Select the Right Compressor (CEP)

n any process, numerous compo-nents are required to make the en-tire concept work. As with any ve-hicle, processes require an engine

and, where gases are involved, the motive forceis usually a compressor. This article will at-tempt to shed some light on the different typesof compressors, how they can be selected, andthe differences between air and gas units.

The gas compressor holds a special place inmost mechanical and chemical engineers’minds, and thoughts can range from admirationto hatred. The reason for this is that compres-sors are usually the most complex mechanicalunits in a process; as a result, they must be un-derstood and selected carefully. A poorly select-ed unit will not only be unreliable in its ownright, but also it will be less flexible to the in-evitable changes that occur when most process-es evolve from theory to practice.

Compressor engineers will tell you that themajority of problems associated with the unitsin service can be traced to the process, the se-lection of the compressor itself, or to poor pack-aging. For the uninitiated, packaging refers toall of the components that allow a compressorto operate. These include drivers, couplings, lu-brication and sealing systems, controls, and fil-tration. If a plant is operating as planned, andthe proper compressor is chosen, most issues

that do arise arefrom items such aspoorly sized cool-ers, pump failures,and so on.

The processengineer’s role

The packagingdecisions shouldbe left to the rotat-ing-equipment, me-chanical, or mainte-nance engineers onany project. The pro-cess itself and the appli-cation of the right com-pressor fall squarely on theshoulders of the process en-gineer. If a flow scheme is al-ready fixed, and the conditionsrequired of a compressor are unre-alistic, then there is very little that themechanical engineer can contribute afterthe fact. Thus, a rudimentary knowledge ofwhat existing, commercially available compres-sors can do is necessary for a good process de-sign. Keeping the numerical possibilities inmind while forming pressure/temperature/flowrelationships can save a company a tremendous

Making the best choice means understanding how flows andpressures relate to availablemachines, and seeing if yourprocess can be adjusted tomeet the capabilities of unitsthat are readily available,reliable, and inexpensive.

Select the Right Compressor

Chemical Engineering Progress July 2000 15

D. Gregory Jandjel,Gardner Denver Engineered Packaging Center

COMPRESSORS

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©Copyright 2000

American Institute

of Chemical Engineers.

All rights reserved.

Copying and

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16 July 2000 Chemical Engineering Progress

COMPRESSORS

amount of both its time and money.Compressor inlet pressures P1 are

as important as the discharge pres-sures P2, since many commercial ma-chines are limited on the inlet side.For example, there are numerous rel-atively inexpensive, oil-injectedscrew (OIS) compressors suitable forprocess gas duties that are limited tovalues of P1 of 100 lb/in.2 (psi) (allpressures here are gage, i.e., psig, un-less otherwise noted). SpecializedOIS compressors can accept a P1 of700 psi, but these are more costlyand have longer deliveries.

Most oil-free screw (OFS) unitsdesigned for gas applications are lim-ited to 150 psi at the inlet. There arespecial cases when they can achieve aP1 as high as 225 psi, but these mustbe checked on a job-to-job basis. Re-ciprocating (recips) and centrifugaltypes are available at nearly all inletpressures, but the centrifugals can be-come costly under P1 and P2 condi-tions where special pressures or mul-tistaging is required. These will bediscussed in the centrifugal sectionbelow.

Gas compressorsThe compressor industry is seg-

mented into numerous sections andsubsections, and recent economicconditions have created considerablecrossover as compressor suppliersjockey for position on their next sale.Fundamentally, there are two majorareas: gas and air.

Gas compression is the more diffi-cult, since the processes they driveare normally very expensive andgases must be handled delicately toavoid leakage, unwanted condensa-tion, other phase problems, and flashpoints. Different gases also havevarying market demands, which af-fect the way a compressor is built andpurchased.

Industries with high demand andvolume will have gas compressors“built for duty” and numerous com-petitors, resulting in low prices. Re-frigeration is the best example. Whilethe exact numbers are difficult to ac-

curately predict, the global number ofstandardized refrigeration units sold(for ammonia, propane, propylene,Freon-replacements, and Freon) fallwell into the thousands annually.Other industries have fair demand

and volume, but standardizing themachines is difficult, since theirP1/P2/flow relationships are widelyvaried and inconsistent. Hydrogen isa good example where there are manyapplications, but disparate flows and

■ Figure 1. Example of “curved” performance on centrifugal compressors.

Inlet Volume

Dis

char

ge P

ress

ure,

P2

-12

3045

60

75Approximate IGV Positions, deg.

Rated Point

Expe

cted

Sur

ge

Preswirl

0

■ Figure 2. Cost-effective sizes for commercially available gas compressors.

Reciprocating

Flow Rate, acfm

Dis

char

ge P

ress

ure,

P2,

psig

0 100

200

400

600

800

1,000

3,000

5,000

15,000

0500 1,000 5,000 10,000 100,00050,000

Diaphragm

Rotary Vane

Oil-Injected Rotary Screw

Oil-Free Rotary Screw

15,000 psig/100 acfm

6,000/6,000

Centrifugal 5,000/4,000 (Start 200) 3,000/10,,000 2,000/30,000

1,500/100,000+

870/10,000 (Start 150)

400/50,000 (Start 250)

150/4,000


pressures make it very difficult to de-sign one set of off-the-shelf equip-ment to cover the variations.

Some of the major gas compressormarkets, and uses, include vapor re-covery (which can also be subdivid-ed into many sections), production,transmission, fuel gases (power gen-eration and boilers), refrigeration,and processing. The refrigeration,fuel gas, and gas transmission indus-tries are very large and consistent,hence, many standardized compres-sors have been created to reduce costand gain market share. Even these in-dustries find that conditions uponwhich gas compressors are sizedvary to such an extent that it is diffi-cult to produce equipment to coverthe entire market.

As a result of the different gasconditions found in the marketplace,broad ranges of customized compres-sors are available. These will typical-ly cost more than standard units, suchas those built for air or the more com-mon refrigeration and wellhead gasservice. The delivery times for theseunits are also longer, as most are builtfrom the moment a purchase order isplaced, unlike air units, which arebuilt ahead of time based on marketestimates. All API-based compres-sors, except for American PetroleumInstitute (Washington, DC) API 11Precips, are custom builds, so that theuser should expect deliveries in ex-cess of 35 weeks for a package. Cen-trifugal and OFS options, built to APIstandards, often have deliveries ap-proaching one year from order. (Sincemany API standards will be men-tioned here, their titles and contentwill not be mentioned. For more in-formation, see API’s Web site:www.api.org/.)

Air compressorsAlthough air is a gas, the incredi-

ble volume and competition in the airmarket has bred an entirely differentline of compressors. From a corrosionstandpoint, air is actually a very diffi-cult gas. It contains two oxidants (O2and CO2), and water is normally pre-

sent. However, air is drawn from theatmosphere, and if a compressorleaks, there is little harm. With a P1variance of roughly 11.2–14.7 psiaand well over 90% of applicationsusing a P2 of 100–150 psi, it has beenrelatively easy for the world’s aircompressor manufacturers’ to “dial-in” their designs. They have completelines of products that are built withconsiderable capacities, using compo-nents that are only acceptable to airor nitrogen. Companies such as Gard-ner Denver (GD) produce thousandsof OIS compressor air-ends per year.

