Reservoir brine

It is usually necessary to prepare the injected polymer solution in reservoir brine. Reservoir brines often contain high concentrations of divalent cations, in particular Ca++ and Mg + +. The solution viscosity of each polymer is affected by the presence of divalent cations, as discussed in Sec. 5.3.3. Both polyacrylamides and biopolymers are stable in high concentrations of divdent cations at low reservoir temperatures. 20.22,23 perric ion (Fe+ ++) will cause gelation of polyacrylamide and must be excluded or chelated within reservoir brines. 

Figure Bl.14.6. J -maps of a sandstone reservoir eore whieh was soaked in brine, (a), (b) and (e), (d) represent two different positions in the eore. For J -eontrast a saturation pulse train was applied before a standard spin-eeho imaging pulse sequenee. A full -relaxation reeovery eiirve for eaeh voxel was obtained by inerementing the delay between pulse train and imaging sequenee. M - ((a) and (e)) and r -maps ((b) and (d)) were ealeulated from stretehed exponentials whieh are fitted to the magnetization reeovery eurves. The maps show the layered stnieture of the sample. Presumably -relaxation varies spatially due to inliomogeneous size distribution as well as surfaee relaxivity of the pores. (From [21].)...

Attard J J, Doran S J, Flerrod N J, Carpenter T A and Flail L D 1992 Quantitative NMR spin-lattice-relaxation imaging of brine in sandstone reservoir cores J. Magn. Reson. 96 514-25... 

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. 

Chlorine. Nearly all chlorine compounds are readily soluble in water. As a result, the major reservoir for this element in Figure 1 is the ocean (5). Chloride, as noted earHer, is naturally present at low levels in rain and snow, especially over and near the oceans. Widespread increases in chloride concentration in mnoff in much of the United States can be attributed to the extensive use of sodium chloride and calcium chloride for deicing of streets and highways. Ref. 19 points out the importance of the increased use of deicing salt as a cause of increased chloride concentrations in streams of the northeastern United States and the role of this factor in the chloride trends in Lake Ontario. Increases in chloride concentration also can occur as a result of disposal of sewage, oil field brines, and various kinds of industrial waste. Thus, chloride concentration trends also can be considered as an index of the alternation of streamwater chemistry by human development in the industrialized sections of the world. Although chlorine is an essential element for animal nutrition, it is of less importance for other life forms. 

Common salt, or sodium chloride, is also present in dissolved form in drilling fluids. Levels up to 3,000 mg/L chloride and sometimes higher are naturally present in freshwater muds as a consequence of the salinity of subterranean brines in drilled formations. Seawater is the natural source of water for offshore drilling muds. Saturated brine drilling fluids become a necessity when drilling with water-based muds through salt zones to get to oil and gas reservoirs below the salt. 

Clear Brines. Brine solutions are made from formation saltwater, seawater, or bay water, as well as from prepared saltwater. They do not contain viscosifers or weighting materials. Formation water-base fluids should be treated for emulsion formation and for wettability problems. They should be checked on location to ensure that they do not form a stable emulsion with the reservoir... 

The vast majority of corrosion design issues faced in marine and offshore engineering involve water in one form or another. In that regard, the two principal media involved are seawater and formation waters (oilfield brines). Seawater, of course, surrounds offshore installations though may also be used as the medium in reservoir injection and other critical offshore process... 

Geomembrane These liners chiefly provide impermeable barriers. They can be characterized as (1) solid waste containment hazardous landfill, landfill capping, and sanitary landfill (2) liquid containment canal, chemical/brine pond, earthen dam, fish farm, river/coastal bank, waste-water, and recreation (3) mining, leach pad and tailing ponds and (4) specialties floating reservoir caps, secondary containment, tunnel, erosion, vapor barrier, and water purification. Plastics used include medium to very low density PE, PVC, and chlorosulfonated PE (CSPE). (The Romans used in their land and road constructions what we call geomembrane.)... 

This is usually prepared by either a base-exchange method using sodium zeolite, by a lime-soda ash process, or by the addition of sodium hexametaphosphate. In addition to the bacteria derived from fhe mains water, additional flora of Bacillus spp. and Staphylococcus aureus may be introduced into systems which use brine for regeneration and from the chemical filter beds which, unless treated, can act as a reservoir for bacteria. 

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]. 

A methanogenic bacterium was isolated from oil reservoir brines by enrichment with trimethylamine. Methane production occurred only with trimethyl-amine compounds or methanol as substrates. Sodium ions, magnesium ions, and potassium ions were all required for growth. This organism appears to be a member of the genus Methanohalophilus based on substrate utilization and general growth characteristics [695]. 

