OFFSHORE CANADA

Nova Scotia and Newfoundland are enjoying their most significant period of investment since World War II. The provinces are finally reaping the benefits of their offshore oil and gas resources, with approximately 77% of their investments during the past five years arising from the energy sector, says Elizabeth Beale, the Atlantic Provinces Economic Council's president and chief economist, in a recent report. Growth rates in the provinces, which have traditionally lagged the rest of Canada, have jumped above national averages. Energy is now a leading export of Atlantic Canada. "In Newfoundland and Labrador, 11% of merchandize export values arise from crude oil, while in Nova Scotia, natural gas makes up 18% of total exports," says Beale. Offshore Canada's oil and gas industry is now on firm footing, and all indications are that it is becoming a prominent source area for North America's energy needs. In Nova Scotia, natural gas is a booming business these days, with a major project on production, another large-scale development under way and an exciting deepwater discovery. The Scotian Basin's attraction lies in its similarity to other prolific producing areas. It displays all the classic features of a passive margin, with early rift deposits, extensive evaporites, a well-developed carbonate platform, and giant wedges of clastic sediments. The basin has salt diapers, mini basins, growth faults and overpressured intervals. Parallels to the Gulf of Mexico are obvious, although the Scotian Basin is about half the size of the Gulf and the Scotian sediments are mainly Mesozoic. Too, a mere 200 tests have probed Nova Scotia's potential, while some 50,000 wells have been drilled in the Gulf. Three viable plays, spanning an area about 500 miles long by 200 miles wide and occurring in water depths up to 13,000 feet, are currently being pursued in the Scotian offshore, which is commonly divided into shelf and slope regions. "We've been seeing a wave of activity in the Scotian Basin during the past five years," says Greg Noval, president of Calgary junior Canadian Superior Energy. "We think it is evolving into a world-class basin." The clastic reservoirs of the Sable Delta are the oldest and most prolific play to date. Since offshore exploration began in 1967, a number of large gas fields have been discovered in these sediments in the Sable Sub-basin. Venture Field, the biggest find, contains about 1.5 trillion cubic feet (Tcf) of recoverable reserves; all told, some 5 Tcf of gas has been discovered. Minor oil production was also developed in Panuke and Cohasset fields. Typically, fields in the Sable play are structural traps related to growth faulting. Production is mainly from Cretaceous deltaic and shoreline sandstones, and both overpressured and normally pressured reservoirs exist. Natural gas began flowing from Thebaud, North Triumph and Venture fields, some 180 miles southeast of Halifax, at the close of 1999. Members of the Sable Offshore Energy Project (SOEP) are ExxonMobil Corp., Shell Canada, Imperial Oil Ltd., Mosbacher Operating Ltd. and Emera. Initially, the partners estimated 3.5 Tcf of gas would be recovered from the six fields in the project, which lie in 65 to 260 feet of water. Earlier this year, Shell shaved 300 billion cubic feet (Bcf) from its net booked reserves of 1.1 Tcf for its SOEP interest, saying it had revised its estimates of gas in place. The cut takes the gross recoverable reserves for the project down to 2.6 Tcf. Nonetheless, the three fields currently on production are making more than 550 million cubic feet of gas per day. The partners plan to bring Alma Field, containing reserves of 230 Bcf, online by the end of this year. South Venture Field is slated for development in 2005; Glenelg Field will likely follow that. The aim is to stagger the developments to sustain production levels as the initial fields decline. Gas flows from each field to the Thebaud platform, through a subsea pipeline into an onshore processing plant, then down a 30-inch mainline to markets in New England. Drilling for the Sable play has been light in recent years, mainly confined to SOEP development wells. However, a high-profile deeper-pool test was drilled by Shell Canada in 2001. The Onondaga B-84 targeted deeper zones in Onondaga Field, a Cretaceous pool that was discovered in 1969. Due to problems encountered in a geopressured zone, drilling operations on the new well were stopped at 16,466 feet, about 1,300 feet short of its projected total depth. The upper section of the B-84 well is productive, although the deeper targets that were penetrated were not commercial. The test, owned 100% by Shell, was suspended as a potential gas producer. "At this time, we don't have any fixed plans to produce the well, but it could follow along behind the second phase of the SOEP project," says Doug Gregory, Shell Canada's East Coast operations manager. Jurassic Abenaki The second major play in the Scotian Basin is the Jurassic