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BP reports rise in oil output at Prudhoe Bay satellite fields
Kay Cashman Petroleum News
BP Exploration (Alaska) Inc. says oil production at its Prudhoe Bay satellites has increased overall but is down in two of the five fields.
In a recent annual progress report and plan of development update for the satellites that was submitted to the state Division of Oil and Gas, the Prudhoe Bay operator reported increased oil production at the Aurora, Midnight Sun and Orion fields and a drop in output from Borealis and Polaris. In the previous year a drop in output only occurred at Aurora.
BP files three plans of development each year for the Prudhoe Bay unit - one for the initial participating area early in the year, one for the Greater Point McIntyre area in the middle of the year and one for the satellites in the fourth quarter.
The plan of development, or POD, update in BP’s Sept. 30 filing was for 2020, while the annual progress portion of the document was for July 1, 2018 through June 30.
Annual progress at Aurora Mobil Oil discovered the Aurora oil pool in the northwest corner of the Prudhoe Bay field in 1969, while delineating Prudhoe Bay.
The average oil production rate for the Aurora field for the annual reporting period ending June 30 was 5,291 barrels per day. In the previous year Aurora produced an average of 4,609 bpd, which was slightly down from 4,696 bpd the year before that.
Development of the Aurora reservoir has focused on phased drilling of production and injection wells from S pad. Production is commingled with other Prudhoe Bay production on S pad and processed at Gathering Center 2, or GC-2.
Water injection was started at Aurora in December 2001.
Tertiary recovery, utilizing Prudhoe Bay miscible gas for water-alternating-gas injection, or WAG, was started in December 2003. All injectors at Aurora were designated as WAG injectors at the end of the latest reporting period.
Tertiary recovery is also known as enhanced oil recovery and is the third phase of oil extraction from an oil reservoir. It allows a field operator to remove a significant amount of oil from a reservoir which they normally would not be able to access.
With field startup in November 2000 and an estimated 200 million barrels of oil in place at Aurora, cumulative production reached 45.1 million barrels by June 30 of this year. At that time there were 35 active wells at S pad − 20 oil producers and 15 injectors.
In 2019, BP conducted 66 wellwork jobs on producers and injectors to minimize oil rate decline, including “tree change outs, gas lift optimization, hot oil treatments, SSV/SSSV work, and VSM repairs,” which are common in most of BP’s workovers.
Of the 66 well work jobs, 20 were rate adding with the remainder maintenance and rate sustainment.
Among other things, the company also side-tracked well S-105A and put it online in second quarter, put a concentric liner in S-109 and hydraulically fractured it, attempted a fill cleanout in S-26 (coil tubing got stuck, fish left in the well), and added perforations in S-113BL1 and S-129.
The most recent new well prior to 2019 was S-200A, a producer spud in October 2017.
Aurora 2020 POD BP made no firm drilling commitments at the Aurora field for next year but said it expected to continue its existing workover regimen. The company is evaluating potential infill drilling targets identified from its geological models, including recent well results.
BP’s Aurora reservoir management strategy is to utilize injection-to-withdrawal, or I/W, ratios at a pattern level that maintains reservoir pressure above minimum miscibility pressure for the miscible flood process, which is accomplished by “setting optimum injection rates, additional drilling, workovers of existing wells, and cycling high gas-to-oil-ratio production wells as needed.”
Annual progress at Borealis Mobil Oil discovered the Borealis oil pool along the western edge of the Prudhoe Bay field in 1969 while delineating Prudhoe.
BP brought the field online in 2001 from L pad, and expanded development to include V pad in April 2002 and Z pad in March 2004.
The average oil production rate for the Borealis field for the reporting period was 5,905 bpd. In the previous year the field had produced an average of 7,914 bpd, which was up considerably from the 6,040 bpd for the year before that.
With an estimated 350 million barrels of oil in place at Borealis, cumulatively the field has produced 88.2 million barrels through the end of June, and there are 24 active wells at L pad (15 oil producers and 9 injectors), 20 active wells at V pad (12 oil producers and 8 injectors) and 8 active wells at Z pad (4 oil producers and 4 injectors).
Development of the Borealis reservoir has focused on phased drilling of production and injection wells from L, V, and Z pads. Production is commingled with initial producing area, or IPA, and Orion production on L and V pads, IPA production at Z pad and processed at GC-2.
Water injection was started at Borealis in June 2002.
