ConocoPhillips is the company most responsible for the westward expansion of oil development across the North Slope and it continues to set its sights even farther west.
The company currently operates production from the Kuparuk River and Colville River units on state and Native land, and is eyeing development from the Greater Mooses Tooth and Bear Tooth units on federal land within the National Petroleum Reserve-Alaska.
Through various subsidiaries, ConocoPhillips also operates the Alpine, Kuparuk and Oliktok pipelines, as well as owning some 28 percent of the trans-Alaska oil pipeline.
Combined, ConocoPhillips was operating an average of 171,809 gross barrels of oil per day in July 2013, according to the Alaska Oil and Gas Conservation Commission.
The Kuparuk River unit
Sinclair Oil and Gas discovered the Kuparuk River oil pool in 1969 with the Ugnu No. 1 well, but it took another decade before ARCO Alaska sanctioned development.
The delay gave the industry time to build the trans-Alaska oil pipeline and to bring the Prudhoe Bay unit into production to the east, but for ARCO it had more to do with economics. Even a year earlier, the Kuparuk development team had been unable to persuade top management to sanction the “marginally economical” field, but rising oil prices and the demand for domestic energy supplies changed the picture by 1979.
At the time, ARCO and Sohio were suing the state over its corporate income tax, but ARCO Chairman Robert O. Anderson said the lawsuit primarily concerned the impact on wildcat exploration. “The Kuparuk represents a fairly well-known quantity, with limited risk, which differs from the high-risk investments cited in the lawsuit,” Anderson said.
The development program called for bringing 20 square miles of the field online by 1982, but also working with nearby leaseholders on a longer-term plan for 200 square miles.
ARCO started work on Central Processing Facility 1 in 1979 and after three sealifts the company brought the Kuparuk River field online in late 1981. At the same time, ARCO was working with the other interest owners on the agreements needed to unitize the field.
The Kuparuk River field produced 32.4 million barrels in 1982 and 39.9 million barrels in 1983, when ARCO started building Central Processing Facility 2 and the Seawater Treatment Plant, and the additional facilities accommodated additional production. The field produced 46.1 million barrels in 1984, 79.7 million barrels in 1985 and 95 million barrels in 1986, when ARCO began construction on Central Processing Facility 3.
Those early years saw two secondary recovery projects, a CPF-1 waterflood launched in 1983 and a small-scale enhanced oil recovery project in 1988. ARCO also began infill drilling in 1988. In December 1992, total Kuparuk River unit production peaked at 339,386 barrels per day, according to the Alaska Oil and Gas Conservation Commission.
Originally, engineers had expected production to peak at 250,000 bpd.
After the peak
In the two decades since, activities at Kuparuk River have been dedicated to expanding the field through infill drilling, satellite development and enhanced oil recovery. The success of these efforts can be expressed in a single fact: In 1999, cumulative Kuparuk production passed 1.6 billion barrels, which was the initial expected recovery estimate for the field.
Through mergers and acquisitions between 1999 and 2002, ConocoPhillips became the operator of the Kuparuk River unit. Today, ConocoPhillips owns a 55.3 percent interest in the unit, with BP Exploration (Alaska) Inc. owning 39.2 percent, Chevron U.S.A Inc. owning 4.9 percent and ExxonMobil Alaska Production Inc. owning 0.6 percent.
By the end of 2012, ConocoPhillips was developing the main Kuparuk field from 44 drill sites — including seven shared with satellites — and 821 active wells, according to a June 2013 report. To enhance recovery, ConocoPhillips was using waterflood at 14 sites, immiscible water-alternating-gas, WAG, at five sites and miscible WAG at 25 sites.
A major program at Kuparuk in recent years has used coiled tubing drilling to access smaller accumulations missed by conventional drilling equipment. A 14-well program in 2012 completed 53 laterals, which brought 5,050 bpd of incremental production online.
ConocoPhillips identified up to 17 coiled-tubing drilling candidates for 2013, including a cluster of sidetracks in the southern reaches of the field at drill sites 2F, 2G, 2H and 2K.
The Kuparuk participating area produced 87,900 bpd in 2012.
The current program includes delineating peripheral areas of the field and using tertiary recovery techniques at select locations. It also involves managing the changing profile of the aging field. Gas and water handling limits have constrained oil production in recent years. The gas handling constraint will be alleviated as the Greater Kuparuk Area naturally becomes gas short — ConocoPhillips even plans to import fuel gas from Prudhoe Bay starting in 2014 to reserve native gas for injection — but ConocoPhillips is working on numerous upgrade projects to alleviate its water handling constraints.
