April 16, 2020 § Leave a comment
I used to think geothermal energy was a niche play. And it was, until fairly recently. Or, to be fair, I became aware recently that multiple approaches were being investigated, all of which were scalable, albeit to different degrees. I define scalability to mean the ability to supply a material portion, and in the limit, a majority, of the electricity needs of the world at a price competitive with conventional alternatives.
The source of geothermal energy is the core of earth. Essentially a nuclear reactor, where temperatures approach those at the surface of the sun. The heat is conducted to the earth’s surface and eventually dissipates into our atmosphere. Harnessing this heat is the essence of geothermal energy production. Utility scale geothermal energy involves drilling a well, not unlike an oil well, pumping a fluid down, usually water, and then recovering the fluid heated by the subsurface rock to perform some work. That work is usually the generation of electricity. In short, we are mining for heat rather than oil or gas. The operations to accomplish this, and the underlying technologies, are identical to those used to prospect for oil and gas, except for the final power generation bit. To the extent that step out technologies are needed, these too are in the general realm of oil industry capability.
Oil and gas companies have recognized the need to diversify and become energy companies. Over a dozen years ago, BP’s CEO famously declared that BP stood for “beyond petroleum”. While premature, the sentiment still led to forays into solar and wind. Except for offshore wind having some synergy with oil company core competencies, these areas were not good fits as portfolio components. Accordingly, to this day, they comprise small portions of the companies.
Geothermal offerings fall into two buckets: those that operate in rock at 200 C plus and ones that require 300 C plus. In the former category fall Engineered Geothermal Systems (EGS). Because the heat content of the rock is relatively modest, inducements are needed for the heat to transfer to the fluid being circulated. This is accomplished with standard hydraulic fracturing. The twist is that existing natural fracture networks are utilized to advantage. The energy required to open existing fractures is much less than that to create new ones. Consequently, induced seismicity (the risk of creating an earthquake, and a concern that has been raised by observers) is very unlikely.
Induced seismicity requires a high energy input into an active fault. An active fault is roughly defined as a fault likely to move in response to an energy input. A fault is a mismatch between two bodies of rock, often created due to a movement (known as slip) of one body relative to another adjoining one. Continued movement in response to an energy input can create a seismic event, an earthquake. The magnitude of the earthquake is directly proportional to the length of the fault. As noted above, the energy from opening natural fractures (a common geological feature not to be confused with faults), is small. Furthermore, EGS operations require a thorough knowledge of the earth stresses, and so detecting faults and their lengths is straightforward. Avoiding operating in proximity to long active faults would mitigate earthquake concerns.
The second bucket is that of hotter zones, exceeding 300 C, most preferably 350 C. High thermal pickups by the fluid in the well can be achieved with well architecture that maximizes contact with the rock, and no hydraulic fracturing is involved. This would be a closed loop system, with the working fluid not entering the rock. If the temperature exceeds 374 C and pressure 221 bar, any water present in the reservoir would be in the supercritical state. This is a state in which it behaves like both a liquid and a gas. When CO2 is sequestered in porous rock, it is in a supercritical state, taking advantage of this dual property. A more mundane example is CO2 decaffeination of coffee beans: the supercritical state allows easy entry into the bean as a gas and dissolves the caffeine like a liquid. Supercritical water will produce more power than would steam.
EGS operations can be executed with the latest current technology. The deeper stuff needs development. The oil and gas industry is well positioned to do both. In fact, an aspect of the development of deeper systems is an extension of recent advances by the industry in high temperature, high pressure systems. One could argue that they are the only ones who could reasonably pull it off.
Now is the time. The oil industry (especially including oil service companies) is positioned to put geothermal energy into high gear. This would not have the appearance of greenwashing even to the most jaded. The federal government ought to help, although in the midst of Covid 19 recovery efforts, that might be tough. And yet, that pandemic is the reason (now that the Russia/Saudi spat is resolved) that the US oil and gas rig count has plummeted over 30% in just one month. Continued demand destruction could ensure a long-lived drop at some scale. That then, would be the time, to put people to work doing something else productive. If at the same time this work moves the needle on a renewable energy source the appeal is to both sides of the congressional aisle.
For the oil and gas companies, a sizeable geothermal portfolio (eventually) provides optionality. Since essentially the same crews can be used to drill for either oil or heat, portfolio shifts driven by market conditions are feasible. Forecasting the speed of adoption of electric vehicles will no longer be important. Good for the industry and good for the environment. Large scale win wins are often mirages; not this one.
April 16, 2020
September 4, 2022 § Leave a comment
California’s recent decarbonization legislation includes extending the life of the Diablo Canyon nuclear reactors in the face of environmentalist opposition. Their concern has been for the marine creatures potentially killed during cooling water uptake from the ocean. The dilemma posed in the title, similar to between a rock and a hard place, applies to the Diablo Canyon decision. A recent paper from Stanford and MIT details the issues and lands in the extended life camp with some twists discussed later here.
