Select the Right Compressor (CEP)

COMPRESSORS

Select the Right Compressor

D. Gregory Jandjel, Gardner Denver Engineered Packaging Center

I

©Copyright

2000

American Institute of Chemical Engineers. All rights reserved. Copying and downloading permitted with restrictions restrictions..

Making the best choice means understanding how flows and pressures relate to available machines, and seeing if your process can be adjusted to meet the capabilities of units that are readily available, reliable, and inexpensive.

n any process, numerous components are required to make the entire concept work. As with any vehicle, processes require an engine and, where gases are involved, the motive force is usually a compressor. This article will attempt to shed some light on the different types of compressors, how they can be selected, and the differences between air and gas units. The gas compressor holds a special place in most mechanical and chemical engineers’ minds, and thoughts can range from admiration to hatred. The reason for this is that compressors are usually the most complex mechanical units in a process; as a result, they must be understood and selected carefully. carefully. A poorly selected unit will not only be unreliable in its own right, but also it will be less flexible to the inevitable changes that occur when most processes evolve from theory to practice. Compressor engineers will tell you that the majority of problems associated with the units in service can be traced to the process, the selection of the compressor itself, or to poor packaging. For the uninitiated, packaging refers to all of the components that allow a compressor to operate. These include drivers, couplings, lubrication and sealing systems, controls, and filtration. If a plant is operating as planned, and the proper compressor is chosen, most issues

that do arise are from items such as poorly sized coolers, pump failures, and so on.

The process engineer’s role The packaging decisions should be left to the rotating-equipment, mechanical, or maintenance engineers on any project. The process itself and the application of the right compressor fall squarely on the shoulders of the process engineer. If a flow scheme is already fixed, and the conditions required of a compressor are unrealistic, then there is very little that the mechanical engineer can contribute after the fact. Thus, a rudimentary knowledge of what existing, commercially available compressors can do is necessary for a good process design. Keeping the numerical possibilities in mind while forming pressure/temperature/ flow relationships can save a company a tremendous

Chemical Engineering Progress

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COMPRESSORS

amount of both its time and money. Compressor inlet pressures P1 are as important as the discharge pressures P2, since many commercial machines are limited on the inlet side. For example, there are numerous relatively inexpensive, oil-injected screw (OIS) compressors suitable for process gas duties that are limited to values of P1 of 100 lb/in. 2 (psi) (all pressures here are gage, i.e., psig, unless otherwise noted). Specialized OIS compressors can accept a P1 of 700 psi, but these are more costly and have longer deliveries. Most oil-free screw (OFS) units designed for gas applications are limited to 150 psi at the inlet. There are special cases when they can achieve a P1 as high as 225 psi, but these must be checked on a job-to-job basis. Reciprocating (recips) and centrifugal types are available at nearly all inlet pressures, but the centrifugals can become costly under P1 and P2 conditions where special pressures or multistaging is required. These will be discussed in the centrifugal section below.

Gas compressors The compressor industry is segmented into numerous sections and subsections, and recent economic conditions have created considerable crossover as compressor suppliers jockey for position on their next sale. Fundamentally, there are two major areas: gas and air. Gas compression is the more difficult, since the processes they drive are normally very expensive and gases must be handled delicately to avoid leakage, unwanted condensation, other phase problems, and flash points. Different gases also have varying market demands, which affect the way a compressor is built and purchased. Industries with high demand and volume will have gas compressors “built for duty” and numerous competitors, resulting in low prices. Refrigeration is the best example. While the exact numbers are difficult to ac-

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e r g u S e d t c p e x E

2

P , e r u s s e r

Rated Point

Preswirl

P e g r a h c s i D

-12

60

45

30 0

75 Approximate I GV Positions, deg. Inlet Volume

s

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

15,000 Diaphragm 15,000 psig/100 acfm Reciprocating 6,000/6,000

5,000

g i s p ,

2

P , e r u s s e r P e g r a h c s i D

3,000

1,000

Centrifugal 5,000/4,000 (Start 200) 3,000/10,,000 2,000/30,000 1,500/100,000+

800 Oil-Injec ted Rotary Screw 870/10,000 (Start 150)

600

400 Oil-Free Rotary Screw 400/50,000 (Start 250)

200

Rotary Vane 150/4,000 0

0 100

500

1,000

5,000

10,000

50,000

100,000

Flow Rate, acfm s

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

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


and volume, but standardizing the machines is difficult, since their P1 / P2 / flow relationships are widely varied and inconsistent. Hydrogen is a good example where there are many applications, but disparate flows and

pressures make it very difficult to design one set of off-the-shelf equipment to cover the variations. Some of the major gas compressor markets, and uses, include vapor recovery (which can also be subdivided into many sections), production, transmission, fuel gases (power generation and boilers), refrigeration, and processing. The refrigeration, fuel gas, and gas transmission industries are very large and consistent, hence, many standardized compressors have been created to reduce cost and gain market share. Even these industries find that conditions upon which gas compressors are sized vary to such an extent that it is difficult to produce equipment to cover the entire market. As a result of the different gas conditions found in the marketplace, broad ranges of customized compressors are available. These will typically cost more than standard units, such as those built for air or the more common refrigeration and wellhead gas service. The delivery times for these units are also longer, as most are built from the moment a purchase order is placed, unlike air units, which are built ahead of time based on market estimates. All API-based compressors, except for American Petroleum Institute (Washington, DC) API 11P recips, are custom builds, so that the user should expect deliveries in excess of 35 weeks for a package. Centrifugal and OFS options, built to API standards, often have deliveries approaching one year from order. (Since many API standards will be mentioned here, their titles and content will not be mentioned. For more information, see API’s Web site: www.api.org/.)

