| Abstract |
This paper discusses a method for characterizing fracture paths in geothermal reservoirs using conductive fluid injection and electrical resistivity measurements. Electrical resistivity distribution of a reservoir can be determined by measuring potential differences between various points, either on the surface or inside wells, while passing an electric current through the ground. The apparent resistivity between these points decreases as conductive fluid fills up fracture paths from the injector to the producer. Therefore, the time history of the electric potential (which corresponds to the apparent resistivity) is dependent on the flow paths of the conductive fluid, i.e. the fracture network, and as a result can be used to estimate fracture characteristics. In this study, the flow simulator TOUGH2 was first used to simulate the flow of a conductive tracer through a reservoir, and then applied to solve the electric fields by utilizing the analogy between Ohm’s law that describes electrical flow and Darcy’s law that describes fluid flow. A discrete fracture network was modeled and the relationship between the electric potential difference and the fracture network was studied. The fracture network was also modeled as an electric circuit and the voltage drop between an injector and a producer was calculated to verify the electric potential solved using TOUGH2. Another fracture network with one injector and three producers was analyzed as well. The apparent resistivity was mapped by kriging to illustrate the changes in resistivity with time when injecting a constant concentration solution of NaCl and into reinjection wells, resulting in increasing NaCl concentration due to steam separation. The results from this study showed promising possibilities for characterizing fractures using electric measurements with a conductive fluid injection. |