Simulations of the IDDP-2 well, Reykjanes, Iceland, and its behavior in different operation scenarios
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 emp...
| Main Authors: | , , , |
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| Format: | Article in Journal/Newspaper |
| Language: | English |
| Published: |
Elsevier
2023
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| Subjects: | |
| Online Access: | https://hdl.handle.net/20.500.11850/625931 https://doi.org/10.3929/ethz-b-000625931 |
| Summary: | 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, ... |
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