Horizontal Well Length: Drill Short or Long Wells?
Authors: El-Sayed Samir , Beckie Bill 
Published: December 2007

In a previous paper Ref. 1 it was mentioned that the reserves of horizontal wells of heavy oil over water is not linearly related to the well length. A series of workovers were performed to verily this conclusion. New wells were especially designed to account for the non-linear relationship between reserves and length for wells longer than the optimum for reserves per meter. This paper is an update with regard to the technique of segmenting the well and producing different segments separately. The main criteria for the success of the technique is to increase the reserve of the well while maintaining a relatively high oil rate to maximize revenue.

Details of a new water shut-off method specifically suitable to water conning is described in detail.

Introduction

The Winter field (Fig. 1) has been developed utilizing horizontal wells to produce heavy oil (13.7 API oil of 2800 cp. viscosity) in a 12 m (37 ft.) thick Cummings sand underlain by a very strong aquifer. Ref. 1 showed that the reserve per well for the first six phases (each year program is called a phase) is the same despite the fact that the average well length for the different phases varied from 574m. (1883 ft.) to 1111 m. (3645 ft.). It also showed that for over 250 horizontal wells, producing oil over water reservoirs in Saskatchewan, the reserves per well is not linearly related to the well length once the well length is longer than 500 m. (1640 ft.). Both of the above lead to assume that for a long well (longer than a critical value around the 500 m) the nature of the pressure distribution in the wellbore and sand face together with the oil water interface being close, premature conning takes place close to the heal of the well. Once the water table establishes communication to the wellbore, say, 300m. from the heal the well is reduced to 300m long well as far as oil production is concerned. Most of the drawdown will be satisfied by the less viscous water coming from the infinite acting aquifer, and oil production, from the pump intake at the heel to the water entry point, will quickly vanish.

The above diagnosis led to two corrective approaches:try to shut-off the water cone by injecting water shut-off material, andtry to isolate the suspected area of the water cone mechanically.

Water Shut-off Treatments

For a long time the oil industry has been looking for the ideal, cheap, reversible, non-damaging anti-conning or water shutoff material.

Now if we can find a smart fluid that when hot it behaves just like water, preferentially displaces water and as it cools off it becomes less mobile (a solid); it would be ideal for use as a water shut-off material. If with such material the well inflow is reduced below economic values it is easy to restore some inflow. Hot water injection into the well will heat up the well bore and sand-face rendering the material mobile again. Once the well is pumped some of the material will be produced and the productivity of the well is improved.

Wax, yes normal problem causing paraffin wax, was the material of choice. A refinery supplied two samples of paraffin wax, one of them has a melting point of 38-40 degrees C (100–102 F) was considered perfect for the Winter Field of reservoir temperature of 26 degree C (79 F). When the wax is heated to 60-90 degree C (140–195 F) it is very fluid with a viscosity much closer to water than to the 3000 cp. oil.

When a well waters out it is very difficult to induce a draw down even with a high rate of production. If we inject water into the well, it takes it on vacuum. In other words wellbore flow resistance is reduced dramatically. This was another reason to choose hot wax.

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