No, John, I am not saying I am the King...I was quoting comedly from a Mel Brooks movie....sorry for trying to break up the seriousness and animosity of the tone...I am hereby out of this message board chat...satisfied?
Read our primer articles on Oil Analysis and Tribology
Frank
Couldn't get on-line yesterday, our IT personnel installed some new patches Wednesday nite - create 2 problems for everyone they fix. good way to ensure job security
As far as I know Kleentek or any other filtering system, electrostatic or physical doesn't remove soluble additives such as amine or ZDTP. However, if you have polar sludge, the polar alkyl amines will coat the sludge and thus be removed from the oil when the sludge is removed.
Trib. Trans. 47 pp.111-122, 2004 Yano,Watanabe, Miyazaki, Tsuchiza and Yamamoto, "Study on Sludge Formation during the Oxidation Process of Turbine Oils" ran 20 different turbine oils with dry TOST at 90 and 120C, pulled samples at set time intervals, ran RBOT and sludge (couldn't find pore size). Two oils had ZDTP. Rest phenol and/or amine based. Oil C had RBOT 350 hours, ZDTP, 1400 S and 59 ppm Zn. Oil F had 595 RBOT hours, 600 S and 59 ppm Zn. Authors stated ZDTP had poor sludge resistance - exceeding their sludge parameters when RBOT life was still 70%. They found sludge was primarily Zn sulfate. Oils C and F sound similar to yours and their research would help explain why Zn levels drop with usage - not sure why your sulfur went up. Would think alkyl amines would be attracted to Zn containing sludge.
I am still puzzled as to why ZDTP would be used in turbine oils but stand corrected.
Couldn't get on-line yesterday, our IT personnel installed some new patches Wednesday nite - create 2 problems for everyone they fix. good way to ensure job security
As far as I know Kleentek or any other filtering system, electrostatic or physical doesn't remove soluble additives such as amine or ZDTP. However, if you have polar sludge, the polar alkyl amines will coat the sludge and thus be removed from the oil when the sludge is removed.
Trib. Trans. 47 pp.111-122, 2004 Yano,Watanabe, Miyazaki, Tsuchiza and Yamamoto, "Study on Sludge Formation during the Oxidation Process of Turbine Oils" ran 20 different turbine oils with dry TOST at 90 and 120C, pulled samples at set time intervals, ran RBOT and sludge (couldn't find pore size). Two oils had ZDTP. Rest phenol and/or amine based. Oil C had RBOT 350 hours, ZDTP, 1400 S and 59 ppm Zn. Oil F had 595 RBOT hours, 600 S and 59 ppm Zn. Authors stated ZDTP had poor sludge resistance - exceeding their sludge parameters when RBOT life was still 70%. They found sludge was primarily Zn sulfate. Oils C and F sound similar to yours and their research would help explain why Zn levels drop with usage - not sure why your sulfur went up. Would think alkyl amines would be attracted to Zn containing sludge.
I am still puzzled as to why ZDTP would be used in turbine oils but stand corrected.
JonnyC
Basically during use, antioxidants in oil deplete, when antioxidants reach around 10 - 20% of original concentration, oxidation accelerates and carboxylic acids (AN)accumulate and oil basestock starts to polymerize (viscosity increase/varnish formation).
In combustion engines, the oils contain additives (BN)to neutralize combustion gases. Some high temperature hydraulic fluids also have additives to neutralize strong acids from additive decomposition - basically independent of oxidation. So BN is only useful in systems that create strong acids.
RULER is an on-ste instrument that primarily measures antioxidants - FTIR, LC and other laboratory methods also available.
AN/BN are usually done by titration on-site or in lab although RULER and FTIR non-titration methods also for AN/BN.
The time from when the antioxidants deplete until AN increases is application dependent. The higher the operating temperature, the shorter the time until AN exceeds limits. So for low temperature applications with big oil reservoirs, the time between antioxidant depletion and AN increase can be months/years. For higher temperature systems, the time between depletion and AN increase can be days.
As with any oil condition trending program, you have to develop some history to understand the degradation mechanisms so that you can determine which technique is of most value. RULER is predictive/can detect abnormal conditons early on (once antioxidant depletion rate established can extrapolate to predict future readings such as when the oil will break)while AN is reactive (can't predict when oil will break)has been around for a very long time and most applications have well established limits for safe usage although recent changes in basestocks and antioxidants are requiring that some established limits and capabilities of other techniques be revisited.
