Geothermal engineering

The Greek words gê, which means Earth, and thérm, which means heat, are combined to form the word "geothermal".  Geothermal energy is the thermal energy that the Earth produces. Geothermal resources refer to localized areas inside the Earth's crust that contain significant amounts of heat energy. Geothermal energy, or heat, that is currently or reasonably soon obtainable and economically used

There are thermal energy concentrations close to the Earth's surface that can be exploited as an energy source because of spatial fluctuations in the thermal energy found in the planet's deep crust and mantle. Three main mechanisms—conduction through rocks, magma rising to the surface, and deep water circulation—transmit heat from the Earth's lower layers. Most high-temperature geothermal resources are linked to heat concentrations that happen when magma (melted rock) moves to places close to the surface, where it can store heat. Due to the low heat conductivity of rocks, massive magma intrusions may take millions of years to cool.

Geologic mapping, geochemical analysis of water from hot springs, and geophysical techniques utilized in the mining sector are the most prevalent methods employed in the exploration for geothermal resources. With developments in seismic methods, reflection seismic surveys are increasingly being employed. Geothermal drilling relies on technologies used in the oil/gas sector that are updated for high temperature applications and wider well sizes. Because high flow rates are often required for profitable production, the oil and gas industry has developed methodologies for extensively fractured reservoirs that are used in well testing and reservoir engineering.

Types of Geothermal Systems

Exploitable geothermal resources are hydrothermal systems containing water in pores and fractures with sufficient permeability to produce fluids in adequate volume. Most hydrothermal resources contain liquid water, but higher temperatures or lower pressures can create conditions where steam and water, or steam alone, are the continuous phases. Examples of steam-alone fields are among the oldest developed geothermal fields—Larderello in Italy and The Geysers in Northern California. These types of geothermal fields are termed "vapor-dominated" because the initial pressure follows a vapor-static gradient, as opposed to hydrostatic gradients in liquid-dominated fields.

Other types of geothermal systems that have been looked into for energy production are (1) geopressured-geothermal systems, which have water that is slightly warmer than normal and under a lot more pressure than hydrostatic for its depth; (2) magmatic systems, which have temperatures between 600 and 1,400 °C; and (3) hot dry rock (HDR) geothermal systems, which have temperatures between 200 and 350 °C. HDR systems are characterized, as are subsurface zones, with low natural permeability and little water. Currently, only hydrothermal systems shallower than about 3 km and containing sufficient water and high natural permeability are exploited.

A more recent addition is "enhanced geothermal systems" (EGS), which fall between HDR and hydrothermal systems. These may lack enough fluid or have low permeability for commercial use, and ongoing research focuses on injecting fluids and enhancing permeability for improved efficiency. Currently, only hydrothermal systems less than 3 km deep with sufficient water and high natural permeability are actively utilized for energy production. Another option is utilizing the heat from beneath the Earth's surface with low hydraulic conductivity, occasionally termed deep heat mining (DHM). Given that the continental crust is primarily composed of granite or gneiss, HDR systems specifically target granitic heat reservoirs. HDR systems typically aim for temperatures above 200 °C, requiring the drilling of wellbores reaching depths of 6 to 10 km in the continental crust, which maintains an average geothermal gradient.

Geothermal Energy Potential

Estimates of potential for geothermal power generation and thermal energy used for direct applications are available for most areas. The most recent review of worldwide electrical generation reports 12,810 MW_e (megawatts electric) of generating capacity is online in 23 countries (Table 9.1). Since that report, additional 4,013 kW_e capacity has been added in Indonesia, the most additional capacity of all countries. The expected capacity in 2005 is 19,757 MW_e. Geothermal resources also provide energy for agricultural uses, heating, industrial uses, and bathing. Fifty-five countries have a total of 16,209 MW_t (megawatts thermal) of direct-use capacity. The total energy used is estimated to be 45,000 TW-hrs/yr (terawatt-hours per year).

• 

  Table 9.1—Worldwide Installed Geothermal Electrical Generating Capacity in 2016 in Megawatts Electric(MWe)

Gawell et al. estimate that identified geothermal resources using today's technology have the potential for between 35,000 and 73,000 MW of electrical generation capacity. The Gawell study relied on expert opinions and generally focused on identified resources. Stefansson prepared an estimate of identified and unidentified worldwide potential based on the active volcanoes of the world. He estimates a resource of about 11,200 ± 1,300 TW-hrs/yr using conventional technology and 22,400 using conventional and binary technology (Table 9.2). Stefansson points out that his estimate is in general agreement with that of Gawell et al., although individual regions may not be in agreement.

