Flooding immiscible

Enhanced oil-recovery processes include chemical and gas floods, steam, combustion, and electric heating. Gas floods, including immiscible and miscible processes, are usually defined by injected fluids (carbon dioxide, flue gas, nitrogen, or hydrocarbon). Steam projects involve cyclic steam (huff and puff) or steam drive. Combustion technologies can be subdivided into those that autoignite and those that require a heat source at injectors [521]. 

Wettability is defined as "the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids" (145). Rock wettability can strongly affect its relative permeability to water and oil (145,172). Wettability can affect the initial distribution of fluids in a formation and their subsequent flow behavior. When rock is water-wet, water occupies most of the small flow channels and is in contact with most of the rock surfaces. The converse is true in oil-wet rock. When the rock surface does not have a strong preference for either water or oil, it is termed to be of intermediate or neutral wettability. Inadvertent alteration of rock wettability can strong alter its behavior in laboratory core floods (172). 

Elkamel, A. (1998) An artificial neural network for predicating and optimizing immiscible flood performance in heterogeneous reservoirs. Computers el Chemical Engineering, 22, 1699. 

Immiscible carbon dioxide displacement injection of carbon dioxide into an oil reservoir to effect oil displacement under conditions in which miscibility with reservoir oil is not obtained see Carbon dioxide augmented water-flooding. 

When two phases are mixed together (gas-liquid, immiscible liquid-liquid), a fine dispersion of bubbles or drops and a high specific interfacial area are produced because of the intensive turbulence and shear. For this reason, resistance to interphase mass transfer is considerably smaller than in conventional equipment. In addition, a wide range of gas-liquid flow ratios can be handled, whereas in stirred tanks the gas-flow rate is often limited by the onset of flooding. Mass transfer coefficients (kLa) can be 10-100 times higher than in a stirred tank. 

Figure 1.) The channeling can occur with either miscible or immiscible floods and results in much lower production of the displaced fluid for any given throughput of the injection fluid once the latter reaches the production well (10,12,15). The problem, which is common to water flooding and to all EOR processes, is most severe for gas flooding simply because it is in gas flooding that the injected fluids have the lowest viscosities (most unfavorable mobility ratios).

The surfactant did not cause viscous forces to dominate during immiscible tertiary carbon dioxide injection. Apparently, the unmobilized oil reduced the foam stability while the surfactant reduced the interfacial tension and therefore the COj-brine capillary pressure sufficiently to allow gravity effects to dominate the flood.(9)... 

Macroscopic experiments such as core flooding have been used to obtain relative permeabilities, dispersion coefficients, and other variables relevant to reservoir flow. However, they cannot reveal details of how immiscible phases interact on the pore level. Instead visual experiments have been used to elucidate microscopic flow mechanisms. The latter approach is taken here with experiments using a novel flow cell and state-of-the-art video equipment. The pore level phenomena observed provide a basis for the proper modeling of two-phase flow through porous media at high capillary numbers. 

Two sets, i.e., four experiments, of core flow studies are compared. Sets No. 1 and No. 2 were tertiary miscible and immiscible CO2 floods without mobility control. The same core from each set, after plain CO2 injection, was restored to waterflood residual oil saturation and flooded with 0.05% AEGS 25-12 surfactant in brine. There was almost no difference between the oil saturation distributions in the cores between experiments, with the average Sorw values of 37 1 saturation percent in both sets of experiments. CO2 was injected continuously in all experiments at a nominal rate of 1 ft/day. No attempt was made to preform a foam, or to inject alternate slugs of surfactant solution and CO2. 

IMMISCIBLE CO2/OIL. SET NO. 2. EXPERIMENT NO. 3. This experiment should be compared with experiment No. 1. The CT scans showed a sharp, nearly vertical, CO2 front without viscous fingering. Figures 14a-d. The CO2 entered the core in the upper half of the inflow face and then swept down, forming a small layover angle. A C02-free oil bank developed during the flood but was overtaken by the faster moving CO2. CO2 and oil production were simultaneous at the outflow end of the core. 

IMMISCIBLE CO2/QIL WITH LOWERED CO /BRINE IFT. SET NO. 2. EXPT. NO. 4. The core used in experiment No. 3 was restored to water flood residual oil saturation and flooded with 0.05 wt% AEGS 25-12 surfactant in brine, and then CO2. Initially, the CO2 began to sweep the entire core cross section and build an oil bank similar to the one observed in experiment No. 3. Then the CO2 buoyed up and overrode the water and oil banks. Figures 15a-d. The result is both poor sweep and poor displacement of oil. 

The beneficial surfactant effects observed during miscible CO2 flooding did not extend to the case when the oil and CO2 are immiscible. A viscous foam did not form or propagate, and the reduced capillary pressure due to surfactant IFT lowering allowed the CO2 to override the brine and oil banks. 

Tertiary oil was increased up to 41% over conventional CO2 recovery by means of mobility control where a carefully selected surfactant structure was used to form an in situ foam. Linear flow oil displacement tests were performed for both miscible and immiscible floods. Mobility control was achieved without detracting from the C02-oil interaction that enhances recovery. Surfactant selection is critical in maximizing performance. Several tests were combined for surfactant screening, included were foam tests, dynamic flow tests through a porous bed pack and oil displacement tests. Ethoxylated aliphatic alcohols, their sulfate derivatives and ethylene oxide - propylene oxide copolymers were the best performers in oil reservoir brines. One sulfonate surfactant also proved to be effective especially in low salinity injection fluid. 

