Christophe Pochari, 2022
Note: Explosive drilling is not an really invention, it is an old technology initially proposed by the Soviets in the 1950s. Hydrostatus Systems in its knack for identifying ignored, missed, or abandoned opportunities, improved upon it by making a number of important contributions. Starting with the choice of over-pressurized gas as a working fluid rather water, employing a suction based spoil removal method, and using solid rather than liquid explosives. These three design changes should be overlooked as mere trivial options, they are fundamental to the viability of this unique technology. The original developers of this otherwise sound concept faced issues that are solved by the implementation of these three design options.
Brief introduction: Hydrostatus Systems has revived a long-forgotten technology by making a number of improvements to the fundamental process, resulting in a new and powerful method to excavate rock without having to resort to technically challenging melting or vaporization methods. Capsulized insensitive solid explosives mass produced for only a few dollars per kg are fed into a shaft encased within the drill “string” and detonated upon the force of impact. Spoil removal is performed using a highly novel suction device within a gaseous over pressurized drilling media. The use of a gas at a pressure above the background water pressures retains the advantages of oil or water based fluids in preventing the influx of unwanted liquids, but allows for much improved fragment recovery and hugely drilling speed. After each detonation, a suction nozzle that generates a 1-2 bar pressure drop is descended into the fragment bed to rapidly evacuate the fragments generated from the previous explosion. While the method is not necessarily cheaper in terms of up-front costs than current technology, it can perform for a longer endurance period without bit replacement and it can penetrate trough hard rock in the brittle-zone at least 10 times more than conventional diamond bits using down-bore motors. The average drilling speed of a diamond bit down-bore motor drill in hard crystalline bedrock is 2.3 meters per hour, this method can excavate as much as 100 linear meters per hour as long as the rock does not yield plastically. The method is most productive in the hardest rocks, exactly where geothermal resources are most propitious. Out of all the present drilling concepts put forward, this is by the most likely candidate to enjoy commercial success on the basis of its simplicity and the maturity of the underlying methodology Compared to the “Plasmabit” marketed by the Slovakian company GA drilling, or the “millimeter wave” drilling system proposed by Quaise, explosive capsule drilling is the most viable for a up to 12 km crystalline rock drilling technology. Issues with thermal degradation, molten rock accumulation, inefficient energy delivery, among many others, handicap thermal drilling systems for the foreseeable future. This leaves us with novel mechanical disintegration methods. Among mechanical means, explosive drilling is simply without peers. Chemical high explosives possess the greatest density of storable kinetic energy of any known technology other than nuclear weapons. Their ability to release immensely high velocity pressures waves afforded unparalleled destructive facility.
Summary and key findings.
#1 Explosive capsule drilling to this day remains the only successfully tested alternative to rotary bits. Other alternatives such as microwave vaporization face a number of potentially insurmountable technical problems.
#2 High flow water cooling can maintain explosive capsule temperature at 100°C or below keeping decomposition to a minimum. Geology, rather than temperature, place a feasible upper limit of 12 km due to the brittle-plastic transition zone encountered which causes rock to plastically yield, causing well cave in and making explosive fragmentation ineffectual.
#3 Contrary to assumptions made by Maurer, it is not cost or safety that limits the technology but rather the issue of using explosives in traditional liquid based drilling fluids, which due to their incompressibility, transmit pressure waves very long distances. The crucial problem to solve is spoil or fragment removal and this will ultimately determine drilling speed and overall viability. By employing a retractable and extending flushing nozzle, high velocity liquid can be sprayed directly in the fragment bed alleviating poor removal, the problem of fragment accumulation has therefore largely been solved on a conceptual basis. Unfortunately, providing close proximity to fluid exit is not sufficient, one the particles exhaust their momentum, they will fall back down. The use of a high viscosity preferably oil-based fluid is essential if not required for successful operation. Thankfully, engineering options exist to permit high viscosity oil based fluids to be used without decomposition or excessive losses.
#4 The critical design feature of the explosive drill is a water-cooled annular sleeve that slips along the well-bore wall to cool the incoming fragment containing oil. The use of actively engaged packers can adequately prevent excessive mixing of oil and a layer of water between the wellbore wall and the annular water cooling channels.
#5 Pumping powers in excess of 10 MW is required, around 5x more than rotary drills due the need for higher viscosity drilling fluids and a large amount of coolant
#6 Drilling speeds as high as 100 meters per hour are feasible in hard crystalline rock using suction spoil removal.
#7 Safety is not expected to be an issue with phlegmatized explosives and the use of heavy-duty shockwave attenuation systems at the surface.
#8 Explosive costs are not a limiting factor, the costs saved by eliminating the drilling fluid and the massively improved productivity offset the added costs of explosives by a substantial margin.
#9 Explosive drills are ideally suited for penetrating large diameter wells which opens up the possibility of novel-down-bore well fissure stimulation using chemical or nuclear explosives for goethermal power extraction.
#10 The technology cannot be used for in soft, plastic rocks typically found in the sedimentary layer.
#11 Explosive capsules can be detonated by using the force of their impact with the rock bed or timed slapper, mechanical percussion, or shock bridge detonators using small batteries.
Introductory Q&A
Why do you think explosive drilling is superior out of all the potential options?
Answer: Because no currently viable replacements to bit-based drilling exists outside of explosive and projectile drilling. Explosive drilling is not chosen due to some intrinsic attachment to the concept on behalf of its developers, but due to the lack of viable alternative options and the sheer fact that it appears immensely attractive from a number of technical standpoints. Presently marketed alternatives, namely so-called “millimeter wave” is plagued by technical issues, leaving explosive drilling and high velocity projectile drilling as the only solutions. Since high velocity projectiles do not sufficiently fracture rock into small fragments needed for satisfactory spoil removal, it is stuck as a “hybrid” option, requiring conventional drill bits to paired to the system.
But explosive drilling is not new, wasn’t it tried before and not developed due to cost and safety reasons?
Answer: The definition of “new” is problematic. The diesel engine was not new as a heat ignited reciprocating engine, Aykroyd engines achieved thermally induced ignition before diesel, but the precise methodology of igniting fuel purely by hot air was. Explosive based drilling is a principle, not a technology. It is a methodology, but in order to built a working system, a number of technical details have to be sorted out. One such detail is effectively flushing rock fragments out. Previous attempts at explosive drilling experienced difficulty doing this because the nozzle had to be held up to 500 millimeters above the rock bed, debilitating the fluid’s removal efficiency. Hydrostatus Systems has circumvented this problem using an electromagnetically actuated rapidly retractable and extendable nozzle that sprays drilling fluid directly into the rock bed after explosions in a cyclical process. Another solution is the use reliable, melt cast metal cased phlegmatized solid explosives fired from the nozzle using combusted fuel and oxidizer in order to reliably detonate them upon impact. Previous explosive drills, namely the Russian one, used leak prone sensitive liquid explosives with complex mixing mechanisms or solid explosives but with sensitivity primary explosive as detonators. These solutions make this technical realization of explosive drilling meat the definition of “new”. Lastly, cost and safety not genuine limitations, explosives such as cyclonite can be synthesized for a few dollars per kg using formaldehyde and ammonia as the only feedstocks with intermittent wind or solar power. Formaldehyde is produced by the catalytic oxidation of methanol. Safety concerns can be quelled by using a highly robust blow-out prevention device to isolate personnel from the effects of shockwaves emanating form the borehole if some of the capsules accidentally go off.
But without a prototype how can you be certain that your design improvements will solve the previous issues encountered with this method?
All technologies are begin their developed course on the drawing board according to our present knowledge of science.
William C Maurer has largely endorsed explosive drilling, while he did not endorse high velocity projectile drilling, claiming such a methodology would not work in narrow and deep petroleum and geothermal wells.
“The efficiency of explosive charges increases with fluid pressure, indicating that this explosive drill would be most effective in deep wells for which drilling costs are high. Efficiency also increases with explosive charge size, which suggests that a full-scale drill would be more efficient than the charges used in these preliminary tests. No attempt was made to optimize the explosive charges in the tests, so considerable improvement could be expected on a detailed development program”.
“This Soviet explosive capsule drill is of special interest because it has been thoroughly field tested and has shown that it can effectively drill holes at fast rates. This drill can penetrate nearly all types of rock and has the advantage of high power output. Its main limitations are that it will not effectively drill soft materials such as clay and that the cost of the explosive capsules is quite high since they are consumed at rates up to 720 capsules per hour”.
Introduction: Accessing the crust’s great depths represents a great leap forward in man’s knowledge of the geology of the earth as well as providing nearly unlimited energetic and mineral resources. For example, presently, gold cannot be mined deeper than 2000 meters due to temperature constraints on men and materials and limited cooling options. With explosive drilling, large multi-meter diameter wells could be drilled in existing gold deposits accessing tens of thousands of cubic meters of rock at great depths ready to be sifted for gold, silver, and platinum group metals. Unlike milli-meter wave drilling, explosive drilling is scale invariant and could easily scale to permit drilling massive diameter well-bores deep into the earth to access exotic elements. Modern civilization, in spite of its prodigious technologies capacities, finds itself helpless when it comes to reaching the deeper regions of the upper crust. This baneful condition results in an incomplete understanding of the crust’s geology, its mineral composition, and most importantly, it leaves civilization stranded scourging the shallow sedimentary deposits for critical resources. It also prevents man from accessing gargantuan deposits of medium grade heat than could, provided fracture stimulation methods are develop, permit man man to generate electricity for less than the cost of oil and natural gas. Developing improved methods of fragmenting and extracting rock to great depths in a continuous process is an essential task for engineering in the 21st century. Hydrostatus Systems views itself as bringing to market an old but updated technology that has long been ignored. This technology is the use of packaged charges of the most explosives fired from a down-bore nozzle to fragment rocks into millimeter size particles easily removed by high lift capacity water-based drilling fluids. A series of improvements are made from the original demonstration of the technology.
A few statements should be made. The term “drilling” should be dispensed with since most of these alternative methods make no use of rotary grinding motion to remove rock. In fact, most if not all of the alternative, “novel” or “advanced” drilling techniques chronicled in William C Maurer’s book deal with methodologies that are inherently “bitless”. Regarding the proper choice of terminology, despite the fact the term drilling fails in properly defining the underlying methodology employed for rock disintegration, the word “boring” is connately redolent of tunnel boring, and even through we would like to dispense with the world drilling, it will still be used for search engine optimization purposes since most prospective customers, engineers and technology developer will continue to employ the conventional vocabulary. Despite its floundering performance in deep and hot crystalline rock, conventional bit-based abrasive rotary drilling technology has must a number of strides over the past century. Starting with rudimentary percussion bits which were dropped into wells using the force of gravity, and concluding with the state of the turbodrills used in ultra-deep methane wells in Siberia, to the horizontal drills exposing shale rock in the Permian basin. The percussion drills of the late 19th century and early 20th resembled a chisel, and despite being very simple and inexpensive, the device would wear out very vast and penetration rates were exceedingly slow. It was not until the early 1900s rotary bits were finally developed, with the famous Hughes roller cone bit completely revolutionizing the oil industry and making petroleum extraction a viable technical endeavor for the time. In fact, one could argue that the Hughes roller cone bit was the single most valuable patent of the early 20th century. But drilling innovation did not stop here, in the 1920s Soviet engineers developed the now-standard turbodrill. Despite the turbodrill’s powerful advantage: negating the need for a drill shaft, a number of innovations in bearing, seal, and gear technology were needed before the turbodrill could be made viable. Early turbodrill blades suffered from rapid erosion, leakage, and short reduction gear life. Advances in turbomachinery design and metallurgy eventually eliminated these challenges making them highly reliable. Once these advancements were made, turbodrils soon surpassed shaft-driven drills in penetration speed and even reliability. One of the key advantages of the turbodrill is its ability to drill much deeper than shaft drive drills, since shaft binding against the bore-wall is not an issue. But by far the most important advantage it its ability to drill laterally, paving the way for the “horizontal drilling” revolution that recently boosted U.S oil production after decades of decline. Ever since this early Soviet invention, Russia has continued to manufacture and engineer the world’s most advanced turbodrills. In its insatiable quest for more advanced drilling technology, Soviet Russia also began developing electro-drills, with downhole electric motors in the 1950s, but poor motor power density and weakly designed power delivery cables limited the technology at the time. With much better microelectronics that can deliver high voltage power to rectifiers into low voltage AC or DC feeding high power density, electrodrills warrant serious consideration even if bit technology is the limiting factor. Despite this, turbodrills remain the mainstay of deep drilling to this day and account for the bulk of horizontal drilling.
Rock boring, whether it is to construct a tunnel in the Swiss Alps or to drill a well for oil and gas, is perhaps one of the most challenging engineering endeavors man can undertake. A combination of the extreme temperatures encountered at the ten-kilometer range, the immense hydrostatic pressure which compresses water to tens of thousands of psi, the sheer hardness of the crystalline rock, and the enormous distance to the surface, culminate to yield a vastly challenging technological demand. An amusing comparison is the fact that its easier to launch a rocket into orbit than to drill an ultra deep well in the crust. Presently, for the price of sixty million dollars, a multistage launch vehicle using kerosene and liquid oxygen can reach geostationary orbit 36,000 kilometers away with 99% reliability, while the best drills in the world can barely penetrate 12 kilometers while taking years to reach this depth. Of course, the comparison is purely illustrative, it is by no means technically homologous. A rocket, once it has expended its fuel mass is simply soaring through empty space with hardly any drag. Then all it has to do is decouple its payload and effectively “dump” it into orbit. The task is momentous and impressive no doubt, but it is surprisingly simple. The greatest challenge faced by designers revolves around ensuring that the propulsion system, highly flammable fuel, does not leak or ignite especially during takeoff. Stage decoupling has become a streamlined process with few hiccups, and guidance, with the introduction of inertial gyroscopes, has proven surprisingly simple. A rock boring machine on the other hand has to spall, fragment, disintegrate the solid extremely hard mass in front of it, all while ejecting this mass back up the hole that is barely bigger than the unit itself. Add in temperature, pressure, and the weight of the shaft or cable that must suspend this entire device plus bear its own weight, and we have a task that greatly exceeds the difficulty of “rocket science”.
But the overall message is clear, what stops us from boring holes at even conservative depths of 12-15 km? Is there any fundamentally physical, chemical, metallurgical, or overall technical factor that simply prohibits us in much the same way we are forbidden from building airplanes with lift-to-drag ratios much over 20 due to the laws of aerodynamics? The answer is yes. As we’ve mentioned before, the fundamental issue that is not receptive to engineering solutions is not heat or pressure, but the change in the rock’s physical properties.
A way of ascertaining the degree to which a present technology can be potentiated is by analyzing the extent to which there exists a noticeable gulf between the desired performance and the demonstrated performance. The gap between technological expectations and actual performance determines how mature or how much potential there is left for improvement. The intensity of environmental attrition. This metric can be used to gauge how susceptible a particular technological complex is to outside factors which cannot be appreciable attenuated. Such an example is the drag acting on a train or the friction that its wheel incurs, or the impact damage should the train hit a vehicle. Engineering can improve the power of the electric motor, the power transmission system, or the vehicle’s durability, but it cannot eliminate these exogenous antagonists. In the case of a bore-hole penetration system, one cannot engineer a device to make the rock strata softer, but one can undoubtedly make a more potent rock destruction apparatus.
Using this metric, drilling technology is either handicapped by some ill-defined but likely highly persistent performance boundaries that are difficult to overcome, determined mainly by concrete physical, thermal, abrasive and material challenges, or there is immense work yet performed to potentiate it. If the latter is the case which we believe to be true, there exists immense upside in performing the necessary R&D not to mention commercialization of the first alternative to the rotary bit for a over a hundred years.
Any alternative drilling or bore-hole penetration system must fundamentally remove rock either by mechanical force or heat. Mechanical force can use abrasion, kinetic energy, extreme pressure, percussion, etc, through a variety of means to achieve said mechanical force. The second category is thermal, which has never to this date been utilized except for precision manufacturing such as cutting tiles or specialized materials using lasers. Thermal borehole penetration is evidently more energy intensive, since rock possesses substantial heat capacity, and any drilling media, whether gas or liquid, will invariably consume a large portion of this heat. This heat must then be introduced somehow, it can either be in the form of combustion gases directly imparting this heat, which in that case the combustion can occur only at the tip, with the transport mechanism being the movement of the combustible compounds in liquid or gaseous form. Alternately, intermediate mediums of delivering thermal energy such as lasers, plasma, or some form of high-frequency radio wave. Plasma can be generated at the tip by passing electrode current from two electrodes. The energy of a very powerful laser can be introduced via a fiber-optic cable and emitted at the tip. Regardless of the technically feasible of the various thermal penetration concepts, they all share one feature in common. The last method available is chemical, in which strong acids may dissolve the rock into an emulsion that can be sucked out. This method is limited by the high temperature of the rock which may decompose the acid and the prohibitively high consumption of chemicals which will prove uneconomical.
Any drilling concept which relies on thermal energy to melt, spall, or vaporize rock is ultimately limited by the fact that it cannot practically use water as a working fluid, since virtually all the energy would be absorbed in heating the water. Additionally, thermal methods such as lasers will incur very high reflective and absorptive losses from rock powder and even micron thick layers of water on the rock bed. Regardless of the medium of thermal energy delivery, be it radio frequency, visible light such as in a laser, or ionized gas, that is plasma, will be greatly attenuated by the presence of the drilling fluid, requiring the nozzle to be placed just above the rock surface, presenting overheating and wear issues for the tip nozzle material. Hydrostatus System’s concludes based on extensive first principles engineering analysis that thermal systems will possess an assortment of ineluctable technical difficulties severely limiting their usefulness, operational depth, and practicality. Our conclusion is that various means of mechanical disintegration, through a combination of pressure, velocity, and force will remain the method of choice for excavating boreholes far in the future. Since mechanical force is the method of choice, we must now narrow down our choice in identifying the optimal means of imparting this mechanical force to the rock media. We have at our disposal plain mechanical action, such as using percussion or rotary force, but these means are quickly ruled out due to lacking force delivery intensity. We are left with the last option, using high-velocity projectiles, but we have ruled out this option due to the availability of an even better alternative: detonation of energetic materials. Energetic materials are a class of nitrogen rich molecules which possess inherent instability due to their strong tendency to oxidize upon stimulation. Energetic materials are class of propellants, explosives, and regular heat releasing deflagrating compounds, colloquially known as fuels. Should explosives not exist, we would undoubtedly employ the option of high velocity projectiles.
For those that are interesting in developing advanced deep hole boring technology for applications other than oil and gas, “heat mining” is the prime candidate. For those unsatisfied by terrestrial energy harvesting schemes, be they solar or wind, it seems only obvious to the astute energy engineer to look down upon the crust for heat. The mantle is a block of molten iron and nickel whose heat emanates from the radioactive decay of thorium, uranium, and other trace isotopes. But heat does not only emanate from these decaying isotopes as they form lighter elements with a mass deficit, yielding energy, it also emanates from the slow cooling of the mantle’s initial formation temperature. This residual source of heat is more than mankind could possibly consume, but most of it is inaccessible for reasons of distance and geology. But this source of heat should not be confused with renewable forms of heat such as the sun or its downstream cousin: the wind. In strictly scientific terms, this mantle residual heat is not by any means a renewable source, since it will gradually decay until it cools down completely. But within anthropogenic terms, this heat source might as well be considered infinite. For all practical intents, man is limited to drilling about 12 kilometers, or about 40,000 feet with current rotary bit technology. It is important to stress that no technology presently conceivable can surpass this depth due to the phenomenon of rocks becoming plastic at the pressures and temperatures at this depth. Such a depth is difficult to visualize on paper, one way to visualize what such a depth represents is to look out the window of an airliner at cruising altitude when cloud cover is sparse. The typical cruising altitude of a wide-body airliner is 12 kilometers, one has to then imagine a continuous tube, as thin as a string, stretching this entire distance.
Due to differences in thermal conductivity, elevation, and tectonic activity (magma intrusion, presence of aquifers that transfer heat through advection), certain localities have more heat available at shallower depths. If there is such a thing as a geothermal industry, it practically exists solely in Iceland where magma intrusion and highly active aquifers transport enough heat to where it is nearly 200°C as a mere 1.5-2 kilometers in the “Hengill” site. A number of sites possess thermal gradients in excess of 35°C/km, these locations are found in Iceland, Western Italy, the Anatolian Peninsula, many parts of Australia, and the Pannonian basin in Hungary. A geothermal gradient of 35°C/km can be found in about 2.8% of the U.S landmass, principally in the Great Basin, Mojave, Sonoran, and Chihuahuan deserts. These sites may be highly attractive to prospective drillers due to low land costs and a propitious regulatory environment due to a lack of population density. A major limitation of conventional geothermal technology is connecting the hot and cold boreholes together at their ends with porous rock formations. The conventional method to extract heat is to drill two holes and then use the force of gravity to drop water down into the inlet hole, and then that high-pressure water passes through a porous rock formation that serves as a heat exchanger. As the water trickles through this porous rock formation, the water then boils and the steam makes its way back up. Some systems may keep the pressure of water enough as to prevent the water from existing as steam to maximum flow rates, since steam is much more viscous than water. This water water can be pressurized like in a nuclear reactor and pumped through a heat exchanger at the power plant to boil water at normal pressure. If the diameter of the borehole is high enough and the surface is not too rough, most of the pumping energy can provided by the difference in density due to the differing gravitationally acceleration. Its important to stress that geothermal is a fundamentally separate series of challenges than drilling technology. Drilling technology, while no doubt subject to a number of exogenous physical limitations, is still nonetheless a primarily technical problem, in which fewer restrictive natural barriers are present, one that can be design to perform at levels significantly than its baseline performance through the augmentation of an array of ancillary components. Geothermal, or crustal heat extraction, is primarily a non-technological and physics problem, one in which natural and restrictive variables such as thermal conductivity, porosity, geology, rock density, and thermal diffusivity limit performance. Engineered techniques cannot fundamentally alter these natural variables or significantly change their impact on performance. In fact, one can argue that the lack of geothermal energy deployment is not due to the popularly adduced problem. In fact, before we continue, it is important to highlight the inherent problematic nature of the word “challenge” which following the word technical or technological. The fact that rock has low thermal conductivity is not a “challenge”, it is an attribute indifferent to our pessimistic categorization, this mutable connotation should be dispensed with. This peculiar phenomenon is the result of the immense success of communication and computational technology that paints the false picture of technical omnipotence of the infinite mutability of everything around us. This is not a luddist interpretation, rather it is philosophy of scientific modesty and strict category adherence. Perhaps the best example of this elusive “infinite mutability” is the subject of man-made fusion. The believe that simply using a high enough temperature and a tight enough magnetic confinement one can replicate the multi-hundred billion bar core pressures found in even small stellar bodies like brown dwarfs, which are only 0.075 times the mass of the sun, are not even high enough to sustain fusion. Stellar bodies such as the sun have core pressures of 265 billion bar. The highest pressure achieved by man-made Tokamak is 3-10 bar! But according to modern physics, “theory” backed up with much constructed mathematical dogma insists that if temperature is raised high enough, then somehow high pressure is not needed! But this defies all understanding of ionized gases, or ordinary gases for that matter. The higher the temperature of a gas body, the further apart gas molecules collect, making it ever more difficult to overcome the ever elusive Coulomb barrier. While this brief inquiry into the impossibility of man-made fusion is not relevant to drilling technology or geothermal energy, it is relevant to our perspective that one must strictly partition technique from naturally defined attributes. The conclusion of this statement is that any geothermal endeavor will be rigidly constrained by these physical attributes which characterize the upper crust, and will not be nearly as receptive to man’s contrivances and techniques than commonly assumed. The strict reason geothermal has not been more widely deployed are not necessarily found only in the drilling process, man has drilled at great depths before, and while the process is immensely tedious and costly, it can no doubt be done at scale using current technology, diamond bits with turbodrills can still suffice if the time is spent. 350°C is well within the tolerable range of high-end alloys and diamond-cutting tips. Drilling productivity is around 5-10 feet per hour using polycrystalline diamond, sometimes if the rock is extremely hard, productivity can slow down to as little as 1 foot per hour. As temperature increases, the strength of the steel bit holder decreases and expands placing compressive stress on the diamond cutting piece. As the bore depth increases, friction on the drive shaft builds up to a point where drilling is impossible, this is usually encountered around 7500 meters. This is discussed in great detail further below in this text. Any further depth requires what’s called a “downhole motor”, which can either be a hydraulic turbine, called a “turbodrill” or an electric motor, called an “electro-drill”. An electric drill is often more challenging since electrical machinery must use copper in its winding as well as its delivery cable. Copper incurs a substantial rise in resistivity with temperature, resulting in reduced motor efficiency. Rotary bits typically operate from 30 to 500 rpm. The second requirement is providing for hydrostatic support, since boring occurs before casing can be inserted, a drilling fluid has to be pumped down at a high flow rate at hundreds of cubic meters per hour. The fluid not only provides hydrostatic support to prevent wellbore cave-in, but also removes drill debris or so-called “cuttings” which pile up rapidly. The drilling fluid must possess a minimum viscosity of around 10 centipoises in order to effectively lift the cuttings out of the hole. The higher the viscosity and density the more effective the drilling fluid is at lifting particles out of the hole since the buoyancy of the fragments is larger as well as the adhesion strength between the fragment and the liquid. The confluence of drill bit degradation, slow drilling rates, shaft friction, bindings, dog-tailing, and slow drill insertion and retraction for bit replacement gives rise to an extremely costly process that effectively forbids the widespread use of deep drilling in all but the most profitable hydrocarbon deposits. Can “innovation”, or even brilliant invention somehow overcome these physical challenges? Perhaps, but one should not be their life savings on it, since we are dealing primarily with thermal, material, and kinetic limitations. Drilling is costly due to the need for a massive number of drilling pieces which must carry their own mass while they descend, the weight of the drill, plus withstand the torque and the downward force needed for the drill work, which must extend the entirety of the multiple-kilometer distance. The energy needed for spinning the drill is insignificant, the preponderance of the cost is in the capital equipment. In fact, most rotary drills use only a few hundred kilowatts, accounting for a tiny fraction of the cost of the well. But in spite of this gloomy technical performance, gas wells have been drilled at these wells and have generated positive returns. The simple and uncomfortable fact is that the energetic yield of such a well is simply too low to justify the investment. Therefor, in order for “heat mining” to be a viable contender, one must be able to devise a method to massively increase the output of a geothermal well regardless of how it is drilled.
