CALGARY�Major hurdles remain to meeting burgeoning natural gas demand in the US over the coming decade. A number of speakers at the recent Canadian Energy Research Institute Conference in Calgary offered their views of the growth in gas supply and demand in North America and enumerated the challenges ahead for gas producers and transporters.
Among the concerns are:
� Rapidly growing gas demand resulting from increasing gas-fired power generation capacity.
� The upstream sector's ability to ramp up supply fast enough to meet demand.
� The timing of the availability of gas from important exploration provinces in Canada, such as the East Coast offshore and the Canadian Arctic.
US gas demand
Great opportunities and major infrastructure and manpower challenges face the North American natural gas industry in the next decade, says a former chairman and CEO of Gulf Canada Resources Ltd.
C.E. (Chuck) Schultz, chairman and CEO of independent Dauntless Energy Inc., Calgary, quoted from a recent National Petroleum Council study indicating that the infrastructure needs of the pipeline sector will require $123 billion (US) in investment capital. Schultz said there will be a need for 38,000 miles of transmission pipeline, 255,000 miles of new distribution mainlines, 850 bcf of storage working gas capacity, and 30 bcf of interregional pipeline capacity. The $123 billion price tag includes $34 billion for transmission, $84 billion for distribution, and $5 billion for storage.
Schultz, who participated in the NPC study, said specific forecast numbers in the study will be wrong; gas demand assumptions are conservative, and electrical power generation will be the key driver for a US demand increase to 29 or 30 tcf by 2010. US gas demand will increase by 32% during 1998-2010, he said. He noted that the NPC study did not include North Slope gas or the possible effect on demand of the Kyoto conference on emission standards. It did recognize the possibility of a natural gas pipeline down the Mackenzie Valley by 2010.
Key production growth areas will be the Gulf of Mexico deepwater, the Rocky Mountain region, and Canada (see chart). Canadian production will increase to 7 tcf/year from 5.5 tcf, and Canada will retain a share of about 14% in the US gas market. Coalbed methane will play a significant role in supply.
Schultz said critical factors for the US industry in meeting projected demand include exploration area access, technology development, capital investment, skilled worker availability, rig availability, lead times, and new customer requirements. The Western Canada industry faces similar challenges.
Schultz said the US has a major problem because many promising areas are now off-limits to exploration. In addition, 50% of skilled workers, such as petroleum engineers and geophysicists, are eligible for retirement in 10 years, and the industry has a serious manpower shortage.
The industry will have to drill 80-100% more wells than it does today to meet projected demand. Majors now produce only 27% of US natural gas output, compared with 50% 15 years ago. This is significant because majors have funded most research in the past.
US gas supply
Michael G. Webb, senior vice-president, Kerr-McGee Corp., said a reversal in a downward trend in production of US dry gas since 1998 is possible, but the structure and source of supply require further examination.
By taking some latitude with NPC's current-technology case, Webb said, historical US production plus proven reserves at 1,050 tcf is close to the perceived 1,150 tcf remaining to be produced over the term of the NPC study. About half is trapped in new fields, one-third in old fields, and the balance in nonconventional reservoirs. Projected reserves include old field appreciation, 300 tcf; new fields, 560 tcf; shale, 40 tcf; coalbed methane, 55 tcf; tight gas, 180 tcf; and other sources, 15 tcf.
Webb questioned the NPC estimates of future gas supply, including LNG and coalbed methane, and said the US will be lucky to get 3% of its gas needs from LNG. He said gas production has been flat or in decline for a number of years in many producing states, including Texas, Oklahoma, Louisiana, Colorado, and Kansas. The deepwater Gulf of Mexico, he said, is a production bright spot.
Gulf of Mexico shallow-water production has dropped 3 bcf/d in the last 4 years (including 2000) but has been nearly balanced by increased deepwater production from almost nothing in 1990 to an expected 3+ bcf/d in 2000. Average discovery size in the Gulf of Mexico shelf area has declined from 225 bcf in the 1970s to 30 bcf in the 1990s.
Recent data show production down 3 bcf/d vs. February 1999, through a combination of high depletion rates and smaller discovery sizes. The overall decline rate in the US is 20%. In the gulf, it is 33%, with first-year declines approaching 50%.
