PUMP MAGAZINE: Questions and Answers
(111 - 120)
Question #111:
James, - do you have any vibration guidelines for Progressive Cavity
pumps? Our pumps are used in the water treatment plant setting to
transfer lime sludge.
Laith Hintz
Design Engineer
Advanced Engineering and Environmental Services, Inc.
Bismarck, ND
Laith,
Although we have done considerable analysis on machinery at water treatment
plants through the years, we do not have any specific vibration guidelines for
Progressive Cavity pumps. We have evaluated a large array of pumps at both
water treatment and wastewater management facilities.
I am not familiar with where you might find such guidelines, but I can refer
you to someone who has considerable expertise with a wide cross section of pump
designs. His name is
James E. Berry, P.E.
President
Technical Associates of
Dr. Nelik comments:
Laith, - I am not familiar with
vibration guidelines specifically for progressing cavity pumps.
There is a lot published and available on centrifugal pumps,
including single stage, multistage, vertical, etc. From the rotary types, very
little is published, both in open literature, as well as even via internal
guidelines by the manufacturers. The names of some of the leading PC pump
manufacturers are noted in your email, and, of course, there are others.
Neither Hydraulic Institute, nor API, publish vibration guidelines for PC
pumps, although they do cover centrifugal types very well.
In the absence of such data, the best
advice I can provide is probably the same as implied by James, which they use
extensively in their work as he noted. Such general guidelines are defined by
various ISO spec, such as ISO 2372-1974, ISO 10816-3, ISO 2372-1974, and some
others. Below is an example of one:
Keep in mind that two things effect
vibrations in PC pumps, in the opposite ways: first, they are inheritably
unbalanced, due to a so called “nutational” motion of the eccentric rotor in
relation to a stator – such motion of the eccentric mass produces undesirable
force; but secondly (fortunately) - they generally run at low speed, typically
below 300-400 rpm. I have found that when a PC pump operates above
approximately 400-500 rpm, vibration becomes a concern and readily “feelable”.
It depends, of course, also on a pump size, length, number of stages, energy
level, conditions of the support (which is very important for a PC pump, or for
any other type for that matter), etc. - but 500 rpm seems to work well for me,
as a rough guideline.
I must say that, generally,
vibration-based troubleshooting is rarely done for PC pumps, although it is a
vastly acceptable, known and important way of troubleshooting root causes of
other pump types, especially centrifugal. Troubleshooting of PC pumps is
typically more pragmatic and rudimental. One of the reasons is perhaps that
there is relatively fewer PC pumps in the filed, as compared to a much wider
population of centrifugal pumps. Vibration analysis of centrifugal pumps can
help reveal and detect early issues with bearings headed to failure, unbalance,
misalignment, blade pass, and numerous other issues. The issues with PC pumps
tend to be less involved (less sophisticated perhaps a somewhat bolder
statement), as far as application of methods of detection of internal faults,
and thus vibration analysis did not enter the arena of PC world as wide as it
did centrifugals. PC failures are more likely to be caused by dry running,
stator chunk-out, overpressure due to bad (or sometimes absent!) relief valve,
wear, and shear-off of the joint, etc. Rarely, the repeated cause of a failures,
for PC pumps, are bearings, because other issues, as noted, usually show up
first - while, again, it is a very common issue with centrifugals.
I hope this helps a little, and sheds
some light on at least reasons why this subject is relatively obscure, although
it still leaves your question open. It is an interesting subject, and I am
forwarding it to the Editor of Pumps & Systems magazine Mike Riley, to
consider publishing, as a discussion, and to ask our reader to comment,
hopefully uncovering more additional sources, standards or published
recommendations, as well as personal insights. In my own opinion, as a rule of
thumb, given a lack of a specific guideline, I would use a 50% higher limit on
PC pumps vibration acceptance level, as compared to centrifugal pumps. For
example, if a centrifugal pump, based on its standard, results in, say, 0.2
in/sec velocity limit, I would use a 0.3 in/sec limit on a PC pump of similar
horsepowers, and limit speeds to under 500 RPM. PC pumps would run rarely at speeds
above 500 rpm, although they do occasionally, and I would then treat vibration
limit on those as a special case. Even more importantly, and perhaps more
useful, would be not the absolute level of vibrations, but trending. If a PC
pump vibrates at 0.4 in/sec (a number generally considered too high for
centrifugals), but pumps well and have been working fine for many years, taking
periodic (overall vibration) trends may be all you need. When such trend begin
to show signs of increase, it could be an indication of a problem beginning to
develop. To avoid catastrophic failure, it might then be a good idea to
schedule an overhaul or a repair. But if failures are frequent, you would
likely find simpler explanation, even without a vibration analysis. For example,
excessive wear may indicate incorrect (too tight interference between the rotor
and stator. Too frequent “flaking” of the rotor may point out on improper
coated rotor. Rubber chunk-out may be caused by dry running. These reasons are
typically listed in troubleshooting guidelines by the manufacturers, and if
these guidelines are followed, plus common sense, much trouble with PC pumps in
field can be avoided.