Air compressors are normallylightweight and use materials, such asbronze, which would not be accept-able for most gases. Thus, air unitsshould always be treated separately

from those handling process gas.Only some reciprocating units (in-cluding some made by GD) havefound success in crossing over. How-ever, despite using the same frame,even these units have differences ininternal construction, depending onwhether air or gas is used.

An aero-derivative screw com-pressor has made inroads in the gasproduction arena, specifically well-head gas. Once again, these units areconstructed differently from the stan-dard air units; they are engineeredsuch that they service wells that typi-cally have 5–7 year lives.

Process gas compressors should beselected from the moment the processdesign begins. Operating companiesthat are successful with their com-

Table 1. Minimum sizing information required by compressor vendors.

Gas Compressors• Site elevation above sea level• Gas inlet pressure• Gas composition (or molecular weight (MW)), heat capacity at constant pressure Cp, k-

value, compressibility Z (for budgetary considerations); also indicate the water content inthe gas

• Gas flow• Gas discharge pressure required• Discharge temperature limitations• Drive selection:

For gas engines or turbines, provide the fuel gas lower heating value (LHV), temperature, and pressureFor steam turbines, provide the steam temperature, inlet pressure, and acceptable backpressure

• For air or water cooling, provide the design temperature of the medium• Level of specification:

Manufacturer’s standard“Near” APIAPI specifications with client inputsClient’s specificationsOil level permitted in discharge gas

Air Compressors• Site elevation• Ambient air temperature range (winter low and summer high)• Relative humidity at high temperature• Discharge pressure required• Discharge temperature limitations• Oil level permitted in discharge air• Drive selection• Air or water cooling• Level of specification

pressors normally try an iterative pro-cess. The engineer designs an initialprocess that fits the range of what themarket has available, then these con-ditions are sent to various compressorvendors and feedback is provided onissues of feasibility, availability,price, and delivery. The process engi-neer than incorporates the revisedpressures, temperatures, and flowsinto a workable process model.

Naturally, this procedure may in-volve mechanical and maintenanceengineers, a corporate rotating-equip-

ment engineer, or an engineering con-sultant. In the end, process engineersshould know a little about what com-pressors can do, and mechanical engi-neers should know a little about whata process’ needs and limitations are.

Compressor sizing information

Important sizing information, re-quired by compressor vendors andpackagers, is listed in Table 1. Com-pressors are sized on absolute inletpressure (psia), inlet temperature,

inlet flow, and gas characteristics.Positive displacement (PD) types,which consist of all models other thancentrifugals, are sized on actual inletvolume (actual ft3/min (acfm)).

For most reciprocating and rotaryscrew applications, the discharge pres-sure becomes almost secondary in theselection of the physical size of theunit. However, knowing the dischargepressure is necessary, since it will dic-tate whether the compressor is capableof the desired pressure, whether thegas will remain gaseous throughout

COMPRESSORS


Table 2. How the four basic types of compressors stack up.

Type of Compressor OIS OFS Centrifugal Reciprocating

Principle of operation PD-OIS PD-OFS Dynamic PDMaximum P1, psi 700 225 Close to P2 Close to P2 (Depends on rod load, as well)Maximum P2, psi 865 400 1,500–5,000 6,000Maximum flow, acfm 10,000 47,000 100,000+ 6,000Maximum T2,°F 250* 400–500 350–500 300–400Pulsation None None None LargeSurging No No Yes NoFirst critical speed Below Below Above BelowMaximum pressure ratio/stage 23:1 5:1† 1.5–3:1 5:1Design point efficiency 70–85% 70–85% 70–88% 75–92%Off-design efficiency Excellent Fair Poor FairOil-free status Filters needed Oil-free Oil-free Filters‡

Polymer gas applications No Yes Difficult NoAPI continuous run, h 16,000 24,000 24,000 8,0005-yr reliability/uptime 98–99.5% 99–99.5% 97–99.5% 90–95%Standby required§ No No No YesInstallation area X 2X 2X 4XNoise level (with enclosure) 85 dB 85 dB# 85 dB 90 dBVibration level Small Small Small LargeSensitive to vibration No No Yes NoCapacity control 15–100% Recycle 70–100% Step or recycleDischarge accumulator No No Yes YesDischarge temperature control Yes Possible No NoVariable inlet pressure Yes Yes No LimitedMethod of P1 variance Slide valve Recycle PCV¶ SVU**/PCV¶

Part-load power Low High High HighGas composition effect Small Small Large Small–mediumLowest molecular weight 2.0 2.0 10.0 2.0 (Special distance piece)Starting torque Low Low High HighInstallation costs Low Medium Medium HighSpare parts cost Low Medium High HighOperation cost Low Low Low–medium Medium–highMaintenance required Low Low Low Medium–high

Notes: * OIS compressors are cooled by oil injection. Most lubricants break down at 280°F.† OFS units can achieve 8:1 ratios with liquid injection.‡ Or nonlubricated with distance piece and purge.§ Standby requirement can also depend upon level of specification.# OFS noise level with silencers.¶ PCV is pressure control valve.** SVU is suction valve unloader.

the compression cycle, the number ofstages required, and what the powerrequirement for the unit will be.

Centrifugal compressors are dy-namic, which means that their perfor-mance is “curved” and dependstremendously upon inlet flow and dis-charge pressure requirements. Figure1 shows the typical pressure volumerelationship for these devices. Notethe P2 curves downward as the flowincreases; this is found in all dynamiccompressors. The multiple curves arefor different inlet guide vane (IGV)settings on a single-stage compressor.

IGVs are pneumatically actuatedvanes at the entrance of the compres-sor that alter the gas flow and create apressure drop. Unlike butterflyvalves, they are quite efficient at80–100% of compressor-design flowrates. The amount of turndown ob-tained by using IGVs depends uponstaging. Single-stage units will typi-cally be capable of 65–105% of flowrange with IGVs, while the effect iscloser to 90–100% on multistage ma-chines. The 105% is achieved on sin-

gle-stage units by “preswirl,” whichis possible by reversing the IGVs.

Centrifugal units can be seen asfixed-ratio compressors, which meansthat only a ±5% change in inlet pres-sure is normally allowed for a fixeddischarge pressure. Dynamic com-pression results from the conversionof gas velocity to pressure. Thus,molecular weight (MW) plays a keyrole, since the selection of the com-pressor is directly related to the headcalculation for the process. This iswhy centrifugals are not used for hy-drogen, or other low-MW gases. Thehead is simply too high for a cost-ef-fective solution when the MW dipsbelow 10. When the MW is below 5,a centrifugal selection is almost im-possible, since the head may be at orwell over 100,000 ft.

The main difference that a usersees between PD and dynamic com-pression is that the former’s compres-sors do not provide a significant in-crease in flow with a drop in dis-charge pressure, whereas dynamiccompressors do (this is called riding

out the curve). In fact, if a PD bloweris sized properly for the pressure ratiorequired, the flow might drop by afew percentage points if the ratio isincreased or decreased by more than10%, due to volumetric efficiency.Table 2 compares the four basic typesof compressors.

Forestalling against surgeBy the same token, while PD units

can produce 20% higher dischargepressures (or more) with only per-centage-point changes in flow, dy-namic units can only rise in pressuremarginally with a heavy payment inflow and a very great danger of ap-proaching surge. Surge is when a cen-trifugal compressor approaches theend of its curve at the left (Figure 1).It is best to keep the compressor op-eration at least 5% (by flow) to theright of this line.

