INTRODUCTIONGE heavy-duty gas turbines are capable of

burning a variety of gaseous and liquid fuels,including low heating value gases (e.g., syngasand steel mill gas), land fill gas, petroleumnaphthas and residuals. These fuels vary inhydrocarbon composition, physical properties,concentrations of potential pollutants and tracemetals.

Within the last decade, GE has developedadvanced-technology combustion systems thatcan burn natural gas and achieve NOx emissionsof 15 ppmv or less without the need for water orsteam injection. During this same period, thequality of the natural gas supply within the U.S.has changed. More specifically, heavy hydrocar-bon liquids are now commonly found in the gassupply delivered to power plants.

What happened during the past 10 years topromote this situation? The passage of theFederal Energy Regulatory Commission (FERC)Order 636 (Reference 1) in 1991 opened accessto transportation pipelines to all gas suppliersand eliminated the semi-monopolistic contractsthat limited access to one or more suppliers.

In addition, FERC 636 changed the way inwhich natural gas is sold by requiring producers,transporters and local distributors to sell gas ona therm or energy basis. This created increasedcompetition within the natural gas industry anddrove suppliers to produce gas at minimum costin order to compete on the open market. It isnow not uncommon for large users to negotiatedaily contracts based on the lowest gas priceavailable for that day.

Higher hydrocarbons in the form of gas or liq-uid can contribute significantly to the heatingvalue and are, therefore, a valuable constituentof natural gas. As a result of stiff competition,stripping these heavier components from the gasin cryogenic processing plants has become lesseconomic. A consequence of this change is thathydrocarbons beyond C6 are now common inmany gas supplies. Depending on pressure, tem-perature and concentration levels, the heavierhydrocarbons can form liquids and have a verysignificant effect on hydrocarbon dew point.

Worldwide, with a few exceptions such asCanada, gas fuel liquids have been a problemfor many years. Problems first arose when liquidslugging caused major problems with standardcombustor machines, often causing hot gas pathdamage. Application of advanced-technologycombustion systems in these areas requires closeattention to the gas clean-up system to ensurethat both condensed liquids and practically allparticulate matter are eliminated at the inlet tothe gas fuel control module.

Untreated gas can result in fuel nozzle plug-ging from particulates and erosion of compo-nents exposed to high velocities in the gas sys-tem. Liquid carr y-over in natural gas hasresulted in premature combustion componentdistress (liners, cross-fire tubes and fuel nozzles)and has affected reliability and availability for alltypes of combustion systems, including Dry LowNOx (DLN).

For DLN advanced technology combustors tooperate properly, it is absolutely essential thatthe gas fuel supplied meet the GE specificationand be free of all liquids and particulates. Thisspecification is documented in GEI 41040E(Reference 2).

This paper discusses where particulates andliquids in gas fuel originate and why they are notbeing removed with the wide range of gas pro-cessing equipment available in the market.

GAS CLEANLINESS ANDQUALITY REQUIREMENTSIt is important that only clean dry gas be used

as a fuel for advanced-technology gas turbines.Particulate matter, such as rust, scale, and dirt,can usually be removed easily through filtrationand separation techniques. The removal of liq-uids, such as water and liquid hydrocarbons, canbe more difficult. Many factors that influenceliquid removal, such as droplet size and distribu-tion, are hard to quantify. This can result in liq-uid hydrocarbons being admitted into gas tur-bine fuel system and combustion equipment.Even extremely small amounts, if allowed toaccumulate in downstream piping, can cause

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GAS FUEL CLEAN-UP SYSTEM DESIGN CONSIDERATIONSFOR GE HEAVY-DUTY GAS TURBINES

C. WilkesGE Power SystemsSchenectady, NY

damage. This fact, combined with the generaldegradation of gas quality in the U.S., makes itespecially important to carefully monitor gasquality and to take corrective actions, if neces-sary, to meet GE fuel specification GEI 41040Ein order to prevent equipment damage.

GE Gas Fuel Specification GEI41040E

In summary, this document defines for limita-tions on particulate matter size to no more thanapproximately 10 microns, calls for the elimina-tion of all liquids at the inlet to the gas turbinecontrol module and specifies the minimum andmaximum requirements for fuel supply pres-sure. Other limitations and qualifications mayalso apply and the user is encouraged to reviewthe details in this document.

A superheat temperature of at least 50 F/28 Cabove the moisture or hydrocarbon dew point isrequired to eliminate liquids. Meeting thisrequirement may require heating the gas ifheavy hydrocarbons are present. Reasons forspecifying gas superheat are:

• Superheating is the only sure method foreliminating all liquids at the inlet to the gascontrol module

• It provides margin to prevent the formationof liquids as the gas expands and coolswhen passing through the control valves

Why 50 F/28 C minimum superheat? • It is an ASME-recommended standard

(Reference 3) that 45 F to 54F (25 to 30 C)of superheat be used for combustion tur-bine gaseous fuel.

• Calculations show the 50 F/28 C minimumsuperheat requirement will prevent liquidformation downstream from the controlvalves and is verified by field experience

• Some margin is provided to cover daily vari-ations in dew point

• Vaporization time for liquid dropletsdecreases as superheat temperature increas-es

Gas Fuel ContaminantsSome of the contaminants that are introduced

into the natural gas supply as a result of the pro-duction and transportation processes are:

• Water and salt water• Sand and clay• Rust• Iron sulfate, iron and copper sulfide • Lubricating oil, wet scrubber oil, crude oil

and hydrocarbon liquids

• Glycols from dehydration processes• Calcium carbonate• Gas hydrates and ice• Construction debris Construction debris is common and includes

materials such as weld slag, grinding particles,grit, portions of welding rod, metal shavings,etc. Despite gas line pigging and vigorous blow-downs, which are necessary and recommended,some contaminants will be found in the gas sup-ply, especially during the early commissioningperiod. During this phase, extra precautions aretaken by installing temporary “witch hat” finemesh strainers at the inlet to the gas controlmodule and selected sections of gas piping with-in the turbine enclosure.

Once satisfactor y operation has beenachieved and the temporary strainers no longerpick up debris and contaminants, they areremoved. Installation of these strainers does notprovide a substitute for a properly engineeredgas clean-up system and frequent outages will berequired to clean or replace the strainers if anadequate filtration system is not installed.

GAS CLEANLINESS ANDQUALITY ISSUES

Gas fuel quality and cleanliness issues thataffect the gas turbine operation are:

• Variation in heating value• Autoignition or hydrocarbon liquids • Particulates that lead to erosion and plug-

ging

Variations in Heating ValueVariation in the heating value as a result of

gas phase composition variation affect gas tur-bine emissions, output and combustor stability.Changes greater than 10% require gas controlhardware modifications, but are not a commonproblem in a stabilized distribution systems.

Some local distribution companies usepropane/air injection as a method for stabiliz-ing variations in heating value. The quantity ofair injected is well below that required to reachthe rich flammability limit of the gas and posesno safety issues.

Variations in heating value could be an issueif gas is purchased from a variety of suppliersdepending on the daily or weekly variations ingas price. In this situation, the user shouldensure that the variations are within the valuesallowed by the contract agreement with GE. On-line instruments that determine and monitorheating value are available from several suppli-

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ers and should be used if significant variationsare expected.

Slugging of hydrocarbon liquids affects theenergy delivered to the turbine and can result insignificant control problems and potential hard-ware damage. For this and other reasonsdescribed below, all liquids must be eliminatedfrom the gas supplied to the turbine.

Autoignition of Hydrocarbon Liquids Removal of liquids has become more of a con-

cern during the past several years as gas qualityhas decreased. Liquids are formed from the con-densable higher hydrocarbons found in naturalgas, generally those higher than about pentane(C5), as well as moisture from water vapor.Moisture is undesirable because it can combinewith methane and other hydrocarbons to gener-ate solids in the form of hydrates. Hydrate for-mation and prevention is discussed in“Formation of Solids — Particulates andHydrates.”

