Effect of Free Gas Saturation on Oil Recovery by Water Flooding

1951 ◽  
Vol 3 (05) ◽  
pp. 135-140 ◽  
Author(s):  
C.R. Holmgren ◽  
R.A. Morse
Keyword(s):  
Oil Recovery ◽  
Water Flooding ◽  
Free Gas ◽  
Gas Saturation

Three-Phase Imbibition Relative Permeability

10.2118/90-pa ◽  
1961 ◽  
Vol 1 (04) ◽  
pp. 254-258 ◽  
Author(s):  
J. Naar ◽  
R.J. Wygal
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Water Flooding ◽  
Pressure Curve ◽  
Complete Wetting ◽  
Oil Saturation ◽  
Gas Saturation ◽  
Three Phase ◽  
Oil Gas ◽  
Wetting Fluid

Abstract An equation for three-phase (water, oil, gas) imbibition oil permeability is developed, assuming the water to be the dominant wetting fluid. Oil isoperms are obtained for consolidated sandstones characterized by. The evolution of an oil-gas system imbibing water from is shown to proceed along a line of constant oil saturation with increasing oil permeability and decreasing gas saturations. When the gas saturation cannot be reduced further, the system evolves along a line of constant with decreasing oil saturation and permeability. The initial gas saturation is shown to reduce markedly the effect of complete wetting by either oil or water on flow performance. Introduction Imbibition oil isoperms are required for performance prediction when a well is producing water, oil and gas. This situation occurs in multiphase displacements such as underground combustion, steam injection and the water flooding of highly depleted reservoirs. In a recent paper, a model was presented for the prediction of two-phase imbibition characteristics. This paper extends the imbibition model to the case of three phases by assuming that the water is the dominant wetting fluid. The following results were obtained from the model:an analytical expression of oil isoperms;oil isoperms as functions of reduced water, oil and gas saturations, valid for all sandstones having a capillary pressure curve which can be approximated by; andevaluation of the three-phase flow performance as dictated by complete wetting by either oil or water. The agreement between predicted and observed oil recovery in the presence of a gas phase, reported in Ref. 1, is a partial support for the present development. However, experimental data are not available at this time to check fully the model predictions. Perhaps this paper will stimulate the collection of such data. THEORETICAL The imbibition model of a porous medium has been described previously, and the reader is referred to the paper of Naar and Henderson for details. In brief, the model is formed by the random interconnection of straight capillaries, with a provision for the blocking of the non-wetting phase by the invading wetting fluid.

scholarly journals Pore-Scale Simulation of Particle Flooding for Enhancing Oil Recovery

Energies ◽  
2021 ◽  
Vol 14 (8) ◽  
pp. 2305
Author(s):  
Xiangbin Liu ◽  
Le Wang ◽  
Jun Wang ◽  
Junwei Su
Keyword(s):  
Oil Recovery ◽  
Flow Behavior ◽  
Ct Scanning ◽  
Water Flooding ◽  
Pore Scale ◽  
Simulation Techniques ◽  
Three Phase ◽  
Remaining Oil ◽  
Three Phase Flow ◽  
Displacement Force

The particles, water and oil three-phase flow behaviors at the pore scale is significant to clarify the dynamic mechanism in the particle flooding process. In this work, a newly developed direct numerical simulation techniques, i.e., VOF-FDM-DEM method is employed to perform the simulation of several different particle flooding processes after water flooding, which are carried out with a porous structure obtained by CT scanning of a real rock. The study on the distribution of remaining oil and the displacement process of viscoelastic particles shows that the capillary barrier near the location with the abrupt change of pore radius is the main reason for the formation of remaining oil. There is a dynamic threshold in the process of producing remaining oil. Only when the displacement force exceeds this threshold, the remaining oil can be produced. The flow behavior of particle–oil–water under three different flooding modes, i.e., continuous injection, alternate injection and slug injection, is studied. It is found that the particle size and the injection mode have an important influence on the fluid flow. On this basis, the flow behavior, pressure characteristics and recovery efficiency of the three injection modes are compared. It is found that by injecting two kinds of fluids with different resistance increasing ability into the pores, they can enter into different pore channels, resulting in the imbalance of the force on the remaining oil interface and formation of different resistance between the channels, which can realize the rapid recovery of the remaining oil.

Estimation of gas-hydrate concentration and free-gas saturation at the Norwegian-Svalbard continental margin

2005 ◽  
Vol 53 (6) ◽  
pp. 803-810 ◽  
Author(s):  
José M. Carcione ◽  
Davide Gei ◽  
Giuliana Rossi ◽  
Gianni Madrussani
Keyword(s):  
Continental Margin ◽  
Gas Hydrate ◽  
Free Gas ◽  
Gas Saturation

An Easy Calculation Method on Sweep Efficiency of Chemical Flooding

2013 ◽  
Vol 275-277 ◽  
pp. 496-501
Author(s):  
Fu Qing Yuan ◽  
Zhen Quan Li
Keyword(s):  
Oil Recovery ◽  
Orthogonal Design ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Solution Viscosity ◽  
Chemical Flooding ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Easy Calculation ◽  
Polymer Compound

According to the geological parameters of Shengli Oilfield, sweep efficiency of chemical flooding was analyzed according to injection volume, injection-production parameters of polymer flooding or surfactant-polymer compound flooding. The orthogonal design method was employed to select the important factors influencing on expanding sweep efficiency by chemical flooding. Numerical simulation method was utilized to analyze oil recovery and sweep efficiency of different flooding methods, such as water flooding, polymer flooding and surfactant-polymer compound flooding. Finally, two easy calculation models were established to calculate the expanding degree of sweep efficiency by polymer flooding or SP compound flooding than water flooding. The models were presented as the relationships between geological parameters, such as effective thickness, oil viscosity, porosity and permeability, and fluid parameters, such as polymer-solution viscosity and oil-water interfacial tension. The precision of the two models was high enough to predict sweep efficiency of polymer flooding or SP compound flooding.

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