BP plans more Prudhoe drilling in IPA
Latest plan for initial participating areas of field covers July 2019-June 2020, discusses increased well work, coil tubing drilling
Prudhoe Bay operator BP Exploration Alaska has submitted an annual progress report for the initial participating areas of the field covering the 2018 calendar year and its plan of development for work from July 1, 2019, through June 30, 2020.
The company said the initial participating area of the field, the IPA, is entering its 42nd year online and is 31 years beyond its production plateau. For the Prudhoe Bay owners the “key priority is on efficient production of the existing wells and facilities,” BP said. There are more than 1,400 wells at the field, and it is well developed, but BP said there is still an important role for development drilling which “will continue at a pace consistent with the business environment and the ability to identify viable targets informed by ongoing surveillance, supplemented by new seismic data being acquired in the first half of 2019.”
BP described that new seismic as “high density broadband seismic” which will cover the majority of the Greater Prudhoe Bay area and will be combined with the North Prudhoe seismic acquired in 2015 to “provide a single continuous seismic image” across the unit, allowing for more efficient drilling. The company said this technology “enables denser and larger datasets to be acquired when compared to legacy methods.”
ProductionCrude oil and condensate production is forecast to average 150,000 to 187,000 bpd from the IPA in 2019, down from 186,800 bpd in 2017, with natural gas liquids for 2019 expected to be between 30,000 and 46,000 bpd. (These volumes are not the same as reported Prudhoe production as they do not include the Prudhoe satellites and a portion of production from Point McIntyre.)
In 2018, average production rates for crude oil and condensate within the IPA were 174,200 barrels per day and that rate, combined with satellite production and a portion of the Point McIntyre field addressed in separate annual reports, “fully utilized available PBU processing capacity within reservoir management constraints,” the company said.
Gas production in the IPA was 2,473 billion cubic feet, production “which continues to be governed by facility handling constraints.” Re-injection was 89.3 percent of produced gas, 2,298 bcf. Natural gas liquids produced from gas totaled some 14.8 million barrels delivered to the trans-Alaska oil pipeline and 1 million barrels taken to the Kuparuk River unit.
The IPA also produced 893,000 bpd of water, for a field-wide average water cut of 84 percent, the company said.
An average of 808,000 bpd of produced water was injected at the field, with 77,000 bpd of produced water exported for injection at satellite fields.
BP said waterflood and water alternating gas operations continued throughout the reporting period, including the gas cap water injection project.
Miscible gas injection also continued, with available MI (miscible injectant) allocated based on MI efficiency, the barrels of oil recovered per unit of MI.
2019 well activityBP said 2019 production “will largely be driven through continuing improvements in operating efficiency, optimizing base production and wellwork.”
Some 400 rate adding jobs and some 550 non-rate adding jobs are planned, with IPA rotary penetrations expected to be about the same as in 2018, between five and seven.
Coil penetrations, however, will be increased from 10 in 2018 to 15-23 in 2019, with rig workovers expected to increase from two in 2018 to from two to eight in 2019.
BP said wellwork activity “remained at a high level in 2018 with 360 rate adding jobs done and about 900 total jobs performed.”
In 2018 a coil and rotary rig operated for a total of one year, drilling 15 wells. There was a pause in drilling midyear allowing BP to pursue cost and efficiency gains and evaluate future targets for drilling. “The coil and rotary rigs were brought back in service in December,” BP said, with future drilling opportunities to “be identified by ongoing surveillance and utilizing the new seismic being acquired and processed in 2019-2020.”
Flow Station 2 was a focus, with eight wells drilled.
TechnologyOne project for 2019 is controls obsolescence management, with the objective of addressing aging control system “by installing vendor supported systems,” improving lifecycle cost and minimizing the impact on production during implementation.
BP said FS3 EMC was replaced by Control Logix in 2018 and Emerson Technologies was identified as a strategic supplier.
“The 2019 plan includes developing technology solutions and an implementation plan for remaining facilities.”
Pilot testing will continue in 2019 on the Operator Workbench, a mobile device for field workers allowing them to collect and input data without returning to a computer station.
BP said it is also expanding use of unmanned aerial vehicles for monitoring.
Major gas salesBP said that as Prudhoe Bay unit operator it has executed a confidentiality agreement with the Alaska Gasline Development Corp. to allow disclosure of information for the Alaska LNG project. “To date, the PBU operator has not received formal requests for information from AGDC, FERC, or any other agency, any other unit operator, or any third party regarding the AGDC-led AKLNG project,” but said it anticipates responding to requests as they arise.
“In 2018, the unit operator, working with AGDC, presented PBU geoscience and engineering data including prospective gas sales forecasts to a prospective buyer,” BP said.
The company listed activities which Prudhoe Bay unit owners anticipate would be needed to ensure alignment with an AGDC-led project, should AGDC decide to proceed with AKLNG:
*The tie-ins at the PBU Central Gas Facility to connect with AKLNG Gas Treatment Plant feed gas line, value manifold module and custody transfer metering module at the CGF pad would need to be identified and designed and installation coordinated with AGDC.
*In the event of short-term outages of the trans-Alaska pipeline, facilities would need to be identified, designed and coordinated to mitigate the impact on gas delivery.
*CGF low temperature separators would need to be identified, designed and modified to meet GTP inlet gas specifications.
*For byproduct injection, BP said the PBU owners will need to identify, design and coordinate installation of high-pressure pipelines to various pads and will also need to drill wells for byproduct injection.
*GTP byproduct flare will be needed for unplanned emergency depressurization to mitigate CO2 related hazards.
*For shared infrastructure it will be necessary to identify potential sharing arrangements for fuel gas, power and propane for GTP construction.
*Operating and maintenance plans will need to be developed for wells and facilities to produce and deliver gas at requisite availability on annual average basis.
*Maintenance programs will need to be developed for existing facilities to maintain facilities integrity and to sustain reliable gas supply.