Drilling advances: Does geothermal 2024 = shale 2005?

FORD BRETT, CONTRIBUTING EDITOR 

The March column explored the possibility that drilling could “save the world” by providing plentiful, reliable, affordable baseload geothermal energy.  Very briefly, conventional geothermal is good, because it provides economic, clean baseload ePower or heat, but it is geologically quite rare and therefore, unfortunately, irrelevant at a worldwide scale.  It is zero carbon, affordable and reliable—but it is not plentiful.   

But because there is an essentially limitless supply of heat below every human’s feet, IF (note the BIG ‘if’), we can reduce costs and improve efficiency enough on hot dry rock (HDR) (or other advanced) geothermal techniques, plentiful wouldn’t be a problem. Unlike conventional geothermal, the issue isn’t being plentiful—the issue is affordability. 

The situation we face with HDR geothermal is a bit like the situation that shale faced 20 years ago: We knew the shales were plentiful and had loads of hydrocarbons—we just didn’t know how to get it out of the ground and still make money. The key to unlocking affordable, reliable and plentiful shale was reducing cost and increasing output to the point that it could make economic sense. It wasn’t easy, but the industry did it.  This and the next couple of Drilling Advances columns will explore what it would take for geothermal to be so affordable, people would do it solely because they could make money.    

Refer to my last column, Drilling advances: Could drilling save the world? if you are interested in more of 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.  

What would it take for HDR geothermal to really be affordable?  

The following will scope the economics of the Geo Energie Suisse project to explore the magnitude of improvements needed to make HDR geothermal lucrative enough that people would do it for solely the purpose of making money—not because it was “green” or because of a “subsidy.”  If we could make HDR geothermal (or any of the other geothermal techniques—see prior column) affordable enough, “greedy” people could produce geothermal and make money—then drilling really could save the world.  

Fig. 1. Geo Energie Suisse Project Plan.

Geo Energie Suisse is a consortium of Swiss power companies with a project now underway to actually build and operate an HRD electric power source.  Figure 1 shows their concept.  They are building a “heat exchanger” by fracing between ~1.5-km horizontal legs in two ~4.5 km total depth wells in 140⁰C 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, according to published data, the project is set to be a money maker 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 $0.61 per kWh. The Swiss government is also subsidizing 50% of the investment cost—so the consortium only sees an investment of ~$75 million.  At that power price, with the subsidy, and after paying some taxes, the consortium is targeting making a reasonable Internal Rate of Return (IRR) on their 30-year project of almost 20%.   

There are many good reasons for the project: proving the concept, identifying and solving technical challenges, providing a technical road map that could be scaled on future projects, as well as spending significant money to understand any tectonic effects of circulating fluid.  As good as the project is from a proof-of-concept perspective, the project isn’t a money-maker without the subsidies.  Figure 2 shows the economics of an unsubsidized project.   

Fig. 2. SCOPING Economics for Subsidy, No Subsidy & Better, Example Geothermal Projects.

Without the 50% capital cost subsidy, and with a more competitive price for green ePower of $.095/kWh (i.e., 85% lower ePower price) and developing the project in one year (instead of the measured five-year development timeline of the subsidized project), the project’s IRR is a stinging MINUS 9%. That’s even after lowering the capital cost by $30 million—the amount being spent on closely monitoring for any induced seismic and other very nice, but not necessary at-scale, “science” projects.  Projects like this will need to do quite a bit better, if affordability is to be a criterion.     

Just what kind of advances would we need to make for HDR geothermal energy to be a money-making deal?  Just how far off are we from making that a reality?  Let’s see how big a jump we need; future columns will look at how realistic it might be to make the jump.     

The “better” project in Fig. 2 shows one example of what would have to change to achieve barely “OK” economics in 140⁰C rock.  The “better” project is notional, but it does scope the kind of improvement needed to achieve a passable 7% IRR, given the somewhat competitive ePower price of $0.095/kWh.  To achieve 6% IRR, a 25-year life project would need 50% greater output (i.e., 7.5 MW), all delivered at a 78% lower capital cost.   

