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Review of EGS and Related Technology – Status and Achievements Chapter 4 415 For Phase 2A of the project, two wells were planned with a total vertical depth (TVD) of about 2,000 m, where the temperature was expected to be around 8090°C – both were deviated in the same plane to an angle of 30 degrees from the vertical in the lower sections, and separated by 300 m vertically. In 1980, the drilling of RH11 (production) and RH12 (injection) began, and took only 116 days. Bottomhole temperatures recorded at RH12 reached 79°C. Stimulation of RH12 (the lower well) then followed, initially with explosives, and then hydraulically at rates up to 100 kg/s and wellhead pressures of 14 MPa. Due to the mainly vertical nature of jointing in the granite, conventional wisdom was that hydraulic fracturing (tensile fracturing; pennyshaped crack) would cause the reservoir to grow vertically upward, especially around 2,000 m, where the minimum principal stress was horizontal. However, microseismic monitoring showed that the majority of fracturing and the reservoir grew by shearing mode and not tensile fracturing; and reservoir growth occurred primarily in a vertically downward direction, opposite the predicted direction (Batchelor et al., 1983; Pine and Batchelor 1984; Baria et al., 1989). The predominant downward growth of the reservoir continued through the subsequent nine months of circulation, and testing of the completed system showed it was not suitable for the purpose of modeling a fullscale commercial HDR reservoir. Phase 2B began in 1983 and entailed the drilling of a third well, RH15 (see Figure 4.6), which would be drilled below the existing wells, to access the large reservoir already created in Phase 2A. The well was drilled to a TVD of 2,600 m and bottomhole temperatures around 100°C were recorded. Hydraulic stimulation of the well was carried out similar to RH12, and circulation began in 1985 (see Figure 4.7), with RH12 continuing to be the injection well and RH15 the primary producer. A series of flow tests was then carried out through September 1986, with rates gradually stepping up. The reservoir was then circulated continuously at various flow rates (typically around 2025 kg/s) for the next four years. Temperature drawdown over the period of the longterm flow test caused a downhole temperature drop from 80.5°C to 70.5°C. Injection rates through the testing phase varied from 5 to 24 kg/s. In the 5 kg/s case, the return from the production well was 4 kg/s and the wellhead pressure was 40 bar. In the 24 kg/s case, the return from the production well was 15 kg/s and the wellhead pressure 10.5 MPa. Flowpath analysis based on spinner, temperature, and other well log data showed that a preferential pathway – or short circuit – developed, which allowed cool injected water to return too rapidly to the production well (Batchelor, 1986). The experimental work at Rosemanowes Quarry was continued in Phase 3A (which involved no further drilling) with further circulation and other tests. In the downhole pump test in Phase 2C, lowering the pressure in the production well seemed to close the joint apertures close to the borehole and increase the impedance. An experiment in Phase 3A to place a proppant material in the joints near the production borehole was designed to demonstrate that this might solve the problem in a deep system. The sand used as proppant was carried into the joints as part of a secondary stimulation using a high viscosity (700 centipoise) gel. This stimulation significantly reduced the water losses and impedance, but it also worsened the short circuiting and lowered the flow temperature in the production borehole even further. It was concluded that the proppant technique would need to be used with caution in any attempt to manipulate HDR systems.PDF Image | Review of EGS and Related Technology
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