29-05-01 Offshore Eastern Canada has been long recognized as one of the world's most hydrocarbon-rich areas, but low oil and gas prices have discouraged investors from attempting to harvest product from the icy depths of the North Atlantic and the Gulf of St. Lawrence. During the last decade however, a steady decline in new fuel sources and skyrocketing prices have prompted companies to take a closer look at these difficult areas. The result has been a rapidly increasing oil and gas industry that can't move fast enough to suit an area plagued with economic hard times.
Quebec, Prince Edward Island, New Brunswick, Nova Scotia and Newfoundland are all in a hydrocarbon "hot spot", but the vast majority of activity is taking place offshore Newfoundland and Nova Scotia. In addition to the well-established Sable and Hibernia projects, several new offshore initiatives are in the early stages. A trend toward onshore exploration is also developing, with production expected to begin as early as this fall.

When Newfoundland's Hibernia oil field began producing in November of 1997, it was Canada's first major offshore oil project to start in a decade. The project's first well broke Canadian records. It's success was soon heralded when, in Feb. of 1999 Hibernia increased oil production to more than 100,000 bpd following the start-up of a new gas injection well. Production had been restricted to an average of 68,000 bpd because of flaring constraints imposed by the Canada-Newfoundland Offshore Petroleum Board. Now, less than four years later, peak production rates reach 180,000 bpd.
Hibernia is located in a water depth of about 80 metres (262 feet), in the Jeanne d'Arc Basin, 315 km (195 miles) east of St. John's, Newfoundland. The two main reservoirs are Hibernia, located at an average depth of 3700 metres (12,136 feet) and Ben Nevis-Avalon, located at 2400 metres (7872 feet).

Hibernia oil is a light sweet crude with a density of about 32 degrees to 34 degrees API and a sulphur content by weight of 0.4 % to 0.6%. The field contains approximately 3 bn barrels of oil in place, with recoverable reserves estimated to be 615 mm barrel. Oil is stored sub-sea, in the Hibernia Gravity Base Structure (GBS).
The crude-oil is then shipped via double-hulled tankers directly to market, or to Whiffen Head, Newfoundland, where it is shipped by additional tankers to both US and Canadian customers. The enhanced Gorilla-Class rig, called Hibernia, was specifically designed for the harsh environment in which it manages simultaneous drilling and production operations. It is recognized as one of the most technologically-advanced mobile platforms in the world.
The concrete production platform has a 15 metres (49 feet) thick ice belt, and a 1.4 metres (4.6 feet) thick ice wall, equipped with 16 concrete teeth and a system of support-walls able to withstand a collision with a 1-mm ton iceberg. There are more than 30 GBS platforms operating in the North Sea, but none are designed to resist the impact of sea ice and icebergs.
Hibernia is owned by Mobil (33.125 %); Chevron Canada Resources (26.875 %); PetroCanada (20 %); Canada Hibernia Holding Corporation (8.5 %); Murphy Oil (6.5 %) and Norsk Hydro (5 %).

Canada's soon-to-be second major oil field development is the Terra Nova project, located 350 km (254 miles) east-southeast of St. John's, Newfoundland and southeast of Hibernia. The Terra Nova Floating Production, Storage and Offloading (FPSO) facility is currently in Bull Arm, Newfoundland undergoing hook-up and commissioning. Terra Nova is set to begin production late this year.
Like Hibernia, the Terra Nova project has to be specially designed to withstand the harshest of weather conditions, including an average wind speed of 35 km (22 miles) per hour; water temperatures ranging from 1.7 to 15.4 degrees Celsius (35-60 Fahrenheit); seasonal fog, sea ice and icebergs. Terra Nova has an estimated 370 mm barrels of recoverable crude oil and a production capacity of 110,000 bpd field life.
Terra Nova is owned by PetroCanada 33.99 %; Mobil Oil Canada Properties 22.00 %; Husky Oil Operations 12.51 %; Norsk Hydro Canada Oil & Gas 15.00 %; Murphy Oil Company 12.00 %; Mosbacher Operating 3.50 % and Chevron Canada Resources 1.00 %.
March of last year, Husky Oil and joint-venture partner PetroCanada proposed development of the White Rose oilfield, located in the Jeanne d'Arc Basin, 360 km (223 miles) east of St. John's. The field consists of both oil and gas pools with an estimated 36 mm cm (230 mm barrels) of recoverable oil. Output is expected to be approximately 100,000 bpd. Projected first oil is 2003-2004.

