PROBLEMÁTICAS NALCO

PROBLEMÁTICAS NALCO

Exposure time for coupons Mussi, Fernanda 1/8/2015

Hi!

I need to know what is the recommended expouse time for coupons in function of metallurgy.

I think is not necessary change it every 15 days to have 2 reading per month (the exposure total time is 30 days but w e put w ith a difference of 15 days of each other)

this is w hat the costumer request.

Regards!

Re:Exposure time for coupons Hovorka, Eddy 1/8/2015

Best Practice is 90 days for mild steel

Re:Exposure time for coupons Dillon, James 1/8/2015

ASTM states that the minimum recommended exposure period for a coupon is 85 divided by the expected mils per year corrosion rate. Your corrosion rate measurement w ill not be accurate if you do not expose the coupon for a suff icient period of time. If your corrosion rates are typicallly high, then 15 days may be suff icient. Even w ith this rule of thumb, w e recommend at least 30 days of exposure.

Re:Exposure time for coupons Tebbetts, Ronald 1/8/2015

In many refiineries, the customer pretty much dictates this as this is a KPI that they like us to track. I like longer than shorter as James pointed out, the shorter durations w ill show higher corrosion rates. Whatever length you pick, you must maintain that duration for all future coupons as you really cannot compare coupon corrosion rates of coupons with differenct durations of exposure. I personally like 90 day coupons but that usually means that you have only 4 data points per year. As an alternative, I use three coupons in one rack. I install the f irst coupon on day one, the second on day 30 and the third on day 60. On day 90, I replace the f irst coupon and then every thirty days thereafter, I replace the coupon that has been in the rack for 90 days. THis gives me a 90 day coupon every month, so I now have 12 data points rather than 4. I do this because w e are often judged on this little piece of metal stuck in a coupon rack w hose f low may not be constant or adequate for the entire test period. Having more data then less w ill provide me w ith the means to respond a little faster to any problems. I also use the fourth spot in the rack for a 30 day coupon so that I have an early w arning system in place.

Re:Exposure time for coupons Mata, Pedro 1/9/2015

It looks your customer is keen to spot corrosion trend changes frequently. As you saw from the above replies, there is a reasonable consensus about the minimum exposure time you should consider for coupons. Why not look for the trend on a continuous basis w ith the probes from the 3DTrasar unit (or a separate NCM if you don't have 3DTrasar) and use the coupons to cross check the average corrosion against the probes? Attached a document I often used w ith my customers. Regards

Re:Re:Exposure time for coupons Mussi, Fernanda 1/9/2015

Good option cross check, thank´s for the document!

Re:Re:Exposure time for coupons Mussi, Fernanda 1/9/2015

if is new treatment, should be measured every 30 days to know the expected rate of corrosion. then I can change it, because if is too low is not necessary 30 days..correct?

thanks a lot for you answer!

NexGuard 22300 Pump Recommendation Tholstrup, Caitlin 1/20/2015

We use NexGuard 22300 at a rate of ~0.5GPM. The current pumps w e have are ~60x oversized so we have a spillback on the system to not overheat the pumps. The pump seals that w e have now are also prone to leaking.

Anyone that uses a small amount of NexGuard have a recommendation for pumps?

Re:NexGuard 22300 Pump Recommendation GLOBAL\rtebbetts 1/20/2015

What pressure are you pumping into and did you mean 0.5 gpm, 0.5 gph or 0.5 gpd? The 0.5 gpm seems high.

Re:NexGuard 22300 Pump Recommendation Tholstrup, Caitlin 1/20/2015

Sorry I meant ~0.05gpm. The pressure is about 55psi.

Re:NexGuard 22300 Pump Recommendation Hovorka, Eddy 1/21/2015

Caitlin, I'm using a pneumatic Williams pump P125V125. I only use about 1-1.5 GPD. Since it is a Class I Div 2 area, pneumatic w as the easiest and more cost effective route.

Re:NexGuard 22300 Pump Recommendation GLOBAL\rtebbetts 1/21/2015

So to be clear, you are pumping 72 gallons per day?

Do you need Class 1 Div 2?

Re:NexGuard 22300 Pump Recommendation Tholstrup, Caitlin 1/21/2015

We typically pump 65-75 gallons per day. I checked w ith electrical and w e do not need class 1 div 2 for this area.

Re:NexGuard 22300 Pump Recommendation NALCO\mharold 1/21/2015

Caitlin - Since there are three small control valves that f low proportion the Nexguard to the BFW streams dow nstream of this centrifugal Nexguard pump, you w ill need to replace w ith a smaller centifugal pump that w ill safely hold the upstream head pressure that the small Nexguard control valves need to function w ell. I don't think smaller positive displacement pumps w ill w ork in this service unless you also get rid of the small Kammerer control valves that currently meter the Nexguard.

I am w ondering if the small 3DTfCW sample booster centrifugal pump might f it the bill. Off hand, I am not sure of the gpm or materials of construction, but you can f ind out from our West Coast Equipment Engineer, David Hess.

N1800 pH measurement Eyckmans, Frank 2/5/2015

Hi,

since 1,5 years we have switch the boiler amine product from N356 to N1800.

This has resulted in a better boiler and condensate pH control.

But regularly w e see a drop in pH from 9 tot 7 and the next day it is 9 again.

the operators react to the apparant low pH by increasing the dosage w hich results in an overdosage.

Is pH measurement more diff icult w hen using N1800? Is there any other explanation or test I can do to verify what is causing the "pH dips".

We have been searching together w ith the customer but still no explanation.

Is there a procedure for measuring pH in boiler/condensate water?

Re:N1800 pH measurement Hovorka, Eddy 2/5/2015

Frank,

There are many factors that go into measuring the pH of condensate.

1. Is the sample point f low ing continuously? That is a best practice. Bad sample, equals bad data

2. Is the sample cooled to 25 Deg. C, or a temperature near that? If it is w ell above or below 25 Deg. C, you should be correcting the value, if your meter isn't corrected/compensated fr temperature.

3. Is your pH meter temperature corrected and/or compensated?

4. How long does the sample sit before you measure the pH. The pH of a condensate sample left sitting on a benchtop w ith the lid open can drop easily by a pH unit or tw o.

Re:N1800 pH measurement Harold, Mark 2/5/2015

Frank - Eddy brings up some good points to consider. I have also seen several other things mess up the measurement of condensate and other pure w ater pH readings/measurements.

If the operators use their pH meter for measurement of any other sample either higher or low er pH and don't fully rinse the probe off w ith demin w ater and then the condensate sample, they w ill get a pH skew . For example, in one of my accounts a given operator w as always getting a high condensate pH result and the other operators w eren't. It turns out that he w as measuring a dilute caustic pH using the same probe right before he measured the f irst condensate sample. The f irst condensate sample show ed 10.4 pH. The second one w as usually in range at ~9.2.

Also, the more you stir the sample and leave the probe in the condensate the further the pH w ill drop. This is because the stirring and sitting time is allow ing air w ith CO2 to be dissolved into the sample. This drops the pH. It is best to fully rinse the probe 3x's w ith demin and then once w ith the condensate sample before dipping the probe in the sample. Once in the sample, read the pH w ithin 15-20 seconds.

Additionally, there are better probes that you can use for low inonic w aters such as condensate, RO product and demin samples. You can also look at adding a couple pinches of Nalco R-1 salt to the sample to give the pure w ater some inoic content w ithout shifting the pH. This gives the pH probe or handheld something to grab onto. It tend to stabilize the readings. In some accounts w here measuring condensate pH's w as an issue, we have asked them to purchase a low ionic pH meter and probe and only use it for condensates, demin and RO prodcut w ater.

Hope this helps!

Mark

Re:N1800 pH measurement Puchan, David 2/5/2015

Generally the issue yor having w ould be attributed to some type of testing error. A list of these have been presented by other commenters. The tw o that w ould be most suspected are 1. The person performing the test is agitating the sample aggressively which will pull air (CO2) and low er the pH. 2. The probe is being stored in 4 buffer (recommended) and not being throughly w ashed off.

