768 bpd during the 2014-15 cycle and 9,932 bpd during the 2013-14 cycle, according to the company. The 2.8 percent decline in oil production between this year and last was far less than the 11.7 percent decline between last year and the year before.
Borealis is developed from three pads - L, V and Z.
BP focused its development work on L pad and Z pad this year. The company hydraulically fractured the L-123 injector and L-124 producer in late 2015 and early 2016. The L-123 well was returned to injection. The L-24 well produced an initial rate of 1,758 bpd after the operation, and “stabilized at a lower rate that was well in excess” of a rate of 83 bpd recorded before the operation. The company also brought the Z-114 injector into operation in early 2016 and repaired the Z-504A and Z504B wells.
BP suspended production and injection at V pad in June 2016 “due to piping over stress findings from an engineering study.” The company launched the study after noticing subsidence at the pad. While BP is currently modifying the piping and support system, and told the state it is expecting to resume operations by the end of the year, any activities undertaken in the coming months would only be a short-term solution combined with ongoing monitoring. The company expects a long-term solution to take until early 2018.
Aside from mentioning vague plans for well work and new drilling as needed, BP provided no details for drilling and maintenance work at Borealis for the coming year.
Midnight Sun production rose over the year.
The field produced 1,134 barrels of oil per day during the 2015-16 cycle, up from 964 bpd during the 2014-15 cycle and 1,106 bpd during the 2013-14 cycle.
The only major activity at the field this year was repairs to the offline P1-122i injection well drilled in early 2015. The work restored the well to injection. The company said it was not planning any additional drilling work at Midnight Sun over the coming year.
Orion production rose during the year.
The field produced 4,747 barrels of oil per day during the 2015-16 cycle, up from 4,693 bpd in the 2014-15 cycle and down from 5,483 bpd in the 2013-s14 cycle.
While the company did not drill at the field over the past year, it conducted considerable maintenance activities, such as changing the waterflood regulation valves of 15 injection wells. The field also produces from V pad and experienced down time similar to Borealis.
Aside from mentioning vague plans for well work and new drilling as needed, BP provided no details for drilling and maintenance activities at Orion for the coming year.
In addition to I pad, BP is looking for ways to reduce downtime at viscous wells in the northwest portion of the field, near the proposed I pad. Over the past year, the company considered sidetracking the L-200 and L-205 producers. “In their current states, both wells have little to no remaining value. A plan to re-drill both multi-lateral producers as vertical wells with frac-pack completions is being evaluated,” the company wrote. A similar evaluation is underway at the Borealis field, which lies beneath the Orion field.
Polaris production rose during the year.
The field produced 4,306 barrels of oil per day during the 2015-16 cycle, up from 3,890 bpd during the 2014-15 cycle and 4,080 bpd during the 2013-14 cycle.
As with Orion, BP did not drill at Polaris over the past year but performed considerable maintenance work such as changing waterflood regulation valves on eight injection wells.
The company listed no specific drilling plans for the coming year.