Back to the dilemma. No form of energy, clean or otherwise, comes without baggage. So, it comes down to compromises. Wind has avian mortality and visual pollution. Solar may carry the least baggage, but recent events pose a unique twist. The price of natural gas going up 5 and 6-fold in Europe due to climate change and Russian aggression shows that reliance on a global supply chain could be fraught. In context, over 60% of solar panel components originate in China. Sabers are rattling in the Taiwan Strait. No telling what happens to solar panel costs if things escalate.
More dilemma: opponents of the decision want to simply build more solar and wind capacity. Even Senator Dianne Feinstein weighed in with the opinion that absent the Diablo decision there would be more natural gas usage. Exactly right, especially if the course of action proposed by opponents, more solar and wind, is followed. This is because solar and wind have low capacity utilization due to diurnal and seasonal gaps in output. At this time these gaps are dominantly filled by natural gas power generation. In other words, more solar and wind means more natural gas burned until carbon-free gap fillers, such as advanced geothermal systems and small modular (nuclear) reactors, hit their stride. And that will take a decade. In the meantime, Diablo Canyon 24/7 output notwithstanding, natural gas will continue to increasingly be used in step with addition of solar and wind capacity. A mitigative measure on the associated CO2 production would be carbon capture and storage attached to the natural gas power plants. The best-in-class technology achieves this for USD 40 per tonne CO2. One of the new California bills encourages this direction. It is opposed on the grounds that it encourages more fossil fuel production. True. But, as noted above, until carbon-free gap fillers are at scale, natural gas is the only practical alternative. Rock and a hard place.
The two plants at Diablo Canyon account for 9% of the electricity and 16% of the carbon-free electricity for the fifth largest economy in the world. Removing it would make already tough zero emission goals almost unattainable, certainly the 2030 ones. This state is currently in an epic heat wave causing power demand spikes. It is also the state most vulnerable to climate change driven forest fires. It can ill afford to take out any carbon-free capacity, especially if the concerns expressed on Diablo Canyon continuance can be met by other means.
Enter the Stanford/MIT paper. It has explicit engineered solutions to minimize marine life extinction in the water procurement. It also has two other interesting suggestions to maximize the environmentally related value of Diablo Canyon. One is to use part of the output to desalinate seawater. The measures taken to protect marine life would apply here as well during the water acquisition. Since reverse osmosis produces a highly saline wastewater, the disposal in the ocean would need to follow means to minimize damage to sea bottom species. These are known methods and simply need adoption.
The other suggestion is to electrolyze water to produce hydrogen. This would be considered green hydrogen because the electricity was carbon-free. Power is employed in this way in Europe during periods of low demand. There they are piloting adding a 20% hydrogen cut to natural gas pipelines, to reduce fossil fuel use. A point of note is that the electrolytic process requires 9 kg fresh water for each kg hydrogen produced. While green electrolytic hydrogen is seductive, especially when using electricity during period of low demand, fresh water is in short supply in many areas, especially South/Central California. Could be a reason for the Stanford/MIT report suggestion regarding desalination at Diablo Canyon.
Aggressive decarbonization strategies will come with tough choices. An easy one is to target “carbon-free” rather than “renewable” energy. A harder one is to tolerate bridging methods, such as natural gas power with carbon capture and storage. The trick is to ensure that the bridges* are to definite targets. With sunset clauses.
September 4, 2022
*A bridge over troubled water, from Bridge Over Troubled Water, Simon and Garfunkle (1970)
August 11, 2022 § Leave a comment
For the longest time blue had been content as a pure spectrum color at a nominal wavelength of 450 nm. Then the hydrogen police said it was not green enough. This despite Kermit the Frog informing us that it was not easy being green. Apparently, Britain agrees with Kermit, as reported in an Economist story. Their hydrogen strategy is heavily loaded with blue.
First a reminder on definitions. When hydrogen is synthesized by reacting methane with water, the process known as steam methane reforming, it is classified as grey hydrogen. If the resultant CO2 is captured and stored, the color of the hydrogen turns blue. If the hydrogen is produced from splitting water electrolytically using green electricity, it is classified as green hydrogen. To confuse matters further, the Government of India has classified the blue hydrogen from methane reforming as green if the methane is biogas sourced.
Going back to the Economist story, Britain has called for hydrogen to be 4% of energy demand by 2030. Even at this relatively modest target, the green electricity required for this hydrogen to be green would be 126 TWh (terawatt hours). This compares to the total green electricity production in 2020 of 135 TWh, with many potential uses beyond electrolytic hydrogen. In fact, one of the uses planned is blending hydrogen to a 20% level in natural gas pipelines. Mainland Europe has been piloting this and there is a consensus that a 20% blend is tolerated by the pipelines and by the end use.
The British plan calls for production of blue hydrogen in two locations with industry such as ammonia and methanol production that already uses grey hydrogen. Carbon mitigation in industry takes two forms. One is to change the process by replacing the existing reactant, such as coke, with hydrogen, thus curbing or eliminating CO2 emissions. One such is ironmaking with the Direct Reduction Iron process, and the resulting steel would be considered green steel if the hydrogen were to be green. Steelmaking is specifically cited by the British plan.