Air compressors Although air is a gas, the incredible volume and competition in the air market has bred an entirely different line of compressors. From a corrosion standpoint, air is actually a very difficult gas. It contains two oxidants (O 2 and CO2), and water is normally pre-

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 in the gas • Gas flow • Gas discharge pressure required • Discharge temperature limitations • Drive selection: For gas engines or t urbines, provide the fuel gas lower heating value (LHV), temperature, and pressure For steam turbines, provide the steam temperature, inlet pressure, and acc eptable backpressure • For air or water cooling, provide the design temperature of the medium • Level of specification: Manufacturer’s standard “ Near” API API specifications with client inputs Client’s specifications Oil 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 c ooling Level of specification

sent. However, air is drawn from the atmosphere, and if a compressor leaks, there is little harm. With a P1 variance of roughly 11.2 –14.7 psia and well over 90% of applications using a P2 of 100–150 psi, it has been relatively easy for the world ’s air compressor manufacturers ’ to “dialin” their designs. They have complete lines of products that are built with considerable capacities, using components that are only acceptable to air or nitrogen. Companies such as Gardner Denver (GD) produce thousands of OIS compressor air-ends per year. Air compressors are normally lightweight and use materials, such as bronze, which would not be acceptable for most gases. Thus, air units should always be treated separately

from those handling process gas. Only some reciprocating units (including some made by GD) have found success in crossing over. However, despite using the same frame, even these units have differences in internal construction, depending on whether air or gas is used. An aero-derivative screw compressor has made inroads in the gas production arena, specifically wellhead gas. Once again, these units are constructed differently from the standard air units; they are engineered such that they service wells that typically have 5–7 year lives. Process gas compressors should be selected from the moment the process design begins. Operating companies that are successful with their com-


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COMPRESSORS

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

OIS

OFS

Centrifugal

Reciprocating

Principle of operation Maximum P 1, psi Maximum P 2, psi Maximum flow, acfm Maximum T 2,°F Pulsation Surging First critical speed M aximum pressure ratio/stage Design point efficiency Off-design efficiency Oil-free status Polymer gas applications API continuous run, h 5-yr reliability/uptime Standby required§ Installation area Noise level (w ith enclosure) Vibration level Sensitive to vibration Capacity control Discharge accumulator Discharge temperature control Variable inlet pressure Method of P 1 variance Part-load pow er Gas composition effect Low est molecular weight Starting torque Installation costs Spare parts cost Operation cost M aintenance required

PD-OIS 700 865 10,000 250* None No Below 23:1 70 –85% Excellent Filters needed No 16,000 98 –99.5% No X 85 dB Small No 15 –100% No Yes Yes Slide valve Low Small 2.0 Low Low Low Low Low

PD-OFS 225 400 47,000 400 –500 None No Below 5:1† 70 –85% Fair Oil-free Yes 24,000 99 –99.5% No 2X 85 dB # Small No Recycle No Possible Yes Recycle High Small 2.0 Low Medium Medium Low Low

Dynamic Close to P 2 1,500 –5,000 100,000+ 350 –500 None Yes Above 1.5 –3:1 70 –88% Poor Oil-free Difficult 24,000 97 –99.5% No 2X 85 dB Small Yes 70 –100% Yes No No PCV¶ High Large 10.0 High Medium High Low –medium Low

PD Close to P 2 (Depends on rod load, as well) 6,000 6,000 300 –400 Large No Below 5:1 75 –92% Fair Filters‡ No 8,000 90 –95% Yes 4X 90 dB Large No Step or recycle Yes No Limited SVU** /PCV¶ High Small –medium 2.0 (Special distance piece) High High High Medium –high 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 w ith silenc ers. ¶ PCV is pressure cont rol valve. ** SVU is suction valve unloader.

pressors normally try an iterative process. The engineer designs an initial process that fits the range of what the market has available, then these conditions are sent to various compressor vendors and feedback is provided on issues of feasibility, availability, price, and delivery. The process engineer than incorporates the revised pressures, temperatures, and flows into a workable process model. Naturally, this procedure may involve mechanical and maintenance engineers, a corporate rotating-equip-

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ment engineer, or an engineering consultant. In the end, process engineers should know a little about what compressors can do, and mechanical engineers should know a little about what a process’ needs and limitations are.

Compressor sizing information Important sizing information, required by compressor vendors and packagers, is listed in Table 1. Compressors are sized on absolute inlet pressure (psia), inlet temperature,


inlet flow, and gas characteristics. Positive displacement (PD) types, which consist of all models other than centrifugals, are sized on actual inlet volume (actual ft3 /min (acfm)). For most reciprocating and rotary screw applications, the discharge pressure becomes almost secondary in the selection of the physical size of the unit. However, knowing the discharge pressure is necessary, since it will dictate whether the compressor is capable of the desired pressure, whether the gas will remain gaseous throughout

out the curve). In fact, if a PD blower is sized properly for the pressure ratio required, the flow might drop by a few percentage points if the ratio is increased or decreased by more than 10%, due to volumetric efficiency. Table 2 compares the four basic types of compressors.

1,600 1,400 Reciprocating 1,500 psig/300 acfm 600/400 300/2,000

1,200 g i s p ,

2

P , e r u s s e r P e g r a h c s i D

1,000

Forestalling against surge

800

600

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

400 200/150-2,000

200

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

Dry Screw 0

200 100

400 300

1,500 500

2,500 5,000 3,000

10,000

20,000

30,000

40,000

Flow Rate, acfm s

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

the compression cycle, the number of stages required, and what the power requirement for the unit will be. Centrifugal compressors are dynamic, which means that their performance is “curved” and depends tremendously upon inlet flow and discharge pressure requirements. Figure 1 shows the typical pressure volume relationship for these devices. Note the P2 curves downward as the flow increases; this is found in all dynamic compressors. The multiple curves are for different inlet guide vane (IGV) settings on a single-stage compressor. IGVs are pneumatically actuated vanes at the entrance of the compressor that alter the gas flow and create a pressure drop. Unlike butter fly valves, they are quite efficient at 80–100% of compressor-design flow rates. The amount of turndown obtained by using IGVs depends upon staging. Single-stage units will typically be capable of 65–105% of flow range with IGVs, while the effect is closer to 90–100% on multistage machines. The 105% is achieved on sin-

gle-stage units by “preswirl,” which is possible by reversing the IGVs. Centrifugal units can be seen as fixed-ratio compressors, which means that only a ±5% change in inlet pressure is normally allowed for a fixed discharge pressure. Dynamic compression results from the conversion of gas velocity to pressure. Thus, molecular weight (MW) plays a key role, since the selection of the compressor is directly related to the head calculation for the process. This is why centrifugals are not used for hydrogen, or other low-MW gases. The head is simply too high for a cost-effective solution when the MW dips below 10. When the MW is below 5, a centrifugal selection is almost impossible, since the head may be at or well over 100,000 ft. The main difference that a user sees between PD and dynamic compression is that the former ’s compressors do not provide a signi ficant increase in flow with a drop in discharge pressure, whereas dynamic compressors do (this is called riding

