THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS 345 E. 47th St., New York, N.Y GT-227

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1 THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS 345 E. 47th St., New York, N.Y GT-227 The Society shall not be responsible for statements or opons advanced in papers or cllacussion at meetings of the Society or of Its Divisions or Sections, or printed in its publications. Discussion is minted only If the paper is published in an ASME Journal. Authorization to photocopy material for Internal or personal use under circumstance not talking within the fair use provisions of the Copyright Act is granted by ASME to libraries and other users registered with the Copyright Clearance Center (MC) Transactional Reporting Service provided that the base fee of $.3 per page is paid directly to the CCC, 27 Congress street Salem MA 197. Requests tor special permission or bulk reproduction should be addressed to the ASWE Technical Publishing Department. Copyright 1997 by ASME All Rights Reserved. Printed in U.S.A GAS FUEL CONDITIONING SYSTEM DESIGN CONSIDERATIONS FOR UTILITY GAS TURBINES Colin Wilkes Power Systems Division, General Electric Company, Schenectady, NY II Anthony J. Dean General Electric Research and Development Center 1 Research Circle, Niskayuna, New York, 1239 ABSTRACT This paper describes considerations that must be addressed when designing a gas fuel clean up system to meet utility gas turbine fuel specifications. Each gas turbine manufacturer has a gas fuel specification that must be met in order to protect the equipment from the effects of burning poor quality gas fuel. With the introduction of advanced technology combustion systems and strict emission requirements, it has become increasingly important that clean, dry gas fuel be provided at the inlet to the gas turbine control system in order to maintain the equipment in proper working order. The ASME gas fuel standard B133.7M is representative of a specification that meets or exceeds most manufacturer's requirements. This specification calls for superheating to avoid the condensation of moisture or hydrocarbon liquids and includes limits on particulate concentration and size. Issues relating to the fuel quality are discussed, including calculation and measurements of dew points. gas sampling and analysis and relative location of cleanup equipment required to meet this specification. INTRODUCTION Industrial gas turbines are capable of burning a wide variety of gaseous and liquid fuels. These fuels vary in hydrocarbon composition, physical properties. concentrations of potential pollutants and trace metals. To provide reliable and safe operation, limits of acceptable fuel quality with respect to contaminants and gas composition have been developed. These limits are described in the manufacturers gas fuel specification. Meeting the fuel specification, however, is usually the responsibility of the user and can be difficult if the process of gas cleanup and the properties relating to gas fuel liquids are not clearly understood. A particular challenge is the removal of hydrocarbon liquids in natural gas. Audience participation in panel discussions at the 1996 IGT/GRI gas quality conference indicated that an increase in natural gas liquids content has become a significant issue over the past few years. Competition among suppliers generated by FERC 636 may be adversely affecting gas quality as large industrial users select the lowest cost bidder. Hydrocarbon liquids are of concern because they lower the autoignition temperature of natural gas and can drastically change the fuel heating value during periods of slugging, a process involving unsteady flow of liquids and gas. The ASME gas turbine fuel standard BI33.7M (reaffirmed in 1992) is brief but states that the maximum condensation temperature for gas fuel must be below the minimum system temperature by a safe margin. A typical value for the safety margin is stated in appendix B as 28 C (5 F), which defines the superheat temperature above the moisture or hydrocarbon dew point. Also included are tables of typical fuel gas properties and limits on contaminants. The limit for particulates is 3 ppmwt of which no more than.1% can exceed approximately II microns, While typical limits of other properties are also listed, the values for superheat and particulates are of most concern here and will be used a guidelines for establishing the cleanup equipment design considerations. In the following sections. the authors have addressed these issues and have provided recommendations for methods of gas sampling, analysis. monitoring and cleanup equipment. NATURAL GAS COMPOSITION Pipeline natural gas is a combination of many hydrocarbon compounds the relative concentrations of which may vary with time and geographic location. As noted by Liss. Thrasher et al. (1992) Presented at the International Gas Turbine & Aeroengine Congress Sr Exhibition Orlando, Florida June 2 June 5,1997