The other approach is to not change the process, but simply substitute a zero-carbon hydrogen for the grey hydrogen. The British plan favors blue hydrogen as a pragmatic means to achieve carbon mitigation faster than may be possible with just green hydrogen. This plan relies on economical means for capturing and storing the CO2 from the methane reforming. This is increasingly a reasonable expectation, with technology already commercial and likely to be available at scale within a couple of years. Economical is defined as fully loaded cost lower than the carbon penalty in force at the time. This is variable and stands at about €85 at this writing (see figure). A leading carbon capture technology claims capture costs at USD 40 per tonne, with an expected reduction to USD 30 over time. Given that geologic storage costs about USD 10 per tonne, the combined figure is well below the carbon penalty.
The Good Before the Great
Few would dispute that the most desirable hydrogen is the green variety. Here too a relaxation must be sought for the strict definition. The electricity source ought to be expanded from renewable to carbon-free. The carbon mitigation purpose is served and scalable carbon-free sources such as geothermal energy and nuclear power are then comfortably included. As previously discussed, these are excellent fillers of the diurnal and seasonal gaps in solar and wind production.
But green electricity is in short supply compared to the demand. The primary reason is that the largest sources, solar and wind, have low capacity utilization. On the demand side, everybody wants some. The MIT spinout Boston Metals needs it to make electrolytic green steel. The other principal green steel method, DRI, needs electrolytic (green) hydrogen. Data centers supporting the cloud are energy hogs that are growing steeply. All the major players in that space want green electricity. Ditto for bitcoin that other fast growing energy intensive sector. In other words, relatively sparse green electricity has many calls on it.
Enter blue hydrogen. The case against it begins with the fact that only 90 to 95% of the CO2 is captured at the point source. Some is still released. The other knock on it is that natural gas production is implicitly encouraged. But the uncomfortable truth is that every new solar/wind emplacement already creates demand for natural gas to fill the longer duration gaps in output. Although coal and oil will continue to decline, natural gas will be needed as a gap filler till the zero-carbon alternatives hit their stride; and that is a decade or more away. That is plain and simple pragmatism. As is the need for blue hydrogen until green electricity becomes more easily available. It is the only viable near-zero-carbon hydrogen that can achieve scale swiftly.
The battle against climate change must be joined with the best weapons at hand. No active battlefront waits on the ultimate weapon. Blue ought to be the primary color of hydrogen until, again quoting Kermit*, being green is easier.
* It’s not easy bein’ green Kermit the Frog, written by Joe Raposo, sung by Jim Henson (1970)
July 21, 2022 § Leave a comment
There is a new sheriff in Energy Town. In much of the world, solar and wind are the lowest cost source of power, clean or otherwise. They are effectively the new base load to which all other sources of energy must fit. And fit is needed.
Dunkelflaute is the German word for periods with no wind and no sunlight. A more fanciful definition is dark doldrums. Navigating doldrums has always been hard for sailing ships. So it is for electricity production in periods of Dunkelflaute, which are substantial year round, because solar and wind utilization peaks out at monthly averages of 25% and 40% respectively, with annual medians at lower figures. The figure shows capacity factors for wind-based generation in the US. Capacity factor is essentially the efficiency of utilization of the nameplate capacity (maximum rated output). Solar energy has similar characteristics in terms of seasonal variation, with annual median capacity factors closer to 20%.
The list is short for clean energy sources for navigating Dunkelflaute: geothermal energy, small modular (nuclear) reactors (SMRs) and innovative storage systems. Sure, pumped hydroelectricity and other forms of gap pluggers exist, and may even be cost effective where available, but they are not scalable.
Seasonal variability of wind in Texas 2001-2013
A feature desired for all gap fillers is the ability to load follow. This means ramping up or down in response to demand on a dynamic basis. Advanced geothermal systems, in late-stage development, can load follow without impairing operations. So can SMRs. One reason that the conventional means for gap filling, natural gas fired generators, are so effective is that gas turbines can spin up or down with minimal energy penalty.
Economics of Gap Filling
There are two types of gaps, diurnal and seasonal. Solar has more diurnal variability than wind, and the most well-known gap is the 4-6 hour one in the evenings. This is filled with batteries and this practice will likely continue. The cost for this in the vicinity of 2 cents per kWh, which effectively doubles the solar based cost in places like Los Angeles. A recent study of several grid systems in the US and Europe by the Rocky Mountain Institute1 has shown that batteries alone will be very costly for the last 50% or so of achieving 24/7 clean power. The numbers go well over 10 cents per kWh on the PJM grid in the northeast US. In estimating the cost of gap fillers, investigators and commentators must resist comparing costs with those of solar and wind. The comparison must be with the conventional gap fillers, and that means aiming for less than 15 cents, and possibly less than 10 cents per kWh.
A frame of reference for this choice is the cost of the most common gap filler, natural gas combined cycle (NGCC). With a relatively low capital cost contribution to the delivered cost (20% as a rough average), the cost of natural gas is the dominant factor. At natural gas cost of USD 5 per MMBTU (which is the energy content of roughly one thousand cubic feet of gas), the dispatched cost from the producer will be about 5 cents per kWh. I am using that figure for natural gas cost because I expect that number to not be exceeded (except in short upset conditions such as the Great Texas Freeze) because of abundant shale gas.
