Many years ago, there was an evening TV game show called To Tell the Truth. There were three contestants who would try to stump the panel of four celebrities. The “central contestant” had an unusual occupation or experience and was required to tell the truth upon questioning by the panel. The two impostors could lie if they chose to do so during the questioning. So what does a TV game show have to do with water treatment ethics and telling the truth?

Let me begin with a common sales scenario. A water treatment sales rep must initially establish credibility by building trust with the prospect. Building trust starts with getting to know the prospect and developing a level of comfort. In order do this, a sales rep must present himself as a trustworthy, honest, and knowledgable person. If he fails to present himself as trustworthy and honest, it does not matter how knowledgable or technically competent he or his company is.

Once a certain point is reached in the sales process, it is sometimes necessary to introduce other company personnel to the prospect. This could be the sales manager, product specialist, technical support personnel, or even one or more of the company executives. At this point, the lead person in the sales process may shift from the rep to one of the upper level management personnel. In many cases, this is acceptable to the prospect however some treatment suppliers fail to explain who will be the primary point of contact once the prospect becomes a customer. When this happens, the prospect usually assumes the sales rep who initiated the sales process will be the service rep. This is not always the case.

Field sales people who have been in the business for many years develop a loyal following and sometimes change employers once or many times. For this reason, non-compete agreements are common among sales people in our industry. This personal customer loyalty is attractive to most prospective employers who see this as an easy opportunity to grow their sales once the non-compete agreement has expired. There is nothing unethical about this fact but let me continue with the sales scenario I started earlier.

The prospect has now decided to make the change in water treatment suppliers after several discussions with the sales rep and meeting with some of the support personnel. The sales agreement has been signed and the deal has been closed. On the day the program is to be initiated, the customer is somewhat shocked to find the sales rep is accompanied by a person he has never met before. Furthermore, the sales rep introduces the previously unknown person to the customer as his new service representative. Whoa! Wait a minute. The trust and comfort level that had previously been developed during the sales process has just taken a step backwards because the customer is now being told he will now be working with someone who the customer is totally unfamiliar with.

Is this ethical? In my opinion, it is not. To me, this is a “bait and switch” move that is more likely to be found on a used car sales lot than in the atmosphere of an ethical, professionally managed water treatment company. The question I would ask if I were the customer is, “Why did you wait until after I signed the agreement to introduce me to the new service rep?” I have seen this happen more times than I care to admit and think it causes a major lack of trust and gives our industry a black eye.

“So will the real water treatment service rep, please stand up!”

When I first began my career in 1976, I was given an account in Evansville, Indiana to service. The customer file I received from my manager had previous service call reports but no information about the system volumes, recirculation rates, metallurgy, temperatures, etc.

This account was a plastics extrusion plant that had a Niagara fluid cooler with a closed loop that cooled small hydraulic oil coolers for the extrusion machines. We were using a patented all organic corrosion inhibitor blend called Drewgard 100 and the feedrate was controlled by a titration test.

One day I visited the plant and was shocked to see the closed loop water looked like tomato soup. Normally it was clear or slightly cloudy white. Hard water makeup was used for the system and there was no meter on the makeup water line. The water sample was obtained from a large concrete sump and was so turbid that it took several minutes to filter it through Whatman #5 filter paper. What bothered me was the total iron in the system was over 50 ppm. When I showed the process engineer the rusty water sample he said, “Oh yeah. I forgot to tell you that we cleaned the system over the weekend and the water is usually very rusty for a few days and then it usually clears up after about a week.” Since I was a rookie and really knew nothing about the system and the treatment history, I accepted the engineer’s response without questioning further and left the plant. On my drive home, I had a very uneasy feeling about what I saw.

I received a phone call from our Regional Industry Manager who lived in Lorain, Ohio asking if he could work with me in two weeks and wanted me to schedule calls on any accounts that were having tough technical problems. This guy had been with the company for 18 years and he really knew how to solve technical problems. Naturally, I scheduled a visit to the Evansville plant. Just before our visit, I received a phone call from the Purchasing Agent who I had never met before. He had recently purchased $ 49,000 worth of new heat exchangers for the closed loop system to replace the old ones that were only 2 years old! He wanted to know what happened. I was shocked and did not know how to respond. I told him that I was bringing in a technical manager and we were going to investigate the problem. Keep in mind that this customer was spending only $ 8,100 per year with my company and the heat exchanger replacement cost would have paid for 6 years of water treatment chemicals.

