Deep Panuke takes a 'time out'
There are 59 exploration licenses offshore Nova Scotia that carry commitments to spend $985 million between now and 2007, according to the Nova Scotia Petroleum Directorate. Nova Scotia's offshore is roughly the same size as the Gulf of Mexico, but there have been fewer than 200 wells drilled in this extremely prospective area.
As a fairly "new" region, Atlantic Canada is attracting a lot of interest from exploration companies, a number of which are investing considerable sums to drill the area.
Marathon in for the long haul
Though discovery of known reserves from the offshore Nova Scotia basin is comparatively modest to date, exploration is at a relatively early stage. According to Philip Behrman, senior vice president of worldwide exploration for Marathon Oil Corp., Nova Scotia is one of Marathon's key exploration areas.
New sources of gas are needed, Behrman said.
"The most likely place to fill the gap is offshore Nova Scotia," he said.
The Nova Scotia offshore is relatively unexplored, and there is great potential.
In November 2001, Marathon added two exploration tracts to its holdings offshore Nova Scotia. That acquisition increased Marathon's interests offshore Nova Scotia to five exploration licenses, covering 1.92 million acres. The company lost no time getting down to drilling, though initially, the deepwater did not bring success.
On April 9, 2002, Marathon plugged and abandoned the first deepwater well ever drilled offshore Nova Scotia. The company shut in the Annapolis well on exploration license 2377 following a gas kick. But only nine days after B-24 was shut in, the company spudded Annapolis G-24. The second Annapolis well was drilled to a total depth of 20,282 ft, where it hit gas.
After reaching this milestone, Marathon is examining lessons learned from last year's drilling program, making calibrated decisions for future drilling, and is looking for ways to substantially reduce drilling costs, Behrman said.
Marathon operates the Annapolis prospect and is also operator of the adjacent leases, holding 50% interest in Empire block and 75% in the Cortland block. Marathon has identified 10 prospects on the three leases and has plans to drill one or two wells this year, Behrman said. The cumulative potential for the area has been set at 5-10 tcf.
Marathon's 2003 international upstream spending is budgeted at $717 million, some of which will be spent on shooting and processing new seismic surveys, which will take a full year. Once seismic analysis is complete, locations will be selected for two or three wells, most likely in the Cortland and Empire blocks, in 2004, said Behrman.
Marathon is well positioned in Atlantic Canada and is vigorously chasing drilling opportunities. The company has already said that one wildcat well will be drilled off Nova Scotia in the near future. There are also indications that an Annapolis appraisal well will be drilled this year.
Others in the mix
Mike Coolen, director of East Coast operations for Canadian Superior, is optimistic about his company's prospects. Canadian Superior is going through the regulatory process for drilling. And while that process moves forward, the company is investing its time reviewing and analyzing seismic data for the Mariner well.
"We've gone out and done our seismic work and are really hard at it getting ready. We're aggressively pursuing our acreage," Coolen said.
Canadian Superior teamed up with El Paso to drill Canadian Superior's Marquis block last year. Although the well did not find commercial hydrocarbons, the company announced that the well results were encouraging, with the well encountering porosity and confirming Abenaki reef reservoir on the prospect. At that time, Canadian Superior indicated that it planned to drill again on Marquis as soon as possible.
The current plan is one well for Mariner in the next few months and one for Marquis later in the year. Of course, drilling results could alter those plans, Coolen said.
"We're targetting a second well, most likely in Marquis," Coolen said, "but that could change if Mariner is a success. The next well could be an appraisal well instead." Canadian Superior also plans to drill its Mayflower deepwater prospect in the near future. At present, the company is planning a seismic survey to be gathered in the coming months over the prospect and is hopeful that the results will be promising.
"We're looking forward to getting approval for our deepwater block," Coolen said.
The offshore area is dramatically underexplored, and the potential is still high for a sizable find. That keeps spirits up for companies with promising acrage.
"It could be quite an exciting year off Nova Scotia," Coolen said.
Imperial Oil Ltd. laid the foundation for a drilling campaign nearly two years ago. In May 2001, Imperial acquired an interest in three deepwater exploration blocks. The three exploration blocks (license numbers 2381, 2382, and 2385) cover 474,400 hectares, about 200 km offshore. With this agreement, Imperial assumed a work commitment proportional to its one-sixth interest – about $15.5 million over the term of the license.
In addition to the acreage bought into in 2001, Imperial holds a 100% interest and operates two additional deepwater blocks totaling 225,660 hectares. The work commitment for these blocks totals $100 million.
Kerr-McGee is also a large landholder in Nova Scotia's offshore. The company owns interests ranging from 50% to 100% in seven blocks totaling 3 million acres. Over half of that acreage, 1.8 million acres, is made up of three offshore deepwater licenses in which Kerr-McGee was awarded 100% interest in November 2000. The licenses are in water depths ranging from 350 ft to 10,000 ft.
Shell is doing environmental work on its deepwater acreage following the Onondaga B-84 well last May. Onondaga B-84 was drilled south of Sable Island near the Sable Offshore Energy Project facilities. The well was suspended as a potential natural gas producer. It confirmed the presence of sweet, hydro-pressured gas and successfully delineated the previous discovery. The primary objective of the B-84 well, however, was to evaluate a previously untested deeper section identified from more recent seismic surveys. The well encountered indications of gas throughout the deeper interval and some potential reservoir sections, but overall reservoir development was insufficient to warrant production testing. The well was not drilled to its intended total depth, which was a disappointment to Shell, which hoped to confirm a larger natural gas accumulation in the deeper section.
