Study of a Possible CO2 Flood in Rangely Field
Authors: Graue Dennis J. , Zana E.T. 
Published: December 2007

A study program for CO2 injection in the Rangely field, Rio Blanco County, CO, is reported. The work used laboratory measurements as well as compositional-model calculations to investigate the phase behavior of mixtures of Rangely reservoir oil and CO2 with two different quantities of light gas contamination. The results showed that a CO2 flood in the field is technically feasible under current reservoir pressure and that a 10 mol 070 nitrogen content in the CO2 was detrimental to the process.

Introduction

The Rangely field was discovered in 1933; waterflooding was begun in 1958. The original oil-in-place (OOIP) in the Rangely Weber Sand Unit was approximately 1.6 billion STB (250×106 stock-tank m3). The work reported in this paper was aimed at evaluating the potential of tertiary CO2 flooding in the reservoir. Because some of the possible CO2 sources contain nitrogen, the effect of flooding on process efficiency was investigated. Another objective was to determine the effect of CO2 slug size on oil recovery.

Three types of laboratory studies were conducted:measurement of the phase behavior of the CO2 gas/Rangely reservoir oil system,core displacement experiments at 160°F (71°) and 2,600 psi (17.9 MPa) using Rangely Weber cores that were conditioned with regard to wettability by an aging process, andslim tube experiments to determine minimum miscibility pressure between CO2 gas and reservoir oil.

Each study was performed with two different CO2 gases. The first gas was about 95 mol % CO2 and 5 mol % CH4. The second gas contained 85 mol % CO2, 5 mol % CH4, and 10 mol % N2.

Rangely Reservoir Oil/CO2 Physical Property Measurements

The physical property data were obtained from constant composition expansion (CCE) and vapor/liquid equilibrium experiments (VLE). CCE experiments were conducted to determine the phase envelope (bubble point/dew point envelope). VLE experiments yielded vapor /liquid equilibrium constants (K-values).

Both CCE and VLE experiments were performed using Rangely reservoir oil and two different CO2 gases, designated Gases 1 and 2. The compositions of the gases and Rangely-reservoir oil are shown in Table 1.

CCE Experiments

Figs. 1 and 2 show the pressure/composition diagrams for Rangely oil/Gas 1 and Rangely oil/Gas 2 systems, respectively, at 160°F (71°C). Both systems exhibited a larger single-phase region below 3,000 psi (21 MPa) than a previous system studied.1 Saturation pressure (bubble- and dew-point pressures) for the Gas 2/reservoir oil system were substantially higher than those for the Gas 2/reservoir oil system. This increase is due to 10 mol % N2 in Gas 2. The maximum percent increase in saturation pressure due to N2 contamination occurred at 70 mol % gas concentration. At that concentration, bubblepoint pressure for Gas 2 was 4,720 psi (32.5 MPa) compared with 2,690 psia (18.5 MPa) for Gas 1. These data and those given in Ref. 1 show that the light gases CH4 and N2 decrease the solubility of CO2 in reservoir oils at a given pressure.

Rangely Reservoir Oil/CO2 Physical Property Measurements

The physical property data were obtained from constant composition expansion (CCE) and vapor/liquid equilibrium experiments (VLE). CCE experiments were conducted to determine the phase envelope (bubble point/dew point envelope). VLE experiments yielded vapor /liquid equilibrium constants (K-values).

Both CCE and VLE experiments were performed using Rangely reservoir oil and two different CO2 gases, designated Gases 1 and 2. The compositions of the gases and Rangely-reservoir oil are shown in Table 1.

CCE Experiments

Figs. 1 and 2 show the pressure/composition diagrams for Rangely oil/Gas 1 and Rangely oil/Gas 2 systems, respectively, at 160°F (71°C). Both systems exhibited a larger single-phase region below 3,000 psi (21 MPa) than a previous system studied.1 Saturation pressure (bubble- and dew-point pressures) for the Gas 2/reservoir oil system were substantially higher than those for the Gas 2/reservoir oil system. This increase is due to 10 mol % N2 in Gas 2. The maximum percent increase in saturation pressure due to N2 contamination occurred at 70 mol % gas concentration. At that concentration, bubblepoint pressure for Gas 2 was 4,720 psi (32.5 MPa) compared with 2,690 psia (18.5 MPa) for Gas 1. These data and those given in Ref. 1 show that the light gases CH4 and N2 decrease the solubility of CO2 in reservoir oils at a given pressure.