Background and motivation
While alternative drilling technology attracts considerable attention especially in the 21st-century due to climate change to tap deep geothermal, explosive drilling has been wholly ignored in this debate despite its high technological readiness. In fact, in a report on how to increase the cost effectiveness of geothermal energy, they mention a number of alternative methods but either ignore explosive drilling or are unaware it exists. The impetus for this technology was principally to access hydrocarbon despots in hard rocks at greater depths than could be attained with conventional rotary bits. Fast-forward half a century and improvements in sensing technology, materials, alloys, manufacturing, and explosive compounds etc, make this simple concept fall within a relatively high TRL of 8. It would be a mistaken to limit new boring technology to geothermal, which is a low grade energy source, therefore we are actively marketing the explosive drilling device for oil and gas drilling in areas featuring dense and hard crystalline bedrock where current drillers struggle to viably and productively penetrate. Notwithstanding their improved productivity, explosive drills make deep penetration much more convenient since the heavy torque shaft is eliminated. Petroleum geologists trained in the outdated theory of “dead dinosaurs” do not bother drilling in areas without the presence of sedimentary deposits, ignoring the millions of square kilometers where dense sediment free-rock with small fissures that could allow hydrocarbons to percolate from. In all probability, current oil and methane reserves are thousands if not millions of times greater than the present estimates. Since the petroleum and methane extraction industry is at best an oligopoly, data on well reserves are notoriously hard to access. Also, extraction organizations or more aptly named “cartels” have a strong incentive to promote theories that raise the price, creating an aura of scarcity by constantly drumming the fossil dogma raising returns in the process. It is likely that most hydrocarbons except for some coal deposits on earth are continuously produced deep in the earth, albeit at a rate that might be slower than our rate of consumption. In embracing this view, we are branded heretics, but throughout history, it was heretics who drove civilization forward, not the dull and blind conformists. In light of the infinite supply of hydrocarbons, one might wonder why we would bother trying to develop wind turbines or geothermal plants! The simple answer is that even if hydrocarbons are produced in the earth, they command a premium in international marketplaces due to their convenience and energy density, and hence are not attractive for applications that require very low-cost energy, such as aluminum production. High-altitude wind and highly productive geothermal have the potential to produce energy at a lower cost than the historical spot price of methane or petroleum. It would be a grave mistake to believe the only application for new drilling and improved deep-hole penetration technology is geothermal, arguably one of the crummiest energy sources we have today. Low-grade heat is a source of energy with little value, it can only be very inefficiently converted into electricity, and even as electricity, lacks mobility, it is a stranded asset. A truly effective deep-hole penetration technology should be viewed as a method for the direct augmentation and eventually superseding of rotary drilling systems. The surface of land on earth is 510 million square kilometers, less than 0.01% has been explored for hydrocarbons. Modern civilization’s most valuable asset after its human capital is none other than these energetic resources. It would be of the greatest folly to abandon such an asset over an unproven theory. Since hydrocarbon extraction, processing, refining, transport, and retail form one of the single largest industries in the world, the technology that facilitates the fundamental extraction of resources represents one of the most valuable and critical technologies to modern civilization. The designer of a more sophisticated system for deep hole penetration is thus occupied by a task of unparalleled importance.
Historical R&D and preliminary attempts at explosive capsule drilling.
Since explosive drilling is the only obvious candidate for replacing rotary drills, it is not surprising they have been tried before. This should not be viewed as a sign of their inherent weakness, since one could argue that the technology was tried but simply abandoned due to technical problems. This is not correct, since we have already repeated that because they do not perform in sedimentary rock, and most oil and gas is drilled in sedimentary rock, there existed little incentive to pursue the technology further.
Aside from its extremely poor performance in soft elastic rock strata which has made it of little use to the bulk of oil and gas drillers, explosive drilling has historically been handicapped by the high cost of manufacturing solid explosives and the perceived danger of storing many tons of explosive in the nozzle shaft itself. In spite of these concerns, they are not insurmountable. Explosive capsule cost can be lowered by synthesizing cheap explosives like R&D by producing very cheap ammonia using cheap intermittent power. The actual capsule fabrication need not be expensive, for example, the use of injection molded polyvinyl chloride is an attractive and very cheap option. Unlike a metal lined explosive capsule, the PVC would fragment into small shards, while metal would form potentially problematic fragments. The cyclonite explosive would be brought to its melting point where it exists as a viscous liquid and poured inside thin-wall metallic or thermoplastic capsule produced in million per year volume reducing unit cost to the point of raw materials. This method is widely employed in munition manufacturing and has been used for close to a century.
The origin of our inquiry into explosive drilling emerged from our interest in low cost energy harvesting. Around the end of February 2022, Hydrostatus Systems, after having success a concept for supporting wind turbines at higher altitudes, was studying the possible ways of overcoming some of the present technical difficulties with rotary drilling. During this pondering, the idea quickly appeared in the author’s head to simply shoot little charges of high explosives to shatter the rock continuously. The idea seemed so elegant and too good to be true it must have been thought of before, but like any obscure but existing idea, the author had never heard of such a concept, and having a good knowledge of general technology, had never heard of the concept, so either had to be very obscure, abandoned, or never thought of. Of course, since almost everything there is to invent already has been thought of, the idea had naturally been proposed, which has the double edge of confirming its soundness but reducing its novelty. In fact, the first to seriously propose and investigate such a concept was a Soviet engineer and inventor Anatoly Pavlovich Ostrovsky (1913-1990), Russian spelling Анатолий Павлович Остро́вский. Ostrovsky, whose name is spelled Ostrovskii in English, began studying the concept in the 1950s after a Soviet program initiated research into so-called “bit-less drills”. Much of this research emerged out of an extensive effort in the 1950s to develop advanced drilling technologies, including electrodrills and horizontal drilling. Few today are aware that horizontal drilling using down-bore electric motors had first been achieved by Soviet engineers decades before any U.S attempt. Later in the 1960s, the Soviets undertook numerous tests using his design for explosive cartridges ejected out of a nozzle drilling down four thousand meters in rocks of varying hardness outside of Moscow. A. P. Ostrovskii published a book chronicling the findings called “Deep-Hole Drilling with Explosives” in 1962. The book remains totally obscure and has no reviews on Amazon. The contents of the book were reviewed by William C Maurer in his two books on alternative drilling technologies. U.S engineers independently developed the concept and develop their own versions using solid explosives. William Robinson at Humble Oil & Refining Company filed numerous patents and developed a small scale prototype. The Robinson method makes use of a two-step process whereby a shaped charge is fired forming a deep and narrow hole, which is followed up by a gauge charge firing to expand the hole. The method is interesting, but despite the shape charge’s much high velocity, the volumetric removal efficacy is hampered, with a 17 gram shaped charge removing only 50 cm3 of rock while an 11 gram gauge charged removed 209 cm3 of rock, equivalent to 53 kg explosive/m3.
Explosive drilling came the closest to realization when the U.S Army became interested in its potential for rapidly drilling boreholes for atomic landmines (atomic demolition munitions), abbreviated ADMs Walter L. Black, AAI Corporation Prepared a 73 page report on the possibility of this technology for drilling dry holes using compressed air to moderate depths. William C Maurer is the world’s foremost expert on drilling technology, having single-handedly introduced Russian horizontal drilling technology to the U.S market, is quoted as saying regarding explosive drilling: “Additional R&D should be performed on explosive drills because of their high potential economic payout”.
The concept of using segmented explosive capsules was also investigated by the U.S military in the following reports available from the DTIC website: Investigation of Techniques in Explosive Drilling, Investigation of Advanced Concepts for Explosive Drilling, and Development of Equipment for Explosive Drilling. The U.S military’s interest in the drilling technology was for rapidly fabricate boreholes to insert nuclear landmines called “Atomic demolition munitions” or ADMs. Holes would be dug In 1962, Leon Haynsworth Robinson Jr at Humble Oil & Refining Company filed a patent for an explosive capsule ejector for hole drilling “Drilling boreholes with explosive charges”. The research effort concluded that explosively drilled holes were uniform, relatively smooth, and consistent, they state “Explosive drilling produces straight holes with very little drift or curvature”. Rock fragment size is preponderantly small, with rock fragments rarely exceeding 50 grams due to the powerful shattering effect of the blast, an important variable that affects the ability of the slurry to remove the rock effectively. The potentially rough and consistent bore diameter has been cited as a potential concern for explosive drilling, since casing must be able to smoothly slide into place. The results from Robinson published his findings in the Journal of the Society of Petroleum Engineers in a paper titled “Experimental Tests of a Method for Drilling With Explosives“. Robinson found that the productivity was 190 grams of rock were removed for each gram of explosive detonated while the DTIC reports found that the number was around 43.5 kg of explosive per cubic meter of rock. Ostrovskii found that number to be 48 kg of rock per cubic meter of rock. John D Bennett at Sunoco Inc filed a patent in 1968 titled “Method and apparatus for explosive drilling of well bores”. More recently, in 2007, a German company called Hazemag and EPR GmbH filled a patent titled “Device and method for explosive drilling”. In 2014, a Chinese patent filled by Southwestern Petroleum university “Explosion well drilling operation method by utilizing sleeve” makes alludes to a shape charge ejector with a sleeve mechanism, although due to the poor translation, it is difficult to get a good grasp of what they proposing.
In the digitalized report: The Cutting Edge: Interfacial Dynamics of Cutting and Grinding, the findings from the book Novel Drilling Techniques by William C. Maurer published some schematics of the Soviet explosive capsule drill.
In Ostrovskii’s design, the binary liquid explosive is contained with a spherical shell, within this shell, liquid explosive consisting of benzene and nitrogen tetroxide is held under pressure. The spherical containment vessel is placed in front of a shaft connected to a series of fins that extend beyond the diameter of the sphere. As the capsule assembly is flushed through a constricting orifice, the fins are prevented from passing through and mechanically pull the diaphragm, allowing the explosives to mix. The time to fully mix the explosive compounds was estimated to be beyond 1.5 seconds. In Ostrovskii’s design, the energy needed to eject the capsules is provided by the flushing fluid. In alternative designs, the capsules might be designed as to be mechanically very stiff to permit it to be fired at moderate velocities from the nozzle, using compressed air, the ignition of flammables, an electromagnetic rail, etc to guarantee smooth detonation upon impact with the rock surface and or higher productivity by increasing the ejection frequency.
With conventional rotary bit drilling which relies on differential rates of abrasion between diamond and feldspar, drilling bits require a continuous feed of lubricating material, otherwise, the bits were down within mere minutes. Most drilling oils are hydrocarbon-based and cannot operate in such hot rock formations that occur at depths greater than 10 km. Most of the heavier hydrocarbons above methane decompose at temperatures of around 300 to 400 C. In contrast, explosive drilling requires no lubrication except for the internal mechanisms of the ejection nozzle which are sealed off from the surrounding media, thus, water can be used as optimal slurry media. The continuous flushing of cold water from the nozzle provides a sharp cooling of the capsule delivery hose and the nozzle maintains its temperature well below the temperature range of the explosive. It should also be remembered that since water has such heat capacity, the slurry never reaches anywhere close to the temperature of the rock since its continuously flushed and carries heat to the surface. Nevertheless, it’s critical to maintain adequately moderate temperatures to minimize the risk of thermal-induced detonation or damage to the capsules. The nozzle can be made of high-strength beryllium copper alloy such as Beryllium Copper C17200. Beryllium copper alloy such as C17200 is comprised of around 2.5% Berrylium, the alloy possesses astounding mechanical properties, boasting a tensile strength of over 1400 MPa and excellent all-around corrosion resistance, but especially stress corrosion cracking. Beryllium copper alloy is virtually immune to hydrogen embrittlement. The capsule delivery hose is insulated and constructed from braided nickel alloy or titanium hose. The capsules would likely be constructed from a metallic structural liner. The solid explosive, hexogen or cyclonite, is pressed to multi-hundred MPa achieving crystal densities in excess of 1.8 g/cm3. Since the explosive is already made very dense by compression, it cannot be compressed by the surrounding water media, so the capsule’s housing need only to provide adequate structural integrity but does not need to withstand the full hydrostatic pressure of the drilling fluid, which will be 120 MPa at the full depth of 12.5 km, or an average pressure of exactly half that. The insulation can consist of compressed argon gas to minimize differential pressure and compressive damage to the insulation. A porous solid media can then be used to prevent radiative heat transfer from the cold inlet water and the hot slurry passing along the hose as it’s pumped to the surface. To prevent damage to the nozzle head from residual shockwaves, the nozzle must be kept at a distance from the zone of detonation at the bottom of the hole, such as 1 meter above the bottom. Capsules are anticipated to maintain a level trajectory due to the straightening effect of the ejection barrel. Hydrostatus Systems has developed a method where the explosive capsules remain isolated from the slurry media prior to ejection from the nozzle and are separably ejected from the energy of compressed air or diesel-oxygen combustion to allow for active modulation of their ejection rates. Ejection rates of up to 0.5 Hz allowing for drilling rates as high as 50 meters per hour can be realized if sufficient rock removal can be facilitated. Ejection rates are bottlenecked by the ability to remove fragments from the bottom of the hole, since there is no drill bit churning the rock fragments, they tend to accumulate at the bottom of the hole. Periodic stoppage and lowing of the freshwater ejection nozzle to just above the rock fragments will likely be necessary to provide the churning necessary to remove fragments.
3D model and rendering of Hydrostatus System’s proposed explosive capsule drilling module. The model above is suspending from a large diameter steel thin wall shaft. The steel shaft serves only as a pipe for facilitating the flow of cooling water to maintain explosive temperature at below its decomposition temperature. The large diameter shaft pictured above does not bear any loads but merely acts as a seal for the flow of cooling water which doubles as rock removal fluid. The inlet cooling tube is not a load-bearing member, rather, inside the tube, a series of metal-foil encapsulated aramid fiber load-bearing cables serve as the load-bearing members and carry the weight of the shaft assembly and the explosive capsules. The shaft section connects every 15 meters to a maraging steel fitting. Contrary to rotary drilling systems which require the shaft to transfer immense rotational force or torque, an explosive drilling nozzle generates only gravimetric force from its own mass and slight vibrational and recoil forces which can all be absorbed by the fiber aramid load-bearing cables. In contrast, the Hypervelocity drill requires a highly rigid shaft to absorb the intense recoil generated when firing the projectile at high velocity. The microwave drill is closer to ours in this respect, since it must bear only the weight of the waveguide.
Hydraulic fracturing will not work in plastic rock, meaning that no drilling beyond the brittle-ductile zone will ever be performed.
There is little point in drilling past 12 km or the brittle-ductile zone, whatever comes first. The main reason is quite simple. Unlike oil and gas extraction which can usually be performed by merely allowing the reservoir of the desired hydrocarbon to gush out into the drilled hole, a geothermal well requires a large heat exchange area. This heat exchange area must be artificially induced by mechanically fracturing the rock using a combination of pressure and thermal stress, combined with the chemical effect of water on the rock’s molecular structure. Once the ductile zone is reached, the rock now yields plastically making hydraulic fracturing impotent and ineffectual. The pressure of the rock would not serve to expand existing fissures but merely compress the rock and compel it to deform, but it would not lead to a root-like growth of tiny cracks and fissures allowing water to flow and pick heat. By definition, Hydrodraulic fracturing implies a “fracturable”, so one cannot expect any type of significant fracturing success in plastic, ductile, and elastic rock strata. Since there is little prospect of finding large amounts of oil and gas past this depth unless the abiogenic theory of oil and origins is correct, and geothermal fracturing is not possible, there is no commercial incentive to drill beyond the brittle zone leaving aside scientific or merely the sake of achieving such a technical milestone.
Novelty aspect #1: Viability of substituting the down-bore extendable nozzle with complete string lifting/dropping.
A minimum offset distance is required to protect the nozzle from the reflected blast pressure and prevent serious pitting of the metallic surface by high-velocity rock fragments. Pressure waves decay with the cube of distance in compressible mediums, so a maximum offset distance of at least 200mm has to be maintained. But in order for the evacuation of the fragments to be performed using a vacuum, the nozzle must be extended to physically touch or at least come very close to the fragment bed to perform suction. Any user of a vacuum cleaner can attest to its poor efficacy if the attachment is kept even a small distance from the surface. Of course, this to a large extent depends on the power of the vacuum, and the total pressure difference, but to minimize the size and power requirements of the suction device, it is desirable to minimize this gap. This creates an obligation to mechanically reciprocate a specially nozzle during each explosion cycle. It is conceivable that an alternative method where the entire drill string is lifted up and down in the well be developed, but such a method would require sliding the string along the series of packers expected to be installed during drilling. The actuation power needed to carry the multi-hundred-ton string would be very high and the speed at which it can be lifted will be limited.
It is therefore expected that circumventing this design feature will be difficult and unattractive.
Novelty aspect #2: Viability of circumventing the suction spoil removal method
The use of air allows for explosive drilling to generate only small fragment size and the unique and highly novel option of using a negative pressure in the delivery hose to carry up fragments. The ability to circumvent this option is physically impossible, since the free-fall velocity of even the smallest is greater than the maximum speed of the gas traveling up the annular space between the drill string and wall. It is therefore impossible to remove the spoil through conventional aerodynamic means, hence requiring an internal spoil transport system.
The proposed invention is to route the spoils once they have been picked up by the vacuum into a fluid-filled hose and then pump them to the surface using a medium-viscosity fluid. This option exploits the propitious explosive lending characteristics of gas while harnessing the efficient lifting capacity of high-viscosity liquid. The liquid spoil-carrying hose is fitted inside the main drill string housing and is provided with pumping power at the surface.
Novelty aspect #3: Viability of circumventing the capsule ejection angle adjustment method
In an explosive drill, regardless of the type of drilling media, the detonation of a charge will produce a spherical radius of fragmentation corresponding to the size of the charge. That is the radius of the explosion zone will remove a volume of rock in the shape of a somewhat compressed half-sphere. In order to drill holes in diameter that are larger than the maximum spherical radius, the ability to adjust the angle at which the capsules are ejected is desirable. This allows a smaller charge to produce a much bigger diameter opening reducing the pressure wave’s intensity and allowing a sizeable reduction in the offset distance of the nozzle. By installing a simple flexible fitting between the nozzle section and the main drill string, an adjustable azimuth capsule ejection barrel can be created. By rotating the nozzle relative to the drill string while the angle is kept in the same increment a pattern corresponding to the entire well diameter can be exploded. Angling the explosive charges also allows the drilling of variable diameter holes using the same size capsule.
One can envision bypassing this option due to the added convenience of having a fixed nozzle, reducing mechanical complexity, but the added performance, flexibility, and versatility the flexible nozzle affords make this an unattractive choice. There may be instances where a given mass of explosive produces a smaller hole diameter due to a harder, more plastic, or less porous rock, this means that the hole diameter is liable to suddenly shrink, potentially resulting in a situation where the hole diameter falls beneath the minimum threshold for the drill string to freely slide through the opening. Since the mass of the individual explosive charge is entirely fixed, and the frequency of explosive events alone cannot change the diameter since the least radius is constant, the only method to actively modulate the diameter of the hole is with the above method. AAI Corporation, working under a U.S Army contract to rapidly drill holes to place atomic land mines, attempted to get around this problem by employing a complex geometry with multiple shaped charges angled at 45 degrees from the Y coordinate. This design did not solve the issue of adjusting the wellbore radius since the shaped charges merely produced narrow indentations.
Novelty aspect #4: use of pre-compressed gas.
While novel from a technical, engineering, and operational perspective, unfortunately, is not an active design feature or an invention, but merely something of a choice that is “known to those with skill in the art”.
Design exigencies of sequential capsulized explosive vertical boring technology.
Prior art by Ostrovskii, Robinson, AAI Corporation, among others, have alluded to the overall architecture or concept of fracturing or shattering rock in a controlled manner for deep bore-hole formation. Hydrostatus System’s founder Christophe Pochari revived the concept in 2022 after suddenly having the vision to use capsuled high explosives to shatter rocks rather than relying on the mechanical firing of projectiles. After a quick Google search, existing attempts were revealed, but since no major technical obstacle was presented, it made little sense that the concept was abandoned for fundamentally insurmountable problems. Considering our competition are attempting technically much more daunting concepts than mere explosive pellets being shot out of a tube, we believe it is worthy of reintroduction and final refinement and commercialization. The parties intending to commercialize this concept must now develop and refine the specialized mechanisms, methodologies, designs, as well as optimize the technical and operational parameters for successful application. It should be noted that while the concept can be simulated and conceptualized on a first principle basis, without extensive testing under the conditions, pressure, temperatures encountered, it will be difficult to anticipate all the variables which affect its design. A number of potential areas of intellectual property are listed hereinafter.