Hydrocarbon liquids are a much more seriousissue because liquids can condense and collectover long periods of time, then result in liquidslugging as gas flow rates are increased after aperiod of reduced power operation. This canlead to:

• Uncontrolled heat addition• Autoignition at compressor discharge tem-

perature (625 F to 825 F/329 C to 451 Crange)

• Potential for promoting flashback and sec-ondary/quaternary re-ignitions

• Varnish-like depositsCarry-over of liquids to the turbine can result

in uncontrolled heat release rates if sufficientquantities are present, resulting in possible dam-age to the hot gas path. A more common prob-lem, however, is with the exposure of smallquantities of hydrocarbon liquids to compressordischarge air. Dry Low NOx combustion systemsrequire pre-mixing of gas fuel and compressordischarge air in order to produce a uniformfuel/air mixture and to minimize locally fuel-rich NOx-producing regions in the combustor.Typical autoignition temperatures (AIT), thetemperatures required for spontaneous combus-tion with no ignition source, for these liquidsare in the 400 F to 550 F (204 C to 288 C) rangeand fall below compressor discharge tempera-ture. Exposure to compressor discharge airabove the AIT will result in instantaneous igni-tion of the liquid droplets, causing, in some

cases, premature ignition of the pre-mixedgases, often called “flashback.”

Because of the seriousness of the problem,GE specification 41040E does not allow any liq-uids in the gas fuel. Furthermore, to preventcondensation in the gas fuel manifolds, which iscaused by gas expansion through the controlvalves, this specification requires a minimum of50 F/28 C of superheat at the turbine speedratio valve inlet flange. This value provides adegree of safety and is within the ASME recom-mended values for dry gas fuel (Reference 3).

Particulates in the Gas StreamThe gas turbine operating issues with particu-

lates in the gas stream are fuel nozzle plugging,erosion and deposition.

Of the three, fuel nozzle plugging has a moresevere and immediate impact on normal opera-tion. Since the gas fuel nozzle hole sizes on DLNsystems are smaller than those used in diffusionflame combustors, they are more prone to plug-ging. Plugging will result in poor fuel distribu-tion from nozzle to nozzle and combustor tocombustor and increase emissions and exhausttemperature spreads. Plugging could also leadto fuel flow split deviations between gas mani-folds, which could lead to poor emissions and,in worst case, to autoignition and flashback.

Eliminating plugging is especially importantduring commissioning and early commercialoperation, or after work has been performed onthe pipeline, when accumulated dirt and con-struction debris can become entrained with thefuel.

If plugging occurs, the nozzles will need to becleaned. Since the disassembly, cleaning andreassembly process can take several days, theavailability of the unit can be adversely impacted.

Erosion problems can result if excessive quan-tities of particulates are present, depending onthe nature and size of the material. The GEI41040E fuel specification calls for removal ofparticulates greater in size than approximately10 microns (see specification for added qualifi-cations) to prevent erosion and deposition.Particles smaller than about 10 microns tend tofollow the gas stream, rather than striking thepressure containment vessel walls and, there-fore, result in a significant decrease in erosionrate.

The gas control valves are designed to operatein a choked flow condition and are, therefore,exposed to velocities up to the local speed ofsound. Erosion rates are exponentially propor-tional to particle velocity and areas that experi-

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ence high gas velocities, such as orifices andvalve seats, are more susceptible to erosion.

Nozzle and bucket deposition can also be aproblem, depending on the nature and concen-tration of the particles, even for those of lessthan 10 microns in diameter. For this reason,GEI 41040E limits the concentration of particu-lates from all sources and sizes to no more than600 ppb at the first stage nozzle inlet.

Formation and Carry-Over of Solids:Particulates and Hydrates

Most solids found in natural gas are due tothe slow oxidation and corrosion of the pipelineand are in the form of fine iron oxide particles.Construction debris such as weld slag, metalshavings, sand and even foreign objects are alsocommonly found in new pipelines, especiallyduring the initial commissioning phase.

Another type of solid material that may be pre-sent is gas hydrates. Gas hydrates are crystallinematerials that are formed when excess water is pre-sent in a high-pressure gas line. These solids areformed when water combines with natural gascompounds, including condensates, when the gastemperature is below the equilibrium hydrate for-mation temperature. Although commonly associat-ed with ice-type crystals, formation temperaturescan be significantly above 32 F/0 C at pipelinedelivery pressures. Hydrates can deposit in stag-nant areas upstream and downstream from orificeplates, valves, tee sections and instrumentationlines, causing plugging and lack of process control.

Figure 1 shows hydrate formation lines fortwo water concentrations for the natural gas list-ed in Table 3. Location of these lines will varywith gas composition and fall above or below thesaturated hydrocarbon vapor line.

Hydrate formation is more likely to be foundin offshore pipeline systems because of the highpressures and cooler temperatures. Fortunately,all transportation companies recognize the needto remove water to prevent hydrate formationand resulting pipeline equipment blockageproblems. Water is typically limited to a nominalvalue of between 4 and 7 lbs per million stan-dard cu ft. (64.1 to 112.1 kg/mmscm). It isremoved to this level by treatment equipmentthat use chemical scrubbing with methanol orethylene glycol; some carry-over of the scrub-bing liquid may occur. Occasionally, a processupset may occur and spillover of inhibitors intothe gas supply can present a hazard by raisingthe hydrocarbon dew point.

Other preventative methods include gas heat-ing upstream from pressure-reducing stations tomaintain the gas temperature above the hydrateformation temperature.

Formation and Carry-Over ofLiquids: Hydrocarbons and Moisture

As the gas fuel is brought to the gas turbine, itoften passes through a series of pressure-reduc-ing stations before it enters the gas control mod-ule. Further pressure reductions then take placebefore the gas enters the gas manifolding sys-tem. At each pressure-reducing station, the gaswill also experience a temperature reductiondue to the Joule-Thompson effect.

Temperature reductions for a typical naturalgas are shown in Figure 2, which are approxi-mately equal to 7 F for every 100 psid (5.6 C per1,000 kPa) reduction in pressure, with no heattransfer to or from the gas. Actual temperaturereduction will vary depending on the gas com-position and local heat transfer conditions.

A system with gas entering the site at 900psia/6,205.3 kPa and 60 F/16 C can experiencea temperature reduction of 31 F/17.2 C prior toentering the gas module at the maximum allow-able pressure of 450 psia/3,102.6 kPa for FA-technology machines. Further temperaturereductions will be experienced as the gas passesthrough the control valves and will be the great-est at low load when control valve throttling is atthe highest level.

Reports of frost appearing on the outside ofthe gas piping downstream from the controlvalves is not uncommon and is not a cause foralarm, provided the hydrocarbon and moisturedew points are significantly less than the localgas temperature.

GEI 41040E calls for a minimum of 50 F/28 C

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0

200

400

600

800

1000

1200

1400

-250 -200 -150 -100 -50 0 50 100

Pre

ssu

re p

sia

Hydrate Formation Line

H20 = 23 ppmv

Hydrate Formation Line

H20 = 230 ppmv

HC Saturated Vapor Line

HC Saturated Liquid Line

GT25721

Figure 1. Equilibrium temperature lines forhydrate formation

of superheat above the hydrocarbon dew pointat the entry to the gas module at all operatingconditions. Unfortunately, as liquid carry-overbecomes more common, the hydrocarbon dewpoint increases and condensation has become aserious issue. Separation of the free liquidsalone is not adequate, as this results in, at best, asaturated gas with a dew point equal to the gastemperature.

Further reductions in temperature down-stream from the separation equipment will,therefore, result in immediate condensationand formation of additional liquids. For incom-ing wet gas, a filter separator and a superheaterare essential to prevent the formation of liquids.Equipment required for this purpose is dis-cussed in “Recommendations for Clean-UpEquipment and Sizing.”

NATURAL GASCOMPOSITION VARIATIONS

AND IMPACT ON GASTURBINE OPERATION

Pipeline natural gas is not a homogeneous

entity, nor is it constant with time or geographiclocation. As noted in Reference 4, there is signif-icant variation in composition and physicalproperties of the natural gas supplied to variousareas of the U.S. This report, prepared by theAmerican Gas Association, quantifies potentialregional and seasonal variations in the composi-tion and properties of natural gas, documentsthe peak shaving practices in the U.S. and assess-es the contribution of the gas composition vari-ability on the formation of condensates.