Before we arrived, I told John (our Regional Industry Manager) about the problem and had no idea about the previous plant history and that the P. A. had requested we meet with him after we talked to the Process Engineer.

Our meeting with the Process Engineer was eye opening. He first told us that they normally acid cleaned the closed loop system once per month and used uninhibited hydrochloric acid. We found out that he dropped the pH down to 2.0 and let the cleaning solution circulate for 24 hours. He then neutralized the acid cleaning solution with lime! Yes, I said lime! He then flushed the system until the water was clear and the rusty water was usually noticed the Monday after production resumed. You should have seen the look on John’s face. He just shook his head and said, “Gene, these guys really need our help.”

We politely told the Process Engineer that his cleaning procedure was actually causing more harm than good. He did not receive this well however John offered to send him a detailed cleaning procedure which would specify the correct cleaning chemicals and amounts. The Process Engineer was OK with this as long as the procedure did not require more time than his current procedure.

We then met with the P.A. and told him we thought the heat exchanger failures may be a result of aggressive cleaning procedures and the Process Engineer was going to follow our new cleaning procedure recommendations. We also explained that we were going to begin monitoring corrosion rates (this should have been done long ago) in the closed loop and fluid cooler systems.

There was a happy ending to this story. We kept the account. Heat exchanger failures were eliminated and cleaning procedures were reduced from monthly to annually.

Over the last few years, I am amazed at how many people do not understand how to operate a dealkalizer system properly or efficiently. This includes some water treatment companies that are selling the ion exchange equipment and replacement resin. In this discussion, I am only going to review Strong Base Anion resin in the Chloride Form.

In many parts of the country, there are water supplies that have high alkalinity water. By that I mean waters that have total alkalinity between 200-250 ppm as CaCO3. There are many areas of the country that have over 250 ppm total alkalinity.

There are different types of strong base dealkalizer resin. Most of them are either Type 1 or Type 2 resins. There is also a Type 3 resin. This discussion will include the more common Type 1 and 2 resins. Type 1 resin is prone to organic fouling which is normally not an issue with municipal water supplies however this can be a problem if other water sources are used. Type 1 resin has slightly lower capacity than Type 2 as well as a lower regeneration efficiency. Type 2 resin has poorer chemical and physical stability than Type 1 resin.

Resin life is greatly affected by the operation of the exchange equipment, the water source used for regeneration, water temperature, the salt impurities in the regenerant brine, TEA (total exchangeable anions), and regeneration frequency. Typical resin life span for Type 1 anion resin is 3 to 5 years and and 2 to 3 years for Type 2 resin.

The most common thing that can shorten the life of Type 1 and Type 2 resins is fouling caused by hardness ions. There are many boiler plants that have bulk brine systems which were installed to eliminate the handling of bag salt by operating personnel as well as reduce the cost per pound of salt. Both of these are good reasons for installing bulk brine systems. What is NOT good is that the bulk brine produced typically uses rock salt which is high in impurities including calcium and magnesium hardness salts. These salts can and will foul exchange sites on the resin beads and will eventually leach out into the water used for boiler makeup causing increased usage of phosphate and chelant chemicals.

To try and compensate for this loss of capacity, the water treatment rep may recommend the use of caustic soda to enhance the regeneration efficiency. In the presence of hardness, the addition of caustic soda during regeneration can precipitate calcium carbonate or magnesium hydroxide in the resin bed causing further reduced exchange capacity. For this reason, high purity salt should be used instead of rock salt for dealkalizer brine makedown to avoid premature resin replacement. This recommendation may initially create push back from the customer however it should be at least discussed PRIOR to the sale of a dealkalizer system.

