By OGJ editors
HOUSTON, Jun. 17 -- Alberta has proposed to force the shut-in of gas production from 900 wells to conserve pressure decline in the geologic formation that contains the Athabasca oil sands.
Some of the 900 wells are not on production. The wells currently producing account for 90 bcf/year or 2% of Alberta's annual gas output and 1 tcf or 2% of the province's remaining gas reserves.
The Alberta Energy & Utilities Board proposed that the shut-in take effect Aug. 1, 2003.
The affected area covers 5.5 million acres. It extends from 85 miles north to 120 miles south of Fort McMurray and is 16 townships at its widest point. Nine townships 91n to 99n adjoin Saskatchewan.
This appears to be about one third of the total area covered by the Athabasca oil sands.
Applications for approval to produce gas are required for wells proposed within the application area and for wells drilled outside the area that are within or extend a field that overlaps the application area, the board said.
The board said it has been studying the situation for 6 years since an oil sands leaseholder filed a gas shut-in request. It plans more public consultation in July.
Pressure drawdown
The board said it has gathered much evidence regarding the effects of gas production on the recovery of crude bitumen in the geological strata known as the Wabiskaw-McMurray in the Athabasca oil sands area.
Evidence indicates that a drop in pressure when gas is extracted "leads to a risk of bitumen loss, as bitumen may not then be recovered through existing thermal recovery techniques, such as steam assisted gravity drainage (SAGD)," the board said.
The amount of recoverable crude bitumen at risk in the area of concern is 100 billion bbl. That is 60 times larger than Alberta's remaining established conventional oil reserves and seven times greater than all of the conventional oil ever produced in the province.
The bitumen at risk contains 600 times the energy content of the proposed shut-in gas production, the EUB said.
The board proposed to review potential bitumen loss in the area of concern and afterward would allow gas production where it found little or no risk of bitumen loss.
EUB disallowed gas production from 146 wells in the Surmont area in 1999 and from 60 wells in the Chard-Leismer area in 2001-02.
The board concluded in March 2003 that Wabiskaw-McMurray gas production associated with channel bitumen presents an unacceptable risk to SAGD bitumen recovery and that the risks increase at lower operating pressures.
It found insufficient understanding of the capabilities and limits of SAGD to definitively establish commercial bitumen pay criteria. It found that the minimum steam chamber pressure required for artificial lift to be technically feasible to be 400-600 kp absolute.
Area of concern
The thickest bitumen in the Wabiskaw-McMurray deposit is generally in a north-south trending channel complex along the eastern portion of the Athabasca area, the board said.
This trend contains all existing and proposed SAGD projects and the areas included in the Surmont and Chard/Leismer hearings.
The board's defined area of concern is believed to have similarities with respect to geological environment, bitumen thickness encountered, and general gas production history. This area is coincident with channel sequences that have thicknesses generally exceeding 10 m and more than 6 wt % bitumen (roughly 50% saturation).
Outside the concern area, the Wabiskaw-McMurray deposit typically becomes thinner, channel sequences are less predominant, and the bitumen is generally not believed to be exploitable using SAGD, the board said.
The concern area contains 500 billion bbl of bitumen in place, of which the board estimates 20% to be recoverable.
The board determined that Wabiskaw-McMurray gas pools in the area of concern are generally in an advanced stage of depletion. Gas production from other zones will be allowed to continue.