Reuse of Oil Wells in Geothermal District Heating Networks: A Sustainable Opportunity for Cities of the Future

Abstract

Climate change and the energy crisis forced industrialized countries to contain CO₂ emissions and use indigenous renewable energy sources. Geothermal energy undoubtedly has great potential, particularly thermal energy, given that 48% of the final energy consumption in the EU20 countries in 2021 was related to heating and cooling systems. The present study verifies and compares the feasibility of realizing district heating systems in two different contexts: (i) depleted hydrocarbon fields with the repurposing of existing hydrocarbon wells into geothermal wells and (ii) areas with documented geothermal resources. The two selected case studies are located, respectively, near Romentino (Northern Italy, province of Novara) and Tuscania (Central Italy, province of Viterbo). Following an assessment of the geothermal resources in the two selected case studies, specific methodological tools have been developed to evaluate the energy demand in the municipalities and determine the projects’ economics. Both case studies show positive economic indices assuming heat tariffs aligned with the values recorded in the 2020–2021 period. However, our results show how reusing hydrocarbon wells in geothermal wells constitutes an excellent opportunity to access geothermal resources, significantly reducing the necessary investment and the mining risk and strongly improving the economics of the projects.

1. Introduction

The current evidence of climate change and the energy crisis pushes industrialized countries to simultaneously contain CO₂ emissions using indigenous and renewable energy sources (RES). Among RES, geothermal energy undoubtedly has great potential, particularly thermal energy, thanks to its 24/7 operation characteristics. Moreover, it should be noted that, in 2021, 48% of the final energy consumption in the EU20 countries is related to heating and cooling systems, with approximately 77% of this share still due to fossil fuels (e.g., [1]).

In this context, this study aims to evaluate and compare different possibilities of covering, totally or in part, the energy demand required for heating residential buildings through geothermal renewable energy sources present in municipal territories. This study has verified the feasibility and pros and cons of developing district heating (DH) systems in two different contexts. The first is represented by depleted hydrocarbon fields in which the possibility of converting hydrocarbon wells into geothermal wells has been documented. In contrast, the second consists of areas with a known geothermal resource.

The quest to reuse or repurpose hydrocarbon wells has grown in recent decades. Several authors have approached this theme, and different solutions have been suggested. The first example of co-production of geothermal energy was tested in the Pleasant Bayou gas field, demonstrating the possible production of gas and hot water and electrical energy generation [2]. Since then, several evaluations have been focused on geothermal energy production from abandoned or depleted hydrocarbon fields, e.g., [3,4,5,6,7,8,9,10,11,12,13,14,15]. More recently, the interest has grown, and several examples of applications for direct use, such as district heating, have been published. For example, an interesting case study reports the possible geothermal use of abandoned wells for rural communities [16]. This case study explores the economic and technical considerations and future studies to achieve the community’s energy requirements. The integration of closed-loop technologies is also promising. A numerical study explored using deep-ground heat exchangers combined with heat pumps to supply a district heating system [17]. A successful experience has been developed over several decades in Iceland, where 89% of space heating needs are now met by geothermal energy. The long utilization case histories provide essential information [18].

Concerning geothermal district heating, the approach proposed by [19] demonstrates the feasibility and importance of simultaneously generating geothermal electricity and heat in German municipalities to achieve energy autonomy. Other studies have been conducted on the energy systems supplying heating and cooling (H and C) in academic buildings or entire campuses. In [20], the potential of Enhanced Geothermal Systems for districts H and C of the Göttingen University campus has been assessed. The EGS heat output should be at least 11 MW. Cornell University developed a project to supply heat to the campus district heating using geothermal energy [21]. The engineering evaluation verified that almost 68% of the annual thermal demand could be satisfied with a nearly 20 MW capacity plant remaining financially competitive.

In this study, two case studies representative of the two previously cited contexts were selected to demonstrate the feasibility of district heating using geothermal energy. The first case study is a municipality located in northern Italy close to the Villafortuna–Trecate depleted hydrocarbon field. In this case, the hydrocarbon wells built for oil and gas extraction will be reused, converting them into geothermal wells to produce and reinject the geothermal fluids. The second case study concerns a municipality in the northern part of the Lazio region with a well-known geothermal location. In this case, the drilling of new geothermal wells is required.

Several methodological tools were also developed, including an innovative approach to evaluating the energy needs of buildings at a granular census section scale.

The results of this study highlight that DH development is viable and profitable in both the two considered contexts and how reusing hydrocarbon wells in geothermal wells can incentivize the development of district heating systems. The last consideration regards the economic sustainability of those projects. The analysis is based on evaluating the payback time (PBT), the projects’ net present value (NPV), and the internal rate of return (IRR). The levelized cost of heat (LCOH) is also evaluated as a key performance index.

2. District Heating Systems

Continuous technological evolution and the need for innovation have seen the evolution of district heating systems reach the fourth and fifth generations [22,23]. The basic assumption is that district heating and cooling are vital in future sustainable energy systems, including 100 percent renewable energy systems. The previous assumption should be completed with the concepts of smart energy and smart thermal grids [22].

