Subsurface Located Geothermal Well – Case Study

The recovery of geothermal energy has become very attractive in the last decades. Advantages like the small footprint, the waste-free and CO 2 neutral energy production and the continuous geothermal resource, will highly promote geothermal energy usage soon. This paper presents a case study of a subsurface located geothermal well. The overall approach is to use existing subsurface facilities and construct the geothermal energy recovery system within them. Currently, the generated power, produced by geothermal energy systems, is more expensive than energy produced from competitive sources, because of the costs associated with the construction of the wellbore. To extend the use of geothermal energy, its recovery costs have to be reduced. The primary wellbore cost driver is the depth. The drilling costs rise exponentially with depth. When situating a geothermal power plant in an underground structure, the temperature at the start point of such a geothermal well is already at an elevated temperature level, and the total amount of meters to be drilled is substantially reduced, thus saving drilling costs. A primary focus this paper is, one hand, and, on the other hand, the technical of such a project. The results have shown that the eciency of subsurface located geothermal wells is higher than for surface located ones. Technical equipment and technology for drilling subsurface are already available today. A case study for investigating the inuence of parameters like depth and number of wells is performed. Depending on geology, simulations have indicated that it is from the technical point of view more ecient to drill a deeper well in comparison to drill several shallow subsurface wells. Nevertheless, from the economic point of view, currently, surface drilled wells are more economical.


Introduction
Geothermal energy is an inexhaustible source of primary energy, spread around the globe in massive amounts, but not equal geographically distributed. Its potential is highest in active tectonic regions. The recovery of geothermal energy requires a small surface footprint, and the extraction is CO 2 neutral and almost waste-free. These are just a few reasons for explaining the globally growing usage of this kind of renewable energy resource. The worldwide operating capacity reached 13.5 GW in 2016 as a result of a 5% annual growth in each of the previous years (Renewable Energy Policy Network for the 21st Century, 2017).
Geothermal plants are spread across 24 nations. The global electricity and direct heat production from geothermal energy, estimated by the Renewable Energy Policy Network for the 21st Century in 2017, is 157 TWh (Renewable Energy Policy Network for the 21st Century, 2017), with fty-fty ratio between usage for electricity and heat. The latest data for Austria report a total primary energy consumption of 372 TWh (Statistik Austria, 2018). 29.5% of the primary energy production is due to renewables. These numbers show that the global geothermal energy production can even not meet the consumption of Austria. Despite the steady growth and the massive potential of the geothermal resource, only a vast percentage is utilized.
Currently, the share of geothermal energy in total electricity capacity and generation remains very low. The global installed electricity capacity in comparison to the net generation indicates that just 0.4% of global electricity is generated from geothermal applications. The vast majority is based on fossil fuels. The total share of non-renewables is currently about 77%. Nevertheless, a forecast made by the Geothermal Energy Association (Geothermal Energy Association, 2017) predicts a continuous growth of the installed geothermal capacity, and by 2020 up to 17.6 GW installed capacity is predicted. Currently, a capacity of around 11.5- Iceland (0.7 GW). By the end of 2014, there were worldwide 612 geothermal power plants operating. Europe experiences a slower development than it could, mainly due to the general lack of awareness of the potential of geothermal energy (Renewable Energy Policy Network for the 21st Century, 2017). Geothermal energy is one of the only renewable energy sources that have the capability of providing base-load electric power, due to its independence on sun, wind, and water. Minimum impacts on the environment are associated with its extraction. Neither CO 2 certi cates within the European Union Emission Trading System need to be bought, nor expensive invests in technologies to reduce the carbon dioxide emissions are required.
The increasing global energy demand, especially in the non-OECD countries and the continuing environmental policy against climate and air pollution, may boost the geothermal energy recovery in some regions. Extraction of geothermal energy is already a competitive technology in terms of costs compared to other types of renewable and conventional energy sources (World Energy Council, 2013). Depending on the type of power plant, the average costs are between 60 to 80 USD/MWh energy generated. The most signi cant share of the overall costs of a geothermal power plant is associated with the construction of the wellbore. Costs for drilling may vary, depending on the oil price. A decreasing rig count in the oil industry generates a potential for utilizing drilling rigs for geothermal wells at moderate costs. Nevertheless, the potential of a geothermal cogeneration plan depends on the location of the wellbore and geology.
Geothermal systems for electricity generation are just useful if the geothermal gradient is relatively high, and the remaining energy from electricity generation can be used for heating purposes; thus, consumers have to be situated within a certain distance to the plant.
In Austria, the geothermal potential highly depends on the region. Whereas in general, the potential is low in the alpine region, Neogene basins, like the Molasse basin in Upper Austria and the southeastern Styrian basin, provide a signi cant potential for geothermal cogeneration (Geologische Bundesanstalt, 2020).