Basically during use, antioxidants in oil deplete, when antioxidants reach around 10 - 20% of original concentration, oxidation accelerates and carboxylic acids (AN)accumulate and oil basestock starts to polymerize (viscosity increase/varnish formation).
In combustion engines, the oils contain additives (BN)to neutralize combustion gases. Some high temperature hydraulic fluids also have additives to neutralize strong acids from additive decomposition - basically independent of oxidation. So BN is only useful in systems that create strong acids.
RULER is an on-ste instrument that primarily measures antioxidants - FTIR, LC and other laboratory methods also available.
AN/BN are usually done by titration on-site or in lab although RULER and FTIR non-titration methods also for AN/BN.
The time from when the antioxidants deplete until AN increases is application dependent. The higher the operating temperature, the shorter the time until AN exceeds limits. So for low temperature applications with big oil reservoirs, the time between antioxidant depletion and AN increase can be months/years. For higher temperature systems, the time between depletion and AN increase can be days.
As with any oil condition trending program, you have to develop some history to understand the degradation mechanisms so that you can determine which technique is of most value. RULER is predictive/can detect abnormal conditons early on (once antioxidant depletion rate established can extrapolate to predict future readings such as when the oil will break)while AN is reactive (can't predict when oil will break)has been around for a very long time and most applications have well established limits for safe usage although recent changes in basestocks and antioxidants are requiring that some established limits and capabilities of other techniques be revisited.
Bob K.
You're a star. Thank you very much for the info.
You're a star. Thank you very much for the info.
All
I have notice that the Kleentek oil cleaner has actually lowered the TAN from 0.31 to new oil condition of 0.24 has anyone an explanation for it?
Frank
I have notice that the Kleentek oil cleaner has actually lowered the TAN from 0.31 to new oil condition of 0.24 has anyone an explanation for it?
Frank
Various papers state that varnish contains carboxylic acids so varnish removal would be expected to lower TAN.
Just curious, what type of repeatability do you have on your TAN measurements?
Just curious, what type of repeatability do you have on your TAN measurements?
Hy John,
I`m looking for materials who talk about TOST, RPVOT, and what test is more representative. I used in my hydraulic system the Mobil DTE 26 but some friends think Tellus 68 is best. Can you help me?
Thank you!
I`m looking for materials who talk about TOST, RPVOT, and what test is more representative. I used in my hydraulic system the Mobil DTE 26 but some friends think Tellus 68 is best. Can you help me?
Thank you!
Dear all,
I need your help to interpret the results of a Foam Test ASTM D892. We detected foaming in the exciter bearings (its is visible in the sight glass). This was detected after a turbine trip due to high vibration in one of those bearings, however, we don’t know if the foaming started before or after the trip. I decided to immediately do an oil analysis for particles count, water content, viscosity etc and for this time (we normally don’t do this test) a foam test ASTM D892. The analysis results were:
Oil: Super Turbo Flow 32 (ISO 32) Petrocanada Turbine Oil.
ISO Cleanliness: 17/15/11 >4μ = 1016, >6μ = 200
Water KF PPM: 26
Wear Metals: Fe = 0 PPM, Ni = 0 PPM, Al = 0 PPM. Cu = 2 PPM
Contaminant Metals: Si = 0 PPM
Additive Metals: Zinc = 1 PPM, Phosphorous = 88 PPM
Viscosity at 40 oC: 35 CS
TAN: 0.03
Foam test ASTM D892
I (5 min blowing) 260 mL
I (after 10 min settling period) 0 mL
II (5 min blowing) 30 mL
II (after 10 min settling period) 0 mL
III (5 min blowing) 50 mL
III (after 10 min settling period) 0 mL
I was very happy to see the good numbers for particles, viscosity, water content etc. Since all of them would indicate that the foaming problem is not the oil but mechanical issues in the turbine bearings or lube system. However, in the case of the Foam test I am not so sure. The fact that after each settling period the foam count was zero is very positive but I did not expect to see such high value of foam forming in the first sequence (260 mL). I called the lab and to my big surprise and disappointment they look to be as clueless as my self about whether the 260 mL was too high or not. Under pressure they finally accepted to do some research and came back to me with an answer. I paste their answer below.
The outsource lab called me back with the reruns results they are still within the test’s repeatability. According to ASTM D 6224-09 Table 3 Warning Levels of In Service Oil Test. Foaming characteristics, Tendency >450 are a fail and <450 are a pass. As a testing Laboratory we recommend that you contact your Lubricate Distributor to address the oil’s forming characteristics. Please let me know if you have any questions.