Best
regards,
Lev Nelik,
Ph.D., P.E., APICS
President /
Technical Director
Pumping
Machinery, LLC
Note from the original
question by Laith Hintz:
Thank you for the
additional insight on PC pumps. My original question on vibration guidelines
for PC pumps stemmed from a general pump specification for a project that
required vibration analysis for all pumps covered in that section (mainly
centrifugal). From your discussion, it sounds like requiring
vibration analysis on PC pumps after installation may be useful but has not
become common practice. Thank you again for taking the time to
answer my question.
Laith
Additional
input from Todd Brown, Moyno Progressing Cavity Pumps company:
Moyno
does not have any published guidelines with respect to vibration values for our
Progressive Cavity pumps. Because of its inherent eccentric nature, the
pump has natural movement, specifically as you near the suction housing and
stator. This situation coupled with the vast array of mounting
arrangements, platforms and foundations, makes it very difficult to come up
with a standard. I know of no standard in the industry for Progressing
Cavity pumps with respect to vibrations. When asked, Moyno will perform
vibration analysis on specific units on the bearing (pump, gearbox and motor)
locations only. I know of no instances where we have failed to meet this
assuming the entire unit was rigidly mounted (i.e. not overhung).
Todd
Brown
Moyno
Pumps
Question #112: Hello,
I am in
Thanks, - if you can help me out or direct
me to information about cold weather pumping.
Regards,
Canada Water, Inc.
Pump Magazine responds: we are forwarding John’s question to our readers, particularly to attention
of those at pipelines and terminals. We would appreciate if you could take a
moment offering your opinion and ideas, and perhaps share your methods of
protecting pipelines from freezing in similar situations.
Let us know. Your
input is appreciated in advance.
Lev Nelik
Editor, Pump
Magazine On-Line
Blair Northen, Kinder Morgan
Pipelines, Atlanta, Georgia comments:
We transport mainly
petroleum products and don't normally have any water. I would suggest keeping
the water flowing where possible and using insulation / burial of
lines and heat strips on equipment that sees static conditions.
Otherwise - drain the water
out!?
My climate here typically does
not experience temperatures below 0 deg. F and not for extended periods.
I can not give you an
actual flow rate that will work but for the most part if the water is moving it
is above the freezing temperature. Any insulation (soil, hay,
foam, even snow in really cold temps) will help keep it above freezing.
Typically heat trace is not practical. We have many instances where non
insulated pipes are exposed directly to cold temps (particularly bridge
crossings) and freezing has not been an issue for us. A neighboring water
utility has installed a small blow off on a pipe hanging from a bridge crossing
a stream. This “leak” occurs all winter and I am not aware of any
freezing issues. In some older cities in Europe,
In my water treatment
plant, things are different. The water flows by gravity and flows very
slowly. Where I have valves in open outdoor tanks, I need to keep the
valves submerged under water all winter. I learned the hard way what it
takes to thaw out a 48 inch butterfly valve that is frozen closed with water
behind it. Keeping the valves submerged reduces the useable capacity but
it is necessary to have any use of the tank. For my indoor filter
operations, the valves are wrapped with heat trace for the winter, it is
inefficient and expensive but it works. Once the tanks have frozen over,
we need to keep the ice from pulling on the wires for the pumps; this is
typically done with sledge hammers and manual labor. I wanted to try a
home made bubble system this winter but did not get around to it (maybe next
year). We also lower the water level under the ice because sagging ice is
not nearly as destructive as heaving ice.
