Another natural gas discovery has just been made on the Mackenzie Delta, joining a sizeable find made a year ago. The two successes are tremendous news for the region, which is in the midst of a mighty revival. And, the long-sought pipeline running along the spine of the Mackenzie Valley is close to securing an important piece of its financing. The pieces are being painstakingly fitted together. Finally, after more than three decades of boom and bust, production from the Mackenzie Delta is tantalizingly close. Far from markets The Mackenzie River is the major northward-draining river on the North American continent, flowing from its headwaters at the Great Slave Lake into the Beaufort Sea. Throughout the Tertiary its shifting channels built a very large delta that is roughly two-thirds the size of the Mississippi Delta, in both drainage area and in sediment load. Indisputably, the Northwest Territories' Mackenzie-Beaufort Basin is a promising petroleum province that combines extensive reservoir and source rocks, a variety of structural and stratigraphic traps, and a favorable thermal history. Its discovered resources are estimated by the Geological Survey of Canada at 1 billion barrels of oil and 9 trillion cubic feet (Tcf) of gas. The three largest onshore fields-containing a total of 6 Tcf-are Taglu, discovered in 1971 by Imperial Oil; Parsons Lake, discovered in 1972 by Gulf Canada; and Niglintgak, found in 1973 by Shell Canada. A great deal more oil and gas can still be found-the Canadian Survey estimates the region holds a total of 7 billion barrels of discovered and undiscovered oil and 67 Tcf of recoverable gas. "Basin-wide appraisals indicate high potential for undiscovered petroleum resources, including the likelihood that several major fields (with recoverable volumes of greater than 100 million barrels of oil or 1 Tcf of gas) remain to be discovered," it says. Despite an early string of impressive discoveries, development of the delta's resources was stymied by the region's harsh climate and distance from gas markets. Several pipeline proposals were advanced during the 1970s to bring its gas south, and the Canadian government launched a three-year inquiry to assess the plans. In 1977, Justice Thomas Berger, head of the effort, recommended that a 10-year moratorium be placed on pipeline construction in the Mackenzie Valley so aboriginal groups in the region could settle their land claims. Exploration continued, however, and interest moved to prospects in the shallow waters of the Beaufort Sea. The largest find was made in 1984 by Gulf Canada-the Amauligak Field, containing some 1.5 Tcf of gas and 350 million barrels of oil. Other offshore fields of note are Issungnak, which contains 1 Tcf of gas and 30 million barrels of oil, and Tarsuit, with 150 million barrels of oil. Drilling eventually ground to a halt in the mid-1980s, as the collapse in oil and gas prices, deregulation of Canadian gas and whopping discoveries in southern Canada made exploration north of the 60th parallel unattractive to most operators. Lease positions were relinquished down to "significant discovery licenses," which served to hold the immediate areas of the drilled accumulations. The delta was dormant until the 1999-2000 winter season, when interest perked again. During the interlude, some events favorable to northern development occurred: the land claims of the Inuvialuit, Gwich'in and Sahtu peoples were settled; significant capacity began to open on western Canada's pipeline system; and an 870-kilometer oil pipeline was completed from Norman Wells Field in the central Mackenzie Valley to Zama, Alberta. Demand for gas was high, and price outlooks for the future were solid. The north was attracting interest once again. Recent activity surge The first sign that industry attention in the delta was rekindled was in 1999, when the Northern Oil & Gas Directorate attracted C$183 million in work commitments on four onshore exploratory tracts, all in the heart of the prospective area. Petro-Canada and Anderson Exploration, which was acquired by Devon Energy Corp. in 2001, offered a C$105.3-million commitment for two properties. Anderson had owned property in the region since its 1995 acquisition of long-time Arctic explorer Home Oil. During the 1999-2000 winter drilling season, the partners began acquiring 2-D and 3-D seismic on their new lands. Poco Petroleums Ltd. and Burlington Resources jointly bid C$77.9 million in work commitments for another two parcels in the same sale. Poco was acquired by Burlington in November of that year. In separate activity, the Inuvialuit people began their own push to participate in the development of the region's resources. The town of Inuvik hooked up a new distribution system, which marked the first commercial gas development north