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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.

Occurrence of Geothermal Energy

The temperature within the Earth increases by an average of around 25°C each kilometer of depth.   Given an average surface temperature of 20°C, the temperature at a height of 3 kilometers is a mere 95°C.   While geothermal energy may be utilized at temperatures as low as around 35°C for some purposes, a minimum temperature of around 135°C is required for generating electricity.  Geothermal resources are found in regions with above-average temperatures under the Earth's surface.

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).

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  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.

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  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. Accessible resource base is that part shallow enough to be reached by production drilling. 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

The process of discovering, harnessing, and utilizing geothermal resources borrows methodologies from both the mining and oil/gas sectors. The geological context of geothermal resources bears resemblance to metal ore deposits, and it's believed that geothermal systems are the contemporary counterparts of metal ore-forming systems. As such, the exploration phase heavily leans on mining industry techniques. The development and extraction of the resource as a hot fluid, on the other hand, employs methods from the oil/gas industry, albeit with adjustments to accommodate the high temperatures and the significantly larger flow rates required for profitable production.

The exploration process kicks off with the selection of a suitable area, guided by a general understanding of regions with above-average heat flow. The most reliable indicators for a more thorough investigation are thermal springs, which are akin to oil seeps. However, to tap into undiscovered resources, geologists must resort to other techniques. Given that the target is an area with above-average temperature, heat flow studies can hint at increased subsurface temperatures. Other methods currently in use or under investigation for regional exploration include remote sensing of elevation changes, faulting age, and geochemical techniques.

For a hydrothermal system to be viable for geothermal development, it must possess adequate temperature and sufficient flow for profitable production. Geochemical techniques can be employed to ascertain subsurface temperatures when hot springs are present, and shallow temperature-gradient holes can be used to estimate subsurface temperatures beneath the drilling level. Geophysical tools also come in handy in determining the approximate size of the reservoir. Since high flow rates are essential for geothermal production, most geothermal production is derived from highly fractured reservoirs. Therefore, geophysical methods that can ascertain fracture intensity are of immense value to the explorationist.

Geochemical Studies

The analysis of hot spring and fumarole chemistry plays a crucial role in geothermal exploration. The solubility of minerals is highly temperature-dependent, and the rate of rock-water reactions is relatively slow. As a result, water that has reached equilibrium with rocks in a geothermal system can maintain their dissolved mineral content as they surface. This means that the composition of hot springs can be used to determine the temperature at which equilibrium was reached. The geochemistry of thermal springs is the most commonly used tool in geothermal exploration for estimating subsurface temperatures before drilling wells.

The most frequently used geothermometer is based on silica solubility. However, since more than one form of silica, each with different solubilities, can exist in the subsurface, the thermometer must be used with care. The two most common forms of silica in geothermal systems provide the following composition-temperature relationships over a temperature range of 0 to 250°C.

....................(9.1)

and

....................(9.2)

where SiO₂ is the concentration of silica in mg SiO₂ per kg water.

The second most widely used geothermometer, Na-K-Ca, was developed by Fournier and Truesdell, and a magnesium correction was added by Fournier and Potter.

....................(9.3)

The concentration units are moles/kg, β = 1/3 for water equilibrated above 100°C, and β = 4/3 for water equilibrated below 100°C.

Because of the importance of geothermometers for exploration and for interpreting chemical changes in geothermal reservoirs during production, a rich literature on the geochemistry of geothermal systems is available. Four publications provide a particularly useful understanding of the chemistry of geothermal systems, how to sample thermal springs, and the application of geochemistry to understanding geothermal systems.

Geophysical Techniques

Geophysical Methods in Geothermal Exploration and Field Operations

Geophysical methods are valuable for identifying permeable structures containing high-temperature water or steam and for estimating the amount of extractable heat from the subsurface over a specific period. As a field progresses, geophysical measurements are important for guiding the placement of additional production and injection wells, understanding the complexities of the permeability structure, and defining boundaries for reservoir models used in managing the geothermal field. The main exploration goals involve the co-location of heat, fluid, and permeability. Wright et al. offer a thorough review of the geophysical techniques relevant to geothermal exploration in this context.

The interpretation of geophysical data in geothermal fields is complex due to two main factors. Firstly, there is a wide range of rock types hosting diverse geothermal systems, such as young sediments in the Salton Trough, California, the Franciscan mélange at The Geysers, California, or a mix of rock types like tuffs, flows, mudslides, and intrusive rocks at Pacific rim, volcanic-hosted fields. Secondly, the geological structures in geothermal systems often exhibit significant complexity, and it's important to note that these structures may not necessarily determine the location or economic feasibility of the geothermal field. As a result, the approach to exploring geothermal energy differs from that used for petroleum fields and is more akin to mineral exploration.

Subsurface temperatures can be measured directly in boreholes or approximated by extrapolating heat-flow measurements from both shallow and deep holes. Heat-flow measurements combine observed temperature gradients and thermal conductivity readings to determine vertical heat transport in areas where conduction is the main heat transfer mechanism. Significant changes in temperature gradients with depth indicate areas where heat transfer is predominantly influenced by advection. Heat-flow measurements offer evidence of both the likelihood of geothermal systems in certain areas. and the scope of localized systems. Given that fluid flow patterns can be intricate, the deeper areas of hot fluids are often not situated directly beneath the shallow high heat-flow anomalies.

Subsurface temperatures can also be inferred from the physical properties of rock masses.Laboratory-based assessments of rock density, seismic properties, electrical characteristics, and mechanical behavior, accounting for factors such as temperature, pressure, porosity, matrix composition, alteration, and saturation, provide essential data for planning and interpreting a geophysical survey.

Identifying areas with sufficient permeability for profitable production poses a significant challenge. The electrical self-potential (SP) method stands as the sole direct indication of subsurface fluid flow, while all other methods necessitate inferring permeability from factors such as extension zones, intersecting faults, stress conditions, or seismic activity, along with secondary effects like temperature distribution or zones of mineral alteration. Surface geophysical techniques have been instrumental in determining the initial placement of wells in numerous geothermal fields. For instance, gravity anomalies resulting from dense, thermally-altered sediments in the Imperial Valley, California, largely directed early drilling activities. However, both surface and borehole geophysics assume greater importance as a geothermal field matures, particularly when wells need to be positioned to ensure sufficient production or injection capacity, or to provide constraints for refining reservoir models.

Examples of Specific Methods as Applied to Geothermal Specific methods applied to geothermal exploration involve the assessment of both natural and induced seismic activity, which serve as indicators of physical processes occurring within or beneath the geothermal system. The significance of these events, or their absence, depends on the specific characteristics of the geothermal system under investigation. It has been suggested that microseismic activity is essential for the continued flow of fluids from hot areas to cooler regions, as it helps maintain open fractures. Consequently, passive seismic methods for detecting microseismic activity have been extensively utilized in the exploration of geothermal fields.

However, certain geothermal fields, such as Dixie Valley, Nevada, and Olkaria, Kenya, exhibit minimal or undetectable seismic activity, while for others like The Geysers, California, it is uncertain whether there was seismic activity before production commenced. Conversely, seismic activity can offer insights into the tectonic environment in which the geothermal system is situated. For instance, in the Salton Trough, natural seismic activity delineates the plate boundaries, whose oblique movement facilitates the extension necessary for the shallow injection of magma and ensuing fluid circulation. Historical and paleoseismic data can also yield valuable information about the context of a geothermal system. For example, Caskey et al. have found that the Dixie Valley field sits in a seismic gap indicated by both 20th-century events and Holocene fault ruptures. Finally, if seismicity only occurs at shallow depths, then the brittle-ductile transition may shallow because of locally high heat flow.

Microearthquakes can also provide insights into the processes occurring during operations in a geothermal field. For instance, research by Beall et al. and Smith et al. demonstrated that a significant portion of the seismic activity at The Geysers can be utilized to track the downward movement of injected fluid, and microearthquakes detected using deep borehole seismic systems have been instrumental in mapping artificial fractures (e.g., Fehler et al. at Fenton Hill, New Mexico, or Weidler et al. at Soultz, France)..

Passive seismic observations are also utilized to create velocity images of the crust. By concurrently determining earthquake locations, time, velocity, and attenuation structures, three-dimensional (3D) images of geothermal fields can be developed. Comparisons of the P- and S-wave images or the velocity and attenuation images can provide insights into steam saturation, porosity, and fracture orientation. Additionally, these surveys can be repeated to assess the impact of production and injection on the field's characteristics.

Historically, exploration seismology has faced challenges in effectively delineating economic geothermal fields, likely due to the complex structures in which they are situated and the somewhat tenuous relationship between the structure and the producing fields. Recent efforts have focused on utilizing a large number of first arrival times to develop a two-dimensional (2D) or potentially a 3D velocity model, which can be employed for migration to image steeply dipping structures. This velocity image not only provides valuable information about the structure but also enhances the imaging of discrete reflectors.