If you have any others
questions or experiences you want to share, give me a call. If nothing
else we can complain about the water operators in
Readers Feedback:
Thanks for getting me contacted with your
network. Just for your info, we have been successfully running three Godwin
pumps continuously as the inflow varies. The temperature was – (minus!) 42 with
a 20 Km/hr breeze for a few days on site. It took some effort to combat
freezing of the 1000M 12” steel pipeline. If anyone else ever asks about cold
weather pumping, feel free to send them to me. At www.canadiandewatering.com
there is a lot of experience and expertise of fluid handling in extreme
conditions.
Regards,
John Carlsen
Question #112: Good day Dr.
Let me introduce briefly. I'm a sales guy working out of
As you may know we are fire fighting pumps manufacturers, and lately we are
working on a project for fire pumps (diesel driven) that are required to be
compliant to API 610. I'm not sure on the content of the norm but I was told
that is applying to the process/chemical/petrolchemical pumps only.
Do you have any comment on why a fire pump should be API 610 compliant?
Looking forward to read from you.
Thanking you in advance for the time you'll be dedicating.
Best Regards,
Ing. Benvenuti Andrea
Peerless Pump Company
Torino -
Dr.
Mr. Andrea, - as you know,
fire pumps are typically split case or vertical turbine pump types, although
other types are applied occasionally as well. They do not fall under a category
of API-610, although are governed by a fire pumps spec, which is more stringent
as compared to a similar pump not intended for fire duty. API-610 design is
very tough and stringent, and applies, as names implies, to petroleum industry,
such as refineries and other petroleum operations. Some other industries,
however, have adopted API-610, to either complete, or partial, intent,
recognizing the fact that pumps designed to API-610 specification are much more
robust and reliable for tough applications. Example would be power generation
industry, which invokes API-610, at least partially, for the boiler feed pumps
– hot, high speed, demanding machine, with utmost priority to reliability.
API-610 covers a variety of technical issues, such as shaft deflections, nozzle
loads, etc. etc., and thus not every pump manufacturer can comply.
But what sometimes happens is this. A typical refinery consists of two types of
equipment – battery limits (where oil is actually being refined), and
supporting equipment. A pump in the basement of the cafeteria, for example,
supplying HVAC needs there, may never see situations as tough and critical as
its brethren a mile away, in the battery limit area. But, a purchasing
department may require a supplier to comply with the API spec, because the
pumps are technically slated to the refinery. Fire pumps may come under similar
considerations.
Thus, each application needs to be reviewed on its merit.
I am copying your note to Peerless folks in
I hope this helps. Feel free if any questions. I might be in
Regards,
Lev
President / Technical Director
Pumping Machinery, LLC
Andrew Warrington, Vice
President of Sales, Peerless Pump Company, comments:
Andrea - Well I am honored to be considered to
"look Italian" by Dr
We often meet this problem. In fact of course, API and NFPA rules are often
even contradictory in many ways (e.g. materials where NFPA or at least UL or FM
dictate a cast iron case and bronze impeller where most API specs would call for
at least cast steel I would think). So it's a non sequitur to say I would like
an FM/ UL approve API fire pump. Many try and we do include some of the API
style requirements in our fire pumps but we (and I don't think anyone else) has
ever made a fully compliant API UL/ FM listed fire pump.
When I was with SIHI for example we supplied many of their specialty pumps to
refineries where the traditional API guys made the centrifugal pumps and for
some reason they wanted a vacuum pump or a side channel pump or a fuel transfer
pump. We would always fight the exception battle and supply something that was
perfectly good for the application but did not fully comply with API (which by
the way changes like the wind with all the new editions anyway). Usually we could
win the battle but the oil companies were always reluctant as they were so used
to getting API pumps.
Another example is when I was with SIHI again we sold ISO standard
Now in Peerless we meet it all the time and the solution is to ask why they
need this or that feature. Our fire pumps built to our standard design are the
best in the business at doing what they do - putting fires out. They are pretty
much a time tested good design for that. They don't do too well supplying
cracking reactors or pumping hot crude or finished petroleum fractions. Then
again, that's someone else's business.