While the variation in the composition of thegas has a small impact on the gas turbine opera-tion (e.g., emissions), the principal point of con-cern is the formation of condensates as the com-position of hexanes+ varies. For example, Table1 of Reference 2 summarizes the maximum andminimum values of higher or gross heatingvalue (HHV) and C6+ variations found in natu-ral gas in the U.S. and Canada.

Depending on the hexanes+ species, this con-stituent of the natural gas could lead to liquidhydrocarbon condensation in the gas streamsupplied to the gas turbine resulting in seriousdamage to the unit. The results of the survey ofU.S. natural gas do not show a strong relation-ship between an increase in heating value andan increase in concentration of C6+ com-pounds. Location does not appear to be a factor,either; samples from Texas pipelines show boththe highest and lowest values for C6+ com-pounds.

INDUSTRY EXPERIENCEWITH GAS FUEL LIQUIDS

In recent years, industry experience with liq-uids in natural gas has been poor. Reports ofincidents resulting from carry-over of liquids arefrequent and affect gas turbine from all manu-facturers equipped with various types of combus-tion systems.

These reports clearly show that this problemis quite widespread in the eastern half of theU.S. The absence of data from other sites, how-ever, should not imply that the western U.S. isexempt from these problems. Table 2 lists thereported concentration for hexanes+, an indica-tor of potential liquids, is distributed through-out the U.S. Since the potential consequentialdamage to the hot gas path from these liquidhydrocarbons is quite severe on dry low emis-sion units, the gas handling system must bedesigned to eliminate this threat under all con-ditions.

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Table 1VARIATION OF HEATING VALUE AND C6+

FOR U.S. AND CANADIAN NATURAL GAS

Country HHV HHV C6+ C6+Btu/SCFT Btu/SCFT Vol. % Vol. %Maximum Minimum Maximum Minimum

U.S. 1,208 970 0.5 0.0Canada 1,106 965 0.4 0.0

0

10

20

30

40

50

60

70

1002003004005006007008009001000

Tem

per

atu

re d

eg. F

.

Specie Mole %

Methane 95.20Ethane 2.82Propane 0.06i-Butane 0.09n-Hexane 0.01CO2 0.61O2 0.02N2 1.08

GT25722

Figure 2. Joule-Thompson cooling with pres-sure reduction

Specie Mole %

Methane 95.20Ethane 2.82Propane 0.06i-Butane 0.09n-Hexane 0.01CO2 0.61O2 0.02N2 1.08

HYDROCARBON ANDMOISTURE DEW POINT

DETERMINATIONTwo approaches can be used to determine

the hydrocarbon and moisture dew points: a cal-culation method using a representative gas sam-ple and extended analysis to C14, and a directmeasurement using a dew point instrument.

The calculation method has been used withsome success, but requires careful attention tothe details required to obtain a representative

gas sample and requires analysis to C14 at theppmv level. Recent experience has shown thedirect measurement of dew point to be a simple,practical and now preferred approach to dewpoint determination.

If the gas entering the facility is known to bewet, i.e., contains liquids at the operating pres-sure, then there is no need to sample or moni-tor the gas quality. Installation of adequate liq-uids removal equipment, as described in“Liquids Removal System,” will remove practical-ly 100% of all liquids present. At the dischargeof the separator, however, the resulting gas will

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Table 2REPORTED HEATING VALUES AND C6+ HYDROCARBONS THROUGHOUT THE U.S.

Higher Heating Value, Btu/scft Hexanes plus Hydrocarbons (C6+)

Mean Min Max Mean Min Max

California #1 - A 1,042.2 1,031.1 1,053.9 0.0 0.0 0.1California #1 - B 1,029.7 1,022.1 1,060.3 0.1 0.0 0.1California #1 - C 1,039.6 1,032.9 1,049.1 0.1 0.0 0.1California #1 - D 1,029.4 1,023.6 1,038.2 0.1 0.1 0.1California #1 - E 1,048.4 1,040.1 1,055.8 0.1 0.1 0.2California #2 - A 1,039.0 1,024.9 1,050.8 0.1 0.1 0.1California #2 - B 1,028.4 1,020.2 1,038.2 0.1 0.0 0.1California #3 1,033.2 1,028.5 1,043.0 0.0 0.0 0.0California #4 1,017.9 1,005.0 1,038.0 0.0 0.0 0.2California #5 995.3 986.0 1,011.0 0.1 0.0 0.1Colorado #1 991.9 971.0 1,035.6 0.0 0.0 0.1Colorado #2 980.2 970.3 1,006.5 0.0 0.0 0.1Colorado #3 984.4 974.3 1,012.5 0.0 0.0 0.1Connecticut 1,027.2 1,022.8 1,033.4 0.1 0.1 0.1Georgia 1,026.9 1,015.0 1,047.0 0.1 0.0 0.2Illinois #1 1,028.2 1,017.6 1,081.4 0.1 0.0 0.2Illinois #2 1,031.3 1,015.2 1,043.6 0.1 0.0 0.2Louisiana 1,023.1 997.7 1,053.1 0.1 0.0 0.2Maryland #1 1,033.2 1,027.0 1,046.7 0.1 0.0 0.2Maryland #2 1,102.3 1,032.1 1,208.1 0.1 0.0 0.1Maryland #3 1,032.2 1,026.9 1,041.6 0.1 0.0 0.1Maryland #4 1,030.7 1,025.4 1,039.0 0.1 0.0 0.1Maryland #5 1,037.2 1,030.3 1,055.6 0.1 0.1 0.1Maryland #6 1,041.0 1,033.4 1,062.0 0.1 0.1 0.1Massachusetts #1 1,060.9 1,017.1 1,190.5 0.0 0.0 0.1Massachusetts #2 1,034.6 1,032.4 1,036.4 0.1 0.1 0.1Michigan 1,031.4 1,010.5 1,043.7 0.0 0.0 0.1New Jersey 1,030.4 1,021.0 1,048.0 0.0 0.0 0.2New York 1,029.6 1,017.5 1,039.4 0.0 0.0 0.0Ohio 1,044.9 1,010.3 1,096.2 0.1 0.1 0.2Oklahoma 1,029.6 1,005.5 1,085.9 0.0 0.0 0.2Pennsylvania #1 - 1 1,029.8 1,023.0 1,041.0 0.1 0.0 0.2Pennsylvania #1 - 2 1,029.1 1,022.0 1,038.0 0.1 0.0 0.1Pennsylvania #2 - 1 1,030.0 1,022.2 1,038.4 0.1 0.0 0.2Pennsylvania #2 - 2 1,029.8 1,023.1 1,048.7 0.1 0.0 0.2Rhode Island 1,029.6 1,027.0 1,033.9 0.1 0.1 0.1Texas #1 1,081.2 1,043.6 1,126.8 0.2 0.1 0.5Texas #2 1,023.8 1,017.0 1,036.0 0.0 0.0 0.0Texas #3 1,059.3 1,020.0 1,105.0 0.2 0.1 0.4Virginia #1 1,044.4 1,032.6 1,088.5 0.1 0.1 0.1Virginia #2 1,039.7 1,029.8 1,088.5 0.1 0.1 0.1Washington 1,038.5 1,013.0 1,056.0 0.0 0.0 0.0Wisconsin 1,005.9 980.7 1,043.7 0.0 0.0 0.1

be in a saturated condition. That is, the gas tem-perature will equal the dew point temperatureand superheating by a minimum of 50 F/28 C isrequired in order to meet the GEI 41040E fuelspecification.

If the incoming gas is in a dry condition, i.e.,the gas temperature is at an undetermined levelof superheat, then gas sampling or dew pointmonitoring is necessary in order to determinethe gas quality.

Gas Sampling Three types of samples are commonly used

for gas analysis. A continuous sample is drawnconstantly from the pipeline into a gas chro-matograph to monitor btu content. A compositesample consists of many smaller samples, eachwithdrawn at a specified time interval, to obtainan average value over a period of several days orweeks. The third type of sample is known as thespot sample. This is the sample most often usedto determine hydrocarbon dew point. It is with-drawn from the pipeline by an operator using asample flask.