Numerous electrical methods have been utilized for geothermal exploration and characterization. Passive electrical self-potential (SP) anomalies have been analyzed to signify areas with intense upward flow of hot water. Direct current (DC) and induction methods, employing various geometries, frequencies, penetration depths, and resolutions, have detected high-conductivity anomalies. These anomalies are interpreted as indications of warm or heavily altered areas, or as indicators of structures that could influence fluid movement. Additionally, repeated electrical methods have been employed to pinpoint zones where cooler recharge is entering a geothermal system.

Traditional potential field methods, such as gravity and magnetics, have been conventionally employed to delineate faults, basin geometries, and other structures. They are also utilized to identify intrusions or buried eruption deposits that could potentially contribute heat or influence flow paths, as demonstrated by Soengkono. The interpretation of these data heavily relies on the specific nature of the system under study. For instance, in the sedimentary section in the Salton Trough, California, known resource areas are characterized by gravity highs resulting from the alteration of sediments by high-temperature circulating fluids. However, in most fields, an area with relatively high gravity would typically not be directly associated with the geothermal system.

While not typically considered as geophysical techniques, geodesy and deformation measurements can offer valuable insights into the processes taking place within a geothermal system.

Borehole logging in geothermal areas has not been extensively utilized, apart from temperature-depth logging and spinner surveys to identify inflow areas. Several factors contribute to this. The high temperatures pose a challenge for traditional logging tools, as their designs and standard interpretation principles are optimized for relatively flat sedimentary sections, a situation uncommon in geothermal environments. Additionally, geothermal wells often have severe lost circulation zones, necessitating rapid casing to save the hole, which can preclude openhole logging. However, high-temperature logging tools can mitigate some of these challenges.

Public access to logging data sets from drillholes in geothermal systems has been facilitated by two scientific projects. The Salton Sea Scientific Drilling project involved the collection of a comprehensive array of traditional well logs, repeated temperature logs, borehole gravity, and vertical seismic profile (VSP) measurements. In the Dixie Valley, extensive borehole televiewer studies and mini-hydraulic fracture tests have contributed to an understanding of open fractures and their underlying reasons. If viewed as measurements of specific formation properties rather than as a means to correlate between wells, additional borehole geophysical measurements could offer valuable information in operating geothermal fields.

Integrated geophysical methods can offer valuable insights into a geothermal system, both during exploration and exploitation. The specific methods that hold value, and the manner in which diverse data sets may be amalgamated, heavily rely on the characteristics of the system under investigation and the pertinent inquiries. The significance of geophysical measurements is heightened when they are interpreted within the framework of a conceptual or numerical model that is also constrained by other information, such as geological and geochemical exploration data, or knowledge acquired during field operations. This integration is potentially most effective during exploitation, where reservoir models account for the geophysical effects, pressure drawdowns, and fluid flows. A similar approach to exploration might prove to be very valuable.

Geothermal Drilling

Background

In the realm of oil and gas drilling, the primary objective revolves around accessing hydrocarbon reservoirs typically situated within zones known for abnormal pressure or kick occurrences. Conversely, geothermal drilling pursues a distinct goal: reaching fracture zones or regions characterized by a notably high-temperature gradient. Geothermal wells, in this context, serve a dual purpose: either as producers, extracting steam for energy generation, or as injectors, channeling water into these fractures to harness the earth's heat. The identification of specific alteration minerals, formed as a result of prolonged exposure to extreme heat, serves as a key indicator, demarcating zones endowed with sustained and consistent thermal energy. Understanding these geological phenomena is paramount in laying the groundwork for effective geothermal exploration and drilling strategies.

One of the primary hurdles encountered in geothermal projects revolves around cost management. In order to remain competitive within the realm of alternative energy sources, it's imperative to drive project expenses to their lowest feasible point. Drilling activities, comprising up to 40% of the overall project expenditure, stand out as a significant cost factor . Any challenges encountered during drilling operations can lead to additional expenses throughout the project lifecycle. Addressing issues such as loss circulation, slow Rate of Penetration (ROP) in rough drilling conditions, secondary cementing requirements, and other related problems often necessitates extended operational time and incurs supplementary costs. Moreover, the utilization of specialized materials to mitigate these drilling challenges further escalates project expenses. Therefore, effective measures to alleviate drilling-related issues can yield substantial cost savings across the entire project spectrum.

Nature of Geothermal Formations

Geothermal formations are characterized by high temperatures, hardness, extensive fracturing, and low pressure. They frequently contain corrosive fluids and fluids with high solid content, making drilling in such environments challenging. Difficulties arise from the degradation of drilling fluids, changes in fluid properties, managing mud systems, slow drilling progress, short lifespan of drill bits, and issues with lost circulation. Additionally, there is a notable risk of fines migration and induced formation damage in geothermal wells, primarily due to the weakening of electrostatic forces at high temperatures and thermal contraction effects.

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

What distinguishes the Geothermal Drilling process from Oil & Gas is the magnitude of pressure and temperature. Geothermal drilling operates at pressures of 300-1500 psi and temperatures of 200°C-360°C, while in Oil & Gas drilling, the pressure can reach 7000 psi with lower temperatures. In the event of a kick during Oil & Gas drilling, water or hydrocarbons are released, whereas in Geothermal projects, steam with temperatures ranging from 200°C to 360°C is released. Consequently, the treatment for handling such kicks differs. Here is a summary of the drilling data parameters for geothermal wells:

• Low pressure: 300 - 1500 psi
• High temperature: 200° - 360°C
• Types of Gas: CO2, H2S
• In case of a kick: release of hot steam, not hydrocarbons
• Total losses are highly anticipated.
• Drilling the production zone using AIR and AIR if drilling mud is lost in the hole (lost circulation.

Geothermal drilling faces challenges such as maintaining drilling costs competitiveness, combating lost circulation, and mitigating thermal effects on equipment and materials.

Well Design in Geothermal

Well Type

The efficiency of converting geothermal steam or water into electricity is relatively low, approximately around 20%. As a result, large mass flows and, consequently, high volume flowrates are necessary, especially in vapor-dominated systems. These substantial volume flowrate requirements mandate the use of large-diameter production casings and liners. In a standard-sized well, the production casing typically employs a standard API 9 5/8" diameter casing, along with either a 7" or 7 5/8" diameter slotted liner within an 8½" diameter open hole section. A "Large" diameter well usually employs standard API 13 3/8" diameter casing for the production casing, along with either a 9 5/8" or 10¾" diameter slotted liner within a 12¼" diameter open hole. The selection of casing sizes for Anchor, Intermediate, Surface, and Conductor casings will be based on geological and thermal conditions.

Comparison Parameters of Various Well Type

Having a comprehensive understanding of both temperature and permeability risks is crucial when formulating an exploration drilling strategy, particularly in deciding the type of wells to be drilled. The inclusion of detailed information about high-grade resources in the conceptual model enhances confidence in determining the suitable well type, whether it involves using small-sized holes, standard holes, or a combination of both. Here is a table outlining several differences in well size,

Parameter to Compare	Big / Large Hole	Standard / Reguler Hole	Slim Hole
Drilling depth	1,500 - 3000 m	1,500 - 3000 m	1,200 - 2330 m
Rig capacity	1,000 - 2,000 HP (depend on well total depth and inclination)	550 - 1,500 HP (depend on well total depth and inclination)	less than 550 HP
Drilling preparation time	Preparing access roads and well pads for larger rigs may take longer than for smaller rigs because of their bigger size.	Preparing access roads and well pads for larger rigs may take longer than for smaller rigs because of their bigger size.	Preparation time is shorter for smaller rigs compared to larger ones because of their compact size and fewer equipment requirements.
Water supply requirement	60 - 95 litre/second	60 - 95 litre/second	5 - 30 litre/second
Casing and cementing	200 tons casing required and +- 84 m^3 cement volume	135 tons casing required and +- 55 m^3 cement volume	80 tons casing required and +- 26 m^3 cement volume
Directional drilling ability	able to accommodate directional drilling technology	able to accommodate directional drilling technology	commonly drilled vertically
Estimated drilling days	30 - 45 days	30 - 45 days	60 - 120 days
Estimated total cost per meter (US$/m)	US$ 3,000-4,500 / meter	US$ 2,000-4,500 / meter	US$ 400-1,000 / meter

When deciding on the type of well to be used, the selection process hinges on the clarity of the conceptual model regarding the hydrology of the geothermal system and the availability of direct data supporting high temperatures and permeability. The presence of high temperatures should be corroborated not only by observable phenomena like fumaroles and boiling chloride springs but also by geological features and magnetotelluric (MT) signatures. Strong indicators of permeability not only enhance the exploration target but also increase the likelihood of successful drilling using standard holes, leading to improved well flow. Conversely, in cases where 3D geological models do not conclusively confirm the presence of high-grade resources and permeability, drilling with slim or core holes is preferable. The absence of direct information on high-temperature systems and permeability heightens the uncertainty of drilling successful wells. Employing smaller wells not only optimizes resource considerations but also minimizes drilling costs compared to standard wells. In such scenarios, it is prudent to initiate drilling in areas with the lowest risks and proceed cautiously. Alternatively, a combination of standard holes and slim or core holes can be utilized, particularly in areas where direct information on high temperatures and permeability is limited. Standard holes are more effective in well-supported areas, while drilling smaller wells is a better option in higher-risk locations.

