Condensate lines

For the frequent case of flashing steam-condensate lines, Ruskan supplies the handy graph shown above. 

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

Thermal shock In biphase systems, steam bubbles may become trapped in pools of condensate in a flooded main, branch, or tracer line, as well as in heat exchanger tubing and pumped condensate lines. Since condensate temperature is almost always below saturation, the steam will immediately collapse. 

To control differential shock, the condensate seal must be prevented from forming in a biphase system. Steam mains must be properly pitched, condensate lines must be sized and pitched correctly, and long vertical drops to traps must be back-vented. The length of lines to traps should be minimized, and pipes may have to be insulated to prevent water hammer. 

Figure 4 shows high-pressure condensate (small line) being added to low-pressure condensate without the usual troublesome hammer. The high-pressure condensate has a chance to cool before emerging into the low-pressure condensate line. 

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

Carbon dioxide CO, Severe corrosion in condensate lines Aeration Deaetation Alkalies (neutralization) Filming and neutralJZiUion amines... 

There was a leak on the line supplj ing steam to a plant. To avoid a shutdown, a hot tap and stopple was carried out, that is, the line was bypassed and the leaking section plugged off (stoppled) while in use. The job went well mechanically, but the leak continued. It was then found that the leak was not coming from the steam line but from a hot condensate line next to it. The condensate flashed as it leaked, and the leak looked like a steam leak [26],... 

A 450 psig steam system discharges 9,425 lbs,/hr of condensate through traps into a return condensate line. The return header is to discharge into a flash tank held at 90... 

Figure 2-54. Sarco flashing steam condensate line sizing flow chart. By permission, Spirax-Sarco, Inc., Allentown, Pa. [59].

Because flashing steam-condensate lines represent two-phase flow, with the quantity of liquid phase depending on die system conditions, these can be designed following the previously described two-phase flow methods. An alternate by Ruskin [28] uses the concept but assumes a single homogeneous phase of fine liquid droplets dispersed in the flashed vapor. Pressure drop was calculated by the Darcy equation ... 

Rgure 2-55. Flashing steam condensate line sizing chart. By permission, Ruskin, R. R, Calculating Line Sizes for Flashing Steam Condensate, Chem. Eng., Aug. 18,1985,... 

Finally, the condensate is often pumped from the receiver to the boiler house. Pumped condensate lines carry only water, and rather higher water velocities can often be used to minimize pipe sizes. The extra friction losses entailed must not increase back pressures to the point where pump capacity is affected. Table 22.10 can be used to help estimate the frictional resistance presented by the pipe. 

Figure22.14 Condensate line sizing chart where pressure at traps is above 4bar (SI units). 1. From pressure upstream of trap move horizontally to pressure in return line (A). 2. Drop vertically to condensate load in kg/h (B). 3. Follow curve to RFI scale and across to same return line pressure (C). 4. Move upward to return line flash velocity - say, 25 m/s maximum (D). 5. Read return line size.

Where steam is used for sterilization, hospital duty, food and drug manufacturing processes, or steam humidification purposes, there generally is a reluctance (or mandated prohibition) to employ amines as a treatment for steam-condensate line corrosion protection. Clean-steam... 

The condensate return system is a post-boiler section system that includes all steam traps, condensate lines, associated manifolds and valves, condensate receiving tanks, save-all tanks, condensate pumps, and other auxiliaries for condensate recovery. 

Avoid using unlagged condensate lines because much of the heat available will simply be wasted to the air rather than returned to the boiler FW system. 

Foulants and contaminants may originate virtually anywhere in the overall steam-water circuit. Some may be derived from pre-boiler systems (such as an economizer or deaerator) or post-boiler systems (such as a steam trap or a condensate line), but they inevitably find their way into the boiler and cause significant damage and expense. 

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

Also, no specific amine-based inhibitor is generally provided to protect LP steam condensate pipework against the ravages of carbonic acid (H2C03)-induced condensate line corrosion. 

Where problems develop, there is always a cause-and-effect process. In this case, as oxygen infiltrates the CR system, enhanced condensate line corrosion results (i.e., corrosion over and above the level that may be caused by the carbonic acid formed during steam condensation). This enhanced corrosion, in turn, creates the potential for further downstream corrosion debris pickup by the returning condensate and transporting this material back to the FW system. 

Today, in an era of water reuse and higher costs for premium-quality water, condensate line corrosion may be an inevitable and serious drawback when using naturally high-alkalinity water as a MU supply source. Some form of dealkalization pretreatment process generally is provided to high MU demand boiler plants but unfortunately not so often to smaller facilities. 

Oxygen infiltration coupled with (steam volatile) carbon dioxide produces enhanced condensate line corrosion. The corrosion rate of steel in the system is particularly high when both gases are present. 

Where pressure drops and oxygen infiltration can occur, the presence of both gases leads to a reaction that produces enhanced condensate line corrosion, which generates more carbon dioxide and becomes self-perpetuating ... 

The pickup, transport, and redeposition of corrosion debris and deposits can happen anywhere in steam distribution and condensate return systems and are not confined to any particular boiler plant size or pressure rating. For example, deposit pickup may occur in a superheater with redeposition taking place perhaps in a pressure reducing station, steam trap, or condensate line. The starting point for transport mechanisms is often a combination of BW carryover and condensate line corrosion. 

Corrosion of condensate lines is a serious problem. It is compounded where both oxygen and carbon dioxide are present because it causes considerable quantities of hematite (Fe203) to develop. Corrosion of other boiler plant components, such as FW heaters, adds more metals to the mix, and corrosion debris typically includes iron, copper, nickel, zinc, and chromium oxides. 

Corrosion and mineral debris can form in condensate lines from a variety of means, and it is not uncommon for the resultant debris accumulated over many years to slough off and return to the boiler when operating conditions change. The result is often a thick boiler-bottom sludge that settles out in the water space or baked-on sludge, which mars efficient combustion and water tube heat transfer. 

Process leaks from food and beverage production or wood leachates often produce sugars, colloidal materials, pectins, emulsions, and proteins that cause stable foams in the boiler. These lead to carryover and further steam-condensate line contamination. The temporary use of a demulsifier or defoamer as part of the water treatment program may be of particular benefit, but again the condensate is unsuitable for return to the boiler. Other process leaks include ... 

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.)... 

Alkalinity boosters, which are vitally necessary to enable carbonate, phosphate, balanced polymer (polymer plus phosphate or chelant), and some other program types to function, are perhaps best described as conjunctional treatments, whereas oxygen scavengers, antifoams, and condensate line corrosion inhibitors are adjuncts. Programs such as phosphate-tannin mixtures are sometimes described as adjunct treatments. The chemistries and applications of various types of conjunctional treatments and adjuncts are described in this chapter. 

Post-boiler section (steam and condensate lines, superheaters, etc.)... 

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