Shell holds an interest in nearly 900,000 hectares of exploration acreage in Atlantic Canada as well as 31.3% of the Sable Offshore Energy Project offshore assets.
Chevron Canada Resources followed Marathon into the deepwater in May of last year with the Newburn H-23 well on exploration license EL 2359 100 km southwest of Sable Island in 1,000 m of water. Drilling was suspended on Newburn at 6,070 m, 330 m short of its target depth. The company said it had collected significant well data to guide its next attempt in the area.
Newburn was followed by EnCana's Torbrook C-15 in mid November. Ocean Rig's Eirik Raude semisubmersible drilled the Torbrook C-15 well in 1,686 m of water 200 km southwest of Sable Island. No commercial reserves were reported for the well.
Deep Panuke on ice
While exploration moves forward, the largest offshore development project in the works has come to a halt. In mid February, EnCana, the second-largest landholder on the Scotian shelf, asked federal and provincial regulators for a "time out" in the regulatory approval process for the Deep Panuke gas project. Deep Panuke, in which the company owns 100% interest, is 250 km southeast of Halifax.
The company's board of directors approved the start of commercial development activities for the Deep Panuke offshore natural gas field in February 2001. At that time, startup was scheduled for early 2005. EnCana filed development applications with the Canada-Nova Scotia Offshore Petroleum Board (Cnsopb) and Canada's National Energy Board on March 1, 2002.
Deep Panuke was to provide sustained production of 400 MMcf/d of natural gas from reserves of 1 tcf over 8-12 years. The successful implementation of the Deep Panuke project was expected to facilitate further natural gas development offshore Nova Scotia.
Treated gas was to be delivered via a pipeline to be constructed from the field to shore, where it would connect with Maritimes & Northeast Pipeline's main line at Goldboro. The 1,051-km pipeline crosses the Canada/US border in New Brunswick and terminates in Dracut, Massachusetts.
EnCana has concerns that the initial development plan may not be the most appropriate fit for the current state of gas development in the region.
"Many things have changed since we first designed the Deep Panuke project," said Gwyn Morgan, EnCana's president and CEO.
According to EnCana, the delay announced in February will allow a more complete examination of overall market options in the Maritime region.
"We are looking to make Deep Panuke a better project, one that provides strong, sustainable financial returns over a longer period of time," Morgan said.
EnCana has requested an adjournment of the regulatory approval process from the Cnsopb and NEB. The good news is that the company expects to be able to apprise regulators of the planned enhancements for the Deep Panuke project by the end of 2003.
"This pause in the process also provides industry with extra time to discover more commercial reserves. We have additional exploration drilling planned this year for the Scotian shelf," Morgan said.
Late last year, the company voiced general plans for as many as three shallow-water wells on the Scotian shelf this year. As recently as January 2003, the company had plans to drill eight to 15 wells in Atlantic Canada over the next three to eight years. So far, however, no specific drilling schedules have been made available.
There have been many seismic surveys gathered over Nova Scotia's offshore in the last two years. According to Cnsopb CEO Jim Dickey, there were seven seismic programs in 2001 and three in 2002. There could be as many as five this year. The data is filed in Dartmouth, where it remains private for two years, after which is made publicly available.
"Mother Nature does not yield her treasures easily," Dickey said. But the potential for those treasures is high enough that exploration companies will continue to take the risks to find them.
Sable Offshore Energy Project
The Sable Offshore Energy Project lies near Sable Island, 10 to 40 km north of the edge of the Scotian shelf, in water depths ranging from 20 to 80 m. The project consists of six gas fields (Venture, South Venture, Thebaud, North Triumph, Glenelg, and Alma) that contain a combined 3.5 tcf of recoverable gas reserves.
The first phase of the project comprised 12 wells, drilled in the Thebaud, Venture, and North Triumph fields in 1999. Thebaud is used as the gas-gathering hub, with North Triumph and Venture acting as satellite platforms and feeding into Thebaud. The North Triumph and Venture platforms were built as unmanned facilities.
Infield pipelines ranging from 5 to 55 km link the platforms to the Thebaud hub. The gas and natural gas liquids from Sable Island then flow through a two-phase subsea pipeline from Thebaud to onshore facilities. Production at the end of 2002 averaged 550 MMcf/d of gas and 20,000 b/d of natural gas liquids
A decision by Sable project owners on whether to proceed with the proposed South Venture development was to be made in early 2003. South Venture was included in Sable's development plan application, which was approved in 1997. Pending owner approval, the South Venture platform would begin operations in 2004. In addition to South Venture, the Tier 2 fields are Alma, scheduled to come onstream in late 2003, and Glenelg.
SOEP has not been without problems, however. Based on technical reviews completed at the end of 2002, Shell revised its estimate of gas reserves for the SOEP fields downward to 700 bcf. Evidently, more significant infill drilling and compression will be needed to maintain production and recover remaining reserves from the Tier I fields. ExxonMobil, which operates the project, has already made plans for an 8,000-metric-ton compression module to increase field production.
ExxonMobil Canada owns 50.8% of the Sable project, with partners Shell Canada 31.3%, Imperial Oil Resources 9%, Emera Offshore Inc. 8.4%, and Mosbacher Operating Ltd. 0.5%.