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Well type selection.

Casing Design in Geothermal

Several considerations in designing casing are similar to casing design in oil and gas. However, there are other considerations that are specific to geothermal fields. Additional factors considered in geothermal casing design include:

1. Strength at High Temperatures:

Conventional casing materials experience strength reduction at elevated temperatures, particularly in higher steel grades. For instance, K-55 casing's yield strength decreases from 388 MPa at 25°C to 359 MPa at 371°C. Quenched-and-tempered L-80 yield strength decreases from 632 MPa to 484 MPa across the same temperature range. It's crucial to consider these variations in properties based on the manufacturing process.

Elevated geothermal temperatures can have several effects on well components. These include changes in the length of unrestrained pipe, such as a 1.8-meter expansion over a 1000-meter length with a temperature increase of 150°C. Additionally, restrained (cemented) pipes may experience compressive stress, reaching up to 360 MPa (52,000 psi) with the same temperature rise. Moreover, steel strength may decrease by 5% or more in casing tensile strength tests at 300°C, and by 17% in wellhead equipment pressure ratings at the same temperature under ANSI Standards. Furthermore, material competence, especially flexible seals, may be compromised.

2. Casing Availability:

Casing procurement for geothermal wells can have a lengthy lead time, especially for specialty grades or uncommon sizes. Early verification of casing availability is essential to ensure adequate procurement time. If the specified casing is not available within the required timeframe, alternative options may increase risks, costs, or both.

3. Stress during Thermal Cycling:

As casing and connections are cemented at one temperature, then cycled up to the reservoir temperature and back to ambient during subsequent operations, they may be stressed beyond the yield point. This stress during thermal cycling should be considered in the casing design and connection selection process.

4. Corrosion Resistance:

Geothermal reservoirs typically produce H2S, limiting casing material options to those meeting NACE 107. These materials often belong to lower strength grades, constraining design choices. The diverse brine chemistry in geothermal reservoirs poses corrosion challenges, ranging from near-potable in moderate-temperature systems to highly corrosive with high dissolved solids in high-temperature systems. Various techniques, such as cement-lined casing, exotic alloys, and corrosion-resistant cement, have been applied to address this corrosion issue. In regions like the Imperial Valley of Southern California, where shallow and hot CO2-bearing zones drive an external corrosion rate approaching 3 mm of carbon steel per year, many production wells have been completed or retrofitted with titanium casing. Despite the high capital investment (approximately US$3,000/m), titanium casing has proven cost-effective in dealing with severe corrosion issues.

Cementation of Casings in Geothermal

In contrast to oil and gas wells, it is customary in geothermal wells to run all casings down to the reservoir back to the surface, and these casings are fully cemented back to the surface as well. The high thermal stresses placed on the casings necessitate consistent cementation throughout the entire casing length. This ensures that stress is evenly distributed along the casing length and helps to avoid stress concentration. The primary goal of any casing cementing program is to guarantee that the total length of the annulus, including both the casing-to-open-hole annulus and the casing-to-casing annulus, is completely filled with robust cement capable of withstanding prolonged exposure to geothermal fluids and temperatures.

Given the permeable and under-pressured nature of the formations where these casings are cemented, using a high-density cement slurry with specific gravities ranging from 1.7 to 1.9 often leads to loss of circulation during the cementing process. The traditional approach to address this issue involved attempting to seal all permeability with cement plugs as drilling progressed. However, this method is usually time-consuming, and more often than not, circulation is still lost during the casing cementing process. Various strategies have been attempted to overcome this problem, including:

• Adding low-density cement slurry additives such as pozzolan, perlite, or spherical hollow silicate balls.
• Using a sodium silicate-based sealing preflush.
• Employing foamed cement.
• Implementing stage cementing.
• Utilizing tie-back casing strings, where the casing is run and cemented in two separate operations.

While many of these options have been explored, none have proven entirely successful or cost-effective.

Drilling Fluids in Geothermal

Historically, the majority of liquid geothermal drilling fluids have been relatively simple, typically consisting of a mixture of fresh water and bentonite clay, and sometimes incorporating polymer additives. To lighten the drilling fluid, a gas—typically air but occasionally nitrogen in cases of serious corrosion—is injected into the liquid. Aerated mud, where gas is introduced, is commonly used when dealing with significant lost circulation issues. This practice has been widely employed internationally since at least the early 1970s, offering numerous benefits. Additionally, drilling with air alone is quite prevalent, especially in regions like The Geysers in northern California, where the reservoir produces dry steam. Air drilling also provides advantages in terms of drilling performance, as the rate of penetration is generally higher compared to mud or aerated mud drilling.

Certain unique considerations in geothermal drilling include:

1. Control of Viscosity

High-quality bentonite clay is the primary viscosifier in geothermal drilling While polymers in liquid and powder forms are also used, they may degrade at elevated temperatures over extended periods. These are typically applied for high-viscosity sweeps before activities like cementing. Adjustments to decrease viscosity may be necessary if drilled solids or high-temperature gelation cause an excessive increase. Recently developed proprietary blends of low-molecular-weight polymers and starch derivatives are effective in both thinning the mud and preventing gelation.

2. Solids Removal

Drilled solids tend to absorb water more aggressively at high temperatures. Therefore, effective mud cleaning becomes even more critical than usual to prevent issues like gelation and viscosity increase.

3. Filtrate (Water Loss) Control

Geothermal filtrate requirements have historically been stringent. Analyzing filtrate requirements for each well and interval is crucial to avoid unnecessary use of costly additives. While lignite has commonly been used as a water-loss reducer, proprietary polymers are becoming increasingly prevalent.

4. Alkalinity

Maintaining a high pH is essential for controlling the impact of certain wellbore contaminants (CO2 and H2S), reducing corrosion, and increasing the solubility of some mud components like lignite. Traditionally, caustic soda (NaOH) has been employed to increase alkalinity, but caustic potash (KOH) is gaining popularity in geothermal drilling due to its positive effects on wellbore stability.

5. Lubricity

Additional lubrication for the drill string may be required during activities such as directional drilling, especially when core drilling without returns. While hydrocarbon-based lubricants might lose effectiveness at high temperatures, there are environmentally friendly proprietary lubricants that maintain good performance under sustained high temperatures.

Well Control in Geothermal

One of the key distinctions between geothermal and oil and gas drilling lies in the behavior of formation fluids and their management. In geothermal drilling, wells can contain water at boiling point, and even a slight decrease in pressure can cause rapid boiling and conversion to steam, known as a "steam kick." While this presents a constant risk, controlling such kicks is straightforward and effective. By closing the blowout preventers (BOPs) and injecting cold water into the well, both down the drilling and annulus, pressure can be quickly stabilized. The pressures involved are relatively low and depend on the saturation conditions of steam and water. During a steam kick, a small amount of non-condensable gas, primarily CO2, may be released. Once the steam is condensed and cooled, any remaining non-condensable gas is typically vented through the choke line. Although some H2S gas may be present, it is usually in small quantities, requiring precautionary measures.

Geothermal Drilling Technology

Drill Pipe Continuous Circulation Device (CCD)

Stuck pipe incidents are common in geothermal drilling, with one notable event causing the loss of equipment and requiring well sidetracking. To prevent future incidents, a Continuous Circulation Device (CCD) system was introduced. However, the system needed requalification to handle the challenging geothermal conditions and accommodate higher fluid flow rates. Compatibility with two-phase aerated fluids and Lost Circulation Material (LCM) was also confirmed. The main goal was to prevent stuck pipe events during drill pipe connections and reduce overall risks. In Indonesia, a CCD system was used successfully across seven different hole sections, preventing any stuck pipe incidents. The system's performance improved over time, with a higher success rate in the second well. Circulation of the drillstring was maintained during all connections in the drilling process.

Drilling with Casing (DWC)

The casing acts as the drill string, rotating to operate the bit and advance the hole's depth. There are two main ways to attach the bit:

1. It can be fixed semi-permanently, allowing it to be dropped off the casing's end at the final depth or drilled through for subsequent casing installation.
2. It can be mounted on a drilling assembly that is retrieved via wireline or drill pipe when the bit needs replacement or the desired depth is reached. If a retrievable bit is used, it must be small enough to pass through the casing's inner diameter, requiring an under-reamer to enlarge the diameter sufficiently to allow drilling fluid to return through the annulus.