Geothermal Systems
Besides near-surface geothermal systems, like ground heat collectors, shallow borehole heat exchangers, and energy piles, which are speci ed by target depths of several 10's of meters up to 150 m, deep geothermal energy recovery systems exist. The temperature at the target depths of deep geothermal systems can reach more than 150 °C and results in increased energy output. Another advantage of deep geothermal systems is that neither daily nor seasonal temperature swings affect the system, which is usually the case up to depths of 10 meters. Deep geothermal energy recovery systems can be further split into hydrothermal and petrothermal systems.
Hydrothermal systems are based on the utilization of hot water originating from an aquifer. The energy extraction takes place in a direct way or via a heat pump and used for the feeding of local or district heat networks. Above surface temperatures of 80 °C, the operation of an Organic Rankine Cycle power plant is an option, whereas temperatures above 120 °C enable the usage of the Kalina process. These processes typically employ a so-called hydrothermal doublet. Hot water is produced from a producer well, heat is extracted via a heat exchanger at the surface, and the cooled-down water is reinjected into the same aquifer where it originated. Reinjection guaranties pressure maintenance of the reservoir layer and is often demanded by the authorities (Stober, I., Bucher, K., 2012).
Petrothermal systems form the second group of systems for deep geothermal energy recovery. They are independent of aquifers since they recover the heat stored in the formation around the borehole. The primary purpose of petrothermal geothermal systems is the generation of electricity. Depending on geology, the aim is to reach formation temperatures of up to 200 °C. Well depths of several thousand meters are often required in crystalline basement formations. These crystalline formations are naturally fractured, and water, which is arti cially added to the formation acts as the circulating uid, can ow through natural fractures in the formation. Heat is extracted by a doublet arrangement of the two wells (Stober, I., Bucher, K., 2012).
The deep geothermal probe is a special type of deep geothermal energy recovery, which uses a closed circulation system in a single wellbore. Recovery is generally lower than in other systems as a result of a low surface area, where heat can be transferred from the surrounding formation to the circulating medium. The formation is cooling down over time because of the heat extraction, depending on the rock properties, which very slowly decreases the performance of the system. Nevertheless, bene cial for the usage of deep geothermal probes is the fact that they can be installed independently on geology without having any risk of environmental pollution or chemical reactions in the formation. Besides, abandoned oil and gas wells can be converted to geothermal energy producers. The deep geothermal probe, or also called the borehole heat exchanger, consists of two concentric pipes and forms a coaxial system. These pipes create two ow paths, one between the inner diameter of the production casing string and the tubing outer wall, the other one inside the tubing. The cold circulating media is injected into the casing-tubing annulus, is heated up due to the increased formation temperature while owing down the wellbore. At the nal wellbore depth, the maximum temperature is reached. The target is to conserve the temperature of the uid while traveling inside the tubing back to the surface, which can be achieved by using an isolated tubing string. Compared to hydrothermal or petrothermal systems, the energy output of deep geothermal probes is lower, but the investment and maintenance costs are lower too (Stober, I., Bucher, K., 2012).

