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2 Geothermal Resources Council, TRANSACTIONS Vol. 5, October 1981 EVALUATING THE COURY HEAT EXCHANGER PROCESS FOR THE REMOVAL OF H,S GAS FROM GEOTHERMAL STEM G. E. Coury, R. A. Babionel, and E. E. Hughes2 'Coury and Associates, Inc., 7625 W. 5th Ave., Lakewood, Colorado EPRI, P.O. Box 1412, Palo Alto, California 9433 ABSTRACT The Coury Process, a heat exchanger process for reniovi ng hydrogen s ul fide ( H2S) from geothermal s team upstream of a power plant turbine, is presently being evaluated by Coury and Associates and Electric Power Research Institute (EPRI). The process uti - lizes a heat exchanger to condense and reevaporate geothermal steam, thus allowing the removal of non- condensable gases, including H2Ss in a concentrated vent stream. Small-scale field tests have been completed showing high removal rates of H2S and other noncondensables. Studies have been completed evaluating predicted costs and performance of various conf i gurati ons and appl i ca ti ons. Shellside baffles INTRODUCTION The presence of H2S gas in geothermal steam poses both envi ronmental and economic problems in geother mal power plant applications. H2S released to the atmosphere is a significant odor nuisance or a health hazard as a toxic gas, depending on concentration, and is potentially damaging to the environment. H2S contributes to corrosion and material deterioration problems with power plant equipment. The presence of all noncondensable gases affects thc performance and capital costs of geothermal power plants with respect to the efficiency in steam use and condenser and vacuum sys tern oversi zing requi rements. Environmental regulations concerning H2S emissions are necessitating the development of processes for H2S abatement in geothermal power plant appl i cati ons, An upstream process whi ch removes noncondensable gases, including H2S, without chemical treatment of the steam would be desirable. A new heat exchanger process for removing H2S gas and other noncondensable gases from geothermal steam upstream of the power plant turbine is currently being evaluated by Coury and Associates and EPRI, under an EPRI contract. Small-scale field tests of the process have been completed at The Geysers with the cooperation and assistance of Pacific Gas and Electric Company (PG&E). The following discussion describes the process, summarizes the results of the field tests, and describes comnercial-scale applications and costs. The final report for the work conducted under the EPRI contract (Ref. 1) presents a comprehensive review of the evaluation of this process. PROCESS DES CRI PT I ON The Coury heat exchanger process is shown schematically in Figure 1. Both the Shellside and tubeside LCV-2 Recr condensate rculatlng FCV-2 Pun 1 Blowdown Frgurn 1. Heat Exchanger Pmcess Vertrcal Tube Evaporator W i t h Baffled Shells4 de Confl guratl on. of the heat exchanger are at saturated conditions, with the tubeside at a pressure and temperature slightly lower than the shellside. This temperature difference causes a heat transfer from the shellside to the tubeside resulting in saturated steam condensing in the shellside and saturated condensate evaporating in the tubeside. The incoming geothermal steam, directly from a well in the case of a vapor-dominated resource or from a vapor-liquid separator at hydrothermal locations, is almost completely condensed. The resulting condensate wi 11 dissolve some of the noncondensable gases contained in the steam, but about 98% of the total noncondensable gases will remain in the vent gas stream. Over a typical range of geothermal steam composi ti ons and process operating condi - tions, 9 to 99% of the H2S will remain in the vent stream. The she1 lsi de condensate is transferred to the tubeside and is reevaporated as it circulates through the tubes. The total resulting tubeside vapor leaves the heat exchanger as clean steam to be supplied to the power plant turbine. The vent gas stream composition may range from less than 1% to more than 3% noncondensable gases. The vent gas mass flaw rate depends on the amount of 455

3 G. Coury, et al. noncondensable gases originally present in the geothermal steam. Calculations based on generalized conditions at The Geysers as shown in Table 1 indicate that the vent gas stream would contain something in the range of 1 to 4% of the initial geothermal steam when the inert gas content is in the range of 2 to 6 ppm. TABLE 1 STEAM COMPOSITIONS AT THE GEYSERS GEOTHERMAL FIELD Average Concen tra ti on Range Component ( ppm) co2 H2S "3 CHI, H i2 - Total Makeup and blowdown streams may be required to compensate for the enthalpy imbalance and to purge chemical species, such as boric acid produced in the wellhead steam, which may become concentrated in the tubesi de condensate. The rate of removal of gases from geothermal steam is determined by how much of each gas dissolves in the liquid phase as the entering steam condenses. The amount of gas absorbed at equilibrium is controlled by three factors: (1) the partial pressure of the gas in the vapor phase; (2) the mass ratio of vapor