On Berea sandstone

In this paper we report on a detailed experimental and theoretical investigation of the influence of acoustic waves on laminar liquid flow through the Berea sandstone. We focus our investigation on Berea sandstone, which is representative for the sandstone of an oil reservoir, with permeability 100 to 300 mD and on acoustic frequencies below the critical frequency [3],... 

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. 

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... 

Adsorption on Berea Sandstone. Berea sandstone was reported by Malmberg and Smith (20) to consist of approximately 91 wt.% sand and 9 wt. % clay. The adsorption measurements reported here are for the crushed sandstone but it should be noted that essentially all of the adsorption occurred on the clay fraction. In a separate experiment the clay fraction was separated from the sand and the adsorption of SDBS measured on both fractions. No adsorption on the sand could be detected while strong adsorption on the clay was found. Moreover, the adsorption on the clay agreed very well with that found on the original crushed sandstone when converted to a common basis. 

An increase in electrolyte concentration reduces the solubility of anionic surfactants in the aqueous phase and increases their tendency to accumulate at the solid—liquid interface. An increase in temperature offsets the loss in solubility to some degree For the DPES—AOS on Berea sandstone, the slopes of the lines in Figure 13a decrease as the temperature increases, and this finding lends support to the hypothesis that surfactant adsorption is related to surfactant solubility. Adsorption of surfactants that are less salt-tolerant than the DPES—AOS, such as the AOS and the IOS, increases much more steeply with salinity. Both surfactants adsorb negligibly at salinities of 0.5 mass % NaCl, but adsorb similarly to the DPES—AOS at a salinity of 2.3 mass %. At moderate salinities (on the order of 3 mass %), these surfactants precipitate, which severely limits their applicability to foam-flooding in many reservoirs that are currently being flooded with hydrocarbon solvents. 

When normalized to unit surface area, the adsorption density of the anionic surfactant is higher on quartz than on Berea sandstone because quartz carries a more positive surface charge than the clays (The clays provide most of the surface area for adsorption in Berea sandstone). If it is assumed that the betaine adsorbs on sandstone at least in part by its cationic group, then the lower adsorption density of the betaine on quartz than on Berea sandstone can also be attributed to electrostatic interactions. Matrix grains of the size encountered in typical reservoir rocks have low specific surface areas. Accordingly, the absolute amount of surfactant adsorbed or the amount adsorbed per unit mass of rock is lower for a clean sand than for a sand containing clays (12, 34, 82). Therefore, the... 

Figure 3. Change in differential pressure versus time for a flow-though test on Berea sandstone. Sample temperature incremented from 20°C to 120°C and then returned to 20°C. Matrix permeability 500 mD. [Courtesy A.B. Polak].

The fourth part includes experimental results on adsorption of pure surfactant and petroleum sulfonates on Berea sandstone. Retention of surfactants is related to their solubility limits in the brine. 

The error in the surface excess is, of course, substantially larger because adsorption levels are quite low and concentration changes due to adsorption are therefore small. An example of uncertainties in the measurements of surface excess for surfactant systems caused by errors in analytical procedures is shown in Figure 7. This error analysis shows clearly that batch methods should not be used for measuring surfactant adsorption on Berea sandstone for surfactant concentrations above 1% unless extremely accurate analytical procedures are developed. 

Fig. 9. Adsorption isotherm for 1/10 Texas 1/sec-butylalcohol in 1% NaCl brine on Berea sandstone at 22°C.

Fig. 2.7.5 Two-dimensional D—T2 map for Berea sandstone saturated with a mixture of water and mineral oil. Figures on the top and the right-hand side show the projections of f(D, T2) along the diffusion and relaxation dimensions, respectively. In these projections, the contributions from oil and water are marked. The sum is shown as a black line. In the 2D map, the white dashed line indicates the molecular diffusion coefficient of water,...

In addition, mercury intrusion porosimetry results are shown together with the pore size distribution in Figure 3.7.3(B). The overlay of the two sets of data provides a direct comparison of the two aspects of the pore geometry that are vital to fluid flow in porous media. In short, conventional mercury porosimetry measures the distribution of pore throat sizes. On the other hand, DDIF measures both the pore body and pore throat. The overlay of the two data sets immediately identify which part of the pore space is the pore body and which is the throat, thus obtaining a model of the pore space. In the case of Berea sandstone, it is clear from Figure 3.7.3(B) that the pore space consists of a large cavity of about 85 pm and they are connected via 15-pm channels or throats. 