• 

  Table 9.2—Estimated Geothermal Resources Suitable for Electrical Generation Reported as Terra-Watt Hours per Year (TWH/A)

The U.S. Geological Survey has prepared several assessments of the geothermal resources of the United States. Muffler estimated that the identified hydrothermal resource, that part of the identified accessible base that could be extracted and used at some reasonable future time, is 23,000 MW_e for 30 years. That is, this resource would operate power plants with an aggregate capacity of 23,000 MW_e for 30 years. The U.S. undiscovered resource (inferred from knowledge of Earth science) is estimated to be 95,000 to 150,000 MW_e for 30 years.

Muffler also provides an explanation of the terminology used to define the various categories of resources. Resource base is all of the thermal energy contained in the Earth. The portion of the resource base that is accessible is shallow enough for production drilling to reach it. Resources are those portions of the accessible base that can be used at some reasonable future time. Reserves are that portion of the resource that has been identified and can be used under current economic conditions. Resources are also divided into categories of "identified" and "undiscovered," based on knowledge of the certainty of their existence.

Geothermal Exploration

Geochemical Studies

Geophysical Techniques

Geophysical Methods in Geothermal Exploration and Field Operations

Geothermal Drilling

Background

Nature of Geothermal Formations

The Key Differences between Drilling Operations in Geothermal and Oil and Gas

Well Design in Geothermal

Well Type

Comparison Parameters of Various Well Type

Casing Design in Geothermal

Cementation of Casings in Geothermal

Drilling Fluids in Geothermal

Well Control in Geothermal

Geothermal Drilling Technology

Drill Pipe Continuous Circulation Device (CCD)

Drilling with Casing (DWC)

Reservoir Engineering

Definition

The Development of Geothermal Reservoir Engineering

Reservoir Characterization

Well Testing

Completion Test

Injectivity Test

Heating Measurement

Production test

Transient Test

Partial Penetration

Decline Curve Analysis

Data Preparation: Normalizing Flow Rates

Arps Decline Curves

Fetkovich Type Curves

Tracer Testing

Geothermal Tracers

Recent Advancements in Tracer Technology

Tracer Selection Criteria

Injection and Sampling Techniques

Analytical Modeling Methods

Interpretation Methods

Flow Channel Model

Advancements in Quantitative Analysis Techniques

Interpreting Tracer Data in Heterogeneous Reservoirs

Numerical Simulation

The Evolution of Geothermal Simulation

Challenges in Modeling Geothermal Reservoirs

Governing Equations

Conceptual Models and the Native State

The Impact of Fractures

The Simulation Process

Future Directions

Field Operations

Stimulating Production

Higher-temperature wells are normally self-energized and produce without stimulation. Initial production of a well is usually allowed to discharge to a surge pit to allow for cleanup of the wellbore of debris from drilling operations. If a well is self-energized, it is also important to know whether the produced fluid remains single phase in the wellbore. Friction losses are much greater for two-phase flow, so increasing the casing diameter at the point where the fluid flashes to vapor will increase production. A well that does not discharge spontaneously will require stimulation. The main goals of stimulation treatments were to improve injectivity of injection wells and productivity of production wells. This helps increase power output and sustain operations by maintaining reservoir pressures.

There are several methods of stimulation used.

Swabbing

Swabbing in geothermal drilling primarily serves to clean the wellbore by removing cuttings and debris accumulated during drilling, which is crucial for preventing blockages and maintaining the flow of geothermal fluids. This technique involves lowering a swab equipped with a one-way valve down the well, below the water or mud line. The valve allows fluid to bypass the swab during descent. Upon raising the swab, the water column is lifted, reducing the hydrostatic pressure on the producing formation, thereby initiating spontaneous fluid discharge from the well. This process often requires multiple trips in and out of the well and this is essential for initiating flashing and inducing flow. Maintaining a clear wellbore is critical for effective heat exchange between the geothermal fluids and surface facilities, ensuring that heat transfer surfaces remain efficient and the well operates at optimal conditions.