Re:N1800 pH measurement Puchan, David 2/5/2015

I recommend you get the ASTM procedure ASTM D5464-07.

This procedure w ill cover what you need. It is available on-line.

Fouling in feeder tank of EC1021A Ramirez, Yorge 2/20/2015

We are using the filmic amine EC1021A, and it's forming gums In Background of feeder Tank , who has Observed this fouling for this product ?. cause?. what am I do?

Re:Fouling in feeder tank of EC1021A Lordo, Samuel 2/22/2015

can you send me an email w ith more of your application details? some information in ec1021a...

it can cause issues if it gets w et and is fed into a tow er. it can cause WSIM issues w hen used at high dosages in some crude tow ers

Fouling in feeder tank of EC1021A Ramirez, Yorge 2/20/2015

We are using the filmic amine EC1021A, and it's forming gums In Background of feeder Tank , who has Observed this fouling for this product ?. cause?. what am I do?

Re:Fouling in feeder tank of EC1021A Vanacore, Mario 2/23/2015

Many years ago (more than 10 years ago for sure) I had a couple of Ec1021A batches that gave a crystalline light yellow deposit in the storage tank (senior porta feed).

You may consider to check if more info about this kind of problems are reported in our Case Management (old name for this w as CQ1) system and you can as w ell check for the retain sample of the batch that gave you problems.

Re:Fouling in feeder tank of EC1021A Claesen, Chris 2/23/2015

I have experienced the same issue years ago. If I remember w ell it w as only with bulk storage tanks and w e were suspecting that contact w ith water or moist caused the formation of a w axy yellow deposit.

Re:Fouling in feeder tank of EC1021A Villar, Marcelo 2/23/2015

w e had same problems that mentionhed for our colleagues. Here w e observed this problems during low temperature days. w e change for EC1010A in this aplications.

Difficult to desalt crudes Farrell, Douglas 2/24/2015

Folks: I w ould like to open a forum discussion on how to handle 'diff icult to desalt crudes'. By this I mean ones that typically contain more salt than is measured by our hot w ater extraction test. These might include but are not limited to: crystalline salts, micro-emulsion or just really high salt content.

We have experienced overhead chloride issues with Ostra/Argonauta Blend, Polvo and Peregrino. We have a good desalter set-up: 2 stage, 3 grid How e Baker desalter.

We w ould like to know what others have done to process these or other crudes which have been identif ied as diff icult to desalt for some reason or other. If w e have local limitations vs w hat others have, that w ould be good to pass along to our customer for future upgrades.

-Doug Farrell

Re:Difficult to desalt crudes Mason, Brad 2/24/2015

I'll start the ball rolling. Apart from the obvious mix valve optimization/changing the ratio of w ash water to the cold preheat to see if you can contact more brine: 1. Caustic is obviously the catch all for diff icult to desalt chlorides to provide another line of defense for the overheads 2. Having a w ater wash in the overheads if you are calculating some salting potential - w ash away the salt and the under-deposit corrosion that can result 3. Consider adding a crude tankage desalting program to desalt some extra salt out before it comes to the desalter - depending on residence time in the tanks and w ater separation, some decent removal rates could be possible. Some plants that have no desalting (or for a short time need to conduct maintenance on the desalters but the unit remains online w ith crude bypassing them) and apply chemistry in the tank farm to achieve sometimes 50-60% removal...





-Doug Farrell

Re:Re:Difficult to desalt crudes Claesen, Chris 2/25/2015

To add to Brad's recommendations:

- Increase the amount of w ashwater (maximum about 7%)

- Put more w ashwater before the cold preheat

- Install desalter automation, on-line salt measurement

- If the transformers are giving high amps, evaluate the KVA/ft2 and consider heavier transformers. A lower tap setting may also help.

- If the crude is not too heavy and w ater can be separated relatively easily, consider adding some w ater in the f ill line to the crude tank to get some dilution and extra tank desalting.

- I have seen lab and f ield indications that the addition of caustic to desalter w ashwater can improve the removal of diff icult to remove salts. Think of it as w ashing off chlorides from a resin, like in the regeneration of a w ater softener. This is something that f irst has to be studied and evaluated properly, if overdosed it can cause more problems that it solves.

Re:Re:Difficult to desalt crudes Fearnside, Paul 2/25/2015

Insure that your w ater f low meters are accurate!!

When w as the last time your w ater f low meters were calibrated?

Re:Re:Difficult to desalt crudes Farrell, Douglas 2/25/2015

Brad: Thanks. First, caustic is not up for consideration at this unit- either in the w ash water or injected into the crude- not in a boat, not w ith a goat. We have been completely shot dow n with that one.

Our salt in crude numbers by extraction are 0.15ptb yet chlorides are 60-80ppm. It has been suggested by some of our LA folks that w e could have crystalline salts or increased CaCl2 hydrolyzation due to nap acids. We have been pushing as hard as w e can with w hat we've got. We have 3.8% w ash water and a static mixer/gate valve combo for mixing. We have about 50% WW going to the front end. How much can w e direct that w ay? 100%.

I w ould like to know what is succeeding with these types of crudes at other locations. We have new Petreco mix valves w hich are not installed and a design case for brine recycle which was cancelled for last fall T/A. If I can make a case for better mixing and more w ash water based on industry experience, it might help get some things done.

-Doug

Re:Re:Re:Difficult to desalt crudes Farrell, Douglas 2/25/2015

Paul: The f low meters add up to roughly w hat we have in steam adds- so I am OK w ith the measurement. How ever, I am not happy w ith our results. We have been moving the mix valves up stepw ise and are in absolutely uncharted w aters vs historical dP's. The only reason w e are getting aw ay with it is because the refinery is short on crude supply and rate is dow n. Otherwise, we would be backing out rate w ith the mix valves.

What I w ould really like to know right now is what % level in mixing or w ashwater or whatever are others requiring when running these 'hard to desalt 'crudes. In other w ords: Are we dead in the w ater with our current WW supply and gate valve style mix valve or not?

Are there other things w e could do w ith the existing equipment? We currently have 50% of total w ash water coming in via the pre-heat. Can w e go to 100%.

What w ould be most useful w ould be to have a direct conversation with someone w ho has had this experience and compare notes. I hink w e have already gone through all the Desalter 101 stuff.

-Doug





-Doug Farrell

Re:Re:Re:Re:Re:Re:Difficult to desalt crudes Fearnside, Paul 3/4/2015

90F is cold.

Putting a higher % of the w ash water into the preheat train should directionally help out.

Re:Re:Re:Difficult to desalt crudes Sarritzu, Francesca 3/4/2015

Hi Alberto, i'm cheking for Peregrino Info. If i understand good, it have high inorganic Chloride content? How much salt did you determine out desalter? and how much Cl in OVHD? Can you describe me the new techniques to measure all chlorides content please?? Thanks a lot Francesca

Re:Re:Re:Re:Difficult to desalt crudes Claesen, Chris 3/5/2015

Francesca,

The instrument is the XOS Clora.

Information regarding the instrument can be found here:

http://www.xos.com/products/chlora-bench-top/

Salt Content measurement Chandra, Debjit 3/14/2015

Frequently it is seen that there is a difference in measurement values of salt content (desalter crude sample). Normally w e measure by Titration method( after double extraction) and Refiners by conductivity method. Which is the recommended method and w hy there is a difference of measurement values?

