Measurement Requirements ana Methods for Geothermal Reservoir System Parameters (An Appraisal) Eemthermal Beservair management

One of the key needs in the advancement of geothermal energy is the availability of adequate measurements to aid the reservoir and production engineer in the development and operation of geothermal reservoirs, wells and the overall process plant. This report documents the geothermal parameters and their measurement requirements and provides an appraisal of measurement methods and instruments capable of meeting the requirements together with recommendations on identified deficiencies. measurement

This report documents an appraisal of measurement methods for geothermal well system parameters performed by Measurement Analysis Corporation (MAC) for the University of California Lawrence Berkeley Laboratory (UCLBL). The specific objectives of the appraisal were the following: 1. Ascertain the key geothermal reservoir system parameters and quantify their associated measurement performance requirements.

2.
Perform an appraisal of current measurement methods and instruments capable of meeting the measurement performance requirements, and 3. measurement deficiencies identified.
Emphasis of the appraisal was on geothermal fluid properties such as temperature, pressure, single and two phase flow rate, thermal energy, and composition; however, measurement needs and requirements are also included for in-situ reservoir formation properties and well physical status properties.
The Lawrency Berkeley Laboratory (UCLBL) has been assigned by the U . S . Department of Energy's Division of Geothermal Energy the task of developing and implementing a comprehensive plan for support of research and development in geothermal reservoir engineering (reference 1 ) . task is the development of improved measurement techniques to aid the reservoir and production engineer in the development and operation of geothermal reservoirs, wells and the overall process plant. Due to the extreme hostile geothermal fluid and downhole measurement environments (high temperature and pressure, corrosion, scaling, etc.) combined with unique operational and geological formation conditions, the measurement techniques and instruments available are very limited or non-existent. Due to these measurement limitations, many needed parameters cannot be adequately measured thus leaving the reservoir engineer to make his own estimate. These limitations have resulted in a federally sponsored program to improve and/or develop key measurement systems to help speed or enhance the commercial development of geothermal energy as an economic, reliable and environmentally acceptable energy source. While some of the key instrumentation Provide recommendations for any key Included as part of this needs have been identified and programs initiated for their improvement/development (references 2 and 3 ) , an overall comprehensive definition of the parameters of value, their quantitative measurement performance requirements, and an assessment of available current measurement techniques and instrumentation which might be utilized, improved or developed to fulfill the requirements was required. UCLBL to perform this appraisal and report based on MAC'S unique expertise and experience in areas of geophysical and process measurement systems, its familiarity with the geothermal energy development organizations and its ability to be unbiased in critiquing the various instruments.
A complementary appraisal was completed in early 1978 pertaining to characterization of geothermal brines (reference 4 ) and projects have been initiated to meet some of the deficiences (references 5-7). The appraisal and the improvement projects underway concentrate on downhole measurement requirements and methods for fluid chemistry/composition. As such, this review has not concentrated on fluid electrochemical sensing, sampling and analysis techniques.
The approach followed by MAC in performing this appraisal was to prepare a preliminary document defining the various key geothermal parameters identified together with a set of quantitative measurement performance requirements for each parameter and a list of possible measurement sensor techniques to be evaluated. This document was then distributed to technical representatives of geothermal energy development organizations for assistance in prioritizing the parameters, refining the quantitative measurement performance criteria, and obtaining inputs on specific measurement methods and sensors utilized or considered to date. A list of the organizations and individuals contacted is provided in Appendix A. were held with many of these individuals to obtain detailed data and feedback on their parameter measurement needs and performance requirements.
The key geothermal parameters and measurement performance criteria were revised to incorporate industries',input and were used as criteria in evaluating measurement methods and instrumentation. The following report presents the findings of this appraisal.
MAC was selected by Meetings 1 2.0 SUMMARY A comprehensive review of the parameters associated with process fluid, in-situ formation and well status required by the geothermal reservoir and production engineers was performed and their measurement requirements have been identified. Using these requirements, an appraisal of current measurement methods and instruments was performed and are summarized in this report, together with an identification of suppliers for the various types of instrumentation. This appraisal concentrated on basic sensor transducer techniques and their inherent limitations and potential for being used to meet the very hostile geothermal process fluid and downhole environments. Recognizing that commercially available electronics that can operate above about 2OO0C (%400°F) is currently limited to a few basic components, downhole signal conditioning for well logging transducers will require thermal protection or await the development of special high temperature electronics. Division of Geothermal Energy is currently sponsoring several major projects for the development of high temperature components and integrated circuits (references 2-3). Fortunately, many sensor measurement techniques employ only a few basic electrical components in their sensing element and can currently operate or can be improved to operate at high temperatures if their support signal conditioning can be located in a low temperature environment.
are existing commercially available technology and measurement systems for all wellhead and The U.S. Department of Energy's Based on the appraisal, it appears that there process plant measurement requirements except for two phase flow measurements. However, downhole logging is primarily limited to tolerable fluid temperature and low resolution pressure measurements leaving the primary reservoirlproducing zone parameters obtained from pressure transient testing techniques employing surface instrumentation. High resolution pressure sensors and flow rate logging tools employing turbine meters for operation up to 2 7 5 O C are currently under development. Some of the simpler electrical induction and nuclear logging tools have been hardened for operation up to about 26OoC (500OF); however, their reported performance to date in geothermal well environments is at best poor. engineers in the geothermal development industry have almost unanimously agreed that the current measurement limitations which should receive the highest development priority to help advance the commercialization of geothermal energy are: Inputs received from reservoir and production Besides these five key parameters, improvements in measuring all identified parameters will be helpful. The parameter measurement requirements and methods presented in the following subsections have been assembled from inputs received from numerous organizations currently involved in geothermal energy development (see Appendix A); however, these parameters and requirements should not be considered all inclusive. It is very difficult to establish both the need and measurement performance requirements for geothermal energy applications. Due to the infancy of geothermal energy development, except vapor dominated reservoirs such as the Geysers, most requirements and efforts to measure process parameters have been associated with reservoir testing (i.e., well flow and interference tests). As such, the need and requirements for process plant start-up, operation and maintenance must be estimated and will vary depending on the specific reservoir and the fluid properties and type of energy conversion process employed. This is further amplified by the large number of different fluid flow conditions within a given process plant. For an overview of the variety of geothermal electric cycles and associated process fluid flow conditions, the reader is referred to reference 8. and type of measurement methods vary widely, and no one 'universal' geothermal process parameter sensor system will exist. Instead, several types of sensors will be utilized and it is up to the user to select an 'acceptable' sensor for his application.

