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Comment Water Treatment

Modern Water-Treatment Challenges

By Brad Buecker and Brian Clarke Kiewit Power Engineers |

Water and wastewater treatment are extremely important at liquefied natural gas (LNG) facilities and other industries that are blossoming due to the shale-gas boom. Engineering concerns are similar to those of other industrial water-treatment and power-generation systems, but with the added issue of adequate treatment for entrained hydrocarbons. With proper system design and operation, plant personnel can plan for, and react to, issues that could otherwise cause unit shutdown, environmental hazards or safety problems. The enormous growth in shale-gas production has led to an expansion in the number of LNG distribution facilities in the U.S. These facilities require power and steam to compress and cool incoming natural gas, and also to scrub the gas of impurities that would otherwise interfere with the liquefaction process. Economically, it is often logical to use a portion of the incoming natural gas as a source of energy for onsite combined-cycle power and steam generation. However, a number of specific engineering challenges confront personnel who must work with makeup water, process water and wastewater treatment for such complex and integrated facilities. Many of the water-treatment processes discussed in this article are also applicable to other industries that are benefitting from the shale gas boom, such as production facilities for ammonia and urea, ethylene and other petrochemicals.  

Processing natural gas

Natural gas is primarily composed of methane (CH4), but the methane content is never 100%. Rather, impurities typically exist in most natural gas supplies (Table 1). Ethane, heavier hydrocarbons and impurities must be removed to ensure successful production and delivery of the required end product. The impurities will negatively impact the liquefaction process, and some may cause corrosion in the equipment. Figure 1 shows many of the fundamental unit processes that are used to treat natural gas prior to LNG production.
 Figure 1. The major unit operations involved in the treatment of natural gas for conversion to LNG are shown here. In order, the processes remove acid gases and sulfur, water, heavy hydrocarbons and nitrogen
The acid-gas scrubber typically uses an aqueous amine solution to remove carbon dioxide and sulfur compounds. This is followed by dehydration to remove water that would otherwise freeze during liquefaction. Next is a heavy-hydrocarbon-recovery unit (HRU), which extracts ethane and other higher hydrocarbons (these are recovered for further processing). It should be noted that ethane is becoming an increasingly popular feedstock for ethylene production, with a new technology — “oxidative dehydrogenation” — gaining interest as an alternative to standard cracking [ 2]. The remaining steps in LNG preparation are liquefaction and nitrogen stripping to produce the final liquid product for storage. The waste- and product-recovery streams from the LNG-production facility are typically treated in various heat exchangers and other unit operations. Among the several water and wastewater streams around the plant, the following are very likely: • High-purity makeup water for the power- and steam-production units. A water-cooled thermal oxidizer may also be present to destroy some organics • Makeup water for the amine solution for acid-gas scrubbing • Recovered water from the dehydration unit • Returned condensate from other unit processes, including heavy- hydrocarbon recovery • Makeup water for a possible cooling tower
Table 1. Constituents in Natural Gas Supplies, %*
Source (State)
Components PA SC OH LA OK
Methane 83.4 84.0 93.3 90.0 84.1
Ethane 15.8 14.8 5.0 6.7
Carbon dioxide 0.7 0.2 0.8
Nitrogen 0.8 0.5 3.4 5.0 8.4
Hydrogen sulfide 0.2
*Abridged from original table in Ref. 1
Table 2. Makeup Water Requirements for HRSGs
Constituent or measurement Normal limit
Chloride 3 parts-per-billion (ppb)
Silica 10 ppb
Sodium 3 ppb
Specific conductivity 0.1 µS/cm
Sulfate 3 ppb
Total organic carbon (TOC) 300 ppb
Source: Reference 4
Treating each of these streams presents new challenges beyond those of standard water purification. Makeup water treatment.Common for new LNG plants and related facilities, such as petroleum refineries and petrochemical plants, is high-pressure steam generation, often with auxiliary power production. Ensuring proper makeup water treatment for this process is critical [ 3]. For high-pressure steam generation, high-purity makeup water must be supplied to the unit. Even slight concentrations of impurities can cause major corrosion and fouling problems within a steam generator, due to the high temperatures and pressures. As an example, the Electric Power Research Inst. (EPRI) has established guidelines (shown in Table 2) for makeup to combined-cycle heat recovery steam generators (HRSGs). To produce water with such high purity, a step-wise process must be employed. Following the removal of large solids via settling, screens, or both, many industrial applications now also carry out micro- or ultra-filtration (MF and UF, respectively), followed by two-pass reverse osmosis (RO), with final polishing carried out by either mixed-bed ion exchange or electrodeionization (EDI). Additional details on these processes may be found in Ref. 3. Heavy industrial plants typically require a large volume of water for cooling and makeup water production. Often, the amount of water needed for steam production is small compared to cooling water needs. This is particularly true if a large percentage of the steam is recovered as condensate and returned to the boilers. For low-volume needs, a freshwater source may be available for