Anyway, I am off to put on my Armani suit and go out on the town.
Ciao,
Andrew Warrington
Vice President of Sales, Peerless Pump Company,
Tel
www.peerlesspump.com
It looks like Andrea got
the help he was looking for, as he notes:
Thank you for your explanations and will certainly be happy to
take you to one of our best restaurants!!
Best Regards,
Ing. Benvenuti Andrea
Question #113: Dear Dr. Pump,
It is being told that the vibration levels specified
in the 9th Edition ( V(filtered) = 0.67 X V(unfiltered) ) is by
error and 11th edition is in the process of correcting the mistake.
Is it so? Please elaborate.
K.Chakravarthi
Engineer, Export Services.
Kuwait Oil Company
Answer:
Regarding the vibration levels being "wrong"
or different in API 610, 9th edition than they will be in the next edition,
here is the logic:
As published in the 9th edition: vf
< 0.67 vu, for discrete frequencies
To be published in the 11th edition: vf < 2.0
mm/s RMS or 0.08 in/s RMS
Obviously 2.0 mm/s and 0.08 in/s are 0.67 x the
overall values of 3.0 mm/s and 0.12 in/s, so there is no change in the values
between what is now published in the 9th edition and what WILL be published in
the 11th edition. However, there is a significant difference when one
misinterprets what was meant by the simple vf < 0.67 vu.
What has happened through some reported
misinterpretations is this: the purchaser of equipment interpreted API 610 as
meaning that the filtered vibration should be 0.67 x whatever actual overall
vibration level was measured. This meant that, with a very well
manufactured pump that exhibited a very low overall vibration level,
it could never pass the filtered values of 0.67 x the low measured overall
level. This was not the intention of API 610. The intention is that
the LIMIT for filtered vibration would be 0.67 x the limit for overall
vibration. The table in API 610 is a table of limits. Because of
the misinterpretation discovered, it was decided to revert to actual numbers
for filtered vibration limits in the next edition.
This, by the way, is NOT the case for shaft displacement measurements and those
figures have not been changed from the 9th edition.
By the way: the vibration limits published in API 610
are meant for performance testing in the vendor's shop, but they happen to work
quite well as field vibration limits as well.
In addition to the above, I rarely
rely on exact value as specified by spec, as in my experience the field
situation differs considerable from theoretical. Filtered, unfiltered overall,
rms, peak-to-peak, zero-to-peak, etc. can be very confusing to most folks at
the plants, who do not use vibrations as the sole way of making a living.
Normally, these days, reliability engineers are the same ones responsible for
machinery reliability, mechanical, structural, vibrations, hydraulics, and
other issues. Years ago, these topics used to be sliced around more people, but
today, with plant’ personnel reduction, much fewer people carry more burden.
Perhaps partly as a result of that, a more pragmatic (some exceptions are noted
further below) field approach is to read vibrations by magnetic pick up probes
(accelerometers) and convert the signal automatically by the instrument into
velocity (RMS) values. While there should, theoretically, be differences on the
allowables, depending on energy level, speed, etc., some general guidelines, in
my view, are sufficient, and perhaps are as:
- A. under 0.10 in/sec – fully acceptable
- B. between 0.10 and 0.25 in/sec – normal
- C. between 0.25 – 0.30 in/sec – cause of concern
and more detailed analysis, but not a shut down
- D. over 0.30 in/sec to 0.40 in/sec – to be
considered as corrected during upcoming outage
- E. over 0.40 in/sec – potential failure could be
imminent
Or, for a more formal guidance you
can refer to ISO specification:
These are overall. Individual
harmonics (FFT) should be analyzed only when troubleshooting, such as over case
(C), but below it I would not waste time. Only in such cases, a more involved
study is invoked, and typically done by vibration specialists. At that time,
preferences between velocity or acceleration, amplitude, time domain versus
frequency domain, begin to emerge, etc., - but all within the realm of
relatively rare, albeit important, group of situations. Perhaps 95% of field
troubles do not invoke that level of detail, and, while remaining extremely
interesting and fascinating, remains under the umbrella of somewhat academic
mould.