The currently consolidated technology is the so-called third generation. With these third-generation systems, the supply temperature is often below 100 °C, and pre-insulated, prefabricated pipes and compact plate heat exchangers are used. The trend over these three generations has been to reduce the temperature level, reduce the cost of piping material, and increase prefabrication. The security of supply the conventional fuel forced to replace oil/gas with various local or cheaper fuels such as biomass and waste. Moreover, solar and geothermal heat has been used only as a supplement in a few applications [22].

Following this trend, the fourth-generation technology provides solutions to fulfill its role in future sustainable energy district heating. The main challenges were the reduction in the delivery temperature to 60–55 °C to expand the possibility of integrating renewable energy sources, recovering the heat dispersed over the territory, and reducing investments in the network: with these levels of temperature, polyethylene, and polypropylene pipes can be used [24]. The technology of thermal networks that function at a temperature close to the ground can strongly contribute to the decarbonization of the heating and cooling sector and exploit many low-temperature heat sources [23]. The crucial role of geothermal plants in providing base load heat and power to achieve energy autonomy is demonstrated. The importance of simultaneous electricity and heat generation modeling in geothermal plants is also evident, as district heating plants reduce costs, especially in municipalities with high hydrothermal potential [19].

Furthermore, high-temperature district heating systems (older generations) suffer from significant heat losses and high installation costs. Especially in the summer period, when many systems generally operate only to satisfy the demand for domestic hot water, heat losses from the network can reach a value equal to approximately 30% of the energy supply due to the high water retention time in the network. This heat loss is why new generations of district heating systems, such as the fourth or fifth generation, will be adopted in the coming years, as they can achieve high efficiencies while operating at low temperatures (Figure 1).

In addition to the above, the fourth generation paves the way for the recovery and integration into the network of excess heat derived from renewable sources. However, the same pipes cannot simultaneously provide heating and cooling services to different buildings in these systems. The ability to deliver heating and cooling services represents the fifth-generation challenge. Although fifth-generation networks are at an early stage of development, several systems are operational in Europe, mainly launched as pilot projects. Many of these systems work differently from traditional district heating–cooling technology. The energy supply grid uses water as a carrier medium and hybrid substations with Water Source Heat Pumps (WSHP) [23]. The substantial differences between the fourth and fifth generations are the temperature distribution close to the ground values, the ability to work in heating or cooling mode regardless of the network temperature, and the bidirectional and decentralized energy flows.

Efficiency in the heat sector and the built environment can be achieved by building retrofits, replacing buildings, and developing district heating as a structural energy efficiency. Excess and low-grade renewable heat sources can now be integrated into the heat sector [25].

The situation of district heating systems in Italy is illustrated by the Gestore dei servizi energetici (GSE) in its report [26]. Italy has over 340 operational networks, with an extension of approximately 5000 kilometers and 9.6 GW of installed thermal power. There are approximately 284 municipalities served, mainly in Northern and Central Italy. The spread of these systems in Italy is mainly due to the geographical–territorial characteristics, climatic conditions, demographic size, and population density. A total of 62% of the municipalities with district heating have fewer than 10,000 inhabitants. The majority of municipalities equipped with district heating, around 95%, are concentrated in the colder climate zones. The installed thermal power and volume heated in the larger municipalities are higher than those recorded in the other classes despite the latter having a more significant number of municipalities, district heating networks, and a more excellent extension of the networks.

At the end of 2020, 68% of the installed power was concentrated in thermal production plants alone, while the remaining 32% was in cogeneration plants [26]. Fossil sources provide 83% of the installed power, while renewable sources are mainly used in plants intended only to produce thermal energy (10.6%) [26]. The percentage of systems based on waste-to-energy plants is low, equal to 6.8% (Figure 2). Waste heat recovery is less than 1%.

According to the GSE report [26], district heating networks served by sources other than methane are present in only 19% of Italian municipalities. The number of district-heated municipalities, district-heating networks, and the average heated volume is much greater than the municipalities served by methane. The 19% share of municipalities not supplied with methane out of the total Italian municipalities is too low. A percentage that will have to grow in the coming years to ensure that Italy reaches the climate objectives proposed by the European Union. The geopolitical crisis and the COVID-19 pandemic have highlighted the need to expand the district heating network using renewable sources to reduce the economic impact and energy security on the population.

The energy sources used for district heating are natural gas, solid biomass, waste products such as coal, geothermal energy, and other renewable sources. A total of 63% of the energy injected into the grid comes from natural gas, 24% from renewable sources, and 13% from other fossil or non-renewable sources (Figure 3).

Recalling that in Italy, the thermal energy introduced in 2020 was approximately 11.9 TWh, the distribution losses amounted to 18%, obtaining a total thermal energy supplied of approximately 9.7 TWh, 77% in efficient networks, and 23% in non-efficient ones. Of the total thermal energy supplied, 66% was destined for residential users, 31% for services and 3% for industry.

Geothermal energy supporting district heating systems is widely established worldwide and, as we have seen at a national level, supplies 2% of the thermal energy injected in the DH systems. Four regions have plants that produce thermal energy from geothermal sources, with Tuscany producing about 80% of thermal energy from geothermal sources.

3. Data, Case-Studies, and Methods

The existing studies on the development potential of district heating in Italy considered renewable sources and waste heat from industrial plants [24].