ConocoPhillips described its future exploration and appraisal plans at Kuparuk as being an “infrastructure-led exploration strategy” based on a 2011 3-D seismic acquisition.
The West Sak satellite
Of the 2.5 billion barrels of oil produced from the unit through July 2013, the main field is responsible for some 2.3 billion and the five satellites account for the remainder.
In 1997 and 1998, ARCO began production from three satellites — West Sak, Tarn and Tabasco — and in 2000 it announced the discovery of a fourth satellite, Meltwater.
In 2012, the Kuparuk satellites produced some 25,200 bpd.
ARCO discovered the shallow West Sak oil pool in 1971 with the West Sak River State No. 1 well and proved the feasibility of producing the viscous oil through a 15-well pilot project across 45 acres of the field between June 1983 and December 1986, but it took another decade before regular production began from the 1D drill site in December 1997.
The pool covers much of the eastern half of the Kuparuk River unit, stretching into the Milne Point unit and the northwest corner of the Prudhoe Bay unit at the north and fanning out at the south to extend beyond the southern border of the Kuparuk River unit.
ARCO followed the initial phase of conventional drilling with multilateral wells starting in 1999 and 2000, but launched a major heavy oil development at West Sak in 2004. The $500 million program called for an expansion of the existing 1E pad and the construction of a 1J pad to better access the huge viscous and heavy oil contained in the reservoir.
ARCO originally developed West Sak from the pre-existing 1B pad at Kuparuk and the new 1C and 1D pads, but added the 1E pad in 2004 and the 1J pad in 2006 and later began using 3K pad to access the field. Through 2012, the field was being developed from 102 active wells — 49 producers and 53 injectors — on those six pads.
Through the end of 2012, the West Sak oil pool had produced 62 million cumulative barrels of oil, including a rate of 14,185 bpd in 2012, according to ConocoPhillips.
Heavy oil
This success, though, masks the difficulty in producing the heavier oil at West Sak.
Efforts to date have included multilateral, horizontal and “undulating” wells, sand filtering, various waterflooding and gas injection techniques and different well spacing. However, as ConocoPhillips recently told the state, “the pace of future West Sak development has slowed while performance of recent developments is evaluated.”
The most recent pilot project — Viscosity Reducing Water Alternating Gas — wrapped up in May 2013, and ConocoPhillips wants to expand it to other areas of the field.
Among those is Eastern NEWS, or North East West Sak, where ConocoPhillips would drill five horizontal multilateral producers and 13 vertical injectors on an existing pad.
The Tarn satellite
ARCO discovered the Tarn oil pool with the Bermuda No. 1 well in 1991.
The Tarn oil pool is in the southwest corner of the Kuparuk River unit and consists of five intervals of late Cretaceous-aged marine sandstone in the Seabee formation. From deepest to shallowest, the intervals are called Iceberg, Arete, Cairn, Bermuda and C30.
ARCO brought Tarn online in June 1998.
ConocoPhillips is currently developing the satellite from the 2N and 2L pads. Through 2012, 63 wells have been drilled from the pads — 43 producers and 20 injectors.
“Recent studies have indicated that there may be additional infill and peripheral development opportunities,” ConocoPhillips wrote in its most recent Tarn update. “Plans for 2013 and 2014 include three grassroots rotary wells and one rotary sidetrack.”
The 2L wells would target the eastern and northern flank of the accumulation with fracture stimulation and focused injection on the western flank. The 2N wells would realign a waterflood pattern and target an area north and east of current production.
2S pad under consideration
ConocoPhillips is currently considering a 2S pad in the region and evaluating a 2008 discovery in the younger Cairn interval as well as an older Esker interval.
Through the end of 2012, the Tarn oil pool had produced 107 million cumulative barrels of oil, including a rate of 7,100 bpd in 2012, according to ConocoPhillips.
In early 2012, ConocoPhillips used Doyon rig 141 to drill the Shark Tooth No. 1 well from an ice pad four miles from the 2K pad, which is northeast of 2N and 2L.
Shark Tooth No. 1 appraised a discovery ARCO made with the KRU 21-10-08 well in the late 1980s. It was “critical for any future development of this part of the Kuparuk reservoir,” as ConocoPhillips told regulators, because it would “provide additional reservoir information in this area and narrow uncertainty around reservoir description parameters including oil-water contact, sand quality and thickness, and oil viscosity.”