Abenaki, a carbonate reservoir that trends along the shelf edge in 80 to 160 feet of water. The play was opened in 1999 when EnCana Corp. (previously PanCanadian Petroleum Ltd.) drilled a deeper-pool wildcat at Panuke Field, one of the small Cretaceous oil pools. EnCana had some 1991-vintage 3-D seismic data that had been designed to image the shallow oil pool. The company decided to test an intriguing anomaly by deepening one of its proposed development wells. The 14,370-foot PP-3C discovery tested at 55 million cubic feet per day from 224 feet of reef facies in the Abenaki. Prior to the discovery, only six or seven wells had probed the Jurassic along Nova Scotia's 500-mile-long stretch of the carbonate bank. The 1-Tcf field now contains four wells, each with potentials in excess of 50 million cubic feet per day. The company recently filed a development application for Deep Panuke with the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB). The field gas is slightly sour (0.2%), and processing will be done offshore, after which the treated gas will be shipped via a 24-inch, 110-mile pipeline to the Maritimes & Northeast Pipeline, which delivers gas to the Eastern U.S. EnCana expects to be delivering 400 million cubic feet of gas per day. The total cost of the project is estimated at $1.1 billion. Efforts are now under way to extend the Abenaki play beyond Deep Panuke. In 2001, EnCana drilled the Musquodoboit E-23 (on EL 2360), which gave good indications of gas but was not commercial. "The well told us a lot about the porosity system, which is associated with a hydrothermal event." says John Hogg, EnCana vice president, East Coast, offshore and new ventures exploration division. This past spring, the company shot a large 3-D survey over Panuke that also extended to the northeast and southwest along the trend. "The reef has been enhanced by the dolomitization process, and 3-D seismic is the key to finding porosity in the Jurassic." EnCana also drilled its Queensland M-88 (on the Panuke Block) last year. The well was a high-risk opportunity that targeted a bypassed sand play in front of Panuke. The company found the bypassed sands it was looking for, but the reservoirs did not contain commercial quantities of hydrocarbons. The most recent well in the Jurassic trend was Canadian Superior's Marquis test, drilled on EL 2402 with partner El Paso Oil & Gas Canada. The vertical L-35 found a very thick Abenaki reef sequence with good porosity developed in several zones. A sidetrack, the L-35A, was drilled to attempt to locate the porosity in a structurally higher position. Neither wellbore established the presence of commercial quantities of gas. Canadian Superior's Noval says that the company plans additional drilling updip on the Marquis prospect during 2003. The newest play Mesozoic deepwater turbidites are the newest play offshore Nova Scotia. Exploration has barely begun, but excitement has been stoked by Marathon Oil's announcement of the first substantial discovery. The find demonstrated that Nova Scotia's deepwater province is a working petroleum system, and relieved a common concern among explorers about the presence of source rock. This year, Marathon drilled its Annapolis G-24 on EL 2377, 215 miles south of Halifax in 5,500 feet of water. The well encountered approximately 100 feet of net gas pay over several zones. Murphy Oil, Norsk Hydro and EnCana are Marathon's partners in the block. The well was actually the prospect's second test; Nova Scotia's first deepwater test was the Annapolis B-24, but a gas flow at 11,469 feet caused problems and the wellbore was plugged. The successful redrill G-24, some 1,600 feet from the original location, reached a total depth of 20,282 feet. "We suspended the well for potential to reenter at a later time, and currently we are reevaluating our seismic data and what we've learned from the well," says Philip Behrman, Marathon senior vice president, worldwide exploration. Marathon likes offshore Nova Scotia because it offers multi-Tcf potential. "If we are successful, we believe the economics will be very good," he says. "The reasons are the large prospect sizes, the proximity to Northeast U.S. markets, and Canada's favorable fiscal regime." Furthermore, the government is extremely stable and the regulatory environment is workable. "We can do business and deal with a lot of issues on a win-win basis in Nova Scotia." Marathon evaluated plays throughout the entire Scotian Basin before selecting deepwater Cretaceous turbidites as its main focus. The company looked at depositional models, and zeroed in on the Annapolis area because of its relationship to the thick sands of the Sable Delta. "Finding sand is critical to finding big fields on big structures. We went to the area where we felt the highest likelihood of finding thick sands would be." Another notable deepwater test was drilled this year by ChevronTexaco, on the Mahone Block, EL 2359. The Newburn H-23 was drilled in 3,206 feet