## 1 Introduction
Decommissioned or disused oil and gas wells, especially those in mature oilfields, represent good candidates for geothermal heat exploitation, providing access to deep subsurface energy resources. Existing wellbores, surface facilities and infrastructures and available geological and geophysical data can enhance potential geothermal projects in oilfields by reducing capital costs and minimising risk and inconvenience [10; 11]. Over time, energy companies and researchers have begun to put greater effort into developing various strategies for harnessing this type of deep geothermal energy resource. The majority of studies that have been carried out on existing abandoned petroleum wells have focused on open-loop systems designed to repurpose petroleum fields as geothermal reservoirs [12; 13]. Although geothermal open-loop systems in sedimentary formations may provide a sustainable solution where the geothermal potential and heat demand coincide [14; 15], these technologies are subject to some technical problems, including groundwater recession, corrosion and scaling. Further important issues are represented by the reinjection of fluids [16; 17] and by the complex additional exploration activities [18]. An effective and optimally dimensionalized alternative for relatively low energy demand is represented by the use of closed-loop deep geothermal systems. Unlike conventional open-loop geothermal systems, heat carrier fluids in closed-loop systems circulate inside of a wellbore heat exchanger (WBHE), while no ground fluids are extracted from the surrounding rocks. Moreover, corrosion and scaling problems are limited. Due to their proven advantages, a large number of studies that deal with developing closed-loop system technologies have been carried out [19; 20]. Despite the recent success of some theoretical oilfield geothermal closed-loop system experiments, several challenges remain related to harnessing geothermal resources at a larger scale in oilfields using closed-loop type technologies, including low levels of thermal energy recovery and low energy conversion efficiency [21]. Moreover, researchers have indeed primarily focused their attention on analysing the impacts on the energy performance of changes in working fluid-related parameters, such as initial temperature and injection flow rate values. In the elaborations reported in [22; 23; 24], the authors fixed the values of different thermophysical parameters (thermal conductivity, volumetric heat capacity and rock density) as weighted mean values. However, due to the continuous spatial and vertical variability of geological formations associated with deep wells in oilfields, the thermophysical parameters of geological strata, as well as the depth of the strata and their thickness, need to be properly considered in order to achieve increasingly accurate and realistic estimates of heat exchanger performance. Given the above considerations, the proposed study aims primarily at contributing to the discussion by encouraging reflection on the potential benefits of using low-temperature to medium-temperature geothermal energy resources associated with dismissed Italian hydrocarbon wells. Using the information about Italian hydrocarbon wells and on-field temperatures available from both the National Mining Office of the Italian Ministry for Economic Development (MISE) and the Italian National Geothermal Database, the attention is focused on two different geothermal closed-loop-type technologies: U-tube and coaxial wellbore heat exchangers (WBHEs). Two different simplified heat exchange models (Coaxial and U-tube WBHE) and thermal resistance systems, described in references [24; 25], respectively, were implemented in the Python environment and applied to a selected hydrocarbon well (Trecate4) located inside the Italian Villafortuna-Trecate field (Northwestern Italy).