We present a well-reservoir modeling study aimed at better understanding one of the hottest geothermal well ever drilled, the IDDP-2 well in Reykjanes. To obtain realistic models of the well and reservoir we follow three main steps. First, we simulate the evolution of the reservoir following the emplacement of a magmatic intrusion thousands of years ago to obtain the most likely natural state of the geothermal system. The simulations show that the reservoir permeability structure largely controls its thermal evolution. Model validation is done by refining the permeability structure and other secondary parameters until the simulation results match the currently measured reservoir temperatures along the well. An important constraint is the reservoir temperature of about 550 °C at 4500 m depth, consistent with previous estimates from geophysical inversions and fluid inclusions obtained in core samples from the deepest part of the well. Second, we constrain the location and permeability of the feed zones by simulating and matching the results from a cold-water injectivity test. Third, we simulate the extensive cold-water injection phase that occurred in the 2017–2018 period. The obtained reservoir state is used as an initial condition for the simulation of well operations. With H2O-NaCl as a proxy to the reservoir's fluid composition, our simulation shows that in the deepest part of the well (from 4200 to 4500 m), the fluid naturally present in the reservoir would be in the vapor + halite thermodynamic field implying that halite scaling upon production could rapidly clog the well. Three different scenarios were investigated: (1) a scenario that mimics the actual history of the well and simulates how flow evolves over 12 years following the cold-water injection phase, to better understand the current thermo-hydraulic state of the well and predict its behavior in the upcoming years; (2) a hypothetical scenario of how the well would have evolved without the preceding, long-term cold-water injection phase that, according to the results of scenario (1) delayed significant production; and (3) a second hypothetical scenario with cold-water injection and modified feed zone permeabilities (enhanced permeability at 4400 m and reduced at 3400 m) to assess if reservoir engineering measures could enhance energy production by favoring inflow from the superhot part of the reservoir. For the first scenario, resembling the actual evolution of the well, we find that by 2018 the formation had cooled significantly in all feed zones due to the extensive cold-water injection. A consequence is that the well flow rate is initially very small (less than 2 kg.s−1) and only slowly rises to its maximum (about 50 kg.s−1) after more than 6 years, which is the time it takes for the formation to recover its initial temperature. This is in good agreement with early flow observations and a well flow test conducted in 2022 that shows a gradual increase in flow rate. The results of the second scenario, which simulates the case where cold-water injection did not occur, are similar to the first one, the only difference being that the reservoir does not need to warm up and that the well achieves its maximum production potential without delay. The third scenario, which considers the case of enhanced permeability of the deepest feed zone and reduced permeability of the intermediate feed zone results in a worse outcome in terms of energy production because of halite scaling and well blockage occurring at the deepest feed zone. These results show that advanced well-reservoir modeling is an essential tool to devise geothermal reservoir production strategies for superhot resources, namely in the case of saline systems.