By the same token, while PD units can produce 20% higher discharge pressures (or more) with only percentage-point changes in flow, dynamic units can only rise in pressure marginally with a heavy payment in flow and a very great danger of approaching surge. Surge is when a centrifugal compressor approaches the end of its curve at the left (Figure 1). It is best to keep the compressor operation at least 5% (by flow) to the right of this line. Physically, as the compressor approaches surge, vibration begins and increases as you approach the surge line (a line drawn by connecting all the left-most points on the IGV curves). Vibration is quite severe and can heavily damage a compressor whose impeller(s) may be spinning anywhere from 7,000 –50,000 rpm. For this reason, all centrifugals should be purchased with a surge system, which unloads the machine via recirculation, as conditions approach surge. Reciprocating, screw, and other PD compressors will push the inlet gas against whatever system resistance exists at the discharge. This is why high-pressure shutdown and relief valves are so important. PDs will continue to push until the system is satisfied, or something else gives (system resistance, unloader setting, recycle setting, alarms/shutdowns, or the relief valve). Apart from volumetric efficiencies, which can vary from 70–95% depending upon the selection vs. requirement relationship, a PD unit will compress the same amount of actual flow through its cylinder, regardless of pressure, temperature, or MW. Naturally, one could get into se-


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COMPRESSORS

mantics over the issue of volume consistency in PD equipment, but when you compare a 25% variance with the 100+% found in dynamic units, the argument holds true. Thus, a compressor system vendor must know the inlet absolute pressure and inlet temperature, along with the flow to calculate the acfm and peg the proper compressor sizing. Reciprocating unit flow results from the multiplication of cylinder volume (based on stroke and diameter), number of cylinders, actual rpm, and volumetric efficiency. Screw unit flow is based on swept volume times rpm times volumetric efficiency. This illustrates the need for an acfm calculation by the vendor and the fact that the voltage must be known for motor drives, since the calculation depends on rpm, and many PD compressors are direct driven. The compressor vendor, due to skid pressure drops across each side of the compressor, should calculate the acfm. Vendors prefer to be given the process flow requirement in standard ft3 /min (scfm), (normal) nm3 /h, lb/h, or kg/h, to ensure accuracy in sizing. This is why the gas composition or characteristics are so important.

Effect of k-value If the buyer ’s gas composition is yet to be finalized, the buyer ’s guess on MW, the ratio of heat capacity at constant pressure to that at constant volume Cp / Cv, and the compressibility Z will still be much better than the vendor ’s. The MW and Z are obviously necessary for flow calculations, particularly if the flow is provided in the desired standardized or mass- flow format. However, Cp / Cv, often known as the k -value, is crucial as well. The k -value is used in various calculations, including horsepower and mechanical volumetric requirements for PD compressors. On centrifugal types, the MW is critical, since the head calculation is so heavily affected by this number (the larger the MW, the lower the head), and the head directly affects the power requirement.

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On PD units, the k -value directly affects the power requirements, and the calculation of it, for bidding purposes. Heavy hydrocarbon gases, such as propane, butane, and propylene, have k -values around 1.14 under most inlet pressure/temperature conditions. Air, nitrogen, and hydrogen are typically at 1.4. Helium can be higher than 1.6. If there were two processes, one with propane and one with air, using identical numbers except for gas composition, the power used by a PD compressor could be 5 –10% higher for the air than the lower k -value propane. This can often mean a frame break in the compressor driver, and this has a significant impact on the temperature rise across the compressor. A frame break is a jump from one size to another. If the jump is from smaller to larger, then it can be costly. Temperature rise affects oil cooling and gas cooling, so the entire system can be affected if cost estimates are based on a 1.15 k -factor, and the final design balloons to 1.3, for example. There is one final note about the gases lighter than 10 MW, speci fically hydrogen and helium. Although PD compressors, notably reciprocating and screw units, are the best for these low-MW gases, these lighter gases are “slippery” and tend to result in lower volumetric efficiencies in the 70–85% range. “Slippery” means that the gas molecules are small and their density is light, so it is difficult to “capture” the gas and make it go where you want it to go. Thus, when compared to a typical natural gas (MW of 17 and k -value of 1.28), hydrogen and helium will require a roughly 10% larger machine, due to lower volumetric efficiency, and 5–10% more horsepower, due to the higher k values. For the purposes of this article, some rules of


thumb will be presented to help guide the process engineer through the availability and selection process. This becomes necessary since nearly every compressor manufacturer has equipment with different pressure and flow capabilities. However, the marketplace will always dictate what is purchased and what is a fringe player, and any good engineer must have bottom-line sensitivity in this day and age. Figure 2 shows the general area where the various types of gas compressors are cost-effectively available in terms of pressure and flow. Figure 3 does this for the air machines. The main types of compressors used in the industry are reciprocating, rotary screw, and centrifugal; lesser selected are rotary-vane, liquid-ring, and diaphragm machines. Only the major ones will be discussed at length in this article.

Reciprocating compressors In the U.S., from the 1900s to the 1960s, the reciprocating compressor became the workhorse for all compression (Figure 4). These have been used in nearly every application, in almost every conceivable way. Although their population is dwindling, and annual sales volumes have been in steady decline since the 1970s, these machines’ capability in handling large s

Figure 4. Bare Y-type reciprocating compressor.

s

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

pressures and small flows, along with single-body/multistage availability, will keep them a necessary part of the landscape for the foreseeable future. Another benefit that reciprocating units provide is their ability to be used as nonlubricated. This means that no oil is injected into the cylinder. If the distance pieces are long enough and purged, then there should be no introduction of oil vapors into the process either (reciprocating units produce a tremendous amount of oil vapors, which can slip around the rings, if the cylinder is not designed to stop them). The result is that nonlubricated recips are often a cost-effective solution in providing a low-oil content (vapors), or oil-free gas. (Distance pieces define the length between where compression takes place (the piston area) and the location of the oil (the crankcase).) These devices are also the most efficient method of compressing gas at a specific condition (under a given P1, T 1, and P2). They can be multistaged easily, and if the unit is lubricated, then adiabatic efficiencies in the 80–92% range can be achieved. Figure 5 shows three machines staged together in parallel, used for boosting natural gas in a cogeneration facility. Figure 6 presents two recips used for natural gas peak –demand shaving. Unfortunately, if the process has many off-design points or if the compressor is oversized, the efficiency gains at design are lost at part-load. This is why variable-speed drivers and unloading valves have become popular, and sometimes expensive, alternatives to the standard recycle system setup. The one major negative, which maintenance people are well aware of, is that reciprocating compressors are maintenance-intensive. This means that their reliability percentage (oper-

