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More sidetracks, horizontal wells at Kuparuk ConocoPhillips says multilateral, coiled tubing drilling will play increasing role in accessing incremental reserves as field matures Kristen Nelson Petroleum News
Horizontal, multilateral and coil-tubing-drilling sidetracks are expected to play an increasing role at Kuparuk as the field matures.
Greater Kuparuk River field operator ConocoPhillips Alaska says its drilling strategy will target high-value locations and apply appropriate well and completion techniques “in an effort to reduce development drilling costs.”
“As the Kuparuk field matures, horizontal, multilateral and CTD sidetrack technologies will play an increasing role to access incremental reserves at reduced cost,” the company said.
In an August 2007 through July 2008 Kuparuk plan of development the company told the Alaska Department of Natural Resources’ Division of Oil and Gas that wells currently shut-in because of mechanical problems or low production rates may be sidetracked.
A Kuparuk-West Sak seismic study produced more than 125 leads for potential infill or sidetrack drilling. Those leads will be developed with a combination of grass root wells, rotary sidetracks and coil-tubing sidetracks, ConocoPhillips said.
Depending on the number of coil-tubing wells, a new-build CTD rig may be warranted.
“In concept, the new rig would feature the latest technologies and incorporate design aspects specific to the North Slope,” the company said.
If a new CTD rig is developed, ConocoPhillips said it expects the rig would be owned and operated by a drilling contractor such as Nabors, Nordic or Doyon, and put under long-term contract.
Change in PPT expected Production at Kuparuk in 2006 averaged 124,000 barrels per day from the main field and 46,000 bpd from satellite fields (Meltwater, Tabasco, Tarn and West Sak).
Development drilling will include a half rig-year per year of new-well rotary drilling or rotary drilling sidetracks. There will be three-quarter rig-year per year for workovers and a half rig-year per year for coil-tubing drilling, ConocoPhillips said.
Depending on the blend of new wells and sidetracks, some 12-25 penetrations are expected in the plan period of August 2007-July 2008.
ConocoPhillips noted that the plans for Kuparuk “are subject to change based upon business conditions.”
The company said that the amount of work will depend on the business climate and that it expects that the state’s petroleum profits tax will be reevaluated by the Alaska Legislature “and may be modified, resulting in increased economic uncertainty, potentially poorer economic returns and project sanction delays.” The economic viability of projects will be tested under the PPT and under alternative taxation proposals, the company said.
Additional seismic possible; exploration ongoing The Kuparuk-West Sak three-dimensional seismic survey may be supplemented in 2008-09 over the southwestern area of the Kuparuk River unit, and unit owners will consider the low-salinity enhanced oil recovery process. That consideration, the company said, “may be in the form of a paced sequence of studies, single well tracer tests, core analysis and small scale piloting.”
ConocoPhillips said exploration at Kuparuk “is an ongoing process that is closely coordinated with development plans.” Targets include “commercially viable exploration targets within KRU lands and the surrounding area.” The 2007-08 exploration plan applies to all areas within the unit not currently in a participating area (participating areas are created when commercial production begins from an area).
2006-07 exploration activity included an application for expansion of the West Sak participating area and continued evaluation of potential northeast West Sak development.
Water, corrosion issues ConocoPhillips said major facilities in place at Kuparuk are the same as in its last plan of development.
A temporary water injection expansion project, TWIX, at Central Processing Facility 2, started up in September 2004, “has operated continuously to date,” the company said. “In mid-2006, the operating contract for this module was extended to mid-August 2008.”
ConocoPhillips said studies in 2006 of the water injection system in the CPF2 area “showed solids in the water injection lines.” The solids, barium sulfate — a form of scale — “caused some concern about the ability of corrosion inhibition chemicals to effectively treat all of the injection system,” the company said.
The scaling occurred because barium-containing produced water (the water which is part of crude oil) is mixed with sulfate-containing seawater. The company said the chemistry of the waters “cannot effectively be altered” so to avert large amounts of scaling in the future, produced water and seawater were segregated into different components of the injection system. Because of the segregation, there was a loss of flexibility in the volume of water which can be delivered to certain drill sites for injection.
ConocoPhillips said projects will be considered to expand the water handling-water injection system to minimize the impact of the segregation of produced water and seawater. “These projects could involve new water pumps as well as additional piping to provide improved hydraulic flexibility.”
Kuparuk to become gas-constrained Miscible water-alternating gas is the sole enhanced oil recovery process at Kuparuk. Kuparuk manufactures miscible injectant by blending produced lean gas and natural gas liquids, the latter from Kuparuk and imported from Prudhoe Bay.
The MWAG project operated at full miscible injectant mode for some nine months in 2006; from mid-August to early November production problems at Prudhoe “significantly impacted their ability to manufacture NGL for export and blending.”
ConocoPhillips said Kuparuk shifted to an immiscible water-alternating-gas EOR “to manage gas and optimize oil production rates” during that period.
Gas management at Kuparuk during 2006 was aimed at balancing solvent injection to maximize EOR oil recovery “while avoiding excessive gas production rates which would lead to gas handling impacts,” the company said.
In 2006 the Kuparuk unit averaged 307 million standard cubic feet per day of gas production, compared to 326 million standard cubic feet per day in 2005. “This gas production drop continues the trend of declining annual gas production volumes,” the company said. “The drop in gas production is driven by higher water injection levels and flat-to-declining gas injection levels along with ongoing gas trapping in immature EOR patterns reducing the available returned gas.”
Imported gas will be needed ConocoPhillips said that in the past the solution gas production at Kuparuk (gas produced in solution in crude oil) exceeded the demand for fuel gas and surplus gas was reinjected for storage or used in EOR.
Field gas production is expected to “decline significantly in the coming years as fuel use and gas trapping from our gas injection processes depletes the volume of mobile gas in the system.” Once the daily consumption of gas as fuel and through trapping exceeds new solution gas production, the company said, both fuel gas and gas for EOR will come from depletion of free gas from volumes previously injected. ConocoPhillips said that volume is relatively small and is expected to deplete in five to 11 years. “Supplying gas to third parties will accelerate the fuel gas shortfall,” the company said.
Fuel gas is the priority, so the amount of gas available for MWAG “will decline to zero beyond which time additional sources of gas will be needed to ensure adequate fuel supply.”
Importation of gas from Prudhoe Bay appears the most technically feasible alternative, the company said, with 2012-18 being the best estimate of when importation would need to begin.
ConocoPhillips said the owners are doing studies “to understand the consequences of various reservoir management scenarios involving reduced volumes of miscible injectant.”
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