Physically, as the compressor ap-proaches surge, vibration begins andincreases as you approach the surgeline (a line drawn by connecting allthe left-most points on the IGVcurves). Vibration is quite severe andcan heavily damage a compressorwhose impeller(s) may be spinninganywhere from 7,000–50,000 rpm.For this reason, all centrifugals shouldbe purchased with a surge system,which unloads the machine via recir-culation, as conditions approach surge.

Reciprocating, screw, and otherPD compressors will push the inletgas against whatever system resis-tance exists at the discharge. This iswhy high-pressure shutdown and re-lief valves are so important. PDs willcontinue to push until the system issatisfied, or something else gives(system resistance, unloader setting,recycle setting, alarms/shutdowns, orthe relief valve). Apart from volumet-ric efficiencies, which can vary from70–95% depending upon the selec-tion vs. requirement relationship, aPD unit will compress the sameamount of actual flow through itscylinder, regardless of pressure, tem-perature, or MW.

Naturally, one could get into se-


■ Figure 3. Air compressors — cost-effective units that are commercially available.

Reciprocating 1,500 psig/300 acfm

Flow Rate, acfm

Dis

char

ge P

ress

ure,

P2,

psig

0500

2,5003,000

5,000

200

400

600

800

1,000

1,200

1,400

1,600

10,000 20,000 30,000 40,000

Centrifugal

Oil-Injected Rotary Screw 250/100-3,000

300100

Dry Screw

200 400 1,500

600/400 300/2,000

200/150-2,000 250/200-3,000 150/3,000-40,000

mantics over the issue of volume con-sistency in PD equipment, but whenyou compare a 25% variance with the100+% found in dynamic units, theargument holds true. Thus, a com-pressor system vendor must know theinlet absolute pressure and inlet tem-perature, along with the flow to cal-culate the acfm and peg the propercompressor sizing.

Reciprocating unit flow resultsfrom the multiplication of cylindervolume (based on stroke and diame-ter), number of cylinders, actual rpm,and volumetric efficiency. Screw unitflow is based on swept volume timesrpm times volumetric efficiency. Thisillustrates the need for an acfm calcu-lation by the vendor and the fact thatthe voltage must be known for motordrives, since the calculation dependson rpm, and many PD compressorsare direct driven.

The compressor vendor, due to skidpressure drops across each side of thecompressor, should calculate the acfm.Vendors prefer to be given the processflow requirement in standard ft3/min(scfm), (normal) nm3/h, lb/h, or kg/h,to ensure accuracy in sizing. This iswhy the gas composition or character-istics are so important.

Effect of k-valueIf the buyer’s gas composition is

yet to be finalized, the buyer’s guesson MW, the ratio of heat capacity atconstant pressure to that at constantvolume Cp/Cv, and the compressibili-ty Z will still be much better than thevendor’s. The MW and Z are obvious-ly necessary for flow calculations,particularly if the flow is provided inthe desired standardized or mass-flowformat. However, Cp/Cv, often knownas the k-value, is crucial as well.

The k-value is used in various cal-culations, including horsepower andmechanical volumetric requirementsfor PD compressors. On centrifugaltypes, the MW is critical, since thehead calculation is so heavily affectedby this number (the larger the MW,the lower the head), and the head di-rectly affects the power requirement.

On PD units, the k-value directly af-fects the power requirements, and thecalculation of it, for bidding purposes.

Heavy hydrocarbon gases, such aspropane, butane, and propylene, havek-values around 1.14 under most inletpressure/temperature conditions. Air,nitrogen, and hydrogen are typicallyat 1.4. Helium can be higher than 1.6.If there were two processes, one withpropane and one with air, using iden-tical numbers except for gas compo-sition, the power used by a PD com-pressor could be 5–10% higher forthe air than the lower k-valuepropane. This can often mean a framebreak in the compressor driver, andthis has a significant impact on thetemperature rise across the compres-sor. A frame break is a jump from onesize to another. If the jump is fromsmaller to larger, then it can be costly.Temperature rise affects oil coolingand gas cooling, so the entire systemcan be affected if cost estimates arebased on a 1.15 k-factor, and the finaldesign balloons to 1.3, for example.

There is one final note about thegases lighter than 10 MW, specifical-ly hydrogen and helium. AlthoughPD compressors, notably reciprocat-ing and screw units, are the best forthese low-MW gases, these lightergases are “slippery” and tend to resultin lower volumetric efficiencies in the70–85% range. “Slip-pery” means that the gasmolecules are small andtheir density is light, so itis difficult to “capture”the gas and make it gowhere you want it to go.Thus, when compared toa typical natural gas(MW of 17 and k-valueof 1.28), hydrogen andhelium will require aroughly 10% larger ma-chine, due to lower volu-metric efficiency, and5–10% more horsepow-er, due to the higher k-values.

For the purposes ofthis article, some rules of

thumb will be presented to help guidethe process engineer through theavailability and selection process.This becomes necessary since nearlyevery compressor manufacturer hasequipment with different pressure andflow capabilities. However, the mar-ketplace will always dictate what ispurchased and what is a fringe player,and any good engineer must havebottom-line sensitivity in this day andage. Figure 2 shows the general areawhere the various types of gas com-pressors are cost-effectively availablein terms of pressure and flow. Figure3 does this for the air machines.

The main types of compressorsused in the industry are reciprocating,rotary screw, and centrifugal; lesserselected are rotary-vane, liquid-ring,and diaphragm machines. Only themajor ones will be discussed at lengthin this article.

Reciprocating compressorsIn the U.S., from the 1900s to the

1960s, the reciprocating compressorbecame the workhorse for all com-pression (Figure 4). These have beenused in nearly every application, in al-most every conceivable way. Althoughtheir population is dwindling, and an-nual sales volumes have been insteady decline since the 1970s, thesemachines’ capability in handling large

COMPRESSORS


■ Figure 4. Bare Y-type reciprocating compressor.

pressures and small flows, along withsingle-body/multistage availability,will keep them a necessary part of thelandscape for the foreseeable future.

Another benefit that reciprocatingunits provide is their ability to beused as nonlubricated. This meansthat no oil is injected into the cylin-der. If the distance pieces are longenough and purged, then there shouldbe no introduction of oil vapors intothe process either (reciprocating unitsproduce a tremendous amount of oilvapors, which can slip around therings, if the cylinder is not designedto stop them). The result is that non-lubricated recips are often a cost-ef-fective solution in providing a low-oilcontent (vapors), or oil-free gas. (Dis-tance pieces define the length be-tween where compression takes place(the piston area) and the location ofthe oil (the crankcase).)

These devices are also the most ef-ficient method of compressing gas ata specific condition (under a givenP1, T1, and P2). They can be multi-staged easily, and if the unit is lubri-cated, then adiabatic efficiencies inthe 80–92% range can be achieved.Figure 5 shows three machines stagedtogether in parallel, used for boostingnatural gas in a cogeneration facility.Figure 6 presents two recips used fornatural gas peak–demand shaving.

Unfortunately, if the process hasmany off-design points or if the com-pressor is oversized, the efficiencygains at design are lost at part-load.This is why variable-speed drivers andunloading valves have become popular,and sometimes expensive, alternativesto the standard recycle system setup.

