Sandstone cores

The effect of alkaline preflush was also studied under two different conditions. All of the oil-recovery experiments were conducted under optimal conditions with a viscous, nonacidic oil and with Berea sandstone cores. 

Sandstone rock surfaces are normally highly water-wet. These surfaces can be altered by treatment with solutions of chemical surfactants or by asphaltenes. Increasing the pH of the chemical treating solution decreases the water wettability of the sandstone surface and, in some cases, makes the surface medium oil-wet [1644]. Thus the chemical treatment of sandstone cores can increase the oil production when flooded with carbon dioxide. 

B. licheniformis JF-2 and Clostridium acetogutylicum were investigated under simulated reservoir conditions. Sandstone cores were equilibrated to the desired simulated reservoir conditions, saturated with oil and brine, and flooded to residual oil saturation. The waterflood brine was displaced with a nutrient solution. The MEOR efficiency was directly related to the dissolved gas/oil ratio. The principal MEOR mechanism observed in this work was solution gas drive [505]. 

T. Austad, S. Ekrann, I. Fjelde, and K. Taugbol. Chemical flooding of oil reservoirs Pt 9 Dynamic adsorption of surfactant onto sandstone cores from injection water with and without polymer present. Colloids Surfaces, Sect A, 127(l-3) 69-82, 1997. 

S. Sheppard, M. D. Mantle, A. J. Seder-man, M. L. Johns, L. F. Gladden 2003, (Magnetic resonance imaging study of complex fluid flow in porous media flow patterns and quantitative saturation profiling of amphiphilic fracturing fluid displacement in sandstone cores), Magn. Reson. Imag. 21, 365. 

An assumption implicit in most adsorption studies is that adsorption is fully reversible. In other words, once the empirical coefficients are measured for a particular substance, Equations 20.6 to 20.10 describe both adsorption and desorption isotherms. This assumption is not always true. Collins and Crocker140 observed apparently irreversible adsorption of phenol in flowthrough adsorption experiments involving phenol interacting on a Frio sandstone core under simulated deep-well... 

Procedure. Core floods were carried out in horizontally mounted Berea sandstone cores of length 61 cm and diameter 5 cm. Porosity varied from 18 to 25% and brine permeability from 100 to 800 Jim2. The cores were coated with a thin layer of epoxy and cast in stainless steel core holders using molten Cerrobend alloy (melting point 70°C). The ends of the cores were machined flush with the core holder and flanges were bolted on. Pore volume was determined by vacuum followed by imbibition of brine. Absolute permeability and porosity were determined. The cores were initially saturated with brine (2% NaCl). An oil flood was then started at a rate of lOm/day until an irreducible water saturation (26-38%) was established. 

Based upon over 50 micellar floods carried out on sandstone cores, the following conclusions are reached ... 

Another series of experiments used sandstone cores previously injected with starved bacteria to investigate the ability of the bacteria to grow within rock cores when given a suitable nutrient Berea sandstone cores of 200 and 400 millidarcy (md) permeabilities were used as they were considered to be more representative of reservoir conditions than the glass bead cores. The sandstone cores were injected with 300 to 450 pore volumes of 10 /ml starved bacteria until the cores contained an even distribution of bacteria (Fig. 3A B) and the core permeabilities were between 13% and 18%. SCM nutrient was injected through the cores (Fig. 3C) until the core permeability fell to 0.1%, this required 360 pore volumes of SCM. 

Figure 11 shows the results of the simulations, plotted as a normalized dispersion coefficient versus a dimensionless rate, compared to experimental data from sandstone cores. The acceptable agreement Indicates three conclusions about the nature of dispersion in laboratory experiments ... 

In the following section we present results of our foam-enhanced oil recovery experiments in Berea Sandstone cores to assess the performance of the three a-olefin sulfonates discussed above. 

The stability of emulsion and foam films have also been found dependent upon the micellar microstructure within the film. Electrolyte concentration, and surfactant type and concentration have been shown to directly influence this microstructure stabilizing mechanism. The effect of oil solubilization has also been discussed. The preceding stabilizing/destabilizing mechanisms for three phase foam systems have been shown to predict the effectiveness of aqueous foam systems for displacing oil in enhanced oil recovery experiments in Berea Sandstone cores. 

Figure 5 shows the results of a typical surfactant transport study in a 2 ft long Berea sandstone core. The AEGS 25-12 surfactant, injected at 0.05 wt%, had a low loss on Berea sandstone of 0.008 meq/100 gm rock compared to -0.05 meq/100 gm for typical petroleum sulfonates used in chemical flooding. Surfactant breakthrough occurred at 0.62 PV (Sorw =0.38 PV). The surfactant concentration is consistent with about 10% transport with the brine front. Surfactant loss and transport were monitored using the hyamine titration technique. 

