|
State approves new POD for Prudhoe Bay
Operator BP summarizes work accomplished under 2017 plan, lays out what owners plan for 2018 for initial operating areas of unit
Kristen Nelson Petroleum News
The Alaska Division of Oil and Gas has approved BP Exploration (Alaska)’s 2018 plan of development for the initial participating areas, the oil rim and gas cap, at the Prudhoe Bay field. In a June 13 letter of approval, division Director Chantal Walsh said the POD, dated March 29, was declared complete by the division April 1. BP had provided a technical presentation March 22, prior to submitting the POD, she said.
2017 report Reporting on 2017 activities, BP, the Prudhoe Bay operator, said crude and condensate rates averaged 186,800 barrels per day, which combined with production from satellite fields and a portion of Point McIntyre, fully utilized processing capacity at Prudhoe. The field delivered 68.19 million barrels to the trans-Alaska oil pipeline in the year ending Dec. 31, the company said.
Gas production totaled 2,549 billion cubic feet, with 2,289 billion cubic feet of dry gas reinjected, 89.8 percent of the produced gas stream, with gas production continuing to be governed by facility handling constraints. Other major uses of gas were as fuel, 5.7 percent of produced gas, and in miscible injectant production, 3.3 percent.
Natural gas liquids production averaged 42,000 bpd, with 1.53 million barrels delivered to the trans-Alaska oil pipeline.
Produced water averaged 930,000 bpd, for a field-wide average water cut of 83 percent, with 804,000 bpd of produced water injected in waterflood and water-alternating-gas operations, and 94,000 bpd of produced water exported for injection into satellite fields.
Miscible gas injection continued, with MI delivered to MI-capable drill sites based on MI efficiency - barrels of oil per unit of MI.
MI injection was expanded in 2017 to two new MI patterns at Point McIntyre.
2017 saw 386 rate-adding wellwork jobs completed and some 1,000 wellwork jobs overall, including integrity, surface repairs, capacity sustainment, rate enhancement, well diagnostics, surveillance and rig workovers.
A focus area in 2017, BP said, was “recovery of liquids from the Sag River gas cap via wellwork on uncompetitive Ivishak producers.”
“Sag River gas contains condensate that has not been swept out through update lean gas reinjection and can be recovered as liquids at surface.”
Sag River recovery is being done by plugging off uncompetitive Ivishak producers and adding perforations upscale in the Sag River gas cap. Work done in 2017 at 29 wells produced 7,000 bpd of new production, with the entire program currently producing some 12,000 bpd.
Two rigs were working at Prudhoe in 2017, with 27 wells drilled, primarily by sidetracking underperforming wells using both conventional rotary and coil tubing rigs.
“As Prudhoe Bay has matured, drilling targets continue to become smaller and more complex with increasing drilling and reservoir risk,” BP said.
2017 facility, reservoir optimization During the 2017 Gathering Center 1 facility maintenance turnaround corroded carbon steel piping in wet gas service was replaced with stainless steel pipeline, mist eliminators and inlet devices were upgraded, along with heat exchanger bundles.
In-line inspections were performed on some 83 miles of lines: three produced oil pipelines, eight three-phase cross-country pipelines, 10 produced water injection pipelines, one seawater injection pipeline and one gas lift transit pipeline.
Stock tank vapor and intermediate pressure turbine-driven gas compressors were replaced at all three flow stations with electric motor driven compressors. BP said this project was fully sanctioned in 2012, the compressor replacement at Flow Station 1 was completed in 2014; the compressor installation at FS-3 was completed and startup was in December 2016; FS-2 compressor installation began in January 2017 with startup in February 2018.
41st year The IPA is in its 41st year, 30 years beyond plateau production at the field, and “the PBU owners’ key priority is on efficient production of the existing wells and plant,” BP said. The field, with 1,423 wells, is well developed and large-scale drilling programs - more than 50 new wells in a year - “have largely been replaced by operations efficiency increases, hundreds of wellwork jobs each year to maintain and enhance existing wellstock … and reservoir management techniques as the key drivers.”
BP said emphasis on increasing production efficiency “resulted in only minor decline in the IPA’s 2017 production rate when normalized for the GC-1 TAR.”
Reservoir management In the gravity drainage area, emphasis will be on operation, maintenance and repair of existing wells, and on sidetracks, as well as oil vaporization by lean gas injection.
BP said that drilling and well work in the gravity drainage area is “increasingly challenged by continued gas cap expansion resulting in thinner oil columns, and water encroachment from gas cap water injection.”