Many critical machinery units have
installed proximity probes, which read amplitudes, rather then velocity, picked
up at the journals of the rotating shafts. These have more elaborate approach,
taking into account electric run-out, etc., and fed into automatic plant
system, which could trigger machinery shut-down in case of a problem, when
vibration accedes a set value. Examples of such would be boiler feed pumps,
and, true to your question, pumps at the refineries, for which, in fact, the
API-610 spec was written originally for. But even for those, a debate over the
exact value of the set points could questioned as important, as most
practitioners are aware of what constitutes high, moderate, or low vibration.
As time changes, more elaborate
schemes come out, but many of these are products of people continue painting
the same painting over, never satisfied with what already exists. In
vibrations, good data have been in existence for years, and charts, graphs and
calculations are published by Vibration Institute, and other practical
organizations. These reflect years of experience, and should be handled by
vibration professionals. I doubt that a pump vibration is any more or less
damaging to a pump in 1950 as it would be in 2007, and constant change of the
acceptance criteria is, in my view, is a waste of time.
However, your question is a good one,
and I thank you for that, and copying a President of a local chapter of
Vibration Institute for in formation. John Visotsky will be speaking on the
subject of vibration at the upcoming PumpTec-2007 Conference in
Lev
President / Technical Director
Pumping Machinery, LLC
Question #114:
My application is for a typical sanitary
sewer lift station and force main design for small to mid size collection
systems, say 6-inch to 16-inch force mains.
Quite often, our parameters require that the
design pumps over a
The question is: what is the latest trend
for the best (and safest-raw sewer) mechanism to use to break the vacuum at the
Russ Brink, P.E.
Engineering
Management Incorporated
Lawrenceville, GA
We
have asked Chris Staud, a Senior Engineer with a City of
Russ:
The City of
City personal retire and don't pass along where
some of these pits are, or developers develop the land and change the entire
look of what use to be a field, or your maintenance road disappears due to lack
of use. Or, my personal favorite occurs when a developer buries your pit under
several feet of fill. It is a challenge to find these manholes with their
air-release valves especially if you don't know if you have the as-built
drawings. Opening the pits sometime
create some interesting problems when you discover that a den of snakes have
taken up residence in your air-vacuum release pit. Our people learn to move fast
when confronted with a den of snakes.
I personally prefer
Hope this helps.
Sincerely
Chris Staud, PE
City of
Question #115:
Dear Pump Magazine,
I have a question regarding the specific gravity limitation of a
pumping fluid: Liquefied Petroleum Gas (LPG) - primarily mixture of propane and
butane which is received from refinery FCC (Fluidized catalytic Cracker) unit.
We have two-stage pumping:
1st stage:
Pump is a vertical centrifugal. Fluid is received in suction piping
directly from LPG sphere. However, the impellers of the 3 stage pump are at 20
feet below from ground level in a canned structure to create the required
NPSHA.
Suction Pressure in the piping: 50 PSIG (before entering the
underground can)
Discharge pressure: 284 PSI
Rated Flow: 950 GPM
2nd stage:
Pump is horizontal centrifugal pump. It receives same 950 gpm from
discharge of the first stage(above) and discharges to underground cross country
pipeline. We normally pump LPG in the specific gravity range of 0.535-0.545 at
ambient 86 °F.
We recently got LPG from the refinery with specific gravity in the
range of 0.345-0.485 for 5-6 hours. We do not have alarm/tripping of pumps
right now on receiving low density of LPG. Hence, we felt the need to
incorporate tripping of pumps on receiving low density since this is an issue
having direct relation to the quality of product we are receiving from the
supplier. Such a qualitative change may not be acceptable to the customer to
whom we are supplying the LPG through cross country pipeline (1250 KM).
I would like to know if such a low density product is harmful for
the pump operation, especially for the first stage pumping since we are having
narrow NPSHA-NPSHR margin in first stage pumping. Also, if we receive low SG
LPG, it indicates that the propane quantity may be higher than normal (and
butane lower than normal) which results in higher vapor pressure since propane
has higher vapor pressure as compared to butane.
The pump O&M manual indicates the SG range as 0.515-0.585 but
does not write anything explicitly about possible problem in encountering low
sp.gr. fluid. Please advice at the earliest.