But for comparison with zero carbon power gap fillers, one needs to remove CO2 from the NGCC process. Technology available today, but not yet at scale, ought to remove 90% plus for USD 40 per tonne CO2, with another USD 10 for geologic storage. That adds about 2.4 cents to the NGCC tab, bringing it to 7.4 cents per kWh in the US example above. Note that gas price in Europe has always been over double that in the US, and today it is at 6 times, making the associated dispatched cost that much more expensive. The point is that a global figure for a true zero carbon gap filler could conservatively be 15 cents per kWh, with an aspiration target of 10 cents over time.
How realistic is that? Very, according to leading developers of advanced geothermal systems and SMRs. At least two of the geothermal folks, Fervo Energy and SAGE Geosystems, have near term plans for commercial installations, at a Google data center and Ellington Air Force base, respectively. At least in the case of Fervo, we will know by 2024 whether the claimed costs of well under 10 cents per kWh are realized. In SMRs, NuScale is also claiming numbers well below 10 cents, but the first installation will not be until 2029.
Role of Hydrogen
Load following has one shortcoming. When not needed, the utilization is lower. In Texas, for example, in the period 2012-2019, capacity factors for NGCC varied from 48% to 57% in response to solar and wind-based delivery shortfalls relative to demand. Over 80% of the cost of electricity from an NGCC is variable cost, dominated by the price of natural gas. Lower capacity factors are more tolerable than they would be for conventional nuclear power, where capex dominates the economics.
Both advanced geothermal and SMRs have relatively low fuel costs, especially geothermal. Load following though they may be, the capital is more effectively amortized if the electricity during the idle periods is utilized in some fashion. The obvious option is storage, but that awaits innovation for systems suitable for long periods.
An option acquiring some currency is production of electrolytic hydrogen. Considered green hydrogen, the value would be high. But the onus of low capacity factors now shifts to the electrolyzer. Here there can be some relief, in that these units can be relatively small and considerable research is ongoing to reduce both capex and opex costs. The low capacity factor piper must be paid, but this seems like the most cost effective stopping point in the toppling dominoes. At scale, the problem of adequate clean water supply for electrolysis becomes an issue. But another variant on the use of idle gap fillers is for enabling desalination plants.
The hydrogen could certainly be stored and used to generate power as a gap filler. But there are higher value uses. One would be to blend into natural gas pipelines to reduce fossil fuel usage. Blends up to 20% are known to be pipeline and end use tolerant and are already being piloted in Europe. Another high value use is in the production of ammonia for several applications, fertilizer being the largest. Transporting ammonia is cheaper than transporting hydrogen, so the ammonia would most profitably be synthesized near the hydrogen production. Recent advances in cost-effective small-scale ammonia synthesis will enable this option.
Carbon-free power grids are certainly in our future. How many, how soon and to what degree, that will depend on technology, policy enablers and appetite for investment. But even this is just one skirmish in the battle against climate change*.
*All in all, you’re just another brick in the wall, from Another brick in the wall (1979), performed by Pink Floyd, written by Roger Waters. This is my interpretation of the lyrics, not the standard one.
1 Dyson, M, Shah, S, & Teplin, C, Clean Power by the Hour: Assessing the Costs and Emissions Impacts of Hourly Carbon-Free Energy Procurement Strategies, RMI, 2021,http://www.rmi.org/insight/clean-power-by-the-hour
November 7, 2021 § 3 Comments
A recent New York Times story cautiously lauds a Russian effort in Siberia to provide heat to a seaside community from a floating nuclear reactor. Two concepts are in play here. One, which is common to all forms of electricity production, is the use of the relatively low-grade heat of the working fluid following turbine operation for electricity. In some cases, this is known as combined cycle. The energy in the heat can often be nearly as much as that in the generated electricity. This part is not new. The relatively new bit is that the reactor is a small one on a barge and could reasonably fall in the classification of small modular reactors.
Small modular reactors (SMR’s) have been around for about two decades, but none are in commercial operation. My first encounter with these was about twenty years ago. A couple of scientists from the Los Alamos National Laboratory came to visit me at Halliburton. They claimed to have an SMR with about 30 MW output of electricity. The key features were that they were safe from runaway by the very nature of the nuclear design and that the whole unit could be placed underground in a chamber. The fuel rods would need to be replaced only every 5 years, with a future target of 10 years. The location of the reactor made it relatively immune to terrorism. This was necessary in part because the intent was to distribute them in communities. The modularity would enable mass production. And unlike conventional nuclear installations, everything would be built in central locations and subassemblies would merely be put tother on location.
I wanted to use the concept in heavy oil recovery in Canada. Steam is conventionally generated on site by combusting natural gas and is essential for inducing mobility to the viscous oil underground. The steam plant is a big CO2 generator and is in large measure responsible for the high carbon footprint of heavy oil. In my concept, the lower grade steam after power generation from the SMR had ample sensible heat for use downhole. The Los Alamos concept became the company Hyperion, but simply did not get off the ground for our use.