The well “discovered hydrocarbons in the Kuparuk sands, in accordance with expectations, and confirmed mapped volumes,” ConocoPhillips said in late 2012.
ConocoPhillips is now permitting a 24-well S pad, an access road and a gravel mine, as well as associated pipelines and power lines at Shark Tooth with an eye toward a 2015 start date, but must sanction the project before it can move forward. ConocoPhillips originally considered developing the prospect from its existing 2L, 2M or 2K pads, but decided those plans would have taxed the abilities of existing drilling technology.
The Tabasco and Meltwater satellites
ARCO discovered the Tabasco oil pool with the Kuparuk River unit 2T-02 well in 1986, as part of its regular development drilling from the 2T pad at the western edge of the unit.
The shallow, viscous satellite in the middle Cretaceous Nanushuk Group Tabasco sand at approximately 3,000 feet subsea came online in May 1998 from the existing 2T pad.
Through the end of 2012, eight of the 12 wells at the field were online. While ConocoPhillips currently has no plans to delineate the field, the existing infrastructure can accommodate eight additional wells with only a minimal gravel expansion.
Through the end of 2012, the Tabasco oil pool had produced 17,345,000 cumulative barrels of oil, including a rate of 1,076 bpd in 2012, according to ConocoPhillips.
ARCO discovered the Meltwater oil pool in 2000 with the Meltwater North No. 1 exploration well drilled into the middle Cretaceous Seabee formation Bermuda/Cairn Sands, the stratigraphic equivalent of Tarn. Philips Petroleum brought Meltwater online in November 2001 from the 2P pad, which accesses two leases some 10 miles southwest of the unit boundaries. A two-phase, 19-well drilling program wrapped up in 2004, but only 15 wells were active by the end of 2012 — nine producers and six injectors.
Originally, ConocoPhillips alternated water and gas injections to enhance recovery at the field, but in 2009 it took a water injection line out of service over concerns about corrosion. Now, ConocoPhillips only uses miscible gas injection for enhanced recovery.
After well monitoring suggested these injections might be migrating underground, the AOGCC prohibited ConocoPhillips from drilling new wells or converting existing wells to MI until it resolved the issue. While ConocoPhillips had no immediate drilling plans for the satellite anyway, the company launched a two-year study of the overburden in the area to better identify the problem.
The AOGCC said the migration was not a threat to drinking water.
The current work at Meltwater primarily involves field maintenance, such as pigging the produced oil line and monitoring bottom-hole pressures at the four shut-in wells.
Through the end of 2012, the Meltwater oil pool had produced 17,015,000 cumulative barrels of oil, including a rate of 2,719 bpd in 2012, according to ConocoPhillips.
The Palm satellite
Kuparuk development has expanded in other ways, too.
Phillips Petroleum discovered the Palm accumulation in 2001 with the Palm No. 1 well, at the far western edge of the Kuparuk River unit. The accumulation is in a Kuparuk C4 interval now known to be in communication with the main Kuparuk reservoir.
To develop the reservoir, ConocoPhillips built the 3S pad, which came online in November 2003. In early 2013, ConocoPhillips conducted a perforation and hydraulic fracture pilot test at the existing DS 3S-19 well to evaluate the Cretaceous Brookian Moraine interval, but is still analyzing the results. “Any development would, of course, require adequate appraisal and study to prove commerciality,” ConocoPhillips said.
The Colville River unit
While Kuparuk was the western frontier for North Slope oil development for nearly two decades, the title now belongs to the Colville River unit — although not perhaps for long.
The main Alpine field and its three satellites — Fiord, Nanuq and Qannik — produced an average of 60,742 bpd in July 2013, according to the AOGCC. A fourth satellite is under construction. The unit is the gateway to National Petroleum Reserve-Alaska production.
ARCO Alaska discovered the Alpine oil pool in 1994 with the Bergschrund No. 1 exploration well and decided the field was commercial in 1996. Along with partners Anadarko Petroleum Corp. and Union Texas Petroleum Alaska Corp., ARCO proposed a $700 million to $800 million program to build infrastructure and drill 100 to 150 wells.
Through mergers and acquisitions, ConocoPhillips now operates the unit and owns a 78 percent working interest in the leases, and Anadarko owns the remaining 22 percent.
The partners originally estimated that the field contained 365 million barrels of recoverable oil, but they increased the reserve estimate to 429 million barrels in 1997.
