Cold Waterflooding a Warm Reservoir
Authors: Weinstein Herbert G. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 words. illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A thermal simulation program and a theoretical analysis consider the effects of cold waterflooding a warm reservoir. For the conditions investigated, the injected water quickly cools the region surrounding the wellbore and accounts for the major part of the pressure drop across the system. Heating the injected water or fracturing the formation each decrease the pressure drop and can be used to avoid an pressure drop and can be used to avoid an uncontrolled fracture or the need for costly, highpressure surface injection equipment. The study showed that thermal effects can play a major role in the economics of waterflooding projects.

Introduction

Several authors have discussed pressure falloff testing in reservoirs that develop fluid banks during improved oil recovery projects. Falloff testing has been used to track the movement of the burning front during in-situ combustion and to locate the position of the outer radius of a water bank. Kazemi et al. used a radial reservoir simulator to assist in interpreting pressure falloff tests in systems having fluid banks.

Fluid banks may arise due to the injection of a fluid having properties different from the reservoir fluids. This creates discontinuities between the region where the injected fluid predominates and the region(s) where the predominates and the region(s) where the reservoir fluids predominate. Examples of such systems are 1) reservoirs being waterflooded, 2) reservoirs undergoing in-situ combustion, and 3) reservoirs receiving gas injection.

This paper considers thermal effects in banks that arise when flooding a reservoir with water having a temperature considerably below that of the reservoir.

DISCUSSION AND RESULTS

As part of a pressure-maintenance program in an extensive field, it has been proposed to inject 70 degrees F surface water at the rate of 300,000 BPD into the 285 degrees F formation. For the well patterns and spacing currently under consideration, the injection rate would be about 10,000 BPD/well.

The steam-stimulation model described by Weinstein et al. was used to investigate 1) the extent to which the reservoir and surrounding strata would heat the injected water and 2) the dependence of the pressure drop across the system on injection rate, permeability-thickness product, injected water temperature, and the product, injected water temperature, and the presence of a vertical fracture. presence of a vertical fracture.