Compressor Dry Gas Seals

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    The Pros and Cons of Dry Gas Seals Installation in

    an Existing Synthesis Gas Compressor

    Six years ago, in 2000, the Petrobras Ammonia and Urea plants located in the Petrochemical

    Complex of Camaari, Brazil, were revamped in order to increase the capacities to 1500 metricton/day, in both plants. Several technological upgrades were carried out, as an effort to modernize the

    process and the equipments. One of these upgrades was the replacement of the synthesis gas

    compressor shaft seals, from floating ring oil seals to dry gas seals.

    The synthesis gas train has two compressor cases, driven by two steam turbines with a total output of30,400 HP (22,670 kW). The low pressure compressor case suction pressure is 370 psia (25.5

    kgf/cm2a) and the discharge pressure is 927 psia (65.2 kgf/cm2a). The high pressure compressor case

    suction and discharge pressure are 884 psia (62.2 kgf/cm2a) and 2,218 psia (156 kgf/cm

    2a),

    respectively. The seals chambers had to be machined to fit the new dry gas seals and the sealing gas

    panels connections ports. In the low pressure case the seals modification has been a success, we areoperating for six years with the seals installed in 2000, without failures. But, unfortunately, it has not

    been the case with high pressure compressor. In five years of operation, from 2000 to 2005, the HPcase seals have failed seven times, presenting an unacceptable failure rate (1.4 failures per year).

    The purpose of this paper is to describe the problem and the solution adopted, as well as to discuss thereliability aspects involved in a major change in the shaft sealing system of an existing compressor.

    Alfredo Jose G A Borba

    Petrobras Fertilizer Plant, Camaari, Bahia, Brazil

    Fabiano Oliveira Borges

    Petrobras Fertilizer Plant, Camaari, Bahia, Brazil

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    Introduction

    echnological updates have proven to be amajor factor in companies competitive-ness, either increasing productivity and ef-

    ficiency of the processes or making the work safer

    and environmentally friendly. But, we should becareful when making decisions that lead to tech-nological changes, for newer technology does notnecessarily mean better solutions to problems orimprovement in a machine performance.

    Every technology has its own limitations and ap-plication range, which we have to take in consid-eration when designing a new machine or just car-rying out a modification in an existing one. Itsnot different with the dry gas seal technology that,

    even not being new in concept, is relatively new inapplications. Bringing several welcome improve-ments in centrifugal compressor shaft sealing, drygas seals have quickly become the type of sealmost used by the centrifugal compressors manu-facturer. This paper discusses the reliability as-pects involved in a major change in the shaft seal-ing system of an existing compressor, brieflyreviews the dry gas seal concept and compares itsadvantages and limitations with the traditionaltypes of shaft seals, presenting the available bibli-ography, as well as our own experience with theconversion of a syn gas compressors shaft seals,from floating ring oil seals to dry gas seals.

    Dry Gas Seals

    The dry gas seal concept is not a new one, but itsapplication in centrifugal compressor shaft sealinghas boomed just in last decade or so. Over 80% ofcentrifugal compressors manufactured nowadays

    use dry gas seals (Stahley, 2001). It works like amechanical seal, with a rotating ring runningagainst a stationary ring, but without any liquidlubricating the contacting faces. The stationaryring (or primary ring) is pushed toward the rotat-ing ring (or mating ring) by springs. Spiralgrooves in the rotating ring (Figure 2) generatefluid-dynamic forces that lift the stationary ring

    off, forming a narrow gap between the rings. So,when running, the seal faces have no contact. Thegap varies from 3 to 10 microns depending on theseal type (Godse, 2000) and is determined by theequilibrium between the force due the gas pres-sure, springs force and pressure force developedby the mating ring grooves.

    Dry gas seals are available in several configura-tions: single, double-opposed and tandem (API617). The tandem type is the most used in processgas service, mainly in high pressure and/or haz-ardous gas applications.

    Figure 1 shows a typical tandem dry gas seal as-sembly, where the spiral grooves can be seen onthe mating rings.