Flexible/rigid pipe assembly: High novelty potential: A method to deliver both slurry fluid, coolant, and the capsules/cartridges/charges must be optimized in order to accommodate the necessary insulation, load-bearing capacity (to suspend the mass of the nozzle and the entire pipe assembly), as well as provide for convenient insertion/removal ability and life adjustment of nozzle height. If materials allow, a hose may be designed to bend at a shallow radius to permit winding into a spool at the drilling set to reduce manpower requirements. Thin layers of bulk insulating material in an argon atmosphere can provide the necessary low thermal conductivity to mitigate the rapid heating of the capsule fluid. If insulation materials that provide this necessary flexibility are found to be impractical and or inferior to a solid configuration, straight 10-15 meter shaft sections are inserted into place and threaded in a similar fashion to conventional shaft drilling. The hose must be resistant to erosion by abrasion caused by small rock fragments traveling upwards at high speed in the slurry media. Another issue encountered may be cavitation damage to the hose as well as ejection nozzle due to small pockets of gas released when the explosive mixture is detonated. A throughout analysis and testing of both the nozzle as well as the shaft/hose’s durability will need to be performed to evaluate the degree of attrition engendered by a combination of shockwaves, gas pockets, rock fragments, and corrosive compounds present in the rock formation.
Explosive cartridge delivery: No novelty potential. A passageway in the main hose/shaft section in the diameter of the capsule plus a small additional margin to provide the needed flexibility to ensure no binding of the capsule and hose/shaft wall occurs due to thermal expansion. The capsule feeding section is placed in the inner portion of the main hose/shaft. Slurry and coolant delivery: No novelty potential. Cleaned distilled water is pumped at the necessary pressure to attain the desired flow rate through a series of separate flow passages surrounding the capsule delivery hose. A portion of this water is used for cooling the explosive and nozzle, flushing rock fragments, and providing ejection power for the capsules if compressed air is not desirable.
Active cooling of nozzle and delivery hose: High novelty potential: The ejection system must provide actively modulated ejection rates depending on rock hardness and rock diffusivity to minimize excessive comminution of rock media. Drilling speed is actively modulated with capsule ejection frequency. Capsule ejection: High novelty potential. Ejection power can be provided by either pressurized water or gas that is flowed in a separate hose from the slurry hose. A separate delivery line can provide the tailored flow rate for the ejection actuation energy that can be controlled via an electrical cable spanning the depth of the well. A method to prevent any clogging of rock fragments in the ejection barrel is critical, such a method may include a rotary valve and or maintaining water pressure above the ambient pressure to prevent any slurry from entering the capsule barrel.
Cartridge design and material: High novelty potential. Since the capsule housing material is recovered at the surface from the slurry separation system, high-cost lightweight and low-conducting materials can be used such as titanium to minimize weight on the delivery shaft/hose. The main cartridge structural liner is constructed just thick enough to prevent impact damage when the capsules encounter a rock fragment in the water. The liner does not need to be insulated since the residence time is so short. It is yet to be determined which material is ideal, field testing will determine the appropriate alloy/material. It is desirable for the capsule to be both somewhat aerodynamic and not too sharp to minimize the distance between the explosive and the rock bed. It is not expected that shaped charges will be used. It is important to select a capsule material that does adversely react with tetranitromethane.
The ability to rapidly remove fragmented rock is critical to avoid excessive comminution which serves to squander explosive productivity. This issue is especially pronounced with explosive drilling since there is no drill bit generating a constant “churning” force that imparts motion to the rock fragments. With explosive drilling, it is foreseen that the fragments will to a larger extent remain stagnant in the bottom of the hole. To counterpoise such a condition from occurring and retarding the drilling rate, the use of a heavily cased but relatively weak penetrating charge is used to periodically perform “heaving” action within the crushed rock bed to compel the individual rock fragments to migrate up into the slurry. This charge can be designed to penetrate the rock after a certain amount of fragmented rock piles up into the borehole bottom. This number would depend on the drilling rate and the effectiveness of water as a rock removal media. Since the explosive is a relatively small contributor to the overall cost of the system, the use of high drilling speeds at the expense of high rock comminution and explosive consumption can be considered. But the issue is not merely a matter of explosive consumption, when excessive amounts of rock fragments build up in the bottom of the wellhole the subsequent charges have very little potency in removing further rock, so productivity slows drastically. Therefore, even if penetration speed is increased, there is an inventible clearly defined limit imposed by the divergence between slurry removal efficiency and fragment buildup. The penetrating heaving charge is theorized to bridge this gap and augment drilling productivity. Its purpose is to remove small layers of rock fragments that build up and become compacted by the subsequent primary fracturing charges. Some may wonder what possible difference could exist between a small penetrating charge and the major fracturing charges. The difference is that the primary charges are much more powerful, but since they do not penetrate any significant depth, they generate a powerful shockwave pushing down on the rock bed, rather than heaving them, they compact them and push the rocks towards the side. The penetrating charge is just strong enough to generate a gas volume to impart considerable churning and heaving motion to the rock fragments, without further comminuting them. Since the charge penetrates a greater depth than the primary charge, the explosive takes place inside the fragmented rock layer laterally pushing the rock fragments against the wall and upwards. The upward motion of the individual fragments allows the liquid opportunity to pull them up into the borehole.
Choice of explosive: No novelty potential. Short of discovering a new molecule, the designer is limited to the available explosive compounds. Liquid explosives entail too much hassle, with elaborate failure prone mixing diaphragms, extreme sensitivity once mixed, and low decomposition temperatures, render liquid explosives no safer than solids. The ability to melt-cast cyclonite Hexanitrostilbene was successfully used on the Apollo program for generating shock waves for experimental seismic sampling and for actuating the landing gear. It was chosen due to its excellent performance in high vacuums for an extended time. Hexanitrostilbene is not inherently a high-cost explosive as for example HMX, since it can be readily synthesized from trinitrotoluene, a low-cost explosive. A solid explosive is ideal due to its added simplicity since it eliminates the mechanisms imposed by the need for mixing. Liquid explosives also confer added leakage risk which may go unnoticed in the nozzle and delivery pipe at the great depths operated. Leakage can potentially cause a sudden detonation if leakage occurs from both the oxidizer and fuel sections of the capsule and are allowed to mix in the ejection barrel and delivery hose. In comparison, a solid explosive can be easily sealed and prevented from dispersing into the environment. A potential disadvantage of solid explosives is their pressure tolerance, very little data exists on solid explosives at very high pressure, while for liquid explosives such as TNM/Toluene, considerable data is available suggesting continued stability and detonability at pressures as high as 4000 atm. Hydrostatic pressures at 15-20 kilometers will be between 2000 and 3000 atm. Due to the more complicated manufacturing process for solid explosives, liquid explosives are a more economical option, but do not seem ideal other than their added safety. The explosive must be manufacturable at scale in order to facilitate large-scale deployment of the technology. Tetranitromethane has a boiling point of 130°C, and while its exact decomposition temperature is not known, is expected to begin rapidly decomposing at temperatures in excess of 300°C, although no data is available. Toluene begins to very slowly decompose at 350°C. An overlooked opportunity is the potential to extract useful work from the compression of explosive oxidization gases. The gases generated during the oxidation of the explosives are immediately compressed by the surrounding water media generating a high-pressure gas that can be used to extract useful work, potentially covering a portion of the slurry pumping energy. This may emerge as an interesting opportunity for novelty. The need to minimize cavitation of the shaft and nozzle by the flowing high-pressure gas bubbles is also projected to form a crucial design exigency.
Height ascertainment system: Medium novelty potential: Height from the wellbore bottom can be ascertained each time device is descended periodically to maximum flushing. Alternative methods include low-frequency sound waves which can penetrate through dense water using time of flight to infer distance. Another method is to simply measure the shockwave propagation time, a high-fidelity pressure sensor can be installed on the nozzle tip to measure the time it takes for a shockwave to propagate from the point of capsule ejection which is a known starting point.
Shockwave absorption system: High novelty potential: Since explosions generate supersonic shockwaves that travel upward in the liquid media, if the nozzle is placed too close, cracking of the metal can occur. The nozzle is thus designed with a conical shape to blunt the shockwaves using the same principle as an MRAP military vehicle which uses a v-shaped hull. Since the overpressure of the shockwaves declines rapidly with distance, keeping the nozzle at only a slight distance, such as 100mm above the explosion zone, can successfully keep cracking risk to a minimum. Unfortunately, as well size increases, the distance must increase as well since each explosive charge grows in power. This imposes an unacceptable loss in fragmentary removal efficacy since the zone of water discharges is moved a further distance away from the rock fragment bed. Such a condition compels the designer to search for an option to place the nozzle as close to the detonation as possible. But in doing so, a number of design exigencies arise. When the shock waves strike even the conical body, they impart sharp energy which can induce fracturing of the metal. This may require both a shock attenuation system using springs or compressible gas to serve as a shock absorber to blunt the shockwave energy from placing excessive strain on both the conical nozzle and the suspension shaft (if a hose is used this is not an issue since it will simply bend). But it is not certain that such a shock-wave attenuation system would necessarily prevent cracking of the nozzle head since the shockwave still strikes the metal surface, and at such an elevated velocity, the recoil time is far too latent to cancel the force imparted upon it by the shockwave. Another option that may be suitable is a compressible layer that can be lined on the surface of the metallic nozzle, much like an ablative phenolic resin coating used on MIRVs. Except that rather than a thermal effect as in the MIRV, the coating serves to absorb as much of the shockwave’s energy in slowly compressing and cracking the material as to attenuate the net force transferred to the metal beneath it. This liner of a yet-to-be-determined material can be periodically replaced. Regardless of the mechanisms used, it is expected that nozzles will have to be replaced periodically due to gradual crack evolution and fatigue cycle accumulation in the metal tip from local stress concentrations from the overpressure. Since the hydrostatic pressure places a 200+ MPa continuous compressive load on the metal, the metal nozzle and any metal components are already at continuous loading conditions which reduces their fatigue life perceptively, especially at the elevated temperatures they operate under. If this crack growth is allowed to persist, catastrophic failure can occur. It is, therefore, necessary for a design that can accommodate easy replacement of the nozzle section to be implemented.
Detonation and initiation mechanism: High novelty potential. There is little to no civilian experience using explosives in high hydrostatic pressure environments. Only naval landmine technology, military underwater explosive placement for demolition, etc utilizes explosives in a high-pressure water environment. The detonation mechanism must not only accommodate the effective mixing of the mixtures and timely detonation, but also the reduction in sensitivity due to hydrostatic pressure. Since water has a density of 798 kg/m3 at 250°C(which corresponds to mean well temp) the hydrostatic pressure gradient will be 8 MPa/km or 117 MPa at 15 km. There is a great need to develop specialized and tailored detonators for these demanding environments. An optimal ignition system is the magnetic activation of a piezo-electric plunger to initiate a primary non-pressurized binary mixture to cancel the desensitization with pressure. This initial ambient pressure but highly sensitive mixture is then placed inside the “mother” cartridge to set off the main secondary but less sensitive explosive. This detonator charge is prevented from being compressed by the surrounding primary explosive with a small metal or composite pressure vessel. This represents a significant departure from Ostrovskii’s prior art of using impact detonation, since greater depths will cause high excessive desensitization which may make it difficult and or unreliable to rely on such a detonation strategy. Alternative but less proven methods may include using powerful electric charges to detonate the primary explosive, sudden heat, or simply increasing the impact energy of the plunger. The least desirable but potentially necessary solution is to simply carry onboard separate small detonator charges made of a high-temperature but solid explosive in pressure-restraining vessels to be inserted into the capsules prior to firing and or kept on board the capsules. But such an option would seem to negate the purpose of the binary explosive in the first place. The last and likely unattractive option is encasing each primary liquid explosive charge in a pressure-restraining or partially pressure-restraining casing to minimize desensitization. This will entail much heavier capsules and a portion of the energy of the explosive used to burst the metal, so it is desirable to search for solutions that can allow the primary explosive to be maintained at the surrounding media pressure.
Capsule manufacturing: High novelty potential. A method for the low-cost mass production of capsules, their safe filling with explosives, and their transportation. Due to the inconvenience of safely filling capsules on site, it is more desirable to transport them by truck to the drilling site in their prefabricated form. A number of design details will need to be highlighted to ensure safe transportation on civilian roadways. If this risk is deemed too great, capsules can be filled by separate liquid tankers at the drilling site using a containerized factory.
Blowout prevention: Very high novelty potential. Regardless of whether liquid or solids are used, accidental detonation must be assumed to occur at a specific occurrence which is a direct function of the probability of exogenous shocks and or endogenous failures occurring in the system of the rock media. If the experience results in a hypothetical failure probability of one in 100,000 hours, a necessary method must be in place to minimize catastrophic damage to surrounding surface ancillary equipment and nearby persons. Causes of accidental detonation may emanate from extraneous phenomena such as well cave-in caused by a sudden loss of fluid and pressure, the blockage and accumulation of rock fragments in the area between the hose and well wall, erosion of the delivery hose, seismic perturbations, embrittlement of metal components, cracking of capsule housing, failure of the diaphragm separator, failure of mixing system, failure of the cooling channel to maintain the explosive temperature within safe limits, failure of detonator, failure or blockage of the nozzle due to debris clogging, violet recoil caused by an accumulation of cartridges in the wellbore (multiple undetonated capsules detonating at once), failure of distance measurement system causing the nozzle to be too close to detonation zone causing severe of the nozzle by shockwaves, among many other not yet to be anticipated causes. It is therefore an exigency of the highest order that an effective mechanism to shield workers and equipment from the blast shockwaves traveling upwards is designed. Such a “shockwave attenuator” device is essential and cannot be obviated and hence may form a key component of the intellectual property. The blowout prevention system should really be named a shockwave attenuation or absorption system. When oil and gas are extracted from the crust, the release of large volumes of substance can exert forces on the well cap that exceeds its restraining strength, causing a catastrophic release of oil or gas into the environment and potentially harming workers. With geothermal drilling, rock geology tends to be harder, less porous, that is metaphoric, and igneous, rather than sedimentary, leaving little opportunity for the release of pressurized substances. The reason that oil and gas drilling, but especially horizontal drilling, can induce artificially seismicity, is due to the removal of large volumes within the crust, causing a natural reactive movement within the rock bodies. With detonation drilling, an entirely new set of exigencies exist which still serve to generate consternation with respect to the sudden release of pressure. The blowout prevention system would in effect be a large valve that instantly shuts off the flow of water out of the well. Since the detonation of some or all of the capsules would generate an immense shockwave, the blowout device must be designed to withstand pressures considerably in excess of those encountered in conventional oil and gas drilling. Another unique feature is that, unlike oil and gas drilling where the blowout prevention device is inserted after the drilling is completed, with the explosive drill, the device must be active during the entire drilling process. This is because we are not trying to prevent the escape of the well’s containments, but rather the stochastic and unpredictable capsule detonation event. The blowout unit is therefore highly unique since it must accommodate the large shaft as it passes through the opening. Nothing like this exists in the oil and gas drilling industry and hence endows a great deal of novelty upon the designer. In order to facilitate the sliding of the shaft while simultaneously providing blowout blockage, a system where the weight of the suspended shaft is used to cause the entire assembly to drop just below or horizontally or angled plunger shaft which closes the flow upon the drop of the drill. But the shrewd engineer should not rely on secondary measures to mitigate catastrophe, he must rather rely as much as possible on primary preventive measures. Such measures include making it almost impossible for individual capsules to spontaneously encounter conditions where detonation energy can be provided by natural circumstances, namely shocks, impacts, or diaphragm failures. This will be achieved with scrupulous attention to capsule quality. But nevertheless, a capsule containing a manufacturing flaw mat inevitably enters the supply, to absolutely eradicate the menacing risk of a chain detonation, a novel system where the capsules are protected with a “buffer zone” of fluid is adopted and chronicled in further detail. Since the explosive capsules are stacked vertically in the delivery hose, the cumulative explosive charge is the sum of all the individual cartridges, which represents a potential explosive power of tens of tons of TNT or more. The bulk of this energy would go to generating micro fissures in the rock since there is nowhere for the water to escape since the blowout prevention module is simply too strong to permit it to escape. Since the operator is compelled to minimize the event where all of the capsules detonate in a chain reaction, where the detonation of one provides the activation energy for another, a method to vertically separate the individual capsules is called for. Such a method may simply utilize a vertical column of water or more ideally, compressed gas, to provide a buffer zone to absorb the explosive power of a single capsule and prevent its spread to the adjacent one. The explosion of a single capsule would result in the destruction of the delivery hose, but if the explosive power is sufficiently absorbed, this force would no doubt destroy much of the shaft and hose assembly, but it would not detonate the rest of the distance capsules. In order to maintain this vertical gas or liquid column, each capsule is fitted with a seal that slides firmly against the tube wall. This makes it impossible for the capsules to fall atop each other since the media in between them would have to be compressed.
High flow cooling allows for PETN or RDX to be used with similar detonation velocity to cyclonite as well as the use of aluminum conductors to power down bore hydraulic pump. It cannot be overstated how advantageous a lower operating temperature is to the overall system’s reliability and safety. Since all ferrous and non-ferrous alloys lose strength with increased operating temperature, cooling increases the structural efficiency of the mechanism, reducing weight and thereby increasing retraction speed. An array of sensors and data collection is essential for adaptive operation, such as adjusting capsule ejection rates depending on rock hardness or the desire to achieve optimal particle size with comminution using additional explosives.
Cooling is the sine qua none of any advanced drilling technology. A number of components, sensors, and structural materials must be maintained at moderate operating temperatures to maintain their strength, stability, and performance. Explosive drilling is no different. But it may come as a surprise to some that in fact, the explosive chemical itself is not the limiting factor in the thermal management of the system. Electronics, notably the solenoid mechanism, pressure, thermocouples, data collection unit, and delivery cable are what limit the temperature of the system. Thankfully, physics and chemistry work in our favor. Water happens to have the highest heat capacity of any substance besides hydrogen, helium, lithium, and ammonia, a relatively small flow of cooled water can more than satisfactorily remove all the heat produced by the rock. Using only 200 bar of pumping pressure, in the 350mm delivery hose, a flow rate of 2100 cubic meters of water can be delivered to the drilling nozzle and back along a 12.5 km distance. A 200-bar triplex pump requires only 6 kWh/m3, such a highly cooled drilling apparatus would draw 12,600 kW of power. If the well is drilled over a 2500-hour period, corresponding to a speed of 5 meters per hour, the cost at 7 cents per kWh is around $2,200,000. But this number is far too high. The realistic sustainable operating temperature of the system is around 100 degrees C, well within the operational limit of high-temperature silicone carbide electronics and many sensors, and will be within the operational limits of cyclonite. Since the average surrounding rock temperature is 218.75 C, 35 C/km x 12.5/2, then we need only to lower the temperature by 118 C. If we choose to be more aggressive, we may settle at a temperature difference of 2.5 or 3 times, bringing out drilling unit temperature down to 70 degrees we must lower the well temperature by 148 degrees. The question is then how much water must we pump to achieve this? We first need to estimate the heat penetration rate, using this calculation, we arrive at an average thermal energy production over 2500 hours of just under 30,000 kWh. The rock is not a source of infinite heat, if more heat is drawn than it can produce, it will cool, but this is not our objective, our objective is to pull just enough heat so that the average temperature of the water does not reach an equilibrium with the rock wall. Since water has very low thermal conductivity, such a large diameter well will have a difficult time heating the block of water inside it, resulting in the rapidly flowing water possessing a lower temperature than its surroundings. Since the average temperature of the water is 70°Cand at 700 bar its density is 1007 kg/m3, the specific isochor heat capacity: cv is 3.795 J/kg-K, the volume needed is only 192 cubic meters, or ten times less than we can pump at 200 bar. This means we only need around 250 kW of power for the pumping machine, bringing out power costs down to only $45,000 per well drilled. Since we need more than 200 cubic meters for spoil removal, if we assume that the drilling fluid should not possess a fragment concentration of over 1.5%, then if we excavate 5 linear meters of rock at a diameter of 550 mm, we produce 1.15 cubic meters of rock per hour. We therefore need only 75 cubic meters per hour of drilling fluid. Of course, this number must be higher since a minimum velocity of 5 meters per second is desirable to remove heavier particles. If the flow rate is set at 800 cubic meters per hour at a pressure drop of around 230 bar, the power is 5600 kW.
Explosive drilling can more easily bore large diameter holes than rotary drilling, there is much more area available for both coolant and slurry flow. Since pressure drop is a function of viscosity and the total surface exposed to the flow, larger diameter tubes will permit higher flow rates. The Explosive Drilling Systems Inc mega-bore
If one performs basic pressure drop and flow calculations for gaseous drilling media, it becomes immediately clear that any drilling technology which is unable to use water or oil is basically impossible. Gases are compressible which means they incur much more turbulent flow and possess intrinsically much more viscosity. The results of this analysis s based on a reputable UK software program. The calculations show that it is effectively impossible to circulate enough nitrogen gas (used in the analysis) to remove the spoils not to mention the even more important requirement of cooling the wellbore. Unlike liquids, gases become more viscous as temperature increases, this is on top of nitrogen’s already 86-fold higher viscosity than water at 200 C. With a hypothetical flow diameter of 200 mm and a length of 38,000 meters (equating to a complete flow along a 15000-meter depth plus additional length to represent the added surface area of the annular flow path), the available flow rate for nitrogen compressed to 100 bar is barely 75 cubic meters per hour. Since the density of nitrogen at 100 bar is 120 kg/m3, only 800 kWh of heat can be removed with a temperature rise of 300 C. This is many orders of magnitudes below the requirement to lower bore temperature by many hundreds of degrees at the 10+ km depths where wall temperatures in excess of 400°Care encountered. It is also far less than what is needed to absorb heat produced from the hot vapor as it passes along the waveguide, not to mention removing heat from the waveguide from losses. The conclusion is due to the physics of compressibility, only liquid can be used for cooling. most of the pressure drop is not caused by viscosity, but by the turbulent flow enabled by compressibility.
With explosive drilling, when one performs a fundamental technical analysis by scrutinizing all the disparate parameters, one will quickly discover that there are no fundamental technical constraints. As long as the system is maintained at temperatures, we have a wide array of explosive options and the ability to incorporate sensitive electronics which will prove critical for adaptive operations. But most importantly, the combination of a very high slurry flow velocity facilitated low surface-to-volume large diameter bores, moderate to high viscosity water base fluid, and a reciprocating nozzle that provides intense churning force directly above a highly comminuted rock bed, we should be able to extract spoils much more effectively than Ostrovskii did or as effectively as rotary bits can.
The most frightening thing for an engineer is an insurmountable technical barrier that stubbornly refuses all attempts at amelioration. With this system, there doesn’t seem to be any one phenomenon that isn’t receptive to at least partial solutions which can be accepted by making trade-offs but still retains the underlying workings of the system.
It shouldn’t come as a surprise that the only truly “alternative” drilling technology that has indeed been tried is none other than this one out of all the possibilities mentioned in that book. This should serve as an endorsement of the underlying simplicity of the method.
The heat of detonation of most explosives is about 4-5 MJ/kg, or about 12.46 kWh/kg. Since explosive productivity of 50 kg/m3 of rock volume without comminution and 100-150 kg/m3 of rock with comminution is expected, the amount of heat released by an explosive drill with a drilling rate of 5 meters per hour is 1380 kWh, which is a negligible number. Compression heating of the water is negligible since water is largely incompressible with a bulk modulus of 3.5 Gpa.