Subsurface Location
The costs for drilling a deep wellbore represent the most signi cant portion of the total costs of a geothermal project. The shares vary widely between 40% (C. Augustine et al., 2006), 50+% (E. Radeberg et al., 2012), and 40 to 95% (S. Thorhallsson drilled in near vicinity of each other, the drilling costs vary widely. The GPK-3 drilling costs were 6.57 million USD, whereas the drilling costs for GPK-4 were 5.14 million USD. A reason for the difference in cost is the local variation in geology, which frequently leads to drilling problems. In general, one additional casing string for a 5,000 m deep vertical wellbore ( ve instead of initially four) caused the overall costs to rise by 18.5%.
The cost behavior as a function of depth is also the concern of a study performed by the Massachusetts To reduce the drilling costs as the signi cant cost driver for deep geothermal wells, this case study investigates the effects if the geothermal well is drilled from existing subsurface facilities, like mines, tunnels, or caverns. Signi cant advantages are a decrease of wellbore length to reach the same target formation, which reduces drilling costs and the reduction of friction pressure losses for circulating the uid in the geothermal probe. Issues to be investigated are the subsurface space requirements for the drilling rig, logistics, and HSE regulations. In subsurface mining, several mineral extraction methods are applied that create vast caverns. The idea is to position the drilling rig in such a cavern for drilling the geothermal probe, as presented in Fig. 2.

Challenges In Drilling Rig Selection And Logistics
The idea of positioning the drilling rig in a subsurface cavern comes along with special requirements for the drilling rig.
Space: The excavation of a cavern is time-consuming and requires high technical and nancial efforts if the excavated material cannot be used as a natural resource. Therefore, the selected drilling rig should have a small footprint and height. Wellbore depth: To gain su cient temperature for the geothermal probe, the target depth of the wellbore must not be below 5,000 m, which results in a speci c hook load constraint for the drilling rig.
Power supply: It needs to be taken into account that fuel-or gas-powered electricity generators can only be used concerning some limitations. The hazard potential through ignition or explosion of fuel or other ammable liquids in a closed, subsurface space is very high. Besides, air ventilation and extraction of emerging fumes must be taken into consideration. Drilling rigs with external power supply via the power grid are preferred.
Circulation system: The drilling mud processing needs to be done in a closed system, because of occasionally occurring gas, which must not escape into the free atmosphere.
The following drilling rigs originating from Central Europe (Germany, Austria) were compared. Table 1 summarizes the technical data of the compared drilling rigs. nevertheless considered is its unique construction. The slingshot system promises a rig-up of the derrick without the need of a crane; the derrick will erect itself. This can be a crucial bene t in the case of the restricted space in a subsurface cavern. A crane for unloading of the transport units from the trucks is required, however. Moreover, the nominal maximum drilling depth is 500 m deeper than for the other two rigs.
If the footprint of the RAG E200/E202 drilling rig can be drastically reduced for subsurface usage, this rig can be included in the above list.

