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2 "'RACER Geothermal Resources Council TRANSACTIONS, Vo. 20, September/October 1006 TWO-PHASE FLOW AS^^^ BY ~~~~ T E ~ Q ~ FOR UENOTAI GEOTHERMAL FIELD IN JAPAN Tatsuya Sato', Kazumi Osato', Paul Hid2, Russell Kunzman', Masao Futagoishi3 1. Geothermal Energy Research and Development Co., Ltd. 2. Thermochem, Ine. 3. Akita Geothermal Energy Co., Ltd. ABSTRACT A tracer flow-test (TFT) survey of three production wells was performed in February, 1996, for Akita Geothermal Energy Co., Ltd. (AGECO) at the Uenotai geothermal field in the Akita prefecture of northern Honshu, Japan. The survey was conducted as a demonstration test of the chemical tracer method for two-phase flow m ~~ement. Although the tracer method has been in commercial use for about 4 years (Hirtz, Lovekin, 1995) ihis was the first time the technique had been applied on wells with mixing runs of less than 12 meters. The tracers were injected through the wing valve on the side of the ~llheads to maximize the tracer dispersion through the 9 meters of pipeline available before sample collection. The three wells tested had steam fractions at the wellhead of 38 to 99.4 % by weight and total flow rates of 31.5 to 51.5 tonsh. Based on the test results the chemical tracer method is considered accurate under the conditions experienced at the Uenotai geothermal field and has been adopted for routine flow rate and enthalpy monitoring. 1. I~RO~~CTION In geothermal fields that produce two-phase fluids, monitoring trends in the enthalpy (heat content) of'produced fluids is impo~t for ~ders~ding the reservoir's pe~ormance. Decreasing enthalpies can indicate breakthrough of injection water or invasion of cooler groundwater. Increasing enthalpies can indicate reservoir boiling and the formation of a steam cap. Enthalpy is essential for the interpretation of geochemical data because it determines the steam firaction at sampling conditions and allows the correction of chemical concentrations back to reservoir conditio^. The enthalpy and mass flow rate govern the amount of steam available fiom each. well and ultimately the energy output of the power plant. The mass flow rate of each phase and the corresponding total enthalpy can be measured directly for individual geothemal wells that produce to dedicated separators. However, due to the high" capital cost of production separators, most geothermal fluid gathering systems are designed with satellite separation stations in which several wells produce to a single separator. In many cases all of the two-phase fluids produced fiom a field are combined by the gathering system and separated in a large vessel at the power plant. Without dedicated production separators for each well, the steam and water mass flow rates and the total enthalpy of individual wells cannot be monitored during normal production. Test separators may be installed for groups of wells, so that the flow from individual wells may be diverted and metered separately during test intervals. Steam venting and production loss can be avoided by piping the separated fluids back to the main production line. However, diverting the well flow may change the flowing wellhead pressure, which could cause the enthalpy and flow rate of the fluids produced during tests to differ from the enthalpy and flow rate under normal operating conditions. Although lower in cost than dedicated production separators, test separator facilities still have relatively high capital and operating costs. James tube testing with a silencer and a weir box can provide reasonably accurate enthalpy and mass flow rate values (James, 1970). This method requires diversion of flow from production, with attendant revenue losses and fluid disposal costs. The atmospheric venting of steam may also require abatement of hydrogen sulfide to comply with environmental regulations. Flowing pressure and temperature (P-T) surveys within p~duction wells can be interpreted to estimate enthalpy (Kaspereit, 1990). This method is accurate when the fluid enters the wellbore as a single-phase liquid, but it is much less reliable when there are fluid entries above the flash point. The interpretation of flowing P-T surveys gives only qualitative information about mass flow rates. Geothermometry can be used to estimate the enthalpy of produced fluids (Foumier and Potter, 1982). However, this technique also requires the fluid to enter the wellbore as a single-phase liquid and it provides no orm mat ion about the mass output of the well, The injection of chemical tracers into two-phase flow allows the determination of steam and water mass flow rates directly fkom tracer concentrations and the known tracer injection rates without disrupting the normal production conditions of the 845