The over-pressurized air drilling revolution
Prior concerns about air drilling mainly focus on the inherent inability of gaseous mediums to prevent the influx of liquids into the wellbore. It has apparently not been considered that gas can simply be pressurized above the formation pressure, even less than a few bars above it, is sufficient to completely halt the influx of unwanted liquids. Freshwater experiences a hydrostatic gradient of 10 MPa/km, but the real number is slightly less since the water will reach the temperature of the rock and its density will drop slightly. There is no technical limitation present with requiring the gaseous drilling media to be pre-pressurized close to the highest formation pressure likely to be encountered in the well. For example, if we use nitrogen compressed to 700 bar at 50 C, it will have a density of 463 kg/m3. Subject to a gravitational pressure gradient equal to 12 km, its pressure will rise by 545 bar. Thus, the gaseous drilling fluid will now have a hydrostatic pressure of 1245 bar, just above that of water with a density of 950 kg/m3. The equipment necessary to contain this high-pressure gas is commercially available or can be readily engineered for this application. Liquid piston ionic liquid compressors can be employed with very high efficiency.
Explosive drillings almost entirely depart from the fundamental assumptions encountered with rotary drilling in oil and gas applications, hence the drilling media, one of the most important variables, is also expected to change.
When explosives are set off in a compressible atmosphere, the preponderance of the shockwave energy is deflected upwards away from the hard surface and its energy is absorbed by compression of the gas molecules. During an explosion in liquid, the shockwave decays at a much slower rate, a difference of around 100 times. This incompressible block of mass contains the shockwave and forces more of it to pierce through the rock, but rather than crushing it into small fragments, it spalls it into much larger fragments since more energy is directed towards disintegration or spalling, but not crushing. This is understandable, since the yield of rock removed by explosive is over 10 times greater in water, necessarily, less energy is directed towards comminution and more of it towards piecing and blasting the rock into larger shards. With underwater explosions, a jet of highly compressed water acts almost like a mechanical cutter, breaking through the rock. With water, the average fragment size was slightly over 20mm, while in air, most of the fragments were powder sized, 500 microns. With liquid drilling, some fragments as large as 40mm were produced. Using the Fergusen and Church equation for particle settling velocity, a 40mm particle will fall at a rate higher than the practically attainable fluid velocity even with very high viscosity, resulting in an accumulation of these fragments in the rock bed. Unless these fragments are effectively comminuted back down to no more than 15mm by subsequent explosions, liquid explosive drilling may not be feasible.
It is expected that the mean fragment size will moderately increase with gas density, but not markedly, since compressibility drops to 0.234 kg/3/bar at 1000 atm down from 1.15 kg/m3/bar at 1 atm. Since water is 10,630 times less compressible than air, water having a bulk modulus of 2.1 GPa experiences a -0.00004762 m3/bar at a starting pressure of 1 atm. Since the difference in compressibility is 10,600 but the difference in shockwave propagation is only 100-fold, we can expect only mild changes in behavior under high pressure but compressible atmosphere.
Quoting Ostrosvkii in “deep hole drilling with explosives”:
“After several explosions in air a funnel 60-70 mm deep and 300-350 mm in diameter at the top was formed on the surface of granite. During the subsequent penetration, the surface was not shattered and a hole of true cylindrical form was developed, 80-90 mm in diameter (as against 300-350 mm for underwater explosions). The average penetration per explosion in granite was 16 mm in a hole with no water. In producing this hole the size distribution of crushed materials differed from the distribution in water-filled holes (formed by explosions) in the predominance of strongly comminuted particles; the following table shows the distribution:
Quantity of granite detached by detonation of a single charge (40 grams): 0.22 kg. Content of particles (in %) of size (in mm): greater than 7 mm 7%, from 5 to 7 mm 2%, from 3 to 5 mm 9%, 0.5 to 3 mm 20%, smaller than 0.5mm 62%. The particles of granite extracted after an explosion were crossed by numerous fractures; they consisted of clumps of crushed crystals. Structurally, altered crusts of granite, predominant features of underwater explosions when sinking holes by explosions, were not observed after explosions in air”.
The consequences of this highly comminuted fragmentation characteristic in air media are immense for deep drilling. Spoil removal had plagued Ostrovskii’s system due to the high freefall velocity of the heavier 40mm fragments, severely hampering drilling speeds as fragments piled in the well-bore floor serving to blunt the subsequent explosions. With air drilling, the small fragments can be very effectively evacuated from the bottom of the wellbore by using a down-bore suction pump. A vacuum of only a fraction of an atmosphere is enough to lift heavy pieces of gravel along multiple meters of hose. Vacuum removal of rock, soil, sand, and grain is widely used in industry. A method called “hydro-excavation” employs powerful vacuum pumps to suck dirt out of holes stimulated by water jets. The suction pump can be a liquid vane pump, positive displacement, a dry impeller, or even an ejector (Bernoulli or Venturi nozzle). When the fragments are brought inside the spoil containment unit between the suction pump filter and the inlet, they are continuously fed into a closed-loop liquid-emulsion hose where a moderately viscous liquid carries them to the surface. Since the fragments are small in diameter, they are readily carried to the surface with moderate pumping powers. In this configuration, the suction pumps only serve to elevate the fragments a few meters into the vacuum filter chamber, the rest of the carriage is performed by the pumped liquid in a closed-hose assembly within the main drilling hose. With this novel over-pressure dry drilling technology, pumping power is reduced and the only liquid in the system is isolated within the drilling nozzle.
It’s interesting that the difference in compressibility between air and water is 10,000 times. If a 1 kg TNT charge is detonated at a distance of 5 meters, the overpressure in water is around 140 bar, while in air it’s only 1 bar. While in a denser compressed air gas atmosphere, one would expect the pressure decay to occur somewhat slower, the difference will likely not be large since air remains almost as compressible at the equivalent hydrostatic pressure of water as 12 km. If we extrapolate the pressure wave decay rater as a linear fraction of the compressibility, we can estimate the additional shockwave pressure, then if the compressibility factor of water is 10,000 and air is 1, and the shockwave wave decay rate is 100 fold difference, we can simply divide the shockwave pressure decay ratio by the compressibility ratio and then multiply by the decrease in compressibility, arriving at an increase of only 0.08 times the distance traveled in a 1000 bar gas atmosphere. Of course, there is no empirical formulae available from the literature nor any experimental data on explosive shockwave behavior in high-pressure gas atmospheres, so we can only deduce a relative ratio assuming linearity, but this may not be the case, but observing the differences between the two extremes, nearly no compressibility, and almost infinite compressibility, it’s not expected a small 8 fold drop in compressibility would substantially alter both the shockwave distance and the comminution behavior. Although it must be tested before financial performance can be calculated with any degree of confidence. But what can be said is that a 1000-order-of-magnitude decrease in compressibility only increases the shockwave pressure by 10 orders of magnitude.
Oil and gas drilling occurs in highly porous, soft, plastic sedimentary deposits with large adjacent reservoirs of liquids under great pressure. This forces oil drillers to use high-gravity weighting agents such as barite to increase the hydrostatic pressure of the drilling fluid to above the formation pressure. In geothermal drilling, with the use of modern prospecting technologies or what’s called “exploration geophysics”, including technologies such as magnetotellurics, transient electromagnetics, rock strata with low water and hydrocarbon content can be identified permitting dry drilling. In cases where groundwater is still present, an over-pressurized drilling strategy is employed, but this strategy can still use gas.
In rock strata that are largely dry and structurally intact, the use of an underpressurized drilling regime with gas enables greater depths due to negating the pressure-dependent desensitization of the explosive. Ultimately, drilling depth is limited by the brittle-plastic transition zone, which can occur as shallow as 10 km to as deep as 20 km depending on the intensity of the geothermal gradient and rock type. Granitic rocks have a high threshold for plasticity, as high as 800 C, while quartz can be as low as 350 C. When the rock becomes excessively plastic, much of the explosive energy is diverted to compressing the rock, and drilling productivity is expected to fall off sharply. Moreover, wellbore stability will be severely compromised and collapse will ensue. This suggests an upper limit of about 12 km, corresponding to around 400 C down bore temperature, is the limit regardless of drilling technology. the real untold limit to drilling depth is neither technology or heat, it’s the brittle-ductile transition zone that depending on the age of the strata, occurs around 15 km where rocks lose much of their brittle nature and will yield plastically, making well-bore collapse almost inevitable, not to mention rendering explosives useless.
#1 The ability to increase drilling rates between 10-50x fold over liquid due to small fragment size eliminates the issue of well-bore cleaning. Productivity depends on vacuum power and powder removal speed more than explosive delivery rate. 50 m/hr is more than feasible.
#3 The rapid attenuation of blast incident pressure due to gas compressibility allows a higher frequency of capsule delivery without transmission of initiation pressure without the use of a valve of capsule delivery and reduced need for nozzle offset. Additionally elimination of any recoil-absorption system.
#4 Vacuum-based fragment removal due to very small fragment size, mean size of less 1mm, effectively powder.
#5 Elimination of elaborate and costly fluid-fragment separation sieves and shakers at surface reducing CAPEX and installation time of rig.
#6 Reduced environmental fears due to the absence of toxic oil-based fluids.
#7 A huge reduction in operating cost is afforded thanks to the use of nearly free atmospheric gas. By eliminating an oil-based drilling fluid with a market value of at least $200-500/ton results in savings of up to $4 million per well drilled. If a well is drilled with oil where lost circulation cab approach 50 to even 100 bbl/hr (avg of 12 m3/hr), assuming an oil density of 870 kg/m3, the cost of simply replacing the lost oil is $3100 per hour! If it takes 3000 hours to drill the well, assuming a drilling speed of 4 m/hr, the cost of the oil alone is over $9 million. Nitrogen is effectively free, its cost is solely a function of compression energy required for both separation (which is negligible) and ultimately compression to 700 bar for its use in the well at great depths. If a lost circulation (volumetrically) of 75 bbl is assumed, since this is the rate that occurs with water-based fluids, and gas will be at the same pressure as water, then we can expect an operational cost of only $6.75/ton-water equivalent. A ton water-equivalent is a cubic meter of nitrogen at a density that yields the same hydrostatic pressure as water. Since we can assume losses to well porosity are a direct function of the pressure of the drilling fluid relative to the pressure of the formation, we can assign the nitrogen fluid the same loss factor as water, or 12 cubic meters per hour. Since the electricity cost is only $7/m3, the cost per hour is a paltry $84, or $252,000 per well, a negligible cost that ranks up there with trivial factors like permitting or site prospecting. Using a four-stage inter-cooled compressor, only 0.186 kWh is used per kg of nitrogen raised to 700 bar. The density of nitrogen at 1000 bar is 536 kg/m3 at 60 C, data is not available at 1200 bar, but this number is close enough since density grows slowly with increasing pressure.
Another advantage afforded by gas drilling is a dramatic reduction in pumping power since only a small volume of low-viscosity gas, namely nitrogen, is needed for the operation. Since the gas need not possess viscosity to carry fragments to the surface, its only function is to provide over-pressure to prevent liquids from entering the hole.
Design variables of a over-pressurized capsulized drilling apparatus.
The five fundamental design exigencies are cooling, sympathetic detonation prevention, spoil removal through suction, trade-off between explosive sensitivity for safety and sufficient sensitivity for impact detonation, capsule construction material, nozzle construction material selection, surface shockwave attenuation, and hose design. Cooling is arguably the least of our problems. In a dry drilling system, we can still pump sufficient water to carry away any heat that will otherwise warm the explosive capsules. Gases have very low thermal conductivity, in the case of nitrogen, at the pressures and temperatures of the media in down-bore conditions, a thermal conductivity of only 0.088 W-mK is found. This low-conductivity gas acts to create an insulating barrier between the drill string and the well-bore surface. Since the drill string is at least 40mm smaller than the well diameter, the heat flux from the surface of the drill string and the surface of the hot rock is only 342 W.
Future critics of explosive drilling may adduce evidence of the increasing rock plasticity with pressure as an indictment of the technology. Since explosives do not work well in rocks that yield plastically, there is a clearly defined depth limit. But in reality, the issue of increased rock plasticity with depth is not really a technologically specific problem, it’s a process-specific problem. One should separate a process from the method to achieve such a process. Explosive drilling is merely a method to deliver a highly concentrated form of kinetic energy to the rock body, it does not attempt to eliminate fundamental geological and physical challenges present. Any drilling technology will be unable to make any progress past the brittle-ductile transition zone to wellbore cave-in concerns. If the rock can yield plastically, it will slowly cave in and jam the drilling string. Since neither millimeter wave nor explosive drilling is practically using a liquid drilling fluid, we are stuck to drilling up to the plastic zone and perhaps a little more, but not much.
In theory, hampered drilling rates past the brittle-plastic transition zone may be circumvented by allowing the rock bed to cool by flushing gas prior to each detonation, this may drastically slow down drilling, but may make it possible to go past 12-15 km. Since each explosive charge only penetrates a few centimeters, imagine we wait 1 minute between each charge, allowing a 1-centimeter layer of rock at say 400 C to remain in contact with a 50 C gas stream exiting the nozzle, such a scenario would result in a flux of 14,000 watts, since the layer of rock would weigh 4 kg, a temperature drop of 200 C would occur in 60 seconds (840,000 J/14,000 J/s). Of course, such a method severely slows down drilling, but it offers a simple option to accept much slower drilling for a few extra kilometers’ worth of heat. Since the plastic zone is only encountered after at least 12 km, most of the drilling is in “fast mode”.
Of course, the above scenario assumes some method to prevent wellbore collapse in the plastic zone is developed, and this is a major assumption. There are a limited number of options outside of filling the entire well with very high-pressure liquid that can achieve the above objective. Even if a column of water is placed between the packers and the drill string, the few meters of well between the packer and the floor will still be liable to cave in. Furthermore, if this column of water is subject to the hydrostatic pressure of the rock as it yields plastically pressing against the water column, the water will experience a sharp rise in pressure, potentially above the maximum tolerated by the explosive. It does not seem like any technological option can work around this problem. Therefore, it concluded that a maximum depth of 12 km is realistic, but in areas with sharp geothermal gradients, the depth of brittle-plastic transition is shallower.
There are no real “downsides” of dry drilling other than its inability to prevent well-bore cave-in of rock in highly plastic regions, but drilling in these regions is not really practical or likely to ever be performed, so this attribute is really of no value to the overall operation. Since an overpressure can be maintained negating the issue of water influx, the gas-based system still fulfills the crucial requirement of preventing excessive liquid influx which is expected to occur in almost every well, even those that appear dry based on surface measurements and inferences. The only disadvantage or deficit a gas-based system is reduced buoyancy experienced by the drill string compared to when suspended in water. This difference in buoyancy for the metal equipment is negligible since the likely material candidates are alloys with a density of at least 5000 kg/m3. The only real effect is with the cooling water. Since nitrogen has a density of only 560 kg/m3, the weight of the water is effectively doubled, adding around 79,000 kg of additional mass in the drill string. The relative gravity of water is 1.7x the compressed nitrogen. To help carry the additional mass of the string, as long as straightness can be guaranteed with periodic measurement, one does need to actually suspend the entire drill string, allowing a reduction in its weight and cost. A series of inflatable packers operating at for example a 50 bar over-pressure can place force against the wellbore wall, which has a high friction coefficient. These packer seals can effectively bear most if not all the weight of drill string. To illustrate the immense tractional load-bearing capacity of a pressurized packer, a single 200mm long packer pressurized to 50 bar can generate 75,000 kg at a friction coefficient of 0.5, corresponding to the typical value for aluminum against rock. A higher friction coefficient can be attained by using a coarser surface
Transmission of shock waves and the potential to initiate adjacent explosives without the use of a closing valve. Explosive Drilling Systems Inc has devised a novel feature to mitigate the risk of shockwave-induced detonation of capsules suspended in the delivery hose. Since water is incompressible, shockwaves from the detonation center can propagate substantial distances. We have developed a novel valve closing mechanism whereby the main capsule hose is deviated sideways within the main drilling unit housing to permit the rotary valve to rotate within the casing and lock into place over the hose area, blocking shockwaves from compressing adjacent capsules.
Capsule feeding mechanism, rigid welded tubular sections, and continuous kevlar-titanium composite cables.
The main fluid delivery hose to the drilling nozzle is constructed out of carbon fiber lined with aluminum covered by an abrasion-resistant ceramic liner. The ceramic liner is then adhered to the metallic surface using a mesh. To reduce roughness, a removal additional metal liner constructed from very hard carbon steel is added. The main load-bearing component is thus the interior carbon fiber sandwiched between the abrasion liners.
Shockwave valve, Ceramic abrasion-resistant coating. Lining the drilling fluid delivery hose with an abrasion material, including a number of water-resistant ceramics, may be desirable for increasing the useful life of the thin-wall metallic hoses. Since the velocity of the drilling fluid can exceed 10 meters per second, considerable erosion potential exists due to the presence of sharp rock fragments.
The inability of coiled hosing to accommodate blowout prevention, and extreme insensitivity of phlegmatized bonded cyclonite. Resistant to gunshots. Those who adduced safety concerns from the use of high explosives are miseducated on the nature of explosive sensitivity. When cyclonite is placed in a binder solution containing paraffin wax or even motor oil, the sensitivity especially to intra-Chrystal friction drops off substantially. Composition A-3 is 91% RDX and 9% paraffin wax. Composition C-4 is 91% RDX with 2.1% polyisobutene, 1.6% motor oil, and 5.3% Dioctyl sebacate. Of course, such formulations necessarily increase the cost of the explosive, but since the moldability properties are not needed for a melt-cast explosive, only the phlegmatizing agent is desired. Motor oil or wax is sufficient to phlegmatize the explosive. CH-6 is a booster explosive with 1.5% calcium stearate and 0.5% polyisobutene and graphite. Before wax could be derived from petroleum, it had been derived from bees which made it prohibitively expensive. Parrafin wax costs only $1000 per ton.
Lost circulation due to water entry. Oil and gas wells that are porous allow higher-pressure water to enter the drilling fluid, diluting it and causing its properties to be altered as a consequence. The need for a low-cost viscosifying agent is of paramount importance for wells where porosity is too high for oil to be used.
A very high-density fluid like barite which can exceed 2400 kg/m3 will experience much greater gravitational acceleration than plain water at 1000 kg/m3, resulting in a situation where the drilling fluid possesses 2.4 times the pressure than the water in the rock pore space. This permits the drilling fluid to penetrate provided the water has the ability to migrate into new void space. Barium sulfate is quite abundant and there exists alternatives such as ilmenite, hematite, and manganese tetroxide. Unfortunately, despite the advantages these fluids confer, they impose deleterious effects on explosive properties.
The need to develop a telescoping shockwave isolation system.
At the well site where the hose enters the hole, an exotic method to prevent highly pressurized water and fragments from hitting personnel and equipment is needed. A novel mechanism is needed where the entire blowout prevention device, capsule feeder, and slurry delivery system is lowered as the pipe is descended into the ground.
The Hydrostatus Systems explosive drill employs a novel height-varying telescoping pressure vessel to contain water from being ejected out of the well by the rare event of an uncontrolled down-bore detonation
This mechanism is elucidated in great detail in the patent drawings.
Choice of drilling fluid.
Since the explosive drill is expected to find the mainstay of its use in drilling so-called “hot and dry geothermal”, drilling fluids demands are unique compared to oil and gas.
The demands of an explosive drill are quite different from an oil and gas rotary drill due to a number of unique requirements imposed by hydrocarbon extraction. Hydrocarbon extraction is an inherently tricky process due to the presence of large bodies of pressurized fluid which must be both extracted and contained. The major requirement of oil and gas drilling fluid besides possessing sufficient viscosity to remove cuttings is to provide enough density to generate a hydrostatic pressure greater than the oil and gas encountered to prevent blowout. One must remember that unlike geothermal, a hydrocarbon well is fundamentally a volume-altering project, where massive volumes of liquid or gas are suddenly allowed to encounter a flow path. This imposes immense challenge, requiring what is called a “kill fluid” to plug wells using its own gravity. Secondly, the nature of the rock strata is very different, rather than drilling in porous sedimentary deposits with the presence of highly pressurized fluid reservoirs at relatively shallow depths, geothermal sites under the so-called “hot and dry” strategy tend to have low porosity and very small quantities of water. To illustrate the relative preponderance of shallow wells in oil and gas, Another difference is that, unlike oil and gas drilling where heavy casing and drill strings must be suspended, there is no need for the additional buoyancy afforded by highly dense drilling fluids. The use of denser fluids naturally reduces the weight of the drill shafts and casing. With geothermal drilling, there is less need for casing as long as the rock is crystalline and fluid incompressibility provides structural support. Secondly, the absence of thick drill shafts and comparatively light hoses used for capsule and fluid delivery make it less important to achieve high density. In fact, a high-density fluid is inherently problematic for an explosive drill, since all explosives become desensitized at extreme pressures. At the hydrostatic gradient of water, a depth of 15 km is still within the range of RDX’s “dead-pressing” pressure. The so-called “dead-pressing” pressure is the pressure at which an explosive is no longer able to sustain steady-state detonation. No number has been published for RDX, but it’s well over 50,000 psi if not close to 100,000. A Russian study found that RDX readily detonated at 1200 bar. This desensitization is caused by the complete elimination of pore volume from the squeezing of crystals together. Pore volume is essential to achieve sufficient sensitivity since they provide air pockets within sensitive zones in the explosive needed to catalyze oxidation. Bentonite, barite, hematite, ilmenite, and other dense metal oxides and other “weighing agents” are routinely added to produce fluids with densities as high as 2400 kg/m3. Another reason such high-density fluids are used is to produce the necessary hydrostatic pressure to prevent high-pressure reservoirs from spilling into the well. The upper crust is thought to contain on average 2000 ppm H2O in feldspar stored within sub-micron inclusions and microcracks. Although there will still undoubtedly be many wells drilled in otherwise dry crystalline rock where bodies of fluid at higher pressure than the hydrostatic gradient of the drilling fluid will be encountered. This is one of the several major limitations of milli-meter wave drilling, using compressible air as a drilling fluid, and being sensitive to water both in the attenuation of the microwaves and the structural integrity of the waveguide, will make it very challenging to drill in areas that contain all but the smallest quantities of water. Lost circulation is another major issue with oil and gas drilling due to the porous and reservoir-rich nature of oil and gas drilling within sedimentary strata. Water-based fluids are favored due to the high cost of oil, since as much as 16 cubic meters of drilling fluid are lost in an hour in oil and gas drilling, the use of even cheap vegetable-based oils would amount to multiple millions of dollars per well. Since vegetable oils have a wholesale value of around $150 per ton, the cost per hour is $2000 just in oil loss, or $5 million over a 2500 hour period. This cost may be tolerable if the subsequent economic output of the well in terms of energy value is high enough. Decomposition of the oil itself, although expected to occur slowly due to the high fluid velocity in contact with hot rock, will not be dominant loss factor since the product gases can be resynthesized into high-chain length molecules.
