ConocoPhillips Alaska Inc. was created through the 2002 merger of Phillips Petroleum Co. and Conoco Inc., which each had considerable prior experience in Alaska.
Phillips Petroleum started its Alaska operations in 1951, through the Katalla-Yakataga contract. The contract was established to develop private leases in the Icy Bay region. In 1959, Phillips bid more than $1 million for leases in the Wide Bay region, in the first state sale. As a nod to its Phillips 66 brand, the company tacked 66 cent onto every bid.
Over the following decades, Phillips participated in important early exploration ventures in the Cook Inlet region and early wells before the historic 1969 North Slope lease sale and was one of the key players in building the pioneering liquefied natural gas terminal in Kenai. During that time, Phillips undertook some interesting and risky exploration ventures, including the Tyonek Deep prospect in Cook Inlet and the first large exploration program in the National Petroleum Reserve-Alaska in recent decades.
As part of a state brokered plan to prevent a North Slope monopoly, Phillips acquired ARCO Alaska Inc. in 2002, when BP Amoco acquired the ARCO Alaska parent company Atlantic Richfield Co. The acquisition expanded Phillips’ legacy in Alaska and its holdings in the state, giving the company a working interest in the Prudhoe Bay field, additional NPR-A prospects and control over the Kuparuk River and Colville River units.
Conoco Inc. had a much less illustrative career in Alaska at the time of the merger but touted some important distinctions, including work on the viscous oil at Milne Point unit and the complex Badami unit. The company sold its Alaska holdings to BP in 1994.
Since the merger, Alaska has remained a major component of the global ConocoPhillips portfolio. It is the only basin for which the company reports separate financial figures.
Over the past 13 years, ConocoPhillips has generally been pushing westward across the North Slope by developing satellites at the Kuparuk River and Colville River units, exploring the NPR-A and acquiring leases and conducting studies in the Chukchi Sea, while also contributing to the Prudhoe Bay unit as a non-operating minority partner.
In the Cook Inlet region, ConocoPhillips operates some of the oldest fields and facilities in the basin: the Beluga River unit, the North Cook Inlet unit and the associated Kenai LNG terminal. After a burst of activity in the mid-2000s, the company began scaling back its investment and, in August 2015, placed its Cook Inlet assets on the market.
ConocoPhillips produced 174,000 barrels of oil equivalent per day in Alaska in the second quarter of 2015, according to quarterly figures provided by the company.
The Kuparuk River unit
The Kuparuk River unit includes the main Kuparuk oil field and four satellites. Sinclair Oil and Gas discovered the primary Kuparuk River oil pool in 1969, and ARCO Alaska sanctioned development a decade later, by which time the trans-Alaska oil pipeline was already delivering oil production from the neighboring Prudhoe Bay unit to market.
Economics caused the delay. But crimped domestic supplies and the subsequent rise in prices at the end of the decade persuaded top management to sanction Kuparuk. The program called for bringing 20 square miles of the Kuparuk field online by 1982 and working with nearby leaseholders on a longer-term plan to develop 200 square miles.
The Kuparuk River field came online in late 1981 and production peaked at 339,386 barrels per day in December 1992, according to the Alaska Oil and Gas Conservation Commission. Originally, engineers had expected peak production of 250,000 bpd.
After ARCO left the state, Phillips Alaska Inc. became the operator of the Kuparuk River unit. ConocoPhillips took over in 2002, after Conoco Inc. and Phillips Alaska merged.
In the 23 years since the unit hit peak production, those operators have been pursuing various programs to expand development and improve production through technology.
Through July 2015, the entire Kuparuk River unit had produced nearly 2.6 billion barrels of oil and the Kuparuk River field was responsible for nearly 2.4 billion barrels of oil.
Recent expansion
In July 2015, ConocoPhillips asked the state to expand the unit to include a lease along the southern boundary of the North Slope unit and to include 18 additional leases already within the unit either in the Kuparuk participating area or the West Sak participating area.
The unit expansion would bring lease ADL 392364 into the unit boundaries, expanding the total unit size by 2,560 acres. The participating area expansions would add portions of 11 tracts (including ADL 392364) covering some 11,900 acres to the Kuparuk participating area and eight tracts covering some 6,100 acres to West Sak participating area. All the relevant tracts and leases are currently held by production from the unit.
The expansion would allow ConocoPhillips to more easily use existing facilities to develop recent discoveries, according to the company. “The reserves discovered thus far in the Expansion Area are not large enough to support the costs of full processing facilities. Even if stand-alone development were economic, there would be economic waste due to the existence of duplicate facilities and services,” the company wrote.
The state approved the unit expansion in September. With more than 2,000 bpd currently being sent to the Kuparuk facilities from the lease, the state said the requested expansion was justified. ConocoPhillips drilled the horizontal 2G-17L1 lateral in 2013 using coil tubing drilling on ADL 392364, just south of the unit boundaries. The well targeted the historically under-performing Kuparuk C sand and initially produced more than 2,900 bpd before settling to a sustained rate of 700 to 800 bpd. Given the success of the well, the company drilled the offsetting 2F-22 horizontal well at the western edge of the lease in late 2014 and initially produced more than 2,000 bpd before settling to some 1,100 bpd, also from the Kuparuk C.