The one major negative, whichmaintenance people are well aware of,is that reciprocating compressors aremaintenance-intensive. This meansthat their reliability percentage (oper-

ation percent-age over 5 yr) isamong the lowest of thecompressors available, andthat the repairs themselves can becostly. Most reciprocating units fall inthe 92–95% reliability/availabilityrange, while screws and centrifugalscan achieve 98–99.5% levels.

Another problem that users haveencountered is the pulsation and un-balanced forces created by the recipro-cating, or piston motion. This requiresspecial foundations and pulsation sup-pressors, while the other types do not.

Mainly, reciprocating compressorsare most cost-effective when the pro-cess P2 is above 865 psi at the dis-charge and the flow is less than 2,000acfm. These devices are also good forpressures above 500 psi, if the flow isless than 300 acfm. In general, recip-rocating units are the most competi-tive type at any pressure, if the flowis less than 200 acfm.

The nonlubricated forms are verycompetitive across the range, as well.Recent innovations in OFS and filtra-tion technology have resulted in theuse of OFS and OIS compressors onmany oil-free applications.

In processes that involve lowMWs, typically below 10, with pres-sures above 350 psi, recips are stillvery popular. Above 870 psi, they arethe only solution, due to the above-mentioned difficulties that centrifugalunits have.

Diaphragm compressorsA variation of the reciprocating

compressor is the diaphragm machine.This derivation uses reciprocating mo-

tion, but has nocylinder. The pistonrod actually moves a plateback and forth, creating compres-sion via the moving diaphragm. Thesemovers can achieve the highest avail-able pressures in the marketplace,roughly 15,000 psi. However, thelargest unit can barely handle 100acfm. Small flow is simply the natureof this unique form of machine.

Diaphragm units are used mostlyon high-pressure gases in R&D orother small-flow processes. They aresometimes used as the final booster ina chain of compressors to achieve apressure above 5,000–6,000 psi.

Capacity control is normally han-dled through recirculation of gases, orblowing off of air. As the compressoronly sees the full design flow underthese circumstances, part-load poweris the same as for full load. Stepped-unloading is available, through theuse of various suction and cylindervalving techniques. By disabling orenabling suction unloader valves indifferent cylinder combinations, vary-ing flows can be achieved.

Unloading normally come in three-step (0–50–100%) or five-step(0–25–50–75–100%) jumps, and themethod is especially popular for theAPI 618 compression units. Unfortu-nately, field personnel are forced to


■ Figure 5. Three identical, horizontal recips, packaged on a common skid, illustrate how large and customized a packaged unit can be.

live with the decision of using step un-loading, which is often unreliable. It isnot unusual for operations personnelto disable or remove reciprocating un-loaders sometime during their operat-ing life, to reduce maintenance costsand increase running time.

Another solution for the capacitycontrol issue is using a variable speeddrive. At first glance, this is the best so-lution for efficiency and power savings.However, 21st century budgets aretighter than ever and variable frequencydrives (VFDs) for motors are expen-sive. Also, when using VFDs, it is im-portant that a transient torsional studybe done to avoid rod load problems onthe compressors at certain speeds.

Mechanical loadingReciprocating compressor frames

are no longer rated by horsepower,since the piston rod load rating is afar more accurate predictor of the me-chanical strain on the unit. It is com-mon for corporate specifications tostate that rod load shall not exceed90% of the continuous operating de-sign for the frame. Rod load capabili-ties increase with the size of com-pressor, so actual numbers would notbe relevant or helpful to this article.What is helpful is knowing that cer-tain combinations of pressure ratio

and flow will load a compressor moreor less. By verifying the load of aspecific application against the pub-lished maximum for the compressorchosen, the mechanical engineer canverify mechanical loading.

Typically, reciprocating compres-sor cylinders can handle pressure ra-tios of up to 5:1 in a single stage, andcan generally be offered in up to sixstages, depending upon the gas androd loading. Both gas temperature androd loading become issues, which as-sist the compressor engineer in decid-ing whether multistaging is required.Note that API 618 does not allow anycylinder to have a discharge tempera-ture above 300°F. However, manywellhead gas applications have usedlubricated cylinders to a maximum of350°F per cylinder. In the air market,some vendors have approached 400°Fper cylinder, on lubricated cylinders,to reduce staging and increase costbenefits to the client.

The main problem with elevatedtemperatures is that ring-life andvalve-life are reduced; in some cases,dramatically. Newer materials haveallowed the recent elevations, but anylubricated cylinders operating over325°F, or nonlubricated cylindersabove 300°F, should be examinedcarefully.

It is not unusual for piston rings towear and be replaced annually. Thecylinder valves should last longer,somewhere between 1–2 yr. In bothcases, the nonlubricated cylinder partswould have shorter lives than the lu-bricated ones in the same application.

Reciprocating compressors comein three formats:

1. Low-speed (300–500 rpm),long-stroke (7 in. and more), per API619.

2. Medium-speed (500–800 rpm),medium-stroke (5–7 in.), GD/Joy-type units.

3. High-speed (900–1,800 rpm),small-stroke (2–6.5 in.), per API 11P.

Reliability is not too different be-tween the types, but preferences andfeatures will guide the buyer towardone or the other. The important thingto remember with recips is that aver-age piston speed is important, not theactual rpm. Piston speed is a functionof rpm and stroke length. Normally,users will accept piston speeds in the600–800 ft/s range. Nonlubricatedprocess applications would normallybe sized below 600 ft/s, per API 618.

The GD-type and API 11P unitsare the most cost-effective and havesteadily gained market share over thetraditional “slow rollers” that API618 specifies, but the traditional ma-chine is still popular in high-end/high-dollar processes. As high-end processes have been the last tosee recent budget demands, and thedwindling API 618 market has causedferocious competition between thenumerous suppliers that remain, thismay not change for some time.

Centrifugal compressorsThe centrifugal compressor is ex-

tremely popular, mostly because near-ly all are oil-free. Centrifugals alsohave oil-vapor and aerosol problems,but most process units can be consid-ered oil-free, due to the special sealarrangements that are used. Anothertremendous advantage these machineshave over all others is the enormousflows (100,000+ acfm) that someunits can compress in a single body,

COMPRESSORS


■ Figure 6. Two radial-type recips packaged on a single skid used for natural gas peak-demand shaving.

with a high-pressure (1,500–5,000psi) capability.

Centrifugals are dominant in thelarge gas-pipeline transmission indus-try, where hundreds of thousands ofcfm must be compressed to 1,000 psiafter considerable line losses. Theyare typically placed every 100 milesof pipe, or closer, and are critical tothe transmission of natural gasthroughout the world.

In process use, they are used forlarge flows, high pressures, andheavy-MW gases, and are popular onthe critical process paths found inmost petroleum refineries and petro-chemical plants. These are locationswhere you find the larger flows and,with the extensive use of catalysts,the oil-free feature is important.

From a cost standpoint, centrifu-gals seem to do best when flows arelarger. There is not much choice withthe other types above 50,000 acfm.As Figure 2 shows, there are alsomany combinations of high pressureswith even larger flows that simplymake the centrifugal the only choice.

In the psi/acfm coverage areaswhere all the types meet, centrifugalsare normally used in specific process-es that have fixed pressure ratios andrequire oil-free gas, particularly withpressures above 400 psi. Normally, ifa centrifugal is similar in cost to a re-ciprocating unit, the centrifugalshould be chosen for its reliability inservice and relatively large mainte-nance intervals. Still, while centrifu-gals are costly to fix, particularly any-thing involving the rotor/impeller orseals, lifetime costs are normallybelow those of the recips.

