Analysis of Wells with Multistage Fractures (2024-2028)

Investigator: Kongphop Wongpattananukul

To characterize a fracture network deep underground, an inverse modeling approach is needed. By analyzing the system response such as pressure and temperature changes with time due to fluid production and/or injection, the system properties can be inferred such as matrix permeability, fracture permeability, fracture geometry, and fracture conductivity. However, fast and reliable analytical or semianalytical solutions for both pressure and temperature are required and these are the main focuses in this study.

In enhanced geothermal systems, a hydraulically connected system through fractures is required. The main goal for enhanced geothermal systems is to maximize heat extraction using fluid circulation between wells. Each fracture connection creates a fluid pathway between injector and producer with large surface area for fluid to contact with a large volume of hot rock.

The system response from this configuration during an injection test is the radial flow inside the fractures (depends on fracture permeability and fracture aperture), the bilinear flow (depends on fracture conductivity), the linear flow (depends on fracture size), and the radial flow inside the rock matrix (depends on rock matrix permeability and rock matrix thickness). For a circulation test or crossflow test where both injector and producer operate simultaneously, the late-time behavior approaches a constant pressure boundary condition instead. Hence, interpretation with multiple wells is required to infer late-time system properties.

In 2024, a 1-month circulation test was conducted in the Utah FORGE geothermal project. To an approximate degree, the well control was a constant rate for injection and constant pressure for production. Therefore, a mixed-boundary condition, multistage fracture well model was derived and employed to estimate fracture properties by fitting pressure and rate measurement.