The company drilled the 2E-01 and 2F-21 horizontal wells earlier this year into the lowermost Kuparuk A sand. The former came online at nearly 1,000 bpd and is now producing some 300 bpd. The latter is an offsetting injection well that is currently being “pre-produced” at a rate of some 100 to 200 bpd.
Aging field
As the oldest field in the Kuparuk River unit, the main Kuparuk field is also the most mature. At the end of 2014, ConocoPhillips was developing the field with 835 active wells at 44 drill sites, according to a June 2015 plan of development. At the end of 2013, the field had 817 active wells at 44 drill sites. The Kuparuk participating area produced 83,200 gross bpd in 2014, down from 85,700 gross bpd in 2013.
ConocoPhillips drilled 26 wells in the Kuparuk participating area last year - eight rotary wells and 18 coiled tubing sidetracks with a total of 40 laterals. The drilling program added some 3,500 gross barrels of peak incremental oil production per day, according to the company. The sidetracks were scattered throughout the field. The new wells included four at Drill Site 2E, two at Drill Site 2K and one each at Drill Site 2F and Drill Site 2M.
Those figures continue a recent trend of increased drilling and declining incremental production from the main Kuparuk field. By comparison, the company drilled 15 wells with 41 laterals at the Kuparuk field in 2013, adding some 4,520 gross barrels of peak incremental oil production per day, and drilled 14 wells with 53 laterals at the Kuparuk field in 2012, bringing some 5,050 gross bpd of incremental production online.
This year, ConocoPhillips expects to drill 23 wells at the Kuparuk field - seven new rotary wells and 16 coiled tubing sidetracks. That would be a decline from 2014.
The new wells are mostly associated with Drill Site 2S. The company is currently developing the new drill site in the southwest corner of the unit with plans to bring production on by the end of the year. The sidetracks are scattered throughout the unit. The company announced in the second quarter of 2015 that drilling had begun at the pad.
The proposed expansion of the Kuparuk participating area would include two blocks - one associated with Drill Site 2S and Drill Site 2M and the expansion lease in the south.
The expansion associated with Drill Site 2S would incorporate portions of ADL 25590, ADL 25603, ADL 355608, ADL 380053 and ADL 380051 in the participating area. The Drill Site 2M expansion would add portions of ADL 390503, ADL 25565 and ADL 25590. The southern expansion would add ADL 39264, ADL 25668 and ADL 25605.
The unit expansion at ADL 392364 would incorporate a lease in the vicinity of Drill Site 2E, Drill Site 2F and Drill Site 2G, where ConocoPhillips has been focusing a noticeable portion of its development drilling budget at Kuparuk in 2014 and for this coming year.
Altogether, ConocoPhillips said it has drilled five wells into the expansion acreage in recent years. Those include wells 2E-01, 2F-21, 2F-22, 2G-17 and 2M-36. All five of those wells encounter hydrocarbons in paying quantities, according to the company.
ConocoPhillips also added 3,360 gross bpd through a rigged workover program and another 10,600 gross bpd through a rigless workover program in 2014. Those figures are up from 2013, when the company added 2,601 gross bpd through a rigged workover program and 10,300 gross bpd through a rigless workover program.
Miscible injection
Aside from increased drilling, the two biggest developments at the Kuparuk field in 2014 were changes to the miscible injection program and an expansion of seismic activities.
The main Kuparuk field had waterflooding activities at 24 drill sites (up from 18 in 2013), immiscible water-alternating-gas at 17 drill sites (up from two in 2013) and no miscible water-alternating-gas (down from 24 in 2013). Currently, miscible injection is unavailable for technical reasons. ConocoPhillips said it intends to continue miscible injection programs at four dill sites - 1B, 1C, 1D and 1E - using indigenous supplies.
In July 2014, ConocoPhillips stopped importing natural gas liquids used for the operations from the Prudhoe Bay unit and planned to convert the Oliktok Pipeline to instead import fuel gas from Prudhoe. ConocoPhillips expects to complete the necessary modifications at Central Processing Facility No. 1 and No. 2 by the end of this year and complete similar work at Central Processing Facility No. 3 by the end of 2017.
Seismic
Another major effort last year was seismic acquisition.
Over the past decade, ConocoPhillips has been relying heavily on seismic information to identify potential targets for additional development within the existing Kuparuk field.
The company completed 4-D processing over a 60-square-mile area of the field and licensed a 47-square-mile speculative 3-D survey in the north end of the unit.
The company also undertook four seismic reprocessing efforts last year.