Now several players have the joined the fray, including large ones like Toshiba and Westinghouse. A big issue will be societal acceptance. Not in my back yard (NIMBY) will be replaced by NNIMBY, with the first two words being No Nuclear. Education on the safety of these compared to the old ones at Chernobyl and Three Mile Island will be key. It will still be a struggle in some countries. Germany painted itself into a corner by banning all nuclear after the Fukushima Daiichi tsunami disaster. I imagine the ultra-low probability of tsunamis in Germany was not a consideration, just the reported intransigence of the Green Party holding sway. In the NY Times story town residents bathing in hot water from the reactor complex do worry about the source. The explanation of fluid contact-less heat exchangers appears to be winning the day.
Here is an irony regarding the phobia for water from such a source. Iceland gets much of its day-to-day use energy from hot water from geothermal sources. Folks soak in the geothermal pools there and all over California, Nevada and Wyoming. Medicinal properties are attributed. The source? That giant nuclear reactor at the center of our earth. OK, to be fair, there is a heat exchanger in play. The heat is conducted through the mantle and only then contacts a water source, which is then transported to the surface via faults in the rock.
The current crisis with unprecedented natural gas prices has people wishing for more nuclear, and bemoaning policies such as those in Germany. But conventional nuclear is costly compared to solar and wind, especially after the augmentation and storage issues are resolved. Curiously, US Secretary of Energy Granholm announced at the COP26 meeting that the US believes in small modular reactors. She plans “to make sure they are less expensive (than conventional reactors)”. I think that goal is more likely in greenfield situations like India, where some savings would be from not having a grid. The greatest savings will be from mass manufacture of the sub-assemblies in central locations, with just final assembly on the site. In traditional nuclear power generation capital represents 74% of the levelized cost (compared to 22% for natural gas). SMR’s are intended to directly address this cost.
Governments ought to consider enabling multiple emplacements of SMR’s through financing and fast permitting, thus speeding the road to mass manufacture, and steepening the glide path to low costs. The Indian government did this with LED lighting and now has some of the lowest cost devices in the world.
November 7, 2021
May 31, 2021 § 2 Comments
This is the story of a minority investor attempting to influence the direction of ExxonMobil to be more climate conscious while being even more profitable. Engine No. 1 (evoking childhood images of the Little Engine that Could) pulled off the improbable. With less than 1% shareholding, they persuaded major players such as BlackRock and the California State Teachers Retirement System (a major pension fund) to go along. Two of their slate of four nominees have been elected and another is possibly on the brink. Management resistance had been acute; much money was spent in opposition. This was seen as a defeat for the Chairman and CEO.
This is New York Times front page news. ExxonMobil’s deteriorating earnings performance certainly helped the insurrection. In a fireside chat with my economist son @justinrao, I was asked whether this would work. Another NY Times piece opined it would not, and that 2 in 12 directors would simply not have the votes to accomplish anything. This is simplistic thinking. A board is not the US Senate (remember the days when senators were collegial and actually listened to opposing viewpoints; well, those days are gone). Each member of any public board has a fiduciary duty to the shareholders. They are on the same team. Usually, important direction setting is given to a subcommittee to research and report on the matter. The report is debated, and a board consensus is achieved. If the new members command the respect of the others, and they are not too radical in their approach, change is possible. The new members are “independent directors”. For those not in the know, independent directors are defined as those not having a material association with the company. Certainly not officers. But also, not employees of the investment groups. There are shades of gray, but independent directors are seen as not influenceable, hence the term.
All change will have to meet the conditions of duality of earnings growth and some other softer objective, in this case carbon mitigation. These are early days in the battle for climate preservation. Relatively low hanging fruit ought to be available. Were I one of those new directors, I would request scenarios to be produced. Scenarios are not predictions, they are more in the form of what-if exercises, and particularly useful when strategizing in an uncertain environment. These would be guides to at least a provisional strategic direction which yields good returns while meeting climate change objectives. The latter would be seen as likely societal outcomes directing company behavior, not ideological.
The future will almost certainly entail reduction in oil usage, with the only debate centering on rate of change. Certainly, both Shell and BP are betting on that outcome. While this is a carbon mitigation direction, from a board perspective it is a demand signal needing response. In this example, the response would be to plan on oil production reduction while investing in electricity, which will be the “fuel” displacing oil. ExxonMobil has stated that entering the renewables arenas is contraindicated because they have no edge in that space. I agree with this view when it comes to production of solar energy. Not so much on wind, where they could have an edge in the emerging application of deeper water production, for which floating platforms will be needed. This last is where they have deep expertise. California has a sea floor that drops off precipitately. Floating production is very likely.
Rather than participating directly in the production of renewables, they could innovate in the space of filling a critical gap in renewables: the handling of diurnality and peaks and valleys. Germany derives 40% of its electricity from renewables. This is an average figure. On a given day that number could be 15% or 75%. A recent solar bid accepted in Los Angeles had a direct solar output price of about 2.3 cents per kWh. But the battery back up added nearly 2 cents to that. Enabling renewables requires a storage solution. As evidenced by the LA figure, basic solar is becoming the low-cost standard. In my view it is headed to commodity status. The profit will lie in solving storage. In that area, companies such as ExxonMobil are well stocked in science and engineering talent. Production of electrolytic hydrogen during periods of excess is one of the candidates. So, is ammonia. Both are staples of ExxonMobil downstream operations. They could do this more profitably than most.