2 there is significant variation in composition and physical properties of the natural gas supplied to various areas of the US. This report quantifies potential regional and seasonal variations in the composition and properties of natural gas, documents the peak shaving practices in the US and assesses the contribution of the gas composition variability on the formation of condensates. There is no regional bias between lumped hydrocarbon (C6+) content and location. with Texas pipelines showing both the highest and lowest values for these compounds. A companion report published by GRI in 1995 presents a survey of minor constituents in natural gas. While the variation in the composition of the gas generally has a small impact on the gas turbine operation (e.g. output. thermal efficiency), the formation of liquid condensates from the heavier hydrocarbons (hexanes +) is a major concern. Natural Gas Contaminants Some of the contaminants that are introduced into the natural gas supply through production and transportation processes are: water, salt water sand. clay rust iron sulfate, iron and copper sulfide lubricating oil, wet scrubber oil, crude oil, hydrocarbon liquids glycols from dehydration processes calcium carbonate gas hydrates. ice construction debris For proper operation. it is critical that all liquids and the majority of solids be removed prior to delivery to the gas turbine. Solid particulates can cause plugging and/or erosion of control valves, fuel nozzles and hot gas path components. Moisture is undesirable as it can combine with hydrocarbons to generate solids in the form of hydrates. Hydrocarbon liquids are a more serious issue as they can collect over long periods of time and result in liquid slugging as gas flow rates are increased after a period of reduced power operation. In addition, the typical auto-ignition temperature (All) required for spontaneous combustion with no ignition source for these liquids is in the 24 to 288 deg C (4 to 55 F) range. Exposure of hydrocarbon liquids to compressor discharge air above the A1T can result in ignition of the droplets. In some cases this may lead to hardware damage and premature ignition or -flashback'. in low emission, premixed combustion systems. Atmospheric pressure A1T's from Glassman (1987) are shown on Figure 1 for some of the heavier hydrocarbons found in natural gas. The minimum A1T decreases with increasing pressure. For example. minimum All of butane/air mixtures is about 3 C (572 F) at 152 kpa (22 psia) according to lost (1946). Gas Hydrate Formation Gas hydrates are crystalline materials that are formed when excess water is present in a high pressure gas line. Hydrates can deposit in stagnant areas upstream and downstream of orifice plates. valves, tee sections, instrumentation lines and fuel nozzles causing plugging and lack of process control. These solids are formed when water combines with natural gas compounds in the CI to C4 range when the gas temperature is below the equilibrium hydrate formation 6 5 w 4 ce I 3 UI UI 1 FIGURE 1: AUTO IGNITION TEMPERATURES FOR SELECTED HYDROCARBON COMPOUNDS AT ATMOSPHERIC PRESSURE temperature. In addition, the gas must be at or below the moisture dew point and have sufficient residence time at that condition for crystalline growth to take place. Although commonly associated with ice-type crystals. hydrates can form at temperatures significantly above C (32 F) at pipeline delivery pressures. Dew Point Calculation Calculation of dew points is laborious but several commercial computer programs are readily available to perform this task. Using the Peng-Robinson equation of state. HYSIM (see references) was used to calculate dew points. The minimum input requirements are operating pressure and gas composition. Figure 2 illustrates the vaporization curve plotted on pressure-temperature coordinates for the extended natural gas composition listed in Table I as sample I. The saturated vapor line represents the hydrocarbon dew point over a range of pressures. Two hydrate formation lines are also shown for two moisture levels to illustrate the sensitivity of formation temperature with concentration. The location of hydrate line can be to the right or left of the saturated