of water. Petro-Canada and ConocoPhillips partnered in the project, which was abandoned after reaching a total depth of 19,910 feet. Drilling plans Interest is widespread in Nova Scotia's offshore, as evidenced by the $331.3 million in work expenditure bids that the CNSOPB received for nine offshore blocks in its November 2001 sale. The sale set records both for total bids and for high bids on individual blocks. Currently, the province has 59 exploration licenses carrying work commitments of $980 million; 26 of those licenses are in the deep water. A steady stream of drilling will occur during the next several years, as blocks begin to reach the end of their initial terms. "Offshore Nova Scotia is in another exploratory cycle," said Jim Dickey, chief executive officer of the CNSOPB, speaking at the Canadian Offshore Resources Exhibition and Conference, held in Halifax in October. Since January 2000, there have been 15 exploration wells and three development wells drilled offshore Nova Scotia. In addition, seven seismic programs were shot in 2001, and three more programs have been acquired through October of this year. "In the coming year, we expect about seven new exploration wells to be drilled. There will also be development wells," said Dickey. Nova Scotia's newest deepwater test was under way at press time. EnCana is drilling a Tertiary test at its Torbrook prospect on EL 2384 in 5,500 feet of water. "We're drilling to 7,200 feet below mudline," says Hogg. "We expect to be at total depth around Christmas." The company is using Ocean Rig's Eirik Raude, a new fifth-generation semisubmersible. After the vessel finishes the Torbrook test, it will move to Newfoundland for two tests. When it returns, in late first-quarter or early second-quarter 2003, EnCana will use it for two additional deepwater tests. At the same time, EnCana is planning to drill two to three Jurassic wildcats within a 15- to 20-mile radius of Deep Panuke. "Our jack-up program is focused on finding additional reserves to help support the Deep Panuke project," says Hogg. "We believe that there is a lot of potential to find more hydrocarbons along the edge of the carbonate bank, and we will continue to explore it." Other deepwater tests are in the works as well. Shell Canada operates three deepwater parcels, on behalf of its partners ExxonMobil and ChevronTexaco. Water depths on its blocks vary from 5,000 to 12,000 feet. "We acquired our acreage in the summer of 1999," says Shell's Gregory. "In the summer of 2000 and 2001, we shot 4,500 square kilometers of 3-D seismic. It is the biggest 3-D survey acquired to date off the East Coast." Shell is evaluating the data to select drilling locations; it plans to spud its first well in 2003. Shell is hardly a newcomer to the province-it and Mobil were pioneers in Nova Scotia's early days. "We drilled some deepwater tests off the East Coast back in the 1980s, and we had certain models in mind about where the sands might be," says Gregory. "We think we have a better idea now, and that, combined with the area's resemblance to the Gulf of Mexico and our success in other parts of the world, has encouraged us." Marathon looks to drill one to two wells in 2003, says Behrman. It hasn't yet determined whether it will drill appraisal wells off the Annapolis discovery or exploration wells. The company also plans to shoot an extensive seismic survey over its adjoining Cortland and Empire blocks, EL 2410 and EL 2411, respectively. Marathon has 75% of Cortland and Murphy has 25%; in Empire, the company owns 50% and its partners Murphy and Norsk Hydro each own 25%. "We have identified 10 prospects, with a gross, unrisked potential of 5- to 15 Tcf on our three blocks," says Behrman. ExxonMobil and its partner Talisman Energy will drill on their EL 2379 in the near future. Kerr-McGee owns several licenses, some in partnership with Canadian 88. Meanwhile, BP Canada and Anadarko share interests in EL 2403; they plan to shoot seismic in 2003 on that block. Canadian Superior owns a deepwater block as well, in the southern end of the play. Its Mayflower Block, EL 2406, has three defined turbidite prospects, says Noval. "We estimate the reserves could be 4 Tcf on our block. We plan to shoot seismic in second-quarter 2003, and drill shortly thereafter." A well on Mayflower will cost in the range of $45 million, he adds. A shallow-water test will also be drilled on Canadian Superior's Mariner Block, on EL 2409 just north of Venture Field in the Sable Sub-basin. The firm just completed acquisition of 2,500 kilometers of 2-D seismic over the block. The block, which is offset by six fields, has never been drilled, says Noval. "We just completed a seismic program and we're in the process of selecting a drillsite." This data will be used to finalize a drilling location over a large roll-over anticline prospect, which will be drilled in 2003. Newfoundland oil The economic health of Newfoundland and Labrador has been dramatically buoyed by the