However, to select our first case study, the possible reuse of existing hydrocarbon infrastructures in district heating projects was considered in light of the circular economy principles (i.e., recovery, reuse, and recycling). The existing infrastructures that can be reused in district heating projects are hydrocarbon wells and the equipment built in the past that are currently not used or expected to be decommissioned in depleted hydrocarbon fields.

According to data from the National Mining Office for Hydrocarbons and Geothermal Energy of the Ministry for Economic Development, at the end of November 2019, there were 193 mining licenses in Italy, 111 onshore. There are 7246 wells drilled for mining purposes; 2166 are active wells, of which 1434 are distributed in the existing onshore mining licenses [27].

These wells are used for different purposes: 462 are productive, 436 are potentially productive, 394 are dedicated to gas storage projects, and 142 are for reinjection and monitoring. Considering a minimum production temperature of 70 °C and a depth greater than 2000 m, 42 reusable fields have been identified for producing thermal energy and, therefore, usable for district heating [28].

Based on the information above, our second case study was the Romentino municipality, located close to the Villafortuna–Trecate hydrocarbon field, with a well-documented geothermal potential [27,28].

The second case study was selected referring to the maps provided by the University of Halmstad, produced within the European GeoDH project (http://geodh.eu/geodh-map/ accessed on 21 September 2023), which indicate the areas with favorable conditions for the presence of geothermal heat based on the reservoirs and geological characteristics of the underground. For the evaluation of geothermal energy sources, three geographic layers were used:

• High underground temperature above 90 °C at a depth of 2 km;
• Average underground temperature above 50 °C at a depth of 1 km;
• Low-temperature surface resource (sedimentary soil or surface water table).

This study showed that the maximum potential of the geothermal resource is approximately 7 TWh for high and medium temperatures and 11 TWh for low temperatures [4].

Based on these results, creating new district heating plants appears at least promising. One of the most exciting areas is the northern Latium region, where the municipality of Tuscania was chosen as our second case study.

3.1. The Case Study of Romentino

The municipality of Romentino, with about 6000 inhabitants, is located in Northern Italy in the Novara province. Romentino and the municipalities of Trecate and Galliate insist on the territory where the Villafortuna–Trecate field, one of the largest European oil fields, was discovered in 1984 (Figure 4). This field had a cumulative production, at the end of 2013, of about 3.6 × 10⁴ m³ of oil and 2.7 × 10⁹ m³ of gas.

The Villafortuna–Trecate oil field in the western Po Valley belongs to a Middle Triassic petroleum system [30,31]. Its reservoir rocks are formed by fractured and dolomitized shelf carbonates, which are sealed by marly and volcanoclastic units. The oil accumulation is charged by the Besano Shales (Anisian/Ladinian) and Meride Limestone (Ladinian) source rocks. The field trap consists of an NNE-SSW trending thrust-related fold developed during the Alpine compressional tectonics, which involved blocks mainly controlled by inherited NNW-SSE faults generated during a Mesozoic extensional tectonic phase (Figure 4).

The main reservoir has a depth of 5700–6000 m, a maximum temperature of 166 °C, a geothermal gradient of 2.8 °C⁄100 m, and an average static pressure of about 850 bar [32]. Over 50 wells have been drilled over the years; many of these wells have been closed, and the number of wells currently available for production activities is equal to 8. There are two wells used for reinjection purposes.

This field can be classified, in terms of the geothermal resource, as a geopressurized system due to the high overpressure present in the reservoir (about 300 bar). This overpressure allows to produce without pumping activity.

The technically available potential has been estimated assuming a value for the recovery factor, efficiency, and life span of the geothermal plants equal to an annual technical potential of 25.5 MW and a total technical potential of 765.4 MW [28].

A more detailed analysis of the Villafortuna–Trecate field showed that the maximum thermal power that can be extracted from each well is approximately 5.5 MW [32]. Consequently, the power that can be extracted from all eight active wells, assuming a power of 5.5 MW, is attributable to a range of 44 MW [27].

From a geothermal point of view, the field is in an area with a geothermal gradient close to the average value. However, hydrocarbon wells reach a depth of 6000 m with temperatures of 160 °C at the bottom of the well and even 130 °C at the wellhead. The high temperature constitutes an exciting index to use the resource where drilling operations at those depths can make a geothermal project non-economically sustainable.

For the existing wells, it will be a question of carrying out a workover by removing the production pipe and producing with the entire section. In doing so, the production flow rate of the well in its classic configuration will be greater. It will be able to cover the circulation flow rate required inside the heat exchanger. The production temperature is measured at 130 °C, and the reinjection temperature is set at 60–80 °C. Given the excessively high pressure, it is not convenient to reinject into the reservoir. As already performed during hydrocarbon production, reservoir fluids will be reinjected in a shallower formation at a depth of about 2500 m.

3.2. The Case Study of Tuscania

The municipality of Tuscania, with more than 8000 inhabitants, is located in the province of Viterbo (in the northern sector of Latium). In this sector, which shows an elevated heat flow and high temperatures at depth [33,34,35,36], the exploration activities carried out in the second half of the last century led to the discovery of several geothermal fields (e.g., Latera, Torre Alfina, and Cesano geothermal fields).