Obtaining a spot gas-phase sample from drygas that is both representative and repeatable isessential for dew point calculation and is theresult of using proper sampling techniques.Sampling procedures can be found in GPA2166-95 (Reference 5).

Others have devised their own sampling pro-cedures, e.g., Welker (Reference 6), that arevariations of those found in GPA 2166-95. Theprocedure selected will depend primarily on thenature (wetness) and temperature of the gas. Asmentioned above, however, if the gas is wet,there is no need to sample for dew point deter-mination. A gas analysis will be required if thegas fuel delivery system is to be fully analyzed.

Obtaining a representative gas sample to thedegree of accuracy required for calculation ofthe hydrocarbon dew point is difficult, and spe-cial precautions must be taken to avoid genera-tion of liquids during the sampling process. Forbest results, the sample should be taken at orclose to the gas line operating temperature andpressure to avoid cooling as a result of expan-sion.

A sampling probe should always be used toextract the sample from the gas line. The sam-pling probe is a short piece of tubing thatextends into the middle one-third of the gasstream. The sampling probe helps to minimizecontamination of the sample with liquids andparticulates that may be present on the walls. Ifthe gas is wet and the sample consists only of the

gas phase, then the calculated dew point willequal the gas flowing temperature. Note that ifthe calculations result in a dew point tempera-ture above the gas flowing temperature, thenthe sample must have been contaminated withliquids and either the gas is wet or liquids weregenerated during the sampling process.

A diagram of a sampling probe is shown inFigure 3. Note that the opening of the probefaces downstream. This assists in the eliminationof entrained liquids from the sample.

Temporary sampling probes can be installedand removed from a pressurized line by use of apacking gland seal and isolated from the lineusing a high-quality ball valve. When the probeand packing gland are removed, a pipe plug isinstalled to provide a second seal in case the ballvalve leaks. Figure 3 shows this arrangement andincorporates an adjustable probe insertiondepth feature that allows the probe to beinstalled and removed without de-pressurizingthe pipeline. A pipe fitting is welded to the gasline, which is attached to a pipe nipple, the ballvalve, a second pipe nipple and pipe plug orpipe plug with a packing gland. Care must betaken when removing the probe from a pressur-ized line to avoid loss of the probe and possibleoperator injur y. Commercial probes haveexpanded sample tips or mechanical stops thatprevent full extraction of the probe from thepacking gland.

Gas Analysis A gas chromatograph is used in the laborato-

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SampleProbeThreadolet

To SampleApparatus

FLOW

Probe Opening45 deg Miter

Entrained Liquids

Sample Shut-off Valve

Pipe Nipple

Full-Port

Ball Valve

Swaged Ferrule

Replace Drilled Plug With Blank Plug AfterUse

Pipe coupling

Compression Fitting(Not Swaged)

GT25723

Figure 3. Gas sampling probe

ry or the field to analyze the gas sample anddetermine the gas composition. The analysis willcheck for the presence of both hydrocarbonsand non-hydrocarbons. Once the gas’ composi-tion is determined, the hydrocarbon and mois-ture dew point can be calculated using one ofseveral available software packages.

Standard Gas Analysis to C6+A common method for heating value determi-

nation is to use the standard analysis. The stan-dard analysis is performed in accordance withASTM D1945 (Reference 7) or GPA 2261-95(Reference 8) and lumps together all hydrocar-bons above C6 and reports them as “C6+.” Theresults of the standard analysis should not beused for dew point determination unless assur-ance can be given that no hydrocarbons aboveC6 are present (i.e., C6 may be present, but noC6+).

Small quantities of heavy hydrocarbons aboveC6 raise the dew point significantly. Using astandard analysis can result in an artificially lowdew point determination (see example below).Instead, an extended analysis should be usedexcept where no C6+ compounds are present.

Extended Gas Analysis to C14This type of analysis checks for the presence

of the heavy hydrocarbons and quantifies theiramounts to the level of C14. The extended anal-ysis is more complicated and expensive than thestandard analysis, and not all laboratories canprovide this service. It is, however, the only typeof analysis that will result in an accurate dewpoint determination. An analysis procedure forC1 through C14 is described in GPA 2286-95(Reference 9).

When choosing a lab to perform the gas anal-ysis, one should always seek a facility that special-izes in petroleum product testing and analysis.They are familiar with the unique aspects of nat-ural gas analysis and sampling; many offer ser-vices and advice that cannot be obtained else-where.

Analysis to the single-digit ppmw level shouldbe requested, but nothing less than two digits(tens of ppmw) should be accepted. It is impor-tant to confirm that the reported laboratory val-ues are obtained by measurement and notthrough a simple mathematical normalizationprocedure to six decimal places. It should beclear that when dealing with concentrations atthis level, absolute cleanliness is essential andsamples can be easily contaminated in the field.

Samples must also be taken at the actualpipeline pressure and temperature to avoid gasexpansion and possible liquid condensation.

Comparison of Standard and Extended AnalysisConsider the gas analysis shown in Table 3,

which was taken from an operating power plantgas supply. In this case, an extended analysis wasperformed and the standard analysis mathemati-cally generated by summing the C6+ con-stituents. The calculated dew point from theextended analysis is more than 23 F/12.8 Cabove that calculated from the standard analysis.

In extreme cases, differences of as much as100 F/56 C have been observed. The resultsshown in Table 3 also illustrate the need for rep-resentative gas sampling and accurate analysisdue to the sensitivity of the dew point calcula-tion to small concentrations of the heavierhydrocarbons. Where possible, the gas analysisshould be determined to within less than 10ppmv.

Use of the standard analysis for dew point cal-culation could lead to falsely concluding thatthe gas has an acceptable degree of superheat,or the superheater could be undersized basedon these results. An exception to this generaliza-tion may be made when the gas is exceptionallydry and where no hydrocarbons above C6 aredetected. In this situation, a standard analysis isacceptable for dew point calculation. Typicalhydrocarbon dew point values for this gas wouldbe in the -30 F to -70 F (-34 C to -57 C) range.Care must be taken when selecting an analyticalservice, however, to ensure that the laboratoryhas the capability to analyze beyond C6.

Further information on trace constituentsthat may be present in natural gas can be foundin Gas Research Institute report GRI-94/0243.2(Reference 10).

Dew Point MeasurementA method for measuring natural gas hydro-

carbon and moisture dew points has been avail-able for almost 60 years. The U.S. Bureau ofMines developed a dew point tester in 1938(Reference 11) that works on the principle of achilled mirror. The mirror is contained within apressure vessel and is exposed to the gas streamat pipeline pressure. The mirror is graduallycooled until condensation droplets begin toappear on the surface of the mirror. Two sepa-rate dew points, moisture and hydrocarbon, aremeasured depending on the nature of thedroplets on the mirrored surface. This type of

8

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measurement provides a direct reading of dewpoint without the need to apply corrections.Pressure within the chamber can be varied todetermine the effect on dew point.

Bureau of Mines Dew Point DetectorThe simple instrument developed by the

Bureau of Mines has been commercialized by atleast one manufacturer in the U.S. The princi-ple of operation is described above. This type ofinstrument is portable and intended for spotsampling, requiring an operator with some skilland experience to achieve repeatable results.GE has experience with this instrument and canprovide a limited amount of information andadvice on its use.

This method of determining dew point hasbecome the preferred approach because it is adirect measurement requiring no calibration orcalculation and interpolation of physical proper-ties data of complex hydrocarbon compounds.For gas system modeling, however, gas samplesand subsequent analysis are still required inorder to determine temperature reductions

from expansion and the risk of liquid condensa-tion. Dew point measurements complement thegas samples and help with model calibration.

