Optimizing Field Development Through Infill Drilling Coupled with Surface Network: A Case Study of Low Permeability Gas Reservoir
Authors: Coskuner Gokhan , Lutes Byron 
Published: December 2007

Abstract
Evaluation of the performance of potential infill wells in complex, low permeability gas reservoirs requires an integrated team approach. Furthermore, the effect of surface gathering facilities on the performance of the pool has to be taken into account simultaneously. This paper describes the an integrated approach taken to determine the optimum field development in the Willesden Green Glauconite 'C' pool of Alberta, Canada using numerical simulation. Well logs were digitized and used in connection with core and well test data to generate the geological properties used in the simulator. The history matched gas in place volumes were in turn used to determine interactively the permeability cut-off value from well logs. Finally, having history matched the past field performance, the optimum infill drilling scenarios coupled with requirements to surface facilities were predicted.
Results of numerical simulations for various combinations of infill drilling and improvements to the surface gathering facilities are presented. Two of the better potential infill locations predicted by the numerical simulation was drilled in the field. In addition, some of the surface gathering facilities were modified in the direction of the recommendations from the simulation. The actual field performance is discussed and a comparison is made between the predictions of the numerical simulation study and the actual field behavior. It is shown that numerical simulation coupling reservoir behavior with the surface network can be used effectively in an integrated approach to optimize the recovery from a low permeability gas field.

Introduction
Willesden Green Glauconite "C" pool was discovered approximately 16 years ago in the area of central Alberta, Canada. Subsequent drilling delineated a relatively large gas pool in the Glauconite horizon. This horizon is the basal member of the Mannville formation. The formation is a sandstone deposit with variable argillaceous and silty material present and is found at a total subsea depth of 1391 m. The main trapping mechanism is a permeability pinchout. No wells to date have penetrated a gas-water contact. A map of the estimated reservoir boundaries prior to this study and currently existing wells are shown in Figure 1. The pool is being operated by two different companies at present and the Newport owned lands are shown in grey in Figure 1. The southeast part of the pool including sections 15, 16, 22, 24, 25 and 30 (wells 11–15, 08–16, 08–22, 11–25, 14–29 and 13–30) are owned and operated by Newport.
The average reservoir properties include porosity in the range of 5 to 14 %, permeability up to 16 mD (mostly in 1 to 5 mD range), net thickness up to 16 m. The upper parts of the producing zone is of higher quality than the lower parts. The average connate water saturation is 35 %. The area of the pool of interest comprises some 4000 hectares. The pool was discovered at an average reservoir pressure of 25500 kPa. The gas has a gravity of 0.689 and contains a moderate amount of condensate (50 bbl/mmscf). It is believed that there is no free condensate in the reservoir and that the gas is free of water at the reservoir sandface.
The pool was depleted at a rate of about 70.0 × 103 m3/d (2.4 mmscf/d) for the first 7 years of production. Newport acquired the property in September 1993, installed compression and drilled 3 delineation wells (11–25, 08–22 and 08–16) subsequently, increasing the production to a rate of 340.0 × 103 m3/d (12.1 mmscf/d) within 9 months from the acquisition date. When the three new wells were drilled they encountered pressures within the reservoir that appeared much higher than the original wells' current pressures.
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