In the east waterflood/enhanced oil recovery area, focus is on optimizing water and MI injection, identifying potential new penetrations, pattern reconfiguration and wellwork.
In this area, seven wells are planned at Flow Station 2 for 2018 with additional wells planned for the future.
In the west waterflood EOR area, focus is on optimizing production and enhancing recovering by replacing voidage and maintaining reservoir pressure. One rig workover is planned for 2018 to allow a currently inoperable injector, X-11A, to restart injection.
Updip Zone 4 project targets remaining oil where the gas cap has expanded into Zone 4 to improve recovery of isolated oil lenses.
BP said recovery of liquids from the Sag River gas cap from uncompetitive Ivishak producers will continue, with some 10 wellwork jobs expected, but no wells targeting Sag River expected in 2018.
At the Eileen west end/northwest Eileen areas, the objective is to optimize production under constraints of gas lift supply and the total gas oil ratio of the EWE large diameter flow line. While additional drilling opportunities are being evaluated in this area, they are challenged by the current economic environment and complex geology and gas and gas influx.
Production, well forecasts Production decreased from 197,900 bpd in 2016 to 186,800 bpd in 2017, due to natural decline and the GC-1 facility turnaround, partially offset by increased operations efficiency and high wellwork activity.
The average annual IPA crude and condensate production rate is expected to be between 150,000 and 187,000 bpd in 2018, with total NGL production between 30,000 and 46,000 bpd, BP said.
BP said it expects to do some 400 wellwork rate-adding jobs, and some 700 non-rate adding jobs, “as well as an active, fieldwide reservoir surveillance program driving these activities.”
Rotary penetrations will remain about the same as in 2017, about five, with coil penetrations reduced from 22 in 2017 to some nine in 2018. Rig workovers are expected to increase from one to one to three in 2018.
2018 projects planned A controls reliability and renewal project is aimed to reduce a backlog of aging control systems, “install control systems with a broader base for support, and improve lifecycle cost, while minimizing the impact on production during implementation,” BP said, with activities planned at FS-3 this year, with FS-1 and GC-2 to follow in 2018-19.
At the seawater treatment plan, BP said the long-term plan is to maximize field recovery. Seawater is used in various areas of the IPA for pressure support and in other areas is injected to support production through waterflood and EOR operations.
Upgrades and maintenance are underway to improve the dew point of dehydrated gas from flow stations and gathering centers, BP said, improving the reliability of the central gas facility.
“Invention and application of new technology has underpinned the IPA’s outstanding production record and will continue in the future,” BP said, with pilot testing of the Operator Workbench in this plan period, a mobile device allowing field workers to collect and input data without returning to a computer station.
A field-wide 3-D seismic survey is being evaluated, using the same technology used in the North Prudhoe survey in 2014.
And installation is planned for more wireless monitoring of pressure and temperature at wells.
Major gas sales BP said it has provided a draft confidentiality agreement to the Alaska Gasline Development Corp. to allow disclosure of information to AGDC for the Alaska LNG project, but said that as of the date of filing its POD it had not received requests for information from AGDC, the Federal Energy Regulatory Commission, any other agency, any other unit operator or any third party regarding the AKLNG project.
BP said that during 2018-19 the Prudhoe owners anticipate appropriate planning and activities to position for a major gas sale “consistent with AGDC progress on the AKLNG project and based on prior work done by the PBU operator to prepare for a MGS. Depending upon AKLNG project milestones and activity, the timing and scope of MGS-related activity may need to be adjusted, and if plans do not occur as scheduled during the 2018-19 time period, then the PBU operator would not anticipate including similar information on MGS activities in the 2019 POD submission.”
BP listed long-range MGS activities that would be needed to support sales gas delivery, byproduct injection, shared infrastructure and field facility maintenance and said the Prudhoe owners “will continue to maximize the opportunity for improved recovery by way of injection of indigenous lean gas and MI into Prudhoe Bay reservoirs.”
Indigenous gas is a proven method to support production and improve ultimate recovery with indigenous gas injection contributing approximately 40 percent of PBU production, BP said, and reinjection of processed gas will continue. The Prudhoe owners will also be preparing for potential commercial discussions with the Point Thomson unit owners for potential delivery of gas from that field for injection into the Prudhoe reservoir and will evaluate a range of potential impacts on the Prudhoe reservoirs and on the operation of the unit.
|