In contrast, where the explosive drill is expected to be used, rock geology will have low porosity, a small reservoir volume, and minimal to reduced risk of the unwanted fluid entrance. Using oil-based drilling fluids, since the hydrostatic pressure of the oil will be by definition be below that of hot water, the water will tend to flow inside the borehole and displace the fluid, preventing it from seeping into the pores and being lost. It would be possible to recover the oil-based fluid by allowing the higher-pressure water to push the oil to the surface. Since oil and water cannot mix, separation is easier. Oils have the advantage of not needing viscosifiers since they already possess high viscosity. The drop in viscosity otherwise caused by temperature is canceled out by the increase in hydrostatic pressure, so the original viscosity of the fluid is largely preserved. More importantly, while viscosifiers such as Xanthan gum will lose viscosity from shear-induced thinning, oils maintain their viscosity regardless of the shear force. The average natural gas well in the U.S in 2008 was only 1981 meters deep, which is trifling compared to the 12-15 km targeted for geothermal. The fact that Quaise energy can legitimately claim to be able to drill in deep crystalline bedrock with no liquid as a drilling fluid suggests either a large fraction of the curst is indeed largely anhydrous or they are making negligent claims, the latter considering the unsubstantiated claims of ultra-low waveguide losses, is more likely the case. One fascinating and somewhat indicting case study is the Kola deep well. The Russian team encountered significant quantities of water past 7 km, and even more surprisingly the rock was highly fractured. The team also noticed the presence of hydrogen gas along with other gases including helium and carbon dioxide which was found to be bubbling out of the drilling fluid. Another interesting geologic finding was the absence of granite to basalt transition zone, predicted by prevailing geologic theory.
“It was established for the first time that zones of highly porous, fractured rocks saturated with deep subsurface waters exist at depth in older shields; their presence had previously not been assumed. Some special features of the chemical composition of subsurface waters were found, which represent a substantial contribution to a model of the hydrophysical zonality of the Earth’s crust. The physical state and properties of rocks at a depth exceeding 10 km were identified by the new data obtained. At places a high permeability of the rocks was fixed, which is important for prognosticating underground “hollows” and assessing the possibility of their use for burying highly toxic industrial wastes”
In short, one must be highly cautious about claims of the deep crust, since drilling is so costly, existing knowledge of the crust’s characteristics and properties rely either on nebulous computer models or a select few deep drilling projects, otherwise, virtually the entire earth’s underbelly is hidden from our instruments.
Performing calculations using the Stokes law equation, the conclusion drawn is that density, and hence buoyancy, plays a negligible role in particle lifting compared to viscosity, which can be said to be the all-important number. Since many of the unique exigencies faced by drilling into sedimentary porose and reservoir-rich strata are eliminated, a geothermal drill may not need any weighting agent. Rather, the need for a moderate temperature-powerful viscosifier is essential. A number of viscosifying agents are used in the oil and gas industry, but since chip size is typically much smaller than with an explosive drill, the level of viscosity required for satisfactory chip removal is much less. A successful explosive drill, unless featuring a down-bore comminutor, will produce a mean fragment size of around 10 mm, therefore a high viscosity but necessarily cheap drilling fluid, ideally water, but perhaps also oil, is essential. If water is used, a strong viscosifier such as xanthan gum, polysaccharides, and polyacrylamides rea needed. Xanthan gum is the most widely used agent. Less than 1% xanthan gum raises the viscosity of water to over 2000 centipoise.
The cost xanthan gum ranges from $1500-2500/ton, it is fermented by bacteria from glucose. On average, the volume of a well 500mm in diameter would total 6.18 tons of xanthan, If the 1% solution were to last 10 hours before complete replacement is needed, the cost per hour is $1200, or $3 million per well, an acceptable cost. 3 million is a rather negligible sum for drilling a 12 km well into crystalline bed rock, considering the Kola deep-bore cost $100 million.
Regrettably, the gum tends to decompose unless the pH is quite high, but then rapidly degrades if the pH is over 11. Proper alkalinity regulation is therefore important for the maintenance of this viscosifier. Since it degrades, one would need to constantly add new gum to the fluid, but since it’s only 1% of the volume of water at best the cost would not be significant unless decomposition was very severe. Using the Stokes equation, which is not exactly accurate but close enough due to the non-Newtonian nature of drilling fluid with suspected particles, extensive estimates of drilling particle sinking rates were ascertained to determine the maximum particle size that could be extracted. Since there is an upper limit on particle size, a certain fraction of the rock mass will never be removed, settling back down to the bottom before the fluid reaches the surface. This will mean this fraction of larger fragments will be crushed down to smaller sizes by subsequent explosions. A natural form of filtering favoring comminution thus occurs automatically since certain very heavy particles will leave the well-bottom. But since no formula exists for non-Newtonian fluids, the Stokes equation can be used for a rough approximation. If the particle size is 10mm, viscosity is set at 100 centipoise, which is the high end of conventional water-based drilling fluid viscosity, and fluid density is 1000 kg/m3, free-fall velocity is around 1.2 m/s. So a drilling fluid velocity of at least twice that is needed to carry the fragments to the surface in an expeditious time frame. If the pumping pressure is set at 250 bar, annular diameter is 350mm, distance is 22,000 meters, viscosity is 100 centipoise, fluid density is 1000 kg/m3, and surface roughness is 5mm, the flow rate will be 1400 m3/hr and the velocity will be 4.15 meters per second. This velocity is enough to carry rock fragments as large as 15 mm, which is expected to be at the high end of the particle size distribution. To illustrate how sensitive particle size is to spoil removal efficiency, if the particle is only 5mm, the free-fall velocity drops to 0.2 m/s under the same viscosity and media density, meaning our fluid velocity need only be say 0.4 m/s. This difference between the free-fall velocity of the suspended fragment and the surrounding media velocity is abbreviated as the “slip velocity”. Theoretically, it only needs to be a slight margin above the free-fall velocity in order for the fluid to cancel out the fall of the particle under gravity. The Stokes equation dictates that the overall flow rate is not important but rather the fluid velocity. A finding that works in the favor of the technology is the pressure drop sensitivity to fluid density rather than viscosity. A large increase in fluid viscosity generates only a small increase in pressure drop, but a much smaller increase in specific gravity generates a much larger pressure drop. A relatively low-density but highly viscous fluid is ideal.
Since smaller explosive charges produce a more uniform borehole and smaller mean fragment size, a design where a large capsule contains multiple independent charges that detonate individually, may be a useful R&D avenue.
The drilling engineer faces a fundamental conundrum when attempting to drill deeper than about 10 km. At 10 km assuming a geothermal gradient of 35 C/km, the wall temperature of the well-bore will reach above the anaerobic decomposition of most mineral oils, resulting in substantial losses to decomposition above the base-line losses from lost circulation, which generally are at 20 bbl/hr. 20 bbl/hr is equal to 3 tons of oil lost per hour, at a cost of $600/ton, this represents $1800/hr alone. If the well takes 2500 hours to drill, the cost of replacing the oil alone is $4,500,000. At a depth of 15 km where temperatures are expected to reach 525 C, the decomposition of the oil-based drilling fluid will be substantial.
The rhermal stability of most minerals with minimal oxygen present is over 10,000 hours at 300°Cor below, but temperatures of even slightly above 350°Cresult in rapid degradation in less than 50 hours.
Furthermore, even if decomposition is accepted as a necessary price to pay, the oil will still lose much of its viscosity as the outer portion heats up to the temperature of the rock. Since water-based fluids suffer from intrinsic limitations, lack of viscosity, and lack of thermal stability in the viscosifier, etc, mineral oil is simply far more attractive. Xanthan gum, polyacrylamides, polymers, etc, are expensive and rapidly decompose, requiring periodic replacement in the water-based drilling fluid. Worst yet, xanthan gum is pseudoplastic, a non-time dependent shear thinning property, much like thixotropic, but without being time dependent. With intense churning and stress applied, the viscosity of these gums drops dramatically, this is a property called pseudoplastic or thixotropic. Motor oil only substantially changes in viscosity with temperature, and shear rates do not substantially degrade its viscosity. Mineral oils, be they vegetable oils, hydraulic oils, motor oils, or gear oils, are ideally suited for fragment removal for an explosive drill. An additional factor that favors oil has to do with its low density yet high bulk modulus. Since explosive drills will be used in low-porosity rock and will rarely be used for oil and gas extraction, the high density of water-based fluids with mineral weighing agents fluids is not genuinely needed. With reduced hydrostatic pressure, the operational depth of the system is increased substantially compared to when heavy muds are used, since at 20 km the hydrostatic pressure of oil at 860 kg/m3 will only be 1700 bar, which is well within the detonation range of cyclonite.
Turning to the crux of the matter, the actively cooled drilling fluid system is very simple at first glance. It is an elegant attempt to harness the propitious fragment removal properties of while harnessing the stellar cooling properties of water. Rather than flowing the drilling fluid and cuttings through an annular space between the shaft and the bore wall, we flow the cuttings and fluid through a similar annular space inside the drilling hose. The same amount of space is still available, the only loss of space is from the thin partition wall. This allows us to fit another sealed annular channel against the rock and adjacent to the drilling fluid channel to facilitate cooling using water. This water not only cools the overall system preventing the decomposition of the explosive, but it protects the thermally sensitive oil from touching the hot rock surface. Since water has low viscosity, higher density, unparalleled heat capacity, and thermal stability, its use as a coolant makes far more sense than oil. The oil is then used solely to extract cuttings and provide additional cooling since it still has over half the heat capacity was water and will absorb heat from its surroundings even better than water since it has high thermal conductivity. Essentially, this novel architecture employs a large diameter drilling hose, that fits nearly the entirety of the well diameter, to provide two separate flow channels for water and drilling fluid. The essential feature is that since the water channel is on the outside, the oil flows within the cool portion only, and is only in contact with the hot rock for a few milliseconds in the hot rock bed just beneath the nozzle. A series of actively modulated packers (essentially just seals) prevent oil and water from substantially mixing, since there is always a thin layer of water between the rock wall and the exterior of the hose. Interestingly, this layer of water and the layer of water flowing within the cooling annular channels act as insulators slowing down heat flux from the rock wall to the oil on the interior, slowing the rate of oil heating. The packers are periodically relieved allowing the drilling apparatus to descend. Since water and oil are not miscible, the oil will be at a higher pressure than the water, and the viscosity of oil is 100 times higher than water, there will be minimal loss of the oil to the surrounding environment. Since the well-wall is not perfectly smooth, the packers are designed to flex and tightly wrap around the rock using internal pressure to provide strong adhesion to the rock. The packers can be constructed out of metallic mesh, high-temperature synthetic rubber, and fibers. The interior of the packers will be cooled by an internal and controlled flow of water or oil which is used to actuate the packers. A small loss of oil is simply unavoidable, no technology is perfect, and we are not delusional propagandists, we fully admit that deep drilling, even explosive drilling, is an intrinsically failure-prone endeavor operating in perhaps some of the harshest and most antagonistic operating environments that any machine is forced to endure. Failures and performance below expectations is the “de facto” condition a shrewd engineer expects in any deep drilling endeavor, and during estimates and calculations, extreme conservatism is wise to avoid terrible disappointment. Physics is uninterested in the Pangolissians spreadsheets and videos of startups. But with the gloominess of reality aside, the crucial thing to consider is the overall “soundness” of the architecture, the expansive system that provides the fundamental working principle must be clearly laid out and contemptible with existing materials and technologies. In evaluating this concept, there is nothing about it that is fundamentally unproven or outlandishly ambitious. We are simply diverting the cuttings and drilling fluid inside the hose rather than between the hose and the well. Then we simply use a few packer seals to attempt as best as possible to prevent the mixing of the water used as a hydrostatic support between the drilling hose and the wall and the oil-based drilling fluid that is circulating at the bottom of the system. As long as the packer can reasonably tightly attach itself to the rock wall, and fluid channels are not punctured, the system will operate as anticipated. In fact, this architecture is not really a technology, it would be akin to cutting a piece of wood and collecting sawdust at the same time is a technology. Nothing in the drilling process changes, with the exception of releasing and re-pressurizing the packers. The expected weakness or downside of the architecture is the limited life of the packers and their necessary overhaul. But since the most wear-prone and life-limited component is the retractable nozzle, it’s expected that overhaul rates will largely converge. The constant pulsation of fluid generates localized concentrated fatigue stress on the nozzle shaft, nozzle, spring, and valve mechanism. These components are not expected to last more than 50-100 hours before overhaul is due.
In summary, we have developed this unique drilling architecture in order to exploit the high viscosity of minerals without worrying about excessive decomposition at depths greater than 10 km. Secondly, and perhaps as important, the architecture allows greater flow rates since rather than flowing the fluids, both water, and oil, over a rough rock surface, they are channeled inside a smooth metallic wall, incurring much less pressure drop, both reducing pumping power or permitting more flow.
Lastly, the option achieves far more than preventing the decomposition of the oil, it preserves its moderate temperature viscosity across the entire depth of the drilling operation, preventing a loss in cutting removal efficiency. The combined effects of this novel architecture is expected to raise the drilling rate by at least 2 fold above the baseline achievable with merely the reciprocating nozzle alone.
Mineral oil, depending on the exact formulation at 50°Cat an average hydrostatic pressure of 600 bar has a viscosity of 100 centipoises, while at 1 bar, it’s 35. The exact viscosity pressure coefficient is largely consistent across different initial viscosity levels. At 100 bar, it’s approximately 400 centipoises.
Viscosity vs pressure curve for a selected mineral oil at varying temperatures.
This means if we maintained an oil temperature of only 50 C, corresponding to an average cooling duty of 170 degrees, if we had a viscosity of 50 cp at 1 bar, will have 142 cp at 500 bar, but since the average hydrostatic pressure is 600 bar, the viscosity will be close to 200 cp. At a viscosity of 100 cp, the free-fall velocity of a 20mm fragment is 3.89 m/s, since the fluid velocity will be in excess of 6.5 m/s, such particles will still reach the surface in about 42 minutes. Since fluid velocity is a direct function of turbulence and pressure drop, to attain a sufficiently high fluid velocity to carry heavy fragments, a larger parasitic power load is the price to pay. In our case, the oil is delivered via the capsule delivery nozzle at a rate of 440 cubic meters producing a velocity of 6.8 meters per second. Since each capsule contains around 2.5 kg worth of explosives and produces a volume of 50000 cubic centimeters, a rate of 60 capsules per hour is sufficient. A low capsule delivery is highly advantageous since more time can be spent with the nozzle extended providing high-intensity fluid flushing at the rock bed.
The choice of a suitable drilling media is critical. A water-based fluid lacks the viscosity necessary to transport fragments to the surface. An oil-based media has the advantage of high viscosity and moderate density which reduces hydrostatic pressure. Since specialized formulations of synthetic or mineral oils can cost in excess of $1000/ton, a cheaper option must be sourced. One such option is pre-used lubricants, hydraulic fluids, and heat transfer oils that have maintained their viscosity but have undergone mild decomposition. To reduce drilling costs, used hydraulic or motor oil may be used with a wholesale value of under $150/ton. A number of organic oils may also be sourced for a price range of $150-300/ton. A high content of metallic contaminants in the case of lubricants is not of concern for a drilling fluid, since these contaminants increase the viscosity. If certain drilling projects are located in regions with rich ground water reserves, leakage and contamination may be of concern. In these scenarios, the use of organic high viscosity oils may be attractive, although such oils usually possess lower thermal stability.
Since HMX is produced in 16% yields from RDX synthesis, one could employ a clever strategy where the majority of the synthesis product, namely the RDX can be sold commercially to cover the costs of HMX production. Since the defense industry is experiencing a renaissance due to the Ukraine conflict, there will be great demand for RDX. The only downside to this system is the added investment of having to build a much-oversized plant and the need to find a reliable customer to purchase the explosive continuously. Since the majority of the 15 billion global RDX still goes for defense applications, it may be difficult for oneself as a government contractor unless the explosive could be produced for cheaper. Using the high-altitude wind turbine, it’s conceivable that one could undercut current producers by producing cheaper ammonia and nitrates which accounts for the majority of the cost of RDX. If the cost of RDX can be lowered through the use of non-baseload electricity, one could conceivably produce it for cheap enough for it to be sold to non-military customers who currently rely on low-brisance explosives such as ammonium nitrate and dynamite.
“The explosive drilling method utilizes explosives in capsule or liquid form which are delivered to the bottom of the hole through a drill pipe. The Russians have extensively tested explosive drilling. One model using capsule explosives developed 68 horsepower. The bottom point of the drilling fluid circulation had to be some distance above the bottom of the hole to prevent dilution and washing away of the explosive, and this resulted in poor bottom-hole cleaning. Explosive drills are not greatly affected by rock strength. However, they are least effective in clay and weak rocks that yield plastically. The high cost of explosive charges in capsule form, emplacement problems, rock removal problems, and the problem of keeping the hole in gauge combine to make this method unattractive”.
Report No. FHWA-RD. By United States. Federal Highway Administration. Offices of Research and Development · 1974
The above summary is from a U.S government report, but note that while they do adduce valid concerns, none are insurmountable, such as in the case of micro-wave drilling where an absolutely anhydrous environment is required.
“Emplacement problems” refers to the design of the nozzle shaft rig attachment and control unit. Since an explosive drill does not rigidly secure to the bore wall, it is free to wobble back and forth in the wellbore, as well as vertically. This can be easily solved with a retractable grapple that slides against the wall to secure the smaller explosive nozzle or the use of packers, which is the strategy we are employing to facilitate the close-fluid circulation concept. “Gauge” refers to the size of the drill relative to the size of the borehole, by definition a standard rotary drill will produce a hole the same size as the bit, unless reaming is employed or the hydrostatic pressure compressed or enlarges the whole after it has been drilled. The issue of spoil removal is by far the most critical and arguably the only salient one, the other two can be easily solved with minor design changes. The issue of keeping the hole diameter to nozzle diameter (so called “gauging”) was not mentioned in Ostrovskii’s 130 page book, so it is not clear how the report came to this conclusion. So called emplacement was not mentioned either. It is likely that the report drew from the findings of AAI corporation during their experience drilling shallow air-fluid wells. The AAI report conclusion was not gloomy by any means, most of the disappointing results were due to the use of air as a drilling medium which reduces explosive productivity by ten fold.
“This concept should not be discarded for its potential in being able to limit the bulk weight of the ADM drilling equipment is extremely attractive and it should be fully evaluated. It was demonstrated that the technique of using explosive capsules to drill hard rock is sound”
In departing from Ostrovskii’s insistence on using post-mixed binary liquid explosive capsules, Hydrostatus Systems is planning on using highly engineered composite capsules filled with pressed hexanitrostilbene.
There is no strict reason to use a binary explosive other than its theoretically improved safety profile. But this claim is dubious if critically examined. Once the capsule is mixed, all the Sprengel explosives presently known highly impact and shock-sensitive, defeating the entire motivation of using this cumbersome and unreliable explosive in the first place. Since mixing is a process that requires some time to elapse, the capsule can still explode in the barrel just before being ejected. Unless the binary mixture is mixed extremely rapidly just prior to hitting the rock, there is still a considerable if not higher risk that the mixed but highly sensitive liquid explosive will detonate than a very insensitive solid explosive. If an effective blowout prevention device is installed, vertical fluid columns separate the individual charges, and mechanical firing pins or impact detonation is used, there seems to be little rational reason to use liquid explosives. The probability of the unmixed capsules experiencing a disturbance strong enough to cause their ingredients to mix is slim to none. In fact, the only real risk is leakage and corrosion, a major issue with tetranitromethane, which reacts violently with most metals. Tetranitromethane when used as rocket fuel in the 1950s had to be stored in metal containers lined with plastic, along with any plumbing and piping components. The second major disadvantage of tetranitromethane is its low decomposition temperature, it solidifies into a solid at 130 and begins decomposing. This relatively low-temperature tolerance means more effective cooling is necessary, necessitating more water pumping velocity and power. In contrast, hexanitrostilbene decomposes at a rate of 0.1% per hour at 260°Cand only begins to appreciable decompose in excess of 300 C. The initiation pressure is 11 kbar at 260 C. The impact sensitivity of HNS is 30 cm or 240 Newtons. The friction sensitivity is 5 Newtons. But by far HNS shines due to its unsurpassed thermal resistance. This is extremely propitious and yields tremendous credence to the technology. If such an explosive did not exist, it is difficult to identify a viable pathway to implementation. When Ostrovskii was studying the concept in the late 50s and early 1960s, HNS had not been discovered yet. It was only discovered by accident in 1964 when TNT was reacted with bleach (sodium hypochlorite). Since 1964, it has found extensive use in space applications due to insensitivity and thermal tolerance. Since geothermal and crystalline oil and gas drilling is the prime application for drilling technology, and the average geothermal gradient is only 35 C/km, only 150 degrees of cooling is needed. This small temperature difference can easily be provided by pumping cooled water at moderate flow rates. It should be remembered that the decomposition temperature of hexanitrostilbene only occurs at a depth of 8.5 km! This means any well drilled to this depth needs no excess slurry pumping for heat removal. If material compatibility issues can be dealt with and post-mixing sensitivity proves not to be a challenge, tetranitromethane and toluene is still attractive explosives primarily because of their immense power, having the highest detonation of any explosive other than octogen. But if the conclusion is that the paranoia over accidental capsule detonation is irrational, then there is a very strong impetus to use solid explosives and in fact, very little incentive to incur the hassle of liquids. Solid explosives enjoy almost every advantage conceivable, they boast a multi-century history of safe handling, reliable detonation, and synthesis. Of course, not all solid or plastic explosives are created equal. TNT might be cheap and ubiquitous but it melts at too a low temperature to be used. RDX has a higher melting point, but other than very narrow-diameter wells, the cost of the RDX is too high. Although since the Chapmen-Joule detonation pressure of RDX will be approximately 1.61x that of HNS, less explosive is needed. But the difference in brisance is not enough to offset the 8x higher price. The added hassle of having to quickly mix the two liquids impose additional engineering requirements on the capsule design. Solid explosives consist of a crystalline molecular profile, they are routinely pressed up to 200 MPa to maximize density which improves brisance. Solid explosives must be phlegmatized with a wax or oil-based phlegmatizer in order to prevent friction between crystals. Solid explosives are not necessarily more expensive than a binary liquid mixture, HNS is expected to cost no more than $2/kg to mass produce.
The appeal of geothermal.
Geothermal for some appears as the ultimate panacea, offering continuous heat production with no little to no interruption. Even if a man must spend three times the capital, of which ultimately is man hours and material, he is still yielding a product of immense potential value, since he can displace the more cumbersome temporally uncertain sources of motive power, namely hydrocarbon on and classic renewables. At any rate, man must develop a mastery of drilling, but is crucial that said solutions to the present woes of rock drilling not be moonshot technologies with little to no commercial practicality with the risks of achieving a permanent state of technological repose as with fusion or autonomous driving. Too many place excessive hope in false gods, and invest the entirety of their intellectual efforts in futile endeavors with little hope of succeeding.
It would be remiss for us to fail to mention the array of alternative drilling contrivances put forward by various inventors and commercial ventures. It is noteworthy to mention that of all the technologies modern civilization enjoys at its disposal, whether it be nuclear fission, wireless communication, or airplanes, man currently enjoys no clear-cut and effective mean to dig deep into the crust. It is therefore an utmost exigency to develop as many conceptual methodologies and to compare these said methodologies in their relative merit and demerit. While there exists a number of alternative drilling concepts, most are immediately eliminated upon brief technical examination, leaving only three worth considering. Excluding ours, presently, we have only one main competitor for the Hydrostatus Systems explosive drill: the combustion gas gun projectile delivery nozzle. The projectile launcher is immediately grasped by those with elementary engineering acumen. The microwave vaporization drill appears the most “novel” in that it entirely departs from any mechanical action, both fracturing and abrasion altogether are eliminated in favor of complete vaporization of the silicon oxides which predominate the crust. Nevertheless, such a design, in spite of its appeal, is riddled with technological issues, many of which are potentially permanently encumbering. Firstly, in order to use microwaves to melt rock, one must construct a heavy-duty heat-proof waveguide to transport this radio waves down to the bottom of the hole. The actual gyrotron regardless of how costly such a device would be, is not so much the issue. The weight and thermal/abrasion resistance of the waveguide will prove a considerable hurdle, since the waveguide must suspend at all times in the bore formation. Additionally, it has been argued that the waveguide must be kept very straight or else performance is degraded due to electromagnetic interference. But we have not yet mentioned the Achilles heel of this concept. We use the word concept because we cannot call it a technology, it is too conjectural to wear this badge. The explosive drill or the high-velocity projectile launcher is no doubt technology, both of which can enjoy commercial success in the near term, because they are extremely simple and easily modeled using rudimentary assumptions. Hydrostatus Systems believes that detonation boring system is superior, even though we actively thought of using metal projectiles to fracture the rock ourselves within minutes of pondering how to improve rock fracturing. The projectile launcher is a meritorious concept and should not be ridiculed. But the millimeter wavedrill really does defy the imagination as it borders on science fiction. In the end of this analysis, we will have concluded that it can really only wear that lable.