The development of favorable geothermal conditions in the subsurface of the northern Latium is the result of its peculiar geological evolution (e.g., [34,37,38,39]). This area was affected by contractional deformations associated with the eastward migration of the Apennine thrust belt between early to middle Miocene times. This tectonic phase generated the tectonic superposition of the Ligurian and Sicilian internal nappes, derived from the Ligurian–Piedmont branch of the Neotethyan Ocean, on the main carbonate Meso–Cenozoic formations of the Tuscan and Umbria–Marche units, developed along the western passive margins of the Adriatic plate. Since the middle Miocene times, back-arc extensional tectonics have started to dissect the area. This process led in Pliocene and Pleistocene times to the forming of a basin controlled by NW-SE and NE-SW normal and transtensional fault systems. These fault systems also influenced the distribution of the Plio-Quaternary volcanism in this area [40].

In this context, the main geothermal reservoir is represented by the fractured Meso–Cenozoic carbonates and evaporites of the Tuscan and Umbria–Marche units (see Figure 5).

The northern Latium area’s geothermal potential has been assessed by [41], and the reservoir of Tuscania is identified with moderate production rates (3192 t/h) and considerable expected theoretical geothermal potentials up to 700 MWt. From this promising evaluation, an investigation started to find the best area to build the production plant, searching for reservoir temperatures greater than or equal to 100 °C.

In this area, direct information from drilled wells can be retrieved from the Italian National Geothermal Database [42]. The construction of the geothermal wells and, consequently, of the production plant is constrained from an environmental point of view. Near Tuscania is a nature reserve and other sites with landscape and archaeological implications.

Based on the temperature and top of reservoir maps [33,42], the geothermal resource is identified at a depth of about 1400 m below ground level. However, a depth of 2000 m has been chosen to have an expected temperature at the bottom of the well of about 105 °C in the carbonate reservoir. Once the completion of the well has been defined, it is estimated that the temperature of the geothermal fluid at the surface will reach 100–103 °C based on the production flow rate range. Considering a reinjection temperature of 70 °C, from 1.74 MW to 4.58 thermal MW can be produced per single well depending on the flow rate.

3.3. Methodology to Evaluate the Building Energy Need

A series of specific methodological tools have been developed for the feasibility study. The first aspect is the assessment of the energy needs of the municipality, bearing in mind the territorial structure and the existing building stock in terms of their energy efficiency.

To evaluate the energy heating needs of a municipality, 2011 data acquired by Istituto Nazionale di Statistica (ISTAT) during the census activity [43] were used at the census section scale (i.e., section population, section number, housing surface, building construction period, building typology), and the reconstruction of heating consumption in the residential sector evaluated by climatic zone, period of construction and typology of buildings, carried out by the Ricerca sul Sistema Energetico (RSE) [44]. For each building, RSE carried out energy performance calculations using an implementation of the hourly method described in the UNI EN ISO 13790:2008 standard [45], to which a spreadsheet for the simulation of the systems was added, which is inspired by the UNI/TS 11300 standard-2:2008 ([44]).

There are seven construction periods (

Table 1. Classification of buildings based on construction period.

Class	Period of Construction
V1	Before 1919
V2	1919–1945
V3	1945–1961
V4	1961–1971
V5	1971–1981
V6	1981–1991
V7	After 1991

), and the typological classes of the buildings are the following four:

• Single-family buildings (MF);
• Terraced houses and small condominiums up to a maximum of 8 residential units (VS);
• Medium condominiums with several housing units between 9 and 16 (MC);
• Large condominiums with more than 16 residential units (GC).

Since public data from the ISTAT census do not report the distribution of building typology according to the construction period as required by the tables given by RSE, these available data will be aggregated according to the number of buildings per construction period and the number of buildings of a given construction typology. To obtain this value for each census section of the municipality, the product between the specific primary energy requirement F_s of each construction period V_i and the number of buildings for each construction type n_j are added and divided by the sum of the total number of buildings. Therefore, the average specific energy demand F_sm for the construction period V_i in kWh/m² per year is:

$$F_{sm,V_i}=\frac{(F_{s,V_i}·n_{MF})+(F_{s,V_i}·n_{VS})+(F_{s,V_i}·n_{MC})+(F_{s,V_i}·n_{GC})}{(n_{MF}+n_{VS}+n_{MC}+n_{GC})},$$

(1)

n_MF, n_VS, n_MC, and n_GC indicate the number of buildings in each type of construction class for the i construction period.

Subsequently, the weighted average specific requirement is determined for a census section by adding the product of the average specific requirement per construction period by the number of buildings in that period and dividing it by the number of buildings. The equation used is shown below:

$$F_{smp}=\frac{\sum _{i=1}^7{F}_{sm,V_i}·n_{V_i}}{{\sum }_{i=1}^7{n}_{V_i}}$$

(2)

This weighted average specific requirement, F_smp, can be considered the total requirement of the single census section. To obtain the total energy requirement of a single census section in kWh/year, the weighted average specific requirement will be multiplied by the value of the total area of the buildings in the census section.