Could you offer me some advice on this topic? Can I trust my lab advice? I am thinking in the possibility of changing the lab we use.
Thanks in advance for your help.
I need your help to interpret the results of a Foam Test ASTM D892. We detected foaming in the exciter bearings (its is visible in the sight glass). This was detected after a turbine trip due to high vibration in one of those bearings, however, we don’t know if the foaming started before or after the trip. I decided to immediately do an oil analysis for particles count, water content, viscosity etc and for this time (we normally don’t do this test) a foam test ASTM D892. The analysis results were:
Oil: Super Turbo Flow 32 (ISO 32) Petrocanada Turbine Oil.
ISO Cleanliness: 17/15/11 >4μ = 1016, >6μ = 200
Water KF PPM: 26
Wear Metals: Fe = 0 PPM, Ni = 0 PPM, Al = 0 PPM. Cu = 2 PPM
Contaminant Metals: Si = 0 PPM
Additive Metals: Zinc = 1 PPM, Phosphorous = 88 PPM
Viscosity at 40 oC: 35 CS
TAN: 0.03
Foam test ASTM D892
I (5 min blowing) 260 mL
I (after 10 min settling period) 0 mL
II (5 min blowing) 30 mL
II (after 10 min settling period) 0 mL
III (5 min blowing) 50 mL
III (after 10 min settling period) 0 mL
I was very happy to see the good numbers for particles, viscosity, water content etc. Since all of them would indicate that the foaming problem is not the oil but mechanical issues in the turbine bearings or lube system. However, in the case of the Foam test I am not so sure. The fact that after each settling period the foam count was zero is very positive but I did not expect to see such high value of foam forming in the first sequence (260 mL). I called the lab and to my big surprise and disappointment they look to be as clueless as my self about whether the 260 mL was too high or not. Under pressure they finally accepted to do some research and came back to me with an answer. I paste their answer below.
The outsource lab called me back with the reruns results they are still within the test’s repeatability. According to ASTM D 6224-09 Table 3 Warning Levels of In Service Oil Test. Foaming characteristics, Tendency >450 are a fail and <450 are a pass. As a testing Laboratory we recommend that you contact your Lubricate Distributor to address the oil’s forming characteristics. Please let me know if you have any questions.
Could you offer me some advice on this topic? Can I trust my lab advice? I am thinking in the possibility of changing the lab we use.
Thanks in advance for your help.
Dear Cristian,
Thanks a lot for your reply. It was of course very useful. In this case, no we have not added any oil to the turbine for a while. So the foaming cannot be becuase of new oil or additived being add. I also want to remark that our foaming problem is not that severe. There is foaming visible in the sight glass of the exciter bearings, which was not there before, but there is none in the oter bearings and in the oil reservoir. It is interesting what you mentioned about the Phosphorous because that is a recurrent problem in our oil analysis even in the new oil sample. I did not give to much importance to that because it was not affecting anithing at least that we know of. However, I will contact our oil supplier and ask them about this. Thanks again.
Thanks a lot for your reply. It was of course very useful. In this case, no we have not added any oil to the turbine for a while. So the foaming cannot be becuase of new oil or additived being add. I also want to remark that our foaming problem is not that severe. There is foaming visible in the sight glass of the exciter bearings, which was not there before, but there is none in the oter bearings and in the oil reservoir. It is interesting what you mentioned about the Phosphorous because that is a recurrent problem in our oil analysis even in the new oil sample. I did not give to much importance to that because it was not affecting anithing at least that we know of. However, I will contact our oil supplier and ask them about this. Thanks again.
I'm fighting a foaming issue now.
My oil is NOT cross contaminated. We're a nuclear unit, we have VERY good records. Plus, I am running every test under the sun on it.
All of the standard tests come back acceptable.
Yet, I have foam. Not to the level of seeing vibration issues, but it's there.
I'd be interested in what type of oil you are running. Have you recently changed to a group II base stock? Maybe without even knowing it?
I'm seeing very, very slight foam levels in other reservoirs too. Mostly running R&O oils.
My oil is NOT cross contaminated. We're a nuclear unit, we have VERY good records. Plus, I am running every test under the sun on it.
All of the standard tests come back acceptable.
Yet, I have foam. Not to the level of seeing vibration issues, but it's there.
I'd be interested in what type of oil you are running. Have you recently changed to a group II base stock? Maybe without even knowing it?
I'm seeing very, very slight foam levels in other reservoirs too. Mostly running R&O oils.
