The cost of northwestern Canadian shale gas will drop to competitive levels as drilling intensifies from scattered field trials into concentrated commercial development, says the pipeline grid for British Columbia and Alberta.
From about C$3.25/MMBtu (US$ at par) in the current "evaluation" stage, supply costs -- including a 15% return on investment -- will slim to C$1.75/MMBtu as production matures, predicts Nova Gas Transmission Ltd. (NGTL).
As TransCanada Corp.'s 25,000-kilometer (15,000-mile) western collection network, NGTL has made a specialty of appraising industry economics and output capacity as guidance for service planning since its 1950s birth as Alberta Gas Trunk Line.
The latest forecast, using data from producers that dominate the grid's roster of shippers, makes a pioneer foray into assessing Canadian performance at adapting made-in-Texas methods of tapping shale gas with horizontal wells and hydraulic fracturing.
NGTL says its new review of "recoverable" or "marketable" northern shale supplies shows the technology still produces only an overall average of about 15% of the gas contained in the industry's most accessible top target, the BC share of the Montney deposit that also extends into Alberta.
But the natural richness of the formation -- in BC alone, a 44,030-square-kilometer (17,000-square-mile) geological carpet up to 300 meters (984 feet) thick -- is projected to make up for the inefficiency of the new methods in northern conditions.
NGTL calculates the BC share in the Montney contains 980 Tcf of gas and that current industry performance makes 137 Tcf recoverable as commercial production.
Initial production during the "evaluation" or trial stage from each horizontal, hydraulically fractured well in the richest known part of the formation -- the North Montney in BC -- has averaged 3.6 MMcf/d.
Early experience with the rate that output naturally declines after its first big surge indicates that typical BC Montney wells will produce 3.7 Bcf, show NGTL’s calculations.
"The area is one of the lowest cost, commercially viable resource plays in the WCSB [Western Canada Sedimentary Basin]," says NGTL. "The economics are robust over a wide range of gas prices."
The western Canadian pipeline grid predicts a gradual but steady market recovery, with annual averages for its benchmark NIT (short for Nova inventory transfer) price rising from C$2.98 per gigajoule (US$3.13/MMBtu) this year to C$3.57/GJ (US$3.75/MMBtu) in 2015 and C$4.93/GJ (US$5.18/MMBtu) in 2020.
The outlook will improve to the extent that nine proposals for new Pacific coast liquefied natural gas (LNG) exports to much higher-priced Asian markets such as Japan and South Korea make it into construction and operation, NGTL adds.
"Not all of these projects are expected to proceed; however, the list does illustrate the strong industry interest in this business opportunity. Based on this level of interest and on the progress to date of some of these proposed projects, NGTL has estimated that LNG exports on the BC West Coast will reach 4.3 Bcf/d by 2030."
The shale economics and production forecast has been submitted to the National Energy Board (NEB) as support for an NGTL application to build a new C$1.7-billion BC leg called the North Montney Project.
The NGTL addition is primarily designed to collect BC shale gas supplies for jumbo new pipelines that TransCanada is proposing to build for deliveries of up to 5 Bcf/d across the province to Pacific coast LNG terminal sites at Kitimat and Prince Rupert.
But NGTL is far from relying entirely upon rapid successes by the Asian export schemes, which have yet to land long overseas sales contracts needed to justify construction price tags in billions of dollars for all but the smallest projects.
The North Montney design calls for a reversible addition to the NGTL pipeline grid that will be capable of flowing BC gas east to satisfy the biggest source of Canadian gas demand growth, thermal oil sands production plants in northern Alberta.
Another new NEB filing by NGTL is a construction application for an addition to serve an in-situ underground bitumen extraction project being built by Shell Canada in the Carmon Creek area of northwestern Alberta. Although the Shell plant is one of the smaller oil sands schemes, it is a giant by conventional industry standards with planned production capacity of 80,000 b/d.
The coming combination of new LNG exports, rising oil sands output and continuing natural declines of aging conventional Canadian gas fields is bound to fuel growing and steadily more efficient northern shale supply development, NGTL says.
TransCanada's western pipeline grid predicts "ongoing improvement in drilling and completion techniques which will result in faster drilling rates, longer horizontal laterals and an increasing number of optimally positioned hydraulically fractured intervals; as well as the use of fit-for-purpose drilling rigs."
NGTL describes the turning point ahead, which will make Canadian shale gas a cost-competitive item, as "the transition from the evaluation drilling phase to the exploitation phase."
The change is forecast to be a case of natural industrial maturing: "During the evaluation drilling phase, single wells are drilled in an effort to prove up area resources. The exploitation phase uses manufacturing and batch approaches to drilling and large volume hydraulic fracturing at centralized drilling sites, which results in a significant improvement in economies of scale."