By the time The Producers went to print, Hilcorp Alaska LLC had yet to close on its acquisition of four North Slope properties operated by BP Exploration (Alaska) Inc.
Assuming the sale goes through, the privately held Texas-based independent would become the operator and majority working interest owner of the Endicott and Northstar fields, the operator and 50 percent working interest owner of the Milne Point unit.
The deal would also make Hilcorp a 50 percent working interest owner of the offshore Liberty field. Liberty is undeveloped and the companies are preparing a new plan.
The deal would also make Hilcorp a major transportation company on the North Slope.
In June 2014, the local BP pipeline subsidiary asked the Regulatory Commission of Alaska for permission to transfer all or some of its interest in the Northstar Oil Pipeline, the Northstar Gas Pipeline, the Milne Point Oil Pipeline, the Milne Point Natural Gas Liquids Pipeline and the Endicott Pipeline to the Hilcorp subsidiary Harvest Alaska LLC.
The current development plans for Milne Point, Endicott and Northstar reflect BP’s visions for the fields. After Hilcorp acquired the Cook Inlet assets of Marathon Oil Co. and Union Oil Company of California in 2011 and 2012, the company dramatically accelerated exploration and development activities in a bid to increase production.
It’s safe to assume Hilcorp is planning a similar strategy for its pending Arctic portfolio.
The Milne Point unit
Standard Oil Company of California discovered four Milne Point horizons in the area northwest of the Prudhoe Bay unit in 1969. The unit primarily produces from the Kuparuk oil pool, but also from the heavier Sag River, Schrader Bluff and Ugnu pools.
Conoco Inc. delineated the field in 1980 and brought it online in November 1985 but suspended operations from January 1987 until April 1989 because of low oil prices.
By the time BP acquired the unit, in 1994, oil production had fallen to 17,000 barrels per day from a peak of 20,000 bpd several years earlier, according to the Alaska Oil and Gas Conservation Commission. BP built the F pad in the northern end of the unit and the K pad in the southeastern corner of the unit, which pushed production to 52,900 bpd by July 1998. But oil production has since fallen back below 20,000 bpd, according to BP.
Cumulatively, the unit produced 319 million barrels of oil through September 2014.
To improve production, BP ran three trials of its BrightWater technology at the Milne Kuparuk oil pool in recent years, but “results are inconclusive at this time,” the company said in 2013.
BP commissioned a seismic program in late 2012 covering some 90 square miles. The program was designed to collect information about the offshore and nearshore potential of the Milne Kuparuk reservoir. BP processed the survey in 2013 and began interpreting the results this year to determine what development opportunities might exist for the future.
Earlier this year, BP conducted significant drilling operations into the Milne Kuparuk, the first development program in more than five years, according to the company. Speaking to the Anchorage Chamber of Commerce in February 2014, BP Exploration (Alaska) President Janet Weiss announced plans for a seven-well coiled tubing drilling program this year.
Through May 2014, BP drilled 14 penetrations this year, according to Alaska Oil and Gas Conservation Commission records. Well names suggest BP drilled three multilateral sidetracks and corresponding service wells at F Pad and a service well at nearby L Pad.
Milne Point: Sag River
BP acquired Milne Point for the lighter oil reserves in the Kuparuk formation, but the future of the unit is with heavier oil in the Sag River, Schrader Bluff and Ugnu.
Conoco tested the Sag River formation at Milne Point as early as 1980 and BP brought the field into production in 1995. Despite occasional spikes through the years, average annual production has generally been less than 700 bpd. Sag River is deepest producing interval at Milne Point, and therefore the oil is lighter than at Schrader Bluff and Ugnu. But high gas-to-oil ratios and poor pump performance have challenged production.
“Sag River faces both technical and economic challenges. But we’ve made progress toward overcoming some of these challenges,” Weiss said in February 2014.
Prior to the sale to Hilcorp, BP had plans to undertake a 15-well program at Sag River in 2015 and 2016, according to Weiss. If the initial program is successful, Weiss said, BP could potentially drill as many as 200 wells, accessing some 200 million barrels of resources with full development.