The reliability advantage is a sig-nificant point for both screw com-pressors and centrifugal units. Recip-rocating compressors must often be“spared,” i.e., with a standby spareunit, due to their low reliability per-centage. Centrifugal packages built toAPI standards are intended to be usedwithout spares, and have done sowith reliability in the 99%+ range.These high-reliability units are nor-mally built to API 617, using API 613

gear boxes, API 541 motors, API 671couplings, and API 614 lube/seal sys-tems. When steam turbines are used,API 611 (general purpose) or 612(special purpose) turbines come intothe equation.

API 617 centrifugal compressorstypically operate in the 8,000–15,000rpm range and use gear boxes drivenby the main driver. There is anotherspecification, API 672, for integrallygeared centrifugals. Machines madeto this standard are intended for airservice only, but some users havepurchased them for clean gas applica-tions, such as pipeline-quality naturalgas boosting. The main problem withthe 672-type units is that they arebullgear driven by 2-pole motors andthe impeller/pinion operates ataround 30,000–50,000 rpm. The in-ternal gearing, high speeds, and limit-ed shaft seal designs make this typeof centrifugal less reliable (98–99%range) than the traditional API 617variety.

Bullgears are large gears wherethe shaft is driven by the driver. Theyhave smaller gears, often, multiplegears, called pinions that can spinvery quickly due to their size vs. thatof the bullgear.

Centrifugal units are the latest typeof compressor to be released by themanufacturers, in bare form, to pack-agers. The use of packagers has great-ly reduced the final cost of the com-plete skid to the user and may bringabout greater use of centrifugal unitsin more competitive industries suchas refrigeration and fuel gas boosting.

Capacity control is achieved byinlet throttling (valve or IGV), vari-able speed, or recirculation. On sin-gle-stage machinery, IGVs are themost cost-effective solution, coupledwith a recirculation system that canalso handle surge. On multistageunits, recirculation and variable speedare the best options.

The only problem with using vari-able speed on centrifugals is that, inmost applications, the compressorcannot operate over the entire speedrange available from the driver. These

units run above their first criticalspeed; the critical speed is where thefirst harmonic vibrations occur for ro-tating equipment, and is normally inthe 8,000–12,000 rpm range for mostequipment. If you reduce the speedon a centrifugal operating at its de-sign point, you will often find a criti-cal disturbance at around 70–75% ofthe run speed. The variable speeddriver would then be programmed toramp through this speed quickly andavoid it by at least 5% on each side.The difference would have to be re-circulated from a greater speed, ifprocess off-design of normal flow orother part-load point were needed.

The main negatives associatedwith centrifugal compressors are theircomparative costs in pressure/flowranges covered by screws and recips,their pressure ratio inflexibilities, en-ergy consumption due to difficultiesat part-loads, extreme sensitivity tovibration, and the size of the installa-tion required if full API auxiliariesare required.

Typical stages can only operate toroughly 2:1, so multistaging is oftenrequired, but intercooling need onlytake place every second or thirdstage. These units are available in upto eight stages in a single body. Thus,pressure ratios of 28 are possible.Many vendors also have drive-through designs that allow two com-pressor bodies to be connected anduse a single driver. This allows formore than the standard eight stages.Stage pressure ratio balancing andimpeller selection are critical whenusing two bodies at one speed.

Standard centrifugal air compres-sors normally come in a three-stageformat (Figure 7). This allows dis-charge pressures up to 150 psi, from anormal sea level inlet (14.7 psia); forlongevity, it is best to use them at 125psi. High-pressure ratios can beachieved across each air stage, sincethe bullgear design allows for pinionvelocities above 20,000 rpm. Al-though this is fast, and would bequestionable on all process gas appli-cations, it is very normal on air and


has been the standard designfor air centrifugal units for 20years.

Oil-free rotary screw compressors

The original screw com-pressor was oil-free. Designedin the 1930s by Dr. Lyceum ofSwedish Rotary Machines(SRM), the first working pro-totype was built in Europe in1939. Commercial use of thescrew compressor did notbegin until 1946, due to WorldWar II, but its popularity wasenormous in post-war Europe duringthe rebuilding process.

In 1948, a group of American busi-nessman obtained a license to buildscrews from SRM. Americans usedthese compressors predominately inthe steel industry, for coke-oven andkiln gas applications. The steel indus-try was a dominant player in the post-war U.S., as the country built its infras-tructure and the car industry developedinto the major player it is today.

The OFS compressor was, and stillis, favored for these “dirty” applica-tions since it has the unique ability topass 200 micron-sized particles contin-uously and without incident. Particleswould settle into reciprocating cylin-ders and cause severe damage to therings and cylinder walls, and sludgingof the oil. The particles in these gaseswould create a sandblast effect on cen-trifugal impellers and cause excessivewear, vibration, and downtime.

OFS compressors can also be builtusing exotic metals. The standardmachine normally has a cast iron cas-ing with forged steel rotors. Howev-er, casings can be made from ductileiron, cast steel, and Type 316 stain-less steel. More importantly, an ordi-nary cast iron or steel casing can benickel-plated to provide a high levelof corrosion resistance and hardness.

The rotors can bemade from different grades of steel,different grades of stainless steel(such as 13-4 and 17-4) and evenmore exotic materials such as In-conel. It is all a matter of what thebuyer can afford. API 619 is thespecification that covers OFS units.

In contrast, recips have little flexi-bility in materials choices, with theonly major changes normally foundin cylinder liners, if they are used inthe design of the unit. Centrifugalscan also be made in a variety of mate-rials similar to OFSs. OIS modelsnormally use cast iron casings, withmost companies offering options touse ductile iron (sometimes callednodular iron) and cast steel. OIS ro-tors are manufactured in either duc-tile iron or steel.

OFSs with polymersPolymerizing gases are truly

where OFS units shine. Gases suchas styrene or butadiene tend to coatany contacted metal with polymerover time. This is disastrous to re-ciprocating units, since the cylinderand crankcase become overgrownwith polymer, and there is a sludg-ing effect of polymer in the oil.Centrifugals have vibration prob-

lems, since the coating either unbal-ances the impeller or grows outfrom the casing walls to meet thecoating on the impeller, causing arubbing effect. The coating also re-duces diffuser and volute areas incentrifugal units, which hinders per-formance. For this reason, centrifu-gal compressors used in low-densityand high-density polyethylene(LDPE and HDPE) service mustcontinually be shut down andcleaned, often chemically. Thisdowntime is expensive, not to men-tion the actual cleaning costs in ma-terials and labor.

The OFS compressor actually im-proves over the life of the polymercoating. These machines are designedso that their timing gears ensure thatthe two rotors do not actually makephysical contact. However, for effi-cient compression, the rotors must beas close to one another as possible.As a polymer coats the rotors andcylinder walls, these clearances closeup and increase the efficiency. Therubbing-effect is not a problem, ei-ther. OFS units are solid and probablythe least sensitive to vibration.

Thus, as the polymer coating rubs

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■ Figure 7. GD-Turbo centrifugal for air containsthree stages.

against itself, pieces smaller than 100µm break off and are releasedthrough the discharge without inci-dent. Polymer applications havebuilt-in filtration and scrubbing sys-tems throughout the piping, sincepolymerized pieces can be formedand released in the piping, vessels,and other components as well.