ation percentage over 5 yr) is among the lowest of the compressors available, and that the repairs themselves can be costly. Most reciprocating units fall in the 92–95% reliability/availability range, while screws and centrifugals can achieve 98–99.5% levels. Another problem that users have encountered is the pulsation and unbalanced forces created by the reciprocating, or piston motion. This requires special foundations and pulsation suppressors, while the other types do not. Mainly, reciprocating compressors are most cost-effective when the process P2 is above 865 psi at the discharge and the flow is less than 2,000 acfm. These devices are also good for pressures above 500 psi, if the flow is less than 300 acfm. In general, reciprocating units are the most competitive type at any pressure, if the flow is less than 200 acfm. The nonlubricated forms are very competitive across the range, as well. Recent innovations in OFS and filtration technology have resulted in the use of OFS and OIS compressors on many oil-free applications. In processes that involve low MWs, typically below 10, with pressures above 350 psi, recips are still very popular. Above 870 psi, they are the only solution, due to the abovementioned difficulties that centrifugal units have.

Diaphragm compressors A variation of the reciprocating compressor is the diaphragm machine. This derivation uses reciprocating mo-

tion, but has no cylinder. The piston rod actually moves a plate back and forth, creating compression via the moving diaphragm. These movers can achieve the highest available pressures in the marketplace, roughly 15,000 psi. However, the largest unit can barely handle 100 acfm. Small flow is simply the nature of this unique form of machine. Diaphragm units are used mostly on high-pressure gases in R&D or other small-flow processes. They are sometimes used as the final booster in a chain of compressors to achieve a pressure above 5,000 –6,000 psi. Capacity control is normally handled through recirculation of gases, or blowing off of air. As the compressor only sees the full design flow under these circumstances, part-load power is the same as for full load. Steppedunloading is available, through the use of various suction and cylinder valving techniques. By disabling or enabling suction unloader valves in different cylinder combinations, varying flows can be achieved. Unloading normally come in threestep (0–50–100%) or five-step (0–25–50–75–100%) jumps, and the method is especially popular for the API 618 compression units. Unfortunately, field personnel are forced to


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COMPRESSORS

s

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

live with the decision of using step unloading, which is often unreliable. It is not unusual for operations personnel to disable or remove reciprocating unloaders sometime during their operating life, to reduce maintenance costs and increase running time. Another solution for the capacity control issue is using a variable speed drive. At first glance, this is the best solution for efficiency and power savings. However, 21st century budgets are tighter than ever and variable frequency drives (VFDs) for motors are expensive. Also, when using VFDs, it is important that a transient torsional study be done to avoid rod load problems on the compressors at certain speeds.

Mechanical loading Reciprocating compressor frames are no longer rated by horsepower, since the piston rod load rating is a far more accurate predictor of the mechanical strain on the unit. It is common for corporate speci fications to state that rod load shall not exceed 90% of the continuous operating design for the frame. Rod load capabilities increase with the size of compressor, so actual numbers would not be relevant or helpful to this article. What is helpful is knowing that certain combinations of pressure ratio

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and flow will load a compressor more or less. By verifying the load of a specific application against the published maximum for the compressor chosen, the mechanical engineer can verify mechanical loading. Typically, reciprocating compressor cylinders can handle pressure ratios of up to 5:1 in a single stage, and can generally be offered in up to six stages, depending upon the gas and rod loading. Both gas temperature and rod loading become issues, which assist the compressor engineer in deciding whether multistaging is required. Note that API 618 does not allow any cylinder to have a discharge temperature above 300°F. However, many wellhead gas applications have used lubricated cylinders to a maximum of 350°F per cylinder. In the air market, some vendors have approached 400 °F per cylinder, on lubricated cylinders, to reduce staging and increase cost benefits to the client. The main problem with elevated temperatures is that ring-life and valve-life are reduced; in some cases, dramatically. Newer materials have allowed the recent elevations, but any lubricated cylinders operating over 325°F, or nonlubricated cylinders above 300°F, should be examined carefully.


It is not unusual for piston rings to wear and be replaced annually. The cylinder valves should last longer, somewhere between 1–2 yr. In both cases, the nonlubricated cylinder parts would have shorter lives than the lubricated ones in the same application. Reciprocating compressors come in three formats: 1. Low-speed (300 –500 rpm), long-stroke (7 in. and more), per API 619. 2. Medium-speed (500 –800 rpm), medium-stroke (5–7 in.), GD/Joytype units. 3. High-speed (900 –1,800 rpm), small-stroke (2–6.5 in.), per API 11P. Reliability is not too different between the types, but preferences and features will guide the buyer toward one or the other. The important thing to remember with recips is that average piston speed is important, not the actual rpm. Piston speed is a function of rpm and stroke length. Normally, users will accept piston speeds in the 600–800 ft/s range. Nonlubricated process applications would normally be sized below 600 ft/s, per API 618. The GD-type and API 11P units are the most cost-effective and have steadily gained market share over the traditional “slow rollers” that API 618 specifies, but the traditional machine is still popular in highend/high-dollar processes. As highend processes have been the last to see recent budget demands, and the dwindling API 618 market has caused ferocious competition between the numerous suppliers that remain, this may not change for some time.

Centrifugal compressors The centrifugal compressor is extremely popular, mostly because nearly all are oil-free. Centrifugals also have oil-vapor and aerosol problems, but most process units can be considered oil-free, due to the special seal arrangements that are used. Another tremendous advantage these machines have over all others is the enormous flows (100,000+ acfm) that some units can compress in a single body,

with a high-pressure (1,500 –5,000 psi) capability. Centrifugals are dominant in the large gas-pipeline transmission industry, where hundreds of thousands of cfm must be compressed to 1,000 psi after considerable line losses. They are typically placed every 100 miles of pipe, or closer, and are critical to the transmission of natural gas throughout the world. In process use, they are used for large flows, high pressures, and heavy-MW gases, and are popular on the critical process paths found in most petroleum refineries and petrochemical plants. These are locations where you find the larger flows and, with the extensive use of catalysts, the oil-free feature is important. From a cost standpoint, centrifugals seem to do best when flows are larger. There is not much choice with the other types above 50,000 acfm. As Figure 2 shows, there are also many combinations of high pressures with even larger flows that simply make the centrifugal the only choice. In the psi/acfm coverage areas where all the types meet, centrifugals are normally used in specific processes that have fixed pressure ratios and require oil-free gas, particularly with pressures above 400 psi. Normally, if a centrifugal is similar in cost to a reciprocating unit, the centrifugal should be chosen for its reliability in service and relatively large maintenance intervals. Still, while centrifugals are costly to fix, particularly anything involving the rotor/impeller or seals, lifetime costs are normally below those of the recips. The reliability advantage is a significant point for both screw compressors and centrifugal units. Reciprocating compressors must often be “spared,” i.e., with a standby spare unit, due to their low reliability percentage. Centrifugal packages built to API standards are intended to be used without spares, and have done so with reliability in the 99%+ range. These high-reliability units are normally built to API 617, using API 613