The casing is rotated using a top drive unit, which connects to the casing's top coupling either by screwing into it or using a fixture that inserts into the top joint of the casing, securely locking and sealing to its inner diameter. The top drive unit circulates drilling fluid through the casing's interior and upward along its exterior, similar to how it operates with drill pipe.

Geothermal drilling with heat-sensitive downhole tools offers several advantages. These include:

• Reduction of costs, time, and issues associated with tripping drill pipe: Tripping drill pipe and handling the Bottom Hole Assembly (BHA) consumes a significant portion of total time and cost in some wells. Many well control and hole stability problems are linked to these trips.
• Mitigation of lost circulation problems: Dual-walled concentric (DWC) systems can continue drilling even when faced with lost circulation. Rock cuttings are typically washed into fractures or permeable zones, effectively acting as lost circulation material. The narrow annulus in DWC systems allows for lower fluid flow rates compared to conventional drilling, which reduces the risk of lost circulation.
• Increased casing setting depth: By drilling through lost circulation zones or weak formations, casing can reach greater depths than with conventional drilling methods. This capability may allow for the re-design of casing programs, potentially eliminating the need for one casing string, resulting in significant cost savings.
• Enhancement of safety: Handling drill pipe presents a high risk of accidents during drilling operations. Eliminating this activity reduces crew exposure to potential hazards.

Reservoir Engineering

Definition

In the realm of geothermal reservoir engineering, a "geothermal reservoir" denotes a segment of the geothermal field characterized by significant heat and permeability, making it economically viable for fluid or heat extraction. It constitutes only a fraction of the entire field and represents merely a portion of the subterranean hot rock and fluid. Rocks that are hot yet impermeable do not qualify as part of the reservoir. The existence of such a reservoir is contingent, at least in part, upon prevailing technology and energy market dynamics.

Characteristic attributes of geothermal reservoirs typically encompass the following aspects :

1. The dominant permeability primarily occurs within fractured rock formations.
2. Geothermal reservoirs exhibit significant vertical extension.
3. In liquid-dominated reservoirs, the presence of a caprock is often unnecessary, and typically, the high-temperature reservoir maintains communication with cooler surrounding groundwater.
4. The vertical and lateral dimensions of the reservoir may lack clarity or precise delineation.

The Development of Geothermal Reservoir Engineering

The phrase “geothermal reservoir engineering” first appeared in the 1970s, and the area emerged as a distinct discipline. During this decade, scientific effort moved away from theoretical studies of what processes might possibly be important in the reservoir to practical analyses driven by the data now becoming available and the actual problems experienced in development.

Coherent conceptual models of reservoirs were developed, consistent with both the large-scale system hosting the reservoir and the local detail determined from well testing. Field developments were normally sized on the basis of volumetric reserve estimates of some form or sometimes on the available well flow alone.

At the beginning of the 1980s, the first numerical simulation codes were developed, and a trial in which several codes were used to simulate a set of test problems demonstrated their consistency. During the 1980s and 1990s, reservoir simulators became more capable, and increasing computing power meant that by the 1990s, it was reasonable to simulate a reservoir with enough blocks to be able to represent known geological structures and varying rock properties within the reservoir. As a result, by the 1990s, larger new developments were being sized on the basis of simulation results.

At the same time, downhole instruments were steadily improving in capability and resolution, making detailed temperature-pressure-spinner profiles possible. More important than either simulation or better instruments was the accumulation of collective experience within the profession. Although the basic concepts were all developed by the 1970s, and the fact that many recent technical papers are superficially similar to some from that time, the weight of experience means that these concepts are now being applied more rigorously and more consistently with observation. In some aspects of the geothermal reservoir engineer’s work, it is now possible to refer to normal practice to define the procedures and expected results.

In the first decade of the twenty-first century, experience, simulation, and instrumentation have all continued to improve. Perhaps the most significant change has been the increasing importance of environmental impacts of development. Seismic effects have become a limiting factor on some Engineered Geothermal System (EGS) projects. Impacts on surface springs have always been an issue in development of the associated deep resource, and this concern has prevented some developments.

Basic to all reservoir engineering is the observation that almost everything that happens is the result of fluid flow. The flow of fluid (water, steam, gas, or mixtures of these) through rock, fractures, or a wellbore is the unifying feature of all geothermal reservoir analysis.

Geothermal reservoir engineering, having its roots in petroleum reservoir engineering, has historically relied on conventional petroleum methods with slight modifications to account for inherent differences in conditions. It was not until the late 1960s and early 1970s that engineers recognized they must include a rigorous energy balance to account for interphase mass and energy exchange and other heat transfer mechanisms that arise from vaporization of fluid during extraction operations. There are a variety of phenomena that make geothermal reservoir engineering unique compared to conventional reservoir engineering, including:

1. The reservoir fluid has no inherent value in and of itself. The fluid (either liquid or vapor) can be viewed as a working fluid whose sole value is the energy (heat) it contains.
2. Geothermal reservoirs in the native state are rarely static and are usually neither isothermal nor of uniform fluid composition. Large spatial variations in pH occur. Highly-corrosive reservoir fluids are not uncommon and lead to additional expense of drilling, completions, and production.
3. Geothermal reservoirs are rarely completely closed. More often, a zone of recharge and multiple zones of discharge (including springs and fumaroles) are associated with the resource.
4. Phase behavior is deceptively complex. In its simplest form, the reservoir fluid is a single component that may partition into up to three phases: liquid, vapor, and adsorbed phases. Usually, there are additional components such as noncondensible gases (CO₂, H₂S, etc.) and salts.
5. Geothermal reservoirs are typically found in highly fractured igneous or metamorphic rocks; very few are found in sedimentary rocks worldwide. While rock matrix properties would make the resource commercially unattractive as a petroleum reservoir (e.g., permeability can range as low as a 10^–20 m², porosity is in the 0.02 to 0.10 range), the relatively large dimensions (thickness may range to thousands of meters) ensure a substantial resource (heat) is in place.

While there are important distinctions between classical petroleum engineering and geothermal reservoir engineering, much of the latter can be considered an extension of the former. In this section, we emphasize these extensions of conventional engineering.

Reservoir Characterization

Well Testing

Geothermal well testing is similar in many respects to transient pressure testing of oil/gas wells, with some significant differences. Many geothermal wells induce boiling in the near-well reservoir, giving rise to temperature transients as well as pressure transients. Substantial phase change may also take place in the well, further complicating analysis. Pressure tools must be kept in a high-temperature environment for long periods of time, and production intervals are frequently very small portions of overall well depth. Production intervals, which are usually associated with fracture zones, may be at substantially different thermodynamic conditions. Finally, pressure and temperature changes induce fluid property changes that require correction. Nevertheless, the principles of geothermal well testing are the same as petroleum well testing. And with the caveats already noted, standard interpretation methods can be used.

Measurement and testing of wells are crucial activities to obtain data or information regarding:

1. Depths of high-temperature zones, production zones, and fracture centers (feed zone).
2. Types of production fluids.
3. Reservoir types.
4. Pressures and temperatures within the well and reservoir.
5. Well production capabilities, including production rates and fluid enthalpy at various wellhead pressures.
6. Fluid characteristics and gas content.
7. Reservoir characteristics around the well.
8. Wellbore conditions, linear casing.

In the context of geothermal reservoir engineering, the types of well tests conducted in geothermal wells are as follows:

1. Completion test (water loss test and gross permeability test)
2. Injectivity test
3. Heating measurement
4. Production test (discharge/output test)
5. Transient test

An explanation of each type of well testing will be explained below.

Completion Test

A completion test, also known as a water loss test, is conducted to determine the depth of the production zone and the depth of fracture centers (feed zones) as well as their productivity.

Completion tests are performed after drilling reaches its target depth (as desired) and the liner is installed in the well. However, this test can also be conducted before lowering the liner or when drilling is temporarily halted. The latter method may slow down drilling activities but is the most appropriate and straightforward way to gain insights into reservoir conditions.

During a completion test, cold water is injected into the well at a constant rate while measuring the pressure and temperature inside the well to determine the pressure and temperature profiles during injection. Completion tests are typically performed multiple times at different pumping rates. By analyzing pressure and temperature profiles, the location of production zones, fracture centers, and their productivity can be determined.

There are two types of tests conducted during a completion test:

• Water Loss Test. The water loss test is conducted to identify locations where water loss occurs or where formation fluid enters the wellbore, indicating the presence of fracture centers. This can be determined from pressure, temperature, and flow profiles when water is pumped at a constant rate.

• Gross Permeability Test. The gross permeability test is performed to determine pressure transient behavior after varying flow rates. By analyzing this data, the total permeability can be determined.