hydrocarbon vapor line depending on gas composition. GAS SAMPLING AND ANALYSIS Because of the extreme sensitivity of the calculated dew point to relatively small quantities of heavy (C6+) hydrocarbons. an extended gas analysis to C14 with an accuracy of better than 1 ppmv is required for consistent results. Obtaining a spot gas -phase sample from dry gas that is both representative and repeatable is essential for dew point calculation and is the result of using proper sampling techniques. For best results, the sample should be taken at or close to the gas line operating temperature and pressure to avoid cooling due to expansion. A sampling probe should be used to extract the sample from the middle 1/3 of the gas line to avoid entrainment of liquids. Further details of sampling procedures can be found in Gas Processors Association (CPA) (1995). There is currently no standard for 2

3 measuring the amount of entrained liquids in a 'wet' gas. For wet gas the techniques described here will identify the gas as saturated and further testing must be done to determine the liquid fraction. A gas chromatograph is used in the laboratory or the field to analyze the gas sample and determine the gas hydrocarbon composition. The complete analysis will check for the presence of both hydrocarbons and non-hydrocarbons. Once the composition of a gas is determined, the hydrocarbon and moisture dewpoint can be calculated using one of several available software packages. The standard analysis is a common method for determining heating value. The standard analysis is performed in accordance with ASTM DI945 (1981) or CPA (1995) and adds together all hydrocarbons above C6 and reports the total as "C64 7. The results of the standard analysis should not be used for dewpoint determination unless assurance can be given that no hydrocarbons above C6 are present (i.e. C6 may be present but no C6+ ). Small quantities of heavy hydrocarbons above C6 raise the dewpoint significantly An extended analysis should be used except where no C. compounds are present. This type of analysis checks for the presence of the heavy hydrocarbons and quantifies their amounts to the level of C14. The extended analysis is more complicated and expensive than the standard analysis and not all laboratories can provide this service. However, it is the only type of analysis which will result in an accurate dewpoint calculation for gas containing hydrocarbons above C6. An analysis procedure for C1 through C14 is described in CPA (1995). Consider the gas analyses shown in Table 1 taken from an operating power plant gas supply. In this case an extended analysis was performed and for the purposes of this comparison, a standard analysis was mathematically generated by summing the C6+ constituents. The calculated dew points from the extended analyses are more than 12 C (54 F) above that calculated from the standard analysis. In extreme cases, differences of as much as 56 C (133 F) fa io 9 _ - HYDRATE 7 FORMATION LINE H2 = 29 ppmv tha 6 - w cc 5 co w 4 HYDRATE FORMATION LINE o. 3 H2 = 29 ppmv SATURATED SATURATED LIQUID VAPOR TEMPERATURE (C) FIGURE 2 :DEW POINT AND EQUILIBRIUM TEMPERATURE LINES FOR HYDRATE FORMATION have been observed. In addition to the calculated values, measured values of dew point were also determined in the laboratory and are shown for comparison. Typically, the calculated dew point will be higher than the measured value because of the error associated with observing the exact temperature at which the first droplet begins to form. The results illustrate the need for representative gas sampling and accurate analysis due to the sensitivity of the dew point calculation to small concentrations of the heavier hydrocarbons. Where possible. the gas analysis should be determined to less than 1 ppmv. Standard Analysis to Ce.. SAMPLE # 1 1 Extended Analysis to Cu Specie Name Weight % Weight % N2 Nitrogen CO2 Carbon Dioxide Water Vapor CH4 Methane C2H6 Ethane C3I-15 Propane C41-11 i-butane Cello n-butane C41-1,2 i-pentane C41-11: n-pentane GBH,. n-hexane CiHis n-heptane Celia n-octane C9I-124 n-nonane -.12 CloHn n-decane.6 Ci1H24 n-undane -.1 Ci2H2s Dodecane -. Ci3I-124 n-tddecane -.2 Ci4H3 n-tetradecane. Totals 1 1 Calc. HC 3447 kpa (C) Meas. HC 3447 kpa (C) TABLE 1: COMPARISON OF CALCULATED DEW POINT FOR STANDARD AND EXTENDED GAS ANALYSES 3