Milne Point: Schrader Bluff
Conoco spent $130 million building four pads and drilling 22 wells at Schrader Bluff and brought the field online in March 1991 at 3,700 bpd. But oil production had fallen to 2,850 bpd by the time BP took over the unit in early 1994, according to the AOGCC.
After several years of drilling activities without a significant boost in production, BP announced a plan in 1997 to develop Schrader Bluff with seven new or expanded pads, 75 miles of new pipeline and some 300 wells. By 2001, BP decided the program was uneconomic. Instead, BP expanded conventional drilling at E pad, H pad and J pad, lifting production to 12,000 bpd by April 2002, and built S pad in the south of the unit.
Using horizontal drilling, jet pumps and waterflooding to counteract the viscous oil and sandy formation, BP pushed Schrader Bluff production to 23,922 bpd by October 2003.
In late 2011, BP ran two BrightWater treatments in the Schrader Bluff, but the “wells have not showed a noticeable increase in oil production,” the company said in 2013.
Last year, BP planned to drill four Schrader Bluff infill wells - one producer and three injectors - that the company had originally planned for 2012. But BP ultimately deferred the program until 2016 “to allow additional planning time due to concerns over reservoir pressure in existing injector wells near the planned targets and complications in defining the completion design,” the company wrote in its plan of development for 2014.
Weiss also announced a $1 billion to $2 billion program to develop some 80 million barrels of viscous oil in the Northwest Schrader area. “We are moving forward with some important trials over the next few years to ensure we have an economic project,” she said.
Weiss announced the proposed Sag River and Schrader Bluff programs before BP announced its pending sale of Milne Point to Hilcorp. If the sale goes through, the future of the two development programs would depend in part of Hilcorp’s idea for the unit.
Milne Point: Ugnu
Ugnu - a 20 billion-barrel reservoir overlying portions of the Prudhoe Bay, Kuparuk River and Milne Point fields - is an even more challenging field than Schrader Bluff.
Starting in 2007, BP launched a pilot program at S pad to test various techniques for producing heavier oil. The first, called CHOPS, or cold heavy oil production with sand, produces oil-saturated sand and heats the mixture at the surface to separate the oil from the sand. BP also began evaluating an alternate method involving horizontal wells.
Following the launch of a $100 million testing facility, BP brought a horizontal heavy oil test well into operation in April 2011. This initial well surpassed expectations, as did the first CHOPS well completed in late 2012. But BP believes it still must demonstrate the long-term viability of the program and better manage the costs of heavy oil production before Ugnu can become a regular component of the North Slope production picture.
To date, BP has drilled four test wells, two nearly vertical and two horizontal.
The initial production tests produced as much as 500 bpd, BP Exploration (Alaska) technology manager Frank Paskvan told the state Senate Resources Committee in April 2014. But a rotating metal rod used drive the underground pump rotor wore holes in the well casing, Paskvan said. “So we’re doing studies now on artificial lift and hope that will improve the run life, because these workovers and tubing replacements were very expensive and made it difficult to continue the operations of the pilot,” he said.
The Duck Island unit
Sohio Alaska Petroleum Co. discovered the offshore Endicott oil pool in 1978.
After building two compact gravel islands connected to shore by a causeway - the first offshore oil producing islands in the Arctic - BP brought Endicott online in July 1986.
Oil production peaked at some 118,000 bpd in the early 1990s.
Cumulatively, the unit produced 478 million barrels of oil through September 2014. The unit currently produces about 7,000 barrels of oil per day, according to the AOGCC.
Today, the Duck Island unit includes the Endicott oil field, the Eider and Sag River North participating areas at the northern end of the unit and the Minke tract at ADL 34633.
In 2008, BP launched a five-year renewal campaign at Endicott. The heart of the program was infrastructure upgrades from wellhead to processing facilities, Endicott Field Manager TJ Barnes told Petroleum News in early 2009. Those efforts, in part, were meant to prepare the facility for an influx of oil from the proposed Liberty field.