    Figure 1: Typical Tandem Gas Seal Assembly

    - Courtesy of John Crane -

    Figure 2: Standard Unidirectional Groove Design

    - Courtesy of John Crane -

    T

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    Due to the very narrow gap between the matingand the primary rings the gas in the seal chambershall be clean and dry, for solid particle larger than3 microns (Stahley, 2003) can wear the rings facesout, and liquid particles in the gas make the crea-tion of pressure force between the rings difficult,causing the mating and primary rings running con-

    tact, leading to the seal failure due to rings facespremature wear and high temperature. Thats whythe dry gas seal needs a filtered gas injection in thechamber between the seal and the process gas. Theseal gas may come from the compressor dischargeor from others sources of clean and dry gas, and isinjected with a pressure about 10 psi above theprocess gas pressure. Needless to say that the sealgas conditioning system is as important as the sealitself.

    It is necessary, also, to avoid allowing the bearinglubrication oil to reach the seal faces. Its the func-tion of the barrier seal installed in the bearing sideend of gas seal cartridge.

    Figure 3 shows a cross-sectional view of typical

    tandem gas seal, detailing all seal components andseal gas / barrier gas inlet ports, and gas leakageports.

    Figure 3: Cross-sectional view of a Typical Tandem Gas Seal

    - Courtesy of John Crane -

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    Shaft Seal Types Comparison

    Table 1 shows a comparative economic evalua-tion of oil seals (Wet Seals) and dry gas seals(Bloch, 1998).

    Table 1

    Wet Seals Dry Gas Seals

    Seal oil supportsystem costs

    Pumps, reservoirs,filters, Traps,coolers, consoles.

    None

    Seal oil consump-tion

    1-100 gallons/day No seal oil

    Maintenancecosts

    A major expendi-ture over equipmentlife

    Negligible

    Energy Costs Seal power loss:10-30 HPUnit driven pumps:20-100 HP

    1-2 HP

    Process gas leak-age

    25 SCFM & Higher < 2 SCFM

    Oil contamination Of Pipeline: Highclean up costsOf Process: Cata-lyst Poisoning

    None

    Toxic and corro-sive applications

    Buffer gas con-sumption (eg N2):40-70 SCFM

    2-4 SCFM

    Unscheduledshutdowns

    High downtimecosts

    Very reliable

    Aborted startups Frequent Rare

    The table, presented by Heinz Bloch (1998), de-serves some comments: It was considered that the dry gas seal system

    has been design within state of the art, pre-senting, therefore, a very high reliability andlow maintenance costs.

    The costs related with the oil support system(Maintenance costs and energy costs) are amajor factor in wet seals disadvantage, com-

    paring with dry gas seals. The costs related with oil contaminations are,

    also, an important factor in favor of dry gasseals.

    A key difference between the wet seals and drygas seals is the support systems. While the gas be-ing compressed is not a major issue in wet sealsdesign, the knowledge of the gas composition,cleanness and presence of liquid, at the entire op-erating range and all possible process variationsthat can change the gas specification, are some ofthe most important design requirements for a reli-able dry gas seal operation.

    J. Delrahim (2005), from John Crane Inc., affirmsthat Analyzing dry gas compressor seals received from the field for refurbishment validates that

    most seal failures result from lack of clean and

    dry buffer gas. He wrote, also, Common con-trol system designs for gas seals consist of filtra-

    tion, regulation and monitoring. However, al-

    though these control systems typically offerelaborate monitoring and regulation features, the

    filtration issue is often overlooked. In most cases,

    users and contractors initially choose standard

    filtration on virtually every application, regard-

    less of gas composition and/or presence of liquid

    or condensation occurring in certain gas mix-

    tures.

    In that sense, R. Aimone (2007), says that In re-viewing dry gas seal failures experienced in 2006

    and previous years, our conclusion is that in amajority of cases, the root cause is that the seal

    and system configuration were not designed to

    handle all the actual site operating conditions, in-

    cluding startup, shut-down and upsets that should

    and could have been anticipated

    Figures 4, 5 and 6 show a typical differentialpressure control support system for tandem drygas seals (API 614). The standard duplex filtersused in this kind of system are not supposed to

    remove all solid particles and/or liquid of a dirtyand/or wet seal gas. For that purpose a properlydesigned gas conditioning system shall be used, inorder to consistently supply pressured, clean anddry gas to seals, either in steady-state operatingrange or on startups and shutdown transients.

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    Figure 4: Tandem Dry Gas Seals Support System Schematic

    - Courtesy of American Petroleum Institute -

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    Figure 5: Seal Gas Filter Module

    - Courtesy of American Petroleum Institute -

    Figure 6: Differential Pressure Control

    - Courtesy of American Petroleum Institute -

    Why Change? (The Pros)

    This is a question everyone should ask before de-ciding to change the original design of a system ora machine component that has been operating. Animportant step in a successful conversion from wet

    seals to dry gas seal is to know all the aspects ofthe new technology.