Coil Tubing and Liquid Nitrogen

The removal of fluid from the top of the column can be achieved with coil tubing by running tubing into the well below the fluid level and injecting liquid nitrogen to lighten the column and induce boiling in the well. This method is the most common method of bringing a well back online after well remediation or surface facility shutdowns. Coil tubing is a continuous, flexible, and durable steel or composite pipe, designed for various operations without the need for assembly like traditional drill pipe, thus facilitating faster and more efficient operations. It is commonly used in hydraulic fracturing to precisely inject high-pressure fluids to crack rocks, delivering these fluids directly to the targeted fracture zones and enhancing control over the stimulation process. Additionally, coil tubing can transport acids to specific sections of the well to dissolve rock formations and remove debris, increasing permeability and fluid flow. It is also employed to operate and transport perforation guns, which mechanically perforate the well casing and surrounding rock to create new pathways for steam and hot water, further optimizing resource extraction.

Liquid nitrogen is a tool for thermal shock applications, inducing rapid contraction in rock structures and facilitating various processes in geothermal fields. It works especially well for thermal fracturing, in which heated rock is injected with liquid nitrogen to cause rapid cooling and contraction, which in effect causes thermal stresses that cause the rock to fracture. Liquid nitrogen is environmentally safe and preferable to chemical stimulants because it evaporates into inert nitrogen gas, reducing pollution and the risk of harmful chemical reactions that could affect well integrity.

Coil tubing and liquid nitrogen can be used in tandem for enhanced geothermal stimulation. For efficient thermal fracturing, liquid nitrogen can be precisely positioned at the required depth using coil tubing. In order to optimize the stimulation of geothermal wells, this integrated solution makes use of the advantages of both technologies: the extreme cooling impact of liquid nitrogen and the precision and reach of coil tubing.

Compressed Air

Compressed air is a versatile and preferred tool in geothermal operations for its multiple benefits in well management and safety. Instead of using nitrogen or swabbing, compressed air is deployed for well control and safety, with standard air compressors working alongside drill pipe to pressurize the annulus and reverse-circulate the column of liquid through the drill pipe. It is also injected under high pressure into geothermal reservoirs to create or widen fractures, enhancing the permeability and flow of geothermal fluids. In addition to these applications, compressed air is used for maintenance tasks such as lifting water and debris from the wellbore and air blasting to remove scale, sediment, and other obstructions. Moreover, it aids in drilling operations by cooling the drill bit and surrounding rock, preventing overheating and reducing wear on the equipment. In conclusion, compressed air is proven to be more cost-effective, simple, and improve environmental safety since it's does not contain hazardous chemical.

Foaming Agents

Foaming agents offering multiple benefits that enhance efficiency in the stimulation and maintenance of geothermal wells. Primarily, these agents are used to purge existing fractures of debris and cuttings by creating a lifting action that transports these materials to the surface. This cleaning is essential not only for maintaining but also for enhancing the permeability of the reservoir, ensuring optimal fluid flow. Foaming agents help reduce the weight of the water column by emulsifying air or nitrogen in the liquid, thus keeping the gas entrained in the liquid and providing greater lift. Additionally, foaming agents are incorporated into drilling fluids to minimize fluid loss into surrounding formations, which is vital for maintaining hydrostatic pressure within the wellbore. The generated foam serves a dual purpose by cooling and lubricating the drill bit as it drills through tough rock formations, thereby prolonging the life of the equipment. Furthermore, foaming agents contribute to improved fluid recovery and aid in well control by managing the migration of gases during drilling and production. This comprehensive role of foaming agents in geothermal energy extraction underscores their significance in promoting efficient, sustainable, and safe drilling and stimulation operations.

Decompression

Decompression is a sophisticated strategy used to stimulate water wells for agricultural purposes and is sometimes effective in starting a geothermal well. This method leveraging the natural properties of the earth to enhance the extraction and longevity of geothermal energy resources consists of pressurizing the wellbore with compressed air and quickly depressurizing the well to atmospheric pressure to induce boiling. By reducing the pressure, a pressure differential is created between the reservoir and the production well. This differential encourages geothermal fluids to move towards the areas of lower pressure, thereby enhancing the flow of these fluids towards and into the production well. Decompression can also stimulate the opening of new fractures or the widening of existing ones within the rock formation.

Pumped Wells

If the well does not produce spontaneously and does not respond to stimulation or if the power production facility is designed to only handle geothermal liquids and not two-phase or vapor flows, it will be necessary to install a pump. Conventional technology for many years was a line-shaft pump with the motor at the surface and the impeller set some distance below the drawdown water level in the well. This arrangement requires a straight, vertical wellbore down to the pump depth. There also may be restrictions on pump depth because line-shaft pumps have limits on how far torque can be effectively transmitted down the wellbore. Recently, high-temperature-capable submersible pumps have been developed that give good service up to about 200°C. The pump must be located at a depth sufficient to avoid cavitations at all flow rates expected.