of Canada's Arctic Circle. The gas, produced from a small field about 50 kilometers north of the town, is used for power generation and residential heating. Ikhil Field was originally discovered in 1986 by Gulf Canada, when its K-35 well tested 3.7 million cubic feet of gas per day from an Eocene sandstone at a depth of about 1,225 meters. The Inuvialuit Petroleum Corp. acquired the discovery, estimated to contain some 25 billion cubic feet (Bcf), in 1996. A 3-D seismic survey was shot in 1998, and two additional wells were drilled. Inuvialuit Petroleum Corp., AltaGas Services Inc. and Enbridge Inc. each own a one-third interest in the project, which will provide gas to the town's 3,000-plus residents for some 20 years. Also in 1999, the Inuvialuit Development Corp. and Calgary-based Akita Drilling Ltd. formed Akita/Equtak Drilling. The venture constructed four special Arctic-class rigs capable of drilling to 5,500 meters. To address the fragility of the environment, the rigs are specially designed. They have footprints that are 30% smaller than those of conventional rigs; they have systems that recycle heat and cool the drilling mud, to prevent the permafrost from melting during the drilling process; and they feature totally contained composting systems. The rigs also possess many redundancies, in deference to the forbidding working conditions in the Arctic. In April 2000, the Inuvialuit also held a land sale, the first sale of oil and gas rights by an aboriginal group. Three concessions were negotiated, for a total of C$75 million in bonuses, with Devon and Chevron Canada. For Chevron, which pledged C$43 million in cash and work commitments on two agreements covering 470,000 acres of Inuvialuit lands, the sale marked its reentry into the delta. The companies negotiated comprehensive cooperation benefits agreements, which specify ongoing obligations and work expenditures. The Inuvialuit have the option to participate in the drilling, notes Calvin Pokiak, assistant land administrator for the Inuvialuit Land Administration. "We are just beginning to see drilling interest on our lands-we have mostly seismic interest right now." In August 2000, another Northern Directorate lease sale provoked even stronger enthusiasm-companies promised work commitments totaling C$466 million for exploration blocks in the onshore delta and the shallow Beaufort Sea. Petro-Canada and Anderson Resources jointly acquired two exploration licenses totaling 369,000 acres for commitments of C$128.2 million. Bidding alone, Anderson # also won a 100% interest in four exploration licenses comprising 837,000 acres in the shallow-water Beaufort Sea area. The company promised total work expenditures of C$224.1 million on the blocks. Delta veteran Shell Canada picked up an onshore block for a C$35-million work bid. New entrants joined in the bidding, anxious to secure attractive positions. Chevron Canada pledged C$76.6 million for a block that straddled the shoreline, and Anadarko Canada picked up a C$2.4-million parcel as well. After the sale, almost the entire delta was under lease to various industry parties. Shortly thereafter, Chevron teamed with BP Canada and Burlington Resources to form the Mackenzie Delta Partnership, a joint venture to shoot seismic and drill exploratory wells on the delta. The agreements covered acreage taken in the 1999 and 2000 federal land sales, as well the Inuvialuit land Chevron had acquired in April 2000. "So far, all of our activity has been done jointly in the Mackenzie Delta Partnership," says Lynn Lehr, Chevron Canada manager of communications and external affairs. Operators continued their seismic programs during the 2000-01 winter season, mobilizing five crews in the delta. And exploratory drilling resumed in the delta after a 24-year hiatus. Petro-Canada and Anderson drilled the Kurk M-15 to 3,093 meters on Exploration License 395. Although the well did encounter gas shows, it was plugged and abandoned after testing during the following winter season. A couple of important shifts in ownership occurred in 2001. In July, Conoco acquired Gulf Canada, assuming a place as one of the major reserve-holders in the Mackenzie-Beaufort Basin, thanks to its new ownership of Parsons Lake and Amauligak fields. And in October 2001, Devon acquired Anderson Exploration. It very much liked that firm's extensive Arctic portfolio, says John Richels, senior vice president, Canadian division. Today, Devon is the largest acreage-holder in the basin, with interests in exploration licenses covering 1.86 million gross acres. During the 2001-02 winter, Devon and Petro-Canada embarked on a three-well drilling program on the delta. The partners scored an impressive success with their Tuk M-18, a delineation well about 15 miles south of Tuktoyaktuk on Inuvialuit