makeup. However, makeup for industrial cooling towers typically requires flowrates of several thousand gal/min or more, most of which leaves the towers as evaporation. To meet this demand, facilities are increasingly being mandated to use less-than-pristine supplies for such high-volume inlet water. These sources include reclaim water from municipal wastewater-treatment plants and groundwater with high dissolved-solids content. For the former source, problem constituents that may arise include elevated levels of ammonia, phosphorus and suspended solids, all of which can be problematic in cooling towers. Excessive suspended solids increase the potential for deposition in cooling tower fill and other locations in the cooling system. Ammonia reacts irreversibly with chlorine, making chlorine-based biocide programs less effective. Microbiological fouling can create a range of problems within cooling systems. Meanwhile, phosphorus in the makeup stream presents multiple problems. For decades, a common cooling-tower treatment method has been based upon a core chemistry of inorganic and organic phosphates, with minor additions of other chemicals to manage corrosion and scale. However, excess phosphorus in the makeup water can throw such programs completely out of range. And another emerging problem is overshadowing this issue in many areas of the country. The issue is “phosphorous impairment” (a condition recognized by the U.S. Geological Survey) of receiving bodies of water. More and more frequently, phosphorus discharges are being limited or banned due to their potential to promote toxic algae blooms [ 5]. In fact, this issue had led to the development of, and demand for, non-phosphorus, cooling-water-treatment programs, in which only polymers are utilized for scale control [ 6]. Condensate return. In a typical power plant arrangement, virtually all of the steam that passes through the turbine is recovered and returned to the steam generator. Losses due to minor leaks and evaporation may consume one or two percent of the stream, but the vast bulk of purified water is continually recovered. At chemical process plants, much of the steam serves process heat exchangers and reaction vessels. Thus, there is substantial opportunity for the condensate to become contaminated. Per the nature of this article, we will focus on organic contamination and start with an illustrative case example. A number of years ago, author Buecker and a colleague were called to an organic chemicals plant that produced phenol derivatives. At the time of the visit, the plant had four 550-psig boilers with superheat. Plant personnel had to regularly replace the superheater of each boiler every 1.5 to 2 years due to extensive solids deposition and subsequent tube overheating. An initial visual inspection showed foam in the boiler drum sample lines. Subsequent research indicated frequent high concentrations of organic carbon in the condensate return, sometimes as great as 200 parts-per-million (ppm). AMSE industrial boiler guidelines [ 7] recommend a total organic carbon (TOC) limit of 0.5 ppm for steam generators of this pressure. Although this case example may seem extreme, the point is that organic contamination can create a host of problems. For high-pressure steam generators of 2,000 psig or greater, the recommended TOC limit in the condensate is 200 ppb. This guideline aims to reduce the transport of organics to the boiler and carryover to the steam, particularly in high-pressure units, since this results in decomposition of these materials to small-chain organic acids. The acids may cause corrosion in steam turbines and condensate systems. For LNG facilities (Figure 1), the potential impurities that can enter the condensate include residual amine from the acid-gas scrubber, and hydrocarbons from HRU and from fuel gas heaters that are not shown on the figure. One configuration that has been developed for volatile-compound removal is shown generically in Figure 2.
 Figure 2. Shown here is one possible treatment scheme to remove impurities from the LNG-condensate return. The process removes combustible materials from the condensate return followed by any excessive dissolved oxygen that may exist. Ideally, the boiler feedwater should contain a small dissolved oxygen residual concentration of 5 to 10 ppb to inhibit flow-accelerated corrosion
The process relies on flash tanks and conventional deaeration to remove the volatile impurities that may be in the condensate. Some streams from the amine-scrubbing system are at high pressure, and these are treated in the HP flash tank. Other, low-pressure (LP) streams, including condensate from heavy-hydrocarbon heat exchangers, enter the main flash tank. This stream combines with condensate recovered from the power plant steam turbine for final conditioning in the deaerator. This particular process relies on the volatility of the impurities. At other facilities where heavier hydrocarbons and oil could be in the condensate, other techniques — such as steam-driven stripping or condensate polishing using activated carbon or adsorbent resin — may be required. Another concern regarding condensate return is the potential transport of piping corrosion products to the steam generator. Straightforward particulate matter filtration might be the answer in some cases, but in others, the use of powdered-resin condensate polishing may be appropriate to achieve greater removal of particulates. Cooling water. The authors and many others have discussed cooling-water treatment methods in numerous publications. But, there are several cutting-edge aspects of cooling water that bear further examination. Perhaps most important to future system design are the pending 316b regulations from the U.S. Environmental Protection Agency (Washington, D.C.). These guidelines have been developed to protect aquatic creatures at plant intakes. The ultimate effect of the guidelines is to eliminate once-through cooling. As discussed in Ref. 8, to meet these requirements, cooling towers, and to a lesser extent air-cooled condensers (ACC), are now the choice for new facilities. As we have previously commented, cooling tower chemistry is becoming more complex, particularly at plants that either accept less-than-fresh makeup water or have tough restrictions on cooling-tower discharge. The list that follows outlines potential treatment and control technologies that can be used to deal with difficult makeup streams for cooling tower systems. • For systems where phosphate/phosphonate chemistry is presently used or is desired, selection of reclaim water for makeup might require installation of a clarifier to remove incoming phosphorus compounds. Iron and aluminum coagulants will precipitate phosphate. Jar testing and pilot testing are a must for developing the proper treatment scheme • Ammonia in makeup water can be removed by breakpoint chlorination, but for high-volume flows (such as cooling towers), this scenario may be a cost-prohibitive technique. Ammonia stripping may be a necessary option • Some plants now have makeup water coming from deep wells. This water often contains high concentrations of hardness, bicarbonate alkalinity, chloride, silica and others. To remove hardness ions and alkalinity, lime and soda ash softening may be required, with possible supplemental magnesium feed for silica reduction. Chlorides can wreak havoc on stainless steels, so more exotic materials may be needed for heat exchangers • Cooling-tower-sidestream filtration is always beneficial in reducing the suspended-solids concentration in the circulating water. Cooling towers are also effective air scrubbers, capturing particulate matter that may enter from the atmosphere, and particulate matter that enter via the makeup stream. Typically, a sidestream filter is designed to treat from 3–10% of the total circulating water flow • Use of substandard makeup water requires very careful selection of the biocide treatment system. Microbiological fouling can occur very rapidly in a cooling system, with severe consequences. In fact, cooling towers have been known to collapse due to the weight of microbiological deposits. Chlorine will be immediately consumed by ammonia and organics in the water, and this can plague systems using reclaim water. Becoming more popular for reclaim-water microbiological treatment is chlorine dioxide (ClO 2). This product must be generated on-site and is more expensive than bleach, but it does not react with ammonia and is not consumed by standard organics
 Figure 3. Shown here is a generalized water-treatment schematic (excluding the cooling tower) for an LNG-production facility. A common demineralizer arrangement is reverse osmosis to remove >99% of dissolved ions, followed by ion exchange polishing to remove residual ions. Pre-treatment to remove suspended solids is not shown
Even with these technologies in place, the wastewater produced during LNG production still needs proper treatment. Wastewater.Cooling-tower blowdown is often the largest wastewater stream at heavy industrial facilities, and at LNG plants, petroleum refineries, petrochemical plants and similar facilities. At many plants, the blowdown is released to a receiving body of water, provided the discharge meets the plant’s National Pollutant Discharge Elimination System (NPDES) guidelines. However, this option is becoming more limited for many process operators [ 8]. Excluding the cooling tower, a generic water balance at an LNG facility with power generation might closely resemble Figure 3. The unit operations are not shown in elaborate detail in Figure 3, but the objective is to provide a system overview. The process shown is similar to that of a typical natural-gas-fired, combined-cycle plant, with a few exceptions. The large bulk of the makeup water goes toward production of steam for process use and as a source of demineralized feed to the process. The aqueous amine used for acid-gas scrubbing needs regular replenishment. As seen in this particular design, plant and process drains are treated in an oil-water separator (OWS) prior to further treatment. The OWS stream combines with boiler blowdown and demineralizer waste in the wastewater tank, from which the liquid is forwarded for further processing. One possibility for wastewater treatment is to remove non-volatile impurities as solids and recycle the distillate, as shown in Figure 4.
 Figure 4. Shown here is an evaporator-crystallizer schematic for wastewater treatment. This process, or variations thereof, allow the plant to operate with zero liquid discharge
Evaporator-crystallizers are commonly used in the chemical process industries, with proven success. A deaerator is typically installed upstream of the evaporator-crystallizer, and as previously discussed, will remove some hydrocarbons, although miscible compounds such as glycols would probably not come out of the water phase as easily as non-polar materials. The same considerations mentioned earlier regarding hydrocarbon carryover from the liquefaction process apply to wastewater treatment, and become even more critical as the wastewater becomes more concentrated. One drawback to evaporator-crystallizers is the significant energy that is required for evaporating large quantities of water. An alternative possibility — see Ref. 8 — is a process that combines filtration, softening and reverse osmosis, which can reduce the discharge volume to be treated by 90%. This leaves a relatively small stream to be further processed by a crystallizer or other method.
Edited by Suzanne Shelley