Re:Salt Content measurement Militello, Walter 3/15/2015

The most accurate method, also suggested by NACE and desalter manufacturers, is the ASTM D6470, salt extraction and potentiometric titration. The electrometric method (ASTM D3230) is not accurate at all, w hen we are talking of salt content on refinery desalted crude (usually less than 2 PTB). The method has been developed for oilfields where laboratories are not very accurate and salt content is quite high, therefore an analytical error of 1-2 PTB does not make a big dif ference. The electrometric method is not accurate because it measures the conductivity of a f luid, indirectly relating the conductivity to its salt content. For desalted crudes, a lot of interferences are from any component that conduct electricity. Just tell to customer that also iron, alw ays present even at small concentration, conducts electricity, and many other salts (from formation w ater), conduct electricity. Therefore the lab measures chlorides PLUS a lot of other conductive species that are not related to salts. Finally, for refineries processing a w ide variety of crude oils (like India), the electrometric method is not accurate ‘cause every time the lab should prepare a standard to reset the instrument (zero conductivity) and to calibrate w ith a know n quantity of salts. This procedure is time consuming, so the vast majority of labs are just making one single calibration solution and calibrate the instrument (w rongly) with the same solution for several real samples.

Black Water When using Ferric Coagulants Duttlinger Jr, William 3/16/2015

Hi all,

Was recently at a refinery in Baku doing some w ater clarification testing with the main goal of reducing oil in w ater to <10 mg/L prior to entry into bioremediation system (didn't get to see this sytem) prior to disposal in the Caspian Sea.

We had great success when using aluminum based products but w hen I tried to use either ferric sulfate or chloride, the w ater would turn blackish. There w ere no discreet particles (that I could see w ith my eyes) and the more I added of the ferric salt, the w orse it got.

My f irst thought w as that it w as ferric sulfide as there w as a slight sulfur type of smell at the plant. The w ater also kind of smelled slightly like ammonia (there w as less than 10 mg/L of ammonia in the w ater when they measured it a w hile ago).

The w ater, when clear, was a light green color. Not sure if any of this is related to w hat I saw . Unfortunately, I didn't take any pictures of the w ater treated with ferric.

Curiosity is getting the better of me so I f igured I w ould ask the netw ork.

Regards,

Bill

Re:Black Water When using Ferric Coagulants GLOBAL\rtebbetts 3/16/2015

Bill

You say that you f irst thought that it w as ferric sulfide but then you don't really say that you have ruled that out. Have you done any testing on sulf ides or composition of the resulting black material?

How much iron coag are you feeding? What is the iron level in the sample w ithout the coag?

My first guess was iron sulf ide but I'd like to see more info.

Re:Black Water When using Ferric Coagulants GLOBAL\rtebbetts 3/17/2015

I do recall that this happened to me a couple of times w hen jar testing in a w aste plant w ith measurable amounts of H2S in the w ater. Upon addition of the Ferric, the jars turned black. Needless to say, I didn't pick ferric as my coagulant of choice.

Re:Re:Black Water When using Ferric Coagulants Duttlinger Jr, William 3/17/2015

Hi Ron, No I haven't ruled it out. We didn't do any analysis at all. At low doses (25 ppm or so), the w ater turned a slight color. I w ent all the w ay up to 1000 ppm and at dose, the w ater was essentially black. Obviously, w e din't use ferric, either. Iron w as less than 10 ppm in the sample but could be less than 5. I w ould have to look it up. I w as wondering about H2S. The plant had a nice sulfur smell and w e were told they didn't have H2S. We didn't smell anything after shaking up the sample to homogenize prior to our testing so I tend to believe that they don't have H2S. Regards, Bill

Salt Content measurement NALCO\dchandra 3/14/2015


Re:Salt Content measurement Scattergood, Glenn 3/17/2015

Brad, does RPS recommend one method over the others? Do RPS endorse conductivity (I'm sure they don't!)?

Re:Salt Content measurement Scattergood, Glenn 3/17/2015

Debjit, it is interesting to plot the atmos and vac overhead chlorides vs. salt-in-crude by both conductivity and hot w ater extraction. One w ill show a nice correlation, the other most likely w ill not.

Re:Salt Content measurement Thornthw aite, Philip 3/17/2015

While w e are discussing the established techniques of conductivity vs extraction / titration and the issues associated with both techniques, it w ill be w orth mentioning to your customer that more refiners are moving to the Chlora analyser.

This is an automated XRF technique that measures total chlorine in the crude (not chloride)

http://www.xos.com/products/clora-bench-top/

Black Water When using Ferric Coagulants Duttlinger Jr, William 3/16/2015

Hi all,

Was recently at a refinery in Baku doing some w ater clarification testing with the main goal of reducing oil in w ater to <10 mg/L prior to entry into bioremediation system (didn't get to see this sytem) prior to disposal in the Caspian Sea.

We had great success when using aluminum based products but w hen I tried to use either ferric sulfate or chloride, the w ater would turn blackish. There w ere no discreet particles (that I could see w ith my eyes) and the more I added of the ferric salt, the w orse it got.

My f irst thought w as that it w as ferric sulfide as there w as a slight sulfur type of smell at the plant. The w ater also kind of smelled slightly like ammonia (there w as less than 10 mg/L of ammonia in the w ater when they measured it a w hile ago).

The w ater, when clear, was a light green color. Not sure if any of this is related to w hat I saw . Unfortunately, I didn't take any pictures of the w ater treated with ferric.

Curiosity is getting the better of me so I f igured I w ould ask the netw ork.

Regards,

Bill

Re:Re:Re:Black Water When using Ferric Coagulants Loris, Alessandro 3/18/2015

HI Bill, There are several species that can give a black product w hean reacted with Fe, but in a refinery the main cause is sulf ides. I suggest to detect H2S but also Sulf ides w ith higher solubility in w ater/oil. At low sulf ides concentration the color is dark green (depending from the environment of course) and at higher conc. it gets black. Regards Alessandro

Re:Re:Re:Re:Black Water When using Ferric Coagulants Duttlinger Jr, William 3/18/2015

thanks Alessandro. I think w hen we do a trial there, w e w ill ask them to test for sulf ides just to be sure. Regards, Bill

Salt Content measurement NALCO\dchandra 3/14/2015


Re:Re:Salt Content measurement Militello, Walter 3/19/2015

Another w ay I use to demonstrate that electrometric method is not accurate, is the chlorides material balance from desalter to overhead.

And if still customer is not convinced about, if analysis shows values that are very low (<2 PTB) I ask them to stop caustic. When the overhead chlorides jump above 100 ppm, then customer starts to believe that electrometric method is not accurate at all.

Re:Re:Re:Salt Content measurement Militello, Walter 3/19/2015

Done.

Please DO NOT SHARE WITH CUSTOMER.

It's not available on internet because it's PAID document.

We do not give know ledge and expertize for free.

Isothiazolone Maximum Concentration Abou Khatw a, Ahmed 3/22/2015

My customer is asking me w hether we have Isothiazolone (N7330) w ith 45% (or higher) concentration. My answer was no.

But the real question is: Does it exist at such high concentrations in the industry? A competitor is claiming they can supply.

Re:Isothiazolone Maximum Concentration Subramanian, Venkat 3/23/2015

Theoretically Isothiozoline solution canc be supplied at higher concentrations of 40% or 45%. DOW (ROHM & HASS) suppleis at a max concentration of 15% due to follow ing consideration:

1. Stability - isoth. is highly unstable at higher concentration and sensitive to pH - slightly acidic pH is preferred.

2. Due to its acute toxicity, spillage handling and exposure risk is limited w hen ahndling solutions of optimum concentration. Dor applications w ith requirement of low concentrations such as CW biocide 1.5% solution is supplied as a standard for easy handlling and stability.

Re:Re:Isothiazolone Maximum Concentration Abou Khatw a, Ahmed 3/23/2015

Thanks a lot Venkat. That is also w hat i found after extensive online search. But I came across the attached and it show s 45%, but don't know if it is still available or not in market. Could you please have a look at it and advise?

Isothiazolone Maximum Concentration Abou Khatw a, Ahmed 3/22/2015

My customer is asking me w hether we have Isothiazolone (N7330) w ith 45% (or higher) concentration. My answer was no.

But the real question is: Does it exist at such high concentrations in the industry? A competitor is claiming they can supply .

Re:Isothiazolone Maximum Concentration Cody, David 3/24/2015

All suppliers to Nalco are under 13%.

