Estimating the Inflow Distribution in Geothermal Wells During Fluid Circulation Using Distributed Fiber Optic Measurements
Authors: Ou Yuhao , Sharma Mukul M. 
Published: January 2025

The inflow of fluids into a geothermal well is crucial for its capacity to produce thermal energy. Limited inflow can hinder thermal energy recovery, making it essential to identify inflow locations and measure the rate of fluid exiting injection wells and entering production wells. This paper estimates the production profile along a well intersected by numerous fractures by measuring and simulating transient thermal slugging during fluid circulation.

Fiber optic data obtained from the FORGE site provides clear evidence of thermal slugging. This data can be interpreted to reveal the flow profile along the geothermal production well. Hydro-thermal connectivity between enhanced geothermal well pairs is established through the stimulation of both the injector and producer wells. A non-isothermal fracture-reservoir-wellbore model simulates early transient fluid circulation in enhanced geothermal systems (EGS), accounting for temperature effects from prior wellbore treatments. Temperature changes in the cemented fiber are calculated, considering heat transfer between wellbore fluids and the reservoir. The fiber measurements are visualized by plotting the temperature change rate within the wellbore over space and time. By integrating transient modeling results with EGS fiber optic data, we demonstrate that the gradient of the thermal slugging signals in the fiber optic waterfall plot can estimate wellbore fluid velocity and infer inflow rates at various wellbore locations, as well as the difference in the conductivities among producing fractures.

We present results on reservoir cooling during fracturing, which propagates into the formation under the combined effects of fluid leak-off, convection, and thermal conduction during warm back. This cooling impacts the measured wellbore temperature profile during fluid circulation. Successive warm-cool regions are observed in the wellbore temperature field at the end of EGS circulation, with each cool region indicating fluid inflow from a fracture. During fluid production, thermal slugs are detected in the wellbore as measured by the cemented fiber. The simulation data is used to estimate fluid velocity along the wellbore, revealing that the fluid velocity inferred from the gradient of thermal slugging signals is proportional to production from different sections of the producer (fracture clusters).

Fiber optic distributed measurements provide direct observations of real-time wellbore flow rates with high spatial resolution. The results presented in this paper demonstrate, for the first time, that integrated modeling of the producer treatment process, shut-in, and fluid circulation—using a fully coupled thermo-flow model—can quantitatively estimate the production profile in a wellbore. This integrated simulation algorithm encompasses the entire fracture-reservoir-wellbore system, capturing the transient thermal behavior during EGS circulation. This approach allows for accurate calculation of the wellbore temperature profile throughout the injection, shut-in, and flowback lifecycle.