The advantages of the Bureau of Mines dewpoint tester are:

• Elimination of the uncertainty associatedwith sampling and analysis as the primarymeans of dew point determination

• Simple and easy to use• Claimed accuracy is +/-0.2 F (+/-0.1 C) for

an experienced user • Identifies moisture, hydrocarbon, glycol and

alcohol dew points• No electrical power required — intrinsically safe

Automatic Dew Point MonitorAn on-line device to automatically determine

hydrocarbon dew point has many advantagesover the difficulties involved with gas samplingand extended analyses. As of August 1996, how-ever, only one commercial manufacturer hasbeen identified that makes this type of equip-ment. The advantages of automatically monitor-ing hydrocarbon dew point include:

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Standard Analysis to C6+ Extended Analysis to C14Specie Name Weight % Weight %

N2 Nitrogen 2.6206 2.6206

CO2 Carbon Dioxide 21.0489 21.0489

H2O Water Vapor 0.0023 0.0023

CH4 Methane 53.4414 53.4414

C2H6 Ethane 9.4684 9.4684

C3H8 Propane 7.5156 7.5156

C4H10 i-Butane 1.8906 1.8906

C4H10 n-Butane 0.7127 0.7127

C5H12 n-Pentane 0.4612 0.4612

C6H14 n-Hexane 0.8252 0.3840

C7H16 n-Heptane — 0.3169

C8H18 n-Octane — 0.1132

C9H20 n-Nonane — 0.0102

C10H22 n-Decane — 0.0006

C11H24 u-Undane — 0.0001

C12H26 Dodecane — 0.0000

C13H28 n-Tridecane — 0.0002

C14H30 n-Tetradecane — 0.0000

Totals 100.0000 100.0000HC Dew Point @ 465 psia 37.6 60.9

Table 3COMPARISON OF STANDARD AND EXTENDED

GAS ANALYSES ON CALCULATED HC DEW POINT

• Elimination of the uncertainty associatedwith sampling and analysis as the primarymeans of dew point determination

• Potential for automatically adjusting gastemperature with changes in hydrocarbondew point as a result of both transient andlong term gas composition changes

• Elimination of unnecessary heat additionand possible decrease in overall plant effi-ciency

• An alarm to alert plant operators thatpotential damage may result if correctiveaction is not taken, e.g. increase superheattemperature

GE is in the process of evaluating a monitorof this type and expects to field test a unit dur-ing late 1996 and early 1997.

Gas Liquids Detector An alternative liquids detection device has

been used by Gasunie, a pipeline transportationcompany in the Netherlands. This deviceextracts a small gas sample that is cooled to themaximum allowable dew point for incoming gas.If liquids are condensed, then the gas supplier isshut off until corrective action is taken. A com-mercial supplier in Europe sells a device thatworks on this principle.

RECOMMENDATIONS FORCLEAN-UP EQUIPMENT

AND SIZINGWhen specifying gas clean-up equipment, it is

important that consideration be given not onlyto equipment size and removal capabilities, butalso to the overall solids and liquids removalprocess. If liquid separation equipment isrequired, including a coalescing filter, thensolids removal is automatically taken care of.

If the gas is known to be dry, meets the 50F/28 C minimum superheat requirement andno liquids removal equipment is installed (e.g.,some LNG meet this requirement), then a par-ticulate removal filtration system will berequired.

Particulate Removal SystemThe recommended particulate removal

equipment is a filter system that is designed withan absolute removal rating of 3 microns or less.The equipment is normally available in a verticalconfiguration and consists of a series of parallelfilter elements attached to a tube sheet. The ele-ments are changed once a predetermined pres-

sure drop is reached for a given volumetric flowrate of gas.

For peaking units, it is acceptable to installone filter vessel, but for base loaded units, twounits located in a duplexed arrangement arerequired. The duplexed arrangement permitsisolation of one vessel for maintenance while theother is in operation. Under no circumstancesshould a bypass line be installed with the inten-tion of using the bypass line for maintenancepurposes.

Sizing of the equipment can be determinedbased on discussions with the vendor. In gener-al, the only considerations for sizing are dirtholding capacity and allowable pressure drop,which determine the size of the vessel and thenumber of elements. If the gas is to be heatedprior to filtration, then the filter elements mustmeet the maximum gas temperature require-ments.

Special considerations must be given to start-ing up a new installation or after work has beenconducted on the gas supply line. Under thesecircumstances, construction debris will mostlikely be present and will be carried along withthe gas as the flow rate increases. Fine meshstrainers are installed in the gas line as lastchance filters immediately upstream from thecontrol valves and the gas manifolds to protectthe fuel nozzles from plugging. The strainers atthe inlet to the gas manifolds are temporary andwill be removed prior to commercial operation.Forty micron strainers will prevent short-termnozzle plugging but do not fully protect againstlong-term erosion problems. For this reason,installation of last-chance strainers should notbe considered a substitute for a properly designsimplex or duplex particulate filter or filter/sep-arator.

The strainer in the inlet supply pipe is perma-nently installed (removable for cleaning purpos-es) and protects the fuel nozzles and acts as aflag to indicate non-compliance with GEI41040E. A well-designed filtration system willprevent particulate build-up on the straineronce the initial dirt and other contaminantshave been removed from the system.

Liquids Removal SystemThe recommended clean-up system will

include the following equipment in the follow-ing order:

• Pressure-reducing station• Dry scrubber• Filter/separator• Superheater

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In special circumstances, an additional heatermay be required upstream from the pressurereducing station if the incoming gas pressure isunusually high, above approximately 1,000psia/6,895 kPa, or if the gas has a high moisturecontent. In this situation the expansion andcooling downstream from the pressure-reducingvalve may require upstream heating to avoid theformation of hydrates and slugging of con-densed hydrocarbons that would otherwiseremain in the gas phase throughout the liquidsremoval process. This heater, most likely, willnot provide sufficient energy to meet the 50F/28 C minimum superheat requirement at thegas control module inlet, while at the same time,may prevent collection of free liquids for thereasons stated above.

Heaters are commonly found upstream fromscrubbers and filter/separators. While this maybe acceptable for some applications, thisarrangement is not recommended for gas tur-bine applications. Heating the fuel upstreamfrom a separator will raise the gas temperature,possibly above the dew point, and little or no liq-uids will be removed. A lack of liquids in theseparator drain tank is no guarantee that thefuel will meet GEI 41040E requirements.Further heating may be required in order tomeet the 50 F/28 C minimum superheatrequirement.

Processing EquipmentTo ensure the correct equipment is specified

for a given gas fuel, the following should beinvestigated before supplying and installing anygas processing equipment to a particular site.

• For an existing power plant, an accurate gassampling and analysis from the site takenupstream and prior to any fuel gas treat-ment equipment, and also at the combus-tion gas turbine fuel gas manifold.

For new construction, the sample shouldbe taken from a flowing gas stream in thepipeline as near as possible to the proposedsite

• Site reviews of in-line gas treatment equip-ment by manufacturers’ technical represen-tatives

• Fuel gas treatment equipment flow designreview by the responsible engineer

DESIGN STEPS FOR SIZINGAND LOCATION

Fuel gas conditioning requires the removal of

both liquid and solid contaminants from the gasstream. There are several ways to accomplishthis, the most common being the use of cen-trifugal separators, slug and mist eliminators fol-lowed by gas filters and combinationliquid/solid separators.

The first item that is required for selectingthe correct equipment is a detailed analysis ofthe available gas. This should include a gas sam-ple analysis from various sources, such as afterpressure reduction or compressor station, oranother source that will be representative of thegas just upstream from the combustion gas tur-bine.

The second stage in the selection process isequipment sizing. Since the efficiency of theequipment in item 1 above will fall with a reduc-tion throughout, it is recommended that thedesign point of inertial separation equipment beselected at 5% to 10% below the maximumexpected flow rate. Most inertial separators willmaintain high efficiency up to 10% above thedesign flow rate; check with the supplier fordetails.

Equipment should be located as close as pos-sible to the combustion gas turbine. This is espe-cially true of the superheater since liquids cancondense in the line downstream from theheater after the unit has shut down — the short-er the line, the lower the volume of conden-sates.

Processing Equipment DescriptionA brief description and simplified sketches of

the various types of clean-up equipment follows.

Dry ScrubbersDry scrubbers are multiple-cyclone (multi-

clones) inertial separators that remove both liq-uids and solid materials without the use ofscrubbing oils or liquids. A typical cross-sectionis shown in Figure 4. They are virtually mainte-nance-free except for blowdown of the draintank. A multi-clone scrubber will operate with ahigh separation efficiency greater than about a4:1 turndown in volumetric flow rate. Only onegas turbine should, therefore, be placed down-stream of each dry scrubber. A dry scrubber isnot generally recommended for slugging condi-tions; however, a modified dry scrubber designto handle slugs can be made available.