gear boxes, API 541 motors, API 671 couplings, and API 614 lube/seal systems. When steam turbines are used, API 611 (general purpose) or 612 (special purpose) turbines come into the equation. API 617 centrifugal compressors typically operate in the 8,000–15,000 rpm range and use gear boxes driven by the main driver. There is another specification, API 672, for integrally geared centrifugals. Machines made to this standard are intended for air service only, but some users have purchased them for clean gas applications, such as pipeline-quality natural gas boosting. The main problem with the 672-type units is that they are bullgear driven by 2-pole motors and the impeller/pinion operates at around 30,000 –50,000 rpm. The internal gearing, high speeds, and limited shaft seal designs make this type of centrifugal less reliable (98 –99% range) than the traditional API 617 variety. Bullgears are large gears where the shaft is driven by the driver. They have smaller gears, often, multiple gears, called pinions that can spin very quickly due to their size vs. that of the bullgear. Centrifugal units are the latest type of compressor to be released by the manufacturers, in bare form, to packagers. The use of packagers has greatly reduced the final cost of the complete skid to the user and may bring about greater use of centrifugal units in more competitive industries such as refrigeration and fuel gas boosting. Capacity control is achieved by inlet throttling (valve or IGV), variable speed, or recirculation. On single-stage machinery, IGVs are the most cost-effective solution, coupled with a recirculation system that can also handle surge. On multistage units, recirculation and variable speed are the best options. The only problem with using variable speed on centrifugals is that, in most applications, the compressor cannot operate over the entire speed range available from the driver. These

units run above their first critical speed; the critical speed is where the first harmonic vibrations occur for rotating equipment, and is normally in the 8,000–12,000 rpm range for most equipment. If you reduce the speed on a centrifugal operating at its design point, you will often find a critical disturbance at around 70 –75% of the run speed. The variable speed driver would then be programmed to ramp through this speed quickly and avoid it by at least 5% on each side. The difference would have to be recirculated from a greater speed, if process off-design of normal flow or other part-load point were needed. The main negatives associated with centrifugal compressors are their comparative costs in pressure/ flow ranges covered by screws and recips, their pressure ratio inflexibilities, energy consumption due to difficulties at part-loads, extreme sensitivity to vibration, and the size of the installation required if full API auxiliaries are required. Typical stages can only operate to roughly 2:1, so multistaging is often required, but intercooling need only take place every second or third stage. These units are available in up to eight stages in a single body. Thus, pressure ratios of 28 are possible. Many vendors also have drivethrough designs that allow two compressor bodies to be connected and use a single driver. This allows for more than the standard eight stages. Stage pressure ratio balancing and impeller selection are critical when using two bodies at one speed. Standard centrifugal air compressors normally come in a three-stage format (Figure 7). This allows discharge pressures up to 150 psi, from a normal sea level inlet (14.7 psia); for longevity, it is best to use them at 125 psi. High-pressure ratios can be achieved across each air stage, since the bullgear design allows for pinion velocities above 20,000 rpm. Although this is fast, and would be questionable on all process gas applications, it is very normal on air and


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s

Figure 7. GD- Turbo centrifugal for air contains three stages.

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

Oil-free rotary screw compressors The original screw compressor was oil-free. Designed in the 1930s by Dr. Lyceum of Swedish Rotary Machines (SRM), the first working prototype was built in Europe in 1939. Commercial use of the screw compressor did not begin until 1946, due to World War II, but its popularity was enormous in post-war Europe during the rebuilding process. In 1948, a group of American businessman obtained a license to build screws from SRM. Americans used these compressors predominately in the steel industry, for coke-oven and kiln gas applications. The steel industry was a dominant player in the postwar U.S., as the country built its infrastructure and the car industry developed into the major player it is today. The OFS compressor was, and still is, favored for these “dirty” applications since it has the unique ability to pass 200 micron-sized particles continuously and without incident. Particles would settle into reciprocating cylinders and cause severe damage to the rings and cylinder walls, and sludging of the oil. The particles in these gases would create a sandblast effect on centrifugal impellers and cause excessive wear, vibration, and downtime. OFS compressors can also be built using exotic metals. The standard machine normally has a cast iron casing with forged steel rotors. However, casings can be made from ductile iron, cast steel, and Type 316 stainless steel. More importantly, an ordinary cast iron or steel casing can be nickel-plated to provide a high level of corrosion resistance and hardness.

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The rotors can be made from different grades of steel, different grades of stainless steel (such as 13-4 and 17-4) and even more exotic materials such as Inconel. It is all a matter of what the buyer can afford. API 619 is the specification that covers OFS units. In contrast, recips have little flexibility in materials choices, with the only major changes normally found in cylinder liners, if they are used in the design of the unit. Centrifugals can also be made in a variety of materials similar to OFSs. OIS models normally use cast iron casings, with most companies offering options to use ductile iron (sometimes called nodular iron) and cast steel. OIS rotors are manufactured in either ductile iron or steel.

OFSs with polymers Polymerizing gases are truly where OFS units shine. Gases such as styrene or butadiene tend to coat any contacted metal with polymer over time. This is disastrous to reciprocating units, since the cylinder and crankcase become overgrown with polymer, and there is a sludging effect of polymer in the oil. Centrifugals have vibration prob-


lems, since the coating either unbalances the impeller or grows out from the casing walls to meet the coating on the impeller, causing a rubbing effect. The coating also reduces diffuser and volute areas in centrifugal units, which hinders performance. For this reason, centrifugal compressors used in low-density and high-density polyethylene (LDPE and HDPE) service must continually be shut down and cleaned, often chemically. This downtime is expensive, not to mention the actual cleaning costs in materials and labor. The OFS compressor actually improves over the life of the polymer coating. These machines are designed so that their timing gears ensure that the two rotors do not actually make physical contact. However, for efficient compression, the rotors must be as close to one another as possible. As a polymer coats the rotors and cylinder walls, these clearances close up and increase the efficiency. The rubbing-effect is not a problem, either. OFS units are solid and probably the least sensitive to vibration. Thus, as the polymer coating rubs

s

Figure 8. Bare OFS compressor, awaiting packaging. The machine will be used in hydrocarbon vapor recovery.