Curtailments

Curtailments are planned or unplanned circumstances that require wells to either be shut-in completely or throttled. Curtailments can occur for various reasons and may involve adjusting the rate of fluid extraction from the reservoir. Examples of curtailments include intentionally throttling production back during off-peak power needs (load following), unexpected tripping of generation equipment, or other surface problems that may require forced outages. Some wells may load up with liquid and stop flowing if any flow constraint is imposed. These wells might then require stimulation to restart production. In cases where short down-time is expected, or to prevent the well from cooling, a plant bypass system might be installed at the surface to keep the well flowing. The bypass system can be a turbine bypass that passes the steam through a condenser (and the condensate back into the resource) or route steam to an atmospheric muffler system. When venting steam to atmosphere is a safety or environmental concern, a condensing system is generally used.

Injection

Injection initially started as a disposal method but has more recently been recognized as an essential and important part of reservoir management. Sustainable geothermal energy use depends on reinjection of produced fluid to enhance energy production and maintain reservoir pressure. Injection also plays role in temperature control, enhance heat extraction, and stimulation of fractures. Injection techniques vary depending on the specific characteristics of the reservoir and the objectives of the stimulation program. Common injection methods include water injection, steam injection, and hydraulic fracturing. The choice of injection fluid, injection rate, and injection location are carefully optimized to maximize the effectiveness of the stimulation process while minimizing environmental impacts.

A simple volumetric calculation shows that over 90% of the energy resides in the rock matrix; hence, failure to inject multiple pore volumes results in poor energy recovery efficiency. When the usable energy is extracted from the fluid, the spent fluids must be disposed, reused in a direct use application, or injected back into the resource. Despite efforts to maximize the fraction of fluids reinjected, it is common for losses to approach 50%, mainly through evaporative cooling tower loss. Frequently, makeup water is used to augment injection. Failure to reinject can lead to severe reductions in production rates from falling reservoir pressure, interaction between cool groundwater and the geothermal resource, ground subsidence, or rapid dryout of the resource. On the other hand, condensate is used or generally re-injected into the geothermal reservoir and can sometimes detrimentally affect nearby producing well temperatures.

Acidizing

Acid injection proven to be is a cost-effective solution to power production maintenance by dissolves scales and plugging solids that reduce the well’s production or injection. Geothermal production usually partially filled with minerals such as calcite and silica, this condition is caused by production / injection process or by natural occurrences. Wells plugging in geothermal mainly caused by calcite deposits, silica deposits, and mud solids. The main purpose of acid treatment is to dissolve minerals, restore conductivity of the natural fissures, and removing scales deposited in wells tubulars. After formation composition is known and the plugging materials identified, the treatment parameters are designed include:

• Type of acid for the main treatment
• Acid strength for the main treatment
• Volume of the main treatment
• Preflush and posflush composition and volume
• Additives selection: corrosion control, scale inhibition, iron control, etc.
• Operational parameters: injection rate, injection pressure, etc.

The most common problem found was silica and calcite deposits in pipe or natural fissures. The challenges in acidizing are corrosion at high temperatures, combined carbonate or silica scales, losses while drilling, and achieving through diversion.

Hydraulic Fracturing

Hydraulic fracturing commonly referred to as "fracking" is a technique used to enhance geothermal productivity by increasing permeability of underground rock formation to improve flow of heat bearing fluids to geothermal wells. This process can significantly enhance the efficiency of geothermal power plants by increasing the amount of geothermal fluid that can be extracted and used for power generation or heating. The process involves injecting a high-pressure fluid into the geothermal reservoir to create new fractures in the rock or to widen existing ones. The fluid used for hydraulic fracturing in geothermal applications is usually water, possibly with some additives to reduce friction or prevent corrosion. The increase in fractures allows for a greater surface area through which heat can be transferred from the rock to the water, enhancing the system's thermal conductivity. Hydraulic fracturing is used in both conventional and enhanced geothermal systems (EGS). In conventional geothermal fields, fracturing can help to improve the connection between wells and the natural heat reservoir. In EGS, which involve creating a geothermal reservoir in hot dry rock, hydraulic fracturing is a fundamental part of the system's development, as it creates the fractures necessary for water circulation and heat extraction.

Measurements in Geothermal Production Applications

Measurements of mass flow and the constituents of the mass produced are integral in the production of geothermal fluids. Accurate physical and chemical measurements of geothermal are a necessity and helps for geothermal production and utilization including resource assessment, operational efficiency, regulatory and royalty payment issues, monitoring the condition of the resource and abatement of corrosive constituents in the geothermal fluid.