The range of measurement requirements
It should be noted that the downhole well measurement requirements and sensors presented and reviewed in the following subsections are further constrained by the current limitation of electromechanical logging cables, evaluation of commercial electromechanical (EM) well logging cables in a high temperature air environment was sponsored by DOE in 1977 (reference 9). having additional eable tests performed to evaluate cable performance in a high temperature brine environment. The results to date indicate the best commercial =conductor cables.are good for less than 8 hours up to about 3OO0C, and multiconductor cables are good for less than 8 hours and up to about 26OoC.
of EM well logging cables are included in Appendix C.

A preliminary
Sandia Laboratories is currently

Identified manufacturers
To evaluate fluid property sensors, an overall perspective of the range of borehole and pipe sizes and associated access restrictions, fluid flow rates, viscosities, tolerable pressure losses, corrosion, abrasion and scaling constraints must be considered. Table 3.1-1 attempts to delineate some of these key constraints. Within the process plant and wellhead-surface fluid distribution system, there are numerous requirements for continuous or regular monitoring of process fluid properties, most of which are in high quality steam (x>95%) or liquid lines. However, some low quality two phase fluid conditions can also be encountered. A major problem in two phase and supply liquid brine lines is scale build-up on contacting surfaces, especially protruding surfaces. The scaling, if not monitored, can cause thermal and electrical insulation of the sensors and associated error. The scale build-up will also change the geometry/ cross section of calibrated sensor bodies such as orifice, drag bodies, etc. -Production wells will tvDicallv ,. '.
The following four subsections give the measurement performance requirements for the four key geothermal fluid parameters considered which are: 1) temperature, 2) pressure, 3) fluid flow rate and thermal energy, and 4) composition.
Each subsection includes a description and comparison of various types of sensor techniques considered. of the manufacturers identified for each type of sensor. It should be noted that numerous other basic sensor techniques for these parameters exist, however, the methods presented are those which based on reviewed data are felt worthy of including in this appraisal study. For a detailed technical description o f theory of operation of the various sensing techniques, the reader should refer to a basic text on physical techniques (i.e., references 12-14! and the manufacturers' literature. Also included is a list of 801118 I 3.1.1 FLUID TEMPERATURE Process fluid temperature is always a high priority measurement parameter in geothermal energy systems from early exploration through process plant operations. Downhole temperabure measurements are required primarily during exploration, well formation test/evaluation and start-up monitor phases of geothermal operations. For plant operations, there is a demand for reliable electronic readout sensors with remote monitor capability.  (2) Resolution down to 0.1'C desired by some for possible identification of formation producing zones.
Besides being required as a direct process parameter, temperature is also required indirectly to calibrate/compensate most other parameter measurements such as pressure and flow rate sensors. While accurate and straightforward measurement techniques exist for obtaining process fluid temperatures, one limitation has been aired. The limitation is that of scaling and associated thermal insulation on pipelines and thermowells inserted in pipelines resulting in loss of calibration and/or lack of confidence in measurements.
Of the numerous types of basic temperature sensing techniques, only three electrical types appear worthy of consideration for geothermal application. These are 1) resistance temperature detectors (BTD's); 2) thermistors; and 3) thermocouples. For applications not requiring remote readout, bi-metallic thermometers with a dial readout are available. A bi-metallic sensor is also utilized in the Kuster Company's 'bomb' type high temperature well logging tool. thermal fluid filled bulb-bourdon tube sensor is utilized in the Geophysical Research Corporation's (GRC's) 'bomb' type high temperature well logging tool. Maximum indicating temperature sensors configured as decals, pellets or markers that change color or melt at precise temperatures are available for special monitor applications such as within well logging and other downhole tools. Bi-metallic and mercury-glass thermometers can also be configured as maximum reading indicators; however, the maximum indicator can change in a shock or vibration environment. Table 3.1.1-2 provides a performance comparison for these six types of sensors. electrical sensors, resistance temperature detectors incorporating a platinum element are felt to represent the best all around sensor for geothermal process temperature measurements which can meet the stringent geothermal performance requirements. It should be pointed out that the performance data given in Table 3.1.1-2 is for the temperature sensor only. As such, most temperature measurement systems will not achieve these listed performances. This is especially true of the downhole 'bomb' type logging tool employing mechanical recording units.

A Of the three
The number of organizations manufacturing temperature sensors is considerable as is indicated by the partial list given in Table 3     A s can be seen from Table 3.1.1-4, only one p r o t o t y p e e l e c t r i c a l temperature logging t o o l (#7) sponsored by t h e U.S. Department of Energy, c u r r e n t l y meets a l l t h e geothermal near-term downhole requirements given i n Table  3

PROCESS FLUID PRESSURB
Process fluid pressure is a required parameter for all phases of geothermal energy exploration, development and reservoir/plant operation. Due to the wide range in requirements and associated performance criteria for geothermal process fluid pressure measurements, the requirements have been divided into the following three use categories: 1 -Downhole pressure measurements for well interference testing; 2 -Downhole pressure measurements for well flow tests and other well logging operation and maintenance application; pressure.

