Recovery of heat from underground resources is currently commercially practiced in one of three main technological areas, i.e., power plants using dry steam, flash steam, and binary systems. Factors controlling selection of one of these technologies for a selected site include temperature, depth, and quality of the water and steam in the area. In all these cases, condensed steam and/or geothermal fluid is injected back into the ground to recover heat. In some locations, a natural supply of water produces steam from magma deposits is exhausted and processed waste water may be injected to replenish the supply.
A disadvantage with current, installed technology for geothermal heat recovery in that many geothermal are operated with excessive injection of fluids to recover the heat and thereby cool the resource. Conservative management to avoid such a result results in a failure to recover substantial heat resources. Current, installed technologies suffer a further disadvantage, in that injection of fluids, both liquid and gas, into the geological formation necessarily disrupts to a greater or lesser degree the structure of the formation. The disruption can result in surface subsidence and/or a severe re-structuring of the formation in a manner that impairs the heat resource.
Therefore, current, installed technologies substantially endanger the heat resource they attempt to recover. Notwithstanding their disadvantages, a brief description is made of the three geothermal heat recovery listed above. A dry steam power plant uses an underground resource where dry steam, without entrained water droplets, is obtained and delivered at above 235° C. (455° F.) to a surface steam turbine to produce electricity. In contrast, a flash steam power plant delivers to surface process equipment hot liquid water above 182° C. (360° F.). Liquid water is flashed into a vessel, where flashed steam is delivered to a steam turbine to produce electricity. Binary-cycle power plants recover liquid water at from 107 to 182° C. (225-360° F.) at a surface facility to indirectly transfer heat in heat exchangers to iso-butane or iso-pentane, which are vaporized and power a turbine.
A fourth technology has not been extensively practiced, in that the depth at which geothermal heat is recovered exceeds those of the above technologies. Hot dry rock systems (1) locate terminal end heat exchanger in a geological formation connected with a closed loop with a heat recovery liquid or (2) inject liquid water into the formation and recover steam in the same or different conduits. A hot dry rock system has many advantages over the others, as it can be used anywhere, not just in tectonically active regions with sufficient water present in the formation.
Of the above technologies for recovering heat from a geological formation, only one will not potentially adversely affect land stability in the surrounding region and/or cause damage to the geological formation. The closed loop, hot dry rock system is the only technology which does not continuously inject liquids into the formation, liquids which explosively expand on introduction into the formation. Such continuous and violent expansion of gases in the vicinity of injection conduits can result in damage to natural flow paths of gases within the formation, potentially closing off wells drilled to recover the vaporized liquids. The use of a closed loop, hot dry rock system necessarily results in a longer-lived and more easily managed heat resource than the other technologies described above.
Thus, there is a need for a closed loop, hot dry rock system which is economically competitive with other technologies and which obtains the substantial benefits of geothermal heat recovery without injection of liquid or gases into the geological formation containing the heat resource. Geothermal formations can provide heat for many decades but using injection-dependent heat recovery technologies can eventually cause a geological formation to cool down to temperatures below which energy production is no longer feasible. This may mean that a specific geothermal location can undergo depletion. Predictive calculations for depletion of heat from a specific location are not presently absolutely accurate, meaning that recovery of investment using injection technologies is necessarily more risky that using a more controllable and predictable closed loop, hot dry rock system.
A key characteristic of a hot dry rock system is that it may often require drilling to at least 10 km. Current drilling technology has improved so that reaching this depth is now routine for the oil industry. Exxon has produced an 11 km production well at the Chayvo field in Sakhalin, Russia.
Some geothermal power plant capital costs are generally constant regardless of the technology and include the cost of land and physical plant, including buildings and power-generating turbines. Resistance to installation of closed loop, hot dry rock systems has been based primarily on an installed cost of prior art devices and equipment to reach deeper geological formations. A closed loop, hot dry rock system which reduces such aspects as pipe diameters and conduit cost per unit length can dramatically affect the overall cost of the project, considering the depths which will be typically reached by the terminal end heat exchangers of the system. There is a need for such improvements. Geothermal power plant lifetimes are typically over thirty years, wherein cost recovery is planned for the first fifteen years of operation. However, those metrics in the near future will change dramatically where energy costs appear to have no upper limit and where energy usage for most of the world's population is predicted to expand to many times the current levels. Even now, there is a strain on our ability to deliver such energy. A closed loop, hot dry rock system incorporating the present invention can become the technology of choice in those circumstances.
“Model estimates demonstrate that a HDR system has to produce a thermal capacity of 10 to 100 megawatts over a period of at least 20 years to be economical. Such size of a system requires heat exchange surfaces of 3 to 10 square kilometers and circulation rates of 50 to 100 liters per second. The critical fluid pressure for subsurface system operation is a function of the stress field at a depth which varies from site to site. For a HDR reservoir of a depth of 5 kilometers, the minimum pumping pressure required is about 40 megapascals. In addition, economics limit the operation pressure. Today it is estimated that the flow impedance in a HDR system (the difference between inlet and outlet pressure divided by the flow rate at the outlet) should be in the range of 0.1 megapascal-seconds per liter (MPa s/L).” (DEVELOPMENT OF HOT DRY ROCK TECHNOLOGY; Tenzer, Helmut; GHC BULLETIN, DECEMBER 2001; pp. 14-22). In U.S. Pat. No. 4,044,830, a model of a radial system of horizontal bores are made to accommodate a number of terminal end heat exchangers for a hot dry rock geothermal recovery system. A specific example describes 15 megawatt production by way of surface level steam at 320 psia and 423 degrees F., returning liquid water at 125 degrees F. The disclosure of the '830 patent is incorporated herein. U.S. Pat. No. 6,679,326 discloses an open loop system of water injection and recovery for steam generation.
The above two examples of hot dry rock geothermal systems are among many describing the prior art challenges to providing a cost-efficient and compact installation. There is a need for such an installation.