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Chapter 5 Subsurface System Design Issues and Approaches 514 4. Conduct stepped flowrate injections until the pressure for each injection step becomes steady. The maximum injection pressure should exceed the minimum formation stress at the point of injection. 5. Maintain high flowrate injection until the seismicity migrates to the distance necessary for targeting the second well. 6. Depending on the relationship of the in situ stress and the density of in situ fluid, it may be possible to influence the vertical direction of reservoir growth by selecting an appropriate density of the stimulation fluid. 7. Perform a shutin test to assess the size of the reservoir. 8. Carry out flow logs in the injection well to identify the main flowing zones. 9. Let the reservoir deflate and then make injection tests at lower flow rates to assess the permanent residual enhancement of permeability i.e., flow against injection pressure. 5.11.1 Geologiccasestudies To demonstrate how this process might work in specific areas, and how costs might vary for different geologic conditions, some specific geologic cases were chosen (Table 5.1). These sites cover a wide geographical area and represent a diverse set of geological characteristics that are appropriate for a nationwide deployment of EGS technology. i. Winnie, Texas A deep, overpressured sedimentary basin with moderate geothermal gradient on the Gulf of Mexico. The area is actively producing oil and gas from both shallow and deep depths. The target 10. Target the second well (production) into the periphery of the seismically activated structure, with the separation of the wells appropriate to suit economic targets. At the same time, ensure that the well has a downhole pumping chamber incorporated in its completion plan. 11. Stimulate the second well in a stepped manner as described above to improve access to the previous stimulated zone and eventually permit the recovery of the mobile in situ fluid (carry out diagnostic technique as in steps 3 and 8). 12. Conduct shortcirculation tests to assess the connectivity between the injector and the producer. 13. Perform tracer tests to evaluate reservoir flowthrough volume, to characterize the residence time distribution, and to identify any shortcircuit paths. 14. Repeat steps 10 to 14 for the third well, i.e., the second production well, and for a fourth and even fifth, if the system warrants this. This process can then be repeated to create a large enough system to support a commercial power generation or heat and power installation. Although the steps described above are very rudimentary and perhaps oversimplify the overall approach, the general trend remains and the procedure fits with our understanding of the reservoir creation process. Each area or region will have its own specific properties and these will have to be taken into account in the general reservoir stimulation concept described. Channeling or short circuiting of circulation fluids has been a nemesis in conductive heat transfer efforts. The feasibility of altering injection/producing patterns may be worth further investigation.PDF Image | Subsurface System Design Issues EGS vs. Hydrothermal Pool
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