Hse Aspects
A signi cant part of the evaluation of a subsurface operating drilling rig is health, safety, and environmental considerations. Factors that are critical for the success of the project are organized in thematic groups, their impact on various operations or the overall project must be assessed, and ultimately measures for the avoidance, or -if it is not possible to avoid these -measures for mitigation have to be de ned.
Transport: One of the most critical aspects of the operation of a drilling rig is transportation.
Components and personnel of the drilling rig must be on location in time. Space is often limited, more than ever in a restricted cavern. Thus, careful planning in the two domains is critical. First, the dimensions of the transported object must be evident. Secondly, proper time management must be set up. Moreover, mutual interference between the drilling operation with its overall supply needs (electricity, diesel) and waste products (cuttings) through the mine and the operation of the mine itself must be avoided.
Limitation of space: A subsurface cavern is limited in space, compared to the less restricted well sites onshore. Access roads too -and from -the caverns are constructed in a way that freedom of movement for regular trucks of haulage contractors is possible. Considerations about the space for storage areas, rig site, accessibility of the rig site, and maneuverability of trucks, cranes, and other vehicles must be made, and issues can be overcome in advance by detailed planning in the preliminary stage of operation.
Working safety: Considerations for working safety are generally valid in any working environment: in the construction industry, in particular, where operating heavy machinery is a daily routine, movement of heavy loads and exposure to all kinds of emissions are common. In uencing factors, risks, and measures for working safety include especially the use of correct personal protective equipment, potential explosion hazard areas (EX zone), handling of chemicals, the occurrence of dust, sparks, especially during welding work, re, optical radiation, the release of gas, and working at heights. In a subsurface located workplace, the failure of the light system and ventilation system must be avoided by all means.
Noise emission: Drilling in a subsurface location bene ts the usually affected residents close-by to a drill site, since the generated noise will not escape from the cavern and thus will not have an impact on residents. The only affected group is the drilling crew and other workers present near the drilling rig.
However, the noise level must be kept within limits enlisted in the working conditions act.
Mud losses while drilling: One of the most signi cant potential risks when drilling a well in a new prospect area. Faults, fracture networks, karsti cation, or even caverns may lead to drilling mud losses in the drilling process. By gathering and analyzing various geological and geomechanical data, possible thief zones can be identi ed and the risk mitigated.
Gas or water in ux from the formation: The opposite of uids leaving the wellbore would be uids unexpectedly entering the wellbore during drilling, for instance, from gas-or water-bearing layers.
Interference due to mining operations: To keep costs low, the access from the surface to the cavern will be the same for the drilling rig and its crew as for the regular mine operation, assuming that the mine is The exhaust gas coming from the standard trucks, which are delivering the drilling rig and supplies, can be ltered with the mine's ventilation system.

