Unconventional gas sources, particularly liquefied natural gas (LNG), will play a critical role in supplying a projected 33-34 Tcf gas market over the next two decades, according to a new study by an Alexandria, VA-based energy consulting firm. But even with added supply from non-traditional sources, Energy Ventures Analysis Inc. (EVA) believes the industry will be challenged to meet future demand requirements.

Gas supplies will have to expand by 28.5 Bcf/d to satisfy an expected 11-12 Tcf growth in consumption over the period, EVA said in its “Long-Term Outlook” of energy markets. The additional supply “will not come from traditional, conventional sources of gas upon which historically the U.S. has relied. Instead, the potential gap between future demand and supply will have to come from…evolving sources of natural gas.”

New LNG terminals and expanded existing terminals will be looked to to supply as much as 46% of the incremental gas supplies; new U.S. plays (subsalt plays in the Gulf of Mexico, 16 emerging coalbed methane basins and deep gas) for 23% of supplies; Arctic gas (MacKenzie Delta in Canada and Alaskan production) for 21%; and offshore eastern Canada for 10%.

“The combination of mature basins, high decline rates associated with modern drilling technology, reduced initial production from new wells and land restriction issues make the outlook for further increases from the traditional sources of U.S. production limited. In essence, the industry is on a treadmill with respect to maintaining or even modestly increasing production levels from these areas,” Energy Ventures said.

As a result of the industry’s new focus on LNG, the study projects that LNG supplies could reach approximately 9 Bcf by 2010 (3.7 Bcf/d from existing terminals and 5.5 Bcf/d from new terminals).

Energy Ventures said it expects only one-third of the 27 LNG regasification facilities that have been proposed for construction over the past two years to be built prior to 2010. That translates into about 8.78 Bcf/d of new LNG capacity.

“The long-term potential of [the subsalt] play is enormous,” possibly 15 or more Tcf, the consulting firm said. The “subsalt play consists of an area underneath horizontal sheets of salt that cover 30 to 60% of the Gulf of Mexico,” but further advances are needed to offset geological and engineering risks, as well as high development costs, it noted. “The industry record to date is that only 31 to 43 subsalt wells have discovered hydrocarbons, and of these, nine are considered commercial and only seven projects currently [are] producing oil and gas. Furthermore, drilling costs are more than twice those of conventional drilling at the same depth,” averaging $10-$15 million per well.

Because of the drawbacks, most major producers “have bypassed this challenging play and focused on the deepwater section of the Gulf. Once they finish with the deepwater arena and begin evaluating the subsalt play in earnest, subsalt production will become a factor, but not until the post-2005 or 2010 time frame,” the study said.

Currently, coalbed methane (CBM) gas production from nine mature and emerging basins, such as San Juan and Powder River, account for approximately 7% (or 3.5 Bcf/d) of overall domestic production, according to Energy Ventures. However, it noted that 16 “frontier” CBM basins show tremendous potential. “Long term these frontier basins should add substantially to domestic production levels, as their estimated recoverable reserves are approximately the same as the nine coalbed methane basins with current production.” The recoverable reserves of the “frontier” CBM basins were estimated at 105.5 Tcf.

Drilling for deep gas both onshore and offshore (defined as below 15,000 feet) has been “infrequent, primarily because historic gas prices have not supported the additional costs of drilling to greater depths,” the report said. “However, the industry just has started to focus on the potential of deep gas…The combination of technological advances, E&P firms making deep gas a core area of concentration, royalty relief and higher prices should make deep gas a key contributor to future U.S. production, particularly post-2005.” Some of the deep-gas plays are yielding 20-30 Bcf per well, it noted.

While the U.S. continues to fight over the route for a gas pipeline from Alaska’s North Slope, Energy Ventures said it believes Canada will push ahead with its smaller pipeline project (1.2 to 1.5 Bcf/d) from the MacKenzie Valley to Boundary Lake, where it could interconnect with Alliance Pipeline, TransCanada Pipeline, Northern Border Pipeline and others.

“The Canadians will begin filing and permitting in earnest in 2003 and could have their somewhat smaller pipeline project completed by 2010,” the study noted. But “since the political debate [in the U.S. over] the Alaskan project is still ongoing and it will take seven years to complete the pipeline, it is doubtful that the Alaskan pipeline will be online prior to 2012.”

Turning to Canada’s offshore, Energy Ventures said some observers foresee “offshore eastern Canada as the next mini-North Sea.” While industry has known about the basin offshore Nova Scotia for quite some time, gas production from the region didn’t start until early 2000 with the completion of the Maritimes and Northeast pipeline and delivery of gas from Phase 1 of ExxonMobil’s Sable Island discovery.

So far, “there have been only 178 wells drilled offshore Nova Scotia, of which 106 have been exploratory wells. Even with this limited activity, the industry has achieved 21 significant commercial discoveries to date and this figure should only increase in the future, as industry exploration efforts to date have only evaluated 5% of the potential offshore acreage,” the study noted.

Of the 17 gas-prone discoveries made so far, seven (about 6 Tcf) should be online by 2005, with the remaining 10 (1.5 Tcf) waiting for infrastructure to be further developed, said Energy Ventures. The favorable production levels from offshore Nova Scotia will likely result in the “doubling and tripling” of volumes on the Maritimes and Northeast system over the year couple of years, it noted.

“To the north of Nova Scotia are the offshore properties of Newfoundland (e.g. Grand Banks) and Labrador, where exploration activity is still in its infancy, but initial results are impressive. For example, the 127 wells that have been drilled to date in this area have resulted in 23 significant discoveries, of which 18 are in the Grand Banks area (5 Tcf) and five are in the Labrador region (4 Tcf).”

Although the Newfoundland region tends to be more of an oil province than the gas-prone Nova Scotia area, the associated gas reserves are “significant,” the study said. It noted the first four projects in the Grand Banks area have the potential to produce at least 400 MMcf/d, but it said it doesn’t expect this to occur until after 2010.

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