Dry scrubbers should be combined with coa-lescing filters in order to provide protectionover the entire operating range of the gas tur-bine. Both vertical and horizontal configura-tions are available. Typically, vertical units are

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used for the relatively small volumetric flowrates for a single gas turbine; the horizontalunits are used to treat larger volumetric flowrates experienced in gas pipelines.

In some cases, a dry scrubber may be installedto protect a pressure-reducing station servingmultiple gas turbines. In this situation, some liq-uid carry-over can be expected when the gasdemand is low because of low load or out of ser-vice operation that extends the turndownbeyond the manufacturers recommendations.

Gas SeparatorA gas separator operates on a similar inertial

separation principle as the multi-clone dryscrubber. Figure 5 shows a sectional view of atypical gas separator of this type. Wet gas passesthrough an inlet baffle to remove liquid slugsand then through a series of angled vanes thatimpart inertial forces on the remaining liquiddroplets. The droplets strike the vanes and areremoved from the flow stream by gravity. Vaneseparators are available in either vertical or hori-zontal configurations and are recommended forapplications where slugging can occur.

Coalescing FilterCoalescing filters are normally used in con-

junction with a dry scrubber where removal ofpractically all liquid droplets is required.Typically, coalescing filters will remove alldroplets and solids larger than about 0.3microns. The filter unit consists of a verticalpressure vessel that contains a number of paral-lel tubular filter cartridges. Depending on thesupplier, inlet gas flow can be either from the

inside of the tube or from the outside of thetube. A baffle at the inlet to the filter housingwill deflect liquid slugs and larger particulates tothe sump. The wet gas containing fine dropletsflows though the filter where the droplets col-lide with the fibrous filter material. The dropletscoalesce with others and form larger dropletsthat are then removed from the filter elementby gravity and collected in the sump.

A sectional view of a coalescing filter is shownin Figure 6. The gas enters the inside of the fil-ter elements and flows outward. Very small liq-uid droplets are coalesced into larger droplets asthey travel through the filter elements. Theselarge droplets then fall away from the outer sur-face of the elements and are collected in thebottom of the vessel. A properly sized filter willprevent the re-entrainment of liquid dropletsinto the gas stream, but the efficiency of thisdevice will drop off dramatically if operatedbeyond its design flow rate.

Coalescing filters should always be precededby a stage 1 liquid and solid removal device toprevent the entry of gross amounts of contami-nation. Filter elements require periodic replace-ment; duplexing may be desirable. Installationof coalescing filters should be seriously consid-ered where gas compressors are located; theseare the only devices capable of removing thefine oil mists that are sometimes introduced intothe gas stream from the compressor.

Combination SeparatorsThe filter separator combines changeable fil-

ter elements along with vane mist eliminator ina single vessel, as illustrated in Figure 7. The gasfirst passes through the filter elements, enabling

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GT25724

Figure 4. A vertical multi-clone dry scrubberGT25725

Figure 5. Vertical gas separator (inertial vane-type)

smaller liquid particles to be coalesced while thesolids are removed. Because of the coalescingeffect, the vane is able to remove more free liq-uid particles than either the dry scrubber or thevertical gas separator alone. This combines theefficiency of the vane separator with that of thecoalescing filter in one vessel.

As with the coalescing filter described above,the filter separator maintains its guaranteed sep-aration efficiency from 0% to 100% of its designflow capacity. Filter separators are often used inlieu of filters when high liquid rates are expect-ed. The filter separator also removes solids fromthe gas stream, but must be taken off-line peri-odically in order to replace the dirty filter ele-ments. For this reason, base-loaded units requirea duplex arrangement that permits mainte-nance to be performed on one unit while theother is in service.

Absolute SeparatorThe absolute separator shown in Figure 8 is a

two-stage device similar to the filter/separator,except the unit is configured in a verticalarrangement and the method of separation isreversed. Here, multi-cyclones or vanes are usedto inertially separate the larger droplets in thefirst stage.

The partially cleaned gas passes on to stage 2,which consists of coalescing filters. Flow throughthe filters is from the inside out. The coalesceddroplets form on the outside of the filter andare then drained by gravity to a collection tank.There are several advantages to this type of liq-uid removal device, including a higher removalefficiency in the droplet diameter range of 0.01microns to 4 microns. Inertial removal of solidsand liquids in the primary separator section alsounloads the filter elements in the second sec-tion, allowing fewer to be used and reducing theoverall vessel diameter.

Fuel HeatingFuel heating to raise the temperature of the

gas to 50 F/28 C above the hydrocarbon dewpoint may be required per the GEI 41040E fuelspecification. Three basic types of heater areavailable; each has economic, maintenance andoperating advantages and disadvantages.

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Inlet

Outlet

VaneSeparators

InletChamber

FilterElements

Drain Tanks

GT25727

Figure 7. Combined filter-separator

Coalescing Filter Elements

Outlet

Inlet

Drain Connection

Drain Connection

Multi-Clone Inertial Separator

GT25728

Figure 8. Absolute separator

GT25726

Figure 6. Coalescing filter

Electrical HeatersElectrical heaters are the most convenient

type of fuel heater to use and install. Figure 9shows a sectional view of an electrical heater. Asimple control system can maintain a constantexit temperature or a constant temperature risewithin the capacity limits of the equipment asfuel flow rate varies. Thermal efficiency is closeto 100% in that all of the electricity used is con-verted into heat and is used to raise the gas tem-perature, neglecting losses to the ambient sur-roundings. The electricity used to power theequipment, however, is being produced at 30%to 40% efficiency for simple-cycle machines; theoverall energy efficiency is approximately one-half, or less than that of gas- or oil-fired heaters.

The capital cost is the lowest of the threetypes, but the operating expense is, therefore,the highest, while maintenance cost are relative-ly low. The electrical heater is simple in con-struction, compact and requires a smaller foun-

dation. Heating elements can be easily replacedand no intermediate heat transfer fluid isrequired, a concern in freezing climates, whichreduces maintenance costs.

Gas- or Oil-Fired HeatersHeaters of this type are readily available and

already in use throughout the world. Figure 10shows a sectional view of this type of heater. Anintermediate heat transfer fluid is generally usedfor safety purposes.

In cold climates, a mixture of ethylene glycoland water or equivalent prevents freezing, ele-vates the boiling temperature of the water andreduces the heat exchanger surface area. Thethermal efficiency of these units is reasonablyhigh; about 80% of the heat generated is trans-fer to the gas and the remainder is discharged inthe flue gas. Heat added to the gas fuel, howev-er, reduces the quantity of fuel required by thegas turbine and offsets the fuel required by theheater to some extent.

Larger foundations are required for this typeof heater, and several burners may be requiredin order to provide improved thermal responseand turndown capabilities. Operating costs aresignificantly lower than an electrical heater, butmaintenance and capital costs are higher.Difficulty in tracking rapid fuel demand changesof the gas turbine may be an issue for peakingunits or during startup.

Waste-Heat-Fired Fuel HeatersThis an option for combined-cycle units

where low-grade heat (hot water) may be readilyavailable. The advantage of this type of heater isthat no fuel penalty is incurred and the overallthermal efficiency of the power plant may beincreased. Disadvantages are higher capital cost,

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Cold Gas InletHot Gas Discharge

Electrical Heating Elements

GT25729

Figure 9. Electrical gas heater

FIRETUBE

Cold Gas Inlet

Hot Gas Discharge

Water Filled

Exhaust Stack

Burner Fuel

Inlet

Burner

GT25730

Figure 10. Indirect- fired gas heater

increased maintenance and installation costs forlarger foundations.

This type of a system is more suited for base-loaded units because of lack of heating duringstartup. Construction is of the tube and shelltype and is heavier than the indirect-fired heaterto accommodate the 400+ psia/2758+ kPa pres-surized water supply. A typical shell and tubeheater is shown in Figure 11.

Dual-Source HeatersThese gas fuel heaters are similar to the waste-

heat-fired heater but can also be fired using aremote gas burner. The advantage of this type ofheater is that the remote burner can be used ifthe gas turbine is operating in simple-cyclemode and during startup to ensure that the gasis completely free of liquids during all phases ofthe operation. Figure 12 shows a simplifiedschematic — less control valves — that illustratesthe dual heat source.