Cumulatively, the entire Colville River unit had produced nearly 453 million barrels of oil through July 2013.
Existing facilities
Early on, Anadarko said Alpine offered “repeatability” and “running room,” or the ability to develop a string of smaller discoveries using its existing facilities, equipment and know-how. While the Alpine satellites are large by Lower 48 standards, they are considered too small to be economic on their own. By timing the startup of the four satellites sanctioned to date, ConocoPhillips has been able to use its existing facilities.
The Alpine field surpassed expectations. While initial projections had pegged production at 80,000 bpd, Alpine produced 98,895 bpd in 2004 and peaked at 130,685 bpd in November 2005. As production increased and the profile began changing, ConocoPhillips expanded the capacity of its Alpine facilities in 2004 and again in 2005 to accommodate 35,000 additional barrels of crude oil and 100,000 barrels of produced water each day.
Alpine production comes from Jurassic-aged sandstone not producing anywhere else on the North Slope, and, at 40 degrees API, is lighter than at Prudhoe Bay or Kuparuk.
Horizontal drilling
The Colville River unit is also unique for being developed using horizontal wells, which has resulted in a much smaller footprint than at older fields. Before CD-5, ConocoPhillips was developing the 25,000-acre reservoir from just 97 acres of surface infrastructure, according to the AOGCC.
For 2013 and early 2014, ConocoPhillips planned to drill five new production wells and seven new injection wells in peripheral southwest and east areas of Alpine, which could lead to future drilling, but planned no Nanuq-Kuparuk drilling in 2013 in spite of (or perhaps because of) current production exceeding expectations. As of mid-September, ConocoPhillips had completed the CD1-47 producer and the CD1-49 service well.
After finding success with a four-well hydraulic fracturing program in 2012, ConocoPhillips planned to use the technique on as many as 15 wells this year.
By the start of 2013, ConocoPhillips had drilled 131 wells including 65 producers at Alpine and nine wells including four producers at Nanuq-Kuparuk. In 2012, Alpine produced 45,300 bpd and Nanuq-Kuparuk produced 2,400 bpd.
Cumulatively, those produced some 396 million barrels through July 2013, the AOGCC reports.
Fiord at CD-3, Nanuq at CD-4
As production grew, ConocoPhillips began thinking about satellites.
ConocoPhillips initially developed Alpine from two pads, CD-1 and CD-2, but in a 2003 environmental impact statement the company proposed five Alpine satellites called Fiord, Nanuq, Lookout, Spark and Alpine West, and hinted at 10 additional oil accumulations within 30 miles of Alpine that could possibly become future satellites.
In 2004, with the facility expansion just beginning, ConocoPhillips sanctioned the first two Alpine satellites: Fiord from CD-3 to the north and Nanuq from CD-4 to the south.
(Today, ConocoPhillips uses CD-4 to develop Alpine, as well as Nanuq.)
The Nechelik No. 1 well encountered the Fiord oil pool as early as 1982, but ARCO Alaska’s Fiord No. 1 well from 1992 is considered to be the discovery well for the satellite. Fiord No. 2 confirmed the discovery in 1994, and several wells and sidetracks between 1999 and 2001 delineated it. Fiord now produces from two zones, the Nechelik sand of the Jurassic Kingak formation and the Cretaceous-aged Kuparuk C sand.
By the start of 2013, ConocoPhillips had completed 11 production wells and 10 injection wells into the Fiord-Nechelik zone. The company planned to drill one well in 2013, two wells in 2014 and one well in 2015. ConocoPhillips had three active production wells and three active injection wells in the Fiord-Kuparuk zone as of 2012 with plans for 2013 to drill two new production wells and to convert an existing production well to an injector.
According to September 2013 AOGCC filings, ConocoPhillips completed the CD3-127 producer, and permitted the CD3-320 and CD3-316B producers this year at Fiord.
Up to 32 wells at Fiord
The existing development plan at Fiord calls for as many as 32 active wells.
Fiord peaked at 32,906 bpd in early 2010. Cumulatively, Fiord produced some 51 million barrels through July 2013. In 2012, its two participating areas produced some 20,100 bpd.
ARCO Alaska discovered the Nanuq oil pool with the Nanuq No. 1 well in 1996 and the Nanuq No. 2 well in 2000. The satellite originally produced from Kuparuk C sands equivalent to those at Fiord, in addition to the shallower and younger Nanuq sands, but AOGGC incorporated the Nanuq-Kuparuk reservoir into the Alpine oil pool in 2009.