3 Sato, Osato, Hirtz, Kunzman, Futagoishi well. This testing technique does not require any flow diversion from the power plant, so there are no power revenue losses or environmental impacts due to discharged steam and water. The TFT technique for the measurement of steam and water mass flow rates and total enthalpy of two-phase geothermal fluids has been in use for four years in the USA. The tracer technique was first tested and adopted on a field-wide basis at the Cos0 geothermal field in California. Validation of the method was performed at the Roosevelt Hot Springs geothermal project in Utah and the Salton Sea and Heber geothermal projects in California by direct comparison to orifice-plate flowmeter measurements of the separated phases. Production well mass flow rates and total enthalpy are now regularly measured by this technique in the Cos0 and Salton Sea geothermal fields. Combined single-phase steam and brine flows from production separators are also regularly monitored at these fields to verify the performance of on-line orifice and V-cone flowmeters. The TFT technique was introduced in the Philippines in early 1995 and has been adopted on a field-wide basis for the Tiwi and Mak-Ban geothermal projects. 11. TRACER FLOW-TEST TECHNIQUE Theory of Method The tracer flow-test technique requires precisely metered rates of liquid- and vapor-phase tracers injected into the two-phase flow stream. s of each phase are collected from sampling separators at a location far enough downstream of the injection point to insure complete mixing of the liquid and vapor tracers in their respective phases. s are collected both before tracer injection (for background analysis, if necessary) and again during tracer injection. The water and steam samples are analyzed for tracer content, and the mass flow rate of each phase is calculated based on these measured concentrations and the injection rate of each tracer. The mass flow rates calculated for each phase are valid for the pressure and temperature conditions in the pipeline at the sample collection point. This pressure andor temperature is needed to calculate the total fluid enthalpy. The mass flow rate of each phase is determined by the following mass-balance equations: Where Q, = Vapor Mass Flow rate QL = Liquid Mass Flow rate QTV = Vapor Tracer Mass Injection Rate QTL = Liquid Tracer Injection Rate C, = Tracer Concentration in Vapor CL = Tracer Concentration in Liquid CB = Background Concentration of Tracer in Respective Phase The entire measurement process is performed by mass, resulting in true mass flow rates for each phase. The vapor mass flow rate includes noncondensible gas (NCG) which can be subtracted out directly to yield only steam if the total NCG content is measured. The liquid mass flow rate includes dissolved salts (TDS) which can also be subtracted out directly if the TDS is measured. The total fluid enthalpy is determined by the following heat and mass balance equation: HT = Total fluid Enthalpy Hv = Enthalpy of Saturated Steam HL = Enthalpy of Saturated Liquid In cases of high NCG content, greater than about 2% by weight, the steam mass flow rate should be used rather than the vapor mass flow rate to calculate the total fluid enthalpy. Under these conditions, the saturation enthalpy for both steam and liquid should be based on the measured temperature or the measured pressure after correction for the NCG partial pressure. In cases where the liquid salinity is high, greater than about 5%.by weight, the enthalpy of the liquid phase should be based on a Pressure-Volume-Temperature (PVT) model for high-salinity brine. Under these conditions, the steam may be superheated relative to pure liquid water and the enthalpy of steam should be based on the measured temperature and the measured pressure after correction for the NCG partial pressure. The selection criteria for liquid- and vapor-phase tracers, techniques for metering and injection of tracers, and procedures for two-phase sampling are discussed in detail by Hirtz et al. (1 993) UENOTAI FIELD TEST Summary of the Uenotai Geothermal Project The Uenotai geothermal field, currently being developed by the Akita Geothermal Energy Co. (AGECO), where the Dowa Mining Co. (DOWA) explored successfully in 1986, is located on the northern heights of the Quaternary volcanic mountains at southeastern comer of Akita Prefecture, Japan. No surface manifestation is found in the project area itself which is totally covered with the Quaternary acidic pyroclastics, however, several hot springs and haroles are known in the surrounding area. The field is one of the most promising areas which had been found from the surface and subsurface exploration by DOWA in the area covering 200 square kilometers since Based 046