Re:Re:Isothiazolone Maximum Concentration Abou Khatw a, Ahmed 3/24/2015

Thanks a lot David.

Looking for reliable method to measure TRASAR in BFW. Tebbetts, Ronald 6/24/2014

Posted on behalf of Victor Corrales w ho asked the follow ing question:

Hi all, In boilers 600 psig, with demineralized water, I have problems with measurements of TRASAR in boiler feed water, and although the dose of N-22300 is above 4 ppm, the HandHeld throws me different results every day, and this condition does not allow me to keep track of the cycles of concentration, and TRASAR cycles are very different from those calculated by conductivity or chloride cycles. On the other hand, the measurement of active polymer by colorimetry with 881.75 SO solution throws me very low results and I've tested oxygen in the water supply to boilers, and is in control. Is there a reliable method for measuring the residual polymer or TRASAR in the boiler feedwater?

Lawrence Hill: Victor, maybe you could try to add a dipper of BaCl powder to 100 ml of Sample, stir, then decant the sample to another cup, and then see if that results in more reproducible results. we have some people doing that to help with iron interference in cooling handhed fluorometer testing. Maybe it will help, if not, little effort to give it a try. Larry Hill

Anton Banweg: Have you done a background fluorescence analysis of the feedwater?

Victor Corrales: Hi Mr Lawrence, thanks for the idea, i will try that option. Hello Mr. Anton, A long time ago we send a sample for this test, and the background fluorescence was four percent is boiler water, but we don't analyze the feedwater because we think that is not representative or the result could be zero. I suspect that could be some error in the instrument, because we already try with three different HandHelds.

Robert White: Victor- Wonder if when you get to the plant you grab your samples. Do the testing as you normally do, but leave a clean sampling container under the Feed water (FW) sample point allowing it to fill slowly over the time you are in there....even let it overflow. Then check the FW conductivity, chlorides, and TRASAR levels again to see if the ratios get closer together on your boiler cycles....perhaps a more "composite" sampling technique is needed based on the mechanics of the feed system or equipment operations?

Victor Corrales: Hello Mr Robert, I think that is a good idea, but the client has some

Re:Looking for reliable method to measure TRASAR in BFW. GLOBAL\vcorrales 3/31/2015

Hi Deb, thanks for response. You are correct, the AP-16 test is for iron. I meant the AP-116 for active polymer. The confirmation of the cycles is by conductivity. We have some discrepancies with the cycles by silica or chloride. Because of that, w e are not using the silica or chloride for calculation of the cycles, only w e use the conductivity and the TRASAR. In the case of pH, the boiler feedw ater have a pH betw een 8.4 and 9.3 units; therefore, I do not know if the pH is causing problems in measuring TRASAR. The boiler feed w ater that provided by the deaerators DH-4601/4602 doesn't have color or turbidity, is demineralized w ater. In the analysis of TRASAR w ith HandHeld TR 8000, I did not observe bubbles in the cuvette w hen I performed the measurement. I can try diluting the sample as you suggest, but I have a doubt: If the value that I should measure is low (betw een 1.8 and 4 ppm), the dilution does not cause a decrease in the measurement range of the instrument. The sample could be more susceptible to any interference? As you said, my sampling point is dow nstream to the injection point, and it doesn't have automatic control. I'm according w ith you relative that w e expect some fluctuation to occur depending on TRASAR feedrate vs feedw ater f low . And because of that, w e calculate the amount of TRASAR according to the f low of feed w ater every day, this in order to compare if the TRASAR measurement is higher than calculated. Generally, TRASAR measurements are higher compared to calculated according to the dose of N-22300 and the feedw ater f low . Recirculation of w ater supply is a good point. I w ill check the amount of feedw ater recirculated in order to see the impact on TRASAR measurements. How ever, I insist in the random measure of TRASAR in the feedw ater than I show in the table N° 1. If I have a sample and I make f ive measurements from the same sample, I w ould expect that the f ive measurements w ill be relatively similar, and not that they w ere as different as show n in Table N°1. According on w hat David says, the HandHeld have the Cap that covers the tip, and I make sure that the measure is realized w ithout expose the sample to the light. In function on w hat Juan says, I think that the sampling point is important part, but in the instrument is happening something that w e have not seen, and only affect the measurement in the feed w ater and not in the boiler w ater.

Reverse Osmsoes - ClO2 Dos Santos, Tatiane 3/17/2015

I have a customer that receive feedwater with ClO2 to his RO unit, and we use sodium disulphite for reduce oxidants elements to protect the membranes.

This plant has a control with ORP and we noted that we have to use much more than 3,6 ppm sodium disulphite /ppm ClO2 to control the ORP on range (160 – 180 mV) and to reduce 0,20 - 0,15 ppm ClO2 (feedwater) to 0,02-0,04 ppm (membrane inlet).

I’d like to ask your help for:

1) Try to f ind the stoichiometric chemical reactions reaction betw een sodium disulphite and ClO2 to understand if this 3,6 ppm applies to this case (as 3,6 ppm normally is used to free chlorine) or not.

2) Ask if has anyone a similar experience and can explain this high consume of sodium disulphite?

Thanks!

Re:Re:Re:Reverse Osmsoes - ClO2 Sparapany, John 4/7/2015

No, use w hat you are but perhaps look to move the injection point back a little to provide more mixing/reaction time.

Is your Scorpion application following best practices? Claesen, Chris 3/13/2015

When w as the last time your Scorpion or HAC (High Acid Crude) application w as reviewed? Are you sure all the best practices are in place? Are you sure you are not over injecting chemical? Are the right monitoring tools in place?

This month there w ill be a HAC processing article by one of our competitors (DK) in the Hydrocarbon Engineering Magazine. The article may draw the attention of your customer and focus him on real or perceived gaps or problems w ith your treatment.

If you are not confident that all best practices are in place or if it has been a w hile since your application w as reviewed by an SME or ITC it is now a good time to plan a review of your application.

Re:Is your Scorpion application following best practices? Claesen, Chris 4/7/2015

Be aw are that DK are making a lot of publicity.

On p81 of the latest PTQ there is a similar DK article:

http://eptqtemp.remotenew media.co.uk/digitalPTQ/2015-ptq-q2/f lipview erxpress.html

They claim:

"The incremental risk of phosphorous fouling from the inefficiency of conventional, thermally unstable acidic phosphate esters has been a major factor in limiting the use of chemical corrosion inhibitors. Tanscient (the DK chemical) is new chemistry that achieves the required corrosion protection at treat rates of 0.1 to 0.5 ppm phosphorus, which is up to 80% less phosphorus than in conventional phosphate esters.

This high phosphorus efficiency is providing refiners with a safer option for corrosion protection and is changing refiners’ perceptions of HTCIs."

While the DK story may look good to an inexperienced engineer it also has a lot of w eak points. Be aw are that DK expresses their HNN treatment in ppm P not in ppm product. When you convert our typical dosages w e have the same or better performance.

We have 30 years of track record with hundreds of application points, they have as good as nothing. The esters they suggest are tri-esters and these w ere the ones that are suspect to distill up tow ers to create fouling in Kero and LGO sections.

Good description of new hyper duplex SS metallurgy Militello, Walter 4/8/2015

Good to know about this new metallurgy on the market. Refineries are going more and more tow ard expensive metallurgies if they feel cannot cope w ith opportunity crudes, high corrosion rates and complicate/unreliable chemical programs.