Recently, the OFS compressor hasbecome popular in vapor recovery, par-ticularly offshore. Figure 8 shows anAPI 619 OFS bare unit, waiting to bepackaged. The machine will be usedfor mixed-hydrocarbon recovery vaporrecovery in the Gulf of Mexico. Thecompressor will be motor-gear drivenat 6,260 rpm by an 800 kW motor.

Offshore heating tank vapors areno longer flared, but, rather, they aredrawn by a compressor and boostedto 100–150 psi. The resultant gas iscooled, filtered, and further com-pressed to the local sales gas pressure(1,000 psi in the U.S.).

In locations such as Alaska and theNorth Sea, OIS compressors havedominated the vapor recovery unit(VRU) gas booster market that hasdeveloped through environmentalconcerns and regulations. As theNorth Sea generally was first in mostoffshore developments, the Brazilianand Gulf of Mexico offshore plat-forms have been designed with OIScompressors, as well. Unfortunately,the hotter climates have caused high-er inlet temperatures to the first stageof compression, which has causedproblems in that gases that are nor-

mally condensed during cooling priorto the gas compressor are not at high-er temperatures.

On northern sites, the typical inletgas temperature falls in the 60–90°Frange with the majority of tempera-tures at or below 80°F. In the Gulf ofMexico and offshore Brazil, this tem-perature ranges from 80–130°F and ismostly 100–120°F. This temperaturedifference allows hydrocarbon heav-ies, such as decanes and higher, to re-main in the gas in sufficient quanti-ties to condense at the discharge andmix with the lubricating oil.

More importantly, since most ofthese applications are water-saturated,water becomes a big issue as the inlettemperature moves above 100°F. Thewater content of saturated gas at 120°Fis nearly thrice that at 80°F. Typically,this means that the gas should not becompressed beyond 70 psi to avoidcondensation at the low temperaturesat which OIS units operate.

The combination of lower temper-atures and greater funds spent on theearly North Sea platforms yieldedprocess conditions that were not du-plicated in the Gulf of Mexico. How-ever, existing processes are hard to letgo of.

This is why some major oil com-panies have had trouble with equip-ment in hotter climates, when thevery same machines, using the sameprocess (with lower temperatures)worked so well in colder regions. Thesolution is to correct the process tem-peratures and pressures, as well as

add better filtration to the newer ap-plications, or use OFS compressors,despite their greater cost.

OFS machines can acceptmist/aerosol entrainment and thehigher discharge temperatures associ-ated with oil-free units flash liquidsand keep the unsteady gases in thegaseous phase. Also, the pressurelimitations would force the user intointerstaging, with cooling and filter-ing, creating a better environment forthe compressor.

The National Oil Company of Mex-ico (PEMEX) has long used OFS unitsto boost the gas from near atmosphericto discharge pressures of 50–70 psi.Other companies are still trying toachieve the 100–125 psi levels they areaccustomed to with their OIS compres-sors, but this would mean two stages inan OFS compressor and significantlyhigher cost.

The solution is in the process engi-neers’ hands. If the process is de-signed to operate at the highest dis-charge pressure achievable by a sin-gle-stage OFS unit, then the final dis-charge pressure can be achieved bymodifying the already expensiveequipment on the back end. Recircu-lation processes can be adjusted byincreasing size of vessels and pipe tolimit pressure drop.

By the same token, if the process re-ally needs the higher pressure, then theengineer should design to the limit of atwo-stage OFS setup, which can be inthe 175–225 psi area starting from at-mospheric conditions. This wouldallow full use of the more expensivetwo-stage OFS units and drop the costof any compressors that follow, sincethey would be much smaller, due to ahigher P1. In recirculation processeswhere there may not be further com-pression, the vessels and piping can besized much smaller, since the compres-sor could now overcome much largerpressure drops across the system.

OFSs and liquidsLiquid entrainment is also a prob-

lem for all other compressors. Inmany saturated gases, there is a


■ Figure 8. Bare OFS compressor,awaiting packaging.The machine will beused in hydrocarbonvapor recovery.

steady stream of mist or aerosol inthe inlet gas. On centrifugal units,this causes erosion similar to partic-ulate bombardment. On recips, thisliquid forms in the cylinder and pro-duces a variety of problems from oildilution to excessive corrosion andwear. OIS compressors may haveproblems when the liquid does notflash off in time and slowly accumu-lates in the lubrication system until iteither replaces or dilutes the injec-tion oil.

In OFS systems, the liquid entrain-ment is easily flashed off due to the450–500°F maximum temperature fora compressor that can sometimesachieve 5:1 ratios (with low k-valuegases) in a single stage. This mistingliquid capability was used by engi-neers in the actual design of someprocess systems.

Capital costs for OFS machineryare always competitive to API cen-trifugal and API reciprocating units,as long as they can be kept in a singlestage. What industry has found is thatcertain gases can accept the introduc-tion of liquids, such as water instyrene, since, many times, the liquidis a part of the process anyway.

For example, with styrene, it iscommonplace in both the Badger(now Raytheon) and Lummus (nowABB-Lummus Global) processes toinject water into the OFS inlet. Wateris shot in as a mist and the flow rate isset to achieve a specific dischargetemperature from the OFS compres-sor, while increasing the pressureratio to 6:1 to 7:1, due to the dis-charge temperature drop created bythe energy required to flash the waterduring compression.

In low k-value gases such as iso-butane, 8:1 pressure ratios can beachieved by reinjecting condensed i-butane from the discharge into thesuction. Each stage of an OFS com-pressor is basically a separate ma-chine, with its own compressor bodyand driver. Therefore, cramming theapplication into one stage by eitherusing the temperature maximums orliquid injection can yield a capital

cost decrease of as much as 50% incertain instances. In addition, opera-tions needs only worry about one setof bearings and seals, not two.

OFS capacity controlsThe advantage do not end there.

OFS compressors are similar to mul-tistage centrifugal units in the meth-ods by which capacity control isachieved. The three major forms ofcontrol — inlet throttling, gas recir-culation, and variable speed — stillapply. However, OFS compressorstypically operate in the 3,000–8,000rpm range, so they are well belowtheir typical first critical speed of12,000 rpm. This makes them excel-lent variable speed machines. Theycan be operated down to roughly 50%of design speed, depending upon theapplication, and the entire range canbe used unless an unusual vibration isfound at one of the speeds in between(this is rare).

As mentioned previously, thestyrene process uses water. It alsouses steam, so the existence of boilersallows for over-sizing and use ofsteam turbine drivers. Unlike cen-trifugal compressors, which requiregear speed increasers most of thetime when steam turbines are used,OFS units often run near the steamturbine (backpressure, single-stagetype) effective speed of 4,000–6,000rpm. For styrene, this has allowed theuse of direct-driven OFS compressorswith steam turbine drivers.

OFS compressors depend upontheir rotors’ ability to capture gas andpush it through a smaller space at thedischarge. This means that the mostimportant variable in the aerodynam-ic equation is the rotor tip speed.Users should not be concerned thatsmaller OFS units run at7,000–10,000 rpm, since the smallerrotor diameter reflects a desired tipspeed. In most cases, OFS compres-sors should operate in the 80–110 m/stip speed range. Anything over 110m/s, on a standard 4/6 male/femalelobe configuration, should be exam-ined carefully and be proven by the

manufacturer that offers it. In the 4/6configuration, a male rotor has theinput shaft, the female rotor is besideit. They are “mated” for fit and mustbe replaced as a set.