4 ~ Sato, Osato, Hi&, Kunzman, Futagoishi Table 1. Uenotai Production Wells \ Well Name T-4 1 T-42 T-44 T-45 T-46 T-5 1 T-52 T-53 Year Drilled Maximum Steam, Brine, Drilled Site Depth, m Temp., O C ton/hr ton/hr 1980 B 1, C 1, C 1, B 1, C 1, C 1, C 2,O B 2, on the data obtained during the exploration and because of the geographic advantages, the exploration had been concentrated to the Uenotai field since 1975 as the first priority area to be developed, including the drilling of the large exploratory wells and the joint investigation for the commercial power generation with the Tohoku Electric Power Co. During a simultaneous production test in 1988, it was observed that the stabilized flow rate of the steam fiom eight wells was 272 tonhour (WHP=6 ksca) and that most of the wells are steam dominated with a few exceptions where a minor amount of a typical NaCl - type hot water were produced. The overall stedwater ratio was 3/1. After the simultaneous production test, a geothermal reservoir simulation was performed based on the significant amount of the data that was provided by DOWA, AGECO, and the Japanese government. It was concluded that the field had enough potential for long-term, 27.5 MW, power generation, Commercial production was started in March of A total of seven production wells are now used for power generation. There are two production wells sites named Site B and Cy with each having one separator connected to three or four production wells. The individual well information is given in Table 1 (M. Morikuni and R. Takeuchi, 1995). Tracer Flow-Test Results for Uenotai The tracer flow-test survey was conducted at the Uenotai field on the wells T-41, T-45, T-53 in late February of 1996, during normal full-load operation of the power plant. The wells are located on a single wellpad (Site B) and feed to a common production separator. The total flow rates of steam and brine for all three wells were measured by single-phase orifice meters downstream of the Site B separator during the test. Normally, steam flow is measured continuously and brine flow is only measured periodically fiom the separator. Testing was complicated by deep snow on the wellpad (3 meters) and low temperatures at night (-15 OC) which required the use of freeze protection for the liquid tracer and related equipment. No equipment failures were experienced during the testing. The typical pipeline configuration for the wells tested is shown in Figure 1. The tracer was injected through the side wingvalve of each wellhead located within the well cellars (below grade) using a probe inserted to the center of the flowstream. The probe assembly consisted of heavy-wall 1 cm diameter (O.D.) stainless-steel tubing, about 1 meter long, inserted through a high-pressure packing gland. The gas and liquid tracers were delivered together to the injection probe through 15 meters of high-pressure flexible hose from the tracer injection skid. The tracers used for Uenotai were selected based on their stability under the production pipeline conditions and their extreme detectability. These tracers are considered proprietary at this time. By using highly detectable tracers, very low injection rates were possible, which simplified tracer handling and storage requirements. This also allowed substantial downsizing of the tracer injection skid h m the original design (Hirtz et al., 1993) and made it possible to mount the entire skid on a small flat-bed four-wheel drive truck. The tracers were recovered fiom the pipeline about 9 meters downstream of the wellhead using sampling separators to collect samples of each phase according to ASTM method E The sampling points were also downstream of the flow control valve for each well, which causes flow turbulence 047

5 Sato, Osato, Hirtz, Kununan, Futagoishi Figure 1. Pipeline Configuration a - and aids in the tracer mixing process. There was concern about the mixing process in the pipeline for the tracers because of the very short mixing runs. Prior to this test, the TFT procedure had never been implemented on a well with less than 12 meters of mixing run. Previous testing has shown that mixing may not be not sufficient, even with piping runs over 12 meters, when tracer injection is downstream of the wellhead and no flow control valve is present between the injection and sampling points (Hirtz et al., 1995). For wells T-41 and T-45, a single separator was used to collect the samples of brine and steam fiom a sample port on the side of the pipeline. There was no problem in collecting adequate samples of each phase fiom the side port because there were approximately equal proportions of brine and steam in the pipelines for these wells. Two separators were used for well T- 53, one on the top port for steam and one on the bottom of the pipeline to collect brine. This configuration was necessary due to the very low brine fraction of T-53. However, using the bottom port, it was possible to collect sufficient quantities of brine for a valid measurement. The TFT results, including the test parameters recorded for each well, are given in Tables 2 through 4. In reviewing the test results, it appears there was sufficient mixing induced by the 90" bend at the wellhead tee and the flow control valve upstream of the sample points. Often the test results are highly variable if there is not sufficient mixing, but in this case for all wells tested the results were very consistent. Although the additional sample ports needed to verifl adequate mixing were not available (Hirtz et al., 1995), the results suggest that the mixing was sufficient. 848