against itself, pieces smaller than 100 µm break off and are released through the discharge without incident. Polymer applications have built-in filtration and scrubbing systems throughout the piping, since polymerized pieces can be formed and released in the piping, vessels, and other components as well. Recently, the OFS compressor has become popular in vapor recovery, particularly offshore. Figure 8 shows an API 619 OFS bare unit, waiting to be packaged. The machine will be used for mixed-hydrocarbon recovery vapor recovery in the Gulf of Mexico. The compressor will be motor-gear driven at 6,260 rpm by an 800 kW motor. Offshore heating tank vapors are no longer flared, but, rather, they are drawn by a compressor and boosted to 100–150 psi. The resultant gas is cooled, filtered, and further compressed to the local sales gas pressure (1,000 psi in the U.S.). In locations such as Alaska and the North Sea, OIS compressors have dominated the vapor recovery unit (VRU) gas booster market that has developed through environmental concerns and regulations. As the North Sea generally was first in most offshore developments, the Brazilian and Gulf of Mexico offshore platforms have been designed with OIS compressors, as well. Unfortunately, the hotter climates have caused higher inlet temperatures to the first stage of compression, which has caused problems in that gases that are nor-

mally condensed during cooling prior to the gas compressor are not at higher temperatures. On northern sites, the typical inlet gas temperature falls in the 60–90°F range with the majority of temperatures at or below 80°F. In the Gulf of Mexico and offshore Brazil, this temperature ranges from 80 –130°F and is mostly 100–120°F. This temperature difference allows hydrocarbon heavies, such as decanes and higher, to remain in the gas in sufficient quantities to condense at the discharge and mix with the lubricating oil. More importantly, since most of these applications are water-saturated, water becomes a big issue as the inlet temperature moves above 100°F. The water content of saturated gas at 120 °F is nearly thrice that at 80°F. Typically, this means that the gas should not be compressed beyond 70 psi to avoid condensation at the low temperatures at which OIS units operate. The combination of lower temperatures and greater funds spent on the early North Sea platforms yielded process conditions that were not duplicated in the Gulf of Mexico. However, existing processes are hard to let go of. This is why some major oil companies have had trouble with equipment in hotter climates, when the very same machines, using the same process (with lower temperatures) worked so well in colder regions. The solution is to correct the process temperatures and pressures, as well as

add better filtration to the newer applications, or use OFS compressors, despite their greater cost. OFS machines can accept mist/aerosol entrainment and the higher discharge temperatures associated with oil-free units flash liquids and keep the unsteady gases in the gaseous phase. Also, the pressure limitations would force the user into interstaging, with cooling and filtering, creating a better environment for the compressor. The National Oil Company of Mexico (PEMEX) has long used OFS units to boost the gas from near atmospheric to discharge pressures of 50 –70 psi. Other companies are still trying to achieve the 100–125 psi levels they are accustomed to with their OIS compressors, but this would mean two stages in an OFS compressor and signi ficantly higher cost. The solution is in the process engineers’ hands. If the process is designed to operate at the highest discharge pressure achievable by a single-stage OFS unit, then the final discharge pressure can be achieved by modifying the already expensive equipment on the back end. Recirculation processes can be adjusted by increasing size of vessels and pipe to limit pressure drop. By the same token, if the process really needs the higher pressure, then the engineer should design to the limit of a two-stage OFS setup, which can be in the 175–225 psi area starting from atmospheric conditions. This would allow full use of the more expensive two-stage OFS units and drop the cost of any compressors that follow, since they would be much smaller, due to a higher P1. In recirculation processes where there may not be further compression, the vessels and piping can be sized much smaller, since the compressor could now overcome much larger pressure drops across the system.

OFSs and liquids Liquid entrainment is also a problem for all other compressors. In many saturated gases, there is a


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steady stream of mist or aerosol in the inlet gas. On centrifugal units, this causes erosion similar to particulate bombardment. On recips, this liquid forms in the cylinder and produces a variety of problems from oil dilution to excessive corrosion and wear. OIS compressors may have problems when the liquid does not flash off in time and slowly accumulates in the lubrication system until it either replaces or dilutes the injection oil. In OFS systems, the liquid entrainment is easily flashed off due to the 450–500°F maximum temperature for a compressor that can sometimes achieve 5:1 ratios (with low k -value gases) in a single stage. This misting liquid capability was used by engineers in the actual design of some process systems. Capital costs for OFS machinery are always competitive to API centrifugal and API reciprocating units, as long as they can be kept in a single stage. What industry has found is that certain gases can accept the introduction of liquids, such as water in styrene, since, many times, the liquid is a part of the process anyway. For example, with styrene, it is commonplace in both the Badger (now Raytheon) and Lummus (now ABB-Lummus Global) processes to inject water into the OFS inlet. Water is shot in as a mist and the flow rate is set to achieve a specific discharge temperature from the OFS compressor, while increasing the pressure ratio to 6:1 to 7:1, due to the discharge temperature drop created by the energy required to flash the water during compression. In low k -value gases such as isobutane, 8:1 pressure ratios can be achieved by reinjecting condensed ibutane from the discharge into the suction. Each stage of an OFS compressor is basically a separate machine, with its own compressor body and driver. Therefore, cramming the application into one stage by either using the temperature maximums or liquid injection can yield a capital

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cost decrease of as much as 50% in certain instances. In addition, operations needs only worry about one set of bearings and seals, not two.

