Abstract

The Falher Formation in the Deep Basin area of Western Canada contains severaltight gas bearing sands overlain by permeableconglomerates. Because of the lowpermeability, the gas cannot be drained from the sands by horizontal flow tothe well bore. However, drawdown of the conglomerate could cause the gas tomove upwards into the conglomerate and subsequently to the well bore. As thiscould occur over a relativelylarge area it could provide an effective method ofdraining the tight sands.

Reservoir simulation calculations using a simple model of a homogenous sandoverlainby conglomerate, yield a recovery factor of about 80% for a one sectiondrainage area. With an average drainage area of 3.7 sections per well, basedupon current well spacing, the recovery factor would decrea3e to 45%.

Visual examination, and porosity measurements of core material, suggestthatexcept for occasional obvious shale breaks, the sands are homogenous. However, log evaluation shows that shaly zones and zones of higher watersaturation are present, both of which are less permeable to gas than the cleansands. Correlation of these low permeability zones between wells wasunsuccessful, and their lateral extent is therefore assumed to be less than thecurrent well spacing.

A reservoir model containing the low permeability zones was constructed bystatistical analysis. Their lateral extend was assumed to be equal to half thewell spacing, and their position in the vertical sequence derived from theresults of log analysis of 142 conglomerate/sand intervals.

Simulations run using these models indicated that with the current welldensity, the recovery factor would probably be about 35%, but could be as lowas 25%.

Introduction

The Cretaceous Falher Fomration in the Deep Basin of Western Canada containsseveral tight gas bearing sands overlain by permeable conglomerates. Because ofthe low permeability of the sands, the gas cannot be drained by horizontal flowto the well bore. However, draw-down of the conglomeratecould cause the gas tomove upwards into the conglomerate and subsequently to the well bore. As thiswould occur over a relatively large area it could provide an effective methodof draining the tight sands.

In the absence of a significant production history, the determination of arecovery factor for the tight sands depends on reservoir simulationcalculations. Theresult of the simulation procedure depends on the input inparticular on the reservoir model used.

Models used in previous studies have assumed:

  1. homogeneous sand directly under1ying conglomerate, giving recoveries of lipto 80%, (10)

  2. an impermeable barrier between the conglomerate and sand in most Hells, recovery factor zero. (2)

Within the area studied in this report (Fig. 1) a model between the twoextremes described above, with some degree of reservoir inhomogeneity, wasconsidered to be more appropriate. The sands are not homogeneous, as inWinter's study (10), but contain lower permeability layerswhich imhibit thevertical flow of gas.

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