Equipment ArrangementFor sites where the specific quality of the gas

is unknown, a vertical gas separator followed byeither duplex multi-tube filters or filter separa-tor and superheater is recommended. Each ofthe duplex units must be designed for 100% ofthe system flow rate so that one can stay on-linewhile maintenance is being performed on theother.

The following are six gas conditioning sys-tems, from the simplest scrubber to the mostcomplex skid package engineered specifically tomeet the individual need of a customer.

If the gas is dry with ample superheat and theexpected daily, weekly and monthly variationsare well known, then a simplex or duplex partic-ulate filter, as shown in Figure 13, is all that maybe required. An example of this type of applica-tion is a site burning LNG where the supplierhas guaranteed no hydrocarbons higher thanC5 and where the gas temperature delivered tothe site is well above the hydrocarbon dew point.For example, a gas with a moisture and hydro-carbon dew point of less than -50 F/-46 C and agas delivery temperature of about 55 F/13 Cwould meet this description.

Allowance must be made for temperature dropthrough the pressure-reducing station, but with asuperheat temperature of 105 F/35 C, thereshould be no concerns with liquid condensation.

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Cold Gas Inlet Hot Gas Discharge

Auxiliary Heater

Auxiliary Heater Exhaust

Return to Heat Recovery Steam Generator

From I/P Feedwater Supply

Auxiliary Fuel

GT25732

Figure 12. Simplified schematic for a dual-source gas fuel heater

Cold Gas InletHot Gas Discharge

Hot Water Inlet from HRSG

Warm Water Discharge to HRSG

GT25731

Figure 11. Waste-heat gas fuel heater

There is a need for particulate removal,regardless of the quality of the gas, since particu-lates can be generated by spallation of rust andother corrosion products within the pipeline.Stainless steel piping is required downstreamfrom the particulate filter.

If the gas is wet but without excessive liquidsand no slugging potential upstream from thepressure-reducing station, then single- orduplexed-filter/separators are recommended,followed by a heater that will provide a mini-mum of 50 F/28 C of superheat. Figure 14shows this arrangement with a single filter/sepa-rator.

If the pressure drop through the pressure-reducing valve is greater than about 300psi/2,068 kPa and the temperature reductioncould cause slugging downstream, then a dryscrubber upstream from the filter separator maybe required depending on the manufacturer’srecommendations. Figure 15 shows this arrange-ment.

If the gas is wet and slugging is present in theincoming gas supply, a dry scrubber may berequired upstream from the pressure reducingstation. Figure 16 illustrates this arrangement. Afilter separator is also required to provide pro-tection over 100% of the flow range and to mini-mize any liquid carry-over to the heater.

If the incoming gas has a potential forhydrate formation, a dry scrubber and heatermay be required upstream from the pressure-reducing station, as shown in Figure 17. A fil-

ter/separator and superheater are required asbefore. The heat input can be minimizedupstream, heating to a level that avoids hydrateformation and allowing the downstreamfilter/separator to remove liquids by physicalseparation.

The hydrate formation temperature may beabove or below the hydrocarbon dew point tem-perature, depending on gas composition andmoisture content. If it is above the hydrocarbondew point, then a re-arrangement of equipmentmay be beneficial to avoid installation of twoheaters. A minimum superheat temperature of50 F/28 C must be maintained at the gas mod-ule inlet.

If multiple units are present on-site, a com-mon clean-up system is often used to protect thepressure-reducing station, but individualfilter/separators and heaters must then beinstalled downstream to protect each unit.Figure 18 shows the arrangement of individualfilter/separators and superheaters.

Figure 19 shows a typical gas compression sys-tem used where the incoming gas supply pres-sure is too low to meet the GEI 41040E pressurerequirements. In this situation, advantage canbe taken of the heat of compression to avoid thecost of a gas superheater. Sufficient heat is nor-mally added to the gas stream that the gas issuperheated, much greater than the 50 F/28 Cminimum requirement.

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GT25735

Figure 15.Dry scrubber installed to protectfilter separator against excessiveslugging conditions

GT25736

Figure 16.Incoming wet gas with sluggingpotential upstream from pressure-reducing station

GT25734

Figure 14.For wet gas with non-sluggingconditions upstream from pressure-reducing station

GT25733

Figure 13.Simple particulate filtration used fordry gas

Attention must be paid to potential spill-overof compressor lubricating oil, however, andinstallation of a coalescing filter or absolute sep-arator should be provided as part of the com-pressor package. If the heat loss in the gas lineto the turbine is excessive, then a coalescing fil-ter and superheater may be required down-stream from the compressor station in order toregain the 50 F/28 C superheat.

Depending on the recirculation intercoolerexit temperature, the recirculation line may beintroduced at the compressor inlet or upstreamfrom the gas clean-up equipment. There is someadvantage to introducing the recirculation lineupstream from the clean-up equipment in thatthe volumetric flow through the separationequipment will be closer to a constant value asload on the gas turbine increases or decreases.

The gas clean-up systems described here areonly examples. The specific needs of each indi-vidual site must be carefully assessed, and theequipment and system design selected accord-

ingly. It is not sufficient, however, to indepen-dently select equipment based on claimed highefficiency alone; the entire system must be evalu-ated and preferably modeled to determine theoverall system sensitivity to changes in gas com-position, pressure temperature and mass flowrate. GE offers an engineering survey servicethat will provide answers to these questions.

CORRECTIVE ACTIONS IFWET GAS IS PRESENT

If wet gas is known to be present at the gasmodule inlet, it is highly recommended that theunit be shut down where practical until theextent of the problem can be determined. A fail-ure to take action significantly increases the riskof an incident that may result in hardware dam-age ranging from combustor or fuel nozzle dam-age to stage 1 nozzle and bucket damage.

If the recommendations contained in thisreport have been followed, then the problemcould be as simple as a tripped fuel heater. Ifthis is a pre-existing condition and clean-upequipment has not been installed or is inade-quate, then one or more clean-up equipmentsuppliers or GE Global Services Engineeringshould be consulted for advice.

As a minimum, if wet gas is known to be pre-sent, then free liquids must be removed and thegas superheated.

GE GAS FUEL SYSTEM ENGINEERING SURVEY

SERVICETo assist customers with the design of new gas

fuel systems or to survey existing systems, GEoffers an engineering service to evaluate pro-posed or existing designs and to make recom-mendations for upgrades to meet current fuelspecifications. The survey may include a sitevisit, gas analysis and modeling of the system to

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GT25738

Figure 18.Common protection for pressure-reducing station and multiple-gasturbines, each individually protected

GT25739

Figure 19.Two-stage gas compressor providingmore than 50 F/28 C superheat

GT25737

Figure 17.Dry scrubber and heater to protectpressure-reducing station from build-up of gas hydrates

show where liquid condensation will occur andcalculation of the required heat input to main-tain 50 F/28 C of superheat.

SUMMARYAppropriate gas conditioning is critical to the

proper operation of advanced-technology low-emission combustion equipment. It is also appli-cable to pre-DLN combustion systems in orderto fully protect the hot gas path equipment asthe quality of the delivered gas continues todeteriorate under the pressure of economicforces both in the U.S. and overseas.

Gas fuel characteristics and quality require-ments are addressed by the GE gas fuel specifi-cation. This paper provides background infor-mation and can be used as a guide to thespecification and arrangement of clean-upequipment that is necessary to meet this require-ment. Several aspects are considered, includingcleanup of liquids, particulates and other con-taminants, together with recommendations forgas sampling, analysis and dew point measure-ment.

Clean-up equipment is often provided to pro-tect the pressure-reducing station, but this aloneshould not be relied upon without a system eval-uation to meet GEI 41040E. Prior to purchasingequipment, it is recommended that the entiregas fuel system from a point just upstream fromthe custody transfer station to the purchaser’sconnection at the gas fuel module inlet be con-sidered in the evaluation over the expectedrange of operating conditions. Several processsimulator programs are commercially availablethat will assist with this task, or GE can providethis evaluation as a service.