OFS capacity controls The advantage do not end there. OFS compressors are similar to multistage centrifugal units in the methods by which capacity control is achieved. The three major forms of control — inlet throttling, gas recirculation, and variable speed — still apply. However, OFS compressors typically operate in the 3,000 –8,000 rpm range, so they are well below their typical first critical speed of 12,000 rpm. This makes them excellent variable speed machines. They can be operated down to roughly 50% of design speed, depending upon the application, and the entire range can be used unless an unusual vibration is found at one of the speeds in between (this is rare). As mentioned previously, the styrene process uses water. It also uses steam, so the existence of boilers allows for over-sizing and use of steam turbine drivers. Unlike centrifugal compressors, which require gear speed increasers most of the time when steam turbines are used, OFS units often run near the steam turbine (backpressure, single-stage type) effective speed of 4,000 –6,000 rpm. For styrene, this has allowed the use of direct-driven OFS compressors with steam turbine drivers. OFS compressors depend upon their rotors’ ability to capture gas and push it through a smaller space at the discharge. This means that the most important variable in the aerodynamic equation is the rotor tip speed. Users should not be concerned that smaller OFS units run at 7,000–10,000 rpm, since the smaller rotor diameter reflects a desired tip speed. In most cases, OFS compressors should operate in the 80 –110 m/s tip speed range. Anything over 110 m/s, on a standard 4/6 male/female lobe configuration, should be examined carefully and be proven by the


manufacturer that offers it. In the 4/6 configuration, a male rotor has the input shaft, the female rotor is beside it. They are “mated” for fit and must be replaced as a set. Note that tip-speed limitations are more easily achieved by large male rotors, say 630 mm dia., than smaller ones, which can go down to 127 mm. Some manufacturers have offered 91 mm dia. versions, but these are very small and would have to be run in excess of 12,000 rpm to achieve performance-efficient tip speeds. OFS compressors are shown on the P2 / flow chart (Figure 2). They are good to inlet pressures of 150 psi, and, in some cases, to 225 psi. They can be used to discharge pressures of 350 psi and, sometimes, 400 psi. Recent developments have allowed flows up to 80,000 m 3 /h or 47,000 acfm. These higher flows can only be realized with discharge pressures of 200 psi or less, but this has made a great impact on hydrogen recirculation and styrene. One disadvantage that the OFS units have is that they use four shaft seals. Centrifugal compressors use one (single-stage) or two (multistage) seals, while OIS types need only one. Four seals are expensive, necessitating the use of dynamic dry gas seals. Four of these and a buffer system can add $250,000 or more to the cost of a compressor. OFS compressors are very good process machines. Unfortunately, they have been underused in the U.S., due to operators’ lack of experience with them as opposed to centrifugal and reciprocating types. They would make excellent ethylene and polyethylene units, compared with most centrifugals that are used in these processes today. In a recent comparison, an OFS screw package was bid at $800,000 for a singlestage, direct-driven unit vs. a $1.5 million centrifugal. However, the rotating engineer recommended the centrifugal, due to his comfort level. He had never used an OFS before, but had used centrifugal units often.

The company basically paid $700,000 more for a compressor based on this inexperience.

Oil-injected rotary screw compressors OIS compressors were introduced in 1958, and their most famous feature, the slide valve, was invented in 1959. Once again, both developments occurred in Europe, so that the U.S. has been behind the times ever since. API 619 did not include this type of compressor until the very latest edition (3rd), which was released in 1997. The OIS compressor was first applied in the air market in the 1960s, and, by the 1980s, these units were dominant. In the 1970s, they entered the refrigeration market, and became principal by the late 1980s. A decade later, acceptance grew in the fuel gas market, and, by the 1990s, they were used on fuel gas wherever they could, only limited by their own pressure capabilities. Figure 9 is a packaged OIS system, rated 250 hp, for compressing boiler off-gas at a liquefied propane gas (LPG) facility. The compressor is at the right of the photo, and the box at the left is a fan cooler. OIS compressors will likely become the machines of choice in most vapor recovery, fuel gas, and other process gas industries by 2015. Three engineering developments have occurred to make this so: lubricant advancement, gas filtration to levels below oil-free standards, and pressure/ flow improvements. Until the mid-1980s, OIS units were heavily limited by lubrication. The lubricants available would easily be oxidized, diluted, and broken down, unless used on gases that were innocuous, such as ammonia. Air would oxidize the oil, water would cause foaming, and hydrocarbons would dilute the lubricant. These initial issues caused reliability problems. The fact that mechanical engineers and operators were accustomed to reciprocating compressors did not help either. For these reasons, screw com-

s

Figure 9. Packaged OIS for boiler off-gas at a lique fied propane gas facility.

pressors received a bad reputation among U.S. engineers, and were not taken seriously until the 1990s. Custom lubricants came about in the 1980s and the landscape changed. Now, air compressors run longer, corrode less, and require fewer oil changeouts than before. Hydrocarbon gases no longer dilute the lubricant beyond usefulness and water can be controlled. Lubricants have evolved from hydrotreated mineral oils to synthetics, such as polyalpha olefins (PAOs), polyol esters (POEs), and polyalkylene glycols (PAGs). Currently, there are also additives that can be used, such as antioxidants, antihydrates, and anticorrosives. Lubricants are even available in various viscosity grades, so that dilution can be planned and accounted for. The industry maximum acceptable dilution rate is 20% by gas to oil. OIS compressors should not operate below 12 cSt, or higher than 300 cSt, so an established range can be maintained by a specific lubricant and viscosity grade. This has allowed extensive use of OIS compressors in hydrocarbon service. Most recently, filtration companies that were players in the medical field have entered the commercial gas filtration arena, and another evolution will result. In the past, effectively cleaning inlet gas to 0.3–1.0 µm, or reducing oil carryover in the gas to less than 1

ppm were either not possible or expensive — but this is no longer so. With better inlet filtration, OIS compressors can now be used more frequently with gases that contain particulates, such as carbon fines. These fines normally fall in the 1 –10 µm range, so they would pass through traditional inlet filters. Now, filters can be designed for 0.5 µm and will stop the smaller 1 µm particles.

Ensuring oil-free service More importantly, oil/gas separation has evolved to such an extent that gas compressor packages can now cost-effectively guarantee an oil content of 0.01 ppm or less in the gas stream leaving the skid. A standard for oil-free was set by the International Organization for Standardization (ISO), Geneva (www.iso.ch/). The organization’s ISO 8573-2, “Compressed Air for General Use — Part 2: Test Methods for Aerosol Oil Content,” (1996) is a specification created to standardize what process engineers consider being oil-free and how the value can be verified. Although this specification is written for air, the 0.01 ppm figure put forward by this document has widely become accepted as the value to which equipment should be designed to achieve oil-free status. The figure is no accident; oil smokes (mostly aerosols) fall into the