Yours truly,
Somak Gandhi
GAIL Ltd.,
Answer:
This is a multifaceted question. One involves low NPSH
margin, which usually (not always) is not a problem in practice with
hydrocarbons, because of the vapor-volume relationship. The second relates
specifically to low specific gravity and possible effects on the pumps.
The API standards have always suggested larger running clearances for specific
gravities below 0.7 because of loss of inherent lubricity and the consequent
danger of wear part damage. With good running material combinations, the
lower specific gravity should not be a problem, especially in the situation
described where the pumps were continuously running. As a safeguard in
these applications, it is beneficial to recommend superior running materials,
such as graphite products (Graphalloy as an example) or other suitable
nonmetals for stationary running parts (PEEK comes to mind as another
option). With this protection, specific gravity excursions are a
non-issue.
I have also discussed your question with engineers I
know at Colonial Pipeline company in US Georgia, from the viewpoint of the pump
operators. Pipelines move gasoline, oil
and other products thru their pipelines, and utilize high energy pumps,
including multistage pumps. Such pumps have long rotors, supported at the ends
by journal oil lubricated bearings, and a center bushing (obviously product
lubricated) to assist rotor support. Contact of the rotor to rings and bushings
is always an issue, especially for low lubricity fluids, where fluid film in
the clearances is weak and offers little support. Such ability to support the
rotor in clearances is often characterized by a so-called Lomakin effect, i.e.
ability of a bushing (or a wear ring) to develop sufficient fluid film to
provide dampening and stiffening forces supporting the rotor from contacting
stationary part. In such cases, occasional rotor to bushings contact takes place,
a known problem and a challenge for the pipeliners. Self-lubricated materials,
such as Grahpalloy, for example, provide significant benefit as a solution, to
prevent catastrophic failures.
Lev
Pumping Machinery, LLC
Question #116:
Does anyone know what C factor should be
used for lay flat and rigid hose, or know where I can find that information? We are in the pump rental business and we
need to calculate head loss in order to select the right pump for our customers.
We have the option of using HDPE pipe, Quick Disconnect steel pipe (Bauer),
Aluminum Victaulic and hose (rigid suction hose and layflat). The rigid hose
has either nitrile or poly liner so the C factor is known. It’s the layflat
hose that is unknown. There are a lot of commercially available TDH programs
out there and I have researched many. I find them to be overly complicated for
our needs and too expensive, so I wrote my own program. It works fine for what
we need it for and the Hazen Williams formula is accurate enough for our
purposes. Going Darcy-Weisback increases the complexity of the programming and
I have neither the time, ability or need to go that route. I was hoping that
someone would have some idea, any idea of a number that would work for layflat
hose, 80, 100, 120, whatever. The key is that we don’t have to be dead-on
accurate for our type of business. If you can suggest a number I would be more
than happy to use it because I have had no luck to this point finding anything.
Pat Black
Engineering Manager
BakerCorp
562-342-7947
Answer:
Pat,
DFS FlowNet by ABZ had a good
database on hoses and tubing but does not use C Factors. Some people found
0.000075 feet absolute roughness works good for calcs for new general purpose hose
up to 4” in diameter. I would probably use 0.0001 feet or even higher to be
safe for new stuff and higher if fouled by grit or slime. I asked some of
my colleagues also, and they did not find a value for a flat hose. Some other
references do not state a roughness for hose. What did a hose manufacturer say?
Unfortunately, some of them make good hoses, my often do not provide a
roughness factor, but it is worth a call. I believe that hose is similar to
HDPE pipe; Nipak (a Driscopipe distributor in WV) recommended to use
C=150 for HDPE. Vinyl hose would be similar to Polyethylene pipe and C factor
may come close to reality on small pipes. Seelye
book lists the following on page 22-03:
For the Hazen-Williams Formula, for Fire Hose:
Extremely smooth: C= 143
Robber Lined: C= 125-140
Mill Hose: C= 100-120
Unlined Linen Hose C= 85-95
Please note that this info is taken from a book
that was published in 1960 (originally 1945).
Elwyn Seelye was a Civil Engineer with over 35 years of experience when
he edited this book. I do not know if PVC hoses were available at that time and
believe that PVC would approach the C used by the HDPE manufacturers, C=150.