4 MEASUREMENT OF DEW POINT In practice, a direct measurement of dew point is preferred because of the difficulties with sampling and analyzing without contaminating the sample. A detailed gas analysis however, is required when performing a gas system analysis from the point of delivery to the site to the point of use. A commonly used and effective method for dew point measurement is based on the chilled mirror principle. A simple dew point tester (OPT), described by Deaton and Frost (1938), using this principle was developed by the Bureau of Mines (BoM) over 6 years ago and is commercially available today and has the capability of measuring to -129 C (-2 F) with liquid nitrogen, approximately - 4 C (-4 F) with carbon dioxide or -29 C (-2 F) with propane used as the refrigerant. The advantages of the BoM dew point tester are: The elimination of the uncertainty associated with sampling and analysis as the primary means of dewpoint determination Simple and easy to use Claimed accuracy is ±.1 C (±.2 F) for an experienced user Identifies moisture, hydrocarbon. glycol and alcohol dew points No electrical power required - intrinsically safe Results from field measurements using the BoM tester are shown on Table 2 together with the average calculated value at the same pressure from the extended gas analyses shown in Table I. It is important to note that the dew point readings and gas samples were taken from the same gas supply several days apart and the agreement may be fortuitous. Nevertheless, the dew point measurements were about as expected based on the calculated value. Another type of instrument that is commercially available is an automatic dew point monitor (DPM). This device contains up-to-date electronic and micro-processor equipment and automatically reduces the temperature of the mirror and records both hydrocarbon and moisture dew points at intervals of approximately 2 minutes. The use of an on-line device to automatically determine and record hydrocarbon dewpoint has many advantages over the difficulties involved with gas sampling and extended analyses. To date, however, only two commercial manufacturers have been identified that make this type of equipment. The advantages of automatically monitoring hydrocarbon dewpoint include the following: The elimination of the uncertainty associated with sampling and analysis as the primary means of dewpoint determination The potential for automatically adjusting gas temperature with changes in hydrocarbon dewpoint as a result of both transient and long term gas composition changes The elimination of unnecessary heat addition and possible decrease in overall plant efficiency Provides an alarm to plant operators that dew point is increasing and that corrective action should be taken e.g. increase superheat temperature Although electricity is required to operate these instruments, no calibration is needed. For both devices, a readily available gas with well known dew point characteristics such as propane can be used at various pressures as a sample gas for testing the functionality of the instrument. Laboratory Evaluation of an automatic dew point monitor An automated DPM (Boyar Model 241) was evaluated in a laboratory environment to verify the accuracy of the instrument. The dew points from the DPM were compared with the BoM DPT and with calculations. A schematic of the test set-up is shown in Fig. 3. First the instruments were tested using pure propane at various pressures. The results were consistent between both instruments and agree well with published tables for propane dew point. LIQUID HEXANE HOLDER Dew Point deg. C Pressure kpa Source VACUUM PUMP Dew point measurement Dew point measurement Dew point measurement Dew point measurement Calculated from extended gas analysis, Table 1 TABLE 2: MEASURED DEW POINT USING THE BOM TESTER VENT CHANDLER OPT FIGURE 3: TEST FACILITY FOR VALIDATION OF DEW POINT MONITOR A second set of tests involved a mixture of hydrocarbons where the presence of a minor constituent increases the dew point temperature. This is a more stringent test because unlike pure propane only a small fraction of the gas mixture condenses at the dew point temperature. Methane/hexane mixtures were made by evacuating the mixing tank to less than 2 tort and then adding the constituents by partial pressure. Hexane was added first to a pressure about 8 kpa (1.16 psia). Then methane was added to a pressure up to 3.4 Mpa (493 4