The plan was to use LoSal enhanced oil recovery program now and a carbon dioxide enhanced oil recovery program once gas sales began. “We’ve rebuilt our reservoir models and have developed a comprehensive depletion plan for Endicott,” Alaska Consolidated Team Resource Manager John Denis told Petroleum News in early 2009. “We’re into the fourth year of a program to stabilize and improve the reliability of our facilities and wellstock, we have brought (the safety and integrity Operations Management System) to Endicott, and we have a robust program under way to renew our facilities. With the development of new technologies like LoSal and production from the new Liberty field, we’re looking ahead to a very bright future for Endicott.”
After trademarking the technology in 2005, BP tested the LoSal technique at the Endicott field between June 2008 and early 2010. The test suggested the possibility to recover as much as 20 percent of the oil remaining in an aging reservoir such as Endicott.
The Duck Island unit is currently in a lull. BP drilled no wells or sidetracks at the unit in 2013 and performed only three workovers, all at the Endicott participating area.
Similarly, BP has no definitive drilling or workover plans at the unit through July 2015.
For a time, BP planned to use the Endicott facilities to develop the offshore Liberty field through state-of-the-art ultra-extended reaching wells, but those plans are expected to change when BP and Hilcorp announce their plans for Liberty later in the year.
The Northstar unit
Shell Western E&P Inc. discovered Northstar in 1984.
BP brought the offshore field online in November 2001 after constructing a five-acre gravel island and a subsea pipeline connecting back to shore rather than a causeway.
The state-federal Northstar unit primarily produces from the Ivishak and the Shublik formations, but BP has recently been developing the Fido and Kuparuk reservoirs.
Cumulatively, the unit produced 161.6 million barrels of oil through September 2014 and production has been in the range of 8,000 to nearly 11,000 barrels per day this year.
The current development program involves injecting gas into the Ivishak formation to improve reservoir pressure for enhanced oil recovery, and BP said it might convert one or more production wells at the unit into injection wells to aid with that ongoing effort.
Currently, Northstar uses some imported gas from the Prudhoe Bay unit for fuel and for injection. But BP said that it has been testing the possibility of using Northstar gas as a fuel source, which could mean reducing or eliminating Prudhoe imports in the future.
Earlier this year, BP and its minority partner Murphy Exploration (Alaska) Inc. asked state and federal regulators to expand Northstar to include some 454.62 acres from two state of Alaska leases - ADL 312798 and ADL 312808 along the southern border.
The addition would expand Northstar to include their desired boundaries for a proposed Hooligan participating area, which would cover the Kuparuk reservoir at the unit.
BP requested the Hooligan participating area in late June 2012 and provided additional information to regulators in February and April 2013. The U.S. Bureau of Safety and Environmental Enforcement approved the participating area in February 2014. The Alaska Department of Natural Resource had yet to rule on the request by September.
With the expansion, the Northstar unit would cover a total of 20,134.70 acres.
The Alaska Department of Natural Resources is taking comments through Sept. 22.
When state and federal regulators approved the Northstar unit in January 1990 and the Northstar participating area in October 2001, the agreement included a provision requiring any acreage outside the participating area to contract after 10 years.
By forming the Fido participating area around federal lease OCS-Y-0181, BP was able to reduce the extent of the contraction in the northeast of the unit. But regulators contracted portions of ADL 312798, ADL 312808 and ADL 312809 along the southern border.
Around November 2010, BP plugged the NS-08 well above the Ivishak to produce from the shallower Kuparuk formation on a tract basis. Using that well and information from other Ivishak wells at the unit, all of which have passed through the Kuparuk, BP mapped out the Hooligan field. The proposed Hooligan participating area would cover the Kuparuk formation at Northstar. Except for the expansion acreage, the reservoir exists entirely within the existing aerial boundaries of the Northstar unit and participating area.
With approval of the Hooligan participating area, BP said it would continue to test the Kuparuk formation at Northstar through its current development plan, into 2015.