Tertiary recovery, utilizing Prudhoe Bay miscible injectant for water-alternating-gas injection, was started in June 2004 as a pilot and fieldwide miscible gas injection began in mid-2005.
BP conducted 70 wellwork jobs on producers and injectors during the reporting period that ended June 30.
Of the70, 21 were rate adding with the balance being maintenance and rate sustaining.
Significant activities at Borealis included drilling L-118L1, with first production from it in third quarter 2018, Z-113 getting a fill cleanout and profile modification in October 2018, L-119 getting an OA down squeeze in November 2018, perforations added in March of this year to L-118L1, and MI injected into nine water-alternating-gas injectors.
Borealis 2020 POD As with Aurora, BP made no firm drilling commitments for the Borealis field for the coming year but said it expected to continue its existing workover regimen. The company is evaluating potential infill drilling targets identified from its geological models, including recent well results.
The Borealis reservoir management strategy is to utilize injection-to-withdrawal ratios at a pattern level to maintain the reservoir pressure above minimum miscibility pressure for the miscible flood process. This is accomplished by setting optimum injection rates, additional drilling, workovers of existing wells, and cycling high as-to-oil-ratio production wells as needed.
Annual progress at Midnight Sun The average oil production rate for the Midnight Sun field for the reporting period was 1.394 bpd, up from the previous year of 1,158 bpd, which was up from the 983 bpd for the year before that.
With an estimated 100 million barrels of oil in place cumulatively Midnight Sun has produced 22.1 million barrels through the end of June and a total of six wells have been drilled in the field, with the most recent one drilled in early 2015.
Historically development has consisted of two producing wells (E-101 and E102), three water injection wells (E-100, E-103, E-104) and one WAG well (P1-122).
Currently five wells remain in the Midnight Sun reservoir; the E-100 injector was recently sidetracked to BP’s Sambuca field and is no longer in service of Midnight Sun.
BP discovered Midnight Sun with the Sambuca No. 1 exploration well in 1997 and began production from the Kuparuk formation in October 1998, targeting Ivishak sandstone, but tapping quantities of oil in what a Alaska Superior Court decision later described as “a geographically discrete bed of oil-bearing Kuparuk C, the Midnight Sun reservoir.”
ARCO Alaska, which named the well, said in 1998 that the Midnight Sun reservoir was one of two intervals discovered in Sambuca No. 1. The Kuparuk interval, the Midnight Sun field, tested approximately 4,000 bpd of 29 API gravity oil and 1.5 million standard cubic feet of gas per day. The shallower Sag/Ivishak interval, the Sambuca field, tested 1,400 bpd of 24 API gravity oil and 490,000 standard cubic feet of gas per day.
Water injection at the Midnight Sun field started in October 2000, MI began in 2016 and WAG in 2019.
Midnight Sun 2020 POD The reservoir management strategy at Midnight Sun has been to target a fieldwide injection-to-withdrawal ratio of 1.0 to 1.3 to maintain reservoir pressure while minimizing resaturation of oil into the gas cap.
During the period July 1, 2018 to June 30, an average voidage replacement ratio of 0.39 was achieved primarily because E-103 was off-line since May 2018. E-102 production was shut-in in May for voidage/pressure management and uncompetitive watercut as a result of no response to P1-122 MI injection.
Voidage replacement refers to replacing the volume of oil, gas and water produced from the reservoir by injected fluids. Voidage replacement ratio is the ratio of reservoir barrels of injected fluid to reservoir barrels of produced fluid.
BP’s plan for Midnight Sun is to continue reservoir surveillance in order to “evaluate waterflood/EOR performance, fluid movement, well integrity, and the opportunity for well work and redevelopment.”
BP said that as the waterflood continues to mature, sidetracking the producers within the pool to maximize oil recovery will be evaluated after the benefits from WAG injection are realized.
No additional injectors or producers are planned for 2020.
Orion oil production The average oil production rate for the Orion field for the reporting period ending June 30 was 4,955 bpd, up from the previous year of 3,900 bpd, which was up from the 3,469 bpd for the year before that.
Of the 3.2 billion barrels of oil in place at Orion, cumulatively the field has produced 35.1 million barrels through the end of June.
A total of 14 wells at L pad are active in the field as of June 30 - 5 oil producers and 9 injectors; with 20 active wells at V pad - 5 oil producers and 15 injectors.
