The drilling conditions described above have led to the following practices, which are reasonably uniform, in the geothermal drilling industry. Bits Because of the hard, fractured formations, roller-cone bits with tungsten-carbide inserts are almost universally used for geothermal drilling. The abrasive rocks mean that bit life is usually low (50 to 100 m), but many bits are also pulled because of bearing failures caused by rough drilling and high temperature. Much research and development in hard-rock PDC bits is under way,  so it is possible that these bits will come into wider use in geothermal drilling. Tubulars Because of the low-value fluid (steam or hot water), geothermal wells must produce large fluid volumes and so tend to be larger diameter than oil/gas wells; typical geothermal production intervals are 219 to 340 mm in diameter.
Tracers are used in geothermal reservoir engineering to determine the connectivity between injection and production wells. Because injected fluids are much cooler than in-situ fluids, knowledge of injectate flow paths helps mitigate premature thermal breakthrough. As in other applications of tracer testing, the goal of the tracer test is to estimate sweep efficiency of a given injection pattern. Because geothermal systems tend to be open, tracer tests can also be used to estimate the extent of recharge/discharge or total pore volume. Currently, however, the primary use of geothermal tracers is to estimate the degree of connectivity between injectors and producers.
Measurements of mass flow and the constituents of the mass produced are integral in the production of geothermal fluids. From regulatory and royalty payment issues to monitoring the condition of the resource and abatement of corrosive constituents in the geothermal fluid, physical and chemical measurements are a necessity for geothermal production and utilization. Depending on the phase being produced, the operator has a choice of many instruments for measuring flow. Conventional methods are typically used to measure flow for single-phase systems. The choice of flow element and meter initially depends on the mass and/or volumetric flow rate, turn-down ratio (range of flow to be measured), the pressure, temperature, and extent of flow surging.
The drilling conditions described above have led to the following practices, which are reasonably uniform, in the geothermal drilling industry. Because of the hard, fractured formations, roller-cone bits with tungsten-carbide inserts are almost universally used for geothermal drilling. The abrasive rocks mean that bit life is usually low (50 to 100 m), but many bits are also pulled because of bearing failures caused by rough drilling and high temperature.
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. 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 Figure 1). 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).
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.
Geothermal reservoirs have many complexities, many of which are not common in petroleum reservoirs. This can create challenges to developing reliable models of these reservoirs via simulation or other means. Simulation of geothermal processes involves solution of highly nonlinear, coupled equations describing mass and energy transport in complex, heterogeneous media. The first models of geothermal simulation appeared in the 1970s. However, it was not until the 1980 Code Comparison Study that numerical models for reservoir management were generally accepted.
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. 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.
The geologic setting of geothermal resources is similar to deposits of metal ores, and geothermal systems are thought to be the modern equivalent of metal ore-forming systems. Hence, exploration draws most heavily on the techniques of the mining industry. Development of the resource and its production as hot fluid uses the techniques of the oil/gas industry with modifications because of the high temperatures and the much higher flow rates needed for economic production. Exploration begins with selection of an appropriate area based on general knowledge of areas with above average heat flow. The best guides for more detailed investigation are the presence of thermal springs (the equivalent of oil seeps).