Re:Good description of new hyper duplex SS metallurgy Claesen, Chris 4/8/2015

Walter, thanks for pointing out that the use of these materials is increasing in the refining and petrochemical industry. I have removed the article as it comes from the HP magazine and thus is copy right protected. I have made a short summary for the duplex steels below . The term Duplex stainless steel comes from the microstructure of the alloy w hich is approximately a 50/50 austenitic/ferritic . Duplex provides better general corrosion resistance, chloride stress corrosion and pitting corrosion than austenitic SS304 or SS316. Duplex steel how ever is not immune to these types of corrosion and especially at higher temperatures (>100 C) and under amine or chloride salts they can still suffer signif icant corrosion. In such cases other alloys like certain Ti grades and Hastelloy C276 may be better options. Duplex alloys can be divided into three main groups; lean duplex, 22%Cr duplex and 25%Cr superduplex, and even higher alloyed, hyperduplex. The alloying elements influence the corrosion resistance and this is expressed as PRE. PRE stands for Pitting Resistance Equivalent and is defined as: PRE = % Cr + 3.3 x % Mo + 16 x % N Duplex has a PRE (or PREN) < 40 (example 2205) Superduplex has a PRE betw een 40 – 45 (example 2507) Hyperduplex has a PRE > 45 (example 2707) More info can be found at these w ebsites: http://www.twi-global.com/technical-knowledge/job-knowledge/duplex-stainless-steel-part-1-105/ http://www.imoa.info/molybdenum-uses/molybdenum-grade-stainless-steels/duplex-stainless-steel.php http://www.smt.sandvik.com/en/products/tube-pipe-fittings-and-flanges/high-performance-materials/duplex-stainless-steel/sandvik-saf-2707-hd/

Calcium Naphthenate deposits in Refinery Reiners, Robert 4/8/2015

Hi all,

During the preparations of a f ield trialfor a naphthenate inhibitor in Norw ay, I had a discussion with a member of our team w ho had more experience w ith this f ield, he informed me that the customer also had problems w ith calcium naphthenate deposits in the refinery. Calcium Naphthenate deposits are formed at pH 6.2 or higher, in this pH range the naphthenic acids in the crude oil deprotonate, become strong surfactants and from "polymeric salts" w ith calcium and other bivalent ions. In this specif ic refinery they receive a crude that contains a lot of Naphthenic acids, during the process they wash the crude with will w ater that contains a lot of calcium. To prevent issues w ith chlorides in another part of the system they add KOH to the w ater as w ell. Just to sum things up: Naphthenic crude + high calcium brine + high pH = Calcium naphthenate deposits. At the ProMax group in Delden w e have an extensive product package for naphthenate inhibitors. For more information about this subject there is a module on naphthenates in the Compass system in the oilf ield chemicals section. Are any of you experienced w ith this kind of problems in the refinery? If there are more question about naphthenates in oil productin or in general, please don’t hesitate to contact me or post it in the Production Maximazation CORE. Robert Reiners SR. CHEMIST, NAPHTHENATES, PRODUCTION MAXIMIZATION EH NALCO Champion | An Ecolab Company Langestraat 169, 7491 AE, Delden, The Netherlands T +31 (0)74 377 1728 F +31 (0)74 377 1730 E [email protected]

Re:Calcium Naphthenate deposits in Refinery Thornthw aite, Philip 4/8/2015

Hi Robert,

In dow nstream w e have a great deal of experience in processing high TAN crudes in ref inery desalters and I have never come across Ca naphthenates being generated in a refinery environment at the desalter.

Generally, desalter w ash water is made up from relatively good sources of water such as overhead condensates or sour water stripper bottoms so the only Ca you w ill see in the brine is that w hich is w ashed out from the inorganic Ca salts. So the actual Ca levels in the desalter eff luent are signif icantly low er than w hat you would f ind in produced w aters from a w ell (orders of magnitude).

There are exceptions of course where some people do use surface water as part of their desalter w ash water but again Ca levels are never really that high otherw ise there is likely to be issues w ith inorganic scaling in the cold preheat exchangers.

With respect to pH, you can have high pH levels but also a lot depends on the buffering capacity of that water and the exces of alkalinity that may be present. There are exceptions of course when people use stripped sour water and that operation does not effectively strip ammonia leading to high pH levels. How ever, high pH w ater is best avoided w hen processing high TAN crudes due to the formation of pH stabilised emulsions.

I am aw are of the f ield and the refinery in question and I w ill contact you via e-mail to discuss

Re:Calcium Naphthenate deposits in Refinery Fearnside, Paul 4/8/2015

They add KOH to the desalter w ash water?

That doesn't make sense in light of the high Nap Acid crudes and how a high pH w ash water stabilizes emulsions.

Is that KOH perhaps added into the desalter crude oil instead of the desalter w ash water?

Low pH and normal PO4 control in waste heat boiler Vishwanath M, Balajee 4/8/2015

Hi,

My site has one of the w aste heat boilers located at H2 plant. Some times pH being depressed w ith PO4 maintained w ell. BW pH drops to the extend even below FW pH. BW pH control range is 9.5-10.2 w ith PO4 control btw 15-30 ppm but pH varies around 7 to 8.5 in tandem w ith PO4 around 17 to 20 ppm. During all these times, FW pH w as well controlled. Also at some instances, pH increases with PO4 varying low all of sudden. There is another w aste heat boiler sharing same FW is not facing such inverse correlation betw een pH & PO4.

We did some activity like increasing BD to remove any acidic contaminants and increase BT-2611 dosage but pH is not recovering. All of a sudden during some sample, pH varies above 9. I observed there is no much change in steam load during any of these period(+/-10% variation). Cl w ere measured around 0.2 ppm & SO4 at 1.3 ppm. Yet to measure for organic acids.

Can this be a phosphate acid formation due to any hide out event ? Please share your view s and experience on the possible root cause. These events has been happening since long time. Cyclic recovery in chemistry and upset situation w orries.

Treatment:

FW - N1805 & eliminox injection in DA

BW - BT-2611 injection in drum

Boiler pressure - 14 bar(200 psi)

Type - Waste heat from process

FW - Demin only(no condensate return)

Re:Low pH and normal PO4 control in waste heat boiler Hovorka, Eddy 4/9/2015

I've seen this happen is high purity systems that operate at much higher pressures (900 psig). Usually, sudden drop in the pH is due to a surface condenser leak. The hardness contamination allow s the magnesium to tie up the hydroxide ( pH drop) w hile the calcium goes after the phosphate.

What do your BFW hardness trends look like?

Re:Low pH and normal PO4 control in waste heat boiler GLOBAL\rtebbetts 4/9/2015

An interesting problem.

Ad Ed mentioned, it's unlikely that it is phosphate hideout causing your problem as your boiler pressuer is too low and w ith hideout, you w ould see the pH go up as the phosphate goes dow n and vice versa. It is a temperature/concentration issue and happens usually under high load conditions. You indicated that your steam load w as normal w ithin 10%. I've attached a couple of documents regarding phospahte hideout. Both are also in the CORE library.

I have a couple of questions:

1. You say you feed to the boiler drum. Do you have independent feed systems to each of the tw o WHB's on the BFW system?

2. Are you using drive w ater to push the BT-2611 into the drum or are you feeding the BT-2611 undiluted?

Impact of "color" portion of turbidity in cooling water systems Stamp, Jesse 3/26/2015

I understand that turbidity measurements are impacted by both TSS and color, and my customer gets periodic sw ings in the amount of "color" turbidity coming from their raw water... meaning that the TSS levels stay relatively steady but turbidity readings still increase. We see a definite increase in the demand of our 8102+ coagulant feed during this period because our chemistry also reacts w ith the color in the w ater... but the question w e have is w hat impact w ill more color have on a dow nstream cooling w ater system, and is there a w ay to quantify that impact? I know that color can be impacted by an elevated concentration of components (ie, a brow nish color with high iron). Iron seems like a pretty obvious issue, but w e w ill pick that up in our normal routine testing... w hat about other potential color components w e can't regularly test for or detect? Our customer is questioning the validity of using turbidity as a the primary metric for driving cooling w ater make-up w ater treatment.

Re:Impact of "color" portion of turbidity in cooling water systems GLOBAL\rtebbetts 4/10/2015

We need to f irst define "color" since this seems to have many folks confused. Color is a test that can be run on a w ater sample to provide a measurement of the amount of dissolved organic (and some inorganic) material that is present in a w ater sample. The color is imparted by decaying organic matter and is usually made up of tannins w hich is a component found in w ood, leaves, etc.

