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BP submits POD for Greater Point McIntyre GPM area part of the Prudhoe Bay unit; majority of crude production comes from participating areas at Lisburne and Point McIntyre
Kristen Nelson Petroleum News
On June 26 BP Exploration (Alaska) filed its last North Slope plan of development as it prepared to close on the sale of its Alaska assets to Hilcorp.
The POD, submitted to the Alaska Division of Oil and Gas, is for the Greater Point McIntyre area, covering the Lisburne, Niakuk, Point McIntyre, Raven, North Prudhoe Bay and West Beach participating areas in the Greater Point McIntyre area of the Prudhoe Bay unit.
Due to COVID-19 and the drop in oil price, “BPXA is releveling PBU activity for the remainder of 2020,” the company said, with activity plans uncertain for the POD year Oct. 1 through Sept. 30, 2021.
Lisburne and Point McIntyre are the participating areas at Greater Point McIntyre accounting for the most production, a combined 25,600 barrels per day, out of 27,940 barrels per day, with small amounts of production coming from the Niakuk PA and the Raven PA. The North Prudhoe Bay and West Beach PAs are not currently in production.
Lisburne PA For the reporting period April 1, 2019, to March 31, 2020, crude, condensate and natural gas liquid rates for the Lisburne field averaged 11,800 barrels per day, with 4.3 million barrels of Lisburne oil and NGL delivered to the trans-Alaska pipeline during that period, the company said.
Gas production totaled 81.3 billion cubic feet for the reporting period, with 59.8 bcf re-injected into the Lisburne gas cap for pressure support and 6.4 bcf consumed as fuel or flare gas.
Per day, Lisburne gas production averaged 222.3 million cubic feet for the reporting period. BP said Lisburne NGL separation averaged 1,810 bpd with a total of 0.66 million barrels shipped through TAPS with crude oil.
Water production for the period was 5.2 million barrels for an average production rate of 14,200 bpd and average water cut of 55%.
BP said produced water from the Lisburne Production Center which is not used for water injection in the Point McIntyre reservoir is injected into two Cretaceous interval disposal wells, with water injection totaling 6 million barrels, for an average water disposal injection rate of 16,730 bpd. Seawater injection into the Lisburne gas cap continues as a supplement to the benefits of as injection for oil recovery. Lisburne gas cap water injection began in 2008 with a pilot, and during the 2016-17 reporting period that pilot was approved by the Alaska Oil and Gas Conservation Commission for permanent injection.
Issues with downtime at the injection well were resolved in the prior injection period, with sustained injection reestablished in June 2019 and 2.48 million barrels of seawater injected during the reporting period.
Peripheral Lisburne Wahoo seawater injection began in 2012, with 916,000 barrels injected during the reporting period. Seawater injection began mid-field in 2013, with 1.2 million barrels of seawater injected in the reporting period.
Seawater injection began in the Lisburne Alapah in 2013, with 1.954 million barrels injected during the reporting period.
Three new wells (L3-06, L5-03 and L5-27) and one new sidetrack (L3-22A) were drilled and completed into the Lisburne formation during the reporting period, with drilling on an additional new well, L5-07, 80% complete. Lisburne producer L1-31 was worked over and new tubing run during the reporting period.
There were 55 rate-adding non-rig interventions on 21 Lisburne wells during the reporting period, including perforations, hydrate and paraffin removal, hot oil treatment jobs, acid stimulations, gas-lift work, profile modifications, fill cleanouts, well integrity repairs, subsurface safety valve replacements and surface component repairs.
BP said the Lisburne Production Center continues to be gas constrained, with oil production rates influenced by seasonal ambient temperature cycles and corresponding compressor efficiencies.
The area was covered by the 2014-15 North Prudhoe seismic survey.
BP noted that due to COVID-19 and the drop in oil price, activity plans for the Oct. 1 through Sept. 30, 2021, plan year are uncertain, but in discussing the Lisburne PA said current plans include the L5-07 rotary well, which was begun in the previous plan period.
Four additional rotary and two coil tubing opportunities “have been matured” for possible future drilling “contingent on the continued performance of the wells drilled during the 2015-2019 period, the results of the current planned wells, and the business environment. Additional rate-adding non-rig interventions are planned.”
Niakuk PA Niakuk crude, condensate and NGL rates averaged 900 bpd for April 1, 2019, through March 31, 2020. BP said that production rate, combined with production from other Greater Point McIntyre area fields, fully utilized the available capacity at the Lisburne Production Center.
Delivery to the trans-Alaska pipeline was 0.324 million barrels for the plan year.
