To estimate the cost/benefit 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. This simulator was developed by the Chair of Petroleum and Geothermal Energy Recovery at the Montanuniversitaet Leoben (Fruhwirth, R.K., Hofstätter, H., 2016). Conduction, radiation, and convection were considered a mechanism for heat transport. The heat losses in the formation are of course considered as transient since the formation cools down with ongoing heat extraction during the operation of the deep geothermal well. The processes taking place inside the borehole were defined as stationary because variations of the parameters occur on an hourly or daily basis, compared to the transient heat losses that occur for years. The transient earth model is linked to the stationary borehole model via the borehole wall temperature.
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 Te. The orange line, which represents the temperature of the fluid in the annulus Ta, is identical with the dashed dark-blue line, which shows the temperature along the borehole wall Tw. The blue line shows the temperature of the fluid inside the tubing Tp. Since the tubing is assumed to isolate entirely, the fluid 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 fluid 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.
Figure 5 presents a schematic of the real wellbore drilled from surface (a) and from subsurface (b) and their temperature profiles just after start of production. The schematic shows that the wellbore consists of an anchor, a surface casing and a production liner. The simulation results show that the wellhead temperature is 143.4 °C for the surface well and similar with 144.0 °C for the subsurface well, both at an inflow temperature of 60.0 °C. Temperatures of both cases, especially the resulting temperatures after 30 years of operation, are too low to generate electricity efficiently. For such low temperatures, the efficiency of conversion to electricity 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 influence 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 flow with depth, the heat flow 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 profit 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 profits 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 defined as the main factor. Even with an accurate knowledge of the expected geology that is going to be drilled, the uncertainty of the financial 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 first cost evaluation will only indicate a direction where the final 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 defined to be 7 inches, which can be found in the majority of already drilled geothermal wells (Teodoriu, C., 2015). Three casing strings are installed because of contingency reasons, although the well could theoretically be constructed with one single casing section. But in case of unexpected formations, there is only spare capacity in size.
Costs per Section | 6,000 m Surface | 5,000 m Subsurface |
Base Costs | 454.795 | 454.795 |
Section 1 — Surface | 336.866 | 336.866 |
Services | 125.913 | 125.913 |
Material and Consumables | 210.953 | 210.953 |
Section 2 — Intermediate | 2.547.348 | 2.547.348 |
Services | 1.307.843 | 1.307.843 |
Material and Consumables | 1.239.505 | 1.239.505 |
Section 3 — Production | 4.001.552 | 2.898.135 |
Services | 2.613.063 | 1.853.245 |
Material and Consumables | 1.388.489 | 1.044.890 |
Total Drilling Costs | 7.340.561 | 6.237.144 |
Difference | | -1.103.417 |
Wellsite Construction Costs | 200.000 | 4.320.000 |
Total Costs | 7.540.561 | 10.557.144 |
Difference | | 3.016.583 |
Table 2: Economic comparison – surface versus subsurface well construction costs
The calculation can be separated into two parts. In the first 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.