A filter is applied to select the census sections with higher population density before adding up the specific weighted average requirements to obtain the total energy demand of the municipality and including it in a development project of DH. Once the population density has been determined, the sections with a population density value of less than 1000 inhabitants/km² will be excluded because they correspond to scattered houses where the DH is not functional. Based on the comparison between the number of buildings and the number of inhabitants and the visualization of the census section with satellite images, the chosen threshold value indicates the presence of scattered houses.

Another methodological element used in evaluating the feasibility of the DH plant is the sizing of the adduction system from the production area to the distribution center. At the level of the actual analysis, the details required by the distribution network design are not available, and only the cost of the adduction system to the distribution center was considered. The sizing of the heat transmission backbone is essential because it significantly affects the total cost of the plant, both in terms of capital and operating costs. The sizing of the piping depends on the following parameters:

• the thermal power Q, deriving from the dimensioning of the existing thermal loads and any predictions of future expansion;
• the temperature difference ΔT between the flow and return of the heat transfer fluid.

The fluid flow rate is determined based on the ratio between the thermal power Q to be supplied to the users and the product of the specific heat of the fluid, c_p, by the delivery-return temperature difference ΔT:

$$\dot{m}=\frac{Q}{c_p·∆T}$$

(3)

The DH system was conceived as a retrofit operation on existing heating systems. Therefore, it was decided to have the transmission backbone working at high temperatures following a conventional scheme of 3rd generation DH.

Considering the delivery temperature equal to 90 °C, various temperature differences between 20 and 40 °C were considered, thus determining a mass flow rate value for each value. The flow velocity was set in the range of 1–2 m/s to size the diameter of the pipelines. Too-low fluid velocities imply the adoption of large-diameter pipes with a consequent increase in heat losses, while fluid velocities that are too high produce more significant pressure drops and an increase in the required energy for pumping. For each fluid velocities value, the diameter value is determined. The average of these diameter values is compared with the diameters of commercial pipes by selecting the one closest to the average.

The heat dispersion along the adduction pipes was calculated and is limited to a maximum of 2.2% of the transported thermal power.

The LCOH, NPV, and PBT are the key performance indexes (KPI) used to compare different case studies and scenarios. Those KPIs are calculated following the methodology reported by [20]. Capital expenditures (CAPEX) include the different components of costs,

$$CAPEX=C_d+C_p+C_{eng}+C_e$$

(4)

C_d is the cost of drilling. The equation proposed in [19] is used to evaluate this cost,

$$C_d={\mathrm{610,000}·b}_{GP}+1.015 ·\left[1.198·e^{0.00047894·\sqrt{{z_D}^2+{d_D}^2}}·{10}^6\right]·\left(1+0.9\right)$$

(5)

The first term includes the well site’s construction costs and is charged only for the first well. The b_GP is the number of drill pads to be realized. The second item is the cost of drilling the first well at the depth z_D, and d_D is the distance between the production and the injection well in the formation. The second well drilled in the same pad will account for 90% of the cost due to the spare mob-demob operations of the drilling plant [19].

C_p is the cost of the main pipes from the production area to the distribution center. This cost is evaluated considering the piping path length and the selected pipe diameter cost.

C_eng is the cost of management and engineering, including the cost of acceptance campaigns [19]. This cost can be split into three different items (C_fs costs for the feasibility study, C_up costs for the underground planning, C_pp costs for the preliminary planning of the power generation plant and the above-ground plant components), and they are calculated as follows,

$$C_{eng}=C_{fs}+C_{up}+C_{pp}$$

(6)

$$C_{fs}=\mathrm{180,000}·b_{GP}$$

(7)

$$\begin{gathered} C_{up}={\mathrm{1,000,000}·b}_{GP}+\mathrm{25,000}{A}_s \\ \mathrm{w}\mathrm{i}\mathrm{t}\mathrm{h} A_s=\left(z_D+4+d_D\right)·\left(z_D+4\right) \end{gathered}$$

(8)

$$C_{pp}=\mathrm{150,000}·b_{GP}$$

(9)

C_e is the cost of equipment (pumps, heat exchangers, piping valves, auxiliaries) considered proportional to the installed power with a unit cost of 234,000 €/MW.

Operational expenditures (OPEX) include the following elements:

$$OPEX=C_{el\_p}+C_{lab}+C_m$$

(10)

C_{el_p} is the annual cost of electricity for pumping obtained considering the energy consumption for submersible pumps and the DH circulation pump. An electrical energy cost of 0.16 €/kWh from ARERA data for 2021 [46] was chosen to evaluate pumping costs. The distance between the production area and the distribution station will be used to calculate the head losses, using the Churchill friction factor relationship and assuming fully developed turbulent flows. An efficiency of 0.8 is considered in evaluating the pump’s work and the required energy, and the number of operating hours is defined based on the climatic zone.