There are tw o measurements of color. The f irst is Apparent Color w hich is the color in an unfiltered sample as measured by a spectrophotometer. True color on the other hand is measured on a sample that has been f iltered through a 0.8 micron f ilter and pH adjusted. Color is not f ilterable at this level of f iltration and w ill pass through the f ilter.

I've had reps w ho insist that their samples are highly colored but w hen f iltered (or even when sitting for several hours) turn out very clear and uncolored. In these cases you are talking about mostly inorganic material that imparts a color to the w ater. Mississippi River w ater is often called highly colored but w hen left to settle w ill end up w ith very clear, colorless w ater. The color in this case is the color of the mud in the river.

I've also had samples w ith high levels of color (150 Alpha Units) w ith very low turbidity readings (< 1 NTU). This w ater looked like tea but w as clear with virtually no TSS.

Turbidity and TSS essentially measure the same thing, e.g. suspended solids but do so in a very different ways. So they are related but do not easily translate from one to the other. For instance, it is safe to say that a sample w ith a turbidity of 100 NTU has more TSS than a sample w ith a turbidity of 50 NTU but you can't say how much more from the turbidity reading.

What is the impact of color? Color w ill cycle up in the tow er just like everything else and w ill result in a very dark colored w ater. This dark color can affect the results of many of the spectrophotometer tests. It can also mask the endpoint of some of the titration tests. It can also degrade to the organic acids and consume some of your alkalinity. In a pH adjusted program, you probably w on't see this except under extreme conditions.

I did see one of these extreme cases where these organics, coming in w ith the w ater provided a good food source for bugs which eventually plugged the f ilm f ill to the point w here the tow er was near collapse. I don't expect that in your case but it has happened.

If the color is mostly suspended solids, then you can use a gross f ilter (like a w hatman 5) to pull out the TSS and clear up the w ater. If you are running the molybdovanadate test (w hich turns yellow), your results will be affected if you use the tow er water as a blank. You should use a DI blank instead.

You need to determine if your color is organic based color or if it's mostly TSS related color. If it's TSS, then gross f iltration may help you out. Get a few 0.8 micron f ilters and f ilter the w ater prior to doing a color test. This w ill tell you the true color in the w ater.

You can start running the UV254 test for color. There is a meter that is used for this test. I w ould not discontinue turbidity as it is an easy indicator of the amount of TSS in the w ater and does let us know of changes from day to day. You may be able to come up w ith a rough correlation of TSS to turbidity for your system but you w ill need to run a bunch of comparison tests to do so. Not sure if it's w orth your time.

Let me know if this gives you enough to satisfy your customer.

MgO and Mg(OH)2 Blockage in Boiler Tubes GLOBAL\dpickett 4/9/2015

My cusotmer has recently suffered severe leaks in their LP boiler's tubes. Upon inspection it w as found the bottom of the tubes near the front of the furnace (risers it looks like) w ere heavily choked with depoist. Upon analysis the chief culprit w as found to be MgO and Mg(OH)2.

My query regards the mechanism of the formation of this particular mineral scale in the place in w hich it w as found. The boiler w ater quality over time in this boiler has been w oeful, and to a large extent the cause of the deposit is a no brainer - commonly high total alkalinity exceeding 700mg/L as CaCO3, breathroughs from the RO plant brining in hardness, appalling Nexguard 22310 control and poor sulf ite control.

My query is how this boiler deposit came to be in this position in particular, and w hy the depsoit showed very very little calcium, and so much magnesium in particular, as if the the magnesium had been preferentially deposited instead of the calcium.

Hoping to receive advice and thoughts.

Thank you.

Darren Pickett

Re:MgO and Mg(OH)2 Blockage in Boiler Tubes Puchan, David 4/10/2015

The 22310 polymer w ill complex calcium and magnesium hardness but the complex formed w ith calcium has a high stability index than the magsesium.

In addition SiO2 and OH ion concentration in the boiler w ater will "compete" for the Mg ion. To keep the magnesium complexed a higher level of product is need. This dosage is based on the amount of Silica and OH in the boiler w ater. There are SiO2/OH charts in the 22310 CPP that show the 22310 dosage/ppm required.

If you underfeed the 22310 the magnesium generally w ill be the f irst of the hardness ions to precipitate. It w ill deposit out as serpentine (magnesium silicate hydroxide) or brucite (Mg(OH)2.

With your alkalinity being extremely high, and assuming your silica is low (being RO treated) Mg(OH)2 w ould be the expected deposit w ith underderfeed.

If you underfeed the product enough you w ill also get calcium depositing.

Note: Phosphate is a competing ion for the calcium. Phosphate chemistry is not added to an all polymer program.

You need to review your 22310 CPP SiO2/OH feed charts and your BFW Ca and Mg hardness levels.

With 700 ppm of alkalinity, poor 22310 control and poor hardness control, your site needs to produce a much high quality of BFW to continue using all polymer treatment. If they con't improve they should evaluate changing to a phosphate/polymer precipitation chemistry.

Nalco Deposit Monitor Bryant, Robert 4/10/2015

I am w orking on a project that I need an NDM for. Who can I talk to about f inding an NDM and instructions on how to run it?

We are w orking on a project one a once through cooling w ater treatment where we want to test to eff icacy of our scale inhibitor.

Re:Nalco Deposit Monitor GLOBAL\rtebbetts 4/10/2015

Robert

The NDM is not and w ill not be available for some time. Instead, you can use an RTM or real time monitor. This is a stand





-Doug Farrell

Re:Re:Re:Difficult to desalt crudes Farrell, Douglas 4/10/2015

Chris: I am follow ing up on your caustic injection comment. The refinery sent some spent caustic to the desalter via slop injection this w eek(unintentional).It completely put the brine off-spec and w e had green foam plumes coming out of the sew ers. How ever, the ovehead chloride numbers did indeed come dow n by about 50%.

Now I am curious as to w hat mechanism is going on w ith the caustic and salt contacting. We had much more emulsion. Is it a saponif ication thing w hich is giving us greater surfactancy? If we are neutralizing some acid or other... w hich acid and how does it interfere w ith our salt/water contacting?

Brad: Can w e duplicate this effect with a different demulsif ier?

-Doug

Cooling tower not cycling up due to low heat load Chouhan, Shesharam 3/26/2015

My customer has a very small cooling tow er with 3 cells. Volume is 130 m3. System runs at less than half the designed heat load. The difference between CWR and CWS is <2 C. System is not cycling up much. We are using 3DT104 ( BZT w ith THSP), 3DT184 ( Phosphate as anodic inhibitor) and 7384 (Zinc as cathodic inhibitor). We need to add soda ash to increase the alkalinity/ pH w ithin spec. BD is shut off. We give blow down once a w eek. Iron is increasing over a w eek. We have brought in Moly to increase corrosion inhibition for CS. It is quite challenging to operate a cooling tow er with very less heat load. Blow down is manual, w ithout any solenoid valve. Conductivity vary at very between 800 and 1000 uS/cm (Spec 800- 1200). System takes w eeks to reach a conductivity (12 uS/cm) to give blow down. Only reason we are giving blow down is to w ash away iron built in the CT. One of my colleague gave an suggestion to shut dow n one of the three fans of cooling tow er. I am not sure this is a practical w ay to cycle up the system. Any suggestion on this? Any guidance to manage BD for such cooling tow er?

Re:Cooling tower not cycling up due to low heat load Ferree, Scott 4/11/2015

Shesharam,

In my experience, trying to control blow down on towers with little to no heat load based on cycles is futile and risky from a corrosion prospective. In these situations, I use max HTI to set the blow down rate and live w ith low er cycles to ensure good program performance. All CW programs have a max - 96 hrs. is pretty typical.

Hope this helps.