Authors

Brad Buecker is process specialist in the Environmental Services group of Kiewit Power Engineers (9401 Renner Blvd., Lenexa, KS 66219; Phone: 917-928-7311; Email: brad.buecker@kiewit.com). The group provides consulting and engineering for industrial water, wastewater and air-pollution-control projects. He has more than 33 years of experience in the power industry, much of it with City Water, Light & Power in Springfield, Ill., and at Kansas City Power & Light Company’s La Cygne, Kan., generating station. Buecker has written many articles and three books on steam generation topics, and he is a member of the American Chemical Society, AIChE, the American Soc. of Mechanical Engineers, the Cooling Technology Institute, and the National Assn. of Corrosion Engineers. He has a B.S. in chemistry from Iowa State University, with additional course work in fluid mechanics, heat and material balances, and advanced inorganic chemistry.
Brian Clarke is a water and wastewater project manager in the environmental services group of Kiewit Power Engineers (KPE; 9401 Renner Blvd., Lenexa, KS 66219; Email: brian.clarke@kiewit.com). He is a professional engineer, licensed in Ohio. Clarke graduated in 2004 from Ohio University with a B.S.Ch.E. After graduating, he worked in data analysis and consulting engineering before transitioning to KPE, where he has focused on the design of water and wastewater systems for power-generation facilities.

References

1. Stultz, S.C., and Kitto, J.B., “Steam — Its Generation and Use, 40th Ed.”, The Babcock & Wilcox Co., Barberton, Ohio, 1992.
2. Oxidative Dehydrogenation of Ethane to Ethylene, accessed at: www.itcp.kit.edu/deutschmann/img/content/od_habil_ii.pdf
3. B. Buecker, Modern Concepts in Makeup Water Treatment, Chem. Eng., November 2011.
4. Cycle Chemistry Guidelines for Combined Cycle/Heat Recovery Steam Generators (HRSGs), EPRI, Palo Alto, CA: 2006. 1010438.
5. Wisconsin to Expand List of Water Bodies Under Phosphorus Pollution Threat, Processing e-newsletter, February 20, 2014.
6. Post, R., Development and Application of Phosphorus-Free Cooling Water Technology, Cooling Technology Inst. Annual Winter Meeting, February 3–6, 2014, Houston.
7. “Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers,” The American Society of Mechanical Engineers, New York, NY, 1994.
8. Buecker, B., Cooling Towers: Dealing with Tighter Cooling Water Regulations, Chem. Eng., Aug. 2014, pp. 57–60.
   
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