C_lab is the annual cost of labor [19] equal to,

$$C_{lab}={380·T}_{wh}+\mathrm{205,500} ·b_{GP}$$

(11)

C_m is the annual cost of maintenance and repair [19] calculated with the simplified equation,

$$C_m=\mathrm{61,000}·b_{GP}+{1.25·0.05·C}_d$$

(12)

LCOH is calculated according to [47],

$$LCOH=\frac{\sum _{j=0}^L\left({CAPEX}_j+{OPEX}_j\right)·{\left(1+d_n\right)}^{-j}}{{\sum }_{j=S}^L{Q}_j·{\left(1+d_n\right)}^{-j}}$$

(13)

The nominal discount rate d_n can be calculated as follows,

$$d_n=\left(1+d_r\right)·\left(1+e\right)-1$$

(14)

where d_r is the real discount rate, and e is the annual average inflation rate. The reference values used in this study refer to the ECB values given in August 2023 [48,49] (d_r = 4.25% e = 5.3%).

4. Results

By comparing the potential assessed in the two case studies areas and the energy needs, the feasibility of the district heating system for both municipalities was designed.

4.1. The Case Study of Romentino

The assessment of the primary energy requirement saw the selection of the census sections to be included in the supply based on the population density as a first step. Five sections with a population density below 1000 inhabitants/km² were excluded. Following the methodology defined above, an energy value for heating equal to 33.5 GWh/year is obtained. The municipality of Romentino is in climatic zone E, which requires a maximum of 2520 h of heating operation per year. The required thermal power of the plant is 13.3 MW.

Three wells are available for their conversion, based on the information obtained from the MASE website [50], and they are all located near the municipality (Figure 6).

Given the position of the wells, it was decided to build two production plants in the currently available well areas: the first includes the two Cascina 1 and Trecate 19 wells, and the second includes the well Trecate 4. With the construction of the two production plants, two distribution plants will be built near the census sections to be supplied with thermal energy.

4.1.1. Production Area A

The production area A consists of the Cascina 1 and Trecate 19 wells. Their heat production will cover the energy demand of census sections n.2, n.3, n.4, and n.5. The total energy required by these sections is equal to 19.60 GWh/year, corresponding to a thermal power of 7.7 MW.

Considering the assessments of the potential of hydrocarbon wells, it is necessary to verify if an intervention on the well is required to satisfy the required performance. The reinjection temperature has been fixed at 64 °C, and it will correspond to the exit temperature from the primary heat exchanger (Figure 7a). The brine flow rate required to satisfy 7.7 MW of thermal power with an inlet temperature of 130 °C is 28 kg/s. This flow rate is split equally between the two wells. Thus, the single well should supply at least 14 kg/s. From [32], the reservoir behavior has been described by a linear Inflow Performance Relationship (IPR) with a productivity index (PI) value of 19.5 m³/d/bar obtained from [51]. The reservoir can meet the required productivity, but the current well completion produces excessive head loss. The alternative is to remove the existing 3″ ½ (OD 88.9 mm) tubing and allow the well to produce at full 8″ 5/8 diameter (OD 219.08 mm). To evaluate the increase in flow rate, it was assumed to maintain the same pressure drops, thus the same velocity in the well.

Consequently, the ratio between the flow rates was calculated and is 4.76.

Table 2. Main production parameter for the reference well.

SBHP (bar)	FBHP (bar)	FWHP (bar)	Flow Rate with 3″ ½ (kg/s)	Flow Rate with 8″ 5/8 (kg/s)
1020	991	538	6.05	28.8

reports primary data for the reference well with the upgrade flow rate with the proposed completion. This flow rate is higher than required, allowing the possibility of spontaneously producing the brine from the reservoir. Figure 7a presents the flow diagram of the production plant.

The distance from the production area and the secondary heat exchanger plant to distribute the heat to the DH network is 600 m. The optimal configuration of the supply line is a single-pipe transport with a temperature difference of 30 °C. Considering a delivery temperature of 90 °C, the return line temperature will be 60 °C. To transfer the heat, the flow rate in the pipeline of DN 250 mm is 61.5 kg/s. The yearly energy demand for the pumping is 2314 kWh.

4.1.2. Production Area B

Production area B is represented by the Trecate 4 well. This area will supply heat to the remaining census sections, n.1, n.6, and n.7. The thermal power installed in the production area equals 5.1 MW. To obtain this thermal power, the flow rate from the well should be 18 kg/s with an injection temperature of 61.2 °C. Considering the previous analysis presented in Production area A, it is possible to conclude that the flow rate from the re-completed well is greater than the required one (Table 2). Therefore, a single well can satisfy the required production (Figure 7b).

Production area B is 1500 m from the secondary heat transfer plant. Also, for this production area, the optimal solution is a single pipe with a temperature difference of 40 °C. The flow rate in the pipeline of 200 mm DN is 30.4 kg/s. The yearly energy demand for the pumping is 2297 kWh.

Summarising, for the municipality of Romentino, the conversion of three active wells makes it possible to cover 100% of the energy demand for heating.

Table 3. Summary of production data for Romentino case study.

Production Area	Thermal Power (MW)	Pumping Energy (kWh)	Produced Heat (MWh)
A	7.7	2314	19.6
B	5.1	2297	12.9
Total	12.8	4611	32.5

summarizes data from the case study.

4.2. The Case Study of Tuscania

The assessment of primary energy demand following the defined criteria allows us to exclude 26 sections of the census based on low population density. For the municipality of Tuscania, an energy requirement of 22.8 GWh/year was obtained. Knowing that Tuscania is in climatic zone D, the yearly heating hours are equal to 1992. The thermal power to be installed is equal to 11.5 MW.