Unstabilised naphta to CDU Moussif, Younes 4/10/2015

Presently the un-stabilized Naphtha from HDS (6 T/hr) is routed to CDU4 using the piping circuit already available at the CDU4 plot area. This naphtha enters the crude column w ith the Return Stream of the GO Bottom Pumparound Exchanger . Could this have corrosion impact in CDU OVHD (H2S are high is this stream) ? What analysis should i focus on ? w eak acid and Sulf ides analysis are enough ? is there any alarming values ? Could the f ilmer dosage increase help ? Thanks in advance for answers

Re:Re:Re:Unstabilised naphta to CDU Militello, Walter 4/11/2015

As Phil T. said, naphtha is rich of ammonia and H2S. The stabilization, indirectly, removes some of ammonia and H2S, so stabilized naphtha is more safe than unstabilized.

You can increase the f ilmer dosage, but take care of some conditions:

increase like 1 ppm and w atch the iron content on ovhd drum, no need to jump to double dosage

increase f ilmer slow ly giving time for the system to react (dosage increase and analytical check after 3-4 hours)

do not exceed by f ilmer. Having less than 1 ppm Iron is enough. No need to reach close to zero ppm values f ilmer, at high dosage, can be a strong emulsif ier. Sour w ater will be hazy and ovhd naphtha very w et = troubles for

CDU reflux and reformers/hydrotreaters

Re:Re:Re:Re:Unstabilised naphta to CDU Moussif, Younes 4/11/2015

Thanks Walter . i'll do

Low pH and normal PO4 control in waste heat boiler Vishwanath M, Balajee 4/8/2015

Hi,

My site has one of the w aste heat boilers located at H2 plant. Some times pH being depressed w ith PO4 maintained w ell. BW pH drops to the extend even below FW pH. BW pH control range is 9.5-10.2 w ith PO4 control btw 15-30 ppm but pH varies around 7 to 8.5 in tandem w ith PO4 around 17 to 20 ppm. During all these times, FW pH w as well controlled. Also at some instances, pH increases with PO4 varying low all of sudden. There is another w aste heat boiler sharing same FW is not facing such inverse correlation betw een pH & PO4.

We did some activity like increasing BD to remove any acidic contaminants and increase BT-2611 dosage but pH is not recovering. All of a sudden during some sample, pH varies above 9. I observed there is no much change in steam load during any of these period(+/-10% variation). Cl w ere measured around 0.2 ppm & SO4 at 1.3 ppm. Yet to measure for organic acids.

Can this be a phosphate acid formation due to any hide out event ? Please share your view s and experience on the possible root cause. These events has been happening since long time. Cyclic recovery in chemistry and upset situation w orries.

Treatment:

FW - N1805 & eliminox injection in DA

BW - BT-2611 injection in drum

Boiler pressure - 14 bar(200 psi)

Type - Waste heat from process

FW - Demin only(no condensate return)

Re:Re:Low pH and normal PO4 control in waste heat boiler Nunez, Teffany Joy 4/13/2015

Dear Sirs,

We have the same low pH issue in our 600psig Waste Heat Boilers in our ref inery.

Currently w e are running a residual phosphate program in three Waste Heat Boilers using N-22341. Our target pH is 10.3-10.8, OH-Alkalinity is 10-30ppm as CaCO3 and phosphate is 5-15ppm.

Below are our average data:

Waste Heat Boiler

Type Average

pH OH-Alkalinity, ppm

as CaCO3 Average

Phosphate, ppm SRU-5 Exchanger Type 8.59 0 11.6 SRU-4 Exchanger 8.66 0 10.8

FCC-1 Conventional (With Steam+Mud Drum)

8.30 0 12.1

Low OH Alkalinity in BOiler Water Ramirez Jr., Rolando 3/5/2015

We are encountering an unusual case in our new boilers in Petron w here the OH alkalinity is very low - which is (of course) manifesting on the boiler. We are lucky if w e get O-alkaliity of 10ppm on the boiler (at 50cycles) but usually it is only 6-8ppm. We are using polymer phosphate product (N22341) for these w aste heat boilers. Questions:

1- What are the adverse effect of too low alkalinity in boilers? 2- Do w e have Nalco internal treatment products that is a net alkalinity contributor (The polyphosphate in N22341 has a Na:PO4 ratio

of 1:1.7 making it a net alkalinity user)

Re:Re:Low OH Alkalinity in BOiler Water Nunez, Teffany Joy 4/14/2015

Hi Sir Armando.

Good day.

I am the site representative of the account Sir Rolando is talking about here.

Below is our typical BFW quality.

Parameter Value pH 8.50

Specific Conductivity, uS/cm 8.30 P-Alkalinity/M-Alkalinity, ppm as CaCO3 2.1/5.1

Total Hardness, ppm as CaCO3 varies from 0.025-0.220

Yes, w e are running a residual phosphate program using N22341 and our phosphate target is 5-15ppm. Our boiler w ater pH ranges from 8.2-9.2 only (vs. 10.3-10.8 target), and OH-ranges from 0-10ppm as CaCO3 (vs. 10-40ppm target).

We attempted to reduce blow down to raise pH and OH-Alkalinity but w e get high total iron. We get above 1.25-5.0ppm. Due to this w e suspended any reduction in blow down because we fear deposition of iron.

How much iron can w e tolerate for a 600psig w aste heat boiler? I read that for Fe2+, maximum acceptable is 2ppb x (cycles), how about total iron?

Right now , as a immediate solution, w e are looking at increasing our BFW pH to a minimum of 9 to help raise our boiler w ater pH. We w ill be increasing our neutralizing amine dosage to do this.

But even if w e increase amine, w e cannot increase our OH-alkalinity right?

You're further insights will be very helpful to us.

Thank you.

Teff

Re:Re:Low OH Alkalinity in BOiler Water Nunez, Teffany Joy 4/14/2015

Hi Ma'am.

Thank you for your insight. I am Teff and I am assigned to the account being referred to by Sir Rolando.

At the mean time, w e intend to increase amine injection to the BFW temporarily address the low pH. Can w e do that?

What is the recommended pH, OH-alkalinity target for 600psig w aste heat boilers running on Condensate+desalinated w ater BFW (quality indicated above)? Can you help us w ith some references, please?

Our current target is 10.3-10.8 for pH and 10-40ppm OH-Alkalinity (although w e don't achieve these). These targets are based on w hat worked for our fuel-oil f ired 600psig boilers w hich uses RO Permeate+Condensate BFW running on the same phosphate program.

Thank you Ma'am.

Teff

Red Internal Boiler Surfaces Dufour, Jerome 4/13/2015

Over the past 20 years, f ive 650 psig boilers have show n 2 differente internal surface colors: "wet" surfaces are red/brow n while "dry" surfaces show the expected black magnetite (see attached picture).

Looking for an explaination.

No internal corrosion or deposition issues. No oxygen pitting has been observed since start-up. Feedw ater (IX demin) copper and iron levels are less than 2 ppb. We are on a congruent pH/PO4 program w ith excellent control (5 - 15 ppm range).

Re:Red Internal Boiler Surfaces GLOBAL\rtebbetts 4/14/2015

Jerome

I have alw ays attirbuted the red color seen in the steam/mud drum as f lash corrosion that occurs when oxygen hits the w et surfaces when the drums are f irst opened. I've seen it over the last 28 years and it's alw ays been superficial and associated with the w et patches or areas that were wet when the drum manw ays were f irst open to atmosphere.





-Doug Farrell

Re:Re:Re:Re:Difficult to desalt crudes Claesen, Chris 4/15/2015

Doug, Sorry for the late reply, I am having a w eek Easter vacation. The effect of better chloride removal can be explained in several w ays. If the chloride is attached to a resin or a large organic molecule by acid base interaction NaOH being a stronger base can remove the chloride from the resin, replacing it w ith OH-. If cross-linked poly electrolytes are present (with Fe3+ or Al3+ as cross linkers) Na+ and OH- (from NaOH) can help break-up the crosslinking and make the poly electrolytes w ater soluble again. Chlorides trapped in the cross-linked polyelectrolite w ould also go to the w ater phase. Polyelectrolytes with AlCl3 or FeCl3 as crosslinkers are sometimes used upstream as gelling agents.