    The benefits that well-engineered dry gas seals sys-tems can present are:

    Reliability improvement

    . The mean dry gasseals failure rate is around 0.175 failures/year,meaning that we could expect one failureevery six years or so (Bloch, 2005). The largerquantity of accessories in the support system isthe cause of the highest percentage of down-time for a compressor using wet seals (NaturalGas STAR Partners, 2003).

    Reduction of unscheduled downtime, as aresult of reliability improvement.

    Elimination of oil leakage into the compres-sor, avoiding the problems and costs related toprocess contamination.

    Elimination of lubrication and control oilcontamination with process gas. The sourseal oil reclamation, through degassing tanksinto the main oil reservoir, often leads to un-desirable oil system contamination.

    Elimination of the seal oil consumptioncosts, including the costs to disposal or recla-

    mation of the sour seal oil. Reduction of operating costs. The power loss

    in dry gas seals is much less; as well the en-ergy to operate the seal oil pumps is elimi-nated.

    Reduction of maintenance costs. The wetseal system has many more components thatneed maintenance effort (e.g., pumps, motorsand/or turbines, coolers, control valves, reliefvalves, etc).

    Reduction of gas emission. The wet seals gasleakage, from the traps vent as well as fromthe sour oil degassing process, is somethingbetween 40 to 200 scfm, while dry gas sealsleak at a rate of 0.5 to 3 scfm (Natural GasSTAR Partners, 2003).

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    Why Change? (The Cons)

    Unfortunately, every technology has its own limita-tions.

    Listed below are the disadvantage dry gas sealssystems can present, taken into account the re-placement of existing wet seals:

    Necessity of compressor heads machining.In order to provide gas ports and accommodatethe dry gas seals, its often necessary to ma-chine compressor heads (Stahley, 2003).

    Changes in compressor rotor dynamics.Thewet seals act as dampers and, so, influence therotor dynamics characteristics of the compres-sor, as critical speeds, amplification factor andlogarithmic decrement. Therefore, its neces-sary to carry out a complete rotor dynamicanalysis (RDA) before replacing the oil sealsby dry gas seal. If the results of RDA are un-satisfactory additional damping equipmentmay be required (Stahley, 2003).

    Highly susceptible to failures due to pres-ence of dirt and/or liquid in the gas. The wetseals have much less problems with dirtyand/or wet gas, while the dry gas seals reliabil-

    ity depends strongly on a system that assures asteady flow of clean and dry gas into the sealschambers.

    Reliability can be reduced by transientconditions. During startups, shutdown or idlein low speeds, the dry gas seals lose the capac-ity of develop the pressure force that keep thenarrow gap between the rings faces, being sus-ceptible, so, to premature failures of the ringsin plants that have frequents shutdowns.

    Higher prices. A dry gas seal cartridge ismuch more expensive than a floating ring oilseal assembly. A tandem dry gas seal assemblycosts between US$ 50,000.00 and US$60,000.00, while a floating ring oil seal as-sembly costs between US$ 20,000.00 and US$30,000.00

    Higher assembly complexity. The dry gasseals support system is less complex than thewet seals, but the dry gas seal assembly itselfis much more complex. The maintenance teamonly replaces the gas seal cartridges, and sendsthe used cartridge to refurbishment and static

    and dynamic test on a test rig in the manufac-turer facility. In developing, or underdevel-oped, countries this means that seals have tobe repaired abroad, and more spares seal car-tridges have to be kept in storage than in acountry where facilities with test rig are avail-able.

    Susceptible to failures due to reverse rota-tion. The nonsymmetrical spiral grooves arenot able to create the pressure force to lift offthe primary ring if the compressor runs in re-

    verse rotation. So, if reverse rotation occurs,the seals faces can fail. If reverse rotation is aprobable occurrence, bi-directional dry gasseals, which use a symmetrical groove profile,should be considered. Additionally, the unidi-rectional dry gas seals are different for eachcompressor end, thus requiring at least twospare seal assemblies for each compressor.