The WBA/Kalubik Depth Migration project will “better image” the western side of the Kuparuk field. The company expects to complete the project in the third quarter. The KRU-KWS 4-D project is reprocessing overlapping portions of the KRU 3-D program from 1990 and the KWS 3-D program from 2005. The KWS Structural Reprocessing project is considering a different aspect of the data. Preliminary interpretation is underway on both projects. The KRU 3-D Depth Migration project is improving imagining along the periphery of the field and should be completed late this year.
The Kuparuk River unit satellites
Unlike the Prudhoe Bay unit, the majority of the activity at the Kuparuk River unit is at the main field and the oldest satellites, while the newest satellites are relatively stable.
In its plans of development for the unit, ConocoPhillips details activities at the Kuparuk participating area and four satellites: West Sak, Tarn, Tabasco and Meltwater.
Through July 2015, those four defined satellite fields as well as undefined oil pools in the Ugnu and Torok formations had produced more than 229.2 million barrels of oil.
West Sak
ARCO discovered the shallow West Sak oil pool in 1971, appraised the feasibility of producing viscous oil from the field with a 15-well pilot project between June 1983 and December 1986 and brought the field into production from Drill Site 1D in late 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, making it an important regional asset for various operators and working interest owners.
ConocoPhillips has devoted far more resources to West Sak than to the other Kuparuk satellites. After several years of conventional drilling, the company began a multilateral program at West Sak starting in 2000. Those wells became increasingly complex over the following decade, with tri-lateral wells and undulating wells designed to target more of the formation. ConocoPhillips also expanded pad infrastructure at West Sak. Altogether, the heavy-oil development program was estimated to have cost some $500 million.
The satellite is currently slated for even more investment.
At the end of 2014, West Sak had 92 active wells at six drill sites - down from 96 active wells at six drill sites at the end of 2013 and 102 active wells at the end of 2012. West Sak shares its drill sites - 1B, 1C, 1D, 1E, 1J and 3K - with the main Kuparuk field.
Even with the decline in active wells, production increased. The satellite produced some 16,241 barrels per day in 2014, up from 15,772 bpd in 2013, up from 14,185 bpd in 2012.
In its current plan of development, ConocoPhillips wrote: “the pace of future West Sak development has slowed while the performance of recent developments in evaluated,” using language the company had previously used in its 2014 plan of development.
The biggest development planned for West Sak is North East West Sak. The NEWS project is a $450 million program to expand existing Drill Site 1H. The project was approved earlier this year and is expected to come online by early 2017 and produce some 8,000 gross bpd at its peak. According to the newest plan of development, ConocoPhillips intends to conduct preliminary work this year and drill four horizontal multilateral production wells and 15 vertical injection wells starting in 2016.
The company is also considering NEWS programs at Drill Sites 1N, 3K and 3R, although all three projects are in the early stages and have yet to be publically defined in depth.
This year, the company is planning drilling campaigns at Drill Sites 1D and 1C.
The Drill Site 1D program calls for four wells. 1D-143 would be a single-lateral into the B sand. 1D-145 would be a quad-lateral into the D Sand, A4 Sand, A3 Sand and A2 Sand. Those two wells are designed to replace the existing 1D-140 well. 1D-146 would be a single-lateral into the D Sand east of the existing 1C-135 and 1D-141A wells. 1D-142 would be an injector supporting 1C-135, 1D-141A and the new 1D-146 wells.
The company already expanded the existing gravel pad to accommodate the wells and expects the drilling will require an expansion of the Sak Core Area participating area.
Given the success of two recent wells at Drill Site 1C, ConocoPhillips plans to drill four more this year - two producers and two injectors - and is considering three others.
As part of its recently requested expansion, ConocoPhillips has asked the state to add eight Kuparuk River unit tracts covering some 6,100 acres to the West Sak participating area. The proposed expansion would add portions of ADL 47449, ADL 25638, ADL 25637, ADL 25636, ADL 25639, ADL 28242, ADL 25649 and ADL 28243, near Drill Site 1H. The company has drilled two recent wells in the proposed expansion area: 1C-150 and 1C-151. Both wells encountered commercial hydrocarbons, according to the company.
Through July 2015, West Sak had produced nearly 77.3 million barrels of oil.
Tarn
ARCO discovered the Tarn oil pool in the southwest corner of the Kuparuk River unit in 1991, confirmed the accumulation in 1997 and brought it into production in June 1998.
At the end of 2014, the Tarn participating area had 69 active wells at two drill sites, 2N and 2L - up from 61 active wells through 2013 and 63 active wells through 2012. Tarn produced 7,700 bpd in 2014, up from 5,600 bpd in 2013 and up from 7,100 bpd in 2012.
The drilling campaigns in 2014 and 2015 have been delineating the Bermuda sands at Tarn, according to ConocoPhillips. The company said it has been encouraged so far by results of drilling into the Purple interval and is evaluating the Cairn and Esker intervals.
After deferring four wells in 2013, ConocoPhillips drilled nine development wells at Tarn in 2014. The success of the first six wells prompted the decision to drill three more wells.
•Well 2N-323A is a rotary sidetrack slant producer brought online in May 2014. The well was producing 360 bpd by the end of 2014.