In most production reservoirs, the produced brines are injected into the formation for purposes of maintaining reservoir pressure and avoiding subsidence and environmental pollution. In the case of geothermal fields, the brines are also injected to recharge the formation. However, the injected brines can adversely affect the fluids produced from the reservoir. For example, in geothermal fields, the injected brine can lower the temperature of the produced fluids by mixing with the hotter formation fluids. 

D. Gevertz, J. R. Paterek, M. E. Davey, and W. A. Wood. Isolation and characterization of anaerobic halophilic bacteria from oil reservoir brines. Number 31, pages 115-129.1991. 

Zukin JG, Hammond DE, Kn TL, Elders WA (1987) Uraniirm-thoriitm series radionuclides in brines and reservoir rocks from two deep geothermal boreholes in the Salton Sea Geothermal Field, sontheastem California. Geochim Cosmochim Acta 51 2719-2731... 

Precipitation may be significant for heavy metals and other inorganic constituents in injected wastes. For example, sulfide ions have a strong affinity for metal ions, precipitating as metal sulfides. The dissolved constituents in injected wastes and reservoir fluids would not be in equilibrium with the in situ brines because of the fluids different temperature, pH, and Eh. When the fluids are mixed, precipitation reactions can lead to injection-well plugging. 

Each interaction involves numerous chemical processes. The dominance of a specific interaction depends on the type of waste, the characteristics of the brine and rock in the reservoir, and environmental conditions. Table 20.14 describes some of the more common processes that may result in incompatibility. 

An American Salt Company plant and the Dow Chemical Company s Midland plant also benefit directly from each other s presence. Dow found that after recovering bromine from brine it had more salt left than it desired. American Salt needed salt. By locating next to Dow s plant it was able to buy this salt stream for less than it would cost to mine it or pump it from natural underground reservoirs. In turn, Dow was able to sell an unwanted stream that it would otherwise have had to pump back into the ground. The American Salt plant is typical of many satellite plants. These are plants that either use a by-product or a waste stream from another plant or are built mainly to supply a needed chemical to an adjacent plant. The nearby presence of another plant determines their location. 

The computer interface system lends itself well to the determination of interfacial tension and contact angles using Equation 3 and the technique described by Pike and Thakkar for Wilhelmy plate type experiments (20). Contact angles for crude oil/brine systems using the dynamic Wilhelmy plate technique have been determined by this technique and all three of the wetting cycles described above have been observed in various crude oil/brine systems (21) (Teeters, D. Wilson, J. F. Andersen, M. A. Thomas, D. C. J. Colloid Interface Sci., 1988, 126, in press). The dynamic Wilhelmy plate device also addresses other aspects of wetting behavior pertinent to petroleum reservoirs. 

Increasing the water-wet surface area of a petroleum reservoir is one mechanism by which alkaline floods recover incremental oil(19). Under basic pH conditions, organic acids in acidic crudes produce natural surfactants which can alter the wettability of pore surfaces. Recovery of incremental oil by alkaline flooding is dependent on the pH and salinity of the brine (20), the acidity of the crude and the wettability of the porous medium(1,19,21,22). Thus, alkaline flooding is an oil and reservoir specific recovery process which can not be used in all reservoirs. The usefulness of alkaline flooding is also limited by the large volumes of caustic required to satisfy rock reactions(23). 

DEMULSIFICATION TESTS. Demulsification tests were conducted using standard bottle test procedures to evaluate the relative performance of Thin Film Spreading Agents in coalescing emulsions of formation brine in crude oil under reservoir conditions. 

To establish the well drainage boundaries and fluid flow patterns within the TFSA-waterflood pilot, an interwell chemical tracer study was conducted. Sodium thiocyanate was selected as the tracer on the basis of its low adsorption characteristics on reservoir rocks (36-38), its low and constant background concentration (0.9 mg/kg) in produced fluids and its ease and accuracy of analysis(39). On July 8, 1986, 500 lb (227 kg) of sodium thiocyanate dissolved in 500 gal (1.89 m3> of injection brine (76700 mg/kg of thiocyanate ion) were injected into Well TU-120. For the next five months, samples of produced fluids were obtained three times per week from each production well. The thiocyanate concentration in the produced brine samples were analyzed in duplicate by the standard ferric nitrate method(39) and in all cases, the precision of the thiocyanate determinations were within 0.3 mg/kg. The concentration of the ion in the produced brine returned to background levels when the sampling and analysis was concluded. 

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