Brine salinity

Cosurfactant requirements can be minimized usiag a surfactant having a short-branched hydrophobe or a branched-alkyl substituent on an aromatic group (232,234) and a long ethoxy group chain (234). Blends of surfactants optimized for seawater or reservoir brine salinity include linear alkyl xylene sulfonate—alcohol ether sulfate mixtures (235). 

Amoco developed polybutene olefin sulfonate for EOR (174). Exxon utilized a synthetic alcohol alkoxysulfate surfactant in a 104,000 ppm high brine Loudon, Illinois micellar polymer small field pilot test which was technically quite successful (175). This surfactant was selected because oil reservoirs have brine salinities varying from 0 to 200,000 ppm at temperatures between 10 and 100°C. Petroleum sulfonate apphcabdity is limited to about 70,000 ppm salinity reservoirs, even with the use of more soluble cosurfactants, unless an effective low salinity preflush is feasible. 

Salinity reversals or decrease of the formation brine salinity with depth are generally associated with overpressured formations. The mud salinity or chloride content reflects the formation water salinity if there is a close control over the mud properties and analyses. 

Fig. 16.24 Plot of variation of partition coefficients (1 1, Miller oil/brine) for phenol (o) m- (A), p- (O), and o- ( ) cresols versus brine salinity (g/L NaCl) at 25°C and 25 bar. Reprinted from Bennett B, Barter SR (1997) Partition behaviour of alkylphenols in crude oil brine systems under subsurface conditions. Geochim Cosmochim Acta 61 4393-4402. Copyright 1997 with permission of Elsevier...

To construct a salinity requirement diagram, 5 to 10 different brine salinities are prepared for at least three surfactant concentrations in screw-cap test tubes. Typically, surfactant concentration will range from 0 to 10 wt%, and salinity will vary according to the reservoir of interest. Sample tubes all contain an identical amount of brine, usually between 50 and 80% by volume. Sample tubes are mixed regularly for several days, then allowed to equilibrate. The equilibration process can take anywhere from several days to several months, depending on emulsion stability. 

By increasing the brine salinity, we observe the sequence of equilibria... 

As the injection brine salinity was reduced to 0.1 CS RB, more oil was produced. When Ca Wa ratio was increased, however, no more oil was produced. 

The phase behavior of microemulsions is complex and depends on a number of parameters, including the types and concentrations of surfactants, cosolvents, hydrocarbons, brine salinity, temperature, and to a much lesser degree, pressure. There is no universal equation of state even for a simple microemulsion. Therefore, phase behavior for a particular microemulsion system has to be measured experimentally. The phase behavior of microemulsions is typically presented using a ternary diagram and empirical correlations such as Hand s rule. 

The input parameters—C50 (initial brine salinity), C60 (initial brine divalents), CSEL7 and CSEU7 (Cjei and when alcohol and divalents are 0) in UTCHEM input—are effective salinities in meq/mL water. 

This chapter reports adsorption data for a number of surfactants suitable for mobility control foams in gas-flooding enhanced oil recovery. Surfactants suitable for foam-flooding in reservoirs containing high salinity and hardness brines are identified. The results of adsorption measurements performed with these surfactants are presented surfactant adsorption mechanisms are reviewed and the dependence of surfactant adsorption on temperature, brine salinity and hardness, surfactant type, rock type, wettability and the presence of an oil phase is discussed. The importance of surfactant adsorption to foam propagation in porous media is pointed out, and methods of minimizing surfactant adsorption are discussed. 

No universally accepted practices exist for selecting foam-forming surfactants for specific rock—fluid systems. In addition, information dealing with foam performance at brine salinities as high as those found in the pools mentioned previously is not readily available in the literature. The selection process is based on the following common sense criteria (2) ... 

In general, trends in MRF with surfactant concentration and foam quality are consistent for all surfactants, but the effects of brine salinity (Figure 4) and temperature (3) vary from surfactant to surfactant. Different surfactants are also affected to different degrees by the presence of an oil phase, as discussed in Chapter 4 of this book. The MRF increases with increasing permeability (Figure 5), as also noted by Lee and Heller (4) and described earlier in Chapter 5. This effect could be very beneficial to foam performance, because it leads to better mobility control in high-permeability zones. 

Figure 4. The dependence of mobility-reduction factor on brine salinity in Berea core at 80 °C and 98% foam quality.

Surfactant Adsorption. Surfactant propagation is crucial to foam propagation. The data compiled in later sections of this chapter show that surfactants that are similarly effective as gas mobility reducing agents may have significant differences in adsorption levels. The level of surfactant adsorption and its dependence on parameters such as brine salinity and hardness may then be the deciding factors in surfactant selection for a specific application. 

Dependence of Adsorption on Brine Salinity and Divalent Ion Content. Brine salinity and composition probably constitute the primary criteria for selecting surfactants for foam applications. Many Canadian pools that are being flooded with hydrocarbon solvents contain near-saturated formation brines. Some of these pools have been waterflooded with fresh water, and therefore, salinity gradients exist. In addition, the majority of hydrocarbon-miscible floods in Canada are conducted in carbonate formations that contain formation waters with high levels of hardness. 

Figure 13. The dependence of surfactant adsorption on brine salinity (7, 10—12 and Mannhardt, K., Novosad, J. Petroleum Recovery Institute, unpublished data).

Figure 8 Unidimensional formulation scan. Typically observed phase behavior for a system containing 2% anionic surfactant, 49% brine, and 49% alkane, versus the brine salinity.

In subsequent tests under optimized conditions, Pilot unit A was operated for X days continuously at 50% recovery - with an MD brine salinity of 140 g/L - and consistently produced an effluent of distilled water quality. 

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