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Subsurface System Design Issues and Approaches Project site Percentage of Hydraulic fracturing costs, $ fracture in granite @ 93 kg/s @ 180 kg/s Winnie, TX 0% 145,000 171,000 Nampa, ID 39% 260,000 356,000 Sisters, OR 83% 348,000 450,000 Poplar, MT 0% 152,000 179,000 Kelseyville, CA 56% 450,000 491,000 Conway, NH 100% 502,000 580,000 Chapter 5 The effective rock mechanical properties (elastic moduli and Poisson’s ratios), and fluid efficiency parameters for the designs, were based on relative percentages of granite to nongranite formation penetrated by the fracture (shear fracture cluster). 517 Cost estimates were based on the assumption that commercial fracturing service companies would perform the hydraulicfracture stimulation. Portions (some significant) of the above costs depend on: (i) equipment mileage from the nearest pumping service company office to the site, and (ii) service company onsite personnel time charges. For these cases, the results from two hydraulicfracturing models, Perkins Kern Nordgren (PKN) and Geertsama de Klerk (GDK), were used for volume, pumping power, and pumping time requirements. The PKN and GDK models yield close, but not exact, results for these. Because no direct link between cost and any property of the reservoir could be found, an average of the results from each was used in the analysis. All cases were for a vertically oriented fracture (or shear fracture cluster), penetrating radially outward and downward as well as up, (centered at the casing shoe), with a fracture radius of 900 m to provide 5x106 m2 of fracture face exposure. The in situ stresses in the fracture regions were based on a stress gradient of 0.136 MPa/m. The injection fracturing pipe string was consistent with the drillingcasing programs for the site for calculating surface injection power requirements. Table 5.2 Cost estimates for wells at example sites, for two average injection rates. The costs for all project wells include tailing (placing) in relatively small, but sufficient, proppant quantities to mitigate highpressure drop (skin) effects in the near wellbore vicinity. Table 5.2 shows the estimated cost for two average injection rates. Detailed step rate injection histories were not used for this analysis. It was assumed that each well would need two fracture treatments. Experience would determine whether this is the best strategy or whether one longer fracture treatment would be more effective, so that in out years, the cost might be cut in half. These costs can be lowered further for later stimulations – once the project is determined to be feasible – by using purchased pumps that would be used for longterm site operations. For largescale projects, there would be onsite fracturing pumps, designed for longterm operation, to stimulate new reservoirs without a service company. This represents a cost benefit in developing a large volume of relatively uniform rock.PDF Image | Subsurface System Design Issues EGS vs. Hydrothermal Pool
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