Through the end of 2012, ConocoPhillips had three active production wells and two active injections wells at Nanuq and planned to drill seven additional wells in 2013. As of mid-September, ConocoPhillips had permitted four wells — the CD4-96, CD4-290 and CD4-292 producers and CD4-291 service well at Nanuq — and completed CD4-292.
Cumulatively, Nanuq had produced some 1.7 million barrels through July 2013, according to the AOGCC. In 2012, the field produced some 1,000 bpd on average.
Fiord and Nanuq came online in August and December 2006, respectively.
The timing worked well. Alpine production averaged 123,000 bpd in fiscal year 2006, according to the Alaska Department of Revenue. In fiscal year 2007, with Fiord and Nanuq both in production, combined Colville River unit production averaged 124,000 bpd — 103,000 bpd from Alpine, 11,000 bpd from Fiord and 10,000 bpd from Nanuq.
Qannik at CD-2
Although the Nanuq No. 1 well encountered the Qannik oil pool as early as 1996, ARCO believed the reservoir was too tight and too thin to be productive. ConocoPhillips demonstrated the quality of the pool through an appraisal program in 2005 and 2006.
The Qannik satellite was not one of the original five satellites ConocoPhillips listed in its 2003 filings, but the pool is in the center of the Colville River unit and is shallower than Alpine, which allowed ConocoPhillips to develop it by expanding the existing CD-2 pad.
The field came online in July 2008.
Through the end of 2012, ConocoPhillips had six active production wells and three active injections wells at Qannik, but drilled no wells in 2012 and planned to drill none in 2013.
Qannik peaked at 2,937 bpd in early 2010. Cumulatively, Qannik had produced nearly 4 million barrels through July 2013. In 2012, the field produced some 1,800 bpd.
Alpine West at CD-5
With success at the three satellites, ConocoPhillips planned to expand into the NPR-A.
The original 2003 filings listed three NPR-A satellites: a CD-5 pad at the Alpine West prospect, a CD-6 pad at the Lookout prospect and a CD-7 pad at the Spark prospect.
The CD-6 and CD-7 pads would be on federal leases, but the CD-5 pad would be on an Arctic Slope Regional Corp./Kuukpik Corp. lease across the Nigliq Channel of the Colville River from the existing Alpine facilities. While ConocoPhillips had drilled an Alpine West exploration well directionally from the CD-2 pad in 2001, the company proposed accessing Alpine West using a bridge connecting back to the CD-2 pad.
ConocoPhillips originally thought that the Alpine West prospect could not, on its own, justify the construction of a bridge across the Nigliq Channel and so it planned to develop CD-6 first starting in 2007 and return in 2009 to develop CD-5 and CD-7 concurrently.
After further evaluation, though, the company changed its view. In 2005, ConocoPhillips began permitting a CD-5 development and described CD-6 as “economically marginal.”
The bridge proposal, though, created years of delays.
Route negotiations
First, ConocoPhillips and local Native groups spent years negotiating the route of the bridge. After they reached an agreement in early 2009, ConocoPhillips revised its CD-5 proposal to accommodate additional drilling. The company said the intervening years of Alpine development had improved its understanding of the Alpine West satellite.
The U.S. Army Corps of Engineers rejected the bridge idea entirely in early 2010, though, telling ConocoPhillips to instead drill directionally underneath the channel. An appeal process led to an “agreement in principle” between ConocoPhillips and federal regulators in late 2011, which allowed the company to move forward on the bridge.
ConocoPhillips sanctioned the CD-5 project in late 2012. With partner approval, it intends to start construction next year in advance of first oil in late 2015 or early 2016, but now the development is facing two court challenges from environmental groups.
In June 2013 court filings related to those cases, ConocoPhillips Alaska Vice President of North Slope Operations and Development Nicholas G. Olds said that the Colville River unit partners have already spent “in excess of $100 million” on acquisition, exploration and development related to CD-5, and expect the satellite to produce some 15,800 bpd.
Economic perspective
To put the larger economics into perspective, ConocoPhillips Alaska President Trond-Erik Johansen compared the CD-1 and CD-5 projects in a speech at the annual Meet Alaska conference in January 2013. When Phillips brought CD-1 online in 2000, it spent $1 billion in return for 80,000 barrels per day, Johansen said. Now ConocoPhillips plans to spend $1 billion on CD-5 in return for what he estimated would be some 18,000 bpd.
