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Geothermal production measurement
Measurements of mass flow and the constituents of the mass produced are integral in the production of geothermal fluids. From regulatory and royalty payment issues to monitoring the condition of the resource and abatement of corrosive constituents in the geothermal fluid, physical and chemical measurements are a necessity for geothermal production and utilization.
Depending on the phase being produced, the operator has a choice of many instruments for measuring flow. Conventional methods are typically used to measure flow for single-phase systems. The choice of flow element and meter initially depends on the mass and/or volumetric flow rate, turn-down ratio (range of flow to be measured), the pressure, temperature, and extent of flow surging. Fluid chemistry is also a factor that can affect reliability because geothermal fluids may be very corrosive and can deposit scale or contain solids that plug the instrument and produce inaccurate measurements. Differential producer-type flowmeters, such as orifice, venturi, V-cone, annubar and pitot tubes, are often used for steam, water and gas-flow rate measurement. Vortex and ultrasonic flowmeters are also sometimes used.
Because of the harsh conditions of geothermal production, conventional flowmeters may not maintain their calibration or even survive long in geothermal service. Because a large number of wells, consisting of many single- and two-phase flow streams, may produce to a power plant, a sufficient number of flowmeters is seldom installed to provide a complete mass balance on the system. In fact, many geothermal fields are produced without continuous flow-rate monitoring of the wells or total fluid through the power plant. Therefore, flow measurement is often necessary using portable, point-by-point, nondisruptive techniques.
One technique for single-phase vapor or brine flow measurement is a pitot tube traverse using an S-type pitot tube. The measurement principle is similar to that of an annubar, but the pitot tube can be easily inserted and removed through a small valve on the pipeline. This allows measurement of flow in any straight section of pipe that has an access port at least 1 in. [ 2.54 cm] in diameter. The pitot tube can traverse across the pipeline diameter to obtain high-resolution velocity profiles and accurate bulk flow rate measurements. These flow measurements are made in single-phase pipelines where conventional flowmeters either do not exist or require external calibration. This pitot tube is referred to an S-type because of the shape of the tip. The velocity pressure tube bends into the flowstream and the static pressure tube bends downstream. This configuration results in a compact tip assembly less than 1 in.[ 2.54 cm] in diameter and has the added benefit of amplifying the differential pressure reading by up to 2 times that of a standard pitot tube or annubar. A thermocouple sheath usually extends slightly beyond the pressure-sensing tubes to protect the tubes from impact against the pipe wall and to allow for concurrent temperature measurement to temperature-compensate the change in density of the fluid. The differential pressure is typically measured by a transducer with an accuracy of about +/–0.2% of full scale. Temperature is also measured so that saturation temperature and/or superheat values can be determined at each traverse point for the final volumetric and mass flow calculation. One of the most important features of a properly designed pitot tube system is the back-purge capability. The pressure sensing lines must be flushed with pressurized nitrogen or air at regular intervals during the measurement process to ensure that no condensate or brine accumulates in the lines. The presence of liquid in pressure sensing lines is the most common cause for error in standard differential-pressure flowmeters. Another technique for nondisruptive, portable flow measurement is tracer flow testing (TFT). This method was originally developed for two-phase flow but has the same applications for single-phase flow as the pitot tube. The basic principle behind the TFT method is to inject a conservative liquid or vapor tracer at a known rate upstream of a sample point. At the sample point, mass of tracer can be measured in the sample and calculations of flow rate can be determined. This method can be used to accurately calibrate stationary flowmeters.
Two-phase fluid-flow measurement by conventional mechanical devices is a more difficult problem. The most conventional method is to install production separators at the wellhead and measure the separated liquid and vapor produced by the techniques already described. Because of the high capital cost of wellhead separation systems, fluid gathering systems are usually installed, and vapor and fluid are separated at a more centralized facility.