ACKNOWLEDGEMENTThis document is the result of several discus-

sions with customers and GE personnel in thePower Generation division and at the CorporateResearch and Development Center. The authorwould like to acknowledge the contribution themany people involved without whom this compi-lation would not have been possible.

APPENDIXA: Hydrocarbon Compounds Foundin Natural Gas

Continuous-Chain SaturatedHydrocarbons

Table 1A shows a list of continuous-chain satu-rated hydrocarbons through C14, known as alka-nes (also called paraffins). These are hydrocar-bons that will not react with hydrogen; they canbe readily recognized by the compound nameending in -ane. Formulae for saturated hydro-carbons follow the simple rule of CnH2n+2.

For isomeric saturated hydrocarbon com-pounds, the chemical formula can be readilydetermined from the name, i.e. di-methyl hep-tane is an isomer of a hydrocarbon higher thanheptane (C7) that has attached two methylene(CH2) chains. The number of carbon atoms istherefore 2xC +C7=C9, and since it is a saturat-ed hydrocarbon (ends in -ane), the completeformula is C9H20.

Care should be taken not to confuse isomerstructure notation, e.g. 2-methyl heptane, whichis C8H18, and is not the same as di-methyl hep-tane, which is C9H20.

Cycloalkanes (Ring Structures)Some hydrocarbons that end in -ane are ring

compounds such as cyclo-heptane C7H14, orcyclo-octane C8H16, and follow the general for-mula of CnH2n.

Combinations also exist such as:dimethyl cyclo-hexane C8H16 (2xC + unsatu-

rated C6 = C8H16)

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CH4 Methane C8H18 Octane

C2H6 Ethane C9H20 Nonane

C3H8 Propane C10H26 Decane

C4H10 Butane C11H24 Undecane

C5H12 Pentane C12H26 Dodecane

C6H14 Hexane C13H28 Tridecane

C7H16 Heptane C14H30 Tetradecane

Table 1A SATURATED HYDROCARBON

COMPOUNDS TO C14

Unsaturated HydrocarbonCompounds

Some reported compounds may be unsaturat-ed, such as benzene (C6H6) or toluene (C7H8),and can be recognized by the compound nameending in something other than -ane.Unsaturated hydrocarbons have hydrogen atomsthat number less than 2n+2 and are compoundsthat will react with hydrogen to varying degrees.

To avoid possible confusion and resultingerrors in the dew point calculation, it is advis-able to request that the gas analysis includeidentification of the hydrocarbon compoundsby chemical formula or carbon number and byname. A standard convention for naming com-pounds has been developed and is called theIUPAC system (International Union of Pure andApplied Chemistry). For more information onthis subject, refer to standard texts of organicchemistry, such as that listed in Reference 12.

B: Typical Component RemovalEfficiencies

The following information is for referencepurposes only. The equipment manufacturershould be contacted for details of performancecharacteristics, including separation efficiencyvariation with flow, particulate size and density.

Vertical Gas SeparatorsVertical vane-type separator with inlet baffle

for high liquid loads.

Liquid Removal Efficiency10 microns and larger 100%Turndown 2:1

Filter SeparatorsVertical or horizontal two-stage separator for

removal of solids and liquids.

Liquid Removal Efficiency8 microns and larger 100%0.5 to 8 microns 99.5%Solids Removal Efficiency3 microns and larger 100%0.5 to 3 microns 99.5%Turndown 100%

Multi-Tube FilterVertical or horizontal single-stage filters for

removal of solids.

Solids Removal Efficiency

3 microns and larger 100%0.5 to 3 microns 99.5%

Vertical Dry ScrubberVertical multi-cyclone separator for removal

of solids and liquids.

Liquid Removal Efficiency10 microns and larger 100%

Solids Removal Efficiency8 microns and larger 100%6 to 8 microns 99%4 to 6 microns 90%2 to 4 microns 85%Turndown 4:1

Vertical Absolute SeparatorsVertical single- or two-stage separator for

removal of solids and very fine mist.

Liquid removal efficiency3 microns and larger 100%Less than 3 microns 99.98%

Solids removal efficiency3 microns and larger 100%0.5 to 3 microns 99.5%Turndown 100%

Line SeparatorVertical vane type separatorLiquid removal efficiency10 microns and larger 100%Turndown 2:1

REFERENCES1. Federal Energy Regulatory Commission

(FERC) Order Number 636, RestructuringRule, April 8, 1992.

2. “Process Specification: Fuel Gases forCombustion In Heavy-Duty Gas Turbines,”GEI 41040E, GE, 1994.

3. “Gas Turbine Fuels,” ANSI/ASME B133.7M,1985, reaffirmed in 1992. An AmericanNational Standard published by theAmerican Society of Mechanical Engineers,United Engineering Center, New York.

4. “Variability of Natural Gas Composition inSelect Major Metropolitan Areas of theUnited States,” Liss, Thrasher, Steinmetz,Chowdiah and Attari, Gas Research Institutereport, GRI-92/0123.

5. “Obtaining Natural Gas Samples forAnalysis by Gas Chromatography,” GPAStandard 2166-85.

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6. “Gas Sampling for Accurate Btu, SpecificGravity and Compositional AnalysisDetermination,” Welker, Natural GasQuality and Energy MeasurementSymposium, Feb 5-6, 1996, published byThe Institute of Gas Technology.

7. “Method for Analysis of Natural gas by GasChromatography,” ASTM method D1945-81.

8. “GPA Method for Standard Gas Analysis,C1-C6+,” GPA 2261-95.

9. “Method for Extended Gas Analysis C1 -C14,” GPA 2286-95 GPA.

10. “Characterization and Measurement ofNatural Gas Trace Constituents, Vol II:Natural Gas Survey,” Gas Research Institutereport GRI-94/0243.2.

11. “Bureau of Mines Apparatus forDetermining the Dew Point of Gases UnderPressure,” Deaton and Frost, May 1938.

12. Fessenden, J.S. and R.J. “OrganicChemistr y,” Brooks/Cole PublishingCompany, 1990.

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© 1996 GE Company

LIST OF FIGURES

Figure 1. Equilibrium temperature lines for hydrate formationFigure 2. Joule-Thompson cooling with pressure reductionFigure 3. Gas sampling probeFigure 4. Vertical multi-clone dry scrubberFigure 5. Vertical gas separator (inertial vane type)Figure 6. Coalescing filterFigure 7. Combined filter-separatorFigure 8. Absolute separatorFigure 9. Electrical gas heaterFigure 10. Indirect-fired gas heaterFigure 11. Waste-heat gas fuel heaterFigure 12. Simplified schematic for a dual-source gas fuel heaterFigure 13. Simple particulate filtration used for dry gasFigure 14. For wet gas with non-slugging conditions upstream from pressure-reducing stationFigure 15. Dry scrubber installed to protect filter separator against excessive slugging conditionsFigure 16. Incoming wet gas with slugging potential upstream from pressure-reducing stationFigure 17. Dry scrubber and heater to protect pressure-reducing station from build-up of gas hydratesFigure 18. Common protection for pressure-reducing station and multiple-gas turbines each protected

individuallyFigure 19. Two-stage gas compressor providing more than 50 F/28 C superheat

LIST OF TABLES

Table 1. Variation of heating value and C6+ for U.S. and Canadian natural gasTable 2. Reported heating values and C6+ hydrocarbons throughout the U.S.Table 3. Comparison of standard and extended gas analyses on Calculated HC dew pointTable 1A. Saturated hydrocarbon Compounds to C14

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Colin WilkesColin Wilkes graduated with an MS in 1967 Cranfield, United

Kingdom, after serving an apprenticeship at the National Gas TurbineEstablishment. He joined the Aircraft Engine Group of GE in Evendale,Ohio, as a combustion engineer and transferred to Schenectady in 1970,where he worked on residual fuel and Dry Low NOx combustion. Heled a development team that ran a successful field test of a dual-fuel DryLow NOx combustor that was the prototype for today’s DLN-1 system.Colin left GE in 1981 and continued his career in gas turbine combus-tion before rejoining GE in 1993 as a technical leader, Dry Low NOxSystems. In this capacity, he provides systems engineering support fornew product development and production units.

A list of figures and tables appears at the end of this paper