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0.01 –1.0 ppm range. They could not be filtered by coalescing and filtration elements until very recently. Thus, entrained oil would be captured, but aerosols (or smokes), would get through and could contaminate a gas up to 1.0 ppm by weight. If 0.01 ppm is achieved, the gas is basically oil-free. Oil-free is a truly a misnomer. Oilfree screw compressors and centrifugals used on air are not necessarily oilfree. This is because most industrial air is drawn at a petroleum refinery, or a chemical or petrochemical plant, and the atmospheric air is not free of oil there. Granted, oil is not introduced, but a sensitive process, such as pharmaceutical production or processes using catalyst beds, would be ruined by the oil that is drawn in air. Filtration is the only solution to ensure air, or even gas, quality. The goal is 0.01 ppm. Reciprocating compressor vendors accepted their inability to achieve oilfree status long ago. That is why they are called nonlubricated reciprocating compressors, instead of oil-free. Of course, nonlube recips often do introduce oil into the process, since reciprocating units produce considerable amounts of oil vapors. The third major reason is pressure and flow design. Until 1990, OIS units could not exceed 4,500 acfm in a single compressor body, now there are units that can do 10,000 acfm. Until the late 1980s, the discharge pressure was limited to 350 psi, however, recent innovations have brought standardized units up to 520 psi and special designs to 865 psi. The latter units accept a 700 psi inlet pressure, hence, their recent in-roads in the fuel gas market. Depending upon the differential pressure across the compressor, and the flow, the inlet pressure may be pushed to 120 psi on ratios below 4:1 or be limited to 70 psi on ratios above 7:1. In many instances, a process design inlet pressure of 125 psi can be reduced to 100 psi without great impact. This small change can reduce

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costs by one-half on the OIS compressor package. A bare OIS unit is shown in Figure 10. The fuel gas market is a good example of how the newer OIS machines can be used to great advantage over recips and centrifugals. Most power generating facilities built today use gasfired turbines. The incoming natural gas from the utility normally fluctuates and must be regulated to the turbine pressures. Unfortunately, the pressure often dips below the turbine requirements and compression is required. On a recent project, the incoming natural gas ranged from 310 psi to 600 psi and the desired discharge was s

Figure 10. Bare OIS gas compressor with inlet valve mounted.

650 psi. A centrifugal must be designed for the worst case, so an inlet pressure regulator was required to ensure that it always received 310 psi, ±5%. Thus, if the incoming gas were at 600 psi, energy would be wasted, since the gas would be reduced then recompressed. On a reciprocating compressor, the entire inlet range could not be accepted, due to rod load problems at the high end. Again, a regulator or expensive unloaders would be required, and the latter are not always reliable.


The OIS compressor can take the entire range and unload at the high end to reduce energy consumption by 60%. A regulating valve is not required, either. Thus, the OIS compressor not only offers the same capital cost as an API 11P reciprocating unit, but the client could purchase a unit that is more efficient over the entire range of compression and more reliable, as well. The added flexibility of the slide valve also reduces the size of the recirculation cooler and saves water. OIS units are sometimes called oilflooded, but this term is entirely inaccurate. The oil is literally injected, at a pressure higher than discharge, into several key areas of the compressor to provide lubrication, sealing, and cooling. Nearly two-thirds of a fully in jected screw compressor ’s oil goes towards cooling, not lubrication. This is why OIS units can produce pressure ratios as high as 23:1 in a single stage. Most companies do not use these machines at ratios above 10:1, since they become extremely inefficient with adiabatic efficiencies dropping to 50% at 15:1 ratios. Normal adiabatic efficiencies for screws, at a single design point, are 70–80%. However, their true installed efficiency remains close to those percentages, since OIS units are considered among the most efficient compressors for overall operation at different points, due to the slide valve. This valve is an internal capacity control device, and is built into all reputable gas machines, without incurring an additional cost. In fact, it is part of the design. The slide valve literally recirculates the compressed gas before compression is completed. That means that only a little energy is required to boost the gas enough so that it can be internally recirculated to the internal suction of the machine. Most slide valves can operate in the 10–100% range, so 0% flow is achievable with a very small recirculation system; GD recommends a 25% size. This removes the need for inlet throttling, full-size recirculation,

To sum up

s

Figure 11. Landfill gas compression. First stage is handled by a blower; second and third by twostage OIS unit.

or variable speed control. In fact, OIS units do not make good VFD units, since their efficiency is so closely tied to tip speeds in the 50–60 m/s range, and reducing the machine ’s speed would reduce its tip speed. The slide valve can be instructed to load or unload based on either P1 or P2. Thus, the process has a very simple capacity control device, based on system pressures. The slide valve has also been proven to be very reliable. The fact that screw compressors use injection oil for cooling is another positive for process design. If a process engineer would like to maintain a discharge temperature, or if the gas condenses at a known temperature, then the oil injection can be throttled to maintain a preset discharge temperature. Using a control valve on the main injection line and a temperature signal from the discharge does this. We recommend that a process stay 18°F (10°C) above the discharge dew point for water, and 25 °F (14°C) for hydrocarbon gases. Once the gas makes it through oil/gas separation, there is no the danger of fouling the lubricant and harming the compressor. OIS compressors can operate up to 10,000 acfm in a single body unit, however, the most cost-effective and competitive area is at 5,000 acfm and below. Standard compressors are generally one-half the price of custom units, but

custom pricing does compare favorably with most recips. The great advantage is that standard OIS units can allow for skid 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 to 35 weeks, while custom (API 619) machinery normally takes about 40 weeks. All these delivery times are shorter than those for centrifugal and API 618 reciprocating machinery. The inexpensive screw compressors can achieve discharge pressures of 520 psi, with some cost-effective modifications. Standard OIS gas units can achieve 350 psi at the discharge, and this pressure level provides the buyer with many market options and creates a healthy competitive bid situation. The main negative found in OIS units is that they do require fairly clean gas at the inlet during normal operation. They handle upsets better than recips and centrifugals, but they cannot do so on a continuous basis. Oil carryover is really no longer an issue with the improvement in filtration technologies. However, polymerizing gases are still a problem, so styrene and butadiene applications where these gases are above 20% content are definitely not recommended. Even antipolymerizing agents have been unsuccessful on OIS units.

In the end, the process conditions and gas will dictate which is the best compressor for a particular application. If a process engineer properly uses the information presented here, then the choice for the right compressor will become abundantly clear. The engineer must understand where the flows and pressures are in relation to available equipment, and see if the process can be adjusted to meet the capabilities of units that are readily available, reliable, and inexpensive for the application under study. Working with the mechanical department and compressor vendors, the right compressor will lead to the right final process conditions, or vice-versa. The most important advice is to keep an open mind, and use an iterative selection process. Any systems engineer or economist will tell you that working in a closed loop without feedback will lead to ruination. Open that external loop, gain that external feedback, and a marginal process can CEP become a great one.

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) 8961154; 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.


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Select the Right Compressor (CEP)

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