Canada: Exploring New Frontiers
World Energy, Vol.3, No.1
by Ron A. Brenneman, President and CEO Petro-Canada
pdf-version of this article: worldenergysource.com
Around the world, the oil industry is extending its reach into new frontiers to find and develop the petroleum resources demanded by the global economy. Whether it is in deep waters of the Gulf of Mexico or in the remote Caspian Sea, various players are addressing the technical challenges posed by the reach into and harsher environments.
Nowhere is this more true than in Canada, where the World Petroleum Congress will be held in June. When they arrive at the Congress venue in Calgary, leaders of the global energy industry will immediately understand the Canadian context. In Canada, three previously forbidding frontiers are simultaneously crossing the threshold to robust commercial success.
This new era of commercially successful frontier development has arrived not because crude prices have recently risen, but in spite of lower prices throughout most of the 1990s. It has come about because decades of technological refinements ? and more than a little persistence ? have brought costs down to the point at which projects are attractive within the range of historic average prices.
Now, billions of dollars are being invested and more investment is planned, accessing billions of barrels of oil and bitumen and trillions of cubic feet of natural gas.
Sites already proven highly commercial include some familiar and historic names. They include Sable Island, site of more than 200 shipwrecks and world renowned as the Graveyard of the Atlantic; Iceberg Alley on the Grand Banks; and the vast, cold reaches of the Athabasca oil sands in Northern Alberta. These regions remain as hostile and remote today as when they were first explored. But today, we are safely and reliably bringing major petroleum resources out of these areas and profitably delivering them to growing markets.
Oil is coming ashore from the Grand Banks, 300 km off Newfoundland?s East Coast. Gas is being delivered to New England from the Scotian Shelf off Nova Scotia, from platforms within sight of Sable Island. Oil sands mining is entering a new phase of consistently profitable and rapidly expanding commercial development, while in situ oil sands development is achieving new recovery rates and triggering new projects at various levels of investment, from large to modest.
The petroleum heart of the Grand Banks is the Jeanne d?Arc Basin, estimated by the Geological Survey of Canada (GSC) to contain between 3.6 and 5.2 billion barrels of oil in place, with 1.6 billion barrels rated proved and probable. Finding costs to date in the Jeanne d?Arc have averaged $1.25 per barrel of oil. The success rate for exploration drilling is 50 percent and the delineation success rate is 81 percent. But the Jeanne d?Arc is only the first and most explored of five separate basins in the Grand Banks, covering an area of 330,000 square miles or roughly 70 percent of the size of the North Sea.
The cornerstone of current Canadian East Coast offshore oil development is actually a hollow concrete pillar. The pillar is as wide as a city block and coincidentally as tall as our Calgary office tower, rising some 52 stories above the sea floor. Today that pillar is filled with oil, ready to be transshipped for the journey to shore in one of two shuttle tankers. The pillar is the Hibernia Gravity-Based Structure, resting in 90 metres of water on the sea floor and topped by a production platform. Last winter, it reached design rates of 150,000 barrels per day and partners have recently applied for regulatory approval to increase production to 180,000 barrels per day (bpd). ExxonMobil, at 33-per-cent ownership, is the leading owner in the $6-billion installation and Petro-Canada holds 20 percent.
We now estimate that Hibernia alone contains some 730 million barrels of oil, while probable reserves in the nearby Terra Nova discovery are currently placed at 370 million barrels ? with significant upside potential.
Terra Nova will be developed more quickly and less expensively than Hibernia, using a 960,000barrel production and storage vessel on site, plus shuttle tankers to move the oil to shore. While Hibernia shouldered the costs of a deep-water construction facility, a transshipment terminal and other infrastructure, Terra Nova is now benefiting from those installations, as other projects will in future. The $2.2 billion Terra Nova project is expected to produce 129,000 barrels of oil per day, beginning early in 2001. Petro-Canada is operator of that field, with a 29 percent interest.
With these two projects as a commercial and technical foundation, Petro-Canada and other East Coast players are now looking ahead to the development of substantial oil discoveries at White Rose and Hebron/Ben Nevis, both within the Jeanne d?Arc basin, as well as to other potential exploration targets in the Jeanne d?Arc and the less explored and deeper Flemish Pass basin.
Husky Oil, the operator of White Rose, has estimated 250 million barrels of recoverable oil in the south field and a further 150 million barrels in the north. One or two more delineation wells will be drilled by mid year that will add to our knowledge and, hopefully, enable owners to commit to development with potential production by 2004. Meanwhile, at Hebron/Ben Nevis, two test wells last year established significant additional reserve potential, placing it between Terra Nova and Hibernia in estimated reserve size. In the Flemish Pass, to the northeast of the Jeanne d?Arc, we see a handful of potentially large prospects, each with significant closure.
