In natural settings, such as the ocean bottom, when buried organic matter decomposes to methane and dissolves in water, clathrates form at temperatures greater than 277 K (4 C or 39 F). Biogenically produced methane in dissolved water forms hydrates very slowly, because of mass-transfer limitations. Over geologic time, the total enclathrated methane in the oceans has been estimated at 2.1 1016 standard cubic meters (SCM)--twice the energy total of all other fossil fuels on Earth. The amount of hydrated methane in the northern latitude permafrost is relatively small (7.4 1014 SCM), within the error margin of ocean hydrate estimates. Figure 1 shows world hydrate deposits in the deep ocean and permafrost, most of which were determined by indirect evidence such as seismic reflections called bottom simulating reflectors (BSRs).
Hydrates are a possibility in oil/gas exploration, production, transportation, or processing, which involves water and molecules smaller than n-pentane. When small ( 9 Å) nonpolar molecules contact water at ambient temperatures (typically 100 F) and moderate pressures (typically 180 psia), a water crystal form may appear--a clathrate hydrate. These individual polyhedra then combine to form specific crystalline lattices. Such solids can be formed with N2, H2S, CO2, C1, C2, C3, and iso-butane. Larger molecules like n-butane and cyclopentane require the presence of some smaller molecules.
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. Polycrystalline diamond compact (PDC) bits have the dual advantages of more efficient rock cutting and no moving parts, but experience with PDC bits in geothermal drilling is both scant and unfavorable. 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.
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.
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.
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. Polycrystalline diamond compact (PDC) bits have the dual advantages of more efficient rock cutting and no moving parts, but experience with PDC bits in geothermal drilling is both scant and unfavorable. 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.
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). 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.