Sulfate scales

Scaling is not always related to temperature. Calcium carbonate and calcium sulfate scaling occur on unheated surfaces when their solubiUties are exceeded in the bulk water. Metallic surfaces are ideal sites for crystal nucleation because of their rough surfaces and the low velocities adjacent to the surface. Corrosion cells on the metal surface produce areas of high pH, which promote the precipitation of many cooling water salts. Once formed, scale deposits initiate additional nucleation, and crystal growth proceeds at an accelerated rate. 

Suifate (S04>-2 Adds to solids content of water, but, in itself, is not usually significant combines with calcium to form calcium sulfate scale Demineralization, distillation, reverse osmosis, electrodialysis... 

The degree of concentration that can be achieved by RO may be limited by the precipitation of soluble salts and the resultant scaling of membranes. The most troublesome precipitate is calcium sulfate. The addition of polyphosphates to the influent will inhibit calcium sulfate scale formation, however, and precipitation of many of the other salts, such as calcium carbonate, can be prevented by pretreating the feed either with acid or zeolite softeners, depending on the membrane material. 

Sulfates (SO,)= Results in the formation of calcium sulfate scale. 

Calcium—In general, calcium (as CaCOs) below 800 ppm should not result in calcium sulfate scale. In arid climates, however, the critical level may be much lower. For calcium carbonate scaling tendencies, calculate the Langelier Saturation Index or the Ryznar Stability Index. 

Where carbonate, phosphate, or sulfate scale-based deposits have been found in boiler systems, analyses show that they almost always contain some silica or silicate as well. Typically, this is less than 8 to 10% unless there is a specific underlying silica-related problem (under such circumstances, the deposit may contain more than 20-30% Si02). 

Sulfates in surface MU water sources usually are present at lower concentrations (typically 20-60 ppm) but this level may rise to several hundred ppm in subsurface waters. The maximum solubility of calcium sulfate is dependent on temperature but is in the range of 1,800 to 2,000 ppm in cold water. This rate is significantly less in hot BW where boiler deposits occur, the sulfate scale normally is present as anhydrite (CaS04). Sulfate scales are hard and very difficult to remove, so treatment programs employed must be carefully controlled to avoid risks of scaling. 

Polyphosphinocarboxylic acid. Products based on this chemical tend to be suitable for brackish waters up to say 10,000 to 15,000 ppm TDS and where high sulfates are present (200 to 300 ppm as S04). A feature of this type of chemical is not only its ability to deal effectively with carbonate and sulfate scaling in higher TDS waters but also the fact that it has dispersant properties of benefit in physically moving potential foulants away from the membrane surface. 

Internal treatment was often based on recommendations dating from the 1920s. The deliberate addition of soda ash (sodium carbonate) to the BW to form carbonate sludges (rather than, say, sulfate scales) that could be removed by BD was a common program. If unde-... 

It was expected that an eggshell thickness of scale would form, but that it would be relatively soft and easily removed (despite normally containing some silicate and sulfate). However, a disadvantage of this method of internal control was that the carbonate degraded to form carbon dioxide, and at higher pressures the rate of breakdown was so great that the necessary carbonate reserve required to prevent sulfate scale often could not be maintained. (Never mind the danger to the steam and condensate lines from the production of carbon dioxide and ultimately carbonic acid.)... 

The most popular form of internal treatment for many years dates from the nineteenth century and is based on a combination of soda ash and caustic. This traditional program, the so-called carbonate-cycle or carbonate treatment, utilizes the addition of sodium carbonate to the BW to deliberately form carbonate sludges that can be removed by BD, rather than permit sulfate scales to develop. If sulfate scales do form in the boiler, the removal process is difficult and very time-consuming, and obviously, boiler operating efficiency will continue to decrease as the sulfate scale increases in thickness. 

If undesirable sulfate scale is to be avoided, a relatively high concentration of carbonate must be maintained as a BW reserve. The quantity of BW carbonate reserve required depends on the level of sulfates present in the BW and the boiler gauge pressure, as indicated in Table 10.2. 

The formation of calcium carbonate (CaCOs), calcium sulfate, and barium sulfate scales in brine may create problems with permeability. Therefore it is advantageous that newly made fractures have a scale inhibitor in place in the fracture to help prevent the formation of scale. Formulations of hydraulic fracturing fluids containing a scale inhibitor have been described in the literature [1828]. 

Y. B. Zeng and S. B. Fu. The inhibiting property of phosphoric acid esters of rice bran extract for barium sulfate scaling. Oilfield Chem, 15(4) 333-335,365, December 1998. 

A common problem in offshore petroleum production is that sulfate scale may form when seawater is injected into the formation during waterflooding operations. The scale forms when seawater, which is rich in sulfate but relatively poor in Ca++ and nearly depleted in Sr++ and Ba++, mixes with formation fluids, many of which contain bivalent cations in relative abundance but little sulfate. The mixing causes minerals such as gypsum (CaSC>4 2H2O), anhydrite (CaSC>4), celestite (SrSOzO, and barite (BaS04, an almost insoluble salt) to become saturated and precipitate as scale. 