5 psia). To ensure proper mixing, the tests were performed at least 24 hours after making the mixture. There is excellent agreement in the dew point temperature between the calculations and the measurements from the two instruments as seen in Table 3. The automated DPM results were consistently slightly lower than the manual tester. This result can be explained by examining the raw signals from the detector in Fig. 4. There are two optical surfaces which allow water dew point and hydrocarbon dew point to be determined independently. One surface is smooth and highly polished and is used to detect condensation of water. The other is a rough. black surface and is used to detect the condensation of hydrocarbons. As temperature decreases the reflected signal from the rough surface dips and then increases. The DPM reported a dew point of -I2.83C (8.9 F) while the first change in signal occurred at -11.2C (11.8 F). Apparently the algorithm to determine dew point from this data uses increasing counts and ignores the slight dip in mirror output at the onset of dew formation. As expected there was very little change to the signal (see Fig. 4) from the smooth optical surface used for water condensation. Pressure DETECTOR COUNTS Calculated OPT Automated DPT BoM DPT (MPa) (C) (C) (C) Mixture mole fractions: Methane,.266 Hexane TABLE 3: COMPARISON OF DEW POINT MEASUREMENTS WITH CALCULATED VALUES Overall the agreement between the three methods of dew point determination is very good. These data show that an automated dew point monitor is a simple. accurate method of assessing the quality of natural gas at the inlet to a gas turbine. One limitation for all dew _ H2 SURFACE RC SURFACE MIRROR TEMPERATURE (C) FIGURE 4: RAW DETECTOR COUNTS AS A FUNCTION OF MIRROR TEMPERATURE AT 2.6 MPa. point monitors are glycols which can form a haze on the optical surface and do not readily evaporate when the mirror is heated. The best approach is to install a membrane glycol filter at the inlet to the monitor. GAS CLEANUP EQUIPMENT A wide variety of cleanup equipment is available from many suppliers. For removal of liquids or solids the method of separation is either inertial or by filtration. Inertial separators are usually of the vane type or cyclone type where acceleration of the gas/liquid/solid mixture results in phase separation and collection. Multiple. parallel cyclones (mutli-clones) of small diameter are usually used in preference to a single large cyclone because of an increase in separation efficiency as diameter decreases. Slug catchers or knock out drums are simple devices in which the gas/liquid stream is deflected and the liquids are collected at the bottom of the vessel. These devices are not a substitute for inertial/filtration devices and are only used as an upstream device if excess quantities of liquid are present. Advantages of the inertial type of separator are: Virtually maintenance free operation Tolerance to liquid slugging Low pressure drop with no increase with use Constant separation efficiency with time The major disadvantages with inertial separators is the limited turndown ratio (maximum volumetric flow rate/minimum volumetric flow rate) at the required separation efficiency and the inability to separate particles less than approximately 8-1 microns in diameter. Ramachandran. Leith et al (1991) and others have developed an empirical model for cyclone optimization based on data from 98 cyclone designs. Using this model it is possible to examine the effects of particle size and turndown on capture efficiency of solid particulates. For this study. the dimensional characteristics of a.51 m (2 ins) Stairmand cyclone were selected as being representative of a typical single element of a multi-clone design. Natural gas properties were used and the inlet velocity, which is proportional to volumetric flow rate at a constant pressure and temperature. was varied from 7.6 to 3.5 tn/s (25 to 1 ft/s). Above 3.5 m/s particles are re-entrained into the gas stream and efficiency begins to fall. At 36.6 m/s (12 ft/s). a significant decrease can be expected. Figure 5 shows the rapid increase in particle size passing as the inlet velocity is decreased below 15.2 mts (5 ft/s), indicating a turndown capability of about 2:1 is possible with a reasonable capture efficiency. Separation of liquids may be more effective as the droplets will coalesce on the walls rather than re-bounding into the gas stream. To be fully effective, staging of parallel cyclone elements would be required in order to maintain the inlet velocity within acceptable limits over the full range of operation from ignition to base load. Performance claims for separation equipment therefore need to he examined and well understood prior to preparing an equipment specification To overcome the limits of turndown and minimum particle size. filtration is used for either liquids or solids. Filters are generally available in parallel, multiple element configurations over a broad range of temperature and filtration capability depending on the 5

