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c. Maximum iniection pressure EPA Region 9, has determined that the maximum allowed injection pressure at the well head will be 810 psig. This determination was made in accordance with the provisions of 40 CFR 146.13(a). EPA regulations require that injection pressure be limited so as to prevent fracturing of the injection and confining zones throughout the operating life of the project. This maximum pressure is based on the fracture gradient of 0.733 psi/ft pursuant to 40 CFR 147.253. Maximum surface injection pressure is related to the fracture gradient through the following equation: Ps = [F.G. - .433(s.g.)](depth) where: F.G. is the fracture gradient for the injection formation interval at the location of the well; s.g. is the specific gravity of the injection fluid; and depth is the depth in feet to the top perforation. For the injection well, the following calculation gives the maximum allowed surface injection pressure. Ps = [0.733 - .433(1.00)](2700) = 810 psi Additionally, injection between the outermost casing protecting underground sources of drinking water and the well bore is prohibited. The maximum injection rate shall be limited to 195 gallons per minute (gpm) for the injection well. The draft permit requires that the annular space between the tubing and the casing be filled with fresh water containing bacteria and corrosion inhibitors or similar nonhazardous corrosion inhibiting fluid. The annular pressure will be limited by the permit to a minimum operating value of 100 psig for leak detection. The permittee is required to continuously monitor the fluid level in the an- nular space. A total annular fluid volume change exceeding two gallons at Standard Temperature and Pressure (STP) would constitute a significant leak. The permittee is also required to notify EPA when the total annular fluid volume varies from the above range. Maintaining a positive annular pressure will allow for continuous mechanical integrity monitoring of the casing, tubing, and packer. The draft permit specifies that EPA, Region 9, be notified within 24 hours of the noncompliance. This notification of noncompliance must be followed by written notice within five days. Well repair and mechanical integrity testing is required if the problem is found to be within the well. The annular fluid volume range and minimum annular pressure must be maintained unless a demonstration for suitable alternate values are submitted by the permittee and have been approved, in writing, by the Director. 7