My favorite renewable for oil companies to consider is geothermal energy. It is fast reaching feasibility at scale. It is also the only renewable of which I am aware, which is both base load scale and load following. Load following essentially means tunable to demand. No storage required. Most importantly, for oil companies, the core competencies are the same as for oil production. Furthermore, the personnel laid off due to reduction in oil production could simply be switched to geothermal.
There is profit in renewables, you simply must pick your spots. The new directors could educate the rest on these points. As for the CEO, sometimes a win follows a loss. Sometimes you get thrown into the briar patch*.
*How Br’er Rabbit snatched victory from the jaws of defeat, literally the jaws of Br’er Fox. Br’er Rabbit and the Tar Baby, a Georgia folk tale.
April 16, 2021 § 5 Comments
Transportation has bad climate change related PR. All sectors combined (including aviation) account for about 13% of global CO2 production, whereas just steel and concrete add up to 15%. Estimates vary, but inescapable is the conclusion that we have not given steel and concrete the attention that we have heaped on transportation to mitigate CO2 production. To exacerbate matters, the world is on an infrastructure expansion spree, including more recently the Biden administration in the US. More infrastructure equates to more concrete and steel. That is more CO2 emissions. Unless we do something about it as we have with electric vehicles and hybrid vehicles.
Mitigating CO2 emissions from concrete and steel is more straightforward than from vehicles because they are what we refer to as point sources. Vehicle tailpipes are distributed, making capture, and disposition of the CO2, prohibitively difficult. Technically doable with pressure swing adsorption methods, but logistically tricky in release to regenerate the adsorbent and subsequent handling of the CO2. A decent analogy is NOx capture with urea, requiring canister replacement, a nuisance to many consumers. This difficulty led to alternative non-intrusive means such as the Lean NOx Trap, with the attendant VW deception.
First a bit of a primer on iron and steel making. Iron ore is largely iron oxide and must be reduced to iron. This is accomplished primarily in blast furnaces, which are shaft furnaces where the reactants are fed at the top and the metal is taken out of the bottom. The iron oxides are reduced by gases produced from coke, which is a derivative of coal. The reaction products include iron and CO2. The iron is then converted to steel by reducing the carbon content and by addition of other alloying elements for properties such as strength and corrosion resistance. Each metric ton (tonne) of steel produces a staggering 1.8 tonnes of CO2.
The Direct Reduction Iron (DRI) process is a means for reducing the carbon footprint. The process temperatures are low, and the iron never in a molten state. The reducing agent is syngas, a mixture of CO and H2. The combination reduces the emissions to 0.6 tonnes CO2 per tonne steel. In a variant, hydrogen alone is the reducing agent, and in a further green variant, the hydrogen is from renewable sources such as electrolysis of water using renewable electricity. However, unlike in the blast furnace process, there is no mechanism for removal of impurities in the ore. Consequently, only high-grade iron ore is tolerated, and this limits DRI to about 7% of the total market because such ore is in relatively short supply and much more costly.
The most promising route to the greening of steel is through CO2 capture at the blast furnace. Unlike flue gases from a power plant, blast furnace flue gas is concentrated, typically 30% CO2. As a result, removal processes are more effective. Today we are on the brink of capture costs below USD 40 per tonne CO2. Carbon credits may be purchased in Europe for about USD 55 per tonne. A recent New York Times story suggests that this will keep rising, with one analyst predicting prices above USD 150. If a major CO2 producer such as steel or cement is forced to buy credits, the price is certain to go up. When the capture cost is below the price for credits, the industry has an incentive to simply collect the gas. However, merely capturing accomplishes little if the gas is not permanently sequestered in what are known as sinks.
One such sink is subsurface storage in oil and gas reservoirs depleted of the original fluid, or in saline aquifers. While feasible, often with costs lowered by using abandoned wells, debate centers on permanence of the storage and the risk of induced seismicity (earthquakes). A variant with an important distinction is injection into reactive minerals such as basalt, with the formation of a non-water-soluble carbonate, which certainly is permanent. However, these wells are more costly because existing abandoned wells are unlikely to be in locations with suitable mineralogy. The exception to that would be abandoned geothermal wells, which could be proximal to igneous rock from the basalt family. However, there are not too many of those, and they are geographically constrained.
Mineralization as a genre is being pursued vigorously, with systems already commercial, although the tonnage being sequestered is still low. Done on the surface in reactors, the resulting carbonate of Na, Ca or Mg can have uses. Monetization even at small profit still renders the capture cost effective. Since, in my opinion, capture costs are heading in the right direction, and already at acceptable numbers, the focus ought to shift to sinks with scalability. Scalability is usefully defined as an aspirational goal of 0.5 gigatonnes CO2 per year by 2040. But goals short of that are fine if several approaches are proven viable.