6 Sato, Osato, Hirtz, Kunzman, Futagoishi Table 2 Well T-41 Tracer Flow Test Results :12 12:45 12:50 13:Ol 13:06 13:16 13:21 Pipeline Gas Tracer ppm, Tracer Steam Flow rate, Pressure, ksc Inj. Rate, SLPM in Steam ton/hr E E Pipeline Liquid Tracer ppm, Tracer Brine Flow rate, Pressure, ksc Inj. Rate, g/min in Brine ton/hr Table 3 Well T-45 Tracer Flow Test Results :15 Pipeline Gas Tracer ppm, Tracer Steam Flow rate, Pressure, ksc Inj. Rate, SLPM in Steam ton/hr oo 6.67E oo 6.63E Table 4 Well T-53 Tracer Flow Test Results Pipeline Gas Tracer ppm, Tracer Steam Flow rate, Pressure, ksc Inj. Rate, SLPM in Steam ton/hr - 12: oo 5.99E I 12:48 I 7.17 I 1.oo I E I 12:26 12:31 12:36 12:42 12:47 Pipeline Liquid Tracer ppm, Tracer Brine Flow rate, Pressure, ksc Inj. Rate, g/min in Brine ton/hr O Not Equilibrated

7 Sato, Osato, Hirtz, Kununan, Futagoishi Table 5 AGECO Flow rate Summary Results Corrected to Ksc Flash Pressure Location Well T-4 1, Tracer Method Well T-45, Tracer Method Well T-53, Tracer Method Sum of Wells T-41, T-45, T-53 Production Separator Orifice Meter Percent Difference. Well Sum Steam Flow, tonhr Brine Flow, ton/hr Total Flow, ton/br O% % -5.6% Mixing can also be verified by comparing the tracer results to known flow rates, if possible. For Uenotai, the three wells tested all produced to a single separator with the total flow rates of steam and brine measured by orifice meters after the separator. The test results for each well are corrected to the production separator pressure and listed in Table 5. As shown, the agreement is good for the sum of the steam, brine and total well flow rates in comparison to the separator measurements. The greatest deviation is in the brine flow rate, which may the result of the mixing process. Previous testing has confirmed that dispersion of the steam tracer is more rapid than the liquid tracer (Hirtz et al., 1995). VI. CONCLUSIONS Since the agreement is good and within the measurement error for both the tracer flow-test and orifice meter methods, it appears that the overall mixing process for the Uenotai wells was adequate. This was a successful test and demonstrated that it is possible to implement the TFT technique on Uenotai wells for accurate on-line two-phase flow measurement. It was also demonstrated that this technique could be routinely used during harsh winter conditions without much difficulty. The TFT method is planned to be used on a regular basis for testing of all Uenotai production wells. ACKNOWLEDGMENTS, The authors wish to express their appreciation to AGECO for permission to write this paper and for the preparation and assistance provided in the testing. We also would like to give our thanks to Akira Sat0 for his assistance with the field testing. REFERENCES Hirtz, P., Lovekin, J., Copp J., Buck, C., and Adams M., (1993); Enthalpy and Mass Flow rate Measurements for Two-Phase Geothermal Production by Tracer Dilution Techniques, Proceedings, Eighteenth Workshop on Geothermal Reservoir Engineering., Stanford Geothermal Program, Stanford, CA. James, R. (1965); Metering of Steam-Water Two-Phase Flow by Sharp-Edged Orifices,, -. Vol. 180, pp James, R. (1970); Factors Controlling Borehole Performance, U.N. Symposium on the Development and Use of Geothermal Resources, Creothgrmu, Vol. 2, pp Kaspereit, D.H. (1 990); Enthalpy Determination Using Flowing Pressure-Temperature Surveys in Two-Phase Wellbores in the Cos0 Geothermal Field, Geothermal Resources Council Transactions, Vol. 14, Part 11, pp Hirtz, P. and Lovekin, J., (1 995); Tracer Dilution Measurements For Two-Phase Geothermal Production: Comparative Testing And Operating Experience, Geothermal Resources Council Transactions, Vol. 19. Naka, T. and Okada, H. (1 992): Exploration and Development of Uenotai Geothermal Field, Akita Prefecture, Northeastern Japan, Mining Geology, 42, Morikuni, M. and Takeuchi R. (1 995): The Geothermal Development of Uenotai Area, Geothermal Energy, 19, Fournier, R. O., and Potter 11, R. W. (1982); A Revised and Expanded Silica (Quartz) Geothermometer, Geothermal Resources Council Bulletin, Vol. 1 1, NO. 10, pp