Note that tip-speed limitations aremore easily achieved by large malerotors, say 630 mm dia., than smallerones, which can go down to 127 mm.Some manufacturers have offered 91mm dia. versions, but these are verysmall and would have to be run in ex-cess of 12,000 rpm to achieve perfor-mance-efficient tip speeds.

OFS compressors are shown onthe P2/flow chart (Figure 2). They aregood to inlet pressures of 150 psi,and, in some cases, to 225 psi. Theycan be used to discharge pressures of350 psi and, sometimes, 400 psi. Re-cent developments have allowedflows up to 80,000 m3/h or 47,000acfm. These higher flows can only berealized with discharge pressures of200 psi or less, but this has made agreat impact on hydrogen recircula-tion and styrene.

One disadvantage that the OFSunits have is that they use four shaftseals. Centrifugal compressors useone (single-stage) or two (multistage)seals, while OIS types need only one.Four seals are expensive, necessitat-ing the use of dynamic dry gas seals.Four of these and a buffer system canadd $250,000 or more to the cost of acompressor.

OFS compressors are very goodprocess machines. Unfortunately,they have been underused in the U.S.,due to operators’ lack of experiencewith them as opposed to centrifugaland reciprocating types. They wouldmake excellent ethylene andpolyethylene units, compared withmost centrifugals that are used inthese processes today. In a recentcomparison, an OFS screw packagewas bid at $800,000 for a single-stage, direct-driven unit vs. a $1.5million centrifugal. However, the ro-tating engineer recommended thecentrifugal, due to his comfort level.He had never used an OFS before,but had used centrifugal units often.

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The company bas ica l ly pa id$700,000 more for a compressorbased on this inexperience.

Oil-injected rotary screwcompressors

OIS compressors were introducedin 1958, and their most famous fea-ture, the slide valve, was invented in1959. Once again, both developmentsoccurred in Europe, so that the U.S.has been behind the times ever since.API 619 did not include this type ofcompressor until the very latest edition(3rd), which was released in 1997.

The OIS compressor was first ap-plied in the air market in the 1960s,and, by the 1980s, these units weredominant. In the 1970s, they enteredthe refrigeration market, and becameprincipal by the late 1980s. A decadelater, acceptance grew in the fuel gasmarket, and, by the 1990s, they wereused on fuel gas wherever they could,only limited by their own pressure ca-pabilities.

Figure 9 is a packaged OIS sys-tem, rated 250 hp, for compressingboiler off-gas at a liquefied propanegas (LPG) facility. The compressor isat the right of the photo, and the boxat the left is a fan cooler.

OIS compressors will likely be-come the machines of choice in mostvapor recovery, fuel gas, and otherprocess gas industries by 2015. Threeengineering developments have oc-curred to make this so: lubricant ad-vancement, gas filtration to levelsbelow oil-free standards, and pres-sure/flow improvements.

Until the mid-1980s, OIS unitswere heavily limited by lubrication.The lubricants available would easilybe oxidized, diluted, and brokendown, unless used on gases that wereinnocuous, such as ammonia. Airwould oxidize the oil, water wouldcause foaming, and hydrocarbonswould dilute the lubricant. These ini-tial issues caused reliability problems.The fact that mechanical engineersand operators were accustomed to re-ciprocating compressors did not helpeither. For these reasons, screw com-

pressors received a bad reputationamong U.S. engineers, and were nottaken seriously until the 1990s.

Custom lubricants came about in the1980s and the landscape changed.Now, air compressors run longer, cor-rode less, and require fewer oil change-outs than before. Hydrocarbon gases nolonger dilute the lubricant beyond use-fulness and water can be controlled.Lubricants have evolved from hy-drotreated mineral oils to synthetics,such as polyalpha olefins (PAOs), poly-ol esters (POEs), and polyalkylene gly-cols (PAGs). Currently, there are alsoadditives that can be used, such as an-tioxidants, antihydrates, and anticorro-sives. Lubricants are even available invarious viscosity grades, so that dilu-tion can be planned and accounted for.

The industry maximum acceptabledilution rate is 20% by gas to oil. OIScompressors should not operatebelow 12 cSt, or higher than 300 cSt,so an established range can be main-tained by a specific lubricant and vis-cosity grade. This has allowed exten-sive use of OIS compressors in hy-drocarbon service.

Most recently, filtration companiesthat were players in the medical fieldhave entered the commercial gas filtra-tion arena, and another evolution willresult. In the past, effectively cleaninginlet gas to 0.3–1.0 µm, or reducingoil carryover in the gas to less than 1

ppm were either not possible or ex-pensive — but this is no longer so.

With better inlet filtration, OIScompressors can now be used morefrequently with gases that containparticulates, such as carbon fines.These fines normally fall in the 1–10µm range, so they would passthrough traditional inlet filters. Now,filters can be designed for 0.5 µm andwill stop the smaller 1 µm particles.

Ensuring oil-free serviceMore importantly, oil/gas separa-

tion has evolved to such an extent thatgas compressor packages can nowcost-effectively guarantee an oil con-tent of 0.01 ppm or less in the gasstream leaving the skid. A standard foroil-free was set by the InternationalOrganization for Standardization(ISO), Geneva (www.iso.ch/). The or-ganization’s ISO 8573-2, “Com-pressed Air for General Use — Part 2:Test Methods for Aerosol Oil Con-tent,” (1996) is a specification createdto standardize what process engineersconsider being oil-free and how thevalue can be verified. Although thisspecification is written for air, the 0.01ppm figure put forward by this docu-ment has widely become accepted asthe value to which equipment shouldbe designed to achieve oil-free status.

The figure is no accident; oilsmokes (mostly aerosols) fall into the


■ Figure 9. Packaged OIS for boiler off-gas at a liquefied propane gas facility.

0.01–1.0 ppm range. They could notbe filtered by coalescing and filtra-tion elements until very recently.Thus, entrained oil would be cap-tured, but aerosols (or smokes),would get through and could contam-inate a gas up to 1.0 ppm by weight.If 0.01 ppm is achieved, the gas isbasically oil-free.

Oil-free is a truly a misnomer. Oil-free screw compressors and centrifu-gals used on air are not necessarily oil-free. This is because most industrial airis drawn at a petroleum refinery, or achemical or petrochemical plant, andthe atmospheric air is not free of oilthere. Granted, oil is not introduced,but a sensitive process, such as phar-maceutical production or processesusing catalyst beds, would be ruined bythe oil that is drawn in air. Filtration isthe only solution to ensure air, or evengas, quality. The goal is 0.01 ppm.

Reciprocating compressor vendorsaccepted their inability to achieve oil-free status long ago. That is why theyare called nonlubricated reciprocatingcompressors, instead of oil-free. Ofcourse, nonlube recips often do intro-duce oil into the process, sincereciprocating units produceconsiderable amounts of oilvapors.

The third major reason ispressure and flow design. Until1990, OIS units could not ex-ceed 4,500 acfm in a singlecompressor body, now there areunits that can do 10,000 acfm. Untilthe late 1980s, the discharge pressurewas limited to 350 psi, however, recentinnovations have brought standardizedunits up to 520 psi and special designsto 865 psi. The latter units accept a 700psi inlet pressure, hence, their recentin-roads in the fuel gas market.