Heat Extraction Comparison
To estimate the cost/bene t ratio of a single versus multiple deep geothermal wells, a simulator was used for modeling of the thermal processes in the region around and within the wellbore. To investigate the impact of the borehole completion on the heat extraction, a simulation under ideal conditions -assuming no production casing, hence direct contact of the circulation media with the formation -and real world conditions -a regular API conform tapered casing string -was carried out.
Besides the borehole completion, the underlying assumptions are identical for both scenarios. A 5,000 m vertical wellbore is drilled into a homogenous crystalline basement rock; the tubing has an OD of 4 ½ inches and is entirely isolated; geothermal gradient 3 °C/100 m, rock density 2900 kg/m³, heat capacity 710 W/kgK, and thermal conductivity 3 W/mK are constant. The beginning of the wellbore is in a depth of 1000 m, where a temperature of 30 °C is present. The bottom-hole temperature is 180 °C. A circulation rate of 10 m³/h at an injection temperature of 60 °C is chosen.
In Fig. 3, the indirect circulation of the subsurface wellbore under ideal conditions is shown. The red line represents the initial formation temperature T e . The orange line, which represents the temperature of the uid in the annulus T a, is identical with the dashed dark-blue line, which shows the temperature along the borehole wall T w . The blue line shows the temperature of the uid inside the tubing Tp. Since the tubing is assumed to isolate entirely, the uid temperature at the wellhead is 148.3 °C. This kind of borehole heat exchanger causes a reduction of the rock surrounding the wellbore. After one year of operation, the amount of energy that can be extracted will drop to 63%, after 30 years to about 50%. Figure 4 shows the changes in the temperature distributions after an operating period of 30 years. The wellhead temperature will reduce to 103.8 °C.
The parameter study performed shows that the energy extraction rate is following the uid circulation rate. A higher circulation rate can achieve higher power rate, but at the same time, the formation will cool down faster, and the wellhead temperature will be lower in comparison to a moderate circulation rate. is only around 10%. It is more useful to utilize geothermal energy for heating purposes at this stage.
From the investigation of the long-term temperature decrease over time with distance to the borehole wall, it can be concluded that the minimum distance between two geothermal wells must be 116.9 m in order to avoid the mutual in uence of the geothermal wells. After 30 years of operation, the temperature at the wellbore wall decreases to 100.6 °C, whereas the undisturbed initial temperature of the formation is present at a distance of 58.46 m.
Assuming a linear increase of heat ow with depth, the heat ow from the formation to the wellbore will be 435 kW for a 6,000 m well. Under consideration of 25% thermal losses, the net thermal energy output will result in 326 kW or earnings of roughly 240,000 EUR for continuous operation over a year. For a 4,000 m well, the thermal energy output will be 84 kW -20% thermal losses already deducted -thus leading to a sales pro t of around 60,000 EUR under similar conditions as before. This concludes that it is not economical to drill several shallow wells instead of one deep.
These potential pro ts must cover the cost of the construction of the wellbore. Overall, drilling costs are affected by various parameters throughout the entire process, where geology can be de ned as the main factor. Even with an accurate knowledge of the expected geology that is going to be drilled, the uncertainty of the nancial outcome of the project is still high. Hard and abrasive formations demand high investments into proper drilling equipment since those formations increase the wear of tools, accompanied by slow drilling progress versus depth. Therefore, a rst cost evaluation will only indicate a direction where the nal costs are heading and should be used with particular caution. Table 2 compares the costs of a 6,000 m wellbore drilled from the surface with a 5,000 m wellbore drilled from the inside of a cavern. The outside diameter of the production casing is de ned to be 7 inches, which can be found in the majority of already drilled geothermal wells (Teodoriu, C., 2015  The calculation can be separated into two parts. In the rst part, the total costs for drilling a well are evaluated and compared. One can see that the 6,000 m wellbore from the surface is almost 18% more expensive than the 5,000 m wellbore, which is drilled from the subsurface. A critical cost factor, which has not been considered so far in the calculation, includes the costs for the construction of the well site. In the case of the subsurface well, the costs for the cavern construction are added to the total drilling costs, whereas for the surface well, the ordinary well-site construction costs are added. With this information, the result has been inverted and seems to be no longer economically attractive. In an optimum scenario, the required cavern will be constructed during the regular mining operation, thus adding no more additional cost for the well site construction of the subsurface located well.
Calculations for different well depths have shown that the savings for 1,000 m of wellbore length are moderate, compared to the costs for drilling a new one. So it is not economical to drill multiple shallower wells compared to a deeper one. Earnings of a wellbore targeting 6,000 m are four-times higher compared to wellbore targeting 4,000 m, whereas the costs for the construction of two 3,000 m subsurface located wells amount to 6.8 million EUR compared to one 5,000 m subsurface well of 6.3 million EUR. The pay-out time for a subsurface located 5,000 m geothermal well is 30.6 years, whereas 36.0 years are required for a 6,000 m surface located geothermal well. 15% of the annual earnings are assumed as OPEX for the operation of the well.

Conclusion
The declared objective of the case study was to identify whether geothermal energy can be recovered from already existing subsurface facilities in a technically feasible, safe, and economical manner. Altogether, the results from the present study are promising for a successful implementation of a deep geothermal probe within a cavern, but with restrictions. The subsurface approach within a subsurface facility is economically feasible only if the cavern or tunnel already exists. A cavern constructed only for geothermal recovery will not nancially justify the savings in 1,000 m of the wellbore. Possible synergies must be identi ed and utilized; only then will such a project will be nancially feasible. Considerations must be made concerning the legal aspects. A drilling rig has never been in operation below ground; a legal framework must be worked out in advance. Emergency exit concepts from the rig site must be thoroughly elaborated.

Declarations
Availability of data and material All data will be provided on request

Competing interests
There are no competing interests

Funding
The research has not been funded from the industry Authors' contributions All authors have done the research together and equally distributed