-Wellhead and process cycle flow line
The specific measurement performance requirements for these are given in Table 3.1.2-1. applications require DC (static) pressure response. These requirements represent a trade-off between what is desired and what can be tolerated by the user versus cost, reliability, and state-of-theart pressure sensor performance.

All
Numerous commercially available ruggedized process pressure transducers exist that meet the wellhead and process plant requirements shown in Table 3.1.2-1. This is possible by isolating the transducers from the very high temperature process fluid with stand-off tubing or linkage to maintain the sensor and electronics below about 2000F (93OC). As in temperature well logging there are more pressure well logging tools and serviees for operation below 4 0 W F .
In comparing downhole performance requirements versus available pressure well logging tools, it is concluded that there are no available commercial tools which completely meet either of the downhole criteria, and the only prototype tool that meets the general requirement is cable limited. temperature, high precision pressure gauges for downhole measurements, geothermal reservoir engineers have been using the Sperry-Sun, Inc. pressure transmission system consisting of a long capillary tube (.094"0.D.) which is suspended down the well with a pressure coupling chamber at the bottom and a low temperature precision pressure transducer connected at the surface. An inert gas or synthetic fluid in the tube provides the pressure transmission link. This technique requires calibration corrections for ambient pressure, coupling fluid expansion due to temperature, etc. Also, the suspended tubing length is limited to about 5,000 Eeet without experiencing Due to the lack of any high excessive stretching and/or failure. Though reported desired by geothermal reservoir engineers to locate the observation well pressure sensor down at the producing zone depth to reduce sources of error, it has proved acceptable to locate the sensor in a less hostile location in the wellbore. For some reservoirs, acceptable pressure data has been obtained by locating the sensor below the minimum water level in the wellbore. One successful pressure sensing method reported for an interference test in Utah was to measure the change in height at the top of the wellbore water column in the observation well.
Due to the identified lack of commercial high temperature pressure sensors for incorporation in well logging tools, the following portion of this subsection will attempt to review basic pressure sensor techniques to provide a review of possible sensing techniques for this downhole pressure measurement deficiency.
There are many basic types of fluid pressure sensing techniques and numerous manufacturers for most types.
types experience some amount of thermal sensitivity shift and thermal zero shift which require compensation in order to meet the stringent accuracy and drift requirements for geothermal downhole applications. Basic fluid pressure transducers typically consist of two functional subsystem/elements: 1) a pressure to force/displacement element, and 2) a forceldisplacement to display signal transducer element. For electrical signal transducer elements, a third auxiliary element consisting of signal conditioning is required which may or may not be integral to the transducer.
Fluid pressure to force/displacement usually consist of one of the following types of elastic element configurations: No one type of pressure to force/displacement element is best or worst but what is important is the detailed mechanical design of each unit to provide a linear response over the pressure range and be insensitive to external environments such as temperature, case pressure,.acceleration, etc.
oame passive concept as ~3  System temp controllcompensatian to *0.2'C to achieve performance quoted. Also makes unit like # 3 below.
Sperry-Sun sells for use with their 'tube' pressure transmission system. Hi temp @ pressure (530'F @ 10,000 psi) unit currently under joint development with Sandia Labs -will have high temp electronics. Some types are more applicable for higher or lower pressure ranges; however, the key factor is in selecting the right type for the specific signal transducer element selected. The following is a list of the identified commercial force/displacement to electrical transducer methods employed in DC pressure transducers:

Mfg claims higher pressure (5K-10K) unit is developable-basic
. Due to the unavailability of commercial high temperature active electronics, the review has concentrated on items 1 and 2. However, it must be noted that ultimate accuracy, resolution and/or drift stability is in many instances, limited by the signal conditioning. Also, the inherent performance of the various types of sensors is to some degree controlled by the manufacturers' detailed design innovations, workmanship, and quality of materials and components. As such, it is difficult to determine inherent performance limits on any specific type of pressure sensor. However, it is possible to review, assess and document current performance of commercially available sensors. Table 3.1.2-3 presents a performance comparison of commercial pressure transducers incorporating various sensor techniques presented above. The manufacturers and models listed are not all inclusive but were selected as representative of current typical state-of-the-art performance and there are numerous other manufacturers, especially for accuracies greater than about 112%. For most sensor systems described, their resolution and drift are limited by the signal conditioning electronics rather than the sensor. All sensors would require temperature compensation. It is also noted that sensors #7 through 114 as listed in Table 3.1.2-3 do not include signal conditioning as do the first six which have all their electronics integrally packaged. As such, selection of the 'best' sensor technique for high temperature (>450°F) downhole interference testing is not technically straightforward. However, in weighing current performance and cost with sensor system size, simplicity and the complexity of support signal conditioning electronics, the following techniques appear more developable for downhole precision geothermal pressure measurement s : . Bellows with vibrating quartz bar . Diaphragm with capacitance sensor . Bourdon tube with differential transformer . Oscillating quartz crystal Sandia Laboratories' Geothermal Technology Division is currently performing R&D on a new, high temperature (530'F) oscillating quartz crystal (reference 15) and is also working with Paroscientific, Inc. to harden their bellows with vibrating quartz bar sensor to operate up to 530°F (reference 3 and Table 3. 1.2-3, 114).
To meet the other downhole pressure measurement applications, it would appear the diaphragm with thin film strain gage sensor represents the best candidate since an existing commercial sensor already meets all the performance requirements and the signal conditioning is relatively simple (reference Table 3.1.2-3, #9).

FLUID FLOW RATE
There are numerous types of process flow rate measurement systems capable of measuring liquid and/or vapor flow. However, the commercial systems capable of accurate and reliable performance in hostile geothermal process applications is at best limited t o a few restrictive applications. Further, there are very limited and generally inaccurate methods for measuring two phase flow rates for even non-hostile, low volume flow rate process applications. mentioned previously, besides very high fluid temperatures, a major sensor design/performance problem encountered in many geothermal supply liquid and two phase brlne lines is scale buildup and corrosion on contacting surfaces, especially protruding ones. Due to the ability of most single phase flow sensors to measure both liquid and vapor states, single phase including high quality steam will be discussed in the following subsection with two phase flow presented in the subsequent subsection.