Endeavors to achieve these goals could be materially assisted by appropriate policy action by the various federal governments. All forms of renewable energy have received subsidies or loan guarantees at some stage in their development. This has resulted in wind and solar being an established part of the electricity portfolio. Similarly, electric vehicles have received subsidy support. The greening of steel and cement ought to receive the same attention. For example, the Biden administration’s infrastructure bill ought to include provisions for preferential purchase of green steel and cement, at premium pricing.
Technology is approaching a tipping point for serious inroads into making steel and concrete green *. Public policy must keep pace.
*For the times they are a changin’ from “The Times They Are a-Changin’” performed and written by Bob Dylan, 1964
April 16, 2021
August 20, 2020 § 4 Comments
Oil drilling leases will soon be available in the Arctic, according to a story in the New York Times. The Alaska National Wildlife Refuge (ANWR), a land-based portion of the Arctic, is cited. But the Arctic is cold, both figuratively and literally. When he took office in 2017, President Trump announced a roll back of a “permanent” ban on Arctic drilling that President Obama instituted as he was leaving the White House. I opined then that the roll back would have no net effect because interest from oil companies would be minimal. I also wrote at the time that President Obama’s action was also largely symbolic, and not material.
The principal reason for these conclusions is that the price of oil has been low since 2015, when US shale oil became the determinant of oil price in the world and the ability of the Organization of Petroleum Exporting Countries (OPEC) to prop up prices was deeply undercut. USD 120 per barrel highs became USD 70 highs. The Covid-19 pandemic has decimated shale oil company ranks, but it has also caused demand, and price, to plummet to historic levels. Accordingly, the crystal ball of future oil prices is murky. Murky crystal balls equate to uncertainty, which, added to the environmental risks, further equates to higher discount rates. Making matters worse on the investment side, any Alaska play has a long-term payout. First oil is likely a decade after the lease purchase. This involves forecasting the price of oil into the second half of the century.
All the indications are that oil demand will reduce significantly by 2040, largely through electric vehicle adoption. Certainly, the super-major oil company BP’s beliefs in this regard have translated into plans for a major replacement of oil revenue with revenue from renewable electricity. They recently announced that by 2030, their oil production will be reduced by 40%, concurrent with major investment in renewables, resulting in 50 GW electricity production. That production is up there with good size electric utilities. This decision also comes at a time when the dividend has been halved and properties divested to raise cash. It also is coincident with the divestiture of their pioneering Alaska North Slope holdings to privately held Hilcorp, during which transaction they sweetened the pot with a loan to ensure closure of the deal. This does not sound like a company that will invest in a US Arctic lease. I do not see any oil company headquartered in Europe doing it either.
Hydrogen is an important industrial commodity even not counting the possible use as electric vehicle fuel. US refineries purchase 2 billion cubic feet per day of hydrogen (in addition to using another 0.5 billion cubic feet produced internally). Virtually all of it is produced from natural gas. As we discussed in these pages earlier, hydrogen produced using surplus electricity during low demand periods is one of the most promising solutions for the problem of intermittency of renewable electricity. Oil companies like BP, doubling down on renewables, are unlikely to miss this point. Also, if conversion to ammonia is more appropriate for storage and transport, who better positioned than an integrated major oil company? In its announcement, BP makes a vague reference to hydrogen. No mention is made of geothermal electricity, but it is highly unlikely they are not watching that space.
Returning to the issue of success of a lease sale in the ANWR, one of the primary challenges is the paucity of high-quality seismic data. These are subsurface images acquired by individual oil companies in proprietary shoots or by seismic operators speculatively shooting to then sell subscriptions to the data in “libraries”. The acquisition and interpretation of the data is the edge employed by oil companies in obtaining the winning bids without overpaying. Less data means more uncertainty. My take on the situation is that there will be fewer bids due to competing capital spend directions, the uncertainty in the price of oil, the environmental risks, and the delays likely due to litigation (case in point the litigation based delays in the Keystone XL oil pipeline construction). But whatever bids that materialize are likely to be low-balled. In that case, the revenue from the sale will be underwhelming. This assumes, of course, that the administration goes ahead with plans to auction the tracts. More than likely this is just another tempest in the Alaskan teapot.
August 20, 2020
April 9, 2020 § 3 Comments
A webinar conducted by the Research Triangle Cleantech Cluster this week, in which I participated, triggered this piece. Some points made by the other three panelists Ivan Urlaub, Renee Peet and Gary Rackcliff are reflected here, but I take responsibility for this product.
For purposes of this discussion, energy falls largely into two buckets: electricity and oil and gas derivatives. In the last two months or so, the price of oil has halved. Part of the driver was the Saudi/Russia spat, which is likely to end soon because neither can live with USD 23 (price at the writing) oil for long. But the “shelter at home” policy in much of the world has slowed industrial output to a dull idle. Gasoline and jet fuel use has plummeted. Electricity usage has dropped. Here we will discuss the likely longer-term implications, especially as relating to energy. Some of the issues addressed arise from questions that were asked in the webinar mentioned above. Here is a crack at a list of outcomes that I see as highly probable. A modicum of support is also offered for the assertions.