•Well 2L-322A is a new horizontal producer brought online in August 2014. The well was producing 380 bpd by the end of 2014.
•Well 2N-322 is a new horizontal producer brought online in October 2014. The well was producing 650 bpd by the end of 2014.
•Well 2L-318 is a new horizontal injector brought online in November 2014. The well was injecting 4,250 barrels of water per day by the end of 2014.
•Well 2L-314 is a new slant producer brought online in November 2014. The well was producing 274 bpd by the end of 2014.
•Well 2N-303A is a rotary sidetrack slant producer brought online in November 2014. The well was producing 740 bpd by the end of 2014.
•Well 2N-337C is a rotary sidetrack slant injector brought online in December 2014 and is currently awaiting hook-up.
•Well 2N-350A and Well 2N-319A are rotary sidetrack slant producers put into production in January and February 2015, respectively.
This year, the company is planning a five-well program and may drill more, depending on results. They would be: the horizontal multi-stage producer 2N-336, the slanted injector 2N-312 and the horizontal multistage producers 2L-308, AL-328 and 2L-316.
Through July 2015, Tarn had produced more than 114.2 million barrels of oil.
Tabasco
ARCO discovered the Tabasco oil pool 1986 through regular development drilling at the 2T pad at the western edge of the unit and brought the field into production in May 1998.
At the end of 2014, Tabasco had the same well profile as the year before - 12 wells at Drill Site 2T - nine producers and three injectors - of which only seven were active.
Tabasco produced some 1,549 gross bpd in 2014, down from some 1,711 gross bpd in 2013 and up from 1,076 bpd in 2012, according to ConocoPhillips.
Although Drill Site 2T has several empty slots for both production and injection wells from the initial phase of development, ConocoPhillips is currently focusing on enhanced oil recovery and isn’t planning any exploration or development drilling this coming year.
Through July 2015, Tabasco had produced nearly 18.9 million barrels of oil.
Meltwater
ARCO discovered the Meltwater oil pool in 2000 and Phillips brought the field online in November 2001 from Drill Site 2P, some 10 miles southwest of the unit boundaries.
At the end of 2014, Meltwater had 17 active wells at Drill Site 2P, up from 15 active wells in both 2013 and 2012, according to ConocoPhillips. Meltwater produced some 1,439 gross bpd in 2014, down from 1,971 bpd in 2013 and 2,719 bpd in 2012.
Although recent activities at the field have been limited to maintenance and repairs, the company wrote that it is analyzing development opportunities, including coiled tubing sidetracks and producer-to-injector well conversions, “in the light of new seismic data, recent surveillance findings, absence of injection water supply and business climate,” language identical to an assessment the company made in its last development plan.
Earlier this year, ConocoPhillips asked the AOGCC for permission to use coiled tubing drilling to sidetrack existing Meltwater wells, which the company believes will improve production rates. The request emerged from a problem experienced early in the life of the field: drilling fluids injected into the reservoir appeared in other wells. ConocoPhillips limited reservoir pressure, which solved the problem but also hampered production.
Through July 2015, Meltwater had produced more than 18.7 million barrels of oil.
The Colville River unit
The ConocoPhillips-predecessor Phillips Petroleum and its partner Anadarko Petroleum brought the Alpine field of the Colville River unit into production in 2000 and finished drilling all the wells planned for the initial development of the field by November 2005.
The initial Alpine development occurred from the CD-1 and CD-2 pads.
Since late 2005, ConocoPhillips has been pursuing “peripheral opportunities” at Alpine, often in conjunction with its efforts to develop the satellite fields. For example, the company began developing the Alpine A and Alpine C sands from the CD-4 pad in 2006.
In 2014, ConocoPhillips drilled only one Alpine well: CD4-93, which the company completed into the Alpine A sands in November 2014. The remainder of the development efforts planned for the Colville River unit over the next few years will be at satellites.
ConocoPhillips currently uses miscible-water-alternating-gas flooding as the primary enhanced oil recovery technique at Alpine. The company fracture stimulated three Alpine wells in 2014, which resulted in “an appreciable production rate increase,” according to the company. As a result, it plans to use the technique on two Alpine wells this year.
Under current Alaska Oil and Gas Conservation Commission definitions, the Alpine oil pool combines the Alpine participating area and the Nanuq Kuparuk participating area.
By the start of 2015, ConocoPhillips had drilled 130 wells into the Alpine, which produced 33,800 barrels per day in 2014 and 389 million total barrels through 2014.
The company brought the Nanuq Kuparuk participating area into production in November 2006. The participating area “continues to exceed expectations,” according to the company. By the start of 2015, the company had drilled nine wells into the Nanuq Kuparuk, which produced 500 bpd in 2014 and 25.5 million total barrels through 2014.
Through July 2015, the two fields had produced more than 421.2 million barrels.