Results of Immiscible Displacement Tests. The results of the tests show that immiscible carbon dioxide flooding followed by waterflooding is effective in increasing the oil recovered from a core. The oil recovered by a conventional waterflood was equal to about 30.4% of a pore volume, PV. Immiscible carbon dioxide flooding increased the recovery to a total of 50.5% PV. The addition of a mobility control agent increased the recovery further to 58.3% PV this amounts to 39% additional tertiary oil due to the effectiveness of the mobility control in the carbon dioxide immiscible process. 

Figure 8. Immiscible CO2 flood with mobility control.

The displacement tests show that a signiflcant increase in tertiary oil production can be achieved when one of the better additives is utilized in 1-dimensional laboratory immiscible carbon dioxide floods. In the miscible displacement case no adverse effect on the miscibility process was found. In... 

Nelson and Pope concluded that chemical flood design should be such as to maintain as much surfactant as possible in the type III phase environment. This condition can be accomplished by designing the micellar fluid such that the initial phase environment of the immiscible displacement is type II(+). A negative salinity gradient is imposed, and it moves the phase environment to type III and, eventually, to II(-). 

Chemical methods of EOR are usually carried out by using water or brine as the carrier fluid. The exception is foam flooding, which also involves an immiscible gas as the driving fluid. Although various chemical methods can be used by themselves, studies have shown synergism in their combined application. 

Healy, R.N., Reed, R.L., 1977a. Immiscible microemulsion flooding. SPEJ (April), 129-139. 

Hydrocarbon-miscible flooding refers to an oil recovery process in which a solvent , usually a mixture of low and intermediate molecular-weight hydrocarbons (methane through hexane), is injected into a petroleum reservoir. Several mechanisms contribute to oil recovery in this process displacement of oil by solvent through the generation of miscibility between solvent and oil, oil swelling with a resulting increase in oil saturation and therefore in oil relative permeability, and reduction of oil viscosity. When solvent and oil remain immiscible, a reduction of gas-oil interfadal tension leads to improved oil recovery. 

The proportion of enhanced oil production that is caused by hydrocarbon-miscible and, to a lesser extent, immiscible flooding is evident from Table I. Hydrocarbon-flooding dominates in Canada, where it accounts for 81% of Canada s enhanced oil recovery (EOR) production. Although steam-flooding is the most commonly applied EOR process in the United States, oil production from hydrocarbon-flooding is significant and has increased by more than the production from any other EOR process over the past 2 years. In countries other than the United States and Canada, most of the oil recovered by hydrocarbon-flooding comes from Libya, but hydrocarbon injection is also applied in the Soviet countries and in the United Arab Emirates (J). 

These results suggest that when the electrocatalytic zone is completely immersed in the perfluorocarbon fluid the diffusion of the reactants and/or products to the catalyst site is impeded by the blocking effect of the additive, which can be described as a flooded system. It is possible that the fluid also interacts with the ionomeric material in the electrocatalytic mixture, decreasing the ability to function as an proton conducting material owing to immiscibility of water with the perfluorocarbon compounds. However, the facility of reaction greatly increases as more of perfluorocarbon exits the system, as shown in Fig. 1.28. These results indicate that the presence of perfluorocarbon fluids have some beneficial effects upon the kinetics of oxygen reduction at Nafion -H-... 

Water injection from seawater or fresh water sources contributes to the souring of oil fields with H2S usually resulting in an increase in the corrosion rate, which sometimes requires a complete change in corrosion strategy. These water sources may necessitate biocide injection and will require deaeration to avoid introducing a new corrosion mechanism into the existing system. Tertiary recovery techniques are often based on miscible and immiscible gas floods. These gas floods invariably contain a... 

A consequence of the use of advanced technology in oil production from a reservoir results in increase in the corrosivity of the oil production environment. The extent of corrosion increases because (i) oil, water, and gas are present in the field. Seawater or fresh water is injected downhole to drive oil out of formation. As time passes, the amount of water to the amount of oil increases and the degree of internal corrosion increases. Water injection from seawater or fresh water sources causes souring of oilfields with H2S and increases in corrosion rate. These water sources require biocide injection and deaeration to avoid the introduction of new corrosion pathways into the existing system. Tertiary recovery techniques involve miscible and immiscible gas floods that may contain as much as 100% CO2. This leads to high corrosivity of the fluids. 

Emulsions formed in crude oil and bitumen during extraction operations are usually water-in-oil (W/O) macroemulsions (>0.1 to 100 om in diameter). Macroemulsions are kinetically stable, unlike microe-mulsions, which are thermodynamically stable. In conventional oil recovery (high-energy process), the crude is often in contact with formation water or injection water, as in secondary recovery. In tertiary or enhanced oil recovery, surfactants are used purposely in water floods to make microemulsions for enhancing the flowability of the crude. Crude-oil macroemulsions are produced when two immiscible liquid phases such as oil and water are mixed via the input of mechanical or thermal energy into the processes. Conventional crudes held under high pressures and temperatures amidst... 

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