Depending upon the differentialpressure across the compressor, andthe flow, the inlet pressure may bepushed to 120 psi on ratios below 4:1or be limited to 70 psi on ratios above7:1. In many instances, a process de-sign inlet pressure of 125 psi can bereduced to 100 psi without great im-pact. This small change can reduce

costs by one-half on the OIS com-pressor package. A bare OIS unit isshown in Figure 10.

The fuel gas market is a good ex-ample of how the newer OIS machinescan be used to great advantage over re-cips and centrifugals. Most power gen-erating facilities built today use gas-fired turbines. The incoming naturalgas from the utility normally fluctuatesand must be regulated to the turbinepressures. Unfortunately, the pressureoften dips below the turbine require-ments and compression is required.

On a recent project, the incomingnatural gas ranged from 310 psi to600 psi and the desired discharge was

650 psi. A centrifugal must be de-signed for the worst case, so an inletpressure regulator was required to en-sure that it always received 310 psi,±5%. Thus, if the incoming gas wereat 600 psi, energy would be wasted,since the gas would be reduced thenrecompressed.

On a reciprocating compressor, theentire inlet range could not be accept-ed, due to rod load problems at thehigh end. Again, a regulator or expen-sive unloaders would be required, andthe latter are not always reliable.

The OIS compressor can take theentire range and unload at the high endto reduce energy consumption by 60%.A regulating valve is not required, ei-ther. Thus, the OIS compressor notonly offers the same capital cost as anAPI 11P reciprocating unit, but theclient could purchase a unit that ismore efficient over the entire range ofcompression and more reliable, aswell. The added flexibility of the slidevalve also reduces the size of the recir-culation cooler and saves water.

OIS units are sometimes called oil-flooded, but this term is entirely inac-curate. The oil is literally injected, at apressure higher than discharge, intoseveral key areas of the compressor toprovide lubrication, sealing, and cool-ing. Nearly two-thirds of a fully in-jected screw compressor’s oil goes to-wards cooling, not lubrication. This iswhy OIS units can produce pressureratios as high as 23:1 in a single stage.

Most companies do not use thesemachines at ratios above 10:1, sincethey become extremely inefficient withadiabatic efficiencies dropping to 50%at 15:1 ratios. Normal adiabatic effi-

ciencies for screws, at a single de-sign point, are 70–80%. Howev-er, their true installed efficiencyremains close to those percent-ages, since OIS units are con-sidered among the most effi-cient compressors for overalloperation at different points, due

to the slide valve.This valve is an internal ca-

pacity control device, and is built intoall reputable gas machines, withoutincurring an additional cost. In fact, itis part of the design. The slide valveliterally recirculates the compressedgas before compression is completed.That means that only a little energy isrequired to boost the gas enough sothat it can be internally recirculated tothe internal suction of the machine.

Most slide valves can operate inthe 10–100% range, so 0% flow isachievable with a very small recircu-lation system; GD recommends a25% size. This removes the need forinlet throttling, full-size recirculation,

COMPRESSORS


■ Figure 10. Bare OIS gascompressorwith inletvalve mounted.

or variable speed control. In fact, OISunits do not make good VFD units,since their efficiency is so closelytied to tip speeds in the 50–60 m/srange, and reducing the machine’sspeed would reduce its tip speed.

The slide valve can be instructed toload or unload based on either P1 orP2. Thus, the process has a very sim-ple capacity control device, based onsystem pressures. The slide valve hasalso been proven to be very reliable.

The fact that screw compressorsuse injection oil for cooling is anotherpositive for process design. If a pro-cess engineer would like to maintain adischarge temperature, or if the gascondenses at a known temperature,then the oil injection can be throttledto maintain a preset discharge temper-ature. Using a control valve on themain injection line and a temperaturesignal from the discharge does this.We recommend that a process stay18°F (10°C) above the discharge dewpoint for water, and 25°F (14°C) forhydrocarbon gases. Once the gasmakes it through oil/gas separation,there is no the danger of fouling thelubricant and harming the compressor.

OIS compressors can operate up to10,000 acfm in a single body unit, how-ever, the most cost-effective and com-petitive area is at 5,000 acfm and below.Standard compressors are generallyone-half the price of custom units, but

custom pricing does compare favorablywith most recips. The great advantage isthat standard OIS units can allow forskid deliveries in the 20–26 week range.Figure 11 shows a two-stage OIS, preceded by a blower, all skid mounted.Special casings would push this out to35 weeks, while custom (API 619) ma-chinery normally takes about 40 weeks.All these delivery times are shorter thanthose for centrifugal and API 618 recip-rocating machinery.

The inexpensive screw compressorscan achieve discharge pressures of 520psi, with some cost-effective modifica-tions. Standard OIS gas units canachieve 350 psi at the discharge, andthis pressure level provides the buyerwith many market options and createsa healthy competitive bid situation.

The main negative found in OISunits is that they do require fairlyclean gas at the inlet during normaloperation. They handle upsets betterthan recips and centrifugals, but theycannot do so on a continuous basis.Oil carryover is really no longer anissue with the improvement in filtra-tion technologies. However, polymer-izing gases are still a problem, sostyrene and butadiene applicationswhere these gases are above 20%content are definitely not recom-mended. Even antipolymerizingagents have been unsuccessful onOIS units.

To sum upIn the end, the process conditions

and gas will dictate which is the bestcompressor for a particular applica-tion. If a process engineer properlyuses the information presented here,then the choice for the right compres-sor will become abundantly clear.

The engineer must understandwhere the flows and pressures are inrelation to available equipment, andsee if the process can be adjusted tomeet the capabilities of units that arereadily available, reliable, and inexpen-sive for the application under study.Working with the mechanical depart-ment and compressor vendors, theright compressor will lead to the rightfinal process conditions, or vice-versa.

The most important advice is tokeep an open mind, and use an itera-tive selection process. Any systemsengineer or economist will tell youthat working in a closed loop withoutfeedback will lead to ruination. Openthat external loop, gain that externalfeedback, and a marginal process canbecome a great one. CEP


D. G. Jandjel is product manager, gas

compressor systems, for The Gardner

Denver Engineered Packaging Center

(formerly Allen-Stuart Equipment), Houston

((713) 896-6510 ext. 131; Fax: (713) 896-

1154; E-mail: [email protected]).

He is involved in all aspects of marketing,

sales, and management of the company’s

gas compressor division, and is responsible

for major accounts, worldwide. His technical

duties include reviewing engineering data,

selecting the most appropriate systems for

bidding, and client liaison throughout

production and testing. He has conducted

seminars for over 50 major clients and has

extensive experience in specifying, costing,

troubleshooting, and engineering

compressors. Prior to his current

employment, he was a manager for both

Howden Compressors and A-C Compressor

Canada, Inc. He began his career as a

mechanical engineer with Ingersoll-Rand

Canada, Inc. Jandjel holds three degrees: a

DEC in pure and applied science from John

Abbott College, a bachelor’s in mechanical

engineering from McGill University, and an

MBA, also from McGill.

All photos courtesy of Gardner Denver, Inc.

■ Figure 11.Landfill gascompression. Firststage is handled bya blower; secondand third by two-stage OIS unit.

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