The importance of the Grand Banks ? and indeed of frontiers in general ? can best be understood by thinking about the life of a an oil well, a field or even an entire basin, in terms of a bell curve representing its reserve life. Each proceeds through phases from discovery, to slow initial production, rapidly rising production, plateau, slow decline, rapid depletion and finally shut-in.
In the relatively mature Western Canada Sedimentary Basin, Canadian producers are certainly into the long, slow decline. Now, by divesting conventional holdings and reinvesting in the Canadian frontier opportunities, many senior producers have stepped back from plateauing production in the Western Canada Basin to the point of rapidly rising production on one or more frontiers. And the size of initial discoveries is such that they?ve made this move without incurring any substantial short-term production penalty during the transition to the frontier.
At Sable Island, in the relatively shallow waters of the Scotian Shelf, ExxonMobil and Shell Canada have tapped into two trillion cubic feet of natural gas reserves and brought offshore gas to market for the first time in Canada. The $2-billion project lands 500 million cubic feet of gas per day and a $1.7-billion pipeline carries it to markets in Atlantic Canada and New England.
The GSC estimates ultimate gas reserves for the shallow waters of the Scotian Shelf at 18 TCF, of which four TCF are proved and probable. A second phase of Sable development, estimated to cost $1 billion, is already delineated and more exploration is planned for this summer by the current players and others, including Petro-Canada.
Meanwhile, Shell, ExxonMobil and Chevron are running three-dimensional seismic programs on parcels of land in up to 3,000 metres of water to the southwest of Sable.
Perhaps as important as what?s happening offshore, is the enabling action taken on land. New generic, profit-driven royalty regimes have been developed with governments to provide for early recovery of the large capital investments required to land these reserves. With these agreements in place, project proponents have clear and stable revenue-sharing schedules on which to base evaluations, knowing that return on capital can be competitive with other opportunities worldwide.
And, while production systems have been built offshore, support infrastructure has rapidly expanded onshore. Project owners have been diligent about involving locally based East Coast companies in international alliances contracted to provide every kind of technical support to offshore development. As a result of this technology transfer, local engineering companies and fabrication shops are expanding to take on more and more of the work in successive stages of oil and gas development. At the same time, companies providing supply boats, helicopters and other essential services are expanding their fleets and their know-how.
After decades of waiting ? and some significant disappointments in the form of earlier project deferrals ? the cities of St. John?s and Halifax are now brimming with confidence and entrepreneurial spirit. They are attracting new investments of every kind and economic opportunity is spreading through the rest of Atlantic Canada. Drawing on business partners with extensive North Sea experience, the communities and businesses of Newfoundland and Nova Scotia see the critical mass being assembled for an economic takeoff similar to that which began on the other side of the North Atlantic some 30 years ago. These companies are showing the ability to implement world-class technology and to compete successfully for a share of the offshore business.
Big things are happening on the East Coast and there?s more to come. But the really big numbers are in the oil sands of Alberta. These deposits contain a nearly unimaginable 1.7 trillion barrels of bitumen in place, of which some 300 billion barrels are considered economically accessible ? even if technology were frozen in its tracks today. For perspective, this compares with Saudi Arabia?s recoverable conventional reserves of 260 billion barrels. And, while conventional pools are depleted worldwide, advancing technology pushes the recoverable estimates for the oil sands higher.
Of course, the finding costs for this oil are nearly zero. In the area near Fort McMurray, Alberta crude bitumen is so close to the surface you can ?discover? it with the soles of your boots or a garden shovel. Tens of billions of barrels lie within reach of conventional truck-and-shovel mining equipment. The challenge of the past three decades has been to find the means to economically extract the heavy bitumen from the entrained sand and clay and upgrade the bitumen to synthetic oil.
The huge Syncrude and Suncor projects have crossed this economic frontier and proved that oil sands development can be consistently profitable. As 12 percent partners in Syncrude, the world?s largest oil sands mine, we at Petro-Canada know how challenging this endeavour has been and how rewarding the future looks. And it should be noted again that this is a future based on historic average oil prices.
Suncor is now embarked on a staged $2.2-billion mining and upgrading expansion project that is expected to take production from 100,000 barrels of light oil per day to 220,000 bpd by 2002. Similarly, Syncrude is now in the midst of a phased $6-billion expansion which will lift production from the current 250,000 barrels of light oil per day to 350,000 bpd by 2004 and to 450,000 bpd by 2007.
