Multiple Phase Behavior in Porous Media During CO2 or Rich-Gas Flooding
- J.L. Shelton (Amoco Production Co.) | L. Yarborough (Amoco Production Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1977
- Document Type
- Journal Paper
- 1,171 - 1,178
- 1977. Society of Petroleum Engineers
- 5.4.2 Gas Injection Methods, 1.6.9 Coring, Fishing, 4.3.4 Scale, 6.5.2 Water use, produced water discharge and disposal, 4.1.2 Separation and Treating, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4.3.3 Aspaltenes, 5.6.5 Tracers, 5.2.1 Phase Behavior and PVT Measurements, 5.2 Reservoir Fluid Dynamics, 5.4.1 Waterflooding, 5.3.2 Multiphase Flow, 5.3.4 Reduction of Residual Oil Saturation, 2.7.1 Completion Fluids, 4.6 Natural Gas, 4.1.5 Processing Equipment
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Mixing oil with high-ethane-content hydrocarbon gases or CO2 can produce multiple liquid phases and an asphaltic precipitate in low-temperature reservoirs. The residual saturation that occurs in a reservoir displacement is not significant from a recovery standpoint, but may produce three-phase relative permeability effects that reduce injectivity produce three-phase relative permeability effects that reduce injectivity and, thus, oil recovery rate during alternate gas-water injection.
Multiple-contact miscible gas flooding has the potential for economically recovering a significant amount of incremental oil over that recoverable by conventional waterflooding. Under appropriate reservoir pressure and temperature conditions, rich gas or carbon dioxide will miscibly displace the oil it contacts. Water is injected alternately with the gas to decrease the mobility ratio and, thus, improve the sweep. One such project using rich gas in a West Texas reservoir has been described previously. However, unanticipated reduction in water injectivity occurred after injection of the first batch of rich gas, and indications were that the problem existed in depth within the reservoir and was not just a wellbore problem. Harvey et al. present the results of field studies that led to the work presented in this paper. Native-state reservoir core tests showed that the injectivity reduction could be caused by a residual oil saturation of a few percent of pore volume behind the rich-gas bank. A small amount of residual oil resulted in unusually high trapped gas saturation and a resulting decrease in water relative permeability. permeability. A small residual oil saturation and, hence, a lowered water injectivity, could arise in the field if oil was bypassed because of small-scale reservoir rock heterogeneities or if the rich gas did not completely displace all the oil contacted. Factors that produce incomplete displacement of contacted oil are presented. PVT cell data are presented that show the occurrence of PVT cell data are presented that show the occurrence of two liquid phases and an asphaltic precipitate when high-ethane-content rich gas and reservoir oil are mixed at reservoir conditions. Core tests are described showing that the formation of multiple phases results in a residual hydrocarbon saturation during displacement. Similar but less detailed studies of a CO2-oil system are also presented. Other authors, observed multiple liquid-phase presented. Other authors, observed multiple liquid-phase phenomena with some miscible gases and West Texas phenomena with some miscible gases and West Texas oils, but did not evaluate the effect on oil displacement.
Windowed Cell Tests Procedure Procedure The general procedure used was to place the driving gas into a variable-volume windowed cells that was held at the reservoir temperature. The driving gases used were rich gas and CO2. A known amount of recombined reservoir oil was combined with the driving gas in the cell. A phase distribution test starting at a high pressure (usually 4,000 to 8,000 psi) was performed on this oil-driving gas mixture. This test consisted of a constant-composition expansion, during which the total volume of the cell and the distribution of the phases in the cell were measured at a known pressure. Upon completion of the phase distribution test, additional oil was introduced into the cell and another phase distribution test was performed. These tests, which were designed to simulate mixtures in the driving gas-rich region of all possible oil-driving gas mixtures, were terminated when sufficient oil had been added to dissolve all the driving gas in the cell. Any mixtures containing additional oil would have bubblepoint pressures that decrease regularly down to the saturation pressure of the recombined oil.
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