A Study of Water Coning in the Kaybob South Beaverhill Lake Field

Abstract Water coning in the Kaybob South Beaverhill Lake Gas Field in West Central Alberta was investigated because production in nearby fields demonstrated that it could be a serious operational problem. The formation water is very corrosive and prohibitively expensive to produce. produce. The water coning phenomenon was studied with the help of a numerical calculation model. The data used in the calculations consisted of fluid and rock data, core analyses, and flow test results. Both vertical and radial variations in permeabilities were included as well as an approximation of non-Darcy flow. Two field cases where water breakthrough had occurred were history matched with the model. Based on model calculations for 20 other wells, the critical flow rates of 38 producers were estimated. The results of the model calculations showed that: (1) critical height is the dominant factor in determining critical flow rate; (2) the ratio of horizontal to vertical permeability is next in importance; (3) non-Darcy flow can be approximated in a Darcy flow model; and (4) non-Darcy flow did not have a strong effect on critical flow rates, at least on wells with critical heights of 50 ft or more. Introduction Kaybob South Beaverhill Lake Gas Unit 3, shown in Fig. 1, was developed to meet a required producing capacity of 490 MMcf/D of sour, producing capacity of 490 MMcf/D of sour, condensate gas and a required injection capacity of 260 MMcf/D of dry, recycled gas. Unit 3 contains about 2 Tscf of gas at 4,350 psig and at a depth of about 11,000 ft. About 30 billion bbl of water containing over 200,000 ppm salts underlie the field. The formation water is extremely corrosive, and the costs of producing it are prohibitive. In nearby Pine Creek field, 10 of the 11 gas wells have been shut in due to water production, and in Kaybob South Beaverhill Lake Units 1 and 2, 11 of the 46 producing wells have begun producing water. It was necessary to replace producing water. It was necessary to replace one gathering-system trunk line in Unit 1 due to corrosion after less than 1 1/2 years on production. The costs to drill and tie in a new well are between $400,000 and $500,000. Therefore, economics strongly favor producing the wells at low enough rates to prevent water production. In addition, the Alberta Oil and Gas Conservation Board requires operators of gas fields to investigate potential water coning problems and their effect on ultimate gas problems and their effect on ultimate gas recovery.