Abstract During 1986 two large volume stimulation treatments were carried out on two low-permeability (<0.1 mD) Panther River wells. The formation treated was the Mississippian Turner Valley (Mt); a thrust-faulted dense dolomite containing sour gas (average 6% H2S) and found at about 4500 m (15 000 ft). Panther River No.2 was stimulated with a staged gelled pad, retarded-acid frac. Panther River No. 7 was stimulated with a massive propped frac using crosslinked HPG frac fluid and 40/60 sand. One of the objectives was to evaluate the response of low-permeability Panther River wells to these different stimulation techniques. This paper reviews well and reservoir characteristics, selection of stimulation candidates treatment design and execution, and the stimulation results. Introduction The Panther River sour gas field is situated on the eastern slopes of the Rocky Mountains about 100 km northwest from Calgary and 12 km southwest from Shell's Burnt Timber sour gas field (Fig. 1). The Panther River field was discovered in 1958. Development has been gradual due to uncertainty in drilling he deep (up to 5100 m), expensive, low-deliverability wells, and the unavailability of suitable processing capacity and markets for the gas. Currently, Shell has ten wells drilled and cased in Panther River of which two are abandoned. Total gas in place is estimated to be 58 E09 m3 (2 TCF); unfortunately, the reservoir exhibits low permeability (less than 0.1 mD) and low deliverability. Two recent events sparked fresh interest in Panther River: 1. natural gas deregulation legislation in Canada provided new market opportunities for Panther River gas; and decline in deliverability from the Burnt Timber wells has created capacity at nearby Burnt Timber sour gas plant. As a result, Shell is proceeding with construction of facilities to connect five Panther River wells to the Burnt Timber gas plant with production to start in 1989. Prior to construction of the gas gathering and compression facilities, two wells were selected as stimulation candidates to improve their deliverability and increase recoverable reserves. Massive hydraulic fracture (MHF) stimulations in similar tight gas reservoirs elsewhere had yielded promising resu1ts(1, 2). Stimulation Candidate Selection Hydrochloric (HCl) acid stimulations had been previously performed on all wens but one: Panther River No.2 was only drill-stern-tested (DST'd). Table 1 summarizes the acid jobs performed on Panther River wells prior to 1986 and some results calculated from post-frac pressure build-up test analyses. These acid treatments were pumped at above formation fracture pressure, at the maximum pump rate possible and without leak-off control. It can be seen from Table 1 that the HCl acid stimulations were successful in removing near well bore damage and the creation of short conductive fractures (mostly less than 16 m). The short fracture lengths were believed to have been caused by: uncontrolled vertical fracture growth, small treatment volumes, and high leak-off due to acid wormholing and natural fractures.