6 8 7 Ti c 6 5 uj N 4 Ui I 3 cc % CAPTURE EFFICIENCY 99.99% 99.% 1 2 INLET VELOCITY (m/s) 3 Feature Convenience of use H M L M Size S M Lg Lg Weight L H H H Transient response H to to hi Cost to M H H Ease of maintenance H ni L L Operating cost H to L L Effect on heat rate Hot side pressure vessel yes no yes yes Overall complexity L M H H FIGURE 5: EFFECT OF INLET VELOCITY ON PARTICLE SIZE PASSING material specified. For particulates. absolute filtration to 3 microns is readily available and for liquids, coalescing filters with capabilities to.3 microns and 6 ppbw are in common use. The major disadvantage of filters is the increase in pressure drop with use and the need for regular maintenance to change filter elements. Turndown over the entire operating range and dirt holding capacity are two parameters that are used to determine the number of elements required and the corresponding size of the filter vessel. To overcome the disadvantages of the filter, manufacturers have developed combined inertial/filtration devices commonly known as fl Iter/separators. By installing the inertial separator upstream of the filter, the dirt loading of the filter is greatly reduced extending the time between maintenance intervals while effective separation is maintained over the entire operating range. Combination units are available in a single pressure vessel with the inertial stage upstream or downstream of the filters. The filter/separator approach uses coalescing filters to generate large liquid droplets which are then removed by the inertial stage. In general, the separator-filter approach will have an improved overall capture efficiency but may have a higher cost than the filter-separator. For base loaded plants. a minimum of two separation units should be installed in parallel ('duplexed' arrangement) with isolation valves that permit maintenance of the out-of-service equipment without requiring a plant outage. For peaking plants, the daily downtime may be sufficient to permit periodic equipment maintenance and installation of a single separation unit ('simplex' arrangement) may be adequate. FUEL SUPERHEATING There are three common sources of heat available: electric, gas or oil and waste-heat. Each has economic, maintenance and operating advantages and disadvantages. An approximate value for the energy required to heat natural gas vapor by 28 C (5 F) is Legend: H = high, M = moderate, L = Low, S = small, Lg = large 1: Electrical, 2: Gas or Oil fired, 3: Waste-heat fired, 4: 2+3 TABLE 4: COMPARISON OF GAS SUPERHEATER TYPES kcal/kg (24 Btu/lb) of gas (assuming 1% efficiency). or approximately.15% of the gas calorific value. In all cases. superheating the fuel by 28 C will result in a small decrease in the fuel required for the gas turbine at a given turbine inlet temperature. This will result in an almost negligible decrease in power output due to the decrease in total mass flow but may have a positive effect on overall plant efficiency depending on the source of heat. If waste heat from the gas turbine exhaust is used as the heat source for the superheater. a small improvement in the simple cycle heat rate of approximately.3% can be expected for every 1 C increase in fuel temperature. Table 4 lists some of the relative advantages and disadvantages of each type of fuel heater. The choice of heater will depend several factors including the type of cycle, daily operating characteristics. space considerations, maintenance practices and the expected gas quality. CLEANUP SYSTEM DESIGN CONSIDERATIONS Fuel gas conditioning 'requires the removal of both liquid and solid contaminants from the gas stream and heating of the gas to provide the required superheat. Equipment to perform these tasks is readily available but an understanding of the gas fuel system and the impact of large pressure reductions have on the gas physical properties is required for successful implementation. Cooling will take place as a compressible gas is expanded due to the Joule-Thompson effect. The authors have reviewed gas fuels ranging from LNG to a wide variety of natural gases and have concluded that the temperature reduction is almost linear and is approximately equal to 5.6 C for every 1 kpa (7 F for 1 psid) reduction in pressure. This generalization is in agreement with similar observations made by Hill and Poulin (1992). To illustrate the need to evaluate the complete gas delivery system, consider the simplified schematic shown on Figure 6. 6