The Achilles heel of so-called “millimeter wave” boring method is its inability to use water as a working fluid. Regardless of whether there is a drill bit touching the rock, there must be a satisfactory fluid to remove the rock media and more importantly, provide an incompressible media to cancel any tendency for the rock formation to cave in on itself. Any newly formed void in the high-pressure rock will have a tendency to move in the direction of least resistance, and this will entail the rock caving in into the newly formed borehole. If hydraulic media were not used, such as oil-based drilling fluid, the rock would collapse within seconds. Since oil or water will absorb the bulk of the energy from the microwaves as well as severely attenuate them, the water will be rapidly heated and all if not most of the energy will be consumed by this heating of the fluid. Therefore, those who proposed using these radiowaves for drilling acknowledge that they are limited to using air. But air or any gas for that matter is inherently very problematic, namely because it is almost infinitely compressible. This means if the air is not at the same pressure as the rock, there will be a tendency for the rock to bulge inward towards the borehole. Pre-pressurizing the air is an option, but would place massive mechanical hassle and cost on the ancillary driving equipment. Since air has a very low density, it must be compressed to thousands of bars for it to attain the same density of rock to cancel any hydrostatic imbalance. This is technically impractical and means the drilling will have to take place in successive iterations between casing insertion, where small areas of rock are drilled and casing rapidly inserted to prevent a cave-in. The cost of the magnetron, the enormous weight and concomitant cost of the waveguide, and the inability to use water should serve to severely stunt this technology. Notably, the founders claim that so-called “fusion” technologies are being drawn upon to form merely a new application for scaled-up magnetrons. These so-called fusion technologies are just very powerful magnetrons, nothing more, that is merely an element of hype and self-aggrandizement that every innovator partakes in, but which is especially egregious in modern start-up culture. The source of the melting energy is high-frequency radiation that is generated using electricity in some form of a thyristor. Lastly, even if milli-meter wave drilling were realized, it would be of limited use for geothermal, since we have already stressed that one can have the best drilling system in the world, but if a solution to generate a huge volume of fissures in the low-porosity rock does not exist, the hole would be but a historical curiosity. Out of all the options to induce fissures, only extreme and rapid pressure build-up can work. Pumping high pressure fluid is of limited practicality since the hydrostatic pressure is already so great, one would require pressures several times greater than the 1500 bar pressures found at the bottom of a 15 km well. The only solution that appears viable is to simply bore a hole larger enough in diameter to insert a heavy explosive charge designed to detonate at the bottom of the well. The explosive charge would be shaped with sharp frontal area in order to permit it to slide to the bottom of the well passing any obstruction using its own mass. A large lead or steel block can be used to increase its weight.
Quaise Energy appears to be a another Panglossian dream like HyperLoop, Theranos, and “silicon nano-wire” anode batteries. Quaise naturally do not mention a single time the issue of waveguide attenuation from dielectric losses and current losses due to slight bends. Conventional rectangular waves achieve losses of as much as 4 decibels per meter in the GHz range. Such losses would make it totally impossible to transmit any meaningful amount of power to the bit not to mention melting the waveguide from the massive amount of current induced by the waves. The only possible way to transmit useful amounts of power to the bottom of the 15000 meter well is to use oversized cylindrical waveguides in the TE11 mode. Its impossible to calculate the exact loss in the waveguide because even just slight sub-millimeter bends will cause substantial power losses. A 1 mm bend every 2 meters will result in a loss of 0.076 dB per 25 meters, or a total loss of 99.99937% of the power! It is extremely difficult to imagine would slight bends will not arise from the thermal expansion, contraction, and occasional knocking of the waveguide within the wellbore. The turbulence caused by compressed gas flowing along the waveguide will invariably cause it to sway within the drill cavity. It is also impossible to drill perfectly straight, since slight deviations will occur to differential vaporization of rock due to differences in density, porosity, water content, mineral type etc. If water were to gush into the wellbore slamming the waveguide towards the borewell suddenly bending it, the losses would rapidly escalate causing runaway heating of the material. The notion that one can realistically keep a 15 kilometer long shaft perfectly plumb in a hot, high pressure bore is ludicrous. Furthermore, if even a small amount of water were to enter the wellbore, it would be immediately vaporized, this water vapor would absorb nearly all the microwave energy and cease drilling operations immediately. Considering water exists in almost the entire crust, it is almost impossible to imagine one drilling a truly “anhydrous well”. This is not to mention the aggregation and buildup of molten rock fragments on the drilling tube, the overheating of the nozzle and waveguide, and the lack of positive formation pressure.
The second competitor worth paying attention to is the so-called “hypervelocity” projectile launcher marketed by a company called “Hypersciences”. Just as with explosive drilling, this idea is by no means new.
High-Velocity Impactors for Excavating Hard Rock Jacob N. Frank, Technical Project Officer Twin Cities Mining Research Center, Twin Cities, Minn. Bureau of Mines Research, United States. Bureau of Mines · 1971.
“A powerful new method of hard rock excavation has been tested and successfully demonstrated. The method, known by the acronym REAM ( Rapid Excavation and Mining), employs high-velocity, smooth-bore cannons to efficiently deliver energy to the rock. Solid projectiles made from inexpensive material, such as concrete, and weighing from 8 to 12 pounds, are launched by conventional high-speed cannons and impact the rock at 5,000 feet per second. A 13-foot -diameter tunnel was driven to a depth of 55 feet by the REAM method through granodiorite having an unconfined compressive strength of 25,000 psi and an average joint spacing of 6 feet. The first 26 feet of tunnel was lined, drilled, and driven in the summer of 1972 by a 105- millimeter smooth- bore cannon firing 10- pound concrete projectiles with an average yield of rock excavated per shot of 1.5 tons, or about 300 pounds of rock per pound of impacting projectile. In 1973 a 90- millimeter gun system was used to continue the tunnel to its final depth of 55 feet, 35 feet beyond the line-drilled portal. The average projectile weight was 8.5 pounds, and the average yield per shot was 2,500 pounds. In general, the overbreak was 6 inches or less, and there were no problems in controlling the tunnel contour. A silencer, developed for the cannon, was able to de-energize and control the muzzle blast, and in extensive underground tests, peak pressures on the order of 1 psi ( 170 dB) were measured. No ground support problems were encountered. Dust was controlled by a simple water spray and blower ventilation system, and no hazard from flying rock was observed on the underground equipment. In other operations the 90- millimeter cannon was used to drill approximately 25 feet of 16- inch- diameter holes with advance rates up to 12 inches per shot. The cannon was also used to carve out a surface cut in moderately weathered rock with an average yield of 5 tons per shot, compared with 1.25 tons per shot observed in tunneling operations. Experiments in breaking free-standing boulders and scaling down long, hazardous rocks were conducted. Boulders weighing up to 40 tons were broken to manageable size with one shot. This work demonstrated the rock-breaking effectiveness of high-velocity projectile impact, the control of tunnel contour while minimizing damage and overbreak, and the development of a silencer able to de-energize and control muzzle blast. It was further demonstrated that this is a viable method for drilling holes, carving out a surface cut, and breaking down large boulders”
The initiative was taken up again in a report published in the year 2000, but nothing has come of it. Maurer does not believe the technology can be used for small wells, he is quoted as saying “The REAM technique appears to be limited to large diameter tunneling or shallow drill holes. Because of space constraints, the REAM system could not be used in deep wells (geothermal and petroleum). High projectible costs and safety considerations would further limit application of this technique. Because of these limitations, R&D on the REAM system should not be given high priority for geothermal or petroleum applications”
The founder of Explosive Drilling Systems Inc had conceived of the same concept (firing steel projectiles at the target) but later moved on to explosives believing the concept was more elegant and to a greater extent: proven. Firing heavy projectiles into rock might work decently, but it feels “primitive” and “crude” compared to achieving a more uniform and highly fragmented rock using a tiny mass of explosive instead. The issue is that concrete has little mass, so in order to impart a substantial dose of energy into the rock, the velocity must be extremely high. Since the drilling fluid is so dense, much of the energy is lost overcoming the resistance of the fluid. The term “hypervelocity” is a tad dishonest since the velocity is not much higher than a typical high-performance firearm, which can achieve speeds of close to 500 m/s. This stands in sharp contrast to the over 900 m/s that can be achieved using the highest-performance explosives such as HMX. The peak detonation pressure of RDX is 34 kbar or 493128 psi. In contrast, firing a concrete projectile 100mm in diameter 280mm long weighing 3.6 produces a muzzle energy of 4300 kgf if accelerated to 1200 m/s, the upper limit of diesel-oxygen deflagration. Since the area of this projectile is 75 cm2, the static pressure of the projectile as it hits the rock is only 56 bar or 800 psi! Of course, the peak pressure at the tip of the conical projectile is much higher, but lasts only a very short time before the projectile is crushed and the wider sections are facing the rock. This means an explosive high-order detonation produces 630 times the static pressure on the rock. This alone should serve as a very strong endorsement of explosive drilling over the lowly “down-bore cannon”. The immense static pressure is what so effortlessly shatters the rock into relatively small fragments, whereas the low-pressure projectile merely lodges itself in the rock and forms cracks around the channel it has dug. Hydrocarbon fuels cannot be made to detonate outside of the most perfect conditions because they do not feature an oxidizer built-in within their own molecular structure, so they must latch onto a nearby oxidizer mixed in the formula. This process takes far more time than if the oxidizer and fuel are placed within extremely close distances as in an explosive. Jet fuel mil-spec grade JP-10 mixed with diethyl ether reaches a deflagration velocity of 97 m/s. This slow-speed burning is inherently inefficient for accelerating a projectile, so a very long barrel must be employed in order to convert the gas expansion motion to velocity.
The maximum velocity achievable by a so-called combustion gas gun, also called combustion light gas guns, is around 1000-1500 m/s, or a relatively small fraction of a high explosive. Most combustion light gas guns studied for military purposes have achieved about 3000 feet per second (900 m/s) using hydrogen gas, it is therefore highly unlikely that something using kerosene will equal that. The proponents of the hypervelocity projectile driller have proposed to use steel-encapsulated concrete projectiles to fracture the rock in front of an existing rotary drill, which is inherently problematic since the rotary drill will still be limited by the surrounding rock temperature and must perform the function of comminuting the large fragments generating by the projectile into small fragments that can be removed by the drilling fluid. A large projectile fired at high velocity into rock will not necessarily shatter the rock into small particles ready to be removed by the drilling fluid, rather it will generate a large hole with cracks and fissures around it. This weakened rock must then be ground down into small cuttings with a conventional drill bit or some other device. This technology can thus be viewed as a hybrid option, as it is not truly a contactless drilling system let alone a “bitless” drill as Ostrosvskii had hoped one day could be built. The updated and improved explosive drill is an entirely contactless system that does not place any mechanical device against the rock to grind or fragment it. The “down-bore cannon” idea upon the first examination fails the major test, being that it does not entirely dispense with the rotary drill. The projectiles alone do not shatter the rock completely the way explosives due, and hence leave a large body of rock that has to be excavated. They propose this can be satisfactorily done with the rotary drill, which has the preponderance of workload relieved due to the already greatly weakened rock. While this is not proven, it is a logical assumption. One thing they do not mention is the extent to which bit wear is actually reduced with this method. While the rock is no doubt weakened, it still is nonetheless the same rock with the same hardness as before, thus it will still wear the bit, albeit less. Unless drilling is done after a certain time after the projectile has fractured some rock, the rock will still be hot, causing degradation in the bit. From a technical perspective, the projectile launcher is no more complex than the detonation drill, in fact, because of the added performance of the explosive drill, it is arguably more complex and sophisticated. The down-bore cannon requires compressed oxygen and some form of hydrocarbon to be pumped into the system and ignited somehow. It then requires a projectile feeding tube just like our capsule delivery hose. It then requires a long barrel to fire the projectiles from. This barrel must be highly straight and smooth barrel for the projectile to accelerate, even small leaks greatly diminish the efficacy at which the projectile is allowed to accelerate. The amount of energy that the projectile must overcome to achieve the same velocity as an in-air is substantially greater due to the density and resistance of the drilling fluid. Additionally, depending on the cycle, near the constant combustion of diesel fuel and oxygen will generate a substantial amount of heat that must be removed in order to maintain the integrity of the barrel material, which will likely have to be constructed out of nickel alloys. The projectiles themselves must be manufactured to be highly uniform, since slight deviations will cause them to jam into in the barrel. The differential thermal expansion of the barrel liner and the concrete capsule housing may cause lodging of the barrel resulting in a bursting event.
A few final technical details are the oxygen diesel injection system and the ignitor, as well as a mechanical valve to permit the projectiles to enter the chamber and be sealed off before ignition. These simple mechanical components are no worse than in an explosive capsule drill. While the technology is simple and somewhat elegant, it is inherently less powerful than a high explosive drill for reasons of fundamental physics and chemistry, something technology is forbidden from altering as these laws are immutable. Lastly, there is virtually nothing new or novel about the concept, there is nothing that can be genuinely patented fundamental to the operation of the system. While explosive drilling is not new either, and we do not claim such, there is a fundamental advance that can be made that is patentable and novel. This feature is discussed in further detail.
Aside from these facts, we can also lay criticism upon the design from a physics perspective. What the designers are attempting to do is fight an uphill battle against the physics of detonation. Detonation cannot ever practically be achieved using hydrocarbons, so velocities will always be limited since the gases expand only so fast. In a true detonation machine, one elegantly harnesses the intrinsically high velocity of the gas’s shockwave to shatter everything in its path. One is therefore in harmony with physics, as opposed to being discordant. One should always strive to build a technology where the fundamental principles or attributes of the main facilitating “agents”, be they water, air, metal, molecular compounds, etc.
Very little is known about the behavior of explosives at great pressures, therefore, it is very difficult for the designer to be confident regarding the detonation ease of high explosives at greater depths compared to normal pressures where the preponderance of explosive experience is drawn from. Limited experience using hexogen at 1200 atm suggest is more than feasible to detonate solid explosives at the pressures that will be encountered using relatively light drilling fluids. The two main variables that that critically affect the performance of the drilling unit are the brisance (the destructive power) and the detonation sensitivity of the explosive. Presently, the only application that demands explosives perform under high-pressure environments is found in naval mines used for military purposes. The classified nature of defense technology make this data difficult to access. Moreover, the hydrostatic pressures encountered by the moderate depths at which naval mines must be used do not reflect on ultra-deep wells. Naval mines use conventional plastic solid explosives in a hydrostatic environment, but the depths in which they operated usually do not exceed a thousand meters, since the shockwaves attenuate rapidly and little damage will occur to vessels above. But in spite of this experience with naval mine technology, little data has been published on their explosive characteristic in these unusual and rather extreme conditions. Thankfully, data does exist which provides almost exactly what the prospective explosive driller desires. The only data set available is from a Russian study on deep-borehole explosives intended for stimulating oil and gas wells. The paper finds that while there was only a marginal decay in brisance, considerable desensitization occurred, but the exact cause is not certain, although a hypothesis has been proposed. The Russian paper “Thermostable Explosives and their effects in deep boreholes” published in 1969 comes to the conclusion that the substantial attenuation of detonation sensitivity or so-called phlegmatization occurs due to the elimination of pore volume.
Cooling
Since a great surplus of water can be pumped into the well and nozzle to carry away more heat than is emitted by the rock wall, thermal damage to the metallic components, hose, or explosive is not the primary concern. It’s easy for the designer to calculate heat flux and temperature rise, but very difficult for him to predict exactly how the explosive will detonate and how much and powerful a detonator he must employ. While it is certain there will be a decay in brisance or explosive removal productivity with depth, it is uncertain how rock type will affect this relationship and the extent of its severity or lack thereof. Cooling is unlikely to pose a technical bottleneck, since if enough pressure can be provided, flow rates can greatly exceed the heat flux of the well even at 15 km in a 35+ C/km gradient. A 6.25 km average wellbore depth with a thermal diffusivity of 0.65 mm/s will produce a thermal flux of 25000 kWh. Only a few hundred cubic meters of water is needed to remove this heat.
Since conventional drilling requires extensive setup time, hundreds of removable shafts, and a giant rig, it is impractical for armies to quickly drill holes and drop nuclear landmines during active conflict. The fact that the military even bothered studying capsulized explosive drilling suggests it’s more than technologically feasible, just because it has enjoyed no commercial success does not automatically indict its technical merit. Soviet claims of drilling speeds in excess of 40 feet per hour can be found in the archives of Google books, which is at least four times higher than mechanical drilling. From the reports at the time, they did not indicate any major technical impediments other than the cost of the explosive, although very little data is available. Since the aforementioned estimate of productivity is about 50 kg/m3, even if we triple this amount of explosive is needed in order to comminute the rock into sub 1 mm particles for successful spoil removal, the argument that explosive drilling is limited by the high cost of explosive is wrong. The most plausible reason such an attractive drilling solution has not been more actively pursued outside of theoretical studies is the fact that the oil and gas industry rarely drills in hard crystalline bedrock. According to the conventional “fossil” theory on the origin of hydrocarbons, geologists only explore for oil and methane in regions of high sedimentary rock deposits, which are typically very soft and easily drilled. In fact, explosives perform very poorly in soft, compressible, and plastic rocks such as clay, so as long as most oil and gas are drilled in this type of rock, there is virtually no impetus to develop this technology. Explosive drilling only works in very hard and firm rocks that are easily shattered, soft and malleable sedimentary rocks cannot be practically drilled with explosives since the bulk of the explosive power goes to churning the porous and elastic sediment. This along with a few technical challenges explained below explains why this technology has never been actively pursued. Secondly, we must not deny that conventional tri-cone rotary drill performance is stellar at shallower depths, where most liquid hydrocarbons are found, at these shallow depths the cemented polycrystalline diamond cutting tips last sufficiently long. Since geothermal energy is effectively non-existent as an industry outside of corporate brochures, there has been little demand for relatively deep, high-productivity, hard rock drilling technology.
Returning to the technical issues with explosive drilling, if there were for any reason a sudden shockwave that fractured the capsule supply hose, one of the explosive capsules could detonate starting off a chain reaction. This would detonate all the explosives lined up in the hose the entire depth of the hole and generate a shockwave that would send material hundreds of meters in the air. For a 250mm diameter hole, the total capsule mass suspending in the hose might tally up to 12,000 kg if the capsules are spaced 2 meters apart and weight nearly 2 kg each which corresponds to a well diameter of 550 mm. Although it is expected that a higher frequency of smaller capsules will produce smaller fragment size. While no one would be allowed to stand within say a few meters from the drilling zone, one could conceivably ignore the risk since the vast majority of the explosive energy would be absorbed by the rock. The shockwave would be narrowed and pierce upward, it would not suddenly turn 90 degrees and spread laterally. Someone standing a few meters away from the borehole opening could definitely be injured, but shockwaves dissipate with the inverse square of distance, so it’s relatively easy to keep workers safe by employing a system that blunts the shockwave by absorbing the energy via a compressible medium such as air. Considering nuclear weapons have been detonated underground dozens of times and material was not shot up in the air after capping, it’s more than conceivable a sufficiently strong blowout prevention system could be fashioned into place, but such a device would undoubtedly be very heavy. Since we are already proposing to detonate large explosive charges at the bottom of the well, we will have to develop these types of capping systems regardless, so even if there is an accidental detonation, the worst that can happen is the system has to be replaced.
Any drilling technology regardless of the method to detach the rock is handicapped by the persistent issue of slurry erosion of the drill shaft. As slurry containing small abrasive rock fragments are pulled up by the slurry pump, they pass over the steel shaft and cause it to abrade. Additional erosion of the steel shaft can arise due to hydro abrasion and cavitation if air pockets are present.
But unlike capsulized explosive drilling where there is no physical contact between the components and the rock, with rotary drilling, the method inherently on the abrasion or grinding, and to a lesser extent shearing of the rock beneath the harder cutting piece. This is the fundamental method of operation for a rotary, a method which has not shown the willingness to be changed for over a century, and arguably, for millennia if one includes crude methods to drill holes into stone using hand drills. But since there is a firm contact and pressure between the tool-piece and the rock face, there is the opportunity for thermal transfer in addition to the heat yielded from the mechanical work of rotation. The mechanical equivalence of heat is readily felt when one uses a dry shaver, the rotary blade cover becomes very hot only after 30 seconds of use. Since a rock drilling bit requires a large amount of force pressing on it to be effective, the amount of friction is huge and hence the amount of heat generated. The result of this phenomenon: bit degradation due to a loss of binder strength in the carbide or diamond particle composite, forms the principal limitation of rotary drilling. The corollary of this is the need to pull the entire drill shaft assembly to replace the individual cutting pieces. If the drill is at a depth of 7.5 km, corresponding to the halfway point for a 12.5 km well, since the retracting speed is limited by the huge mass, it may take four times as long to remove and reinsert the shaft than the bit lasts in hours.