SINGLE PHASE FLOW
Single phase flow of both liquid (brine) and high quality (~2 9 5 % ) steam flow measurement systems will be addressed in this section. The performance requirements for the single phase liquid flow are given in Table 3.1.3-28 while the single phase and high quality steam flow requirements are given in Table 3.1-3-2B. and fluid viscosities given in Table 3.1-1 results in Reynolds Numbers that are above 10,000 for flow velocity above 1 ftfsec.
Using typical pipe diameters  . Pressure probe (pitot) . Drag (target) . Variable orificefmovable obstruction Turbine Thermal anemometers Vortex Other Some flow meter types give a measure of the spatial average velocity across the pipe. However, since the velocity profile across the pipe in laminar flow (non-turbulent) is not constant, flow measurement systems that sense velocity at one small spatial location must be calibrated to compensate for what may be very large discrepancies in the velocity measured versus the spatial average fluid flow velocity in the pipe. Insertion type flow measurement meters will be sensitive to this type of problem. They will sense a local velocity and the user must be aware and make the required calibration changes in order to obtain the average flow velocity of the system. Another problem will surface when the flow is so low such that air voids are created making the fluid a two phase liquid-air media making its velocity measurements impossible with single phase flow measurement meters. It is suggested that when the flow is so low to create air voids, the measurement be taken on a neck-down venturi section or vertical section be installed to eliminate and/or minimize the two phase flow in the sensor section.  The performance data comparison for each type of single phase flow meter category reviewed, is felt to be representative of the various commercial flow meters on the market, Included in the table is the author's appraisal of the potential for each category in geothermal downhole logging and process pipeline measurement applications. The results indicate all techniques have potential for process plant application, however, it is felt that acoustic flow sensing techniques are more capable of being configured t o meet the downhole geothermal flow sensing measurement requirements and environment. and types of flow meters they manufacture. The following subsections will address each type of single phase flow meter category in more detail. Measurement techniques, ranges of measurements, pressure and temperature ranges, accuracies and applicability to geothermal well systems are closely scrutinized. Mass flow rates may be obtained by simple calculation of the product of the flow velocity, flow cross sectional area, and density of the fluid. The fluid density must be obtained from other measurement techniques. A discussion of fluid density sensors is included under two phase flow since the sensors reviewed will measure both single and two phase flow.    doppler flow measurement is identical to an active sonar system wherein the emitted acoustic wave is reflected from particulate and/or bubbles in the fluid and receiv-d at the place of emission with a frequency (doppler) shift relative velocity between the transducer and the moving particles or bubbles. design, the transducer produces an acoustic wave train at a frequency, fs. When the wave collides with a particle or air bubble (i.e., impedance mismatch), some amount will be reflected back to the receiving transducer. The frequency, f , , of tbe received reflected wave train will be shifted in frequency. Assuming the velocity of sound in the fluid, C, is known or can be measured, then the average fluid velocity for the flow is proportional to the average frequency shift, Af, and may be properly measured. For two phase flow with different phase velocities, the reflected ultrasonic wave energy will have two frequency shifts related to the two relative velocities. As such, spectral averaging of the received reflected wave must be performed to measure the different phase velocities. The doppler technique can incorporate a continuous wave (CW) mode which gives a spatial average or a pulse mode which provides distance and some spatial cross section (beam width) discrimination. The only doppler systems identified iccorporate continuous wave acoustic transmission systems with separate transmit and receive transducers paclcqged aide by side as one sensor assembly. The meters are obstructionless with bi-directional sensing capability. This type of measurement can be performed in a dirty fluid with sludge and/or heavy caating, giving the fluid flow velocity as a linear function of the electrode signal across the tube. The inner liner of the flow meter must be made of a non-conductive material which presents pressure and temperature limitations for many geothermal process applications. Most commercially available systems can be provided with ultrasonic cleaners for the exposed electrodes.

