Steam and condensate

Heat exchanger is used to improve efficiency of the cycle, reducing consumption of steam and condenser water. 

External Steam and condensate at a partial vacuum of 4-10 in. (10-25 cm) of mercury... 

External Steam and condensate treated with an oxygen scavenger and ammonia, pH 7.S-9.2, temperature ambient to 150°F (66°C)... 

Environment Internal Well water 95°F (35°C), pH 7.9, sulfate 900 ppm, chloride 330 ppm, molybdate water treatment External Steam and condensate... 

External Steam and condensate with ammonia and hydrogen sulfide... 

External Steam and condensate, pH 9.0, ammonia 300 ppb, oxygen 20 ppb, conductivity 3.0 pmhos/cm... 

Environment Internal River water treated with microbicides, 35-115°F (2- 6 C), pH 8.2 External Steam and condensate, pH 8.5-9.0... 

Environment Internal Treated cooling water adjusted with sulfuric acid for pH control and sodium hypochlorite added as a biocide pressure 50 psi (345 kPa), temperature 100-120°F (38-49°C), water velocity 7 ft/s (2.1 m/s), pH 8.0-8.4, sulfate 500-1000 ppm, chloride 100-450 ppm, total hardness 500 ppm External Steam and condensate... 

Environment Internal Brackish river water, pH 7.1 External Steam and condensate... 

Carbon Dioxide CO2 Corrosion in water lines and particularly steam and condensate lines Aeration, deaeration, neutralization with alkalies, filming and neutralizing amines... 

Utility Baiances. The operating company should also require a balance for each plant utility. The most involved of the utility balances is usually the supply/demand steam tabulation showing all levels of steam and condensate and their interactions. The steam balance is almost always required at this stage for any required side studies. The steam balance influences many design parameters, such as boiler size and contingency, treated water makeup rates, blow -down disposal rates, chemicals usage, and surface condenser size. 

Differential shock Differential shock, like thermal shock, occurs in biphase systems. It can occur whenever steam and condensate flow in the same line, but at different velocities, such as in condensate return lines. 

The VPS overhead consists of steam, inerts, condensable and non-condensable hydrocarbons. The condensables result from low boiling material present in the reduced crude feed and from entrainment of liquid from the VPS top tray. The noncondensables result from cracking at the high temperatures employed in the VPS. Inerts result from leakage of air into the evacuated system. Steam and condensable hydrocarbons are condensed using an overhead water-cooled condenser. The distillate drum serves to separate inerts and non-condensables from condensate, as well as liquid hydrocarbons from water. Vacuum is maintained in the VPS using steam jet ejectors. 

Carbon dioxide COj Results in the corrosion of water lines, especially steam and condensate lines. 

Figure 10-91B. Steam and condensate temperatures versus condenser length. Temperature distribution curve for the same multizone condenser as in Figure 10-91 A. Points A, E, and F are the same. Point B is above C, which locates the start of the wet desuperheating zone on the tube surface. (Used by permission Rubin, F. L. Heat Transfer Engineering, V. 3, No. 1, p. 49, 1981. Taylor and Francis, Inc., Philadelphia, PA. All rights reserved.)...

The steam turbine is operated as a condensing unit when the exhaust steam is condensed as it leaves the turbine. This is usually below atmospheric pressure and often advisable in order to (1) maintain proper plant-wide steam and condensate balance and (2) use all reasonable energy in steam. Figure 14-18A. 

An alternative way to use flash steam is to provide several, small self-contained FSHR systems, keeping the system pipework to a minimum and lagging the pipes to avoid unnecessary heat losses. Flash steam forms at the point where the pressure drops, which is at the BD valve or the valve seat of the steam trap. From this point the flash steam and condensate travel together until the flash vessel is reached. The vessel then acts as a steam-water separator. 

Sample points should be provided for the final FW and all sources of water, steam, and condensate that supply the FW tank. All FW tank sample points should incorporate a sample cooler. 

Also, corrosion may result in contamination at some downstream point in the steam-water cycle. For example, iron and copper ions often may be present as corrosion products in steam and condensate and consequently will reduce the purity of the steam. This may render the steam unsuitable for certain industrial processes or applications where live steam injection is required. 

Contamination in this context refers specifically to the debasing of the purity of steam and condensate. Contamination may occur in the presence of unwanted steam volatile materials (such as silica volatiles), minerals carried over with BW, oil and process materials infiltrating the steam-water circuit, or by the results of corrosion processes. 

Operational problems, such as BW foaming and surging (priming) all ultimately lead to BW carryover and the resultant contamination of steam and condensate lines. 

Consequently, any and all waterside or steamside problems that may hinder or sometimes completely prevent the achievement of these objectives must be addressed. In practice, there are a myriad of potential problems that may develop in the steam and condensate systems, and (as in other areas of the boiler plant) many of these problems are... 

The frequency and types of tests employed should, of course, bear some relation to the type of facility being considered. If steam and condensate are not tested, carryover, corrosion, contamination, and other potential problems may be missed, which undoubtedly will have a deleterious impact in other parts of the overall boiler plant. 

Oxygen, nitrogen, carbon dioxide, ammonia, hydrogen sulfide, sulfur dioxide, and other contaminant gases are generally present to some degree in all steam and condensate systems. 

Thus, oxygen infiltration gives rise to a range of localized steam and condensate system corrosion reactions and products. These reactions may, in turn, lead to further downstream problems of corrosion debris transport when the condensate returns to the FW system. 

In areas where the water has a high natural alkaline hardness, the potential for contamination of the steam and condensate system by C02 may be very significant. And in those plants requiring a high percentage of MU water, the risk of serious condensate system corrosion to the steel pipework, valves, traps, threaded joints, and points where noncondensable gases can collect is very real. 

Where carryover occurs, much of the solids content is deposited in the first parts of the steam and condensate system, such as superheaters, but the balance can be transported all the way back to the pre-boiler system and from there to the boiler itself. Thus, a chain of cause and effect may once again develop in a manner similar to the progression of problems in other areas of the boiler system. 

Where new boilers are married to old steam and condensate systems, similar effects occur because of the transport of debris and the resultant blockages of valves and steam traps. Where the replacement boilers are of a higher rating than the existing boilers, the problems are further exacerbated (often due to surging, faster steaming times, or increased steam velocities). 

Process leaks into the steam and condensate system may take the form of phenols, glycols, and various other organics that produce an... 

Recycled condensate often is of higher quality than FW, although in facilities with extremely long runs of steam and condensate lines, or where amine treatments are not used (e.g., some food processors, hospitals, drug manufacturers, etc.) and in high heat-flux power boiler plants, there is a tendency for the condensate to be contaminated by iron and smaller levels of copper. 

Steam/condensate line corrosion control. Control over steam and condensate line corrosion requires the control of oxygen, carbon dioxide (carbonic acid), and ammonia. 

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.)... 

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