Another common mistake that is made when a dealkalizer system is first set up is the service run is sometimes set too low. This results in wasted regenerant water and salt due to more frequent regenerations than necessary and further deterioration of exchange capacity due to resin bead breakage and resulting loss of resin fines during backwash.

New dealkalizer SBA resin in the chloride form typically has an exchange capacity of 10,000 grains/cubic foot. In actual practice, most often you will see the regeneration set point at 90% of the full exchange capacity or 9,000 grains/cubic foot at a salt dosage of 5 lb/cubic foot of resin.

Another consideration in setting up a dealkalizer system is to consider the affect TEA (total exchangeable anions) has on the exchange capacity. The TEA includes PO4, SO4, SiO2, NO3, and chloride ions. Why would chloride ion affect exchange capacity? The answer is that high concentrations (usually 100 ppm) of chloride ions can interfere with ion exchange efficiency just as high sodium levels in softener influent can interfere with exchange efficiency.

I actually had an equipment sales manager tell me a few years ago that he always set the regeneration set point at 6,500 grains/cubic foot for Indianapolis city water as “this was was the point at which alkalinity increased at the end of the service run”. Did he bother to check the amount of hardness in the brine, the TEA, or the water source (there are 4 different water sources used by the municipality having different TEA’s), or if caustic soda was added during regeneration?

One final thing that needs to be mentioned, ONLY soft water should be used for dealkalizer regeneration.

A few years ago, I got a call from an upset Refinery Manager at a large soybean processing plant in Indiana. He wanted to know what was plugging his sodium bisulfite injection quill located in the deaerator.

The customer had been having problems with plugging for quite some time and it was becoming a real aggravation for him and his lead boiler operator. The lead operator went onto say that they never had a plugging problem until they switched over to RO water. This did not make sense to me so I decided to further investigate what was causing the problem.

I first examined the plugged nozzle and sure enough there was a purple colored deposit that was restricting chemical feed in the quill. I was able to scrape enough material for a deposit analysis by a lab in Ohio. When I got the lab result, I was somewhat surprised to find that it contained almost 90% cobalt! We were losing the cobalt sulfate catalyst from the sodium sulfite solution.

The only other chemical (other than some recycled amine from the condensate system) we were adding to the deaerator storage section was caustic soda for pH adjustment. Normally, the pH in the in the bulk boiler feedwater was near 9.0 although there were times when the pH was closer to 10.0. We never expected to have a precipitation problem however it was now obvious that our pH control was not as good as we thought since the caustic was fed continuously and feedwater pH was only checked twice per month during my service calls.

Since the feedwater temperature was usually near 230 degrees F and dissolved oxygen testing was usually around 10 ppb or less, our technical director recommended switching to a non-catalyzed sodium bisulfite solution. This eliminated future plugging problems however it made us more aware of proper deaerator monitoring and the need for more frequent dissolved oxygen testing since the customer had an economizer in the B&W boiler.

We also thought about moving the sodium bisulfite injection point further away from the caustic injection point however since the deaerator was a pressure vessel, a certified welder would have been needed to install a weld-o-let and the customer was not keen on doing this.

It has been several years since I have visited the plant and the service responsibility has been passed onto another service representative. Hopefully, he is aware of the previous history and is continuing to closely monitor the feedwater system.

I was asked this question by the plant engineer at a plant that manufactured mufflers and tailpipes in 1984.

This plant had a number of welding machines that used cooling tower water which was used to cool the welding tips. The plant had been running for many years with the same water treatment company using a non-acid treatment program but for some mysterious reason, they were operating the system at 1.5 cycles of concentration. I mistakenly assumed that the reason for the low cycles was because of the high LSI caused by the high alkalinity (250 ppm) in the makeup water. I sold the account on water and chemical savings by operating the system at 4 cycles of concentration using sulfuric acid for pH control.

About a month after we started up the new program, I noticed the acid usage was considerably higher than the theoretical amount needed. The problem was that cycles were only 2.0 and I told the engineer that the system was losing water somewhere which caused higher inhibitor and acid usage.