The Sable Offshore Energy project was Canada's first offshore natural gas project. It began production on Dec. 31, 1999 and is set to start phase two in 2004. The Sable project lies approximately 160-300 km (100-186 miles) southeast off Nova Scotia's east coast, 10-40 km north of the Scotian Shelf. It's 230 km (140 miles) from Halifax to the Thebaud main production platform.
Production levels averaging 500mm cfpd are expected throughout the project, which has a life expectancy of 25 years. Since first gas, it has produced approximately 3.5 bn cm of natural gas, from 6 fields. Established reserves of 171 bn cm (6 tcf) have been confirmed and estimated recoverable reserves of 99 bn cm (3.5 tcf). In addition to gas, the project also produces approximately 7,100 barrels of propane, 4,000 barrels of butane and 11,000 bpd of condensate.
One of the biggest challenges developers of the Sable project faced was laying almost 300 km (186 miles) of pipeline beneath the North Atlantic. The pipeline joins the Thebaud offshore central processing platform with the Goldboro gas plant onshore in Nova Scotia. It had to be designed to withstand the strong ocean currents, fishing trawler nets, ship anchors, and 15 to 150 tons of water pressure it would encounter in the area. Every precaution had to be taken to ensure stability of the pipes, which measure 20, 30 and 66 centimetres in diameter and about 37 feet in length.

On May 4, El Paso and Marathon Oil announced intentions to conduct a feasibility study for a second sub sea pipeline that would connect the Sable project to the north-eastern US. Other major industry players have also expressed a similar interest in such a project. While it made local headlines during the start-up phase of the project, Sable is now quietly focusing on maximizing its production efforts and ensuring the process runs smoothly in the coming years.
The majority of gas produced by Sable is sold to US customers, while both Nova Scotia and New Brunswick struggle to develop a lateral pipeline system to deliver the product locally.
Project owners are: Mobil Oil Canada Properties (50.8 %), Shell Canada (31.3 %), Imperial Oil Resources (9 %), Nova Scotia Resources (8.4 %) and Mosbacher Operating (.5 %).
In February, 2000 PanCanadian Petroleum announced a major discovery on the Scotian Shelf, approximately 250 km (155 miles) south-east of Halifax. The discovery was made directly beneath Nova Scotia Resource's now-defunct Panuke oil field. Exploration wells maxed-out PanCanadian's equipment when each well flowed at 55 mm cfpd of natural gas. The Sable project well rates are 50-100 mm cfpd, so it's not unreasonable to expect another project of the same magnitude.
The Panuke P-3C well intersected net pay at 230 feet and the second well, Panuke 1-1 bn intersected net pay at more than 100 feet. Investors were even more encouraged when a third well, M-79A, flowed at an average 63 mm cfpd of natural gas. These rates were limited by the downhole configuration of the test string.
The well was drilled to a depth of 15,105 feet with a horizontal sidetrack in the main reservoir section that encountered 360 feet of net pay. Preliminary development and planning for the project have started, and production should begin in 2005.
The company is also conducting surveys on other offshore parcels in Eastern Canada. PanCanadian hold 15 blocks (exploration licenses) off Nova Scotia, covering more than 4 mmgross acres.

Eastern Canada's boom in offshore oil and gas production has resulted in the inevitable turn of interest to onshore developments. Although several companies, both large and small, have holdings throughout the area, none are yet producing. Indicators suggest that most of the provinces will have actual onshore production by the fall of 2001.
Five companies are currently exploring for oil and gas on 1.6 mm hectares of land on mainland Nova Scotia. Although exploration onshore has been going on for more than 140 years in Nova Scotia, there has never been a significant discovery.
In December 2000, PanCanadian Petroleum announced its intention to spend $ 3.95 mm (Canadian) exploring for coal-bed methane in the Stellarton, Nova Scotia area, near the site of the Westray coal mine disaster, where 26 men lost their lives in 1992. The exploration zone is outside of this area. Amvest Nova Scotia has been exploring for coal-bed methane in Nova Scotia since 1994 and it recently joined forces with Nova Scotia Power to explore in the Westray mine area, as well.

One of the most persistent players in onshore petroleum exploration of Eastern Canada has been Corridor Resources. Since 1995 the junior oil and gas exploration company expanded to holdings of 195,000 acres, to 5,650,109 net acres of petroleum exploration licenses in New Brunswick, Quebec and Prince Edward Island.
On April 16, the company announced that flow testing of the McCully No. 2 well, 12 km northeast of Sussex, New Brunswick, has been completed. The test reached a stabilized natural gas flow rate of 2.2 mm cfpd at a flowing tubing head pressure of 2,100 psi following a three-day flow period. Indicators show gas being produced from several sands over a 400 metre gross interval, including the sand that is the main productive zone in the adjacent McCully No. 1 well.
Initial analysis indicated that the well has a potential gas flow of 4.1 mm cfpd at the design separator pressure of 400 psi. The McCully No. 2 well is currently shut-in for pressure build-up analysis. The well is 50/50 joint venture partnership with the Potash Corporation of Saskatchewan, with Corridor acting as the operator. Corridor expects to be producing commercially from the McCully project by the fall of 2001.

Newfoundland, Prince Edward Island and Quebec are all expected to have some onshore production in place by the end of 2001. Preliminary wells and testing have been completed in each of these three provinces.