In the Explosive Drilling Systems Inc explosive drill concept, there is a sizeable gap between the hot rock wall and the drill shaft, protecting it from high temperatures. In a conventional rotary drill, it is the actual drilling head, not the shaft that is the concern. The shaft is always by definition narrower than the hole since it must pass freely through, but the drill bits directly touch the hot rock. The amount of torque uses up much of the material’s tensile strength, leaving little left over for bearings its own gravimetric weight. At a speed of 200 rpm, the torque on the shaft is between 2000 and 4000 Newton meters. The Russians used an aluminum alloy called D16T with a yield strength of 330 MPa for drill pipes, but this limits depths to only 7.5 km. Maraging steel could theoretically be used, but the cost would be astronomical and issues would be encountered with stress corrosion cracking. Titanium is an attractive option. Either way, regardless of alloy selection, rotary drilling is simply too slow, expensive, and ineffectual in the hard rock formations that are needed for high-output geothermal wells. The structural metallurgical limitations, along with biding and erosion, effectively forbid conventional shaft-driven drills for being used at the depths targeted. This leaves turbodrills or electro-drills as the only viable option. Turbodrills were the candidate of choice for the Kola deep drilling project in Russia. Conventional shaft drills are unable to rotate at the speeds needed to exploit the high cutting efficacy of diamond bits. Turbodrills can rotate at much higher speeds thanks to the use of a small-diameter turbine powered by the drilling fluid. This turbine can even feed into gear to decrease the RPM to correspond to suitable drilling speeds. Russia has numerous patents on geared turbodrills and continues to dominate the technology to this day. While turbodrills are highly attractive because they eliminate the issue of shaft bindings, they still rely on rapidly degradable cutting pieces which handicaps drilling productivity and raises cost by requiring frequent shaft removal. During the Kola deep-well drilling experience, the carbide bits would last 4 hours but required 18 hours to be expended each time the shaft has to be pulled out and reinserted in deep hole. This lowers the drilling speed by 4.5 times over the baseline drilling speed of the cutting tool. The weight of the rig necessary to suspend and lift the drill shaft was 15,000 tons. Explosive drilling is definitely tedious, complicated, and more failure prone than the tried and true rotary drilling technology, so it is expected the bulk of methane and petroleum drilling will rely on rotary drills for the foreseeable future. But the technology is simply unsurpassed in its theoretical ability to eliminate thermal degradation of cutting pieces, increase productivity, and possess a hardness invariant penetration profile. Impact of hydrostatic pressure on explosive properties. Explosives are rarely used at pressures significantly above atmospheric, hence there exists little data on the behavior of explosives, especially liquid compounds, at high or extremely high pressures. The density of the water slurry is around 960 kg/m3 at the 150°C outlet temperature, this corresponds to a hydrostatic pressure of 1400 bar at the absolute bottom of the well-bore. The average pressure across the well shaft is only 60 MPa, around the pressure of a fuel cell hydrogen tank. While there is very little data available on the behavior of explosives at high pressure, data from Soviet research into deep-borehole explosive detonation for oil and gas extraction is available. In a report titled “Thermostable Explosives and their Effects in Deep Boreholes” by Fillipp Abramovich Baum found that a liquid explosive mixture of tetranitromethane with various combustible hydrocarbons, toluene, benzene, etc experienced a substantial decrease in its sensitivity, with the critical diameter (minimum diameter for steady state detonation) increasing from 0.03-0.1 mm to 4 mm at a pressure of 400 bar. The authors found no decrease in brisance (depth of penetration) for metal, and a mild decrease in rock. This suggests that drilling at greater depths will not negatively impact the productivity of the explosive, which is extremely good news for the success probability of the technology. If on the other hand, the explosive’s efficacy fell by 5 fold at greater depths, this would strongly dissuade people from pursuing this technology. But the decrease in sensitivity does pose a moderate technical challenge that must be overcome in order for smooth and consistent capsule detonation to be guaranteed. The desensitization of the explosive with pressure at first glance appears as a positive feature, since it would enhance safety and quell fears of accidental detonation, but nonetheless still poses a small technical nuisance. In order to obviate this desensitization, a miniature-pressure vessel containing a portion of the explosive can maintain this quantity of explosive at ordinary or moderate pressures and can serve as the detonator, but still act as a binary explosive ensuring no accidental detonation. This small pressure vessel would still contain a diaphragm and feature a mixing element. This pressure vessel containing the binary explosive mixture would be placed either inside the primary capsule or behind it to provide maximum detonation efficiency and rapidity. Impact detonation, what Ostrovskii relied on, may not be ideal for greater depths and at higher capsule ejection rates. A possible alternative method, although not an option we are planning to use, is employing an electrically timed and activated plunger that rapidly compresses the detonator capsule placed just behind the primary charge acting as a mechanical detonator. Netranitromethane and toluene, once mixed, is actually extremely sensitive explosives and very easy to detonate. Detonation with a mechanical system ensures reliability and low risk of an accidental detonation as is the case with primary explosive detonators such as DDNP, mercury fulminate, lead styphnate, etc. The actuator could use a strong spring, magnetic solenoid, hydraulic cylinder, piezoelectric crystal, and a small combustion chamber, among other options, to provide the necessary firing energy to detonate using impact force. The initiation of this mechanical plunger detonator can be facilitated by a magnetic field that acts as a latent timer in the ejection barrel. As the capsule passes through a magnetic field created by an electric field around the ejection barrel, it causes the mechanism to activate with a built latent period corresponding to the time of travel. All these little features should not demoralize the engineer and convince him it’s too challenging, but ironically they create novelty that would quell concerns about prior art for prospective investors who desire to secure intellectual property on the technology. Another such design exigency is insuring the capsule are not accidentally detonated by hitting a rock fragment that are being lifted by the slurry, this is unlikely to occur since the explosive capsule consists of a strong metal, composite or ceramic casing. Minor technical problems are not a deal breaker unless they pose insurmountable problems, such as something requiring an alloy that melts at the operation operating temperature anticipated!
Hydrostatus Systems has not just studied wind energy and how it can be improved, we have also investigated the possibilities of improving geothermal energy technology with an improved drilling technology using consecutively ejected binary liquid explosive capsules. Since rock is so hard to drill due to its high hardness, it makes far more sense to use the immense shattering force of high explosives, those with detonation velocities in excess of 7000 meters per second, to fragment the rock into small sub-5mm shards which can be sucked back to the surface. Each capsule is insulated to prevent the liquid explosive from reaching the temperature of the surrounding liquid media.
There is no major technical impediment facing this technology but “perceived safety” and “FUD”, fear, uncertainty, and doubt. The only thing that could be described as close to a “technical problem” was the reduced efficiency of spoil removal due to a combination of larger rock fragment size than produced during rotary drilling and a gap between the nozzle and the rock bed. Hydrostatus Systems has attempted to obviate to a great extent these two challenges by employing a rapidly retractable nozzle that sprays drilling fluid right above the fragmented rock bed just as a rotary drill does.
One of the reasons that the only alternative drilling technology being developed in the 21st century is the down-bore cannon (excluding the microwave system due to technical infeasibility) is because of the perceived danger of explosives that discourages the pursuit of its immense power.
Anything that ends with “explosive” freaks people out, especially the more technically simple-minded. Another concern might be from environmentalists that oppose to injection of hundreds of tons of highly toxic tetranitromethane into the earth, but it should be remembered that our concept does not make use of groundwater for energy extraction. While explosives perform less well at greater depths due to increased hydrostatic pressure, more of the energy of the explosive charge is used to overcome the surrounding pressure, but the difference is quite small, since the peak pressure wave of a high explosive such as RDX can approach 34 gigapascals, a hundredfold greater than the rock’s hydrostatic pressure at 12 km. The most important fact to highlight is the tremendous increase in explosive productivity when an explosion occurs below a body of water. A single 40-gram charge produces 2.2 kg of rock fragment when detonated under high-pressure water, while it produces only 0.22 kg if detonated in a standard gas atmosphere. This is highly intuitive since air is highly compressible and hence the preponderance of the explosive’s energy is absorbed by air compression. Below is a technical schematic and rendering of Hydrostatus Systems‘ explosive boring machine. The diameter of the shaft is quite a bit larger than the actual shaft that would be drilled for illustrative purposes.
The theoretical raw material-only production cost of two standard high explosives is provided below. Note that the nitrogen dioxide and ammonia costs are lower than normally advertised due to the use of our high altitude ultra low LCOE wind turbine which we would use to generate hydrogen to produce fixed nitrogen. Since RDX uses formaldehyde and ammonia to produce hexamine, the production of RDX is quite attractive and convenient since we can easily couple the system into the modular nh3 synthesizer drawing from the high-altitude turbine. The production of RDX can be done for less than $1/kg for hard raw materials only.
Any technology that relies on consumables for its operation must be shown to be compatible with current production capacities. In our case, we must consume a substantial volume of explosive material, drilling fluid, and electricity. The explosive, due to producing a somewhat larger mean fragment size, requires a higher viscosity drilling fluid to reduce its free-fall velocity. Compared to a rotary drill, up to twice the pumping power will be required. Many people mistakenly believe that alternative or new technologies must invariably be “cheaper”, but this is a flawed notion. Vacuum tubes are clearly cheaper to engineer and manufacture than integrated circuits and silicon transistors. Rather, it is the expected performance of the superior silicon transistor that justifies its higher cost. Mechanical drilling is an archaic technology that has remained virtually unchanged for centuries, and while there exist countless alternatives, all of them share one thing in common, they are expected to be a higher-performance system but with added complexity and cost. Explosive drilling is no different.
Total explosive consumption to drill enough holes to meet all U.S energy demand. If we assume a 500mm dia well can produce 30 MWe of power with aggressive fissure stimulation, and 600 tons of explosive (5x over-use for rock comminution) are used to drill the well and 100 tons are used to induce fissuring, then we assume per MW explosive use is 23 tons. Since the U.S electricity grid is 456,000 MW, we will need 10.5 million tons of RDX. Interestingly, the U.S produced 15 million lbs of RDX monthly or 81,000 tons in the 1970s. This means to produce the entire U.S electricity grid over a period of say two decades, RDX production capacity would not have to increase by very much.
It should be remembered that these estimates are purely for scientific interest, they have no practical bearing whatsoever since extreme scenarios by definition occur in reality. It is extremely unlikely a single energy source will ever power 100% of a country’s energy budget, except for cases where it is as simple as building a demand, such as in Norway.
The realities of “hot dry geothermal”.
The idea of pumping water into a rock body to induce fissuring is not new, it was developed by multiple individuals independently in the 1970s motivated by the energy crisis. Bob Potter issued the first patent on the principle. The idea is extremely simple, use a slight excess of pressure above the formation pressure to slowly enlarge existing micro-fissures. The crust is thought to be rich in tiny fissures or faultlines that exist perpendicular to the hydrostatic gradient. Since the force of gravity manifests in the vertical plane, displacing the rock tangent to the surface plane is much easier. While the permeability of the crust is estimated to be in the nano-darcy range, existing microcracks are liable to be expanded slowly over time with enough pressure, although there is considerable variability in the presence of pre-existing microcracks. Many hot dry geothermal projects were attempted in the 70s and 80s. Most notable is the Fenton hill well in New Mexico. While there were several successful runs where fissures were formed after substantial pumping effort, many wells refuse to “open” and power output remained low. An article by Richard A Kerr in SCIENCE entitled “Hot Dry Rock: Problems, Promise” chronicles some interesting findings without placing a positive spin on it. Kerr is quoted as saying “After a decade of hard lessons and limited success, tapping the enormous heat reserves in rock too dry to yield steam or hot water on its own faces more challenges”. He goes on to say: “No one has figured out why some fractures open and others do not”. “Hot dry rock has proved to be a recalcitrant, even devious foe, demanding greater respect and subtlety of design than pioneers in the field imagined”. Kerr describes how some of the wells drilled and hydraulically stimulated that performed well were because of natural openings and not due to the hydraulic fracturing itself. A major scientific error made by geothermal proponents is comparing existing hydraulic fracturing strategies used in highly brittle, soft sedimentary shale rock. Many geothermal proponents have made totally unfounded claims that somehow they can apply shale fracturing technology to extremely hard, strong, highly compressed igneous and metamorphic rock, which is highly erroneous. There is little reason to believe the mild pressures used to stimulate fractures in shale will ever produce even close to the results in deep crystalline rocks. While our proposed strategy to use the immense detonation pressure of explosives to generate thousands of bar of pressure of the background hydrostatic pressure may not even be sufficient, it is at least an attempt. One thing can be said, regardless of how successful the efforts at developing new drilling technologies are, the entire effort is ultimately determined by how much and if we can fissure deep rock strata. If it should be too difficult to reliably induce fissuring to achieve the necessary surface area and flow path, geothermal energy will remain in obscurity. This will mean any alternative drilling technology will be seen as an asset to aid in deep gas exploration in hard rock strata. It is quite astounding to see so many geothermal startups makes claims with utter confidence and certitude that once we have this magic bullet that is some new drill apparatus, all we have to do is effortlessly pump water into the hole and “voilà”, a huge volume of pore space will suddenly be generated. Considering the only successful and proven site was Fenton which was only 3 km where hydrostatic pressure is much less than at 12 km, one cannot extrapolate these results.
Another important factor is establishing the energetic inputs of pressuring the hydraulic fluid. If we assume we need a few hundred bar of additional pressure of 500 bar, and to generate a seismic volume of 80 million cubic meters we must inject 25,000 cubic meters, a total of 300,000 kWh is required, or about 12.2 kWh/m3 at a pressure of 500 bar. These numbers seem to endorse the overall energetic efficiency of hydraulic fracturing. Even if an order of magnitude more water was required, the power still only amount to 3 million kWh, which is a reasonable number.
It’s interesting to note that currently, there’s yet a consensus on the exact mechanism at play during hydraulic fracturing. It’s assumed the planar fractures propagating along the rock layers are slowly enlarged, but evidence suggests crack also propagate parallel to the hydrostatic gradient. Either way, until more certitude, exists on the
Nitrogen oxide is shown instead of “nitric acid” since nitric acid has a higher molar mass than NO2 due to the addition of water which adds oxygen and hydrogen molecules to the NO2. NO2 has a molar mass of 46 grams, while HNO3 has a molar mass of 63 grams, so one kg of NO2 yields 1.37 kg of HNO3. The cost of ammonia is assumed to be $350/t (corresponding to a wind-powered plant with power costs of $0.03/kWh), since 300 kg of ammonia is needed to produce 1 ton of NO2, the cost per ton of NO2 is only $100. The indigenous in-house production of all the raw materials is essential for cost control and the production of cheap high explosives, which forms the enabling strategy for high-intensity explosive drilling. Being fascinated by explosives does not make on a terrorist, rather it makes one a keen observer of the fact that conventional high explosives are a sui generis technology. No other technology but electromagnetic coils in particle accelerators can move matter at the speeds at which conventional high explosives routinely detonate. It is precisely because explosives possess these unparalleled and sui generis properties that make them a robust candidate for making the first genuine breakthrough in drilling technology since the invention of the turbodrill in the 1920s. Outside of rock blasting, explosives find few applications in civilian engineering outside of their niche application in ballistic parachutes and airbags. It just so happens there exists a potentially enormous application for explosives to be harnessed for peaceful purposes to generate large amounts of energy. At the present time, the chief usage of high explosives such as cyclonite is for military purposes, artillery shells, missiles, and rocket warheads. There exists no civilian sector whose core technology rests on the power of explosives to perform essential functions outside of quarrying and blasting, and these sectors mainly use low detonation velocity explosives such as ammonium nitrate fuel oil or dynamite (nitroglycerine and diatomaceous earth). One such application as we have discussed already is drilling deep holes in the earth faster and more efficaciously than with rotary bits. But perhaps a more important and unknown application is their ability to induce the fissuring of rock at great depths. Even if a conventional rotary bit can suffice albeit with reduced performed, the whole can no doubt still be drilled. But one this borehole has been drilled, from a geothermal perspective, it’s utterly useless. For conventional hydraulic fracturing to work, water must be pressurized above the surrounding rock pressure, otherwise, the water does not possess the necessary force to break the rock. Rock cannot be broken by water and a lower pressure than itself! Horizontal “fracking” for oil and methane occurs at shallow depths compared to what is needed for geothermal, making it unsuitable and ineffective for geothermal fracturing. This means there presently exists no technology for generating large fissure volumes for water to capture the necessary heat from the rock. It’s irrelevant how good drilling technology becomes, even if we had a brilliant drilling technology invented tomorrow, there exists no method to flow water into non-porous rock formations. This effectively restricts geothermal technology to geologies where highly porous rock already exists and or aquifers. This is where we are currently in the so-called “geothermal industry”, which is a misnomer because there is no geothermal industry. Hydrostatus Systems has proposed the only physically possible fissure formation mechanism available. We have called this technology “Downbore fissure formation using high explosive charges”. Conventional geothermal technology is not just limited by poor drilling technology, it is limited by the inability to reach a large rock mass to capture sufficient energy. Hydrostatus Systems has devised a scheme to use the explosive drill to bore large diameter shafts up to 15 kilometers deep and place insulated binary liquid explosive charges consisting of tetranitromethane and toluene to induce massive fissure growth to achieve power outputs in excess of 50 MW per wellhead. The charge would be filled in situ and quickly detonated minimizing heat transfer into the explosive chamber. The size of the explosive chamber is limited by the diameter of the well, this is where explosive drilling comes in, because it can facilitate much wider hole drilling than rotary drilling, a much more powerful shaped charge can be placed in the wellbore. The weight of the charge could reach 1000 kg, which is a substantial size bomb roughly the size of the typical truck bomb, which can level entire concrete buildings. The larger diameter of the bore allows for reduced heat transfer, allowing the explosive more residence time needed for capping the well. If the casing of the hole is relatively smooth and lubricated, the explosive charge can be descended quite rapidly. The issue is then insuring that the well is properly capped. It may be required to insert along the entire depths series of solid metal or hollow-concrete-filled shafts to absorb, although this may pose issues with recoverability. If the mounting mechanism on these shaft sections is damaged by the explosion, it may be impossible to recover effectively making the well useless. A better option may be to merely fill the area above the charge with water and place a very heavy mass above it. Since the explosive cylinder would be a shaped charge, the direction of shockwave propagation is downward, and while the recoil would be immense, it would be well within the ability of current engineering to prevent any major blowback from occurring. The concept of using explosives to stimulate geothermal wells to fissure allowing a large area for water to flow is not new. During the so-called energy crisis of the 1970s a report by the DOE titled “High-temperature explosive development for geothermal good stimulation” and another report titled “Explosive stimulation of a geothermal well: GEOFRAC“, and another report by Lawrence Livermore titled “Explosive Stimulation of a Geothermal Steam Reservoir” all studied using explosive charges at the bottom of the well to induce large fissure growth in the rock. The primary issue encountered was the poor temperature resistance of most explosives compounds, liquid and solid alike. Since the explosive charge has to be placed before the well is capped, the charge may have to spend several hours in the well before it is detonated. The second problem is that since in most of the reports highlighted they only placed a single consecutive charge, the actual volume of rock fissured was minimal and had little effect on the productivity of the well. If an explosive charge can barely induce fissuring, one must ask the obvious question: how on earth can lowly pressurized water induce it? The answer is of course it can’t, hydraulic fracture is impotently hopeless in the hydrostatic pressures encountered at the targeted depths.
The DOE even considered using fission devices to induce fissuring. Such an option would be extremely effective and generate a water flow area so large as to extract potentially thousands of megawatts per wellhead. Since the cost of a geothermal well is directly a function of how much power can be extracted per well drilled, the ability to induce massive fissures using nuclear weapons may be extremely attractive. It is anticipated political issues would thwart any such effort in Western countries, but non-Western countries may take up the challenge. It’s conceivable that if hydrocarbons are being depleted and climate change concerns continue to be so grave, this option may be a necessity for geothermal to ever be widely used. Below is an image from the Cannikin explosion that took place on the Amchitka Island in Alaska where the Atomic Energy Commission drilled an 1800-meter deep hole 2.2 meters in diameter and inserted a 5.5-megaton thermonuclear warhead. The image illustrates the fissures that would be predicted to occur from the detonation. The entire Amchitka island incurred a massive crack, no induced seismicity occurred despite concerns. It is almost impossible to imagine anything like this happening today, the stultifying political and cultural environment has put the brakes on any extraordinary engineering, all we’re allowed to do is code HTML and Starbucks. Although it is unlikely such a powerful blast is actually needed, consecutive detonations of 800 kg high explosive charges will likely produce enough fissures to generate satisfactory power output. Ignoring radioactivity concerns, there are also serious logistical and technical issues with using even miniaturized fusion devices. Such warheads firstly have to be manufactured and made available to certain government-approved entities. presently, these are not legally allowed to be sold to private citizens! Secondly, it must be transported, stored, and inserted into the well. Insertion into the well is by no means a massive technical challenge, but transporting a warhead to the site, especially considering thousands of these wells will be drilled, would be unpalatable. Either way, it is interesting to realize that Hydrostatus Systems is the only engineering firm in the world that is proposing this combination of technology to massively potentiate geothermal energy. Since the original 1970s DOE report, no attempt to drill holes and inserts high explosive charges for fissure formation has been attempted nor are any “startups” pursuing it. This is unsurprisingly considering today’s engineering climate where gimmicks and magical technology are what occupy everyone’s time. Modern-day Western engineers are preoccupied and wasting their time with “e-mobility”, a complete technological boondoggle, to bother pursuing genuinely useful innovations.
High explosives, nuclear or conventional, are the only technology available to actually generate a large surface area needed for heat transfer to be rapid enough for the will to capture a large volume of rock.
The way to understand heat transfer kinetics in the rock is by creating an arbitrary 3D coordinate system to visualize the series of rock layers that surround the flow path. In reality, there is no finite boundary, that would be absurd, there is rather a smooth gradient from hot to cold.
A simple thermal boundary to illustrate the flux of thermal energy from a hot body to a cold body. In this case, a cylindrical shaft is inserted into a arbitrarily large block of material with the assumed density of 2650 kg/m3 and a thermal conductivity of 2.1 W-mK.
The rock consists of primarily silicon and oxygen atoms, often with metallic cations, which are vibrating, if the vibrating atoms on the inner section facing the water flow surface begin vibrating more slowly, an exchange of energy will occur. For an exchange of energy to take place, there must be a deficit of energy on one side. Since a geothermal well is not a continuously heated system, it draws down the thermal budget of a fixed rock mass that can expand in radius indefinitely across the system’s lifespan. If heat is drawn faster than it can be replenished, the cooled area will expand effectively growing the size of the water flow area which initially starts at only a very small radius. Heat drawdown can be visualized as a process of “consumption” where the cold water eats away like corrosion at the energy around it. The cool area grows, the hot area shrinks, but the same amount of energy still flows across the circuit because the total temperature remains constant. By definition the rate of heat transfer must equal the area that is traveled by the energy over the operational duration, this is measured as thermal diffusivity and is discussed in more detail earlier. Cold inlet water is continuously fed through the pipe, as heat is removed from the inner section, heat then moves the outer section and replenishes that section that was just drawn, this is then immediately depleted and the cycle repeats. But each time this occurs, the radius that heat must travel increases since each time there is a deficit of energy below what is needed to replenish the rock, so the rock gradually cools further away from the radius, but the total flux of energy remains constant since the temperature difference remains constant only over a larger area. This larger area that heat must travel to reach the inner section is why well power output declines of the life of the unit. Any estimate of a geothermal well’s power output that is not the average of its operational life is worthless. The output of the proposed 360mm diameter mono-bore is 16 times more in the first hour than over its 100 year life. This is because the thermal penetration distance is squared. The diameter of the hole, the type of fluid used, the rate of fluid flow, the type of powerplant etc, make no difference whatsoever on the available thermal energy that can be drawn from a geothermal well. It is exclusively and solely a function of the rate at which heat can propagate over a given distance over the lifetime of the unit. Any claims otherwise are marketing gimmicks.
Below are quite detailed calculations and estimates of the system’s performance, cost, and lifespan. The estimates are based on using the current data available for rock thermal diffusivity, heat capacity, and density. The earth’s crust is highly heterogenous and many geographies may feature rock with a poorer thermal conductivity than others, which may affect the output of the well, but this occurs both ways, since our estimate is based on the “mean” rock of the crust, which by definition doesn’t really exist, since the crust is made of dozens of different minerals. The system is assumed to be a closed-loop vertical well-bore with no down-bore rock fissuring since down-bore fissuring has yet to be proven. In this case, the well is effectively a vertical straight version of the so-called “Eavor-Loop”, a Canadian geothermal company that has proposed obviating the need for fissure formation by drilling a series of horizontal loops. Since Hydrostatus Systems believes it is finally possible to drill relatively deep inexpensive holes with detonation drilling, we can simply drill a bunch of straight holes in the earth and merely cool the surrounding rock without needing any fissure formation or horizontal drilling. Developing a large flow area at the bottom of the well may prove impossible, even with down-bore conventional explosive charges, so Hydrostatus Systems views straight-bore technology as perhaps the only realistic option achievable in our lifetimes.