ConocoPhillips drilled the CD4-96 well in 2013. The well originally targeted the Alpine reservoir but problems during drilling forced the company to complete it as a Kuparuk well instead. In 2014, the company sidetracked the well into the original Alpine target.
CD-5
The biggest development effort this year is at CD-5.
After years of regulatory delays, ConocoPhillips recently completed construction of the newest drilling pad at the Colville River unit and is currently drilling development wells.
The company plans to drill six production wells (CD5-03, CD5-04, CD5-05, CD5-09, CD5-10 and CD5-11) and seven injection wells (CD5-01, CD5-02, CD5-06, CD5-07, CD5-08, CD5-12 and CD5-13) into the Alpine A sands from the new pad between mid-2015 and early 2016, according to its most recent plan of development. The CD-5 program also includes two Nanuq-Kuparuk wells: the CD5-314 horizontal producer and the CD5-315 horizontal injector. The company is considering a third well, CD5-SUN3, but said the decision will depend on the results of the first two wells and rig availability.
Using information gleaned from the previous Alpine A sands work, the CD-5 program includes a horizontal pattern MWAG flood in the Alpine A sand for enhanced recovery.
The Colville River unit satellites
From the beginning, the ConocoPhillips-predecessor Phillips Petroleum and its partner Anadarko Petroleum designed the Colville River unit to have “sequential development.”
The idea was to use the large Alpine oil field as an anchor to support development of smaller satellite fields in the vicinity. To date, the partners have developed three satellites - Fiord, Nanuq, Qannik - and are nearing completion on a fourth, Alpine West. As a result of the program, the Colville River unit will also support proposed developments at the eastern edge of the National Petroleum Reserve-Alaska. While Alpine West is managed through the plan of development for the main Alpine field, the other three are managed through separate plans of development associated with the main Alpine field.
Fiord
ConocoPhillips brought Fiord online from the CD-3 pad in August 2006. The Fiord pool includes the Fiord Nechelik participating area and the Fiord Kuparuk participating area.
At the start of 2015, ConocoPhillips had drilled 23 wells into the Fiord Nechelik participating area. The company completed the CD3-316B sidetrack in April 2014 and was planning a single development well into the pool in 2015. The Fiord Nechelik produced 12,100 barrels per day in 2014 and 46.1 million total barrels through 2014.
Through July 2015, Fiord had produced 61.2 million barrels of oil.
At the start of 2015, the company had five active wells in the Fiord Kuparuk participating area and had no plans to drill additional wells in 2015. The Fiord Kuparuk participating area produced 1,400 bpd in 2014 and 12.6 million total barrels through 2014.
The company is planning to fracture stimulate one Fiord well in 2015.
Nanuq
ConocoPhillips brought Nanuq online from the CD-4 pad in December 2006. At of the start of 2015, the company had drilled nine wells into the Nanuq participating area, which produced 1,600 bpd in 2014 and 2.6 million total barrels through 2014.
Through July 2015, Nanuq had produced more than 2.9 million barrels of oil.
The company drilled the CD4-289 development well in late 2014 and brought the well into production in early 2015. The well will be converted into an injector this year.
Qannik
ConocoPhillips brought Qannik online from an expanded CD-2 pad in 2008. At of the start of 2015, the company had drilled nine wells into the Qannik, which produced 1,700 bpd in 2014 and 4.8 million total barrels through 2014. The company drilled no wells at Qannik in 2014, planned none for 2015 and sees no near-term opportunities.
Through July 2015, Qannik had produced 5.2 million barrels of oil.
The Beluga River unit
Richfield Oil Corp., Shell and Standard Oil Company of California discovered the Beluga River gas field on the west side of Cook Inlet in 1962, while drilling for deeper oil.
Production from the field began in 1968 to service the new Chugach Electric Association power plant built nearby. Enstar Natural Gas Co. built a pipeline to Anchorage in 1984.
Through its predecessors ARCO and Phillips, ConocoPhillips became operator of the field in 1986 and currently owns a 33 percent working interest ownership in the field, alongside independent producer Hilcorp Alaska LLC and utility Anchorage Municipal Light & Power. Earlier this year, ConocoPhillips announced plans to sell its Cook Inlet properties but had yet to announce a buyer when The Producers went to print.
ConocoPhillips conducted an expensive development campaign at the field between 2008 and 2012. The program included drilling six wells and upgrading compression in an attempt to improve deliverability. The company appears to be done drilling new wells for the time being and is focusing on smaller maintenance activities to improve performance.
As it enters its 47th year of operation, the legacy Cook Inlet natural gas field is “fully delineated,” according to a recent plan of development from operator ConocoPhillips Alaska Inc. The Sterling reservoir has declined to 25 percent of its original pressure, down from 30 percent a year ago. As would be expected, deliverability has also declined.
Even with those downward trends, though, annual production increased last year. Beluga River produced 25.1 billion cubic feet in 2014, up from 22.4 bcf in 2013, which suggests that some of the maintenance activities at the field are yielding results.