Mass Flow

Single-Phase Flow

The operator can choose from a variety of instruments to measure flow, depending on the phase being produced. For single-phase systems, conventional methods are commonly employed. The selection of the flow element and meter primarily hinges on factors such as the mass and/or volumetric flow rate, the turn-down ratio (the range of flow to be measuring), as well as the pressure, temperature, and the degree 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.

Due to the extreme conditions in geothermal production, conventional flowmeters often fail to keep their calibration or survive for extended periods. With numerous wells that consist of many single-phase 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. As a result, there is often a need for flow measurement using portable, point-by-point, nondisruptive techniques.

There are different methods in measuring steam, water, and gas flow rate for single phase flow, such as orifice plates, v-cone, pitot tubes, vortex, ultrasonic, and tracer flow testing (TFT).

• Orifice Plates Orifice plates is method to measure steam flow rates using differential pressure method. The flow rate is calculated by measuring the difference in fluid pressure across upstream and downstream of the plate or from pressure drop caused by the flow through the orifice.
• Venturi Meter Venturi meter are widely used for flow measurement in geothermal wells due to their simplicity and ability to handle corrosive fluids and high temperatures. They measure flow rate by inducing a pressure drop as the fluid passes through a constricted section of pipe. The flow rate is determined based on the pressure difference before and after the constriction.
• Pitot Tubes 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 flow stream 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.
• Tracer Flow Testing (TFT) Tracer flow testing is another method for nondisruptive, portable flow measurement. This method was originally developed for two-phase flow but has the same applications for single-phase flow as the pitot tube. The fundamental concept of the TFT method involves injecting a conservative liquid or vapor tracer at a controlled rate upstream from a sampling point. At this point, the tracer's mass is measured in the sample, allowing for the calculation of the flow rate. This method is effective for precisely calibrating stationary flowmeters.

Two-Phase Flow

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 using previously described methods. However, due to the high capital cost of wellhead separation systems, fluid gathering systems are usually installed, allowing vapor and fluid to be separated at a more centralized facility.

In two-phase geothermal fields, it is crucial to monitor the enthalpy of the fluids being produced to assess 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 as it helps in determine 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.

The mass flow rates of steam and water phases, as well as the total enthalpy of the flow, can be directly measured for individual geothermal wells that utilize dedicated separators. However, due to 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 flow metering 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 non condensable 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.

  Where

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.

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.

Examples of data from online brine flow measurements are shown in Figs. 9.10 and 9.11, as measured by a portable field analyzer for the liquid tracer. Note that the first well (Fig. 9.10) was producing at a stable rate, while the second well was surging significantly (Fig. 9.11). Well behavior and detailed flow resolution can be obtained by continuous real-time monitoring.

Fig. 9.10 Mass flow rate of a well as measured by the TFT method. This well is producing at a stable rate.

Fig. 9.11 Mass flow rate of a well as measured by the TFT method. This well is surging (unstable flow rate).

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. 9.12 for the production wells at the Coso, California power plant.

Fig. 9.12 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 TFT measurement process are summarized in Table 9.8. For comparison, an error analysis performed for a standard James-tube well test in the Philippines is given in Table 9.9, 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.

Table 9.8 Typical Errors in Tracer-Derived Two-Phase Flow Measurements

Table 9.9 Typical Errors in Measurements When Using James-Tube Well Tests

Fluid Compositions

There are three main categories of geothermal fluids: gas, steam, and air. Each fluid has a different concentration of ions and compounds. The diversity of rock properties and heat intensity causes geothermal systems to have unique characteristics that differ from one field to another. Different ion concentrations can be caused by many things, including differences in temperature, gas content, water source, rock type, condition and duration of rock-water interaction, and the presence of a mixture of water from one source with another.

Sampling two-phase geothermal fluid demands specialized methods that use inertial separation to distinguish between phases. Often, geothermal steam includes minor quantities of entrained liquid water and noncondensable gases like CO2, along with additional components like silica. Impurities like NaCl might exist either dissolved in the liquid phase or as solid particles. 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.

Geothermal Energy Conversion Systems for the Production of Electrical Power

Direct Steam Systems/Vapor-Dominated Resources

Flash Steam Systems/Liquid-Dominated Resources

Binary Systems/Liquid-Dominated Resources

Nomenclature

Acknowledgments

Copyright Notice

Noteworthy papers in OnePetro

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External links

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See also

PEH:Geothermal Engineering