Laboratory Design of a Gravity-Stable Miscible CO2 Process
- R.L. Cardenas (Texaco Inc.) | R.B. Alston (Texaco Inc.) | A.J. Nute (Texaco Inc.) | G.P. Kokolis (Texaco Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- January 1984
- Document Type
- Journal Paper
- 111 - 118
- 1984. Society of Petroleum Engineers
- 5.3.4 Reduction of Residual Oil Saturation, 5.4.2 Gas Injection Methods, 3.1.6 Gas Lift, 4.1.9 Tanks and storage systems, 4.1.2 Separation and Treating, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4.9 Miscible Methods, 5.2.1 Phase Behavior and PVT Measurements, 4.6 Natural Gas, 5.4.1 Waterflooding, 4.1.5 Processing Equipment, 5.3.2 Multiphase Flow, 2.4.3 Sand/Solids Control, 5.4 Enhanced Recovery
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In dipping reservoirs, such as those of the Louisiana gulf coast area, tertiary oil can be recovered by gravity-stable miscible CO2 solvent floods. Laboratory design of gravity-stable floods requires extensive experimental studies to select the proper composition and size of the injected CO2 solvent slug. In a gravity-stable process the injected CO2 solvent slug must be less dense than the oil and water under reservoir conditions. and the injected drive gas must be less dense than the CO2 solvent slug. Laboratory experiments showed that the CO2 solvent slug can be tailored to achieve the density required for a particular gravity-stable application by the addition of methane. Additional studies demonstrated that, if required, various hydrocarbons can be added to the CO2 solvent slug to ensure miscibility with the reservoir oil.
Studies were performed to determine density and viscosity of the oil, CO2 solvent, nitrogen. and CO2 solvent/oil mixtures under reservoir conditions. A number of displacement tests at reservoir conditions were conducted in a 12.19-m [40-ft] slim-tube apparatus to determine the miscibility of various CO2 solvent mixtures with reservoir oil. Further floods were produced under reservoir conditions in a 3.66-m 112-ft] sandpack system. These floods were conducted at velocities less than the critical velocity to prevent growth of viscous fingers. The results show that after miscibility was achieved, the injected CO2 solvent mixture effectively removed all the residual oil left after waterflooding. The 3.66-m [12-ft] sandpack floods also provided data to determine dispersion parameters for the leading and trailing edges of the CO2 solvent slug. This information was used to estimate the CO2 solvent slug size for Texaco's gravity-stable CO2 solvent miscible flood in its Bay St. Elaine field, Terrebonne Parish, LA.
A gravity-stable miscible CO2 process can be established in a dipping reservoir by updip injection of a properly designed CO2 solvent. Gravitational forces will stabilize the flowing front because of the density difference between the less dense injected CO2 solvent and the more dense displaced oil and water. A gravity-stable miscible CO2 process was designed at Texaco's Bellaire (TX) Research Laboratories for use in an EOR project at the Bay St. Elaine field. Terrebonne Parish, LA.
The project is being conducted in the Miocene 8000 Foot Reservoir E Sand Unit (RESU). Table 1 presents sonic key reservoir data. Reservoir E is bounded on two sides by faults and is truncated updip by an unconformity. This reservoir, with its 36 degrees dip and confined nature. was determined a good EOR candidate for a gravity- stable CO2 miscible flood.
Fig. 1 shows a cross section of Reservoir E between the CO2 Injection Well 22-26 and one of the downdip producers, Well 22-5. From the outset, the oil-recovery process envisioned was an updip injection of a CO2 solvent slug, followed by nitrogen drive gas. Once miscibility is established, an oil bank is formed, followed by an oil/CO2 solvent transition zone, CO2 solvent, the CO2 solvent/drive fluid (nitrogen) transition zone, and finally pure drive fluid.
Various laboratory studies were performed to design and implement a gravity-stable process in the Bay St. Elaine field. These studies provided the necessary data to design the field project and to evaluate its feasibility and potential success. The laboratory studies conducted to obtain the design data for this project consisted of (1) a PVT study of the reservoir oil, (2) the CO2 solvent PVT properties at reservoir conditions, (3) the miscibility of the CO 2 solvent with reservoir oil at design conditions in slim-tube displacement tests, (4) the phase behavior ofthe CO2 solvent/oil mixture, and (5) sandpack floods to determine longitudinal dispersion coefficients and coninn miscible displacement of the reservoir oil by the selected CO2 solvent-that is, to determine linear displacement efficiency. This paper discusses each study.
Reservoir Oil PVT Study. A PVT study of the Bay St. Elaine reservoir oil was performed to determine solution gas/oil ratio (GOR), bubblepoint pressure, formation volume factor (FVF), density. and viscosity as a function of pressure. For this project, the density and viscosity were the most important properties because of the basic design criteria for a gravity-stable flood.
In late 1978, existing wells in the project area and adjacent segments were either off production in the 8000 Foot Sand or were not completed in this sand. Available wells producing from the 8000 Foot Sand in the nearby Segment 850 were on gas lift and could not be used to obtain an uncontaminated reservoir oil sample.
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