to liquid in contact with each other; and (3) the ph of the liquid solution. The major variables that affect gas removal rates are temperature, pressure, gas composition, and the percent of inlet steam vented. Figure 2 shows the results of calculations predicting H2S removal rates over a range of chemistries that can be expected in most geothermal steams. Two sets of curves are shown, one set for a heat exchanger vent rate of 2% (98% of the incoming water vapor condenses) and the other set for a vent rate of 1% (9% of the incoming water vapor condenses). The curves cover an H2S concentration range of 1 to 1 ppm. The curves show data for C2 concentrations of 3 and 8 ppm, data for cases with no "3, and cases with the NH, concentration equal to the H2S concentration. The ph range of the condensing liquid is shown for each case. As seen in Figure 2, when no NH3 is present, almost 97% of the H2S will be removed when 98% of the steam is condensed. On the other hand, when 9% is condensed, almost 99% of the H2S will be removed. High NH3 concentrations will reduce the efficiency of H2S removal. For 98% condensation of the steam, H2S removal in the presence of NH3 will be in the range of 91 to 96%. At the lower condensation rate of 9%, H2S removal rate varies from 95 to 98% in the presence of NH3. FIELD TEST RESULTS The testing of the small-scale test uni t at a geothermal location was a major part of the work con- ducted in evaluating this process. The test unit consisted of a 15-ft2 heat exchanger, simi'lar to that shown in Figure 1. These tests were conducted with the cooperation of PG&E at Unit 7 of The Geysers Power Plant, at a dry steam geothermal field. The objectives of the test program were to: (1) demonstrate the capability of the process to remove at least 9% of the H2S present in the incoming geothermal well steam; and (2) demonstrate the heat transfer performance of the falling-film vertical tube evaporator in a geothermal envi ronmen t. The test unit accumulated approximately 1 hours of operating time with the following results: The measured H2S removal rates were consistently better than 9%, with an average removal rate of 94%. Total noncondensable gas removal was indicated to be comparable to or better than the H2S removal. Measured heat transfer rates were high enough to i ndi cate acceptable economi cs for application of the process on a comercial scale. The average measured heat transfer coefficient was 576 Btu/ (h*ft2af) with indications that all measured Val ues were conservative. The test unit demonstrated very simple and predi ctable operating characteri sti cs during both s teady-s tate and transient conditions. Figure 3 shows the H2S removal data obtained during these tests, with HzS removal plotted versus heat exchanger vent rate. The H2S removal measurements, as defined below, ranged from 98 to 87% (the one data point lower than go%), with an average of 94% and a standard deviation of 2%. 456

4 -i 99 98' Y an rn 92- chemtrtty analysls error range: b4x* (error bands shown for reference) Variations due to erpected fluctuations in In- 88 let H2S and NH, concentrations:.5-2s B X Vent Rate figum 3. Test Unlt Perfomnce. H2S Removal Venus Vent Rate R = [l - $3. 1 where R = percent H2S removal X = clean steam H2S concentration (ppm) Y = inlet steam H2S concentration (ppm) Figure 3 shows the expected dependency of the H2S removal on vent rate with H2S removal increasing as the vent rate is increased; however, the linear curve fit of the data gives values slightly less than the theoretical predicted values. Most of the data represented in Figure 3 are from baseline tests with vent rates between 2 and 8% of the inlet steam flow rate and AT'S across the heat exchanger of between 5OF and 9OF. During the baseline tests, the inlet steam composition was not modified and was similar to that shown in Table 1. A few of the data points represent special tests such as high vent rate tests and gas injection tests. As expected, the high vent rate tests typically showed high levels of H2S removal. During the gas injection tests, the inlet steam concentrations of H2S and NH3 were artificially increased as much as four times over the normal concentrations and the ratio of NH3 to H2S concentrations in the inlet steam was varied from.2 to 2.. The H2S removal was essentially the same as experienced during the base1 i ne test, thus demons tra ti ng the high capability for H2S removal over a wide range of steam compositions. An error analysis of the data indicates that the expected variations in measured H2S removal range from.5 to 2% due to normal fluctuations of H2S and NH, concentrations at The Geysers, and from 1 to 4% due to normal errors in the chemistry analyses techniques. In accordance with these ranges of probable errors, error bands of +1 and,+4% are indicated in Figure 4. As can be seen, most of the data points and the predicted values are inside the 24% band. During the test program, a very high percentage of the composite inlet gas mixture, primarily C2, was consistently removed. Test data indicated removal levels comparable or better than for H2S. The measured