Alaska North Slope crude output up slightly

Alpine hits new daily production record with completion of ACX2 facility expansion, allowing production up to 140,000 bpd

Kristen Nelson

Petroleum News Editor-in-Chief

Alaska North Slope crude oil production averaged 892,192 barrels per day in November, up 0.9 percent from an October average of 884,080 bpd, including a new daily production record at Alpine on the western side of the slope.

BP Exploration (Alaska)’s Milne Point field had the largest percentage month-to-month increase, up 3.78 percent to average 42,748 bpd in November, compared to 41,191 bpd in October. That level of production was a 9.8 percent decline from September, when the field averaged 45,653 bpd. The Alaska Department of Revenue said Milne had gas compressor problems Oct. 22-23. On Nov. 5 the field was shut down due to generator failure, dropping production to 13,004 barrels; the field returned to production levels in the plus-40,000 bpd range Nov. 9, and hit a one-day high for the month of 46,214 barrels Nov. 18.

BP-operated Endicott averaged 21,673 bpd in November, up 3.4 percent from an October average of 20,970 bpd. Endicott production includes Sag Delta, Eider and Badami.

Alpine hits 136,141 bpd Nov. 19

ConocoPhillips Alaska (78 percent) partners with Anadarko Petroleum (22 percent) at Alpine. Initially projected to produce 70,000 bpd, further study of the reservoir and the decision to go with horizontal wells, waterflood and enhanced oil recovery changed the initial capacity to 80,000 bpd, John Whitehead, ConocoPhillips Alaska’s vice president for the western North Slope, told Petroleum News in a June 2004 interview. But as more wells were drilled, he said, “they recognized that they had well capacity to go above the 80,000 barrels a day.”

Operations, engineering and drilling cooperated in tweaking the original Alpine facilities, a range of activities from learning how to operate at a little higher rate to things like installing a little bigger valve, Whitehead said. For the reservoir engineers, he said, it was a matter of working on “how do we manage this reservoir correctly at a higher level.”

From 2001 to 2002, de-bottlenecking increased Alpine production to 100,000 to 105,000 bpd.

And there was a “junior” capacity expansion project in the summer of 2002, upgrading transfer pumps at Kuparuk where Alpine buys seawater for injection, allowing the shipment of some 10,000 additional bpd of water to Alpine for fluid replacement in the reservoir.

The first major expansion project, ACX1, was approved in 2003. That project increased produced water handling capacity from 10,000 bpd to 100,000 bpd Whitehead said, and also allowed an increased production of about 5,000 bpd of oil.

ACX2, like ACX1 about a $60 million project, was also begun in 2004 and completed in 2005. ACX2, Whitehead said, is designed to increase Alpine capacity to 140,000 bpd. Seawater injection capacity was increased to more than 130,000 bpd to compensate for increased oil production. ACX2 also includes a small increase in gas handling capacity, Whitehead said, from 160 million cubic feet a day to about 180 million.

Mark Ireland, ConocoPhillips Alaska’s Western North Slope development manager, told Petroleum News this August that work on ACX2 was completed in June during a maintenance shutdown with installation of the final cooling equipment. When the field came back up, production rates began to rise, he said.

Ireland said work also began over the summer for ACX3, a condensate stabilizer which provides a cleaner break between the oil and gas leaving the facility, providing more hydrocarbon components to aid in enhanced oil recovery. ACX3, Ireland said, is geared to long-term production increases through enhanced oil recovery, rather than to immediate production increases.

Prudhoe production up

BP-operated Lisburne (including Point McIntyre and Niakuk) averaged 40,799 bpd in November, down 0.4 percent from an October average of 40,953 bpd.

The ConocoPhillips-operated Kuparuk River field (which includes production from West Sak, Tabasco, Tarn, Meltwater and Palm) averaged 171,998 bpd in November, down 1.2 percent from an October average of 174,014 bpd.

BP-operated Northstar had the steepest month-to-month decline, averaging 59,984 bpd in November, down 2.3 percent from an October average of 61,402 bpd. Revenue said there was a plant shutdown at Northstar Nov. 17 due to a power outage, with reports of problems restarting a compressor. Production at the field dipped to 41,566 bpd Nov. 17, but got back above the 60,000-bpd level by Nov. 21 and remained above 62,000-bpd for the last nine days of the month.

The North Slope temperature at Pump Station No. 1 averaged minus 9.6 degrees Fahrenheit for November, down from a 21.7 degree average in October. Revenue said the three-year average temperature for November is 5.6 degrees F.

Cook Inlet production averaged 18,790 bpd in November, down 4.6 percent from an October average of 19.691 bpd.