Abstract

The problem of water coning has plagued the petroleum industry for decades. Both gas and oil wells are assailed by this phenomenon which, in almost every case, results in eventual shut in of the well and substantial loss in revenue. The problem occurs in every quadrant of the globe and engineers view its resolution as a technical "holy grail".

This paper discusses the problem of water coning and offers a potential solution for serious water-coning reservoirs. The use of a coning simulation model, incorporating chemical treatment options, is also discussed wherein the optimal treatment volume is computed. An analysis of the axial and radial velocity gradients appears to hold promise as a means by which the size of a water shut-off treatment can be estimated. The time of water shut-off treatment in the life of a producing well is investigated indicating that early application of water shut-off is better than after the cone is fully developed. A review of chemical solutions is included and some of the laboratory tests that can be conducted to analyze potential treatments.

This paper brings to the evaluation of water coning state of the art techniques which should help to separate fact from fiction concerning upside for water coning wells.

BACKGROUND

Water production in oil and gas wells has been a problem for many years. Commonly, reservoirs have an aquifer beneath the zone of hydrocarbon. If the aquifer is large it may act as a constant-pressure lower boundary. In such cases, this bottom-water boundary condition constitutes an infinite aquifer. This results in excellent production support replacing all voidage induced by the production of the hydrocarbon. However significant the benefit of a strong water drive, if the water drive dominates and fills the near well-bore region with water (literally a cone of water in the region of the producer - thus the name of water coning) then hydrocarbon production suffers and in some cases the well may become uneconomic. Depending on the variables of the reservoir, in-situ fluids, production protocol and completion interval, the well may exhibit more or less serious coning problems.

The Darcy equation is very useful in describing the phenomenon of water coning. Equations 1 and 2 define this simple relation for the case of oil and water flow.

(equations (1) is available in full of paper) (equations (2) is available in full of paper)

Darcy stated that the velocity of the fluid is inversely proportional to the viscosity of the phase and proportional to the absolute permeability, the relative permeability and the pressure gradient of that phase. As the pressure gradient increases, the more mobile phase begins to dominate production. Typically, water is more mobile and, therefore, water production increases relative to the rate of oil production.

(equations (3) is available in full of paper) (equations (4) is available in full of paper)

Dividing Equation 2 by Equation 1 shows the ratio of water velocity to oil velocity very clearly as Equation 3 (neglecting capillary pressure), which is the common mobility ratio.

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