7 Here the local distribution company (LDC) has provided a heater followed by a filter separator upstream of the primary pressure reducing station. The purpose of the heater and liquid separator is to protect the pressure reducing station from liquid slugging and provide dry gas to the customer but without any specifications on superheat requirements. As no local measurement of dew point is available, the heater will usually be set to provide gas at a pre-determined minimum temperature. In this example. the gas listed in Table 1 is received from the pipeline at 7584 kpa and 12.8 C (11 psia and 55 F) and delivered to the custody transfer station in a dry condition with 5.5 C (1 F) of superheat at 4137 kpa and 22.2 C (6 psia and 72 F). This requires heating the gas to 4.5 C (15 F) prior to the expansion process. After custody transfer, the gas is further expanded in the secondary pressure reducing station to 2758 kpa (4 psia) where an additional 8.3 C (15 F)temperature reduction takes place. The gas leaving the secondary pressure reducing station is now in a wet saturated condition approximately 2.2 C (4 F) below the dew point. The heating and expansion process from the pipeline to the secondary pressure reducing station discharge is illustrated on Figure 7 by the path from I to 2 and 2 to 3 respectively. The secondary pressure reduction is represented by the path 3 to 4. Point 4 is below the dew point of the original gas and if no further clean up measures were to be applied. delivery to the gas turbine in this state would result in the formation of condensed liquids and potentially damaging results. To ensure compliance with the required gas fuel specification, a combined separator-filter followed by a nominal 28 C superheater is installed just upstream of the gas turbine. The separator and coalescing filter combination removes practically all of the moisture and particulates above.3 microns leaving the gas in a near-dry saturated condition (dew point equals the gas temperature). Heating the gas by 28 C raises the superheat by an equal amount and has been accomplished without the need to measure dew point. The vaporization curve following liquid separation illustrated on Fig. 8 while the superheating process is shown as the path from 4 to 5. If the pipeline gas is of a higher quality and the delivered gas is in dry and superheated condition, then little or no heating may be necessary to meet the fuel specification. In this situation. continuous INCOMING GAS 1 OAS FUEL NEATTJI TRANSPORTATTON COMPANY EOURMIENT SECONDARY PRESSURE REDUCING STATION COMBINED FILTER/SEPERATOR COMBINED GAS FUEL SEPARATOR AND SUPERHEATER COALESCING FILTER PRIMARY PRESSURE REDUCING STATION GAS FUEL METERING STATION OAS TURBINE' POWER PLANT EOUWWENT FIGURE 6: GAS FUEL DELIVERY SYSTEM WITH PARTICULATE AND LIQUIDS CLEAN UP GAS HEATING PROCESSED GAS AFTER LIQUIDS tu 5 REMOVAL co 4 SATURATED 2 LIQUID LINES 1 PRIMARY EXPANSION SECONDARY EXPANSION SUPERHEATING " Me 5 INCOMING GAS TEMPERATURE (C) FIGURE 7: HEATING, EXPANSION, LIQUID SEPARATION AND SUPERHEATING PROCESS dew point monitoring may be justified just upstream of the gas turbine. The monitor will record an increasing trend dew point temperature and either alarm the operator or call for gas superheating. In some cases the gas ma): have a hydrocarbon and moisture dew point below -34 to -4 C (-29 to -4 F) with little or no variation in composition. Under these circumstances the liquid removal system and superheater can be eliminated and a simple particulate filter installed. Energy Efficiency Considerations Gas heating for the purpose of eliminating the formation of liquids is best performed \vh i le no liquids are present. If condensation is allowed to take place. the liquids must first be separated and the remaining dry saturated gas then superheated. Heating a two phase gas/liquid mixture in a simple single pass heat exchanger will not ensure complete vaporization of the entrained droplets within the heat exchanger unless excess heat is applied. Separating hydrocarbon liquids from a gas stream, however, will reduce the heating value of the delivered vapor phase fuel and requires proper disposal of the liquids. If the delivered gas is heavily saturated, then removal or liquids could have a significant impact on the plant overall thermal efficiency. depending on whether the liquids are removed upstream or downstream of the custody transfer station. It is clearly in the interest of the plant owner to require that gas be provided in a dry state close to. or at. the pressure at which it will be delivered to the gas turbine. Under these conditions. the LDC would take the full pressure drop across the primary reducing station and the secondary reducing station would be used for trim purposes. This would require heating the gas to a higher temperature upstream of the custody transfer station to account for the increased pressure drop. Some further heating may he required upstream of the turbine to meet the fuel specification that would justify installation of an automatic dew point monitor in order to minimize superheating fuel or power consumption. To investigate the effect of removing hydrocarbon liquids from the gas stream, a simple process model was constructed using the gas 7