In two-phase geothermal fields, monitoring the enthalpy of produced fluids is important in understanding the reservoir performance. Decreasing enthalpy can indicate breakthrough of injection water or invasion of cooler groundwater, while increasing enthalpy 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 fraction at sampling conditions and allows the correction of chemical concentrations back to reservoir conditions. Enthalpy and mass flow rate govern the amount of steam available from each well and ultimately the energy output of the power plant.
Mass flow rate of steam and water phases and total enthalpy of the flow can be measured directly for individual geothermal wells that produce to dedicated separators. However, because of 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 from 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 total enthalpy of individual wells cannot be measured during production.
An atmospheric separator, James tube and weir box can provide reasonably accurate enthalpy and mass-flow rate values. However, as this method requires diversion of flow from the power plant, with subsequent revenue losses, it is most frequently used during development production tests. In some fields, atmospheric venting of steam may not be allowed because of environmental regulations for hydrogen sulfide emissions and brine carryover.
The injection of chemical tracers into two-phase flow (i.e., TFT) allows the determination of steam and water mass flow rates directly from tracer concentrations and tracer injection rates, without disrupting the normal production conditions of the well. There are currently no other online two-phase flowmetering systems available for geothermal applications, but testing of a vortex shedding flowmeter (VFM) with a dielectric steam quality sensor (DSQS) was performed at the Okuaizu field, Japan in October 1998. The VFM/DSQS system was calibrated against the TFT method, and two of the three tests agreed within 10%. The DSQS is sensitive to liquid and vapor phase electrical conductivity, so large corrections are required for dissolved salts in brine and noncondensable gases (NCG) in steam. It was also concluded that the sensors would be adversely affected by scale deposition if used in continuous operation.
The tracer flow test technique requires precisely metered rates of liquid- and vapor-phase tracers injected into the two-phase flow stream. Samples of each phase are collected with sampling separators at a location downstream of the injection point to ensure complete mixing of the tracers in their respective phases. 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 rate of liquid (WL) and steam (WV) is given by
|WL,V||=||mass rate of fluid (liquid or steam),|
|WT||=||tracer injection mass rate,|
|CT||=||tracer concentration by weight.|
The mass rates calculated for each phase are valid for the temperature and pressure at the sample collection point. The total fluid enthalpy can then be calculated from a heat and mass balance equation using the known enthalpies of pure liquid and steam at the sample collection pressure/temperature. Enthalpy corrections can be made for high-salinity brine and high-NCG steam, if necessary.
The TFT liquid tracer can be measured directly on site and even online to obtain real-time liquid mass flow rate data using a dedicated portable analyzer. Data resolution is greatly improved over the discrete grab-sampling technique, especially under surging flow conditions. The gas tracer, usually sulfur hexafluoride (SF6), can also be sampled on site using portable instrumentation so that single-phase steam and two-phase flow-rate results are immediately available. Automated online systems can be used for continuous metering of multiple single and two-phase flow streams.
Examples of data from online brine flow measurements are shown in Figs. 1 and 2, as measured by a portable field analyzer for the liquid tracer. Note that the first well (Fig. 1) was producing at a stable rate, while the second well was surging significantly (Fig. 2). Well behavior and detailed flow resolution can be obtained by continuous real-time monitoring.
During flow testing, the continuous total mass flow rate can also be monitored using a two-phase orifice meter. In this case, TFT is used at regular intervals to determine the total discharge enthalpy, which is needed for the two-phase orifice calculation, and to calibrate the orifice meter. This technique is used at some power production facilities for continuous monitoring of wells in production to the power plants, with intermittent measurements by TFT. An example of the correlation between the two-phase orifice meter and TFT measurement for total flow is shown in Fig. 3 for the production wells at the Coso, California power plant. Although two-phase orifice metering is accurate to only about +/– 20%, it provides useful real-time trending data for total flow rate.