Fig. 3.7.4 (A) CRMI results of pressure versus volume on the Berea sandstone sample with a porosity of 20% and permeability 0.2 darcy. The two lines are raw CRMI data and the corrected data by a calibration run. Transducer noise was also filtered. The amount of the correction is fairly small and the two data sets overlap. (B) CRMI pore body volume distribution showing a predominant peak at around 20 nL. Figure from Ref. [57] with permis-...

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. 

The Effect of Surfactant Concentrations, The effect of surfactant concentrations on CC -foam mobility is plotted on a log-log scale in Figure 3. The presented data points are the average mobility values obtained from a superficial velocity range of 2-10 ft/day, with the CC -foam fraction was kept constant around 80%. With Berea sandstone, ZS and AEGS surfactants were used. The measured average permeability of the Berea sandstone with 1% brine was 305 md. With Baker dolomite, AEGS was used to make comparison with Berea sandstone. The permeability of the Baker dolomite was 6.09 md measured with 1% brine solution. 

Agrawal, D.L., Cook, N.G.W. and Myer, L.R. (1991) The effect of percolating structures on the petrophysical properties of Berea sandstone. In Rock Mechanics as a Multidisciplinary Science, Balkema, pp. 345-354... 

Effect of Surfactant Concentrations. The effect of the surfactant concentration on foam mobility has been studied extensively. The surfactant under investigation for this effect was Varion CAS, a zwitterionic surfactant from Sherex. The rock under study was Berea sandstone which has a permeability of 308 9 md measured by using 1% brine solution. The permeability using N2 gas at atmospheric pressure was 1000 6.2 md. 

Kia, S.F., Fogler, H.S., Reed, M.G., Vaidya, R.N., 1987. Effect of salt composition on clay release in Berea sandstone. SPEPE (November), 277-283. 

Figure 1. Electron micrographs of Berea sandstone and selected core samples (a) Berea sandstone, representative fracture surface, 102.75X (h) Berea sandstone, clay on quartz crystals, 959X (c) Glenn sand core, representative fracture surface, 123.3X (d) Glenn sand core, clay crystals on quartz, 3938.75X (e) San Andres core, representative fracture surface, 123.3X (f) San Andres core, clay and dolomite crystals, 993.25 X.

Experimental Materials and Procedure The equilibrium adsorption of sodium dodecylbenzene sulfonate (SDBS), and deoiled TRS 10-410 (a commercial petroleum sulfonate with an equivalent weight of 418) on silica gel (Davison Grade 62), and crushed Berea sandstone was measured at 30°C at two brine concentrations (0 and 1 wt.% NaCl). 

Adsorption of anionic surfactants on crushed Berea sandstone occurs on the clay only and adsorption maxima are observed. The addition of one wt.% NaCl to the surfactant solution results in greatly increased adsorption but in no significant change in the shape of the adsorption isotherm. 

Fig. 4.3. Adsorption isotherms of Mahogany sulfonate AA on two ground Berea sandstone samples and one crushed Berea sandstone sample.

The same conclusions have been reached on the basis of core-flood experiments. Suffridge et al. (35) studied foam effectiveness in Berea sandstone cores, both untreated (water-wetted) and treated with the Quilon C chrome complex described previously. The treated cores became intermediate to oil-wetted at waterflood residual oil saturation. They found that the foams were more effective (stable) in the water-wet cores than in the oil-wet cores. Holt and Kristiansen (27, 56) studied foams flowing in cores under North Sea reservoir conditions that were either partially or completely oil-wetted. They found that foam effectiveness was favored by water-wet conditions any degree of oil-wet character reduced the effectiveness of the flowing foam. 

Figure 2. The dependence of mobility-reduction factor on surfactant concentration in Berea sandstone at 80 °C and 98% foam quality in 210,000 ppm (21 mass %) reservoir brine.

Figure 11. The dependence of surfactant adsorption on temperature, measured in Berea sandstone or silica sand. Adsorption levels were obtained using the surface excess model (1—10).

Clays are considered detrimental to EOR processes that are based on the injection of chemicals, such as foam-forming surfactants, because clays provide a large amount of surface area for adsorption. Table VII shows a comparison of specific surface areas of some clays (97, 117, 118) and of the solids used in the adsorption experiments of Figure 15 (12, 119, 120). Figure 15 allows comparison of adsorption levels in Berea sandstone, which consists mainly of quartz and 6-8% clays, with adsorption on clean quartz sand. 

Figure 16. The effect of solid surface charge on adsorption of anionic and amphoteric surfactants. Key SS, Berea sandstone LS, Indiana limestone and Dolo, Baker dolomite. (Reproduced with permission from reference 12. Copyright 1992 Elsevier Science Publishers.)...

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