The engineer checked the blowdown line to make sure there was no bleed through when the blowdown valve was closed, checked the cooling tower on the roof to make sure there was no excessive drift or tower overflow. He also went around to check the some of the individual welding machines for leaks. His inspection proved there were no losses at any of these locations.

He called me and was naturally irate and tired (this was a large plant) because he had spent nearly 4 hours trying to find the leak(s). He told me that he wanted me to come in Saturday and walk the plant to inspect the machines that he missed during his inspection. I arrived early Saturday morning and was given a layout drawing of the machine locations and set about checking the machines omitted during his inspection. I found no leaks at any of the other machines. He was not pleased when I told him I could find no other leaks.

I asked him if he would mind if I could check the machines he previously inspected. He said. “Be my guest since you do not believe me.” I knew then I had lost credibility with him and had better come up with the answer to the system water loss. To my dismay, I found no leaks.

He escorted me to the front of the plant. As we neared the plant entrance, I saw two machines that were not on the layout drawing. I asked him why they were not on the drawing and was told that these were machines used by the New Product Development Department to determine the manufacturing method required prior to a full production run. He said these machines were rarely used and the cooling water was supposed to be shutoff when the machines were idle. I asked permission to inspect them and sure enough, both machines had water flowing through them however the discharge hose from the welder tips was going to a floor drain! I pulled the hoses out of the drain and timed the flow into a 5 gallon bucket. The water losses were equivalent to the amount of water that was preventing the tower from achieving 4 cycles of concentration.

Moral of the story. Be completely familiar with the pieces of equipment and location in the plant. Layout drawings should be requested during a plant survey however they should not be accepted as 100% accurate. As we found out, 2 new machines were installed after the original layout drawing was made and was not updated to show the additional equipment.

A few years ago, a long time customer decided to purchase new twin softeners from my company for his new RO system. The RO water was to be used as boiler makeup water as well as a source of high purity water for their homogenizers.

The equipment room where the softeners and RO were located did not have any floor drains. There was a small pit that collected water or any other spills and a sump pump that was routed to a large overhead drain line.

Just before the softeners arrived, I received a call from the plant engineer asking me if it would be OK to route the softener drain lines to the overhead line which was located 10 feet above the floor. Instead of checking with our engineering department, I called the softener manufacturer sales rep (who I later found did not have a clue about proper engineering design) and was told, “No problem”.

The softeners were installed and I soon received a phone call from the Maintenance Superintendent who informed me that the softeners were leaking anywhere from 4 to 6 ppm hardness after regeneration. He wanted to know why this was occurring when the old softeners always showed zero to 1 ppm hardness. The old softeners were much smaller however they were located in the boiler room which had a floor drain which collected the regeneration water.

I decided to call my engineering department (which I should have done in the first place). The design engineer who previously worked for Bruner and later Marlo and had a significant amount of knowledge about softeners, was able to quickly diagnose the problem. He explained that based on the inlet pressure, the softeners were designed for a brine draw flow rate of 0.5 to 1.0 gpm per cubic foot of resin to insure optimum brine/resin contact time and regeneration efficiency. He calculated the brine flow was less than 0.5 gpm and the brine was basically channeling through the bed because of low flow.

We scheduled a meeting with the customer and they were obviously upset because I gave them bad information. I did explain that the softener company assured me there would be no problem with the overhead drain line. My design engineer was with me and quickly offered an option that they install a 3-way valve which would direct the backwash and fast rinse water flows to the overhead drain line but would be programmed to direct the brine draw cycle to the sump pit located in the floor. The sump pump could handle the much lower brine draw flow rate without flooding the equipment room floor.

This recommendation solved the problem as they noticed less than 1 ppm hardness even at the end of the service run.

Lesson learned: Make sure you know who you are talking to when you ask for help solving a problem. Not all salespeople are poor technically but there are some who are.

Keeping with the recent theme of chemical safety in plants, I offer another true story.

One of my accounts was feeding sulfuric acid from a 55 gallon drum to control pH in an evaporative condenser system for ammonia refrigeration. The plant had a very good safety record over the years because of conscientious and well trained operators.

