ARTICLE | doi:10.20944/preprints202110.0179.v1
Subject: Engineering, Energy & Fuel Technology Keywords: Well placement; CO2-EGS; water-EGS; Discrete fracture networks; THM modeling
Online: 12 October 2021 (12:40:20 CEST)
Well placement optimization in a given geological setting for a fractured geothermal reservoir is a prerequisite for enhanced geothermal operations. High computational cost associated in the framework of fully coupled thermo-hydraulic-mechanical (THM) processes in a fractured reservoir simulation, makes the well positioning as a missing point in developing a field scale investigation. Here, in this study, we shed light on this topic through examining different injection-production well (doublet) position in a given real fracture network. Water and CO2 are used as working fluids for geothermal operations and importance of well positions are examined using coupled THM numerical simulations for both the fluids. Results of this study are examined through the thermal breakthrough time, mass flux and the energy extraction potential to assess the impact of well position in a two-dimensional reservoir framework. Almost ten times of the difference between the final amount of heat extraction is observed for different well position but with the same well spacing and geological characteristics. Furthermore, stress field is be a strong function of well position that is important with respect to the possibility of unwanted stress development. As part of the MEET project, this study recommends to perform similar well placement optimization study for each fracture set in a fully coupled THM manner before a field well drilling.
ARTICLE | doi:10.20944/preprints202110.0169.v1
Subject: Engineering, Energy & Fuel Technology Keywords: Soultz-sous-Forêts; EGS; Hydro-thermal modeling; Wellbore coupling
Online: 11 October 2021 (15:22:10 CEST)
The deep geothermal industrial project at Soultz-sous-Forêts is located in the Upper Rhine Graben, France. As part of the MEET project, this study aims to evaluate the possibility of extracting higher amounts of energy from the existing industrial infrastructure. To achieve this objective, the effect of reinjecting fluid at lower temperature than the current fluid injection temperature of 70 ℃ was modelled and the drop in the production wellhead temperature for 100 years of operation was quantified. Two injection-production rate scenarios were considered and compared for their effect on overall production wellhead temperature. For each scenario, reinjection temperatures of 40 ℃, 50 ℃ and 60 ℃ were chosen and compared with the 70 ℃ injection case. For the lower production rate scenario, the results show that the production wellhead temperature is approximately 1-1.5 ℃ higher than for the higher production rate scenario after 100 years of operation. In conclusion, no significant thermal breakthrough has been observed with the applied flow rates and lowered injection temperatures even after 100 years of operation.
ARTICLE | doi:10.20944/preprints201709.0079.v1
Subject: Earth Sciences, Geophysics Keywords: EGS; crustal permeability; finite element flow modelling; crustal wellbore temperatures; wellbore injection; well logs; well core
Online: 18 September 2017 (12:01:16 CEST)
We use Matlab 3D finite element fluid flow/transport modelling to simulate localized wellbore temperature events of order 0.05-0.1oC logged in Fennoscandia basement rock at ~ 1.5km depths. The temperature events are approximated as steady-state heat transport due to fluid draining from the crust into the wellbore via naturally occurring fracture-connectivity structures. Flow simulation is based on the empirics of spatially-correlated fracture-connectivity fluid flow widely attested by well-log, well-core, and well-production data. Matching model wellbore-centric radial temperature profiles to a 2D analytic expression for steady-state radial heat transport with Peclet number Pe ≡ r0φv0/D (r0 = wellbore radius, v0 = Darcy velocity at r0, φ = ambient porosity, D = rock-water thermal diffusivity), gives Pe ~ 10-15 for fracture-connectivity flow intersecting the well, and Pe ~ 0 for ambient crust. Darcy flow for model Pe ~ 10 at radius ~ 10 meters from the wellbore gives permeability estimate κ ~ 0.02Darcy for flow driven by differential fluid pressure between least principal crustal stress pore pressure and hydrostatic wellbore pressure. Model temperature event flow permeability κm ~ 0.02Darcy is related to well-core ambient permeability κ ~ 1µDarcy by empirical poroperm relation κm ~ κ exp(αmφ) for φ ~ 0.01 and αm ~ 1000. Our modelling of wellbore temperature events calibrates the concept of reactivating fossilized fracture-connectivity flow for EGS permeability stimulation of basement rock.