The most recent well was drilled in November 2017, L-205A, a producer.
Annual progress at Orion Mobil Oil discovered the Orion oil pool in the northwest corner of the Prudhoe Bay unit in 1968 while delineating Prudhoe. BP confirmed the accumulation in 1998, began initial drilling in December 2001 and brought the field online in April 2002.
The company originally developed Orion from V pad and expanded development in mid-2004 to include L pad.
Development of Orion’s reservoir has included phased drilling of a total of 48 producers and injectors from L pad, V pad and Z pads and numerous additional appraisal wells, BP said in its progress report.
Orion production is commingled with initial participating area and Borealis output and flows to GC-2 for processing.
Water injection started in December 2003. The waterflood was designed to increase recovery and provide pressure support in the Orion reservoir.
Tertiary recovery utilizing Prudhoe Bay MI for WAG was initiated in October 2006.
Central and southern areas of Orion are being developed using existing and expanded infrastructure at L, V and Z pads.
As of June 30, the Orion reservoir is being produced from seven Schrader Bluff sands (Nb, OA, OBa, OBb, OBc, OBd, and OBe).
During the reporting period, MI was injected into 14 Orion wells and it was determined via production logging that the Oba lateral in L-202 had a matrix bypass event to the aquifer in January 2018. Long term options to remediate the problem are being evaluated, BP said.
In addition, matrix bypass events between V-212i and V-204 (OA and Oba sands) and V-222i and V-204 (OA sand) were confirmed via separate red dye tests and options to remediate the events are being evaluated.
Waterflood regulating valve changeouts were performed on seven injection wells, which BP said are “significant operations requiring several pieces of equipment for several days. They are performed to adjust injection profiles and/or ensure correct regulator function.”
Two production logs were also run in the Orion field. Installation of sand-face pressure gauges for each injection zone in new injectors started in January 2007. This technology has enabled identification of matrix bypass events, the company said.
The monitoring of sand-face pressure gauges is an “integral part of the base management process and has also helped identify problematic waterflood regulating valves.”
A total of 65 wellwork jobs were conducted in the one year reporting period. Of the 65, 20 were rate adding with the remainder being maintenance, surveillance, rate sustainment, and pre/post drilling.
In addition, rig workovers on L-200A and V-227 were approved during the reporting period and are scheduled to be done this year.
No wells were drilled or completed during the progress reporting period ending June 30.
Still studying, evaluating Orion As mentioned, GC-2 in the Prudhoe Bay unit was originally built to handle light, not viscous, crude.
Sand-laden viscous oil requires a substantially enhanced solids handling capability, BP said. The current volumes of viscous oil entering GC-2 have led to “operational difficulties and increased wear on plant components.”
To mitigate these problems at GC-2 in 2012 and 2013 BP upgraded its solids handling capabilities at the gathering center. An accumulator was installed, and improvements were made in sand jetting procedures and dehydrator sand jetting. The equipment was commissioned in mid-2013.
Although there was some improvement, the project did not yield the desired level of improvements, BP said.
Additional engineering work is “ongoing to evaluate design improvements to resolve certain issues with the solids handling system,” the company said.
Subsurface uncertainties have also impacted production, including the optimal design and placement of wells.
“Learnings from the ongoing modeling work and completion studies will be incorporated into any future developments in the Orion PA,” BP said in its progress report.
Additionally, BP is looking for ways to address the significant downtime affecting viscous wells in the northwest portion of the Orion field. Those wells have been down nearly half the time in recent years due to sand production, matrix bypass events and downhole equipment failures.
The company is studying alternate well designs, saying these designs or junction technology and sand control technology are a requirement.
Fixes to one such well was tested in March. BP is looking to deploy the modified equipment used in it to another existing well that can be recompleted across the Schrader to ensure the equipment works as designed.
A single sand horizontal well with an ultrafine screen completion is being evaluated to redevelop the OBd sand; however, there are drilling and completion challenges with it, so BP continues to study the situation.
One of the longest delayed projects at Orion is the proposed I pad, which the company claims is dependent “upon the results of sand control technology deployed in the Schrader Bluff formation and the business environment.”
Orion 2020 POD Because of the variability in sand and oil quality between zones at Orion, reservoir surveillance has been undertaken to develop a better understanding of the reservoir performance by zone and to design a development program to maximize recovery.