However one day, the day shift operator was unable to prime the acid pump after changing out the acid drum. He looked at the suction tubing and found it to be cracked and decided not to use the tubing as it was old. It was also seriously discolored making it difficult to see the liquid level in the suction hose.

He soon discovered there was no new tubing in stores and decided to install a used hose and foot valve that had previously been used to feed an unknown chemical. He had to lean over the drum to install the ‘slightly used’ tubing and was able to successfully prime the chemical pump. As he was leaning against the drum, he noticed the drum was beginning to get hot – very hot. After stepping back, he noticed the drum was beginning to swell! He quickly grabbed a fire hose and began spraying the drum with cold water. He continued to douse the drum as if he were putting out a fire and finally the drum began to cool and return to normal size.

The consequences of what might have happened had the drum burst are scary. First of all, the operator was alone in the equipment room and could have been hit by several gallons of concentrated acid. There was a safety shower nearby but if he were hit in the eyes, he may not have been able to find it. Secondly, there were several ammonia compressors nearby that could have been damaged by the acid. If the electrical components, had been shorted out, they could have lost several hundred dollars worth of poultry products. As it turned out, there was no damage to either man or machine or food product.

The used tubing and foot valve may have contained caustic soda or KOH that reacted with the concentrated acid in the drum releasing a tremendous amount of heat. The operator was a very religious man and told me he prayed during the crisis. God answered his prayers that day.

The importance of operator training is one area of a water treatment program that is at times overlooked. Why is that? Well, for one thing it requires a time investment on the part of the water treatment service rep and there is usually no direct compensation for this additional training.

Keep in mind that the plant operator is usually interested in understanding why he/she is treating water in the first place. In addition, most of them are usually concerned about the safe handling of chemicals as well as operation of machinery and controls in general. More importantly, they want to know what to do in an emergency situation.

Here are some real life examples of what happens when operators make mistakes because of lack of training.

1. An operator once plugged a sulfuric acid pump into a hot outlet rather than into the on/off outlet of the pH controller. The result was a gross overfeed of acid which caused free mineral acid (pH < 4.3) to form in the cooling tower water which supplied two large chillers. Fortunately, the day shift operator discovered the problem the next morning. The root cause of this problem was lack of training as well as improper labeling of the electrical receptacles.
2. A packing plant was using a neutralizing amine (DEAE) in a plant where there was direct steam contact with the meat products. Limits for DEAE are 15 ppm in FDA regulated plants. For some reason, the operator plugged the DEAE pump into a hot outlet rather than in the relay that metered in the chemical at a controlled rate. Approximately 85 ppm of DEAE was fed based on the amount of chemical that was added over a 24 hour period. This caused a real dilemma for the plant manager who did not know if it was safe to approve the meat for shipment. I never found out what he decided to do but I must say I was reluctant to purchase their bacon for awhile.
3. An air separation plant was using an orthophosphate based corrosion inhibitor and a HACH DR-890 for measuring treatment levels in the cooling tower water. Distilled water was used for diluting the tower water samples. The lead operator (who should have known better) was approached by the shift operator and notified that he had just used the remaining distilled water and a new supply should be ordered. Rather than writing a requisition, he simply went to the cooling tower water sample point, and filled the distilled water bottle! He never told anyone he did this. When I visited the plant, the operator wanted to know why my PO4 reading was half of what his reading showed. We were doing a 1:1 dilution of tower to distilled water. I decided to test their ‘distilled’ water and found it to contain 8 ppm orthophosphate. The lead operator was embarrassed and I was even more embarrassed for assuming that he new better than to do this.

There is an old saying in the water treatment business that “An operator can make or break your treatment program.” I would like to modify that saying to read , “An untrained operator can and will eventually break your treatment program.”

Please take whatever time is necessary to properly train the operating personnel at your customer plants. Blaming an operator for their mistake is really a reflection on their lack of training which you as a rep are responsible for providing. Do NOT allow another operator to train a new operator for you. He may tell him something that is wrong or misleading. Instead, commit to having at least one in-house training program per year for ALL of the operators. During this time you may want to pass out updated training manuals.

