2016: The Year Ahead
It’s going to be another busy year for the $14-billion Hebron project.
The ancillaries – the helideck and two lifeboat stations built by C&W Offshore in Bay Bulls – were shipped to Bull Arm in January. The utilities processing module (UPM), which is being built by Hyundai Heavy Industries in Ulsan, South Korea, is scheduled to arrive this year.
With the arrival of the UPM, the integration and commissioning of all the topsides modules and ancillaries will begin with the installation of the drilling support module and the derrick equipment set. Then, the living quarters module, helideck and west lifeboat station will be integrated with the UPM, followed by the east lifeboat station and the flare boom.
This summer, lead Hebron partner ExxonMobil expects to install the pipeline and bases for the offshore loading system (OLS), which will pump crude from the storage tanks of the Hebron platform’s storage cells to shuttle tankers.
ExxonMobil says the final concrete slip-form operation for the gravity base structure (GBS) brought the center shaft to its final height of approximately 120 metres.
Tow-out of the completed Hebron platform to the Grand Banks oilfield is scheduled for 2017. First oil is expected in late 2017.
Statoil Canada expects to continue its Flemish Pass drilling program until this spring. Since spudding the first well in November 2014, the West Hercules rig has drilled 11 exploration and appraisal wells, including three sidetracks, for Statoil in the Flemish Pass and Northeast Newfoundland Shelf.
So far, all but two of the wells have been drilled in Exploration Licence (EL) 1112, where Statoil and partner Husky Energy made the Bay du Nord discovery estimated to contain up to 600 million barrels of light crude in 2013.
Statoil targeted one well each in EL 1123 and EL 1126. In EL 1123, Statoil is partnered with Shell, which recently acquired BG International’s stake in the licence once held by Repsol. In EL 1126, Statoil is partnered with Chevron Canada (40 per cent) and Shell (10 per cent).
Statoil is prepping for a 3D seismic survey of its exploration licences in the Flemish Pass. Scheduled to take place sometime between May and September of this year, the survey will cover 5,000 square kilometres of seabed. The exact location of the survey has yet to be determined.
Statoil has also acquired an interest in six of the seven new exploration licences issued in the Flemish Pass for total bids of more than $1.2 billion late last year. The company is the operator of five of those new ELs issued in January.
The West Hercules rig is under contract to Statoil until January 2017, according to Seadrill’s fleet status report issued November 24, 2015.
Husky Energy expects the semi-submersible drill rig Henry Goodrich to return to the Newfoundland and Labrador offshore by mid-year. The Henry Goodrich is contracted to Husky from May of this year to May 2017, according to a Transocean fleet status report issued February 11.
Husky announced the two-year contract for the rig in December 2015. It will be primarily used for ongoing development drilling at the White Rose oilfield and satellite fields, including the North Amethyst-Hibernia well and the next series of wells at South White Rose, which started production last year.
Production from the North Amethyst-Hibernia zone, which is located deep beneath the White Rose oilfield, had been scheduled for late 2015. That production timeline was revised to 2016-17 following the September 2015 cancellation of the contract for the newbuild rig, West Mira, by Seadrill Ltd.
The SeaRose floating production, storage and offloading (FPSO) vessel is scheduled for a 20-day maintenance turnaround during the third quarter of this year.
Husky continues to evaluate both a wellhead platform and subsea tieback as development options for the West White Rose satellite field. In December 2014, the company announced it was deferring its investment decision in West White Rose to reduce costs and reassess the development options. Husky has since said production from the satellite is expected in the “2020-plus timeframe.”
The West Aquarius rig will continue drilling wells this year for Hibernia Southern Extension (HSE). The subsea tieback consists of up to five production wells drilled from the Hibernia GBS and up to six water-injector wells drilled by the West Aquarius. To date, three of the HSE six water-injector wells have been drilled.
The $2-billion expansion will also enable additional wells to further develop the Ben Nevis-Avalon reservoir, which has been in production since 2000.
Hibernia Management and Development Co. (HMDC) also plans to spend six months upgrading the two drill rigs on the Hibernia platform starting in July. Both rigs will be out of service until the end of December. HMDC says the upgrades are necessary because the rigs will be in use longer than originally anticipated when the Hibernia platform was built. The oilfield is expected to continue production until 2040 due to increased Hibernia reserves. Oil production at Hibernia will continue during the rig upgrades.
