Abstract
Engineering methods are being developed to evaluate reservoir fluid systems for Suitability to CO2 flooding. This paper presents our evaluation procedure as applied to laboratory data for a high-pour-point [95 degrees F (35 degrees C)] oil from the Red Wash field in Utah. The data were obtained from phase behavior and slim tube experiments.
The results of this work indicate that high pressures are required for a miscible displacement of the highly paraffinic. high-pour-point Red Wash oil. The minimum miscibility pressure (MMP) was found to be 4,650 psia (32 060 kPa), increasing only 5% to 4,900 psia (33 784 kPa) when the injected CO2 contains a 10 mol% nitrogen contaminant. These pressures are not currently economically obtainable in the Red Wash field.
lntroduction
The Red Wash field is located in Utah in the northeastern Uinta basin. With a comparatively low ultimate recovery predicted from primary depletion and waterflooding operations, the field is considered an attractive condidate for tertiary recovery methods. The work reported in this paper presents laboratory experiments and calculation techniques used in evaluating reservoir fluids for CO2 flooding. The laboratory work includes constant composition experiments, vapor/liquid equilibrium experiments, liquid-phase viscosity experiments, and slimtube multiple-contact miscibility experiments. Calculation techniques utilized a two-constant equation of state (EOS) to predict phase behavior and fluid properties.
One CO2 source available in the area contains approximately 10 mol% nitrogen. To evaluate the effect of nitrogen contamination, experiments were performed with two different gases, one with and one without the nitrogen contaminant.
Red Wash Oil/CO, Gas Physical Property Measurements
Physical property data for the Red Wash oil/CO2 gas system were obtained from constant composition expansion (CCE), vapor/liquid equilibration (VLE), and liquid-phase viscosity experiments.
CCE experiments were conducted to determine the pressure/composition behavior (bubble-point/dew-point envelope) of Red Wash oil and injection gases. VLE experiments measured vapor/liquid equilibrium constants (K values). Liquid-phase viscosities determine to what extent injection gases dissolved in the liquid phase affect the flow behavior of the reservoir oil.
All experiments used Red Wash reservoir oil and two different injection gases. The first CO2 gas (Gas 1 ) was approximately 5 mol% methane and 95 mol % CO 2. The second CO2 gas (Gas 2) contained about 10 mol% nitrogen, 5 mol% methane, and 85 mol %, CO2. The exact compositions of Gases 1 and 2 and Red Wash reservoir oil are shown in Table 1.
CCE Experiments
A high-pressure visual PVT cell was used in the CCE experiments. All experiments were conducted at the reported reservoir temperature of 130 degrees F (54.4 degrees C). During each CCE the visual cell was loaded with measured volumes of Red Wash oil and injection gas.
SPEJ
P. 587^
Simulation and discussion of CO2 flooding associated gas separation by mixed amine absorption method