Are you evaluating an old
installation, or are you considering a brand new design? If an old one, I can
recommend some ways to assess the C-factor in a somewhat round-about, but
pragmatic, way. You could easily check these values by installing two pressure
gauges on a flat water-hose and just calculating the pressure loss this
way. You may need a “5 gallon bucket” to check the flow rates etc.
Regards,
Lev Nelik, Ph.D., P.E., APICS
President / Technical Director
Pumping Machinery, LLC
Question #117:
Dr. Pump,
Please advise the source of Asarcon-520 material.
Thanks,
Bill Bogdan
Crane Aerospace & Electronics
Our contributing affiliate, Luis Rizo
comments:
Hi Bill,
Asarcon 520
was a lead impregnated bronze used for sleeve bearing in horizontal split
pumps. I have not seen it in use, since my days at
Years later, while I worked for Exxon as
a Rotating equipment engineer we began using graphite impregnated carbon (Grapholloy) (www.graphalloy.com/html/products.html?gclid=CK2M_Iuco5UCFQSsGgodwkGSkQ) sleeve bearing for pumps and Thorlon
for the slower running centrifuges. We retrofitted some old packing pumps
in hot oil services to mechanical seals. These pumps, by design,
depended on the packing for shaft support. In order to support the
shaft and allow the mechanical seal to live, I installed steel encased
Grapholloy encase in a steel sleeve with spiral grooves between the bearing
house and the old packing box. This eliminated the run out and allowed
for the seals to run true and not leak. The Graphalloy material can be
used in plain stock or encased in a steel sleeve to add strength, depending on
need.
In either case you must calculate
the loads to assure that the bearing is appropriately designed and support
the shaft loads and that it is not on a node in the flexural curve.
I hope this helps,
Good Luck!
Luis F. Rizo, PE
GE
For additional information on similar
materials, also review www.pump-magazine.com/pump_magazine/q&a/faq1_20/faq1_20.htm
(question #15)
Question #118:
Dear sir,
I want to design the pumps handling LPG
(liquefied petroleum gas).
The tank outlet from the top, not from the tank
bottom.
My question is how to calculate the NPSHa
for LPG pumps. I have a closed vessel with 12 bar pressure. Vapor and liquid at
the vapor space are equalized. Liquid level is above the pump suction
centerline.
Is my calculation correct? Please go thru
sketch and help me to calculate NPSHA.
Viswanathan Damodaran
Exterran
First, convert
everything into same units, say meters. If there is pressure gage on top of the
tank, it would show 12 barg as 265.5 meters, as shown by calculations, given
the specific gravity of LPG as 0.50 (502.9/1000). At the pump inlet, pressure
is somewhat greater – by the level of the full tank, less the 1 m rise from the
floor, so it is 268 meters, assuming hydraulic losses in the pipe around 0.2
meters (you can calculate these for better accuracy).
The 10.19 barg
(11.19 bar(absolute)) would equal to 228 meters, and thus the NPSHA = 268-228 =
40 meters. The pump you would select would need to have NPSHR of less then this
NPSHA, - perhaps around 35 meters or so. You also may want to double check the
units of pressure, - are they in gage or absolute units? – or perhaps a
mix (for example, I suspect your 10.19 bar is in absolute, not
the gage units I used)? If not, convert to the same (consistent)
units, and recalculate, following the sequence I outlined for you.
Note that in order
for pressure in the tank to be 12 barg, temperature there would need to be less
then 37.8 deg.C, otherwise, if you state it is in equilibrium with the gas,
then the pressure would need to be 10.19 barg, not 12 barg. You need to check
that, and redo the calculations as I showed. There are also examples of similar
problems on our web site, under section Articles or section Q&A. Please
also keep in mind that initially, when the pump first starts, it needs to pull
the liquid up the pipe to prime the line, i.e. the pump needs to be either
self-priming, or have some special ways for pushing the liquid in the tank thru
the line, up, and then to the pump. This is sometimes done by pressurizing the
tank with nitrogen blanket or similar means.
For more
information, you are welcome to attend one of our
Regards,
President /
Technical Director
Pumping Machinery,
LLC
Tel. 770-310-0866
Fax. 770-350-9311
email DrPump@PumpingMachinery.com
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