In all US gulf shallow waters, 3D seismic and horizontal drilling, where applicable, have been used, and some estimates suggest 60% of onshore fields have been similarly exploited. Many onshore fields have been reduced in size to 160 acres or less, making future supplies difficult to grow in these areas. Deeper means less-explored; it also means more-expensive and increasingly stratigraphic, since large, deep structures have all seen the drill bit, says Webb.
Canada's East Coast
Rob Symonds, general manager, frontier, for Shell Canada Ltd., said the Sable Offshore Energy Project (SOEP) now in production off Nova Scotia is a lever for new and profitable development opportunities on Canada�s East Coast offshore.
He noted that the ultimate resource potential of the Scotian Shelf is 18 tcf, and there is an estimated 80-90 tcf of gas remaining to be discovered in East Coast basins as a whole. And there is an additional 2-3 tcf of gas in significant discovery areas in the Sable Island area.
Symonds said the Thebaud well complex at the SOEP project is now producing 200 MMcfd of sales gas, and that will increase to 530 MMcfd this fall when new lateral lines are in place. Sable production could eventually increase to 900 MMcfd, depending on markets, pipeline commitments, and new discoveries.
He noted that, the longer-term trend in East Coast exploration is toward deepwater potential. At a land sale in April 1999, some blocks were taken in more than 10,000 ft of water; companies including Shell, Mobil Oil Canada, Imperial Oil Ltd., and PanCanadian Petroleum Ltd. are now shooting seismic on the new acreage.
Symonds believes the main deepwater challenge is technology. He predicted wells will be drilled in 10,000 ft water depth within 2-3 years.
Promising East Coast areas include the Georges Bank, Laurentian sub-basin, and the Jeanne d�Arc basin. But Georges Bank is under a moratorium against drilling, and the Laurentian basin is the subject of a jurisdictional dispute between the provinces of Nova Scotia and New Brunswick.
Symonds commented that, although the Canadian East Coast is an area with significant supply potential, economics are the key to development. Demand potential in Atlantic Canada and the US Northeast could support another four or five developments on the Sable project scale, he said.
Canadian Arctic
R.D. (Dennis) Seidlitz, manager of frontier development, Gulf Canada Resources Ltd., says there is good reason for renewed optimism on development of Canada�s Arctic gas and a pipeline to markets.
He said conditions are more positive than 20 years ago, when exploration surged in the region and a number of pipeline plans were proposed. Now, he said, pipeline length has been reduced; gas prices are stronger; export markets to the US have grown; advances in pipelines include high-strength pipeline steels and automatic welding technology, with lower construction costs possible; and progress has been made in land claims in the area, a factor which hurt earlier plans.
Seidlitz said offsetting factors include uncertainty on regulatory and environmental approvals.
Gulf has been doing internal work for more than a year on the feasibility of developing Mackenzie Delta gas and is now a member of a group studying development of three onshore fields in the Delta. It is planned for completion by yearend.
A pipeline could run from east of Inuvik on the Arctic coast to Norman Wells, NWT, and follow an existing pipeline right-of-way to Zama in northern Alberta. There, it could connect to mainline systems in Alberta and British Columbia.
Seidlitz said a pipeline could be 80% of the total cost required to bring Delta gas to markets. A study by TransCanada PipeLines Ltd. has estimated capital costs for a line at less than $3 billion (Canadian).
Randy Dahlman, Chevron Canada Resources Ltd., says there is strong activity, and a race is under way to find the next major discovery in the Fort Liard region of the Northwest Territories. Chevron and partners have made major discoveries in the region, which is Canada�s newest exploration hot spot and is seen as a positive factor for Arctic development and a pipeline to southern markets.
Dahlman said Chevron�s K-29 discovery is expected to be online by May, and pipeline connections to processing facilities are now under construction. The M-25 discovery is now waiting to be tied in. The two wells will produce a combined 150 MMcfd, and a gathering contract has been completed with pipeline Westcoast Energy Inc.
A Liard Valley producers group was formed before the first major discovery, and Dahlman stressed the importance of liaison with and participation by area residents in development.