Gas production at Niakuk totaled 0.4 bcf for the reporting period, none of which reinjected into the Niakuk reservoir. BP said the produced gas is processed at the LPC and injected into the Lisburne and Point McIntyre reservoirs. The total of produced gas consumed as fuel or flared was 31 million cubic feet, with NGL separation averaging 19.16 bpd for a total of 7,000 barrels delivered and shipped with crude oil during the reporting period.
Water production was 4 million barrels for the reporting year, averaging 11,000 bpd. The produced water is processed at the LPC and injected into the Point McIntyre reservoir.
BP said Niakuk activity focused on optimization of producers and scale management during the reporting period, with nine rate-adding non-rig interventions at six Niakuk wells.
The North Prudhoe seismic survey is being used for “a better understanding of subsurface areas of interest” at Niakuk and further analysis of compartmentalization at the field is underway, the company said.
North Prudhoe Bay PA Production from North Prudhoe Bay PA occurred from a single well completed in 1993 at West Beach pad, BP said, with the well shut-in in early 2000 due to safety concerns “arising from continued proppant production from an earlier fracture stimulation of the Sag River Formation.” While attempts were made to eliminate flowback of proppant, BP said production testing was suspended due to safety and environmental considerations and production is currently shut-in due to integrity concerns.
Total crude and condensate production to date is 2.1 million barrels.
BP said it has reviewed the condition and history of the WB-03, the single West Beach well, “and concludes that the well is not currently in condition to bring on line and flow.” Options for restoring the well are under evaluation, the company said, noting there are challenges in development of the Ivishak and Sag River intervals “due to structural complexity, reservoir compartmentalization, and fluid contact uncertainty.”
The surface kit at the West Beach pad has been evaluated and surface repairs identified, BP said, with additional engineering work planned.
Point McIntyre PA BP said crude, condensate and NGL rates at the Point McIntyre PA averaged 13,800 bpd in the April 1, 2019, through March 31, 2020, period, with a total of 5.04 million barrels delivered to the trans-Alaska pipeline. “Field offtake was managed to maximize production within the available pipeline and facility constraints, while maintaining close to full voidage replacement,” BP said.
All Point McIntyre production until October 2016 went to the LPC; completion of the STP-36 Project in October 2016 enabled PM-2 production to go to Gathering Center 1 for the entire plan year again.
Gas production from Point McIntyre totaled 53 bcf for the reporting period, with produced gas from the LPC injected into the Point McIntyre gas cap for pressure support and to “promote recovery in the up-structure area.” Injection into the Point McIntyre gas cap/gravity drainage area totaled 33.5 bcf during the reporting period. Lean gas from the LPC supplied for reinjection is a mixture of gas from Point McIntyre, Lisburne and Niakuk.
Point McIntyre gas consumed as fuel or flared totaled 2.5 bcf during the reporting period.
NGL separation averaged 1,010 bpd; a total of 371,000 barrels was delivered to the trans-Alaska oil pipeline during the period.
Produced water for the period was 40 million barrels, an average of 109,200 bpd.
Raven PA BP said Raven PA production, combined with production from other Greater Point McIntyre area fields, fully utilized Lisburne Production Center capacity “within reservoir management constraints.”
Raven crude, condensate and NGL rates averaged 1,440 bpd for the April 1, 2019, to March 31, 2020, period, with a total of 530,000 barrels from the Raven PA delivered to the trans-Alaska oil pipeline during the period.
Raven gas production totaled 1.78 bcf during the period; the gas is processed at the LPC and injected into the Lisburne and Point McIntyre fields. Gas consumed as fuel or flared totaled 143 million cubic feet; NGL separation averaged 77.1 bpd with a total of 28,200 barrels delivered to the trans-Alaska oil pipeline. Raven water production totaled 680,000 barrels, with an average water production rate of 1,900 bpd. Raven produced water is processed at the LPC and injected into the Point McIntyre field.
Technical evaluations of Raven drilling options use the 2014-2015 North Prudhoe seismic survey, completed in April 2015.
West Beach PA West Beach startup was in April 1993, BP said, with 11 penetrations - seven wells and four sidetracks. Total field production has been 3.37 million barrels of crude oil, with some 92% from the original WB-04 well.
“Oil production was suspended in 2Q 2001 due to increasing GOR and declining reservoir pressure,” the company said.
Water injection at WB-06 began in late 2000 and continued through the fall of 2003, with an annular communication leak caused the injection to be shut-in.
The company described work on the WB-06, WB-05B in the early 2000s, with low rates of production, which BP said, combined with cool well head temperatures, might cause the 12-inch production line to “become inoperative due to hydrates.”
The 6-inch test line between West Beach pad and LPC No. 1 pad had an external inspection in 2010 which found no evidence of structural problems.
BP: said the West Beach pad surface kit has been evaluated and repairs identified; engineering work will continue.
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