development of the Hibernia and Terra Nova fields. The massive projects helped the province rebound from the disastrous collapse of its cod-fishing industry a decade ago. Since offshore drilling began in the 1970s, some 2.4 billion barrels of oil and gas liquids and some 5.6 trillion cubic feet of gas have been discovered in Newfoundland's Grand Banks area. The Grand Banks span an area of 127,000 square miles, covered by relatively shallow water of 200 to 1,000 feet. The Grand Banks basins have often been compared to the North Sea, given the similarities of rifted grabens and associated horsts in both regions. But, the Grand Banks are only about one-sixth the size of the North Sea, and the rocks are of different ages. The Jeanne d'Arc Basin contains all of the discovered oil fields and much of the gas, and is the most heavily explored of the Grand Banks grabens. It is so prolific because it hosts a world-class source rock, the Jurassic Egret, which ranges in thickness from 180 to more than 650 feet. The fields found to date are primarily Mesozoic, with traps formed by Cretaceous-age faults and stratigraphic pinchouts. Hibernia Field inaugurated Canada's offshore production in 1997. The field, discovered in 1979, lays in 260 feet of water some 200 miles offshore St. John's. It is the largest conventional oil field in Canada today. An immense, gravity-base structure, built to withstand the impacts of icebergs, produces oil from Cretaceous sandstones at depths between 7,800 and 12,100 feet. Initially, recoverable reserves were thought to be in the range of 615 million barrels of oil, but Hibernia's reservoirs proved to be more prolific. Today, the Canada-Newfoundland Offshore Petroleum Board (C-NOPB) reports recoverable reserves of 1.03 billion barrels of oil and natural gas liquids, plus 1.3 Tcf of gas. According to the C-NOPB, Hibernia produced more than 200,000 barrels of oil per day in August; cumulative production currently stands at 207 million barrels of oil. Produced gas and water are reinjected into the field's reservoirs for pressure maintenance and the oil is transported to shore via shuttle tankers. Partners in Hibernia are ExxonMobil, ChevronTexaco, Petro-Canada, Canadian Hibernia Holding Co., Murphy and Norsk Hydro. Terra Nova, White Rose Newfoundland's second completed project was Terra Nova, about 21 miles southeast of Hibernia. The field, discovered in 1984, contains recoverable reserves estimated at 420 million barrels of oil and gas liquids and 269 Bcf of gas. First oil flowed in January 2002 from a floating production, storage and offloading (FPSO) facility. Presently, Terra Nova is producing 120,000 barrels of oil per day. To date, 10 wells have been drilled in the field. Terra Nova's owners are Petro-Canada, ExxonMobil, Husky Oil, Norsk Hydro, Murphy Oil, Mosbacher Operating and ChevronTexaco. The project was groundbreaking-it hosted the first FPSO vessel to operate in North American waters, and the first in the world deployed in a region prone to icebergs and pack ice. The vessel's hull was specially strengthened for the North Atlantic conditions. The project also pioneered glory holes, which are depressions in the seabed that protect the wellheads and equipment from scouring icebergs. Now, a third project is in development. Husky Oil's White Rose Field was discovered in 1988 about 50 miles east of Hibernia. It contains estimated proven and probable reserves of 379 million barrels of oil and gas liquids and 2.7 Tcf of gas, making it the largest gas accumulation yet discovered offshore Newfoundland. During 1999, three wells were drilled in White Rose, with encouraging results. The partners decided to proceed with development, and sanctioned the project in March of this year. Husky says it expects to recover 200- to 250 million barrels of oil, at a project development cost of $1.57 billion. Gas will be reinjected, as there is no pipeline infrastructure offshore Newfoundland. Like Terra Nova, the project will be developed using an FPSO vessel. Between 18 and 25 development wells are planned by Husky and its partner Petro-Canada; first production is slated for the end of 2005. Peak rates are expected to be around 100,000 barrels of oil per day. A disappointment for the region was the decision this past winter by partners ChevronTexaco, ExxonMobil, Norsk Hydro and Petro-Canada not to proceed with their Hebron project, six miles north of Terra Nova Field. The companies said that Hebron, Ben Nevis and West Ben Nevis fields, which contain significant amounts of heavy crude, were too costly to develop. Nonetheless, the partners continue to consider alternatives for development. Iceberg Alley After enjoying several years of brisk offshore land sales, the C-NOPB decided to defer a scheduled sale this year, citing such factors as industry consolidation and a growing interest in deepwater prospects. Exploration interest is clearly waning in the relatively mature Jeanne d'Arc Basin. The two wildcats that were drilled in