The West Aquarius is under contract to HMDC until April 2017, according to Seadrill’s fleet status report issued November 24, 2015.
Suncor Energy’s main activities this year for the Terra Nova oilfield will be ongoing maintenance. The Terra Nova FPSO is scheduled for a four-week maintenance turnaround starting in mid-May.
Suncor does not currently have a drill rig contract and the company says no drilling is planned this year in offshore Newfoundland. The company says it is prepping for a drilling program in 2017 and is looking for a rig to carry out this work. Suncor has issued expressions of interest (EOIs) to procure long-lead equipment items for the drilling program.
Suncor is also looking for other offshore services. One EOI, which closed in December, indicates the company is looking for dive support vessel, construction support vessel and light well intervention vessel services. The scope of the work includes additions to an excavated drill centre consisting of flexible jumper, flying leads, connectors and Christmas tree flowlines, along with light well interventions on two to six wells.
In 2014, Suncor conducted well interventions at Terra Nova using the Skandi Constructor.
Nalcor Energy Oil and Gas
By the end of 2015, Nalcor Energy Oil and Gas and its international partners TGS and PGS had acquired 110,000 line kilometres of 2D multi-client seismic data throughout the Newfoundland and Labrador offshore area. This seismic survey program, which includes marketing the multi-client data to global oil & gas companies, has been ongoing since 2011.
Early this year, Nalcor expects to issue a second resource assessment in advance of the 2016 licence round. A round is scheduled in the Jeanne d’Arc basin.
In the fall of 2015, Nalcor and the provincial government released the first in a planned series of resource assessments by Beicip-Franlab. It showed the hydrocarbon potential in 11 parcels up for bids last year in the Flemish Pass Basin to be 12 billion barrels of oil and 113 trillion cubic feet of natural gas.
In November 2015, combined bids from oil & gas companies totalled more than $1.2 billion for the exploration rights to seven of the 11 parcels up for bids in the Flemish Pass.
Land tenure activity
In mid-January, the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) issued seven licences to oil & gas companies that bid successfully in last year’s land sale in the Flemish Pass:
EL 1138: Chevron Canada (35 per cent), Statoil (35 per cent) and U.K.-based BG International, which was acquired by Shell (30 per cent);
EL1139: Statoil (40 per cent), ExxonMobil (35 per cent) and BG International (25 per cent);
EL 1140:Statoil (34 per cent), ExxonMobil (33 per cent) and BP Canada (33 per cent);
EL 1141: Statoil (34 per cent), ExxonMobil (33 per cent) and BP Canada (33 per cent);
EL 1142: Statoil (50 per cent) and BP Canada (50 per cent);
EL 1143: Statoil (100 per cent);
EL 1144: Nexen Energy (100 per cent).
Also in January, the CNLOPB issued calls for nominations in three offshore regions:
North Eastern Newfoundland Region – The deadline for nomination of areas of interest is April 27. Under the four-year land tenure cycle for this region, a call for bids is scheduled for August 2019 and bids close November 2020.
Southern Newfoundland Region – The deadline for nomination of areas of interest is April 27. The region, which includes the Laurentian sub-basin, is under the four-year land tenure cycle. A call for bids is scheduled for August 2019 and bids will close November 2020.
Labrador South Region: Sector NL01-LS – The deadline for the nomination of parcels is March 16. Nominations will be considered in a call for bids issued later this year. Bids are scheduled to close in late 2017.
Scheduled land tenure activity is also ongoing in other offshore regions:
Jeanne d’Arc Region NL15-01JDA: Parcels that were nominated by the October 20, 2015 deadline will be considered for a call for bids in 2016. The call for bids will be known as NL16-01JDA.
South Eastern Newfoundland Region: In June 2015, the board identified Sector NL01-SEN, the first sector identified in this offshore region. This sector includes the Carson Basin. Interested parties will have an opportunity to nominate parcels in early 2018. A call for bids is anticipated in 2019.
Labrador South Region: In June 2015, a second sector was identified in this offshore region, Sector NL02-LS. Sectors are identified at the beginning of the land tenure cycle. Oil & gas companies will have an opportunity to nominate parcels in this sector in early 2018. A call for bids is expected in the summer of 2018, and bids close in the fall of 2019.