Sulfate scaling poses a special problem in oil fields of the North Sea (e.g., Todd and Yuan, 1990, 1992 Yuan et al., 1994), where formation fluids are notably rich in barium and strontium. The scale can reduce permeability in the formation, clog the wellbore and production tubing, and cause safety equipment (such as pressure release valves) to malfunction. To try to prevent scale from forming, reservoir engineers use chemical inhibitors such as phosphonate (a family of organic phosphorus compounds) in squeeze treatments, as described in the introduction to this chapter. 

The above reaction is applied in descaling calcium sulfate scale in heat-exchanger tubes. 

Scale Prevention. The scale normally formed on heat transfer surfaces of sea water evaporators consists of calcium carbonate, magnesium hydroxide, and/or calcium sulfate. The first two form as a result of the breakdown of bicarbonate in sea water, which is initially saturated with calcium carbonate. Calcium sulfate scale forms purely as a result of its inverted solubility curve. Sea water is not saturated with calcium sulfate and an economically reasonable amount of fresh water can be recovered from sea water without exceeding saturation with calcium sulfate. However, at the start of this investigation, the solubility of calcium sulfate in sea water was not accurately enough known to tell whether 30, 50, or 80% of the water content could be removed at various temperatures without encountering calcium sulfate scale. 

To increase the value of the demonstration plant, features have been incorporated to permit operation under other than demonstration conditions. It will be possible to operate the evaporator at first-effect temperatures up to 300° F., thus almost doubling plant output if calcium sulfate scale can be prevented, and to use the acid method of scale prevention in place of the sludge method. Provisions have been made for later installation of a vapor compressor, which would convert the plant to a combination multiple effect-thermocompression system. This would add about 15% to plant output and would permit performance evaluation of vapor compressors in sea water service. 

It will also be possible by relatively minor piping changes to convert the forward-feed evaporator to backward feed, which might be more favorable if the calcium sulfate scale problem can be solved. Except for tubes, pump shaft sleeves, impellers, etc., the plant will be built exclusively of steel and cast iron. Tube materials will be evaluated by tubing different evaporator effects and heat exchangers with steel, admiralty metal, aluminum brass, and 90/10 cupronickel. The copper alloy tubes will be used exclusively in the final condenser and in the few heat exchangers that are in contact with nondeaerated sea water. 

In cooling water deposits, the sulfate scale is normally present as gypsum (CaSC>4 2H2O). Sulfate scales are hard and difficult to remove and therefore treatment techniques employed must be carefully controlled to avoid scaling risks. There are specific polymeric chemical treatments now available to control sulfate deposition in high sulfate waters. 

PCA 16 is particularly effective for control of calcium sulfate deposition (and thus finds application, under different brand names and grades, as a calcium carbonate/sulfate scale inhibitor for RO systems treating brackish waters). This inhibitor is also useful for calcium phosphate control. It is stable against chlorine. 

In general, SS/MA and the other calcium phosphate inhibitors are not as good at inhibiting calcium carbonate scale as PMA or HEDP or as good at inhibiting calcium sulfate scale as PMA and 2000 MW PAA. 

Acid cleaning agents such as hydrochloric, phosphoric, or citric acids effectively remove common scaling compounds. With cellulose acetate membranes the pH of the solution should not go below 2.0 or else hydrolysis of the membrane will occur. Oxalic acid is particularly effective for removing iron deposits. Acids such as citric acid are not very effective with calcium, magnesium, or barium sulfate scale in this case a chelatant such as ethylene diamine tetraacetic acid (EDTA) may be used. 

Alternatively, antisealants can be used to control calcium carbonate scale at LSI values as high as 2.0-2.5, depending on the specific antisealants. Calcium also forms scales with fluoride, sulfate, and phosphate. The LSI will not help predict these scales analysis of water quality, using the ion product and solubility constants, is required to determine the potential for scaling with calcium fluoride or calcium phosphate. Antisealants currently available can address calcium fluoride and calcium sulfate scale they do not address calcium phosphate scale (although newer antisealants will be available in the near future to address this scale). 

Barium and strontium form sulfate scales that are not readily soluble. In fact, barium is the least soluble of all the alkaline-earth sulfates. It can act as a catalyst for strontium and calcium sulfates scale.4 Analyses of the ion product with the solubility constants for barium and strontium sulfates is necessary to determine the potential for scaling with these species. If the ion product (IP) for barium sulfate exceeds the solubility constant, scale will form. Note that in the case of strontium sulfate, if IP > 0.8Ksp, scaling is likely. However, the induction period (the time it takes for scale to form) is longer for these sulfate-based scales than it is for calcium carbonate scale. 

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