the basin this year, both by Husky Energy, were plugged and abandoned. The Husky Trepassey J-91 was drilled on EL 1044 about six miles south of White Rose Field; the Husky Gros Morne C-17 was drilled further south on adjacent EL 1055. Both wells were targeting large undrilled structures. They did encounter thick, good-quality reservoirs that unfortunately were wet. "We see the land holdings moving out of the Jeanne d'Arc Basin, which has been the focus of exploration in Newfoundland, to new basins and deeper waters," said Fred Wray, vice chairman of the C-NOPB, speaking at the CORE conference. "Currently we have a little more than C$500 million in work expenditure commitments on our books. The geologists tell us there is another 6 billion barrels of oil and another 62 Tcf of gas to be discovered." Attention is now directed at the Flemish Pass Basin, a deepwater basin that lies sandwiched between the Grand Banks and the Flemish Cap, some 300 miles from St. John's. Conditions are hostile-aside from being so far from land, the water depths are as great as 3,900 feet, the basin sits in "Iceberg Alley," and pack ice forms every several years, attaining thicknesses of up to 30 feet. Just three wells have been drilled in the basin, the most recent in 1986. These indicated the presence of similar-age reservoirs and source rocks to the Jeanne d'Arc Basin. But the real intrigue comes from seismic, which shows significant prospects featuring four-way closure and tilted fault blocks. Estimates are that fields could be in the range of 500 million barrels in size. The next year will be exciting for the remote area. After the Eirik Raude finishes its inaugural well for EnCana in Nova Scotia, it will move to the Flemish Pass. Petro-Canada will drill the Mizzen and Tuckamore prospects in the northern portion of the Flemish Pass Basin. Norsk Hydro and EnCana are partners in those wells; each firm holds a one-third interest. "The Flemish Pass is a brand new oil basin," says EnCana's Hogg. "We believe that it is very similar to the Jeanne d'Arc Basin, and it has all the right characteristics for oil." Several more basins await the drillbit as well-operators hold licenses in the North Jeanne d'Arc, Salar, South Whale and Laurentian basins. This year's seismic acquisition trends support the interest in these far-flung areas, which encompass a wide range of water depths and play types. Through October of this year, three seismic programs had been shot offshore Newfoundland, ranging through the Grand Banks and Labrador slope regions to the Laurentian Sub-basin and South Whale Basin. By 2005, a number of these rank areas will see important tests. Eastern Canada has arrived. WORLD-CLASS POTENTIAL In a recent study, Calgary-based consultant Ziff Energy Group estimated Scotian Shelf gas production could increase from its current levels of 500 million cubic feet per day to more than 1.2 billion cubic feet (Bcf) by 2006, and in excess of 2 Bcf by 2010. To the U.S. Northeast, the Scotian shelf offers a couple of strong advantages over other gas-supply basins: at 750 miles, it is by far the closest source of production and it is free of weather-related problems such as icebergs or hurricanes. To date, the only gas transportation out of the region is via the Maritimes & Northeast Pipeline, a 30-inch line from Nova Scotia to Massachusetts. The current capacity is 600 million cubic feet per day, but that can be expanded to volumes as great as 1.2 Bcf per day. Additionally, El Paso Pipeline Canada plans to develop a new pipeline that will carry 1 Bcf per day from the Scotian Shelf to Northeast markets. The Blue Atlantic line, currently being surveyed, has an expected completion date of 2006. An ultimate resource potential on the order of 50 Tcf or more for the Scotian Shelf can be considered reasonable, says Ziff. Separately, the Canada-Nova Scotia Offshore Petroleum Board recently released a new assessment of the resources of the Scotian slope, defined as the area from the shelf edge in 650 feet of water to depths of 13,000 feet at the base of the slope. "The board's resource evaluation is based on the interpretation of 30,000 kilometers of 2-D seismic data collected over the area," said Jim Dickey, chief executive officer of the CNSOPB, speaking at the Canadian Offshore Resources Exhibition and Conference held in Halifax in October. "The results of this interpretation were compared with public data logs from deepwater hydrocarbon basins on the North and South Atlantic continental margins." The CNSOPB estimates the undiscovered gas potential for the deepwater Scotian slope ranges from 15 Tcf (risked recoverable) to 41 Tcf (unrisked recoverable). The undiscovered oil potential is forecast to range between 2- and 5 billion barrels. "As more deepwater wells are drilled offshore Nova Scotia, more discoveries are made and more plays are proven, the risk assessment numbers are expected to increase and move toward the higher unrisked resource numbers," says Dickey.