Depending on the landscape constraint, such as the presence of the Tuscania natural reserve and the location of the 100 °C isothermal line at 2000 m depth [32], it was decided to build the production plant in a NW area at about 1500 m from the town (Figure 8). The production area will host the wells and the primary heat exchanger section.

The expected reservoir temperatures in the area are between 105 °C and 110 °C. To evaluate the productivity of a single well, a simulation of the flow through the well has been performed using the model DoubletCalc 1.4.3 [52]. The main data used in the simulation are reported in

Table 4. Main well characteristics for flow simulation.

Depth (m)	Casing	Thermal Transmittance (W/m2K)	Reservoir Temperature (°C)	Reservoir Pressure (bar)
2000	9″ 5/8	4.42	100–120	200

. The well is completed with a production casing of 9″ 5/8 (OD 244.48 mm). The calculations of well productivity are conducted with a temperature range of 100–120 °C and a flow rate between 50 and 120 t/h. Those flow rates are extrapolated from existing wells in very similar geological formations. The target of calculations is to find the conditions allowing a wellhead temperature greater than 100 °C.

Assuming a reinjection temperature of 50 °C, the thermal power ranges from 3 to 8 MW as the reservoir temperature goes from 105 to 120 °C. Restricting the reservoir temperatures between 105–110 °C, to obtain a thermal power greater than 7 MW, the flow rate should be larger than 105 t/h (see

Table 5. Production well parameter with a flow rate of 115 t/h.

Bottomhole Temperature (°C)	Wellhead Temperature (°C)	Thermal Power (MW)
105	102.7	7.0
110	107.5	7.7

). Therefore, two production wells are needed to obtain the necessary thermal power of 11.5 MW with a total flow rate of 64 kg/s. Two reinjection wells will be drilled to complete the production area.

The transport pipeline will connect the production plant to the distribution plant, which will be built near the center of the municipality. The temperature at the outlet of the primary exchanger on the side of the supply pipe is fixed at 90 °C, with a return temperature of 50 °C.

Since installing 11.5 MW of thermal power is necessary to cover the energy requirement for heating the selected sections of the municipality, the sizing of the piping to minimize the operational cost and the capital expenditure indicates a pipe with 250 mm DN and a flow rate of 68.5 kg/s.

Table 6. Summary of production data for Tuscania case study well.

Scenario	Thermal Power (MW)	Pumping Energy (kWh)	Produced Heat (MWh)	Electrical Energy (MWh)
A	11.5	12,459	22.8	0
B	11.5	92,140	22.8	787.5

summarizes data from the Tuscania case study in different scenarios. The base scenario indicated with A concerns the heat supply without any other ancillary plant, and the reservoir pressure drives the production (Figure 9a). In the case of non-self-productive wells, the production plant should be completed with submerged pumps installed in production wells. Considering a pressure difference of 5 bar, the pumping power is 30 kW. The economic analysis, in this case, is dramatically negative. Scenario B is built to solve this problem, including an ORC power plant to satisfy the required load (Figure 9b). The selected power plant is 100 kW and requires a mass flow rate of 28.5 kg/s of brine. The use of the ORC plant will reduce at 98 °C the inlet temperature of the brine in the primary heat exchanger section.

4.3. Economic Analysis

The economic analysis has been conducted considering the plant’s lifetime of 30 years, the actual discount rate, and the previously reported annual average inflation rate. The ARERA survey conducted in 2022 [52] was considered to fix the heat tariff. This analysis reports the price paid by the user from 2020 up to the first trimester of 2022. The median value of the price ranges from 81 to 191 €/MWh. A price increase after the fourth trimester of 2021 was observed to correlate to the occurring geopolitics issues. The average price in 2020/2021 is 100.5 €/MWh and will be the conservative reference price adopted in the following calculations. The difference between the minimum and maximum price is 62 €/MWh, which defines a minimum price of 70 and a maximum of 132 €/MWh.

Table 7. Summary of the economic evaluation of the two case studies and scenarios with an adopted heat tariff of 100.5 €/MWh (CAPEX, Capital expenditures, C_d, cost of drilling; C_p, cost of the main pipes; C_eng, cost of management and engineering, C_e cost of equipment; OPEX, Operational expenditures; C_{el_p}, the annual cost of electricity for pumping; C_lab, the annual cost of labor; C_m, the annual cost of maintenance and repair; LCOH, levelized cost of heat; NPV, net present value; PBT, payback time; IRR, internal rate of return).

	Romentino	Tuscania A	Tuscania B
	6000	2000	2000
Thermal power (MW)	12.8	11.5	11.5
Pumping energy (kWh)	4611	12,459	92,140
CAPEX (M€)
Cd	3.53	13.5	13.5
Cp	0.48	1.00	1.00
Ceng	0.66	2.86	2.86
Ce	3.00	2.69	3.19
OPEX(M€)
Cel_p	1.22	1.99	0.0
Clab	0.46	0.24	0.24
Cm	0.14	0.10	0.10
LCOH (€/MWh)	80.96	193.83	109.76
NPV (M€)	6.10	−20.50	−0.82
PBT (years)	2.35	8.74	8.5
IRR (%)	43	9	10

reports the primary production data used in the economic evaluation of case studies and its results.