Among the noteworthy technologies that have made these investments possible, both companies are using hydro-transport systems to move oil sand ore from their mining sites to bitumen extraction plants. By pipelining the bitumen to the extraction plant in a water slurry, they not only improve transportation efficiency; they simultaneously pre-treat the bitumen to reduce the required intensity and cost of the hot-water-based bitumen extraction process.
The other standout achievement in reducing the costs of oil sands mining investments has been the adoption of conventional truck-and-shovel mining systems to replace or augment larger, more capital-intensive and less reliable bucketwheel and dragline extraction systems. Along with hundreds of incremental innovations, these two major cost improvements have cut the all-in cost of synthetic oil production from the tar sands in half. Not entirely coincidentally, they have succeeded at a time when the major players in the Canadian industry have badly needed large new opportunities to replace declining reserves and potential within the conventional arena of the Western Canadian Sedimentary Basin.
As with the East Coast, another stimulus to new oil sands investment has been the creation of a supportive generic royalty regime specifically for these projects. Investors pay 1 percent of revenues until capital costs are paid out and 25 percent of net operating revenues thereafter, making it attractive for companies to undertake these very large investments.
In the future, the integration of electrical power co-generation plants will further improve the economics of several oil sands projects ? while reducing environmental impacts. Using waste process heat, these projects will drive steam turbines to supply their own power and to sell power onto the electrical grid. Both Suncor and Syncrude expansions include co-gen plants, while the newly-launched Shell/Chevron project includes two.
With fiscal regimes in place and cost-effective methods established, other investors are coming to the oil sands. In addition to the Syncrude and Suncor investments already mentioned, other players have proposed projects worth an additional $22 billion ? for a total of $30 billion ? to be completed between 2002 and 2007.
Notable among new mining projects currently under way is the Shell/Chevron Albian Sands development. The partners will invest $3.5 billion in a mine, bitumen extraction plant and upgrader capable of producing up to 150,000 barrels of light synthetic oil per day by late 2002. The upgrader will be located, not at the extraction site but adjacent to Shell?s Scotford refinery near Edmonton, some 400 km to the south. (An independently owned $600-million pipeline between the mine and upgrader is not included in project costs.) The upgrader will further differ from current methods in that it will inject hydrogen into the bitumen to produce light oil, rather than extracting carbon in a de-coking system.
The important point here is that new players will continuously bring new ideas to the oil sands, expanding the technological "gene pool" to provide a broader, more robust scientific inheritance for each new generation of development.
Not all the oil sands investment is going into mining. Imperial Oil, an ExxonMobil affiliate and 25 percent owner of Syncrude, is also the leader in in situ extraction of bitumen from oil sands which lie too deep to be effectively mined. (This system involves injecting high-pressure steam through well bores into oil sands formations to separate bitumen from sand underground and pump mobilized bitumen to the surface.) At Cold Lake, Alberta, Imperial now extracts 130,000 bpd of bitumen. That?s up from 100,000 a year ago and the latest expansion will add another 30,000 bpd by next year.
Other projects, by BPAmoco, Alberta Energy Company, PanCanadian and others would cost more than $1 billion in total and add another 100,000-plus bpd of oil to commercial production, this year or soon after.
Meanwhile, Suncor has announced plans for a $450-million in situ oil sand development on its Firebag property north of Fort McMurray that will increase bitumen production by 35,000 bpd. With it, they announced a $300-million expansion to their upgrader.
Petro-Canada has applied for approval of an in situ project on our MacKay River leases near Fort McMurray, based on steam-assisted gravity drainage (SAGD) technology. In this approach, multiple pairs of horizontal wells are drilled into subsurface oil sands formations in over-and-under configurations. Steam is continuously injected into the upper wells of each pair and mobilized oil is produced as it drains to the lower well bores in each pair. Our MacKay River proposal envisions a first phase with 24 pairs of horizontal wells producing 22,000 to 30,000 bpd.
And, as this article went to press, Canadian Natural Resources announced plans for a $6.5-billion mining and in situ project to produce 300,000 bpd within seven to 10 years.
Experience tells us that these projects will not all proceed and that those which do will not all be rewarded with instant success. But it also tells us that, in the oil sands, persistence pays. Over a reasonable period of time, we can expect many of these projects to solve the riddles of profitable production. When they do, nearly every one of them is capable of substantial expansion analogous to what Suncor and Syncrude are doing now ? and based on known reserves. That?s the magic of the oil sands that makes it truly unconventional. The resource is huge, the exploration risk is essentially zero and the technical risk of expanding on a proven project is easily tolerable within the standards of our industry.