- Electricity from renewable sources will not take a hit, except for diminished access to capital due to federal loan paybacks and the availability of workers for production and installation. An uptick in this space is possible, in which case closer attention to storage will be required.
- Distributed electricity production, with associated microgrids, will remain unaffected, except for capital constraints. Non reliance on a grid makes this segment attractive for resiliency in the face of disasters such as forest fires and hurricanes, but that sort of resiliency is less applicable to this disaster. To the extent that current deployments are in underserved communities, especially in low- and middle-Income countries, oversupply is unlikely because the supply usually just barely keeps up with demand, or the potential demand of increased productivity.
- Electricity suppliers with a heavier footprint in smart features, such as remote monitoring of home usage, are benefitting during this crisis because so much service can be provided without deploying personnel. Post crisis enthusiasm for these features, leading to wider adoption, is likely. This can only help with resiliency as well and ultimately with enterprise profitability. Compared to other power industry investment, the scale of this one is small.
- Oil prices will hover in the range USD 30-50 per barrel, with possible excursions to USD 25, with considerable volatility. For the first time in a Very Long time, Texas producers may agree to a cap on production. The Texas Railroad Commission, which has had nothing to do with railroads since 2005, regulates the industry. Prior to OPEC, they were the determinants of oil price. Production controls, whether mediated by the TRC or not, are likely to return. Were that to happen, and if Russia and the Saudis reciprocate with production cuts, oil price could well be in the upper reaches of the range noted above, once the economic recovery is in full swing. The US government has also announced a purchase of 77 MM barrels of oil for the Strategic Petroleum Reserve (SPR). Since the SPR is depleted by about that amount, this would top it up. The average cost of the current reserve is USD 28. If they go through with it (funding for it is in doubt) the new oil will likely be at a similar price. I have blogged previously that the SPR is not really needed any more, that shale oil in the ground is the reserve, but this could help prop up the price at a bargain cost.
- In not agreeing with OPEC on production restraint, Russian intent was to kill US shale oil. Shale oil will be wounded, but not killed. As in the last plummet in oil prices in 2015, highly leveraged players will declare bankruptcies. The properties will be scooped up by the major oil companies for dimes on the dollar. With deep pockets, the majors will simply keep shale as a portfolio item and unleash when profitable.
- The short- to medium-term reduction in shale oil production will reduce associated gas production. After the winter of 2020, natural gas prices will begin to firm. This firming will not be enough to reverse the attrition in coal demand for power.
- Electric vehicle (EV) adoption rate will not materially be affected by the drop in gasoline prices, no matter how sustained. The fully loaded cost of EV fuel is dominated by cost of amortization of the batteries. At a battery cost of USD 100 per kWh, as forecast by Elon Musk for next year (he actually said 2020, but I will cut him some Queen Corona slack), a 200 mile range EV will have a fully loaded cost of about USD 1.50 per gallon equivalent. This is based on a lot of assumptions, but the electricity “variable” cost is between 17% and 30% of that figure. The main takeaway is that unless gasoline price drops to a sustained USD 1.50 or lower (unlikely in most of the US, very unlikely in California and incomprehensible for Europe), gasoline pricing will have little influence on EV adoption. If a battery swapping model is adopted (where the consumer does not own the battery and swaps a charged one at each “fill”), the pay as you drive concept will be appealing, with lower car purchase cost and lower per mile cost.
- EV adoption rate is on the upswing, but still hard to predict. Oil and gas companies would do well to diversify their portfolios into electricity, which has other markets as well. This has indeed been happening for a while. But wind and solar don’t fit the core competencies of these companies. A relatively new entry is scalable geothermal energy. The operations are not only a fit, but oil (and oil service) companies are uniquely positioned to speed up the entrée and scale. Once in their portfolios, they can balance them based on the EV adoption rate, much as they currently do with their oil versus natural gas components.
- Remote working will have some measure of sustained adoption post apocalypse. It is being “field tested” by outfits that may not have used the mechanism in the past. Some may find that it is cost effective. I remember when Shell Oil went to a 10-hour day, four days a week, in Houston to reduce commute miles and associated emissions. Remote working is that on steroids. During this emergency each company will have sorted out which functions (and persons) are suited to this approach. They can take an informed view on adoption.
- Virtual meetings will have an even greater adoption rate. Technology has kept improving, but inertia or conservatism has kept adoption down. Now, with the enforced testing regime, informed decisions will be made. I see a strong uptick in this area. Winners are IT connectivity companies. Losers are airlines. Business travelers are the most profitable passengers on a plane.
- Both the above will reduce use of oil derived liquid fuel. Depending on scale this demand destruction could materially affect the price of oil. Natural gas pricing will remain unaffected; different markets served.
One, somewhat off topic outcome is rise in public empathy, and possibly altruism. When behaviors such as these are entrenched for months, they are more likely to stick. This is good. The (positive) irony would be if the pandemic caused “a contagion of good example” to spread. From an entrepreneurial standpoint, innovations in enabling this trend could be effective.
April 9, 2020