In the Tuscania case study, two different scenarios have been analyzed. The results obtained with the selected tariff, corresponding to the conservative 100.5 €/MWh price, present a negative NPV after 30 years and a payback time of about eight years (Table 7). However, it should be noted that it is possible to obtain positive economic results by increasing the heat tariff over the LCOH. However, this increase in heat tariffs is aligned with the values recorded by ARERA [53], following the general increase in energy prices caused by recent geopolitical crises, highlighting the feasibility of this type of project. For scenario A, an increase of heat tariff up to 200 €/MWh allows us to obtain an NPV of 1.36 M€, a PBT reduced to 4.4 years, and an IRR of 22%. In scenario B, with an ORC plant of 100 kW power to satisfy the request for electrical energy for pumping activities to reduce operational costs and to produce improved results by increasing the tariff up to 150 €/MWh, the NPV is 10 M€. The PBT is slightly less than six years, making the investment rentable (IRR 16%).

The case study of Romentino allows us to demonstrate the higher favourability of the project. The calculation of the capital costs (CAPEX) has considered the workover costs for the two production areas. The piping cost is obtained considering the connection length between the production areas and the distribution plants. The rest of CAPEX includes the management and feasibility costs and the equipment. Operational costs (OPEX) are formed by the electrical energy cost for pumping and the maintenance and personnel costs. The economic index considered highlights the profitability of the investment with an NPV of 6.1 M€ and a payback time of 2.35 years. The 100.5 €/MWh tariff adopted in the economic evaluation is larger than the obtained LCOH, equalling 81 €/MWh, confirming the project’s economic sustainability.

The economic analysis highlights the convenience of reusing existing oil wells, reducing investment costs, and making the investment profitable even with lower tariffs. On the other hand, drilling wells, as in the case of Tuscania, requires a higher heat tariff to achieve similar economic results. It can be concluded that the cost of building a district heating network and using hydrocarbon wells is lower than building a system that uses heat extracted from wells that need to be built. Therefore, it can be affirmed that converting existing hydrocarbon wells into geothermal wells constitutes an excellent opportunity to access the resource, not to be missed, significantly reducing the necessary investments and mining risk.

A second aspect concerns the use of the pumps for production. The energy required to produce the expected flow rate is expensive, making the investment non-profitable. A power plant should be considered to produce the required electrical energy and to increase the income with the sale of its extra production, improving the project’s economics.

5. Conclusions

In Italy, as in many other European countries, the energy required for residential district heating comes mostly from fossil fuels and very little from renewable sources such as geothermal. Given the characteristics of the Italian subsurface, the geothermal resource can and must be used for district heating. The limited diffusion where geothermal resources exist is due mainly to the high initial investment cost.

In this study, a methodology has been developed to be applied to municipalities where the local geothermal resource is present and for which the feasibility of a district heating system is being assessed. Two different contexts were considered and compared: (i) areas with a well-documented geothermal resource, where new wells need to be drilled, and (ii) areas with depleted and still active hydrocarbon wells with a known potential to be converted into geothermal wells.

The proposed methodology first analyses the potential of the geothermal resource in the territory of the two municipalities chosen as case studies representative of the two settings mentioned above. The results show that the two municipalities have a similar heat demand, 11.5 MW for Tuscania and 12.8 MW for Romentino. The main difference consists in the different building efficiency. In Romentino, 28% of buildings are older than 1919, and only 41% were built after 1971. On the contrary, in Tuscania, 69% of buildings are more recent than 1971, and only 13% are older than 1919. Therefore, the energy demand is highly influenced by the less efficient and older buildings.

Both case studies show positive economic indices assuming reasonable heat tariffs aligned with the values recorded in Italy in 2020–2021 and in the first part of 2022 following the recent geopolitical crises. However, the results of our economic evaluation show how reusing hydrocarbon wells in geothermal wells constitutes an excellent opportunity to access geothermal resources, which can significantly improve the economics of district heating projects.

Although not present throughout the territory, these potentially reusable hydrocarbon wells often have characteristics that allow the production of fluids at high temperatures and their spontaneous production thanks to the high pressures of the reservoir. Reusing these wells allows the investment cost to be drastically reduced, given that the drilling of a well affects over 50% of the system’s total cost. In our two case studies, the drilling cost alone accounts for 46% of the CAPEX in Romentino and 67% in Tuscania. Drilling costs in Romentino are 25% of those in Tuscania. It should also be noted that LCOH for Romentino is less than 50% of the value for the Tuscania case study.

The solutions adopted in this study can also be optimized by considering the construction of a cogeneration system, producing electricity and heat simultaneously. District heating systems using cogeneration plants make it possible to achieve greater global energy efficiency.

It is necessary to revolutionize the residential district heating system through solutions such as the one described in this study, creating district heating systems that use a zero-emission energy source as the primary source, such as geothermal. The promotion and diffusion of geothermal district heating networks could significantly contribute to achieving the climate objectives set by the European Union.