The responsibility for keeping an account happy starts with everyone being on the same page. This can only come through knowledge and understanding by all personnel that are involved in the implementation of your treatment programs.

Several years ago, I was contacted by a small college who had an unusual boiler tube failure problem. The unit was an old fire tube boiler that was rated at about 350 HP and operated at 60 psig.

The boiler had operated for at least 20 years and had never had a tube failure. When I arrived on the scene to survey the situation, the boiler operator told me the boiler had three tube failures caused by oxygen pitting in the last 3 years. The unusual thing was it was the same tube that was failing. During my visual inspection, I did not observe pitting on any of the other tubes.

The feedwater tank temperature was 130 F (typical for summer) and was about 170 F during winter operation. Checking a dissolved oxygen versus temperature chart, the dissolved oxygen was in the 3.5 to 6 ppm range for the feed water temperature operating range. There was no steam sparge line as the temperature was determined by the amount of condensate returning from the campus.

I asked about the feedwater pumps which appeared to be oversized compared to the feed water tank volume. I was told a ‘new’ maintenance director, had been hired and he immediately changed out the original pumps and installed the larger pumps that had been sitting in the boneyard. His line of reasoning for this change being he did not want to buy new pumps and he felt the old pumps were running too long in order to keep up with steam demand in the winter months. After the change was made, the larger pumps developed a cavitation problem as they were starving for water. To correct this problem, a larger makeup water line was installed on the tank which increased the rate at which cold water was added. This caused the dissolved oxygen in the feed water to increase rapidly.

The following recommendations were made and implemented:

1. The larger feed water pumps were replaced with new pumps which were the same size as the original pumps. The new maintenance manager was irate about this as it went against his decision to go with larger pumps.
2. A steam sparge line with a temperature regulator was installed on the feedwater tank.
3. A flow regulator valve was installed on the larger makeup water line to prevent sudden dumping of cold water into the feedwater tank.

These changes resulted in no further tube failures and a reduction in sulfite usage as the average feedwater temperature was consistently in the 185 F to 190 F range.

The value of dyes in chilled water and hot water boiler treatment products cannot be understated. When I worked for a major water treatment company, we frequently used a nitrite/borate/azole product that contained a yellow-green dye.

The use of the dye was added to help locate leaks in chilled or hot water piping systems. When mixed with water, the color made the treated water look like antifreeze.

I first used this product in a hot water heating loop that had been previously treated with a similar corrosion inhibitor package except there was no dye in the previous formula. The previous corrosion inhibitor had to be added on a monthly basis even though no system leaks were ever found. One day I received a panicked call from the customer who told me the water in his steam boilers had turned green! At last, we found the reason for the water loss as the tube bundle for the steam heated hot water loop had been leaking for some time. The dye showing up in the boilers confirmed the heat exchanger leak.

A few months later, I received another urgent call from the same customer who told me that one of their visitors complained of yellow-green water coming out of one of the drinking fountains! This time, one of the maintenance men who installed a new drinking fountain thought the nearby chilled water line was the domestic cold water and used it as the fountain supply line. As far as we know, no one suffered ill effects but nitrite as well as azole are chemicals that you should not drink. You can read about the health affects of these chemicals on the CDC website.

Over the years, at least two of my customers found leaking pop off valves on their hot water boilers after finding the boiler room floor stained with the dye. Another customer had some old fermentation reactors that had chilled water, steam, and cooling tower water piped into the jacketed vessels. All of the valves on these various lines were thought to be in good working order until the water in both steam boilers turned green. The leaking chilled water valves were then replaced.

It would seem the use of dyes in closed loop formulations would be more prevalent however there are disadvantages to using dyes in closed loop products. The biggest complaint is with the nitrite test accuracy. The accuracy of the nitrite test can be greatly affected when using a photometer because of the affect on light transmittance. A better test would be the potassium permanganate titration test using a burette (rather than counting drops). Most people dislike using permanganate because it can stain lab glassware as well as your hands and clothing. In addition, the shelf life on potassium permanganate is not very long as it will turn from purple to brown over time.

The use of activated carbon filtration prior to testing has been useful in many cases in removing the dye color prior to testing.