Review of the literature resulted in several references relating to the use of emulsions as agents for causing permeability reduction. McAuliffe (2) demonstrated that injection of externally produced oil-in-water emulsions at 24 C effectively reduces the water permeabilities of sandstone cores. These laboratory findings were later substantiated by a field test of emulsion injection followed by waterflooding in the Midway-Sunset Field (3). 

Particle Size. After determining, with bottle tests, which systems easily produced stable oil-in-water emulsions, the droplet size distributions for the oil-in-water emulsions were determined with a Model TA II Coulter Counter. The quantitative results obtained with the Coulter Counter were verified by qualitative observations with an optical microscope. The droplet size distributions for several oil-in-water emulsions are given in Figure 5. A qualitative correlation between droplet size and emulsion stability was observed. The smaller the median droplet size, the more stable was the emulsion. The pore size distribution for a 300-md Berea sandstone core is given for comparison. 

Berea sandstone cores (25.4 cm by 3.8 cm) used in the experiments with Wilmington and Delaware-Childers crude oils were fired at 427°C. After firing, the cores were saturated with brine, mounted in a Hassler type core holder, and placed in a temperature-controlled oven. After initial absolute permeability was determined, the cores were left either oil-free or saturated with oil and waterflooded to residual oil saturation. 

The core experiments with Kern River oil were performed using sandpacks (25.4 cm by 3.7 cm) made from unconsolidated field core. The core material was packed into Teflon sleeves with Teflon end caps and then placed into a Hassler type core holder. Before packing, the sand was cleaned by Soxhlet extraction with toluene and was not fired. Otherwise, the procedure was similar to that for saturating the consolidated Berea sandstone cores. 

Permeability reductions were also observed by McAuliffe (9), and his results are shown in Figure 14. He used a Boise sandstone core with an initial permeability of 1600 mD and injected a 0.5% OAV emulsion having average oil-droplet sizes of 1 and 12 xm. The small-diameter emulsion reduced the permeability from 1600 to 900 mD after 10 pore volumes of the injected emulsion the 12-fxm emulsion was much more effective in reducing the core permeability. After 10 pore volumes had been injected, the permeability was reduced to 30 mD, almost a 50-fold reduction. 

This observation was also made by McAuliffe (9), who injected a 0.5% OAV emulsion (3.8-(xm average droplet size) into a Boise sandstone core (1170 mD) and Alhambra core (520 mD). The results are shown in Figure 20 and depict that the permeability of the Alhambra core was reduced more rapidly earlier during the injection period than that of the Boise core. The percentage reduction in permeability after 10 pore volumes of emulsion injection, however, was the same for the two cores. After 10 pore volumes of the OAV emulsion, distilled water was injected into the two cores. Distilled water, however, does not remove the oil droplets that are captured in the... 

FIGURE 5.32 The measure(i changes in the MWD of an HPAM sample after mechanical degradation in a sandstone core. Source Seright et al. (1981). 

This value seems to be on the higher side of the typical values of surfactant adsorption on Berea sandstone cores Green and Willhite (1998) summarized... 

It is also important to assess what atmospheric contaminants are deposited on the surface.Consequently, two examination schemes have been adopted for this purpose. In general, the contaminants of greatest concern are those which are water soluble. Therefore, sandstone cores are pulverized and dispersed in distilled water. 

SchulZ Rojahn (unpublished) Upper Namur Sandstone (core)... 

Table 1. Derivation of the Tirrawarra Sandstone core samples. Mineralogical compositions were determined by semiquantitative bulk-rock XRD analysis. Siderite is the only carbonate cement present, but occurs in varying proportions...

Some researchers have found a so-called critical velocity for the onset of foam generation (39, 45, 60). Friedmann et al. (39) generated foam in sandstone cores at different initial surfactant-laden water saturations after steady gas and surfactant-free liquid flow is established. Critical onset velocities increase with decreasing saturation of the water phase, Sw. Velocities up to several hundred meters per day are reported when the initial water saturation is low. Once steady two-phase flow is established, high gas velocities are apparently required for the gas to build a sufficient pressure gradient and enter into wetting liquid-filled pores (e.g., as in Figure 5). 

Holt and Kristiansen (26, 27) obtained similar results for foams flowing in cores under North Sea reservoir conditions in that the presence of any of a number of residual oils (including a crude oil and a variety of pure hydrocarbon oils) reduced the effectiveness of flowing foams. Rater-man (28) measured the pressure drops obtainable for several foams flowing in sandstone cores under moderate pressure and in the presence of a residual pure alkane oil phase and found that the foams were destabilized by the oil. Schramm et al. (40) conducted foam-floods in sandstone cores and found a range of sensitivities to residual crude oil from oil-tolerant foams through to oil-sensitive foams. 

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