Fig. 3—Correlation between two-phase orifice meter and TFT measurements at the Coso, California geothermal field. Data collected by Thermochem during routine flow monitoring at the Coso, California, geothermal field. This figure is modified from Hirtz and Lovekin, used with permission from the Intl. Geothermal Association.
Flow measurement errors in well testing
The errors typically associated with the tracer flow testing (TFT) measurement process are summarized in Table 1. For comparison, an error analysis performed for a standard James-tube well test in the Philippines is given in Table 2, with calculations for two types of weirs used in brine flow measurement. The James-tube technique was a common well test method before the development of TFT. Drawbacks to the James-tube technique are the requirement that the well must be discharged to atmosphere and limited accuracy, especially at higher enthalpies.
Sampling of two-phase geothermal fluid requires special techniques involving inertial separation of phases.Geothermal steam frequently contains small amounts of entrained liquid water, noncondensable gases such as CO2, and other constituents such as silica. Some impurities, such as NaCl, may be present as dissolved species in the liquid or as solid particulate. These other constituents affect power generation efficiency and corrosion, but extensive discussion of their measurement is beyond the scope of this section.
Relevant terminology is summarized briefly next.
- Steam purity is the proportion of pure water (both liquid and vapor) in a fluid mixture.Typically, only steam impurity is discussed in quantitative terms and is expressed in units of concentration by mass in the mixture.
- Total dissolved solids is the concentration by mass of nonvolatile, dissolved impurities in the steam. These typically include silica, salts, and iron. Semivolatile constituents such as boric acid are not usually considered as part of the TDS.
- Noncondensable gases (NCG) are the other constituents that have a pronounced affect on geothermal operations. NCG is typically defined as a mass fraction, or weight percent. Principal NCG constituents include CO2, H2S, NH4, CH4, and H2. The amount of NCG produced with geothermal fluids must be known to correctly size NCG removal systems.
- Peña, J.M. and Campbell, H.E. 1987. Steam Wetness Measurement Using a Transversable Retractable Probe. Geothermal Resources Council Trans. 11: 53.
- Hirtz, P.N. et al. 1993. Enthalpy and Mass Flow-Rate Measurements for Two-Phase Geothermal Production by Tracer Dilution Techniques. Proc., Eighteenth Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California, 17.
- Hirtz, P. and Lovekin, J. 1995. Tracer Dilution Technique for Two-Phase Geothermal Production— Comparative Testing and Operating Experience. Proc., World Geothermal Congress, Florence, Italy, 1881.
- James, R. 1970. Factors Controlling Borehole Performance. Geothermics Special Issue 2 (2): 1502.
- Yasuda, Y., Horikoshi, T., and Jung, D.B. 2000. Development of a Two-Phase Flowmetering System, ed. Eduardo Iglesias et al. Proc., World Geothermal Congress, Pisa, Italy, 2999–3004.
- Hirtz, P.N. et al. 2001. Developments in Tracer Flow Testing for Geothermal Production Engineering. Geothermics 30 (6): 727.
- Benoit, D. 1992. A Case History of Injection through 1991 at Dixie Valley, Nevada. Geothermal Resources Council Trans. 16: 611.
- Standard E1675-2000, Standard Practice for Sampling Two-Phase Geothermal Fluid for Purposes of Chemical Analysis. 2004. West Conshohocken, Pennsylvania: American Society for Testing and Materials.
- Hirtz, P.N., Buck, C.L., and Kunzman, R.J. 1981. Current Techniques in Acid-Chloride Corrosion Control and Monitoring at The Geysers. Proc., Sixteenth Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California, 83.
- Stockman, E.J. et al. 1993. Measuring Steam Impurities in a Geothermal Pipeline System Using Real-Time Instrumentation. Geothermal Resources Council Trans. 17: 399.
- Stark, M. and Koenig, B. 2001. Generation Gain in the Northern Geysers Because of Injection-Derived NCG Reduction. Geothermal Resources Council Trans. 25: 469.
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