Abstract

Results of a reservoir condition core flood were matched by a compositional model. Using this model as a base case, the effect of gas composition on oil recovery from an onshore Australian oil field was investigated.

Based on this and earlier studies it was found that CO2 injection in this field gave MMP values well within proposed injection pressures. Even at concentrations of methane as high as 50% and CO2 of approximately 25%, oil recoveries remained only slightly under that of pure CO2 so long as significant quantities of C3+ were retained in the injection gas stream.

This effect of the C3+ fraction was further investigated by isolating the effect of n-pentane in the injection gas on a 92 mol% CO2 and 8 mol% methane gas mix. It was found that while recoveries certainly improved, the economic gain from the extra recovery is likely to be outweighed by the cost of n-pentane.

Introduction

Field A is a very tight sandstone reservoir (average permeability of approximately 1 mD) containing a volatile oil of 51 °API and solution gas-oil ratio of 1263 scf/stb1.

To date the recovery has been only 3–4% of the original-oilin- place, and simulation studies indicate a recovery at abandonment of some 5–10%. Hence, it is envisaged that a suitable EOR scheme may help improve recovery. With a suitable gas injection process, it is estimated that the ultimate recovery would increase to 20–30%.

The reservoir is essentially produced by depletion drive. Although there is an indication of some aquifer support, little data are available to analyze its impact.

Due to the tight nature of the reservoir, the required water flooding injectivity pressures would be impractically high. However, fluids with much lower viscosities than water, such as carbon dioxide or hydrocarbon gases, would have a higher injectivity. Therefore, the viability of flooding the reservoir with a gas would be much greater.

A summary of Field A reservoir properties is provided in Table 1. Average porosity throughout the oil bearing formations of Field A is low at ∼7–11%. The initial reservoir pressure of Field A was approximately 4200 psig. The reservoir pressure in the northeastern part of the reservoir is currently approximately 3150 psig while in the southwestern part of the reservoir it has been depleted to approximately 2700–2800 psig. The oil has a low viscosity (0.14 cP) at reservoir conditions. Reservoir temperature is quite high at 279 °F.

In the past ethane has been injected in a neighboring oilfield with success2. Both the neighboring oilfield and Field A produce mainly from the same rock formation and have similar reservoir rock and fluid properties. Although the primary motivation for ethane injection at the neighboring field was to store it, it also contributed to improved oil recovery.

An important conclusion derived from the ethane injection experience is that injectivity of ethane was not a major concern.

This content is only available via PDF.
You can access this article if you purchase or spend a download.