PRESSURE HEAD FLOW SENSORS
Pressure head flow sensors comprise those types of sensors which relate 1) the pressure loss, AP, across a fixed obstruction such as an orifice or venturi; 2) the differential pressure, AP, between the dynamic and static flow stream pressures such as a pitot tube; 3) the force applied to a fixed obstruction in the flow tube such as drag body; or (4) the displacement of an obstruction resulting in a variable cross section such as a rotometer or variable orifice to fluid flow rate. The main advantage to these types of. probes is simplicity, low cost and high temperature operation, while the main disadvantages are limited accuracy, dynamic range (except variable cross section) and for geothermal application, scaling and pressure drop represent added problems. However, due to their high temperature operation, head meters are most widely used flow meters used to date by the geothermal energy development industry. Their reported satisfaction with these head meters has at best been marginally tolerable.
A schematic of a drag force meter is shown in There are numerous commercially available turbine flow meters. The general technique is to measure the liquid flow by directing the fluid through a multiblade turbine rotor. The fluid stream exerts a torque on the rotor causing it to rotate at an angular speed proportional to the fluid flow rate. The rotor is connected to some type of tachometer such as a pulse counter where the pulses are generated by each blade as it passes a sensing device placed in the housing.
The pulse frqquency (Hz) can be shown to be linearly proportional to fluid velocity over a wide range of flow rates. Typical accuracies achieved are *1/2%. rneters are viscosity sensitive to a degree, the fluid viscosity limits for a specific linear flow range must also be considered by the user. The turbine performance is generally given in the form of a curve of calibration coefficient as a function of pulse frequency over viscosity or Since all turbine flow Flow in small pipes is strictly measured by the inline type while for large pipes (above 16 inches diameter) insertion types are used. Thermal anemometers relate fluid velocity to the heat removed from a 'hot wire' or 'film' probe. Figure 3.1.3-7 shows a typical probe configuration. The exposed 'hot wire' probe typically consists of a platinum-plated tungsten wire suspended on two arms, and the 'film' type probe typically consists of a temperature sensitive conductive thin film such as platinum, on variously shaped bodies encased in quartz. The wire of film is electrically heated and the power supplied is a measure of the velocity of the flowing medium. Two control sensing methods are employed. The first is to supply a constant current through the sensing wire or film. Variation of flow velocity will cause a change in temperature, hence a change in resistance which thereby becomes a measure of flow. The second and most commonly employed method is to maintain constant temperature by varying the current input which similarly results in the measurement of flow velocity. The heat loss from the probe is also a function of fluid characteristics such as thermal conductivity, specific heat, density, etc., hence requiring proper calibration curves andlor measurement of the parameters that influence the probe heat loss. Exposed 'hot wire' probes are only used in gases and nonconducting liquids whereas the film probe can be used in conducting liquids such as geothermal brine.
The advantages of the thermal probes are their small sensing elements, short response time, high sensitivity, no moving parts, and good velocity ranges. While some of their disadvantages are their susceptibility to corrosion and scaling and they are delicate (break very easily).
The hot wire probe is very delicate due to the fineness of the wire across the prongs. Thermal anemometers are typically used as laboratory flow instruments. The film sensor type is less delicate than the hot wire and has been used successfully fn the ocean environment. However, the high temperature and corrosive liquid brine will cause pitting and scaling therefore giving erroneous measurement results. Also the liquid bubbles in steam will change the heat transfer characteristics causing a drift in the calibration. Based on the above information, both probe types are considered inadequate for geothermal well logging operation. Strouhal's number fluid velocity frontal width of the blunt object velocitv will be DroDortional to the shedding frequenc; if Strouhal's Number is a constant. It was shown by experimental tests that Strouhal's Number has less than 112% deviation for Reynolds Number above lo4. Strouhal's Number has a perturbation of fl% for Reynolds' Numbers between 5x103 and 104, Number of 5x103, the Strouhal's Number will increase rapidly making the flow meter inaccurate.
It may be generally stated that vortex flow meters will operate with reasonable accuracies in a turbulent flow media.

Below a Reynolds'
The methods used to sense the vortex shedding frequency vary considerably and are typically the limiting performance element of the instrument. vortex meters reviewed giving this sensing technique and performance. .

.3-6 presents a tabulation of the
Manufacturers claim that there is no problem with fowling the blunt object due to the high tunbulance. However, their use in geothermal process lines should be limited to relatively clean fluids. One unit is currently being used/evaluated in a liquid flow loop at one of the Roosevelt Hot Springs (Utah) KGRA well sites with excellent performance reported to date.

OTHER SINGLE PHASE FLOW SENSING TECHNIQUES
As noted previously, there have probably been more than a hundred flow velocity sensing techniques devised over the years. lists a few of those reviewed but were felt not to warrant serious consideration for use in hostile environment geothermal flow lines and/or have not been proven as a viable process fluid flow sensor.

TWO PHASE F L U I D MASS FLOW RATE AND ENTHALPY
There are many applications where the direct measurement of two phase geothermal brine-steam fluid flow rate and fluid enthalpy are desired. However, due to the unavailability of commercial two phase flow measurement systems for other than benign, small flow rate fluids, the geothermal industry has to date, improvised using indirect measurement techniques.
A continued measurement problem for geothermal reservoir engineers is the measurement of two phase mass flow rate and enthalpy in performing well flow tests. To date, the two methods employed with tolerable success are: 1. Use a separator and measure the single phase flow and enthalpy. Enthalpy can also be measured in the liquid zone downhole below the two phase zone.
The James' technique requires knowing the fluid enthalpy to relate critical lip pressure to mass flow rate or utilizing a separator down stream in conjunction with lip pressure and measuring the liquid mass flow and enthalpy. The James technique has not worked successfully in some areas due to excessive scaling and is considered to 'at best' yeild measurement accuracies of f20%. complaint in using a separator is its size which can represent a portability problem for some well sites where roads and access are poor or limited. Another constraint at most well sites is that electrical power is not available thereby requiring a portable power supply. The current approach of most of the geothermal development organizations is to locate a separator into the area early in the reservoir testing/development phase to minimize the portability problem.