Eastern Newfoundland Region: In February 2015, the offshore board identified Sector NL02-EN in this region, which includes the Flemish Pass and the Orphan Basin. The next step is a call for the nomination of parcels within the sector. A call for bids is due in the spring of this year and bids are expected later in the year.
Polarcus U.K. Ltd. filed a project description with the C-NLOPB in December 2015 to conduct 2D, 3D and 4D seismic surveys spanning more than 308,000 square kilometres in the Eastern Newfoundland offshore region between 2016 and 2022. The proposed survey area includes the Jeanne d’Arc Basin, Flemish Pass and Orphan Basin. A C-NLOPB environmental assessment is ongoing.
Seitel Canada Inc. filed a project description with the C-NLOPB in November 2015 to conduct 2D, 3D and 4D seismic surveys over most of the Newfoundland and Labrador offshore from northern Labrador to the French baguette off the south coast to the southern Grand Banks, and eastward beyond the Flemish Pass. Surveys would take place in the 2016-2025 timeframe. A C-NLOPB environmental assessment is ongoing.
CCG Services Canada filed a project description with the C-NLOPB in October 2015 to conduct 2D, 3D and 4D seismic surveys in the 2016-2025 timeframe. The proposed survey area includes portions of the Northern and Southern Grand Banks, Northeast Slope of Newfoundland, Flemish Pass and Orphan Basin.
In January, the C-NLOPB announced a one-year extension for EL 1105, which is held by Corridor Resources Inc. The licence area contains the Old Harry Prospect in the Gulf of St. Lawrence where Corridor has proposed a one-well drilling program. The EL is now scheduled to expire January 14, 2017, unless the company drills a well that would extend the licence period.
The C-NLOPB also waived the $1-million deposit that is usually required to extend the term of a licence, stating: “In consideration of regulatory factors that have resulted in Corridor Resources encountering delays in drilling a validation well in the final year of its nine-year licence term, the board has removed the requirement for a drilling deposit. The board will announce plans for consultations on the environmental assessment with aboriginal groups and with the public at a later date.”
Black Spruce Exploration also received a one-year extension on EL 1120, which contains the Lark Harbour prospect. That licence now expires in January 2017.
“Black Spruce Exploration received an extension to (the licence period) because onshore-to-offshore drilling activities require co-ordination with the board’s provincial government counterparts, as the board does not have jurisdiction for the onshore portion of such activities,” a C-NLOPB spokesman told The Telegram on January 19.
Shell Canada is in the midst of a two-well exploration drilling program in the Shelburne Basin located about 350 kilometres south of Halifax, N.S. The drillship Stena IceMAX spud the first well, known as Cheshire L-97, on October 23, 2015, and drilling wrapped up early this year. The company has applied for authorization to drill the second well dubbed Monterey Jack. Shell holds a 50 per cent interest in six exploration licences in the Shelburne Basin. The company is partnered with ConocoPhillips (30 per cent) and Suncor Energy (20 per cent). Shell also owns a 31 per cent interest in the Sable Offshore Energy Project (SOEP).
ExxonMobil Canada has said it could begin plugging wells at the Sable Offshore Energy Project as early as 2017, but a firm timeline has yet to be announced for decommissioning the natural gas field that started production in 1999. The field was expected to have a 25-year lifespan, but in recent years natural gas production has dwindled.
BP Canada has issued an EOI for a baseline environmental sample survey of the seabed in the Scotian Basin where it operates four ELs. The company has said it plans to start drilling in the latter half of 2017 and an environmental assessment is ongoing. BP acquired 7,090 square kilometres of wide azimuth 3D data two years after acquiring the deepwater exploration licences southwest of Sable Island in 2012. The company is partnered with U.S.-based Hess Corp. (40 per cent) and Australian-based Woodside Petroleum (20 per cent).
The Deep Panuke natural gas field resumed production in late October following five months of inactivity. Last year, Encana Corp. announced the field would become a seasonal operation – producing during the winter when natural gas prices are higher and shutting in during the summer months when demand and prices decline. The move is expected to increase the life of Deep Panuke, which has been producing high rates of water. Encana also cut its remaining reserve estimate for the field by more than half – from 200 billion cubic feet to 80 billion cubic feet. Deep Panuke started production in 2013.