    Necessity of barrier gas. Its necessary toavoid that the bearing lubrication oil reaches

    the seal faces. To doing so, a barrier seal is in-corporated in the outboard end of the dry gasseal assembly, and barrier gas is injected intothe barrier seal chamber (Figure 3). For safetyreasons in most cases nitrogen is used as bar-rier gas. Therefore, a reliable nitrogen sourcemay be necessary.

    Case History: A Syn Gas CompressorSeals conversion

    Six years ago, in 2000, the Petrobras Ammoniaand Urea plants located in the Petrochemical Com-plex of Camaari, Brazil, were revamped in orderto increase the capacities to 1500 metric ton/day, inboth plants. Several technological upgrades werecarried out, as an effort to modernize the processand the equipments. One of these upgrades was the

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    replacement of the synthesis gas compressor shaftseals, from floating ring oil seals to dry gas seals.

    The synthesis gas train consists of two compressorcases, driven by two steam turbines with a totaloutput of 30,400 HP (22,670 kW). The low pres-sure compressor case suction pressure is 370 psia(25.5 kgf/cm2a) and the discharge pressure is 927psia (65.2 kgf/cm2a). The high pressure compressorcase suction and discharge pressure are 884 psia(62.2 kgf/cm2a) and 2,218 psia (156 kgf/cm2a), re-spectively.

    Over the years, the plant had experienced severalprocess contamination events of oil from the float-ing ring oil seals system. Adding to this were thecosts of sour seal oil disposal. For these reasons the

    syn gas compressor seals were upgraded to dry gasseals. A proposal was requested from the compres-sor OEM based only on the synthesis gas composi-tion in normal conditions. The proposed designwas installed: two sets of unidirectional tandem drygas seals with standard seal gas support system(panels), for each compressor cases (Figure 4).

    Each seal gas panel consisted of a standard filtra-tion module (Figure 5), a standard differentialpressure control module (Figure 6) and a vent

    leakage monitoring module. The sources of sealgas supply to the panels were the compressor casesdischarges.

    The compressor cases heads seals chambers had tobe machined to fit the new dry gas seals and theseal gas panels connections ports.

    In the low pressure case the seals modification hasbeen a success. The plant has operated for morethan six years with the seals installed in 2000,

    without any failure. The low pressure case sealsperformance has proven that the existing wet sealconversion to dry gas seal can be very successful.

    But, unfortunately, this has not been the case withhigh pressure compressor case. In five years of op-eration, from 2000 to 2005, the HP case seals havefailed seven times, presenting an unacceptable fail-ure rate of 1.4 failures per year.

    What has been gone wrong with the HP case sealsconversion? Why was the seals reliability so muchdifferent between the two cases? First, considera-tion was not given to the ammonia synthesis reac-tor catalyst reduction in startup after plant turn-around. During the reduction there was liquidwater in the gas flow to the recycle suction. So, theunexpected water was the cause of the first HP casedry gas seals failure, immediately after the sealswere installed.

    Less than a year after the first failure, the HP caseseals failed again. This time a black powder wasfound in the seals chambers, clearly indicating thatthe gas was not as clean as thought. Investigationdetermined the dirt was coming from the ammonia

    synthesis reactor catalyst. The filtration module ofthe seal gas panel was not designed to cope withthis kind of dirty gas. To minimize this problem,the HP case source of seal gas supply was changedto a point downstream of the synthesis reactor pre-heater (121-C), where the gas is cleaner and dry.But during transients in startups and shutdown theseal gas supply point had to be changed back tocompressor discharge, upstream of the dischargecooler, causing saturation of the filters. Duringtransients there was not enough differential pres-

    sure between the seal gas and the process gas intothe compressor case. This allowed the dirty processgas to enter the seals chambers causing wearing ofthe seals (Figures 7 and 8).

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    Figure 7: Damaged Mating Ring

    Figure 8: Scratches on the Mating Ring

    The reliability improvements used to justify thewet seals replacement, were jeopardized by a sealsupport system, whose design had not taken intoaccount the actual seal gas conditions.

    After review of the failures, the compressor OEMcarried out a thorough engineering review of theseal gas supply sources and the existing seal gassupport system. Based on the seal composition andoperating conditions, a simulation of the seal gaspressure and temperature drops expected across thevarious components within the gas seal system, has

    been done. Figure 9 shows the seal gas phase dia-gram for the two source of seal gas supply.