To provide an overview, below is the general procedure commonly followed when testing geothermal wells in New Zealand:

• Lower the slotted liner into the well.
• Clean the well by pumping water at an injection rate of approximately 20 liters per second.
• Perform the first water loss test by pumping water at a rate of 10 liters per second.
• Conduct permeability tests by pumping water at rates of 10 and 20 liters per second.
• Perform the second water loss test by pumping water at a rate of 20 liters per second.
• If deemed necessary, repeat the water loss test to determine the exact location of production zones and the depth of fracture centers.
• Shut down the pump (warm-up). Analyze the data obtained from the water loss and permeability tests as discussed below.

Injectivity Test

Once the major loss zone has been recognized, the injectivity index can be simply calculated for wells with poor overall permeability that can be overpressured throughout their openhole depth during injection. Since the pressure difference between the wellbore and the formation increases with depth, favoring the deeper zones, the injectivity index should be evaluated as close to the zone of highest injectivity as possible. This zone may not be at the same depth as the "major" loss zone. Typically, the pressure gradient in the well during the injection of cold water is significantly greater than in the hot formation. This is especially crucial in situations where the openhole length is substantial (>1000 m).

It is important to make sure that the zero pressure used to evaluate the pressure tests matches stabilized pressures measured in the weeks of heating following the injection test. In wells with poor permeability, it may take several hours or even days for the well pressures and formation pressures to equilibrate after an injection test. The wellbore pressure is sufficient to increase the natural rock permeability by forming cracks, therefore for extremely low permeability wells, it is simple to overpressurize the formation, even at very small injection rates (as low as 10 l/s) and generate deceptive signals of permeability.

A value for gross permeability may not be very meaningful for higher permeability wells that have inflows at the upper levels during injection (because wellbore pressure is lower than formation pressure in the upper part of the open hole), as the value will depend on the depth at which the pressure is measured and may not account for the additional inflowing fluid. It may not be reasonable to compare the downhole pressure change with the surface injection rate in some circumstances, as the inflow rate may exceed the injection rate at the surface.

The pressure transient measured after varying the injection flow rate should always be examined for indications of irregularity, including rebounds, cycling, loud pump noise, and, most importantly, unlogged changes in pump rate (which, for instance, may be the result of a rig pump valve failing; these can be challenging to detect because the pump rate is typically calculated by counting the stroke rate and assuming a fixed volume per stroke). Although the stabilized pressure at each rate is what defines the injectivity. The injectivity statistics are either completely invalidated or at best of inferior accuracy if such an abnormality is noticed during a pump test. The fluid velocity obtained from spinner data measured in the cased hole at the top of each spinner profile can be used to cross-check the injection flow rates.

Heating Measurement

Following the completion of the well testing phase, water injection ceases by deactivating the pump. This leaves the well in a relatively cool state. Production testing is not conducted at this stage due to the potential for rapid temperature fluctuations caused by hot fluids flowing through the cool casing. Such fluctuations could induce thermal stresses and damage the casing. Therefore, post-completion, the well undergoes a shut-in period to allow it to heat up before production testing commences.

During the shut-in period, pressure and temperature within the well are monitored at specific intervals. Typically, measurements are taken on days 1, 2, 4, 7, 14, 28, and 42. However, if a more detailed temperature profile is required, the heating test can be extended. The duration of the heating test varies depending on specific conditions, ranging from a few hours to several months. Ideally, to obtain comprehensive data, the heating test should span at least one month. As the well remains shut-in, it gradually heats up, resulting in an increase in temperature and a decrease in the pressure gradient within the wellbore.

There are several mechanisms by which heat can reach the wellbore:

• Conduction: Heat transfer occurs through the surrounding rock formations via direct contact.
• Interzonal Flow: Fluids flow directly into the wellbore at one depth and exit at another, facilitating heat transfer.
• Convection: Heat transfer occurs through the movement of fluids within the wellbore itself.

The rate of temperature change within the wellbore is influenced by the permeability of the surrounding rock formations. In highly permeable formations, convective heat transfer is significant, leading to a more rapid temperature increase compared to low-permeability formations where conduction dominates. Consequently, wells in low-permeability formations may require several months to reach thermal equilibrium.

Figure 9.1 illustrates the temperature profile of well NG17 (Ngawha, New Zealand), where the temperature change is relatively small. This suggests that heat transfer occurs primarily through conduction, indicating low rock permeability. This observation is supported by completion test results, which show very low permeability (injectivity of 2 kg/MPa.s ) near the 700m depth.

Fig. 9.1-Temperature profileduring heating test in well NG7.

Interzonal flow, characterized by the movement of water between different depth levels within the wellbore, manifests as a more rapid and uniform temperature increase in specific sections of the well. An example of this phenomenon is observed in the heating test results of well OK5 (Okoy Field, Philippines), as shown in Figure 9.2. The temperature profile suggests interzonal flow between depths of 1100m and 1550m, indicating relatively high permeability at these depths.

Fig. 9.2-Temperatureprofile during heating test in well OK5.

Upon completion of the heating test, well fluids are typically bled to the surface through a small pipe at a very low flow rate (around 1 kg/second ). This process aims to pre-heat the casing before production testing commences.

Production test

Production testing, also known as discharge or output testing, is conducted to determine:

• Fluid Types: Characterize the reservoir fluids and the produced fluids.
• Production Capacity: Evaluate the well's ability to produce fluids, including flow rates and enthalpy at various wellhead pressures.
• Fluid Characteristics and Gas Content: Analyze the properties of the produced fluids and the presence of gas.

The data acquired from production testing is crucial for determining the optimal wellhead pressure for operating the geothermal wells. Flow rate, enthalpy, and pressure data are essential for calculating the well's potential under various operating conditions.

One of the key outcomes of production testing is the generation of production curves (output curves). These curves illustrate the well's production capacity by plotting relationships between total mass flow rate, steam mass flow rate, enthalpy, and vapor fraction (dryness). Examples of production curves from various geothermal fields are shown in Figures 9.3, 9.4, and 9.5.

Fig. 9.3 - Example of a production curve (output curve).

Fig. 9.4 - Well production test curves from various water dominated geothermal fields.

Fig. 9.5 - Well production curves from various steam dominated geothermal fields.

Several methods are commonly employed for production testing:

• Single-Phase Measurement Method: This method measures the total mass flow rate and assumes a homogenous fluid phase.
• Calorimeter Method: This method utilizes a calorimeter to determine the enthalpy of the produced fluids.
• Lip Pressure Method: This method measures pressure at the wellhead and at a point downstream to calculate the flow rate.
• Separator Method: This method separates the steam and liquid phases of the produced fluids to measure their individual flow rates and properties.

Transient Test

Pressure transient testing serves as a vital diagnostic tool for assessing the condition of geothermal wells and estimating reservoir properties. By analyzing pressure data collected during these tests, valuable insights can be gained regarding various aspects of the reservoir and well system. These include:

• Formation Characteristics: Determining key parameters such as permeability, storativity, and porosity, which govern fluid flow within the reservoir.
• Reservoir Boundaries and Barriers: Identifying the presence of impermeable barriers or leaky boundaries that may influence fluid movement and pressure distribution.
• Wellbore Condition: Assessing the well's condition, such as identifying potential damage or stimulation effects near the wellbore.
• Fracture Detection: Detecting the presence of major fractures in close proximity to the well, which can significantly impact fluid flow.
• Reservoir Pressure: Estimating the average pressure within the reservoir.

Pressure transient tests typically involve controlled production from one or more wells while monitoring pressure changes within the producing well or nearby observation wells (interference tests). The collected data is then analyzed using specialized techniques to extract the desired information. A comprehensive review of these techniques can be found in works by Matthews and Russell, Earlougher, and Streltsova.

While extensive literature exists on pressure transient analysis for oil and gas reservoirs, geothermal systems present unique challenges. Geothermal reservoirs often exhibit non-isothermal two-phase flow behavior during testing, and the formations encountered by geothermal wells typically possess non-uniform properties, unlike the more homogenous formations found in oil and gas fields.

Partial Penetration

Traditional pressure transient analysis methods often rely on the assumption of a fully penetrating well intersecting a homogenous aquifer, where the line source solution serves as the foundation for interpreting pressure responses. However, geothermal reservoirs typically exhibit more complex characteristics. Permeability in these reservoirs is often concentrated within thin stratigraphic layers or fracture networks. As a result, geothermal wells only connect with the reservoir at specific depths where they intersect these permeable zones, while remaining isolated from the formation throughout the rest of their depth. This scenario is analogous to a partially penetrating well in oil or groundwater systems.