8 properties listed in Table I and the quantity of liquids removed from the gas stream was varied. The resulting gas/liquid mixture was then heated to vaporize and superheat the mixture by 28 C and the chemical energy recovered from the liquids compared with the energy required for superheating. Figure 8 shows the results normalized by the mass of the resulting vapor and the corresponding liquid concentration in the incoming mixture. The break-even point represents the point where the chemical energy recovered from the liquid just equals the energy required for vaporization and superheating. From the figure this is seen to be when the liquid content of the incoming mixture is approximately.15 % by weight. In other words, if the liquids removed by a separator exceed.15% of the incoming mixture, consideration should be given to heating the gas to a higher temperature upstream of the pressure reducing station in order to minimize the loss of energy due to liquids removal. Deaton and Frost "Bureau of Mines Apparatus for Determining the Dew Point of Gases Under Pressure -. R.I This example is greatly simplified and provides only an order of Federal Energy Regulatory Commission (FERC) order number Restructuring Rule. April SUPERHEAT AND 25 VAPORI2ATION ENERGY EQUALS ENERGY IN LIQUIDS REMOVED 2-5 I SUPERHEAT (28 C) ENERGY REQUIRED FOR DRY GAS ENERGY REQUIRED FOR SUPERHEATING (kcal/kg mixture).25 5,2 aee O z.15 al ce g.1 :oce 1-5 X.5 g a FIGURE 8: COMPARISON OF CHEMICAL ENERGY IN CONDENSED HYDROCARBON LIQUIDS WITH THAT REQUIRED TO VAPORIZE AND SUPERHEAT LIQUIDS AND GAS MIXTURE magnitude concentration that identifies the need for additional review. For a detailed and accurate analysis, considerations must also be given to the efficiencies and source of heat for the heaters, the potential gas and liquid composition changes and the effects on the gas turbine heat rate. SUMMARY The quality requirements for gas turbine fuels are clear and are provided by each manufacturer and an ASME standard is in place. Removal of solid contaminants from natural gas is well understood and easily accomplished. The methods used for cleanup of liquids however, are not always well understood. An analysis of the gas delivery system is required to ensure compliance with manufacturers standards and to provide an energy optimized system. Verification of gas quality using on-line measurement tools may be required. The information presented in this paper has outlined some of the key issues and provides a basis for understanding the cleanup process. REFERENCES Natural Gas Quality and Energy Measurement Conference sponsored by the Institute of Gas Technology in cooperation with The Gas Research Institute ANSI/ASME B133.7M reaffirmed in Gas Turbine Fuels. An American National Standard published by The American Society of Mechanical Engineers. United Engineering Center. 345 East 47th Street. New York, NY 117 ASTM method D "Method for Analysis of Natural gas by Gas Chromatography- CPA Standard Obtaining Natural Gas Samples for Analysis by Gas Chromatography" CPA "CPA method for standard gas analysis. C j - C6 +" CPA , "CPA method for extended gas analysis C1 - C14 GRI. 1995, "Characterization and Measurement of Natural Gas Trace Constituents Volume II: Natural Gas Survey". Gas Research Institute Report GRI-94/ January Glassman, I.. "Combustion Academic Press. New York Hill, W. S., Poulin, E. C Concept for Passive Heating at Meter/Gate Stations-. Final Report December August 199. GRI-8817, published by the Gas Research Institute HYSIM Version 2.5. process simulator computer software by Hyprotech Ltd.. Calgary. Canada lost. W., 1946, -Explosion and Combustion Processes in Gases-. McGraw-Hill, New York Liss, Thrasher, Steinmetz. Chowdiah and Attari "Variability of Natural Gas Composition in Select Major Metropolitan Areas of the United States"_ Gas Research Institute report GRI-92/123. Rarnachandran, G.. Leith. D.. Dirgo. j.. and Feldman. H "Cyclone Optimization Based on a New Emperical Model for Pressure Drop", Aerosol Science and Technology. vol 15. pp (1991) 8