The primary
Many liquid dominated hydrothermal energy conversion cycles currently being developed or being considered incorporate the flashing of the geothermal brine into steam. In some of these cycles, the flashing begins within the wellbore or even possibly in the formation itself-similar to vapor dominated reservoirs. Prior to entering a steam separator (scrubber), the quality can vary anywhere up to about 10%. Most 'scrubbed' fluids will have steam lines of qualities exceeding 98%; however, within the conversion process plant the steam quality in some lines may be as low as 80%.  3-7 gives the range of two phase flow rates, enthalpy and quality with the desired flow measurement performance requirements. The only identified requirement for a downhole two phase flow measurement is a sensor to determine where in the borehole two phase flow exists such as identifying where the transition zone starts in liquid dominated reservoirs or determine if any liquid is entering the borehole in a vapor dominated reservoir producing zone. There is a requirement to measure downhole fluid velocity in the producing zone of liquid dominated reservoirs when the well(s) is shut-in (not flowing); however, the producing zone will be in a single phase liquid state with the well shut-in. Also the fluid will typically be in a single phase liquid state with the well flowing due to the downhole pressure at the producing formation.
For large diameter pipes (i.e., > 3 " ) most two phase sensing devices are of the in-line insertion type which sense only a small percentage of the overall pipe cross section or they incorporate a small flow sampling by-pass line where the sensor(s) are installed. A major problem with these insertion or by-pass techniques is the requirement that the flow regime be homogeneous; which is very difficult to achieve in other than high quality vapor. shows the two phase flow regimes encountered in horizontal and vertical pipes (reference 19). The only homogeneous flows where insertion type of by-pass sampling is valid are spray or annular dispersed flow. To improve the homogenity of two phase flow, 'flow homogenizers' consisting of vanes or orifices are installed directly upstream of the sensing devices. Even with flow homogenizers installed, most data reported in the literature indicate variances in the measurements exceeding *20% for low quality flow. The understanding and measurement of two phase low quality (x<95%) fluid flow parameters such as mass flow rate is an age old problem which to date has met with very limited success. Currently, there are numerous publications on two phase flow including one journal devoted specifically to the subject (International Journal of Multiphase Flow) and numerous research and development projects on the development of two phase flow measurement systems. For the past several years, the U.S. Nuclear Regulatory Commission (NRC), the Electric Power Research Institute (EPRI) and similar foreign country nuclear energy organizations have been sponsoring numerous research and development projects for two phase flow instrumentation for transient mass flow measurements in reactor safety studies (references [20][21][22][23][24][25]. The nuclear reactor fluid measurement environment is similar to geothermal fluids (very high temperature water-steam), however, geothermal fluids contain scaling, corrosion chemicals and noncondensable gases.  1 6 S C 6 ( t y p i c a l l y S < 2) 0.5 <Vv <IO0 One less Btringent requirement for geothermal measurements is they do not require fast transient response. Based on a recent review group meeting wherein the status of all of these instrument related R&D projects were presented, together with reviewing numerous papers, tests and manufacturers' literature, it is this author's opinion that development of reliable instrumentation to meet the two phase geothermal measurement requirements will be a long, difficult. high risk project. Further, based on discussions with members of the geothermal energy development industry, the availability of such measurement tools does not appear to be critical to the development of geothermal energy. However, the availability of a small reliable low cost instrument is very desirableyespecially for well flow tests.
The following subsections provide a brief discussion of two phase mass flow rate, enthalpy and density measurement techniques and sensors reviewed.

MASS FLOW RATE
Two phase water-steam mass flow measurement techniques will be divided into the following, categories:  A third thermal heating mass flow meter manufactured by Agar Instrumentation was also reviewed. This instrument is designed for measurement of single phase hot (up to 800°F) corrosive gases and no data on its use with steam or two phase fluid was available.

J?LUID ENTHALPHY AND QUALITY (CALORIMETRY)
While the computation of single phase liquid (water) and saturated of superheated steam enthalpy can be performed with measurements of temperature and pressure, measurement of the quality andlor enthalpy in two phase fluid flow is much more difficult, especially in low quality (x<95%) non-homogeneous flow. Identified applications for measuring the quality of two phase geothermal fluid are: 1. During.the performance of well flow 2.
3. For measuring heat loss through segments pressure transient tests.
To periodically measure the performance of steam separators.
While the measurement accuracies for well flow tests (applicatlon 1) are not stringent, the quality of the fluid is typically less than 50%, is not homogeneous, contains undissolved gases and is subject to severe scaling and corrosion on eaposed surfaces. The reverse situation is encountered in the other two applications wherein high measurement accuracy is the principal difficulty with the fluid being high quality, relatively clean steam. A fourth measurement application, though not yet reported but required by the geothermal industry, i s the measurement of enthalpy and/or quality in the fluid delivered to the procuring utility company at some location(s) in the conversion plant such as the steam at the turbine input or fluid at binary heat exchange input and the fluid at the injection well input.
LBL has recently contracted with Battelle-Pacific Northwest Laboratory to perform a detailed review and design tradeoff study f o r calorimeeers to measure geothermal wellhead enthalpy (application 1 above). As such, the remaining discussion here will only briefly list the qhality and enthalpy measurement techniques.
Steam calorimetry is a well developed science and several measurement techniques, instruments and associated sampling methods are well documented (reference 26).
The two most commonly used are the throttling calorimeter and the separating calorimeter which are discussed in most thermodynamic texts, for measurement of very high quality steam while the separating calorimeter will measure any quality, One problem noted by a geothermal development organization working at the Geysers is that neither of these two units were acuurate enough for The throttling calorimeter i s only suitable application 1 3 above. For this application, they were interested in accuracies of less than 2 BW's per pound of steam (<$.2% of reading), Besides these two classic calorimeter methods, the following i s a list of other methods considered: . Condensing 'barrel' calorimeter (see . Heat exchanger/cdndenser technique . . Measurement of average void fraction (z), vapor and liquid phase velocities, temperahure and pressure The first two methods listed involving condenser and heat exchanges require sampling/by-pass techniques with their inherent sampling error problems, however , the density and void fraction/ phase Velocity techniques can be in-line devices. The heat exchange/condenser technique was proposed as a method for geothermal wellhead flow quality measurements but was not developed or tested. Both the latter methods require obtaining the density of the vapor and liquid from temperature and pressure conditions. equations give the relationships utilized: Currenr: commercial identified sensors to measure void fraction employ fiber optic techniques which are not currently suitable for use in geothermal fluids. However, several conductivity probes developed for the nuclear industry (see paper by Creare, Inc. in reference 23) appear to give good performance snd appear viable for use in geothermal pipelines. void fraction technique is that measurement of the phase velocities are also required, a very difficult measurement.
The disadvantage of this c 3.1.3.2.3 SINGLE AND TWO PHASE FLUID DENSITY As presented previously, fluid density measurements are used to compute mass flow rate in both single and two phase flow streams and can be used to compute quality. The single phase flow meters presented in Section 3.1.3.1 provide a measurement of fluid velocity (i.e., ft/sec), which together with the pipe or borehole cross section can provide a measurement of volume flow rate (i.e., gallons per minute). However, in many geothermal process applications, the desired fluid parameter is for mass flow rate (i.e., lbs per hour)., For high quality (x>95%) and superheated steam flow lines, the density can be computed by measuring the temperature and pressure and using steam tables. used to obtain density for most single phase liquid flow lines; however, some emperical data must be obtained for fluid with large amounts of dissolved solids. Measurement of average fluid density in two phase flow streams i s used to compute quality with the aid of fluid temperature and pressure measurements. This together with separate measurements of vapor and liquid flow velocities and flow cross section, are then used to compute mass flow rate.
Temperature and pressure can be For applications requiring an 'in-line' actual measurement of process fluid flow density, the following three types of commercial sensors are available: . Vibrating 'U' flow tube . Vibrating emersed tube . Gamma beam densitometer The two vibrating tube techniques are based on the principle that the natural frequency of the tube is proportional to the mass of the fluid flowing through and around the tube.
'U' tube is only available for a small by-pass sample flow stream ( -1 ' ' diameter) where the vibrating emersed tube is available in a by-pass or insertion design. These units are available to measure liquid and vapors and will also function accurately in two phase flow streams.