lands. The Devon-operated well reached a total depth of 2,692 meters in Cretaceous Kamik sandstones and tested at restricted rates of up to 30 million cubic feet per day. Devon estimates the field contains potential recoverable reserves of 200- to 300 Bcf. The Tuk find was the first major onshore gas discovery in the delta in decades. Two additional wells were drilled during 2001-02: Devon operated the Tuk B-2 and Petro-Canada operated the Kugpik L-46. Both were unsuccessful. Seismic acquisition by various parties also continued, with six crews active throughout the season. This past winter, news of another discovery jazzed up the delta. The Chevron-BP Canada-Burlington Resources group announced that its Langley K-30 found commercial quantities of gas. The 1,390-meter well, projected to cost C$8 million, is in the North Langley area 11 kilometers from Niglintgak Field, and 130 kilometers north of Inuvik on EL 394, a Burlington Resources block. The Chevron-operated well tested at a rate of 18 million cubic feet of gas per day from a zone in the Tertiary. "This discovery has encountered exactly what we had projected we would find," says Alex Archila, Chevron Canada president. "It reaffirms our confidence in the exploration potential and commercial viability of the region." Chevron spudded the well in mid-March, and just finished testing at breakup. "April 15 is the usual departure date," says Lehr. "We were fortunate that the weather was cold this year, and we were able to get a few-day extension to the deadline to finish our preliminary testing." Devon had an active drilling season as well. First, it teamed with Shell Canada to drill the 1,865-meter Itiginkpak F-29, some 17 miles north of Inuvik on the Napartok structure. Shell Canada farmed into the deal, its first drilling activity in years in the area. The company has existing reserves of 1 Tcf on the delta, and one exploration block on which it is still evaluating seismic, says Jan Rowley, public affairs manager. The Devon test was of particular interest to Shell, as it was just east of EL 403, which Shell was awarded in 2000. "This is a future area for us-it is a frontier play that is an important part of our portfolio." Devon and Petro-Canada also continued their joint efforts, drilling the 3,250-meter Nuna I-30, some 50 miles n ortheast of Inuvik on Petro-Canada-operated lands. That test is about 20 miles southwest and on trend with the Tuk M-18 discovery, in the Cretaceous Kamik play. At press time, both the Itiginkpak and Nuna wells were still tight holes. Additionally, EnCana Corp. and its partners ConocoPhillips and Anadarko Canada conducted seismic programs this past winter. The group acquired 2-D seismic data at Richards Island on the outer Mackenzie Delta and the Tuktoyaktuk Peninsula, and northwest of Parsons Lake Field. A 3-D program was shot directly west of Parsons Lake. Pipeline momentum These days, the proponents of the Mackenzie Delta pipeline are awash in optimism. A powerful group of producers, the Canadian federal government, and a number of local communities all strongly back the project. In 2002, the producers group-Imperial Oil Resources, ConocoPhillips Canada, ExxonMobil Canada and Shell Canada-joined the Aboriginal Pipeline Group (APG) to form the Mackenzie Gas Project, with the aim of building a line from the delta's stranded gas fields to markets in the south. The proposed pipeline is planned to be 1,350 kilometers long and could initially carry 1.2 Bcf of gas per day. The preliminary schedule calls for completion by the end of the decade. Additionally, with compression the capacity could be expanded to 1.9 Bcf per day. Costs are estimated at C$3- to C$4 billion for the pipeline, with about another C$1 billion needed for field and gathering system developments. The APG, formed in 2000, represents the interest of the aboriginal peoples of the Northwest Territories in the Mackenzie Valley pipeline. At press time, five of the six aboriginal communities that own land along the proposed pipeline route had signed a memorandum of understanding with the delta producers. That agreement provides for the APG to assume an equity interest of up to one-third in the Mackenzie line. At press time, the APG indicated that it is close to reaching an agreement with a third party for funding for its share of the proposed pipeline. The APG will use the money to pay for its share of project-definition costs. "We're making good progress on the pipeline," says Fred Carmichael, president of the Gwich'in Tribal Council and president of the APG. "Our mandate is to maximize benefits for the aboriginal people, and that is our main goal. We want ownership in the pipeline so that our people can have long-term income." The APG is seeking revenues from the flow of gas through the pipe, as well as