For producers, production allocation efforts focus on using geochemical fingerprinting analysis on produced oil. This technique is in use world-wide and has proven useful in the Schrader Bluff fields on the North Slope, BP said in its 2020 POD.
The complex nature of multilateral designs makes conventional production logging for zonal contribution difficult, the company noted.
For injectors, efforts include injection logging and zonal control using flow regulators. Work is ongoing to balance waterflood pattern voidage and provide proper pressure support.
No new wells were mentioned in the Orion 2020 POD, although BP said the wellwork program will be maintained - and the company will continue evaluating sidetrack options for the long term shut-in patterns at L pad.
Regarding potential new projects, BP said development plans for the remaining opportunities in the Orion field will focus on reducing risks and costs.
Polaris oil production The average oil production rate for the Polaris field for the reporting period ending June 30 was 3,969 bpd, down from the previous year of 4,158 bpd, but close to the 3,891 bpd daily average for the year before that.
Of the estimated 1 billion barrels of oil in place at Polaris, cumulatively the field has produced 24.7 million barrels through the end of June.
Four wells were active at S pad as of June 30 - 1 producer and 3 injectors. And 20 wells were active at W pad - 7 producers and 13 injectors.
The most recent well drilled in the Polaris field was W-221, an injector spud in May 2011.
Annual progress at Polaris BP discovered Polaris in 1969 while delineating the Prudhoe Bay field and brought Polaris online in 1999 from S and W pads. Development of the Polaris reservoir has involved phased drilling of a total of 28 production and injection wells from those two pads, with initial drilling starting in November 1997.
Production is commingled with IPAs and Aurora production on S pad, and with IPA production on W pad, and is then processed at GC-2.
Water injection began in May 2003.
W 215i injected MI for a short time in 2006, but the offset producer was subsequently shut-in, so the water-alternating-gas cycle was curtailed.
MI injection in Polaris resumed in November 2009.
Polaris is managed as a WAG flood, with injectors alternating between produced water and MI.
During the progress reporting period ending June 30, MI was injected into seven Polaris wells. S pad MI was down from third quarter 2018 to first quarter 2019 for planned maintenance.
No new matrix bypass events were identified during the reporting period.
Waterflood regulating valve changeouts were performed on three injection wells.
During the reporting period, two injection logs were run - installation of sand-face pressure gauges for each injection zone in new injectors started in 2007, enabling identification of matrix bypass events.
A total of 31 wellwork jobs on producers and injectors were done. Of the 31, seven were rate adding with the remainder being maintenance and rate sustainment.
Work continued with developing plans for two new WF/EOR patterns on S pad. The Northern S pad pattern is planned for a three well development (one multilateral producer (S-202) and two vertical injectors (S-201Ai and S-210i), which are planned for fourth quarter 2019.
Modeling and well planning work are currently underway for the southern S pad pattern. If proven to be viable, development of additional areas at S pad with good oil mobility would be limited to the number of donor wellbores and surface slots available that are able to reach the target without anti-collision issues, BP said.
The modeling and completions studies work at S pad will transfer to other areas in both the Orion PA and Polaris PA. “Consideration of further potential M and S pad viscous oil development is contingent upon the results of sand control technology deployed in the Schrader Bluff formation and the business environment.”
During the reporting period, work continued on evaluating technologies and potential deployment locations within the Orion PA for demonstration of sand control completions. If Schrader Bluff sand control alternatives prove successful at Orion, the potential for deployment in the Polaris PA will be evaluated, BP said.
Polaris 2020 POD Many of the projects at Polaris and planned for the immediate future, particularly those involving viscous oil and sand control, overlap with those at Orion.
The POD calls for wellwork to continue to maintain production and mitigate decline.
Development plans within Polaris are focused on reducing risks and cost.
During the 2020 POD period, BP will continue to gather data from the current wells and work will continue evaluating options for alternative completion designs and technologies that are intended to improve junction reliability and control sand production.
Regarding M and S pad development, during 2020 BP plans to continue to work on dynamic modeling to help with reservoir management and development in the Polaris field. Alternative sand control technology will be studied for future deployment in the Polaris PA.
At least one well test per month will be used to check the performance curves and to verify system performance. No NGLs are allocated to Polaris.
Editor’s note: Plans for 2020 could change if the sale of BP’s Alaska assets to Hilcorp closes and Hilcorp or one of the other major owners of the western satellites takes over as operator, including ConocoPhillips and ExxonMobil.
- Kay Cashman
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