The vibrating
The main problem/limitation for two phase flow density is in obtaining a homogeneous flow stream so the sample/by-pass flow or insertion sensor area is representative of average density in the pipeline. Also the units are susceptible to scaling w i t h degradation. in accuracy, The gamma beam densitometer incorporates a nuclear source that radiates a calibrated gamma beam through the liquid to a detector, The radiation reaching the detector produces a signal which is inversely related to fluid density. The source and detector can be configured as a 'clamp on' sensor, however, scale build-up on the pipe wall will degrade its performance. Several well logging tools are available for downhole fluid density measurements that employ gamma beam densitometers, however they are not designed for high temperature operation. Besides these three types of commercially available fluid densitometers, R&D densitometer programs are being sponsored by the Nuclear Reactor Test Program include quick closing valves, pulsed neutron activation, multiple (3) gamma beams, slewed gamma beam, and vibrating emersed structures (beams) (see references [22][23][24].
Except possibly for the quick closing valves and the vibrating beam, the other techniques do not appear to be practical for geothermal applications. It would appear that a by-pass line employing two quick closing valves to trap the liquid followed by removing or condensing the vapor and weighing the liquid would provide an acceptable method with the disadvantage of being a by-pass sampling device, quite tedious and slow, yielding one measurement at a time.

FLUID COMPOSITION
As noted in the introduction, an assessment of measurement requirements and techniques for the chemical composition of geothermal brines has been performed (reference 4), and development projects have and are being instituted by the U.S. Department of Energy's Division of Geothermal Energy for electro,Chemical probes to measure conductivity, Ph, etc. (references 5-7). Also, LBL has contracted to Terra Tek, Inc., for the improvement of the "McDowell" fluid partial pressure instrument for in-line measurement af the concentration of C02 in geothermal fluids (reference 28). . In-line partial gas pressure technique etc.) solids for total undissolved gas A good presentation of sampling and analysis methods is contained in reference 7. The current measurement techniques to obtain a sample of the fluid are usually at the wellhead, however, downhole fluid samples have also been utilized. The ability to sample geothermal fluid density downhole is currently very limited. samples collected are either mixtures from several producing formations or contaminated with water from other locations transited by the sampler in the borehole. Some of the identified developers and manufacturers of downhole fluid samplers are given in Table 3.1.4-3. Various deficiencies were reported by the geothermal industry with the commercial downhole samplers (82 and #4) such as not obtaining a representative sample due to inability to purge and to hold at sampled temperature and pressure.

MEASUREMENTS
Bescides the measurement of geothermal process fluid properties, there are many key in-situ reservoir formation parameters that must be measured in the development and operation of the reservoir. Also, tools to measure physical status of wells such as orientation and casing condition are a necessity in the development and operation of the well and process plant.
While many of the intrinsic parameters to be measured in a geothermal well are the same as those for an oil or gas well, the range of the parameters, their priority and the well environment differ significantly. Geothermal wells are typically much hotter and located in different geologic formations (i.e., igneous or metamorphic versus sedimentary for oil and gas). and reservoir size are key measurement parameter objectives for both geothermal and petroleum wells; however, the range of permeability, its controlling parameters (i.e., fracture size, quantity, etc.) and parameters governing the reservoir size/ potential vary significantly. petroleum logging tools, though not optimum, could provide useful data for the geothermal industry if they would operate at high temperature. A very hostile deep oil or gas well may reach a bottom hole temperature of 260OC (500aF) while many geothermal wells have reported temperatures in excess of 275OC (527'F) with a few wells reported in excess of 350°C (662OF). Recently, there has been a large increase in the use of steam injection for secondary oil recovery with accompanying operating temperatures approaching 275OC (527OF). These fossil energy high temperature well logging rqquirements combined with the small but increasing requirements of the geothermal industry are providing some incentive for the commercial well logging tool development and service organization to "harden" some of their logging tools. To date, however, there are very few formation parameter and well inspection tools capable of operation above about 204OC (4000F).

Many of the existing
This inability to obtain key formation and well status measurements is reported t o be one of the key factors limiting the development of geothermal energy. been possible to cool the well down using drilling mud or other fluid to perform the logging operation.
considered the lesser of two problemsno 'In some instances it has Cooling of a geothermal well must be meaeurements versus distorted measurements, and risk of damage to the well casing. wells this cooling operation can have a long term adverse effect on the well performance. Also in some Table 3.2-1 gives a list of the identified formation and producing zone parameters and their associated measurement requirements. The only well physical status measurement identified were: 1. Well casing integrityidentification of flaws (cracks, fractures, cement bond failures, etc.) on both internal and external surfaces.