Coming as lawmakers debated revisions to the fiscal regime, Johansen credited this disparity to taxes. “The tax system was much more favorable than it is today, and you got five times the production for the investment you spent. So let’s get real,” he said.
The speech failed to mention a range of other factors.
While Alaska oil sold for $20 to $30 per barrel in 2000, the state expects the price to stay above $100 per barrel in the coming years. Of course, oil prices are also higher in cheaper basins. A decade of inflation and rising construction costs has challenged economics, though. Then again, Alaska now offers numerous tax credits not available back in 2000.
All of which suggests how difficult it is to compare the economics of any two projects (and even more so without the benefit of complex and proprietary modeling software.)
As with the rest of the unit, ConocoPhillips plans to develop CD-5 using horizontal wells — six production wells and seven injection wells alternating water and miscible injectant.
Greater Mooses Tooth
As it moves toward first oil at CD-5, ConocoPhillips is also in the early permitting stages for CD-6, although the company has since re-named and refocused the satellite project.
After the U.S. Bureau of Land Management formed the Greater Mooses Tooth unit in 2008, ConocoPhillips changed the names of the CD-6 and CD-7 pads to GMT-1 and GMT-2, respectively, to better distinguish between its state and federal developments.
In July 2013, ConocoPhillips submitted a GMT-1 proposal calling for an 11.8-acre gravel pad with the capacity for 33 wells. A 7.8-mile gravel access road would connect the GMT-1 pad to the CD-5 pad. The road would also accommodate pipelines, power lines and other associated infrastructure. ConocoPhillips expects first oil by late 2017.
The GMT-1 proposal is “very similar” to the original Alpine CD-6 pad the BLM approved in its 2004 decision, according to the agency, but does include some “notable changes.”
The changes mostly stem from a new location proposed for the drill site, which would reduce the length of roads and pipelines and therefore the amount of gravel required for construction. The original CD-6 pad would have been on lease AA-81819, but the proposed GMT-1 pad would be on lease AA-81798, which is slightly closer to Alpine.
The GMT-1 project also proposes a longer Ublutuoch River bridge, requires 3.3 additional miles of ancillary pipeline from the CD-1 pad to a pipeline tie-in north of the CD-4 pad, and would accommodate larger pipelines in the future than the CD-6 plan.
To consider those changes, the BLM is supplementing its 2004 Alpine Satellite Development Plan environmental impact statement. The supplemental EIS will also consider environmental studies conducted since 2004, such as the regional climate change assessment for the NPR-A, the recent Integrated Activity Plan for the NPR-A and the listing of the polar bear as a threatened species under the endangered species act.
The supplemental EIS will also consider future drilling, such as a GMT-2 pad.
In September, ConocoPhillips staked four wells in leases AA-81784 and AA-81803, which cover the Rendezvous prospect in the center of the Greater Mooses Tooth unit.
The original CD-7 pad would have been on lease AA-81802, slightly closer to Alpine.
Technology
At both the Kuparuk River and Colville River units, ConocoPhillips is using a combination of technologies to improve the economics of smaller pockets of oil.
With time-lapse 3-D seismic (also known as “4-D” seismic), ConocoPhillips can “illuminate pockets of oil that are in separate fault blocks or for whatever reason are not producing into an existing well bore,” Executive Vice President of Technology and Projects Alan Hirshberg said in February 2013, during the annual update for analysts.
Coiled-tubing drilling can “twist and turn through the rock” to reach these pockets.
The coiled tubing is a continuous length of flexible, small-diameter steel tubing instead of the lengths of rigid steel drill-pipe used in conventional drilling. A tool at the end of the drilling equipment can turn more than 60 degrees over a 100-foot stretch of well, which “allows us to go right to these pockets that we found with the 4-D,” Hirshberg said.
This process allows ConocoPhillips to use existing wellbores to target pockets of oil that would be too small to justify drilling a separate vertical well. When seismic information uncovered eight different zones near a single wellbore at Kuparuk, the company used coil-tubing equipment to drill the first “octolateral” on the North Slope. “That’s a very cost effective way to get at those zones that weren’t producing before,” Hirshberg said.
Coiled-tubing drilling has been used on the North Slope for more than a decade, but it has become particularly useful at the compartmentalized reservoir rocks of Kuparuk. With a growing portfolio of coiled-tubing drilling candidates, ConocoPhillips commissioned the Nabors CDR2-AC rig in 2009 and has been drilling sidetracks continually ever since.
