Abstract

The gas reserves and well spacing units in the Horseshoe Canyon-Belly River Formation coal measures in Alberta are assigned based on gas-in-place determined by canister desorption tests of coal following ERCB (2010) guidelines. However, substantial gas, which is not measured by desorption tests, also occurs in the free state within the coals as well as adsorbed and in the free state within adjacent fine-grained strata (referred to here as shales) interbedded with the coals. A series of laboratory experiments (matrix flux, volumetric strain, rock mechanics) were conducted to quantify the reservoir properties of the coals and shales and were integrated with the results from field tests (well logs, pressure build-up) to be used as model inputs for a reservoir simulator. The purpose of the modeling was to address two main questions: 1) do variations in the amount of free gas within the matrix porosity of the coal seams affect production; and 2) to what extent is the gas stored within the strata interbedded with the coal seams co-produced?

The free gas stored within a coal seam with an effective matrix porosity of 8% is shown to comprise on the order of 25% of the total original gas-in-place. The modeling results show that in high permeability coals (150 mD), an increase in production equivalent to the additional gas-in-place resulting from the free gas occurs after 25 years. Even very low permeability reservoirs (0.3 mD) are modeled to experience an approximately 2% increase in cumulative gas after 50 years of production.

Including the gas bearing shales adjacent to the coal seams results in a substantial increase in producible gas. An increase of 144% in the cumulative gas produced after 50 years is observed when shales with a fracture permeability of 0.01 mD, matrix permeability of 1×10−4 mD, and an effective fracture spacing of 10 m are modeled with coal seams with a fracture permeability of 15 mD. The coal seams, being more permeable than the shales, act as horizontal drains for the over and underlying shale layers. The enhanced production is strongly dependent on the fracture and matrix permeability as well as the fracture spacing of the shales. The spacing of 4 wells/section, assumed in the above model, results in an estimated ultimate recovery (EUR) of 23% of the total original gas-in-place in the coals and 9% in the shales after 50 years of production. Downsizing to 8 wells/section increases the EUR to 35% for the coals and 15% for the shales and to 16 wells/section to 50% for the coals and 22% for the shales. The resulting increase in cumulative production with the decrease to 8 wells/section spacing is 57% and an additional 42% when further decreased to 16 wells/section.

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