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state operating conditions, and laid the groundwork for the development of strategies to increase the productivity of future HDR reservoirs The Current HDR Reservoir. Taken together, the hydraulic fracturing operations employed to create and enlarge the Phase I HDR reservoir involved the injection of about 2000 m3 of water. The rapid cooldown of that reservoir indicated the need to create a much larger and hotter HDR reservoir in order to produce energy at the high rates and temperatures required for commercial power production. For this reason, plans were developed for a Phase II HDR reservoir which would be larger, deeper, and hotter. These plans were based on generalizations about the formation of HDR reservoirs, some of which later proved to be incorrect. The results of work with the Phase I reservoir led to the assumption that hydraulic fracturing typically resulted in the formation of thin, vertical fractures in the intact rock, and that the size and heat production capability of an HDR system could be manipulated by employing a number of fracturing operations in isolated sections of a single wellbore to induce multiple, independent vertical fractures of this type. Until these preconceived notions were cast aside, extreme difficulties were encountered in the creation of a viable Phase II HDR system In 1980, under the auspices of the International Energy Agency, Japan and Germany joined the US HDR project. Both countries contributed funding and personnel to the project for the next five years, and the Japanese continued to be a part of the program for one additional year. Development of the Phase II system by this international group took place at the Fenton Hill Site within a few hundred ft of the Phase I wellbores. Work proceeded under the assumption that hydraulic fracturing would lead to vertical fractures as discussed above. Therefore, two wells were drilled before any fracturing was attempted. The deeper well was drilled to a vertical depth of 4390 m with the bottom 1000 m directionally drilled at an angle of 35° to the vertical. The temperature of the rock at the final depth was 327°C. The second well was drilled in a similar manner to the first, but with the inclined section located 380 m vertically above the lower wellbore. The intent was to position the wellbores so that a number of individual vertical fractures, far enough apart to be thermally isolated from one another, could be created to connect the two wellbores. A number of fracturing operations were conducted between 1982 and 1984. During the largest of these in December 1983, over 21 000 m3 of water (more than 10 times what was injected during all the experimental work with the Phase I system) was injected into an isolated zone of the lower wellbore located at a depth of 3520 - 3540 m. The pumping was carried out over a period of 2-1/2 days at injection pressures averaging 48 MPa. Neither this operation, nor any of the other hydraulic fracturing experiments resulted in a flow connection between the two wellbores. Furthermore, microseismic data indicated that the reservoir was developing approximately along the trajectory of the inclined portion of the lower wellbore in such a way that a connection between the two wellbores would never be established. It was then decided to sidetrack and redrill the upper wellbore with the goal of penetrating the reservoir volume indicated by the microseismic data. Sidetracking was initiated at a depth of 2830 m. Drilling continued to a final depth of 4018 m where a bottomhole rock temperature of 265°C was measured. The sidetracked well penetrated the reservoir and intersected a number of joints that had been opened during the large (21 000 m3 hydraulic fracturing operation described above. A small amount of additional stimulation produced good flow connections between the two wellbores. A cross-section view of the underground portion of the Phase II HDR system is shown in Figure 2. 4PDF Image | Hot Dry Rock Geothermal Energy Development in the USA
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