    Figure 9: Seal Gas Phase Diagram

    Based on the review, the compressor OEM pro-posed the installation of a seal gas conditioningsystem, upstream of the HP case seal gas panel. Asshown on the seal gas phase diagram, both sourceof seal gas supply have sufficient margin from thedew point of the gas, and therefore no pre-heaterwas required in the seal gas conditioning system(Figure 10).

    The conditioning system consisted of:

    One duplex wet gas pre-filter separator, withautomatic drains

    One air driven pressure boost system (To keepproper seal gas differential pressure duringstartups and shutdowns)

    One relief valve

    316 stainless steel tubing and fittings

    All of the system components were mounted on a

    single stainless steel fabricated panel.

    The seal gas conditioning system was installed twoyears ago and, since then, the compressors sealshave operated free of failures.

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    Figure 10: Seal gas conditioning system

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    Conclusion

    Dry gas seal technology development has broughtvery welcome solutions for the following problemsexperienced with centrifugal compressors that use

    wet seals: Process contamination and catalyst poisoning

    with oil,

    Unscheduled shutdowns caused by loss ofcontrol of seal oil system and/or seal oilpumps/driven failures,

    Lub/control oil contamination with processgas.

    All of these issues are hoped to now be history. Itshard to think today of purchasing a new centrifugalcompressor with other shaft sealing system thandry gas seals.

    But, the replacement of existing wet seals by drygas seals is not a straightforward solution for com-pressor seals related problems. Before making thefinal decision be sure that:

    Its the best or the only solution available.

    A comprehensive feasibility study has beendone, considering the seals chamber dimen-sions and ports, compressor rotor dynamics,compressor operating conditions and varia-tions, seal gas and barrier gas supply source,reverse rotation and surge occurrence rates, theslow roll or idle operations at low speed andso on.

    The design does not overlook a seal gas condi-tioning system that is able to assure a steadyflow of clean and dry gas to the seals at the

    proper pressure in the entire range of operatingconditions and on startups/shutdowns. HeinzBloch (2005) wrote: Consider gas sealsonly in conjunction with a clean gas sup-

    ply.

    The maintenance facilities and spare partsavailability have been assured.

    The maintenance and operating teams trainingis an important task of the project.

    In doing this you will have an acceptable risk forthe seals replacement project and can take all thehigh reliability advantages of a well-engineered drygas seals system.

    Reference

    Stahley, John. S., 2001, Design, Operation andmaintenance Consideration for Improved Dry GasSeal Reliability in Centrifugal Compressors, Thir-tieth Turbomachinery Symposium, Turbomachin-ery Laboratory, Texas A&M University, CollegeStation, Texas.

    Godse, A. G., 2000, Understand Dry Gas Seals,Hydrocarbon Processing Magazine, February 2000.

    Stahley, John. S., 2003, Mechanical Upgrades toImprove Centrifugal Compressor Operation andReliability, Dresser-Rand Company, Olean, NY.

    Bloch, Heinz P., 1998, Improving Machinery Re-liability, Third Edition, ISBN 0-88415-661-3,Gulf Publishing Company, Houston, Texas, pp.581 - 593.

    Delrahim, J., 2005, Use Gas Conditioning to Im-prove Compressor Gas Seal Life, HydrocarbonProcessing Magazine, January 2005.

    Aimone, R., Forsthoffer, W., Salzmann, D., 2007,Dry Gas Seal System: Best Practice for Selection,Which Can Help Prevent Failures, Turbomachin-ery International, January/February 2007, Vol. 48,No. 1. Pg. 20-21.

    Natural Gas STAR Partners, 2003, Replacing WetSeals With Dry Seals in Centrifugal Compressors,EPA - Lessons Learned Summaries, November2003.

    API 614, Lubrication, Shaft-Sealing, and Control-Oil System and Auxiliaries for Petroleum, Chemi-

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    cal and Gas industry Services, American Petro-leum Institute, USA.

    API 617, Axial and Centrifugal Compressor andExpander-compressors for Petroleum, Chemicaland Gas industry Services, American PetroleumInstitute, USA.

    Rangel, Roberto S., Campos, Rogrio S., vila,Paulo R., Lins, Paulo S., Costa, Eduardo M., 2004,Relatrio do Grupo de Trabalho, Petrobras, Fe-bruary 2004, Camaari, Bahia, Brasil.

    Bloch, Heinz. P., 2005, Consider Dry Gas Seal forCentrifugal Compressors, Hydrocarbon Process-ing Magazine, January 2005.