“Field efforts continue to mitigate well declines, find production enhancing opportunities and improve operational safety and reliability in this mature asset,” the company wrote.
Through 2014, Beluga River had 14 producing wells (one less than in 2013), 10 shut-in wells (one more than in 2013) and two disposal wells, according to ConocoPhillips.
Through July 2015, the unit had produced more than 1.3 trillion cubic feet of natural gas.
Maintenance program
In 2015, ConocoPhillips has planned maintenance work on at least eight wells.
Its proposed program includes: installation of artificial lift on 212-35T and 232-26 and, if the work proves to be successful, the evaluation of similar activities on 224-34 and 214-26; installation of a velocity string on 232-23; a fill cleanout on 212-25, milling a plug on 244-23; and swabbing and flow testing 211-03, which could lead to additional work.
Many of these projects were either planned for 2014 or grew out of work begun in 2014.
ConocoPhillips had originally intended to conduct rigged workovers on three wells last year. The company completed its program on 244-23 in May 2014 and 242-04 in September 2014 but suspended work on 224-13 “due to operational issues.” The well is currently a candidate for a sidetrack, which ConocoPhillips would drill in 2016.
The artificial lift installations on 212-35T and 232-26 were originally planned for last year but delayed. The project calls for installing an electric submersible pump on 212-35T and a hydraulic submersible pump on 232-26 sometime early this year. The similar installation being considered for 224-34 follows a recent mechanical integrity test.
The flow testing on 211-03 is a continuation of work conducted in May 2014. The current project includes performing a mechanical integrity test, adding perforations and conducting a swab and flow test with an eye toward adding a flow line back to C pad.
ConocoPhillips evaluated clean-out jobs on 212-25 and 212-35. The 212-35 project was scrapped for now. The 212-25 job remains under evaluation. The company also planned to install a velocity string on 232-23 last year but postponed the project to this summer.
Other projects completed last year include:
•An unsuccessful fishing operation on 211-26 in July 2014.
•A successful clean out of 212-24T in August 2014.
•Re-cylindering of seven wellhead compressors, completed in October 2014.
•Studying a proposal to install a water trunk line at the field. The company ultimately decided to keep studying the project and make a decision no earlier than 2016.
•Studying a proposal to add water storage to an existing DW-2 disposal well. The company ultimately decided that the project was “not necessary at this time.”
•Upgrading water storage capacity at C pad in June 2014.
•Studying but ultimately not commissioning a similar project at E pad.
ConocoPhillips completed turnarounds on five facilities in 2014 - BRWD-1 in April, C pad facilities in April and early May, M pad in May and B pad in May and early June - and other maintenance, repairs and inspections at infrastructure throughout the field.
The Colville River unit
The ConocoPhillips-predecessor Phillips Petroleum and its partner Anadarko Petroleum brought the Alpine field of the Colville River unit into production in 2000 and finished drilling all the wells planned for the initial development of the field by November 2005.
The initial Alpine development occurred from the CD-1 and CD-2 pads.
Since late 2005, ConocoPhillips has been pursuing “peripheral opportunities” at Alpine, often in conjunction with its efforts to develop the satellite fields. For example, the company began developing the Alpine A and Alpine C sands from the CD-4 pad in 2006.
In 2014, ConocoPhillips drilled only one Alpine well: CD4-93, which the company completed into the Alpine A sands in November 2014. The remainder of the development efforts planned for the Colville River unit over the next few years will be at satellites.
ConocoPhillips currently uses miscible-water-alternating-gas flooding as the primary enhanced oil recovery technique at Alpine. The company fracture stimulated three Alpine wells in 2014, which resulted in “an appreciable production rate increase,” according to the company. As a result, it plans to use the technique on two Alpine wells this year.
Under current Alaska Oil and Gas Conservation Commission definitions, the Alpine oil pool combines the Alpine participating area and the Nanuq Kuparuk participating area.
By the start of 2015, ConocoPhillips had drilled 130 wells into the Alpine, which produced 33,800 barrels per day in 2014 and 389 million total barrels through 2014.
The company brought the Nanuq Kuparuk participating area into production in November 2006. The participating area “continues to exceed expectations,” according to the company. By the start of 2015, the company had drilled nine wells into the Nanuq Kuparuk, which produced 500 bpd in 2014 and 25.5 million total barrels through 2014.
Through July 2015, the two fields had produced more than 421.2 million barrels.
ConocoPhillips drilled the CD4-96 well in 2013. The well originally targeted the Alpine reservoir but problems during drilling forced the company to complete it as a Kuparuk well instead. In 2014, the company sidetracked the well into the original Alpine target.
CD-5
The biggest development effort this year is at CD-5.
After years of regulatory delays, ConocoPhillips recently completed construction of the newest drilling pad at the Colville River unit and is currently drilling development wells.