Today, synthetic oil and bitumen production have surpassed 500,000 bpd, or more than 25 percent of total Canadian oil and equivalent production. New proposals would push oil sands production above 50 percent of Canadian supply by 2007. And for every month that oil prices stay near or above $20 (US) per barrel, the slate of new proposals is likely to grow. But it?s worth remembering that many of the projects proceeding today were conceived and launched during 1998, when oil prices were at low ebb. This was possible because companies now build low price cases into their economics and still find room to proceed.
Canada is, however, a big country with more than two frontiers. While commercial development proceeds on the East Coast and in the oil sands, exploration for the future is actively being pursued in the Arctic. Earlier this year, Imperial, Gulf Canada, Shell Canada and Mobil announced a study of the economic feasibility of jointly developing their Mackenzie Delta gas discoveries near the shores of the Beaufort Sea. During the 1970s, Imperial booked three TCF at Taglu, Gulf discovered 1.8 TCF at Parsons Lake with Mobil, while Shell discovered one TCF at Niglintgak. Petro-Canada and partner Anderson Exploration are among several companies exploring for additional reserves. If prices of $3.50 (Cdn) per thousand cubic feet could be preseen, it is estimated that reserves of 10 TCF would be sufficient to justify a pipeline spanning the remaining thousand kilometres to connect with the current northern reaches of the gas transmission system. Four major pipeline companies have expressed interest in making the connection.
During the 1980s, high exploration costs, erosion of gas prices, first nations land claims and rising pipeline cost estimates shelved development proposals for the area. But continuing growth in North American gas demand, new pipeline proposals and strong support from First Nations communities have recently and dramatically changed the outlook.
Based on findings to date, the GSC places ultimate gas reserves at 56 TCF, both onshore in the Mackenzie Delta and offshore in the Beaufort Sea. Given currently known reserves, it now seems within the realm of reasonable expectation that onshore reserves could be tied in and profitably produced before the end of this decade. That would, of course, provide the impetus for greatly increased exploration aimed at realizing a significant part of the potential outlined by the GSC. But with a pipeline in place, it might also be possible to tie in previously discovered gas from Prudhoe Bay, on the Alaskan side of the Beaufort, as one group of investors has proposed.
Major Arctic oil discoveries date from the 1970s and early ?80s and are overwhelmingly clustered in the near and medium offshore areas of the Beaufort. Total oil discoveries to date are 1.4 billion barrels, or about the same amount as on the Grand Banks, with the 300 million barrel Gulf Amauligak field rating as the largest single find. But, when gas development reaches the area, it will provide a powerful impetus for oil exploitation.
The Mackenzie Delta may become the next Canadian frontier to come into commercial production, possibly within this decade. But Canada also has a frontier beyond both the Delta and the Beaufort Sea.
For real northern exposure there is the Sverdrup Basin, much of which lies above the magnetic North Pole in Canada?s Arctic Islands. Drilling rigs must be flown in by multiple loads on Hercules aircraft and the planes land on sea-ice runways that are reinforced by repeated flooding and freezing in order to bear the landing impacts. When most of the discoveries were made, in the 1970s, drilling crews were accompanied by sled dogs, not to haul equipment or people, but to act as polar bear detectors.
Discovered reserves include significant oil accumulations and some 19 TCF of gas, including 12 TCF in two fields on the north end of Melville Island. Petro-Canada is a 53 percent partner in PanArctic Oils and in the early 1980s we proposed gas liquefaction and tankering schemes as well as an eventual Polar Gas Pipeline. Of course, prices eroded substantially from those days and spelled the end of many projects. But reduced costs have brought many frontiers within reach since then and may eventually do the same for reserves of this size, even in such extreme environments and at such distances from markets. At the same time, social consensus is supporting increased northern development with the involvement of communities and first peoples of the region.
Reaching into new frontiers means working with new partners to develop the socio-economic, environmental and technical foundations necessary for successful projects. These are challenging objectives that will draw on all the skills we?ve learned in previous work. Addressing these issues effectively will impact the pace of development for each project. But stable, attractive royalty regimes are in place in each of the Grand Banks, the Scotian Shelf and the oil sands. More than mere revenue-sharing agreements, these arrangements signify a determination by local communities to see resources developed for the general benefit of those regions. Now, as distinct from 30 years ago, the peoples of the Northwest Territories are declaring a similar determination.
It has taken decades of increasingly intensive work to make the East Coast and Athabasca frontiers truly competitive investments. But that competitiveness has arrived. With that experience behind us, with new levels of expertise and established technical partnerships, it seems entirely possible that the next frontiers may see shorter timelines to commercial production. |