The mathematical framework for analyzing partially penetrating wells has been established by Nisle and Brons and Marting. The pressure response of such wells exhibits distinct features, with buildup (or drawdown) curves displaying two distinct straight-line segments on a Horner plot. The ratio of the slopes of these segments corresponds to the penetration ratio. However, in many geothermal wells, the permeable intervals represent such a small fraction of the overall formation thickness that defining a meaningful penetration ratio becomes impractical. In such cases, during early flow or shut-in periods, the pressure response resembles that of a spherically symmetric source/sink rather than a linear one. Tang presents the mathematical theory for analyzing spherical flow behavior in geothermal wells. During this spherical flow period, plotting pressure drop or buildup against the square root of time (t-0.5) yields a straight line, and the slope can be used to estimate formation permeability.

A significant consequence of partial penetration in geothermal systems is the observation that transmissivity values derived from interference tests often surpass those obtained from single-well tests. This discrepancy highlights the importance of considering the complexities introduced by partial penetration when analyzing pressure transient data in geothermal settings.

Decline Curve Analysis

Decline curve analysis (DCA) is a widely used technique in geothermal reservoir engineering for predicting future production performance and understanding reservoir depletion mechanisms. It involves analyzing historical production data to forecast future production rates, estimate recoverable reserves, and optimize reservoir management strategies.

Data Preparation: Normalizing Flow Rates

Before applying decline curve analysis, it's crucial to normalize well flow rates against a standard flowing wellhead pressure. This accounts for variations in pressure and allows for a more accurate comparison of production data over time. For steam wells, the following equation is used:

....................(9.4)

For liquid-dominated wells, a slightly different equation is employed:

....................(9.5)

Where:

• W_norm is the normalized flow rate
• W is the measured flow rate
• P is the estimated static wellhead pressure
• P_std is the standard flowing wellhead pressure
• P_wf is the measured well flowing pressure

It's important to exercise caution when extrapolating rates too far into the future, as factors like phase changes can significantly impact fluid properties and decline behavior.

Arps Decline Curves

Arps decline curves, based on empirical equations developed by Arps, provide a framework for analyzing production decline. The general rate-time equation is:

....................(9.6)

Where:

• D_i is the initial decline rate
• b is the Arps decline exponent (0 ≤ b ≤ 1)
• t is time

Depending on the value of b, different decline types can be identified:

• Exponential decline (b = 0): Production declines at a constant rate.
• Harmonic decline (b = 1): Often observed in naturally fractured reservoirs, production decline follows a hyperbolic curve with a decreasing decline rate.
• Hyperbolic decline (0 < b < 1): Represents a general case with a declining decline rate.

These decline equations are useful for estimating future production rates and determining the time or flow rate at which a well might be abandoned.

Fetkovich Type Curves

Fetkovich type curves provide a theoretical foundation for decline curve analysis and offer additional insights into reservoir properties. They are used to estimate decline parameters (Di and b) and provide estimates of permeability-thickness product (kh) and wellbore skin (S). The relevant equations, adapted for geothermal applications, are:

....................(9.7)

....................(9.8)

Applying Fetkovich type curves in geothermal well analysis requires careful consideration of potential phase changes and their impact on fluid properties, especially compressibility. Significant changes in reservoir conditions can lead to inaccuracies in decline rate predictions and reservoir property estimations.

Decline curve analysis, using both Arps and Fetkovich methods, provides valuable insights for understanding production decline behavior and optimizing reservoir management strategies. However, it's essential to consider the limitations and complexities of geothermal reservoirs when interpreting results and making long-term predictions. By carefully analyzing historical data and accounting for potential phase changes and reservoir heterogeneities, DCA remains a powerful tool for navigating the challenges of geothermal reservoir engineering and ensuring sustainable energy production.

Tracer Testing

In the realm of geothermal reservoir engineering, tracer tests play a critical role in understanding the intricate connectivity between injection and production wells. Reinjection of spent geothermal fluids has become a standard practice, driven by environmental considerations, reservoir pressure maintenance, and improved energy extraction efficiency. However, the temperature disparity between injected fluids and the native reservoir fluids raises concerns about premature thermal breakthrough at production wells.

Tracer tests provide valuable insights into the movement of injected fluids, enabling the optimization of injection strategies. By determining the sweep efficiency of various injection patterns, operators can minimize or delay the return of injected fluids to production wells while still maintaining reservoir pressure. Furthermore, due to the open nature of many geothermal systems, tracer tests can also be utilized to estimate the extent of natural recharge and discharge processes, as well as the total pore volume of the reservoir.

The primary objective of geothermal tracer testing lies in quantifying the degree of connectivity between injection and production wells. This information serves as a foundation for developing effective injection programs that balance pressure support with the mitigation of thermal breakthrough, ensuring the long-term sustainability and productivity of geothermal operations.

Geothermal Tracers

Tracer tests play a crucial role in understanding the complex flow dynamics and connectivity within geothermal reservoirs. Due to the unique characteristics of these reservoirs, including irregular well spacing, potential weak connectivity, and the presence of high temperatures, tracer selection and testing methodologies require careful consideration.

Recent Advancements in Tracer Technology

While traditional tracers like chloride, ammonia, and stable water isotopes have been utilized for decades, advancements in tracer technology have expanded the available options. These advancements encompass:

• Polyaromatic Sulfonates: Offering high thermal stability at temperatures exceeding 300°C and boasting detection limits in the parts per trillion range, polyaromatic sulfonates have become a preferred choice for high-temperature geothermal reservoirs.
• Micro and Nano Tracers: Expanding the scope of tracer applications to encompass low-permeability formations, such as Enhanced Geothermal Systems (EGS), micro and nano tracers offer the advantage of improved transport through tight pore spaces. Examples include microparticles like melamine rhodamine B and DNA-based tracers.
• Temperature-Sensitive Tracers: Providing insights into subsurface temperature distribution, these tracers utilize materials that exhibit detectable changes in response to varying temperatures. Recent developments involve silica-encapsulated DNA particles with hydrofluoric acid chemistry, offering potential for monitoring temperature variations within the reservoir.

Tracer Selection Criteria

Selecting the appropriate tracer for a specific geothermal reservoir involves evaluating several key criteria:

• Thermal Stability: Ensuring the tracer remains chemically stable at the reservoir's temperature is crucial for accurate interpretation of results. High-temperature environments necessitate tracers like polyaromatic sulfonates, while lower temperature conditions may allow for the use of fluorescein or specific salts.
• Background Concentrations: Tracers with low background concentrations in the native geothermal fluid are preferred to ensure a clear signal and facilitate accurate detection.
• Detectability: The tracer should be easily detectable at low concentrations using available analytical techniques. This factor influences the required injection mass and overall cost of the test.
• Environmental Impact: Choosing environmentally benign tracers is essential to minimize potential ecological risks.
• Sorptivity and Volatility: The tracer's tendency to adsorb onto rock surfaces or volatilize can influence its transport behavior and should be considered during interpretation.

Injection and Sampling Techniques

Tracer tests typically involve injecting a known mass of tracer into the reservoir and subsequently monitoring its concentration at production wells. The injection can be performed as a pulse (slug) injection or a continuous injection. Slug injections are often preferred due to their simplicity and cost-effectiveness. Sampling frequency depends on the expected travel time and reservoir characteristics. Early-time sampling with higher frequency is crucial to capture the initial breakthrough of the tracer, while later stages may require less frequent sampling.

Analytical Modeling Methods

Interpreting tracer data involves matching field observations with analytical models that describe the transport behavior within the reservoir. Commonly used models include:

• Multi-Fracture Model: This model assumes flow occurs primarily through a network of interconnected fractures, reflecting the fractured nature of many geothermal reservoirs.
• Fracture-Matrix Model: Accounting for both fracture and matrix permeability, this model provides a more comprehensive representation of fluid flow in fractured geothermal systems.
• Dual-Porosity Models: Recognizing the presence of distinct fracture and matrix domains with differing porosities and permeabilities, dual-porosity models offer another approach to characterize fluid flow in geothermal reservoirs.
• Homogenous Model: Assuming uniform reservoir properties, this model may be applicable in specific cases where the reservoir exhibits minimal heterogeneity.

Matching model predictions with field data often employs the non-linear least squares method. Specialized software and tools, including those developed by Akin and Axelsson et al., facilitate this process and aid in estimating reservoir parameters such as permeability, porosity, and flow dimensions.

Advancements in tracer technology and analytical methods continue to enhance our understanding of geothermal reservoirs. By carefully selecting appropriate tracers and employing robust interpretation techniques, tracer tests provide valuable insights into reservoir connectivity, flow paths, and transport characteristics, ultimately contributing to improved reservoir management and sustainable geothermal energy production.

Interpretation Methods

Interpreting tracer test data is crucial for extracting meaningful insights into the connectivity and flow dynamics within geothermal reservoirs. While qualitative analysis provides a basic understanding of tracer movement, quantitative interpretation techniques offer a more detailed and accurate assessment of reservoir characteristics.

Flow Channel Model

A widely adopted method for interpreting geothermal tracer tests involves the concept of specific flow channels connecting injection and production wells. This approach assumes that fluid flow between wells can be approximated as one-dimensional flow within these channels, which may represent fractures, interbeds, or larger interconnected volumes.

