Abstract

A series of displacement tests was conducted on preserved reservoir core plugs to assist in estimating waterflood and miscible flood performance potential for the Eagle Lake Viking Reservoir in Saskatchewan. The reservoir rock 1s a heterogeneous sandstone, being comprised of thin interbeds of sand and shale with the sand lenses containing widely different amounts of smecrtite clays. To assess miscible recovery efficiencies in this complex sand, displacements tests were conducted with first contact miscible propane and carbon dioxide. Using standard waterflood relative permeabilities and a dual permeability model, all miscible displacements were matched by simulation with a Todd-Longstaffe-type miscible mixing model.

Introduction

The Eagle Lake Viking reservoir is located in southwest Saskatchewan. It is a sandstone formation of Mississippian age. Discovered in 1957, one half of this 12.7 million cubic meters field was put on waterflood ten years later in 1967. Unfortunately. because of its low permeability, it has been possible to only inject 0.14 pore volumes of water in the subsequent 20 year period. As a result I in the 30 years since discovery only 15 percent of original oil in-place bas been produced. The cause of poor performance appears to be due to the abundant shales and clays. Thin section analyses however, show that bands of higher permeability are also found throughout the pay zone and often exist as thin to very thin sand stringers which are relatively free of clays.

In 1985, operations engineers decided that the half of the field which was still under primary depletion should be placed under some form of secondary recovery. Since the waterflood had been less than satisfactory, it was decided to examine miscible flooding as a potential alternative. Hence a core flooding study using carbon dioxide as a flooding agent was designed with the following objectives:

  1. Quantify carbon dioxide oil displacement efficiency,

  2. Compare carbon dioxide with waterflood oil recovery, and

  3. Compare the potentially complex carbon dioxide miscible oil displacement behavior with a straight forward hydrocarbon solvent displacement using propane.

  4. To extend the initial reservoir design purposes, a was to;

  5. Quantify waterflood and displacement parameters for field simulation.

2.0 RESERVOIR FLUID AND CO2 MISCIBLE PRESSURE

The live all used in this study was obtained by recombining separator gas and liquid to a bubble point pressure of 6,509 kPa at 22 °C. Fluid densities were measured as a function of pressure at the reservoir temperatures of 22 °C and were matched with the Peng-Robinson (1) equation-of-state. Table 1 illustrates the accuracy of this prediction which involved proprietary correlations. This set of data was used in the simulation study.

To determine the first contact miscible pressure for CO2, oil and CO2 were blended in a visual cell at 22 °C. These results and the Peng-Robinson equation-of-state matches are presented in Table 2. The experimentally measured bubble point pressure increased from 6 509 kPa at 0 mole % CO2 to a maximum of 8,446 kPa at 43.9 mole % CO2.

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