The company plans to drill six production wells (CD5-03, CD5-04, CD5-05, CD5-09, CD5-10 and CD5-11) and seven injection wells (CD5-01, CD5-02, CD5-06, CD5-07, CD5-08, CD5-12 and CD5-13) into the Alpine A sands from the new pad between mid-2015 and early 2016, according to its most recent plan of development. The CD-5 program also includes two Nanuq-Kuparuk wells: the CD5-314 horizontal producer and the CD5-315 horizontal injector. The company is considering a third well, CD5-SUN3, but said the decision will depend on the results of the first two wells and rig availability.
Using information gleaned from the previous Alpine A sands work, the CD-5 program includes a horizontal pattern MWAG flood in the Alpine A sand for enhanced recovery.
The Colville River unit satellites
From the beginning, the ConocoPhillips-predecessor Phillips Petroleum and its partner Anadarko Petroleum designed the Colville River unit to have “sequential development.”
The idea was to use the large Alpine oil field as an anchor to support development of smaller satellite fields in the vicinity. To date, the partners have developed three satellites - Fiord, Nanuq, Qannik - and are nearing completion on a fourth, Alpine West. As a result of the program, the Colville River unit will also support proposed developments at the eastern edge of the National Petroleum Reserve-Alaska. While Alpine West is managed through the plan of development for the main Alpine field, the other three are managed through separate plans of development associated with the main Alpine field.
Fiord
ConocoPhillips brought Fiord online from the CD-3 pad in August 2006. The Fiord pool includes the Fiord Nechelik participating area and the Fiord Kuparuk participating area.
At the start of 2015, ConocoPhillips had drilled 23 wells into the Fiord Nechelik participating area. The company completed the CD3-316B sidetrack in April 2014 and was planning a single development well into the pool in 2015. The Fiord Nechelik produced 12,100 barrels per day in 2014 and 46.1 million total barrels through 2014.
Through July 2015, Fiord had produced 61.2 million barrels of oil.
At the start of 2015, the company had five active wells in the Fiord Kuparuk participating area and had no plans to drill additional wells in 2015. The Fiord Kuparuk participating area produced 1,400 bpd in 2014 and 12.6 million total barrels through 2014.
The company is planning to fracture stimulate one Fiord well in 2015.
Nanuq
ConocoPhillips brought Nanuq online from the CD-4 pad in December 2006. At of the start of 2015, the company had drilled nine wells into the Nanuq participating area, which produced 1,600 bpd in 2014 and 2.6 million total barrels through 2014.
Through July 2015, Nanuq had produced more than 2.9 million barrels of oil.
The company drilled the CD4-289 development well in late 2014 and brought the well into production in early 2015. The well will be converted into an injector this year.
Qannik
ConocoPhillips brought Qannik online from an expanded CD-2 pad in 2008. At of the start of 2015, the company had drilled nine wells into the Qannik, which produced 1,700 bpd in 2014 and 4.8 million total barrels through 2014. The company drilled no wells at Qannik in 2014, planned none for 2015 and sees no near-term opportunities.
Through July 2015, Qannik had produced 5.2 million barrels of oil.
The Beluga River unit
Richfield Oil Corp., Shell and Standard Oil Company of California discovered the Beluga River gas field on the west side of Cook Inlet in 1962, while drilling for deeper oil.
Production from the field began in 1968 to service the new Chugach Electric Association power plant built nearby. Enstar Natural Gas Co. built a pipeline to Anchorage in 1984.
Through its predecessors ARCO and Phillips, ConocoPhillips became operator of the field in 1986 and currently owns a 33 percent working interest ownership in the field, alongside independent producer Hilcorp Alaska LLC and utility Anchorage Municipal Light & Power. Earlier this year, ConocoPhillips announced plans to sell its Cook Inlet properties but had yet to announce a buyer when The Producers went to print.
ConocoPhillips conducted an expensive development campaign at the field between 2008 and 2012. The program included drilling six wells and upgrading compression in an attempt to improve deliverability. The company appears to be done drilling new wells for the time being and is focusing on smaller maintenance activities to improve performance.
As it enters its 47th year of operation, the legacy Cook Inlet natural gas field is “fully delineated,” according to a recent plan of development from operator ConocoPhillips Alaska Inc. The Sterling reservoir has declined to 25 percent of its original pressure, down from 30 percent a year ago. As would be expected, deliverability has also declined.
Even with those downward trends, though, annual production increased last year. Beluga River produced 25.1 billion cubic feet in 2014, up from 22.4 bcf in 2013, which suggests that some of the maintenance activities at the field are yielding results.
“Field efforts continue to mitigate well declines, find production enhancing opportunities and improve operational safety and reliability in this mature asset,” the company wrote.
Through 2014, Beluga River had 14 producing wells (one less than in 2013), 10 shut-in wells (one more than in 2013) and two disposal wells, according to ConocoPhillips.
Through July 2015, the unit had produced more than 1.3 trillion cubic feet of natural gas.
Maintenance program
In 2015, ConocoPhillips has planned maintenance work on at least eight wells.
