This edition of Drilling Advances will be the last in a series that explores what would need to happen for Hot Dry Rock (HDR) Geothermal to be economic in its own right—i.e. no subsidies. The size of the potential prize is crazy big—IF (note the big ‘if’) the industry can reduce the capital needed to tap this virtually inexhaustible resource. The situation begs the question: Just how far would we need to advance to make HDR a real money-maker?
Past columns have discussed various flavors of geothermal energy, the promise of HDR Geothermal, and explored the economics of one current pilot HDR Project being conducted by Geo Energie Suisse (a consortium of Swiss power companies). This column will explore how close that project would be to being economic, if unconventional-like economies of scale and operational efficiencies were applied… in hotter rock (see previous column about the importance of ‘hot’).
Refer to my last columns <Link to last article here> if you are interested in the complete story. I try to make each of these helpful as stand-alone missives, but there is a red thread running through them all and prior articles might be useful for new readers.
Briefly, the left half of Fig. 1 shows our baseline Geo Energie Suisse HDR Project. They are building a downhole “heat exchanger” by fracing between ~1.5-km (4,900-ft) horizontal legs in two ~4.5-km (14,800-ft) total depth wells in 150oC (300oF) rock, circulating fluid at about 60 lps (~950 gpm), and use the extracted heat to generate electricity. The Geo Energie Suisse website has loads more detail, but by way of summary, the project is set to be a money-making effort for the consortium after investing ~$150 million to drill the wells, build a 5-MW power plant and sell power to the grid at a guaranteed—and subsidized—price of $.61 per kWh. The Swiss Government is also subsidizing 50% of the investment cost, so the consortium only sees an investment of ~$75M.
Table 1 summarizes that the consortium can expect reasonable ~20% Internal Rate of Return (IRR) with its subsidized capital and electricity price. However, without the subsidy and even with removing $30 million in “science spend” from the capital cost, the project’s IRR is negative 8%. That’s far from being attractive.
What would happen to project economics, if we could construct longer-lateral geothermal wells as efficiently as we build shale wells?
To try to answer this question, let’s see what could be done to improve the economics of the Baseline project. Prior columns have shown that we need both to get energy out and be cheaper.
To get more energy out, we need more contact area in hotter rock. The right half of Fig. 1 shows this “better” HDR schematic. Things don’t really scale linearly, but the basic idea here is to get more ~3x more heat out by having laterals 3x longer and get another ~2x more heat out by having one injector flanked by two producers. This would increase the stimulated rock volume by 6x. By doing all this in HDR >250oC, instead of 150oC, we could tap 3x more heat (given a 100oC sink) and extract it 3x more efficiently because of Carnot’s law (see prior columns).
To have any hope of being economically attractive, geothermal needs to get bigger or go home. As mentioned, things don’t really scale linearly, but 3x longer laterals, with 2x more wells, with 3x more heat, extracted 3x more efficiently could be only 20% correct to increase output by 10x. At 10x, a 5-MW facility could become 50-MW—longer laterals in hotter rock could make this happen.
But we’d need to construct all this much cheaper, too. Are unconventional wells drilled efficiently enough to make this happen?
Table 2 shows the actual costs from a Marcellous unconventional well: 15k-ft (4.5-km) lateral at 8k ft TVD, with 7-in. production casing can be drilled to TD in 21 days, built for a well cost of $5 million and has an all-in completed and fraced cost of $12 million.
This benchmark isn’t suitable as a direct comparison for an HDR geothermal well, because geothermal wells need to be larger, as they generally take more fluid, and igneous rock is certainly harder than the Marcellus well. Larger holes and stronger rock mean the HDR geothermal well must take longer and cost more to drill, even if it is as operationally efficient with the same economies of scale.
Question: just how much longer and how much more would it cost, if the HDR operation was as far up on the learning curve as the Marcellous well and had similar economies of scale for service delivery costs?
Future columns might review this in detail but suffice to say that you can use a Mechanical Specific Energy (MSE), and the sonic travel time as a surrogate for rock strength to determine the technical limit for drilling operations (Brett, AADE 06-DF-HO-13 has the details). The example Marcellous well’s estimated MSE technical limit is 18 days. The well actually took 21 days to drill, 15% longer than the technical limit.
The same MSE technical limit approach would estimate a technical limit of 46 days, if the lateral section were to have 30k psi compressive strength rock and be cased with 9-5/8-in. pipe. If the HDR well, like the Marcellous well, also took 15% longer, then its MSE technical limit would be 54 drilling days. With equivalent economy of scale for materials and service costs, each of the three unstimulated wells would cost some $7.3 million. With similar completion/fracing costs to the Marcellous well, a stimulated one-injector, two-producer downhole heat exchanger suite would cost $33 million. The left half of Fig. 1 shows the HDR suite’s schematic, and Table 3 summarizes the time and cost.
So, IF the better HDR downhole suite were drilled as efficiently, with equivalent economy of scale as the example Marcellus well, we could expect a subsurface cost of ~$34 million that could deliver 10x the power output.
We need one final number to scope the full cycle economics of the prospective project: How much would the surface equipment cost? Natural gas power plants can be constructed with a capital cost of ~$1,000 per kW of generation capacity. Not sure it would be possible, but IF the surface facilities of our prospective HDR project could be constructed for $1,500 per kW (i.e. 50% more than an equivalently powered natural gas facility), then a 50-MW project would have a capital cost of $109 million ($75 million for surface and $34 million for subsurface). Table 4 shows that such a Prospective Projects would have an attractive IRR of ~30%.
Natural gas power generation isn’t a real analog for geothermal power generation, but certainly geothermal systems do not currently benefit from economy of scale and would certainly be much cheaper at scale. Further, they can still be 1.5x more costly per kW than natural gas systems and still be attractive.
To summarize geothermal energy’s opportunity: Attractive returns (IRR >30%) would be possible in HDR >250oC (>480oF), with enhanced geothermal systems with laterals of 10k to 15k ft (3 to 4 km). This is IF economies of scale and continuous improvement could construct electric power generation facilities for <$1,500 per kW (~50% more than the cost of combined cycle natural gas facilities), and IF the larger wellbore needed was constructed with the efficiency that is routinely achieved in shale wells.
To make this a reality, drilling folks would need to move along the learning curve in hot dry igneous rock to match the efficiency of unconventional drilling operations—key advances needed to make this a reality (in my opinion) would be: a) achieving bit life in harder and hotter rock (drilling on air could be a game-changer; see prior columns); and b) conducting drilling and completion operations reliably and routinely in >250oC (>480oF) rocks. Also surface equipment would need to be manufactured at scale and installed, instead of being one-off “stick built.”
So… What would happen, if we could construct geothermal wells as efficiently as we build shale wells? Answer: The world would go crazy for geothermal wells. I’m not saying it will happen. But crazier things have happened… shale became a reality.
The next edition of Drilling Advances will get off this “crazy” geothermal kick and return to advances in oil and gas drilling. Thanks for indulging this detour into geothermal drilling and until next time, I hope to start a conversation with any of you on how we can all help Drilling Advance. If you have any questions, ideas, comments or corrections please email me at ford.brett@petroskills.com and I promise I’ll respond. WO
FORD BRETT, P.E., is CEO of PetroSkills. He has consulted in over 45 countries, been granted >35 patents, authored >40 technical publications, and has served as an SPE Distinguished Lecturer, as well as on the SPE Board as Drilling and Completions Technical Director.