Well orientationlsurvey.
Of all the parameters reviewed and discussed with the geothermal energy development industry, current inability to obtain measurements of the following five parameters were felt to represent the most severe measurement limitations for reservoir and production engineers in their efforts to develop geothermal energy as a viable commercial source of electric power: All the above parameters are derived by the measurement of one or more underlying variable parameters which can be related to the desired parameter. Therefore, the priority and need for these underlying variable paremeters such as acoustic wave velocity or electrical resistivity will differ depending on the specific well logging measurement method utilized (i.e., electrical and electromagqetic vs radioactivity BS acouditic vs optical vs gravity vs mechanical vs other). Table 3.2-2 lists some of the identified well logging techniques and tools that are felt to be mrthy of further consideration for providing meaaurements of the above high priority geothermal parameters. ments and formations, it is felt that no one singular logging tool will be best for all geothermal applications.
Due to the varied downhole environ-1

CONCLUSIONS AND RECOMMENDATIONS
Based on this appraisal of measurement requirements and methods for geothermal reservoir system parameters, it is concluded that the availability of commercial instrumentation for wellhead and process plant parameters have many deficiencies and downhole well logging tools for obtaining measurements of the key parameters are non-existent. The following specific findings and conclusions are: Process Fluid Temperature -Basic resistance temperature device sensors are available which meet all the temperature sensing requirements, however some improvements in calibration and scaling control are required. Deficiencies in both electrical 'wireline' and slickline 'bomb' temperature logging tools exist, however several organizations are currently working on solutions.
Process Fluid Pressure -Process pipeline pressure sensors are available, however high accuracy hostile environment pressure sensors required for downhole measurements are not available. Several commercial sensors have been identified that have the basic performance (accuracy, stability, size) but require temperature hardening and other performance improvements. A DOE-DGE sponsored program is currently underway to harden both the basic sensor and the signal conditioning electronics of one identified commercial system (Paeroscientific) for operation up to

275OC.
However, the final performance and scheduled commercial availability of the sensor are unclear.
Process Fluid Flow Rate -Single Phase Flow -Several promising single phase paocess pipeline.flow rate sensors have been identified that might meet geothermal uphole measurement requirements, however downhole flow sensors are non-existent. Further, the need for a downhole flow sensor to identify producing and theft zones is considered very important for geothermal development. Acoustic flow sensors appear best suited to meet the downhole measurement applications based on their simplicity (no moving parts), accuracy, dynamic range and proven sensor hardenability.

Process Fluid Flow Rate and Enthalpy for Two Phase
Flow -Commercial two phase flow sensing devices for low quality (x<90%) are currently limited to by-pass sampling devices. To date, the geothermal development industry has been able to improvise using large separators with single phase flow sensors and/or the 'James' critical pressure technique. Unfortunately these currently employed methods require changing the fluid state. Numerous two phase mass flow rate measurement techniques for high temperature pressure and volume fluid are currently being developed by the nuclear energy industry for reactor safety tests. The techniques under development include using both single phase velocity sensors combined with density sensors such as turbines, drag disks and void fraction. contact probes and true mass flow rate sensors. Many of these techniques and tools, when and if developed and commercialized, could be used for geothermal process fluid measurements. One identified commercial insertion type fluid density sensor can operate in the high geothermal fluid temperature, however it may be subject to scaling. LBL is currently sponsoring a separate project to assess calorimeters for low quality two phase wellhead measurement applications.
Process Fluid Chemical Composition -Except for several slickline 'bomb' type borehole fluid samplers with marginal performance, there are no identified commercial process fluid chemical composition measurement systems that can function in the hostile geothermal fluid environment. An assessment of theee deficiencies has been performed and a DOE-DGE sponsored program to develop the needed sensors is underway. There are currently no well logging tools available which can operate in the downhole hostile geothermal environment and provide the reservoir and production engineer with data on these critical parameters identified. Several non-hardened existing well logging tools that appear attractive for geothermal applications have-been identified for each of the identified key downhole measurement parameters.

RECOMMENDATIONS
logging tool should be instituted. It would appear from the sensors and high temperature technology reviewed that either an acoustic The following provides a list of recommendations to meet the measurement deficiencies identified: Process Fluid Temperature -Though improvements in scale build-up and associated calibration problems exist, additionalgovernment sponsored projects for improved temperature sensors does not appear required.
Process Fluid Pressure -A more aggressive group of projects to improve and temperature harden promising pressure sensors for use in downhole well logging is required. More specific effort should be placed on improving/ developing several commercial sensors wherein their signal conditioning electronics can be thermally protected in the event DOE-DGE's high temperature electronics development program requires additional time to develop and become commercially available.
Single Phase Process Fluid Flow Rate -Identified promising single phase process -flow sensors should-be evaluated i n several geothermal process fluid (liquid) flow loops and steam flow loops. Several identified fluid density meters should be included in this experimental evaluation. This careful evaluation would lead to future improvements of the most promising sensor(s).
A development program for a prototype downhole flow pulsed doppler or travel time sensor technique would best meet the downhole geothermal requirement.
Two Phase Mass Flow Rate and Fluid Enthalpy -While deficiencies exist in the measurement of two phase fluid, the only recommended effort in this area is to periodically review and assess other programs attempting to solve this difficult problem and provide findings to industry. Consideration could be given to evaluate by-pass flow sampling techniques for two phase geothermal process lines and include in the by-pass lines the two phase mass flow sensors and density sensors identified for evaluation.
Fluid Chemical Composition -Recommendations have been performed by others and programs for their implementation are underway.

Downhole Formation, Production Zones and Well
Status -An experimental evaluation of promising well logging techniques identified should be performed. This should be performed in a well logged, known, low temperature well or simulated well aherein each technique can be evaluated and compared. Using this 'benchmark' type experimental evalu8tion results, the mast useful and developable tools should then be 'hardened' or developed for operation in geothermal hostile environment wells.