heat transfer coefficient (U) values ranged from 333 to 788 Btu/(h-ft2soF) with an average of 576 and a standard deviation of 85. An evaluation of the U value measurement techniques indicated that the measured U values are probably conservative. COMMERCIAL-SCALE APPLICATIONS: COST AND PERFORMANCE Figure 4 is an example of a comnercial-scale H2S a- batement system that would be appropriate at both a dry steam resource such as The Geysers and a liquiddominated resource where liquid is flashed to produce steaq. This system consists of a two-stage heat exchanger process for removing H2S and other noncondensables and a Stretford plant for disposal of the removed H2S. The clean steam from the first stage supplies the power plant turbine and the vent gas goes to the second stage. Clean steam from the second stage is used to supply the after-turbine condenser vacuum system and the Stretford process. The vent condenser cools the second-stage vent gas down to temperatures required for discharge to a Stretford unit, normally around 12OoF. The condensate formed in the condenser is injected into disposal wells or discarded by some other means. flgurr 4 Geothermal stem Clean steam to turbine Hakeup water Recl rcula tinq e condensate ft rs t-s trge heat errhangers final Ant gar stream to Stre tford unl t Vent gas condenser Process Flar Olagram. Coamrcltl-Scale Heat Eachanner Process.HpS Abatcnwnt System The capital cost for the heat exchanger process system sized for a 55-MW power plant with steam conditions typical of The Geysers is estimated at $5.6 million. Based on vendor quotes, a 2.5-tonper-day Stretford unit cost is $2.6 million, giving a total abatement system cost of $8.2 million. Total direct annual operating costs for both the H2S removal process and the Stretford unit are estimated to be $425, or 1. mill/kwh. With annualized capital charges of 18.5%, the total annual operating and capital costs are $1,945, or 4.4 mills/kwh, including the Stretford unit. The subs tan ti a1 capi tal and operati ng costs associ ated with the Stretford unit could be avoided if alternative means for disposal of the H2S gas could be uti 1 i zed. 4 57

5 G. Coury, et al. The heat exchanger process could result in a slight loss in power production because of the vented steam and the lower pressure of the steam which goes to the turbine. However, since the process removes all of the noncondensable gases ahead of the turbine, the demands of the steam jet air ejector system are reduced and enough clean steam can be ob tai ned from the second-s tage heat exchanger to drive the ejectors. The potential power which can be produced per uni t of we1 lhead steam must take all of these factors into account. Calculations of theoretical power were done for various AT'S and vent rates. The results are presented in Figure 5 which shows the relative power produced by the steam from the heat exchanger process versus using 35OoF saturated wellhead steam directly. The figure is based on typical Geysers ratios of 95% of the wellhead steam going to the turbine and 5% going to the ejectors for the case without the heat exchanger process. The effect of the heat exchanger process on power production depends on the combined results of all of the factors discussed above which will vary with each specific application. Both AT and the heat transfer coefficient (U) have significant effects on the capital cost of the H2S abatement system. Figure 6 shows the cost effect of these parameters for a 55-MW H2S abatement system as previously described. The capital cost decreases as either AT or U values are increased. AT is essentially an operating parameter which has the effect of reducing overall power production capabilities as the AT is increased. The U value is essentially based on the physical design of the heat exchangers. U values of approximately 6 were measured during the field tests discussed a- bove; however, it is believed that design improvements could significantly increase the actual U values. The base case shown in Figure 6 represents the estimated costs presented above for the twostage 55-MW system. 12 Basis. I5 6 million for 55-MI heat e changer process with AT =!O'F. U = 6 Btu/(h-ftg.'F). HZS = 22 ppa, Capital Costs Vdry with 6 power of required heat transfer area Stretford plant cost constant at $2.6 milllon 8aSiS: 177OC (35OF) SdtUrdLed SUUM Without heat exchanger process. -45 of wellhead steam goes to vacuum rystca r O --No pressure loss upstream of Yu L a 12- turbtne PI- LO Y m cu Z- D I Y Is@ Y "Y 2% 25 -.I ;z 98- Y Y. -- 5: - LL 5 c.- 11 * c m c Y 29 U e 1 H 'F I 1 I I 1 1 I I OC O b G 2 I ' I1 1-2 OF 14 I I I I I OC Figure 6 Conparison of Heat Exchanger Process Capital Costs as a Function of Temperature mffemnce (bt) and Heat Transfer Coefficient (U) In First-Stage Heat Exchanger AT Figure 5 Coqdrison of Power Production Using Heat Exchanger Process as a Function of AT and Vent Lte -- REFERENCES 1. Coury, G., and R. A. Babione, 1981, A Heat Exchanger Process for the Removal of H2S Gas from Geothermal Steam--Final Report: Prepared for Electric Power Research Institute, Palo Alto, California. 4 58