So, all we have to do is increase heat output by 50% at 78% lower capital cost?  

Is HDR geothermal climbing a tree to get to the moon?  Making HDR geothermal economic (in 140⁰C rock anyway) is a big challenge but, shale DID make improvements of similar magnitude and became the new normal in many places.  It’s a challenge, but it could be possible. I’m going to list a few potential ways to increase heat output by 50% at 78% lower cost.  Future columns will explore the following in a bit more detail; but, to show that while challenging, this might not be impossible. Consider the following: 

• How to get 50% more heat out.  The Geo Energie Suisse project is based on 66% of the fractures working with a 1-km lateral.  How to get more heat out?  Some obvious ideas: 
• Increase lateral length – heat output is roughly proportional to lateral length.  These days, 15-kft (4.6 km) laterals are quite common.  
• Design and execute the fracture stimulation, so that almost all the factures are conductive. This project—probably prudently—assumes that one-third of the fractures will be nonproductive—e.g., there won’t actually be a flow path to the sister well.  Even without increasing lateral, good old-fashioned frac design and operations could increase the number of productive fracs. 
• Optimize sister well spacing to get better heat flow. Ideas like two injectors and one producer (or vice versa), or farther spacing to create more contact and conductive area are all options. Shale has played around and is still playing around with how to have the most “stimulated rock volume.” 
• Try hotter rock or go deeper—there is really hot rock everywhere, if you can go deep enough.  The efficiency with which you can extract useful energy is proportional to the temperature difference between the heat source and the sink. Future editions will discuss the effect on heat transfer, heat content and the thermodynamic effect of hotter rock. The effect is not trivial, which means learning how to operate in hotter environments has a nonlinear positive effect. 

There is a lot of room for improving how too much heat can be extracted from the subsurface.  The physics of heat transfer are pretty well-known; for any specific flow area, in any rock, the amount of heat that you can transfer to the surface is a junior year of Mechanical Engineering school problem. Specifying what is needed to get 50% more heat out is a matter of execution… it took time, but the unconventional guys improved the flow in their wells by a factor of 10x from the initial Barnett wells.  The project’s estimated output of 5 MW is probably prudent for Iteration One… but if shale experience has any validity, there will be loads of improvement possible. 

• How to reduce capital cost by 78%. To get this project nearly economic, big, big cost reductions will be needed. Are improvements of this magnitude even within the realm of possibility? How could this be possible? 
• Reduce well cost by 85%. The two wells cost about $30 million; to make this project economic without subsidies, the cost would need to be about $2.25 million, each.  How could that be possible? 
• Approach unconventional drilling efficiency; a well with similar depth and displacement in Oklahoma would not be $15 million… it’d be more like $2 million. Why? 

1. 1. Build economies of scale into drilling operations. We’d need to have “Permian” pricing for materials, services and rig rates.  Improve hot rock tools and techniques 
   2. Drilling operations would be much faster. 

• How to reduce surface facilities’ cost by 75%. The surface facilities for this project are estimated to cost about $90 million, they need to cost $23 million. Seems daunting, until you realize that the facility is a one-off design, being stick built and structured to handle many contingencies, given the uncertainty about fluids etc. The first large-scale ethanol plants, LNG re-gas facilities, provide history that shows with enough economies of scale, manufacturing then assembling onsite could provide cost reductions needed.   

I do not want any of the above to, in any way, cast a shadow on the Geo Energie Suisse project.  This is their first well—George Mitchell’s first shale wells were not so good.  These improvements will be challenging but do seem within the realm of possibility.  We will need to get on it.   

I’ll investigate the opportunities in the next column, but to summarize for now: The industry needs to make some pretty big advances to make HDR geothermal economically attractive without subsidies (at least for HDR of 140⁰C at about 2.5 km / 8 kft).  These advances seem daunting, BUT they are similar to the advances that we have actually made in shale.  Next edition will see what technical advances we will need to make this a reality.  

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 ideas, please email me at ford.brett@petroskills.com, and I promise I’ll respond.