The model utilizes the advection-dispersion equation to describe tracer transport within the flow channel. By simulating tracer return curves observed at production wells, key parameters such as flow channel volume, dispersivity, and the fraction of recovered tracer mass can be estimated. This information is essential for predicting potential thermal breakthrough and temperature decline during reinjection operations.

While the flow channel model provides a valuable tool for initial interpretation, it's important to acknowledge its limitations. The assumption of one-dimensional flow may not always hold true, particularly in complex geological settings. Additionally, the method does not provide direct information on the geometry or surface area of the flow channels, which are critical factors influencing heat transfer.

Advancements in Quantitative Analysis Techniques

Several advancements have enhanced the quantitative interpretation of geothermal tracer tests, particularly in addressing the complexities of heterogeneous reservoirs:

• Multi-Tracer Tests and Inversion Techniques: Utilizing multiple tracers with distinct properties allows for a more comprehensive characterization of reservoir heterogeneity. Inversion techniques, such as those implemented in software like TRINV, enable the simultaneous analysis of multiple tracer return curves, providing improved estimates of flow parameters and reservoir structure.
• Geochemical and Isotopic Data Integration: Integrating tracer data with geochemical and isotopic analyses of geothermal fluids offers additional insights into reservoir processes and flow paths. For instance, monitoring chloride concentrations can help distinguish between injected and native fluids, while stable isotope ratios can provide information on fluid origins and mixing.
• Numerical Modeling: Advanced numerical reservoir simulators, such as TOUGH2, can be used to model tracer transport in complex geothermal systems with greater accuracy. History matching tracer data with numerical simulations allows for a more detailed understanding of reservoir heterogeneity and flow behavior.

Interpreting Tracer Data in Heterogeneous Reservoirs

Heterogeneity poses a significant challenge in interpreting tracer test data. The presence of fractures, faults, and varying rock properties can lead to complex flow patterns and deviations from idealized models. To address this, several approaches are employed:

• Model Selection and Comparison: Evaluating the fit of different analytical models (e.g., multi-fracture, dual-porosity) to the observed tracer data helps identify the most representative model for the specific reservoir.
• Flow-Storage Capacity Plots: These plots, based on temporal moments analysis, provide insights into the heterogeneity and flow distribution within the reservoir.
• Machine Learning Techniques: Artificial Neural Networks (ANNs) can be utilized to analyze complex tracer data and identify suitable models, particularly in cases with multiple peaks or non-ideal behavior.

Interpreting geothermal tracer test data requires a combination of analytical methods, numerical modeling, and consideration of reservoir heterogeneity. Recent advancements in tracer technology and interpretation techniques have significantly improved our ability to quantify flow parameters, predict thermal breakthrough, and gain a deeper understanding of subsurface flow dynamics in geothermal systems. By incorporating these advancements and adapting methodologies to specific reservoir complexities, tracer tests continue to serve as a vital tool for optimizing geothermal resource management and ensuring the sustainable utilization of this valuable energy source.

Numerical Simulation

Understanding and managing geothermal reservoirs require tackling the intricate dance of mass and energy transport within these heterogeneous systems. Numerical simulation has emerged as a powerful tool to navigate this complexity, employing sophisticated models to solve the coupled equations governing geothermal processes.

The Evolution of Geothermal Simulation

The journey of geothermal simulation began in the 1970s with the development of early numerical models. However, it wasn't until the landmark 1980 Code Comparison Study that these models gained widespread acceptance for reservoir management. This study involved testing various geothermal simulation codes against a set of standardized problems, demonstrating their capability to accurately solve complex geothermal equations. Since then, numerical models have become indispensable tools, applied to numerous geothermal fields worldwide and contributing significantly to reservoir management strategies.

Challenges in Modeling Geothermal Reservoirs

Simulating geothermal reservoirs presents unique challenges due to the complex interplay of various physical and chemical processes:

• Multiphase flow: Water, the dominant component of geothermal fluids, can exist as liquid, vapor, or in an adsorbed state. Phase behavior is further complicated by factors like vapor pressure lowering, the presence of non-condensible gases (e.g., CO2), and dissolved salts. Accurately capturing phase changes, such as vaporization and condensation, occurring naturally in heat pipes or induced by production/injection operations, is crucial for realistic simulations.
• Mineral Precipitation and Dissolution: Changes in temperature and pressure can trigger mineral precipitation or dissolution, impacting porosity, permeability, and overall reservoir performance, particularly near wellbores.
• Heterogeneity: Geological features like faults, fractures, and varying rock properties contribute to significant reservoir heterogeneity, requiring careful consideration in model development.

Governing Equations

Geothermal simulations rely on fundamental conservation principles, similar to thermal petroleum or hydrological simulations: conservation of mass for each component and conservation of overall energy. However, geothermal systems necessitate additional considerations:

• Non-Isothermal Conditions: Geothermal reservoirs often exhibit significant temperature variations, demanding the inclusion of heat transfer mechanisms within the model.
• Two-Phase Flow: Specialized equations are needed to capture the interactions between liquid and vapor phases, accounting for factors like relative permeability and capillary pressure.
• Chemical Reactions: Mineral precipitation/dissolution and other chemical reactions influence reservoir properties and fluid composition, requiring additional equations to represent these processes accurately.

Conceptual Models and the Native State

Building a robust conceptual model is crucial for accurate geothermal reservoir simulation. This model represents the understanding of the reservoir's geological structure, including faults, fractures, rock properties, and fluid flow patterns. Geothermal reservoirs often exhibit unique characteristics compared to oil and gas reservoirs:

• Dynamic Equilibrium: Geothermal systems exist in a dynamic equilibrium with their surroundings, involving continuous heat influx, heat loss, and natural recharge and discharge processes. Accurately capturing these dynamics in the native state model is essential for reliable simulations.
• Open Boundaries: Open boundaries allow for fluid and heat exchange with surrounding formations, impacting reservoir behavior and long-term sustainability.
• Convection Cells: Driven by local variations in heat flux, convection cells significantly influence fluid circulation patterns within the reservoir.

Recent advancements in conceptual modeling include:

• Integrated Geophysical Data: Incorporating geophysical data, such as seismic and magnetotelluric surveys, can help refine the understanding of reservoir structure and heterogeneity, leading to more accurate models.
• Data-Driven Approaches: Machine learning techniques are increasingly used to analyze large datasets and identify key parameters for conceptual model development, improving model accuracy and reducing uncertainties.

The Impact of Fractures

Fractures play a crucial role in fluid flow and heat transfer within geothermal reservoirs. Accurately representing fracture networks within the model is essential for simulating reservoir dynamics and predicting future performance. Recent developments in fracture modeling include:

• Hybrid Modeling Approaches: Combining discrete fracture networks (DFN) with continuum models allows for a more detailed representation of major fractures while maintaining computational efficiency.
• Stochastic Fracture Modeling: Accounting for the inherent uncertainty in fracture distribution and properties, stochastic approaches generate multiple fracture realizations to assess the range of possible reservoir behaviors.

The Simulation Process

Geothermal reservoir simulation typically involves:

1. Building a Native State Model: Simulating the reservoir's evolution over geological time to establish initial conditions that match observed data.
2. History Matching: Calibrating the model by comparing simulated results with historical production data, including flow rates, enthalpy, pressure, and tracer data.
3. Predictive Simulations: Evaluating the impact of different production scenarios and management strategies on reservoir performance and long-term sustainability.

Recent advancements in simulation processes include:

• Ensemble-Based History Matching: Running multiple simulations with varying parameters to assess uncertainties and improve model calibration.
• Coupled THMC Modeling: Integrating thermal, hydrological, mechanical, and chemical processes provides a more comprehensive understanding of reservoir behavior and interactions between various physical and chemical phenomena.

Future Directions

Geothermal numerical simulation continues to evolve with advancements in computational power and modeling techniques:

• Machine Learning and Artificial Intelligence: Integrating machine learning algorithms can enhance model calibration, optimize reservoir management strategies, and improve predictions of reservoir behavior.
• Big Data Analytics: Utilizing big data analytics can help identify hidden patterns in large datasets and improve understanding of complex reservoir processes.
• Supercritical Geothermal Systems: Research is extending simulation capabilities to explore deep-seated geothermal resources under supercritical conditions.

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

The type of energy conversion system used to produce electrical power from a geothermal resource depends on the type and quality (temperature) of the resource. Vapor-dominated resources use conversion systems where the produced steam is expanded directly through a turbine. Liquid-dominated resources use either flash-steam or binary systems, with the binary conversion system predominately used with the lower temperature resources.