Its proposed program includes: installation of artificial lift on 212-35T and 232-26 and, if the work proves to be successful, the evaluation of similar activities on 224-34 and 214-26; installation of a velocity string on 232-23; a fill cleanout on 212-25, milling a plug on 244-23; and swabbing and flow testing 211-03, which could lead to additional work.
Many of these projects were either planned for 2014 or grew out of work begun in 2014.
ConocoPhillips had originally intended to conduct rigged workovers on three wells last year. The company completed its program on 244-23 in May 2014 and 242-04 in September 2014 but suspended work on 224-13 “due to operational issues.” The well is currently a candidate for a sidetrack, which ConocoPhillips would drill in 2016.
The artificial lift installations on 212-35T and 232-26 were originally planned for last year but delayed. The project calls for installing an electric submersible pump on 212-35T and a hydraulic submersible pump on 232-26 sometime early this year. The similar installation being considered for 224-34 follows a recent mechanical integrity test.
The flow testing on 211-03 is a continuation of work conducted in May 2014. The current project includes performing a mechanical integrity test, adding perforations and conducting a swab and flow test with an eye toward adding a flow line back to C pad.
ConocoPhillips evaluated clean-out jobs on 212-25 and 212-35. The 212-35 project was scrapped for now. The 212-25 job remains under evaluation. The company also planned to install a velocity string on 232-23 last year but postponed the project to this summer.
Other projects completed last year include:
•An unsuccessful fishing operation on 211-26 in July 2014.
•A successful clean out of 212-24T in August 2014.
•Re-cylindering of seven wellhead compressors, completed in October 2014.
•Studying a proposal to install a water trunk line at the field. The company ultimately decided to keep studying the project and make a decision no earlier than 2016.
•Studying a proposal to add water storage to an existing DW-2 disposal well. The company ultimately decided that the project was “not necessary at this time.”
•Upgrading water storage capacity at C pad in June 2014.
•Studying but ultimately not commissioning a similar project at E pad.
ConocoPhillips completed turnarounds on five facilities in 2014 - BRWD-1 in April, C pad facilities in April and early May, M pad in May and B pad in May and early June - and other maintenance, repairs and inspections at infrastructure throughout the field.
The North Cook Inlet unit
Pan American Petroleum Corp. discovered the North Cook Inlet Tertiary System Gas Pool in 1962. The offshore field is developed from the Tyonek platform, which connects back to the east side of Cook Inlet and eventually feeds into the Kenai LNG facility.
Today, ConocoPhillips owns the unit outright. North Cook Inlet unit production began in 1969. Through July 2015, the unit had produced nearly 1.9 trillion cubic feet of gas.
As with Beluga River, ConocoPhillips conducted a large development program at North Cook Inlet between 2008 and 2013. The company drilled three wells in 2008 and 2009 and undertook some maintenance and upgrades in 2012 that continued into 2013.
This year, ConocoPhillips performed work on four wells: adding nitrogen lift to A-09 in March, changing out a gas-lift valve at A-14 and B-01A in April and making adjustments to A-13 in August to meet requirements of the U.S. Environmental Protection Agency.
The company also performed a range of maintenance and upgrades on field infrastructure, including installing temporary living quarters, upgrading turbine compressors and performing a summer platform turnaround in August.
In 2016, ConocoPhillips plans to continue an ongoing evaluation of potential rigged workovers or drilling opportunities, with an eye toward a 2017 workover program.
Although ConocoPhillips was marketing the unit (as well as the Beluga River unit) to potential buyers as The Producers went to print, the company intended to retain 100 percent working interest in its Kenai liquefied natural gas export terminal in Nikiski.
Over the past five years, the fortunes of the pioneering operation have swung wildly.
While the facility was the largest in the world when operations began in 1969, larger facilities and facilities closer to East Asian markets gradually overshadowed it. In early 2011, ConocoPhillips and its then-partner Marathon Oil (ConocoPhillips later bought out Marathon to become the sole owner of the facility) announced plans to mothball the facility for lack of sufficient contracts. But they ended up keeping the facility open through 2012 and into 2013 to accommodate an unexpected increase in Asian demand.
ConocoPhillips decided against seeking an extension of its federal export license in early 2013 but said it would consider restarting the facility once local energy needs had been satisfied and also said it would consider alternative uses for the facility, including imports, if necessary. When Hilcorp Alaska LLC contracted with utilities to meet local demand through 2018, the state asked ConocoPhillips to apply for a new export license.
ConocoPhillips acquiesced, and in early 2014 the U.S. Department of Energy issued a license for the company to export as much as 40 billion cubic feet over two years.
The company told the federal regulator it planned to make as many as six shipments to Pacific Rim customers between May and October 2015. The company also made two deliveries to Fairbanks distribution utility Fairbanks Natural Gas LLC in the first half of the year, according to the federal filing. In addition to shipments, ConocoPhillips undertook a limited maintenance campaign to clean, re-coat and re-seal its storage tanks.
Although ConocoPhillips continues to supply the facility using the North Cook Inlet unit, the export terminal has also begun accepting volumes from other suppliers in the region.