CDU overhead neutralizer change from EC1005A to EC1495A Haynes, Dennis 4/15/2015

There is a customer that operates their crude unit atmospheric overhead environment w ith approximately 100ppm chlorides. They have experienced corrosion in the overhead line and the implication is that it is due to amine salt formation. They are interested in sw itching to EC1495A.

The question is about experience in other previous applications; does anyone have a CDU atmospheric tow er overhead corrosion control application w here there was a switch from EC1005A or EC1000A to EC1495A w ith an environment that w ould have greater than 75 ppm chlorides in the condensate?

If so, can you share the improvements regarding corrosion rates or iron data?

Any experience that can be shared w ould be most appreciated.

Re:CDU overhead neutralizer change from EC1005A to EC1495A Fearnside, Paul 4/15/2015

Hi Dennis,

I have multi crude unit data that show s the total amount of OVHD w ater, per bbl of crude charge, can run from x up to 5x, for the same chloride ppm.

So is that 100 ppm Cl in this units OVHD w ater really that high?

I ask this because of my experience w ith OVHD vapor line corrosion occurring due to the neutralizer injection quill not w orking. Or in a few cases, not being there at all.

Re:CDU overhead neutralizer change from EC1005A to EC1495A Haynes, Dennis 4/15/2015

Paul,

They previously operated at about 20-40 ppm Cl successfully; years ago. With the increase to 100 ppm in recent times, they have experienced about 50 mpy corrosion in the overhead line and are planning repairs. I understand the point about various steam rates, but in this case due to the corrosion rate, the 100 ppm Cl in atmospheric crude tow er overhead aqueous condensate long term is diff icult.

But the basic question is regarding the search for experience where a refinery has changed from EC1005A to EC1495A and documented improvements.

There w as one report from AP, and I have found one from the US w here the switch was made due to cold tow er operations and the salt points as determined by Pathfinder. In that case, there w as also heat transfer loss in the overhead bundles due to salting that w as found to improve after the sw itch to EC1495A. But, I have not seen the data from the AP report, and I am hoping that there are more than just these tw o. There w as a third, but that overhead line w as C276 and not carbon steel, so w hile interesting, it is not a direct comparison.

Thanks for the feedback.

MBR Membrane Cleaning GLOBAL\tw heewen 4/13/2015

Anyone has experience in using surfactant such as sodium lauryl sulfate, or secondary alkane sulfonate (SAS) together with enzymes to carry out a Detergent cleaning process for the membrane? Would like to f ind out more on previous experience.

Re:Re:MBR Membrane Cleaning GLOBAL\tw heewen 4/16/2015

They are supplied specif ically for membrane cleaning

Mudwash Procedure Hennig, Matthew 4/15/2015

Hello,

My customer has a specif ic question about mudw ashing procedure. Their desalter has three zones, and each zone is mudw ashed for 20-30 minutes.

The w ater is pumped through the nozzles in each zone being mudw ashed, however the brine is f low ing through the eff luent headers in all three zones. Does anyone currently have a similar setup w here the brine is only drained through the zone that is being mudw ashed? Would this change in procedure potentially benefit the customer?

I should add that w e performed a mudw ash study in 2013 and determined that the current mudw ash procedures were sufficient. There has been no evidence that this has changed, the customer is just asking about the experience w e have as a company. Thanks!

Re:Mudwash Procedure Haynes, Dennis 4/16/2015

Mud w ashing sections in the desalters w as a design practice to minimize pumping and w ater use requirements for longer desalters. Many operate this w ay withall of the eff luent brine lines open during the mud w ashing of the individual sections. Only in cases of plugging of eff luent brine lines is the isolation of individual outlet lines recommended. If there w ere a few brine outlet lines that w ere observed to be colder that the others (indicating plugging), then closing off some of the other eff luent lines and forcing f low into that sections has resulted in clearing the lines in some refineries. Whe the mud w ash is turned on, some of the mud w ill kick up and slurry into the w ater phase; if some of the other sections brine outlet lines are closed, then it may result in that material depositing in other areas and not f lushing out of the vessel. My exerience has been that the sectional mud w ashing with all of the eff luent brine lines open is the standard practice.

Desalter Maximum Operating Temperature Recommendations GLOBAL\dpickett 4/16/2015

Dear team,

Currently, my customer's desalter is running at 153deC, and I raised a f lag on this, informing them their grid insulating bushings may be at risk of cracking. They repleid that their current max temp alarm limit for the dealter is 176degC, as the manufacturer has suggested 176degC as the maximum permissible operating temperature below which there is no fear of bushings failing. Interestingly, the previous limit w as 150degC, but it w as upped to reflect the manufacturer's recommendations.

I have been asked to attend a meeting to review the desalter's maximum recommended operating temperature, and w ish to attend armed w ith the right background on potential issues.

I am aw are of the simple ones: high temp = high w ater solublity in crude, so more goes overhead as grids become less able to coalsece due to drop in vltage and increase in current. But I am less au fait w ith the issues surrounding potential bushings faliures, and perahps there are other high temp risks w hich I haev not thoguht or read of.

Can you enlighten me?

Thank you.

Darren Pickett, Geelong, Australia

Re:Desalter Maximum Operating Temperature Recommendations Fearnside, Paul 4/16/2015

Adding Supplemental Copper Corrosion Inhibitor for Closed Cooling Water Sandogji, Sohail 4/27/2015

My customer has a HC leak that contain H2S; to closed loop cooling w ater (fresh water). NCM reading for Copper corrosion is high (9.9mpy). Also copper and admiralty coupons show bad corrosion.

it is agreed to add 3DT199 (TTA) as a supplemental copper corrosion inhibitor in addition to TRAC109.

The question is: can 3DT199 add upstream the already corroded admiralty exchangers, is it gonna improve or w orse the situation? or it should be added to the bulk w here it diluted to desired concentration before entering the exchangers.

Re:Adding Supplemental Copper Corrosion Inhibitor for Closed Cooling Water GLOBAL\rtebbetts 4/28/2015

The added azole is needed to protect the remainder of the yellow metal in the system (and the carbon steel from galvanic attack). It certainly w ill not f ix the exchanger that is leaking. I w ould get the additional azole in as fast as you can in w hatever spot you can use. As a closed system, the leaking material w ill eventually propagate to every part of the system as hopefully so w ill the azole. The leaking exchanger w ill have the highest concentration of the contaminant so that exchanger will be at the greatest risk of damage. Likely there is little you can do about that.

You need to feed enough azole to both protect the metal surfaces and to sequester the copper being released into the bulk w ater.

Is there any w ay to bleed some of the w ater out of the system until the leak can be f ixed? If the leak is big enough, you w ill likely see your surge tank level rising anyw ay so you need to try to get this material out of the system quickly if possible.

Watch your microbio too as you are putting food into the system.

Re:Re:Adding Supplemental Copper Corrosion Inhibitor for Closed Cooling Water GLOBAL\rtebbetts 4/28/2015

I w ould have some gluteraldehyde (H-550 or equivalent) ready as a non-oxidizing biocide.

Bacteria count in Water injection - AccuCount ATP method Souza, Susana 4/17/2015

Good morning all!

I w as doing a search on CORE over the paramethers of Injection Water. And found this very helpful "cheat-sheet" attached. But I have one question over this. The bacterial count takes in consideration the number of positive bottles on the dillution method. Do we have an update of this information considering the AccuCount ATP Method?

Can I consider that, if the amount of bacteria is in the "Green Zone", the w ater is ok for injecting "bacterial-w ise"?

Thanks in advance!

Best Regards!

Re:Bacteria count in Water injection - AccuCount ATP method Keller-Schultz, Carrie 4/29/2015

Susana,

I apologize for the delayed response. Attached you will find an AccuCount Test Kit information and other bulletins.

Regards,

Carrie Keller-Schultz

PRINCIPAL MICROBIOLOGIST– RD&E MICROBIOLOGY, ENERGY SERVICES

Documents

PROBLEMÁTICAS NALCO