Direct Steam Systems/Vapor-Dominated Resources

When the geothermal resource produces a saturated or superheated vapor, the steam is collected from the production wells and sent to a conventional steam turbine (see Fig. 9.13). Before the steam enters the turbine, appropriate measures are taken to remove any solid debris from the steam flow, as well as corrosive substances contained in the process stream (typically removed with water washing). If the steam at the wellhead is saturated, steps are taken to remove any liquid that is present or forms prior to the steam entering the turbine. Normally, a condensing turbine is used; however, in some instances, a backpressure turbine is used that exhausts steam directly to the ambient. The steam discharges to a condenser where it is condensed at a subatmospheric pressure (typically a few inches of Hg). The condenser shown in Fig. 9.13 is a barometric condenser. In a barometric condenser, the cooling water is sprayed directly into the steam, with the cooling water and condensate being pumped to a cooling tower where the condensing heat load is rejected to the ambient. Some plants use surface condensers where the latent heat from the condensing steam is transferred to cooling water being circulated through the condenser tubes. With a surface condenser, the cooling water and condensate are typically pumped to the cooling tower in separate streams. The steam condensate provides a makeup water source for the evaporative heat rejection system. Any excess condensate, together with the tower blowdown, is injected back into the reservoir.

• 

  Fig. 9.13—Schematic diagram of a dry-steam power plant.

Hydrothermal resources typically contain varying amounts of dissolved minerals and gases that impact both the design and operation of the energy conversion systems. In power cycles where steam is extracted from the geothermal resource and expanded in a condensing turbine, the cycle design must account for the removal of the noncondensable gases extracted from the resource with the steam. If not removed, these gases accumulate in the condenser, raising the turbine exhaust pressure and decreasing power output. When hydrogen sulfide is present in the process steam, it also accumulates in the condenser, though a portion partitions or dissolves in the condensate or cooling water. When the hydrogen sulfide levels are sufficiently high so that some abatement process of the condensate or cooling water is required, surface condensers are typically used to minimize the quantity of water that has to be treated. In addition, the noncondensable gas stream containing hydrogen sulfide must also be treated prior to being released to the atmosphere.

Flash Steam Systems/Liquid-Dominated Resources

With few exceptions, the fluid in hydrothermal resources is predominantly liquid. Frequently, the reservoir pressure is insufficient to overcome the hydrostatic head in the wellbore and bring the fluid to the surface as a liquid, at flow rates sufficient for commercial production. Depending on the power cycle used, it may be necessary to use downhole pumps to provide the necessary flow. In instances when the reservoir temperature is sufficiently high, the fluid is allowed to flash in the wellbore. This reduces the hydrostatic head in the wellbore and allows more production flow. When flashing occurs in the well, a two-phase fluid is produced from the well. The conversion systems used with this flow condition are typically flash-steam power cycles. In a single-flash cycle, a separator is used to separate the fluid phases, with the steam phase being sent to a turbine. Typically, in this cycle, the fluid pressure immediately upstream of the separator is reduced, which results in additional flashing of the liquid phase and produces additional steam flow. This single-flash steam power cycle is depicted in Fig. 9.14. Once the steam leaves the separator, the cycle is very similar to that for a vapor-dominated resource (Fig. 9.13). The saturated liquid brine leaving the separator is reinjected along with cooling tower blowdown and excess condensate.

• 

  Fig. 9.14—Schematic diagram of a single flash-steam power plant.

The dual-flash steam power cycle adds a second low-pressure flash to the single-flash cycle. In the dual-flash cycle, the liquid leaving the first (high pressure) separator passes through a throttling device that lowers fluid pressure, producing steam as the saturated liquid flashes. The steam from this second flash is sent either to a second turbine or, if a single turbine is used, to the turbine at an intermediate stage. The steam exhausting the turbine(s) is condensed with a heat-rejection system similar to that of the steam plant used with a vapor-dominated resource. In the dual-flash cycle, the optimum pressure of the first separator is higher than the optimum flash/separator pressure in a single-flash cycle. Unless the resource temperature is high, the optimum first-stage pressure can be found using an initial approximation that this separator temperature is at the mid-point of the temperature where flashing starts to occur (liquid reservoir temperature) and 100°C. The second, or low pressure, flash is typically just above atmospheric pressure. As the resource temperature increases, the optimum pressures for the two flash stages increase.

As with the direct steam systems (vapor-dominated resource), flash plants must have provisions to remove noncondensable gases from the heat-rejection system, to remove liquid from the saturated steam before it enters the turbine and, if levels are sufficiently high, remove hydrogen sulfide from the noncondensable gas and condensate streams. In addition, mineral precipitation is generally associated with the flashing processes. This requires the use of chemical treatment in the wellbore, separators, and injection system to prevent the deposition of solids on piping, casing, and plant-component surfaces. The potential for mineral precipitation increases as the fluid is flashed because the dissolved minerals concentrate in the unflashed, liquid phase.

Binary Systems/Liquid-Dominated Resources

A binary conversion system refers to a power cycle where the geothermal fluid provides the source of energy to a closed-loop Rankine cycle that uses a secondary working fluid. In this closed loop, the working fluid is vaporized at pressure using the energy in the geothermal fluid, expanded through a turbine, condensed, and pumped back to the heat exchangers, thus completing the closed loop. This type of conversion system is used commercially with liquid-dominated resources where the fluid temperatures are below ~

200°C. Typically, this conversion system requires the use of pumped production wells to provide necessary well flow and to keep the fluid in a liquid phase to prevent minerals from scaling of heat exchanger surfaces. The system is depicted schematically in Fig. 9.15 with an evaporative heat-rejection system.

• 

  Fig. 9.15—Schematic diagram of a binary power plant.

In some areas where geothermal resources are found, there is little water available for evaporative heat-rejection systems. In these cases, the cooling tower and condenser, shown in Fig. 9.15, are replaced with air-cooled condensers. A commercial plant that uses this sensible heat-rejection system is shown in Fig. 9.16. Typically, all of the geothermal fluid that passes through the binary plant heat exchangers is injected back into the reservoir. This is environmentally desirable, as it effectively eliminates all emissions to the ambient and, more importantly, provides a recharge to the reservoir to maintain its productivity. The working fluids used in these plants are volatile and typically are in a gas phase at room temperature and atmospheric pressure. They liquefy at moderate pressures, and the entire working-fluid system is generally operated at above atmospheric pressure to prevent the leakage of air into the closed loop. Existing plants use isobutane, pentane, or isopentane working fluids.

• 

  Fig. 9.16—Picture of the air-cooled binary plant near Mammoth Lakes, California. Photo by Joel Renner, used with permission.

The performance of the binary system depends on a number of factors, including the resource conditions and the selection of the working fluid. These plants are usually used with lower temperature resources because, relative to the flash-steam power cycles, the binary cycle can produce more power from a given quantity of geothermal fluid. Cycles can be designed to maximize the conversion of the geothermal energy to power. In simple cycles, the working fluid is boiled at a single pressure. One method of improving performance is to boil at multiple pressures (the working-fluid flow stream is split into high- and low-pressure stream paths). Another proposed technique is the heating and vaporization of the working fluid above the fluid ’

s critical pressure. Both of these design strategies attempt to match the working fluid heat addition process to the sensible cooling of the geothermal fluid (as depicted on a plot of temperature vs. total heat transferred). While the supercritical cycle has a higher associated component and pumping costs because of the higher operating pressures, these cycles have fewer components and are less complex than the multiple boiling cycles. They also are more efficient in converting the geothermal energy into electrical power.

Conversion efficiency is maximized by minimizing the temperature differences during the heat-addition and heat-rejection processes. The conversion systems that more efficiently convert the geothermal energy to electrical power also tend to be more equipment intensive, especially with regard to heat-transfer areas. If there is a significant cost associated with the production of the geothermal fluid (resource exploration, drilling, surface piping, etc.), these costs will offset the additional energy-conversion-system cost and the more efficient plants will produce power at lower cost.

Studies have shown that power cycles using working fluids of mixed hydrocarbons have superior performance (in terms of power produced from a unit quantity of geothermal fluid) to those having single-component working fluids. Mixtures have an advantage because their isobaric phase changes (boiling and condensation) are nonisothermal. This allows the vaporization of the mixture to more closely match the sensible cooling of the geothermal fluid. Perhaps more importantly (in terms of reducing cycle irreversibility), this characteristic allows the desuperheating and condensing of the working fluid to more closely approach the sensible heating profile of the cooling fluid (water or air).

A binary cycle is being commercially developed that uses an ammonia-water mixture as the working fluid instead of a hydrocarbon. In this cycle, a great amount of recuperative preheating of the working fluid is accomplished with the superheat in the turbine exhaust. Though the cycle has a more complex heat-exchanger train than indicated by the flow schematic in Fig. 9.16, it is more efficient in converting the geothermal energy into electrical power. The systems using this cycle are called Kalina Cycle^® systems.

Nomenclature

Acknowledgments

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References