other benefits. "We are working toward self-sufficiency-we want to create employment, training opportunities and long-term revenue for our people. "There's a will on all sides to make the pipeline happen." Nonetheless, not all of the aboriginal groups with lands along the pipeline route have joined the APG. The Deh Cho, which have lands in the southern portion of the valley, are hold-outs. "The Deh Cho are in the process of settling their land rights, but those are not finalized," says Hart Searle, spokesperson for the producers group. "We are pleased with the participation and support of a Deh Cho community for the memorandum of understanding that the producers group and the APG signed in October 2001." The producers group is committed to working with all Deh Cho communities in advancing a Mackenzie Valley pipeline, says Searle. "This commitment is independent of decisions by Deh Cho leaders whether they ratify the memorandum." At press time, the Deh Cho had signed an interim land pact that covered about 80,000 square miles. The agreement will run for five years, or until the Deh Cho finish their negotiations with the federal government. The pipeline project has three components: the three fields, the gathering system and the main transmission pipeline, says Searle. The partners will retain their interests individually, so that each firm is responsible for its field development. Imperial's development of Taglu will require drilling 10 to 15 wells, planned from a single surface site. ConocoPhillips and ExxonMobil, 75%/25% partners in Parsons Lake, will need a similar number of wells, and Shell's Niglintgak is slated for six to eight wells. That field may require more than one surface site because the reservoir is fairly shallow. Current thinking is that cumulative field and gathering system developments will cost about C$1 billion. The pipeline's projected capacity is about 50% higher than the volumes that will be produced by the three anchor fields, leaving room for other firms to ship gas down the line. "The pipeline will open up the entire Mackenzie Delta area for all the potential shippers. It will be an open-access line, and rates will be subject to National Energy Board review and approval," Searle says. Presently the project is in its definition phase, which includes engineering studies, environmental fieldwork and extensive public consultation. This past winter, engineering data were collected in both the Gwich'in settlement area and the Inuvialuit settlement region, to help determine the preferred location of the pipeline and associated facilities. Similar programs in other regions of the Northwest Territories are expected in the future. The gas project group hopes to file applications for approvals to build the pipeline as early as the end of this year. Imperial, as operator, will submit applications to the National Energy Board and to groups in the Territories-land and water boards and environmental review boards-that have jurisdiction. The agencies have created a cooperation plan for a coordinated review process. The NEB review is expected take two to three years. "It's a complex process. We have estimated that the pipeline project will require some 500 to 600 significant approvals, permits and agreements," Searle says. The ultimate decision to proceed with construction can only be made after the regulatory review is complete and a decision is issued, says Searle. Such factors as development costs, demand for natural gas, and fiscal and royalty regimes will all be weighed. If the pipeline gets the final go-ahead, building it will take another three winter construction seasons. Much has been made of the competition between the Mackenzie Delta pipeline project and the various proposals to bring Alaska's North Slope gas to market. "Our position is that all the gas is necessary at some point," says Devon's Richels. "What we have is a pipeline that makes financial sense-it is doable without any subsidies. And the gas that it delivers can easily be absorbed into existing infrastructure in Alberta." The Mackenzie Delta is also one of the handful of areas in North America that still holds potential for large oil and gas fields. Today, Devon and other operators are looking for anchor fields containing several hundred billion cubic feet. Quite a number of wells will be drilled in the coming seasons, as deadlines approach to satisfy the work commitments on acreage taken in the 1999 and 2000 federal sales. Further along, smaller prospects offer a plethora of opportunities. "We've seen a lot of indications that there are many 50- to 100-Bcf prospects in the delta. These will be drilled once the pipeline is in," says Richels. And, after that will come offshore development. "We can see gas from the shallow-water Beaufort Sea coming on in 2012-13."