It should be said for investor transparency that the power of a geothermal well cannot be estimated without engaging in pure conjecture and yielding grossly incorrect estimates which are useless and dangerous. Just like a gas or oil well cannot be estimated, neither can a geothermal well. What can be said is that if the well does indeed employ the techniques we suggest to drop large high explosive charges one after another to fracture a radius of rock around the bottom of the well, a higher degree of confidence may be attained.
The “power density” of a kg of the crust’s rock is less than that of an ant!
People have a difficult time grasping just how minuscule a quantity of energy a given mass of rock actually possesses. Because the deep earth is viewed as being inherently “hot”, people intuitively assume it possesses a huge amount of practically “infinite energy”, which as we have previously discussed, is far from the truth. This might be true on a macro scale, but at a microscale, where it is relevant for a geothermal well, the energy available is truly minuscule. If we assume the geothermal well we drill will be used for a century, the total area cooled (thermal drawdown region) over its lifetime is a fixed radius around the wellbore center whose size is directly proportional to the thermal diffusivity. This radius happens to be around 90 meters for a thermal diffusivity of 0.65 the average for the crust at 300°C, with a heat capacity of 1150 kJ/kg-K. To draw 20 MW for a hundred years will cool a mass of rock approximately 1.3283628 × 10^12, (one trillion three hundred twenty-eight billion kg), which is a mass of rock that is almost impossible to grasp by the human mass. The volume assuming an average density of 2650 kg/m3 is 5.01268981 × 10^8 cubic meters, or a dome 1300 meters wide and 600 meters tall. This means our geothermal well must cool an area of rock twice the height of the Eiffel tower with a diameter of 1.5 times the Burj Khalifa’s height. The average amount of power extracted from each kg of rock is only 15 microwatts (0.015 milliwatts), or 1.50561277 × 10-8 kW. This is an infinitesimally small power density, around ten million times lower than a lithium-ion battery, which is already one of the lowest power-density energy systems out there. In summary, rock has just a tiny fraction of the energy density of solar energy, wind, tidal energy, or even animal power. The only reason it’s technically viable is due to the sheer mass of the rock that forms the radius around our well, since the well forms a 15-kilometer deep tunnel, the total mass of rock tapped is simply humungous, even though it only yields a sum of energy that is lower to the caloric budget of an insect. Cataglyphis bicolor, an ant, has a metabolic energy of approximately 30 microwatts when crawling at its maximum speed. The earth is simply so gargantuan, even though we are drawing just microwatts from a kg of rock, it represents a massive aggregate sum of energy. The land area occupied by each 100-yr well is 0.038 km2, since each well generates around 20 MW, the power density is 518 MW/km2, which is about 17.3 times better than high-altitude wind. Since we have in the U.S around 250,000 km2 at 35°C/km, we can theoretically produce 128,750,000 MW, or 9 times global energy consumption for a hundred years, or current energy consumption for 919.6 years. At current human lifespans of 85 years, this represents the upper limit on human time horizons, since the probability of catastrophic civilization-destroying events (nuclear war, pandemic, asteroids, dysgenics, etc), occurring in this timeframe is considerable, it is of little use to extrapolate such a long time. This tiny of amount of energy on a volumetric basis is also reflected by the very sluggish heat transfer dynamics. If we have a body of rock with a thermal conductivity of 2.1 W/mk and we pass water that is 100°Cthrough a pore at 565°Cthe thermal flux is only 50 watts per square meter, meaning that if we wanted to extract 30 MWt from a well, we would need to induce a total of 2,000,000 square meters of fissure area. Thankfully, due to the high degree of asperity of these fissures, the specific surface area would be immense.
Since the availability of high-altitude wind power is limited to sites with wind speeds in excess of 10 meters per second, and there is a potentially serious risk of “terrestrial stilling” caused by climactic warming due to so-called ‘polar amplification”, we have hedged our bets and investigated geothermal as an alternative. As usual, Hydrostatus Systems does not merely assume the industry dogma to be valid at face value. In fact, many of the assumptions and customary methodologies employed by the geothermal industry if there exists such a thing are dubious. Attempting to fracture rock at great depths is simply a technical challenge beyond our present capabilities, hence the development of the mono-bore. Since few sites feature attractive natural aquifers to tap into, if geothermal is to ever scale, a technology is needed to obviate the need for both rock fracturing and aquifer availability.
High-altitude wind technology is forced to compete with three major forms of alternative energy technologies. The first and most well-known and proven of these alternatives is the trusty silicon boron-phosphorous doped polycrystalline photovoltaic module. The second is geothermal, where holes are drilled in porous rock media, and water is flowed up to the surface as steam. The third is hydropower, intuitive enough to not need an introduction. The fourth is fission, where uranium 235 is fissioned in a moderated light-water reactor core. This technology might be pollution-free, but it’s not even remotely close to renewables. If scaled to meet eventually world energy demand, all the world’s accessible uranium would be burned up into iodine, cesium, strontium, xenon, and barium within a few years. Since we have analyzed photovoltaics quite extensively, it would make sense to rather briefly analyze geothermal technology to determine whether it can ever be a viable competitor. The short answer is that it will not be a large-scale contender in the alternative energy landscape for a simple physical limitations: the low thermal conductivity and more importantly the low thermal diffusivity of rock. Interestingly, many might believe the issue is merely technological, and that improvements in say drilling technology can make it viable, but this is not really the case.
Many people believe the issue with geothermal is that either we lack the appropriate drilling technology, or that the temperature is not high enough at accessible depths to make it viable. Neither of these facts is really correct upon close examination. There are at least 100,000 square miles of area available where gradients are up to 50C or more per kilometer. Around 12,000 square kilometers in Iceland are available at 55C/km, and around 120,000 or more are available in Australia where gradients approach 47°C/km. Since energy is defined as a change in temperature, to draw a meaningful amount of power from a geothermal well an insignificant drop in temperature is needed. The less the temperature in the well, the smaller the minimum temperature drop can be.
About 3% of the U.S land area, mostly in the Western desert, is at 35°C/km or more. 35°C/km is the minimum for a viable powerplant. Australia, Iceland, parts of Western Italy, and Anatolia are more optimal sites, but excluding Australia, land restrictions may be an issue.
Most of the world has a gradient of around 30°C/km, which is insufficient to justify drilling an elaborate well. The petroleum exploration industry has successfully drilled more than 10,000 meters with rotary bits around 200mm in diameter. The deepest hole ever drilled in the earth is in Siberia in the Sakhalin-I gas complex. The depths approached 12 kilometers. Since water or oil is used as the drilling fluid, the drilling bit is subjected to pressures of 1000 bar or more at this depth. Conventional drilling technology is limited to a speed of at best 10 meters per hour, but the deepest drilling occurs at a snail’s pace of only a few feet per hour. 39% of the upper crust consists of plagioclase feldspar, 12% as Alkali feldspar, 12% as quartz, and 11% as pyroxene. The average hardness of feldspar is very high, with a Mohs hardness of 6-6.5 (Vickers hardness of 900 kg/mm2), equivalent to a Rockwell°Chardness of 55. In comparison, hardened steels machined using tungsten carbide typically achieve hardness levels of around 45 HRC or a Vickers hardness of 270 kg/mm2. This means it requires three times more force to grind feldspar than hardened steel. When cutting hardened steel, carbide inserts rarely last a single hour. Rock drilling bits use diamond cutting inserts, the inserts are made not of solid diamond, since the cost would be prohibitive since growing large diamonds is a very slow process. Instead, they use polycrystalline diamond powder manufactured using periodic explosive charges to create shockwaves and local pressure zones which induce the graphite powder to form the allotrope of diamond. This type of polycrystalline diamond costs around $500/kg, but since it has no structural integrity on its own, it cannot be formed into a solid rigid shape unless a binder is used. Binders can be either metallic or resin, since resin decomposes and or loses most of its strength at relatively low temperatures, metallic binders must be used. But since metal is much softer especially at high temperatures compared to rock, the metal binder is rapidly abraded and the diamond tool piece is rendered useless after just hours of use. Since only a few feet can be drilled per hour at great depths, the bit must be pulled out along with the entire drive shaft every few hours. The total time to drill a 12-kilometer well could be multiple years including withdrawal and shaft removal and reinsertion. Since the shaft can only be as long as the length of a semi-truck and is limited by the height of the rig unit, most shafts are no longer than 15 meters. This means that if the drill bit is inserted down to 12,000 meters, if the bit wears out and needs to be replaced, a total of 800 shaft sections must be removed and placed somewhere. The process then has to be repeated 800 times. The book series published by Springer titled “Exploration of the Deep Continental Crust” contains following texts, The German Continental Deep Drilling Program (KTB) Site-selection Studies in the Oberpfalz and Schwarzwald by Rolf Emmermann and Jürgen Wohlenberg, published 1989, Deep Drilling in Crystalline Bedrock Volume 2: Review of Deep Drilling Projects, Technology, Sciences and Prospects for the Future by A. Boden and K.G. Eriksson published in 1988, Super-Deep Continental Drilling and Deep Geophysical Sounding by Karl Fuchs Yevgeny A. Kozlovsky and Anatoly I. Krivtsov published in 1990, Observation of the Continental Crust through Drilling II Proceedings of the International Symposium by Hans-Jürgen Behr and Francis G. Stehli published in 1987, and finally The Superdeep Well of the Kola Peninsula by Yevgeny A. Kozlovsky. Hydrostatus Systems used the search function with the keywords “drilling speed”, meters per hour feet per hour, feet/hour, meter/hour, etc to find mention of drilling speeds. The results were successful and turned up a chart showing the achievable drilling speeds as a function of downward force and RPM. The chart below suggests with an intermediate RPM of 400 with a shaft force of 8 kilopounds, the speed can reach 8 feet per hour. This would suggest the drilling time alone for the 12 km well would be 5000 hours excluding bit withdrawal time.
Since conventional rotary abrasive drilling is a very slow process, requiring periodic bit replacement, the suspension of the heavy torque shaft, the need for a large rig to carry its mass, a propulsion system for providing the torque, and the issue with binding and shaft friction along the bore walls, a number of alternative methods have been proposed in an attempt to finally make geothermal a genuine contender in the energy landscape. But considering the Soviets drilled a hole 12 kilometers deep in crystalline bedrock quite successfully with 1980s technology, why should we believe this? If the energy available at these depths were so great, we could easily justify the 10-20 million dollar investment to drill 10-12 kilometers no? the reality is quite obvious to those with knowledge of thermodynamics, unfortunately, most people lack this and fall victim to fantastical claims about “infinite energy” available in the earth. An entire array of alternative drilling contrivances have been suggested, ranging from plasma vaporization, thermal spalling, projectile launchers, explosive capsule ejectors, and water jet spalling, among others. None of these alternatives have been commercially deployed, and while they appear attractive in theory, there is too much multiplicity considering the extreme conditions they face, hundreds of degrees °C, and hundreds of megapascals of hydrostatic pressure. Even the most well-designed drilling system faces intense stress during its operation and considering conventional rotary drills have such a proven track record, any contender faces a steep battle to compete with them.
Rock is not an “infinite source” of energy
Aside from drilling, which is likely improvable with better technology, the critical limitation is not technological but rather purely physical limitation arising from the sluggish thermal diffusivity of crustal of rock, of which the most common is plagioclase feldspar. The upper crust is assumed to have a thermal conductivity of 2.1 W/m-K, with a relatively high heat capacity of 800 J/kg-K. With a moderately high density of around 2650 kg/m3, these numbers translate into a very sluggish thermal diffusivity, the most crucial variable in determining how fast we can “draw” heat from a rock mass. Many people mistakenly assume thermal conductivity is the only metric that matters, this is incorrect. Thermal diffusivity is the crucial variable because it is a direct measurement of the propagation rate or speed at which thermal energy (heat) travels across a surface of a material measured in square meters or millimeters per second. Thermal conductivity in theory is such a measurement, since it measures the total flux of energy across an arbitrary body with a given temperature difference, but it is not material invariant. Thermal diffusivity is arrived at by dividing the thermal conductivity by the heat capacity multiplied by the density. Thermal diffusivity, unlike thermal conductivity, takes into account the material’s ability to absorb heat as it conducts. When heat flows through which has a temperature gradient (which is a tautology since no heat can move without a gradient) some of the heat is reabsorbed by the material’s depleted heat capacity, thermal diffusivity adjusts for density and conductivity and heat capacity to estimate how fast thermal energy can move in a solid material, gas or liquid. A material with a low density, high conductivity, and low heat capacity, will have a high thermal diffusivity since there is little mass and heat capacity to absorb the energy that is propagating across the material. Conversely, if the material has low conductivity, high density, and high heat capacity, the thermal diffusivity will be sluggish since the bulk of the energy traveled is reabsorbed by the dense high heat capacity material. It might seem as if we want a high heat capacity in our rock, after all, if we reduce the temperature of a given rock mass by X amount, the power available is directly a function of the heat capacity. But unfortunately, the situation is not so simple, because if we draw down an arbitrary section of rock around or geothermal well flow area, we have temporarily “stolen” the heat of that rock and transferred it into our flowing water which is then pumped to the surface. This energy has been permanently removed from the rock. If we then continue to draw heat down from this rock mass since our water is still flowing, we will now be pulling heat from an arbitrary rock section slightly further away from the well water flow area, so heat must now have time to flow across the just-depleted rock. But since we are constantly sucking heat out, this energy that is now flowing due to the temperature difference will not go to replenishing the rock since we are constantly depleting it, the difference between the depletion rate and the supply rate is proportional to the mean distance between the drawdown distance. As this process repeats, the radius of “thermally drawn” rock will grow ever so slightly around the water flow area infinitely until after millions of years, and the entire crust is cooled to the temperature of the water. Since heat flow is a function of temperature difference, the more we cool the rock the more energy actually flows, so in that respect, this is what we want. But since this heat flow is immediately captured, the rate at which this heat flow travels from the outer radius of the flow area to the center determines the amount of energy we can extract per hour. The mathematics now becomes interesting, because the equation for thermal penetration length or thermal penetration rate is the square root of 2 times the thermal diffusivity coefficient and the time, thermal penetration is thus directly proportional to the square root of time, but. Therefore, the speed at which thermal energy propagates is very fast at the center but slows down logarithmically towards the outer radius. If we double the elapsed time from which heat can travel, the distance reached grows by only 1.4142 times. This inverse logarithmic relationship causes wellbore output to sharply fall in the first few hundred hours of operation and then level off only very gradually declining. 1.4142 is an irrational number and happens to be the square root of 2. The equation is written as √2αt, where α is the diffusivity coefficient and t is time. The diffusivity coefficient is also sometimes denoted as d or k. Hydrostatus Systems created a solver using fxsolver.com in order to simplify the calculation by allowing one to solve for distance, time, or diffusivity coefficient, most other calculators on the internet only allow one to solve for distance. In order to ensure our calculations are correct, we compared it to the calculator below offered by Thermtest, the results are identical. https://thermtest.com/thermal-resources/heat-penetration-calculator#thickinput_125,diffinput_1.1,timeinput_3600
Thermal Penetration distance: √2αt
It would be remiss to ignore other technical issues with geothermal besides the low thermal diffusivity of bedrock. Another issue is the fact that the water cannot be heated to the temperature of the rock or else no heat transfer will occur, yet the water desires to be as hot as possible for efficient conversion in a Rankine cycle. Since most nuclear reactor steam turbines draw steam at 315°C, their efficiency is only about 30%. If the water temperature is only 250°C, the efficiency can drop below 20%. For any heat transfer to occur, there must exist a substantial difference, this means that the mean temperature of the water must remain well below the temperature of the bore, this requires to flow at a rate substantially faster than the ability for the water to warm otherwise it will simply rapidly rise to the temperature of the surrounding rock and heat transfer will slow down to very low levels. If we are pumping 20°C water from the surface, depending on the flow rate of the water, heat transfer will continue to occur until the rock has cooled to some equilibrium at some midpoint between the rock and the water. This depends on the diameter of the flow area, since water has low thermal conductivity, its much easier for heat to flow through the hot rock and into the cold water than for heat to flow within the water. This equilibrium is always going to be lower than the ambient temperature of the uncooled rock. This means if the bottom of the geothermal well is 660°C (55°C x 12 km), the water must be kept at a mean temperature of only 350°C, or less than half the average well temperature, since it will very quickly reach a high fraction of the mean rock temperature if flowed relatively slowly. If the water is flowing fast, the rock cools faster but the heat transfer increases. If the water temperature is allowed to fall significantly below the surrounding rock media at the end of the flow area corresponding to the end of the bore, the temperature difference between the minimum desired turbine efficiency and the surrounding rock temperature determines the heat flux. Therefore, a good compromise is made around 410°C below the 660°C bore, which maintains decent turbine efficiency but allows for very rapid sufficient heat transfer to occur. Of course, this can only be achieved in sites with high thermal gradients, otherwise, the temperature difference between the minimum turbine temperature requirement and the available heat of the bottom of the rock flow area is too small for sufficient power extraction. This might sound confusing, but the central reason why its a problem for geothermal wells is that unlike a real heat exchanger say using combusted flue gases to warm water, the bulk of the heat transfer occurs rapidly across a very small surface, in other words, the specific heat transfer rate is huge because the energy input is unlimited, it is impossible for the working fluid to pull enough heat to cool the flue gases passing through our heat exchanger. On the other hand, in a geothermal well, the flow path is very long which means the heat transfer is dispersed across a large area as well as a large increment of time. This means the water is quickly warmed from the initial flow trajectory, but then only slowly captures heat from the rock further along its flow path. But since the initial rock loses most of its heat and transfers it to the water, the heat transfer from then on is sluggish.
Corrosion of the borehole liner is another issue for geothermal wells. Casing is required not to withstand the hydrostatic pressure, but to prevent erosion and gradual decay of the rock hole and to prevent sediments and rock fragments from contaminating the water supply. Since cathodic protection may generate hydrogen and cause embrittlement of high-strength ferrous alloys, most bore liners are unprotected and barely last a few decades due to the high presence of sulfur and chloride compounds in the surrounding rock. Another challenge is related to supporting its mass during its installation as it descends into the multi-kilometer shaft. If the bore liner is not supported on a ledger on the side of the bore wall, which requires tapering the bore which adds considerably drilling hassle, then it must be suspended in its entirety as its welded and lowered into place. A further issue is heat loss as the hot fluid flows up through the cooler rock at shallower depths, which might result in half of the total energy being lost to the cool rock in the upper half of the up to the 10-kilometer-deep shaft. But by far the single biggest limitation is heat transfer, not drilling, bore-liner, or heat losses, which are amenable to technological enhancement. Ultimately all technologies have physical limits that place a strict cap on their performance or output, a Shockley Queisser limit for photovoltaic, a Betz limit for wind, a Carnot limit for heat engines, and a number of less-known physical limits on a host of other technologies. Technology can only improve the way an artificial mechanism can perform a natural phenomenon, it can only improve it to the extent the natural phenomenon is amenable to process efficiency, and it cannot in any way alter the natural phenomenon itself.
It bears repeating that most people mistakenly believe drilling technology is the “Achilles’ heal” or “limiting factor” for geothermal, but this is wrong. The central issue is creating a surface area large enough for heating a sizeable portion of water, sufficient to make drilling the well economical.
The critical weakness that effectively forbids its wide-scale deployment is the difficulty of establishing a flow path between the inlet and outlet boreholes. For any sizable power output, the system must employ what the industry calls a “closed loop” circuit, where working fluid is pumped down into an inlet well to be heated and then pumped back out. The pumping energy is usually provided by a thermal driving head, the so-called “thermosyphon effect” where the difference in hydrostatic pressure is used to overcome the viscous resistance. But this difference in pressure may not be enough to compensate for pressure drop and pumping power may be necessary for very high flow rates. For a sufficient surface area to be created to heat the flowing fluid, a large amount of rock has to be shattered horizontally at kilometers of depth to allow water to establish a circuit. A highly porous flow path has to be established, this can in theory be performed by pressurized water above the hydrostatic pressure, but practical considerations make this extremely difficult. Firstly, the fracture has to be in the right direction, pressure desires to flow in all directions at once, merely pumping water into the well above the hydrostatic pressure is no guarantee that the fracture will occur straight between the two shafts and form a perfect path between them. Secondly, the amount of pressure needed above the hydrostatic pressure is substantial, which means the water must be pressurized starting from the beginning of the hole at the surface, requiring massive pumps.
Present-day geothermal relies on so-called “hydrothermal” architecture, which taps into natural reservoirs, most Icelandic plants employ this principle. The power densities of this configuration are very low. The only way to scale it is to pump water down into the borehole. But to pump water down into the borehole requires that water to flow horizontally at sufficient volumetric flow rates as it encounters viscous pressure drop due to the porosity of the rock, if the pressure drop exceeds the thermal driving head, then the flow is limited or requires pumps.
After about five minutes of studying how present geothermal wells operate, it becomes evident they are severely handicapped. The only present strategy that could possibly provide enough energy is through drilling two holes and hopelessly trying to use the pressure of water to find its way through the dense rock formation to form a circuit. An alternative option and the more common method is to simply drill a hole and hope that water is already down there and simply draw out the steam without putting any water into the ground, this is what they call “hydrothermal”, but its power output is severely limited. The central disadvantage of this method is the high viscosity of steam. Steam has a much higher viscosity than liquid since it is a gas and is compressible, thus the pumping parasitic power caused by friction along the borehole wall causes a drop in the pressure limiting the available flow rate.
Heat transfer is bottlenecked by the rock. Assuming a heat capacity for rock of 500-1000 kJ/kg-K, a thermal conductivity of 2.1 W-mK, and a temperature drop of 270°C, the available power is only 90 MW-thermal for a 15 km well in a 55°C/km geography.
In summary, geothermal energy is effectively technically difficult, not saleable, but potentially very cheap, so it is attractive, but not a “game changer” and will never be used on a large scale due to fundamental thermodynamic limitations. We can thus confidently conclude that outside of major innovations in fission, such as potentiated reactor designs and or safe breeder reactors, no major energy panacea will arrive, leaving high-altitude wind turbines as a very potent contender for decades if not centuries to come.
A substantial portion of the earth’s heat core and mantle heat budget is residual heat from its formation, the balance is isotopic decay. Anyone who claims geothermal is renewable is ignorant of thermodynamics, of which many people unfortunately are. Photovoltaic in comparison is not a finite source because one is tapping into a constant stream of photons, and it would be by definition physically impossible to capture more of them than are arriving because it would require an invisible solar panel to allow them to be stacked in front of other! Since a solar panel can only capture 18% of the prevailing ultraviolet and visible flux, one cannot drain down this source, only tap it to its maximum. Wind is like solar, you cannot pack more wind turbines in a square kilometer than the minimum wake losses permit, so once you max out the area, the energy source is tapped out, but it does not decline since only a tiny fraction of the wind’s kinetic energy is captured by the turbines and in theory, keeps going on forever as the wind blows. Wells will only be drilled in regions where the crust’s rock composition has high thermal conductivity or a close distance from magmatic intrusions. Rock has high density and high heat capacity, but very low thermal conductivity, which means slow thermal diffusivity, a measure of how fast heat penetrates into a body. This means that if you drill a well, if you draw more than the thermal diffusion rate can resupply it, the well will rapidly cool. This limits the amount of power extractable to between 9.5 and 19 watts per kg of rock over its lifetime depending on the geothermal gradient and the minimum temperature required by the steam turbine. The power density by area is much greater since we are drawing from a very deep mass of rock the entire depth spanning from the well bore to the surface. Hot regions don’t necessarily produce more energy by land area, because more heat is drawn from these regions in a shorter time frame, since the temperature difference between the hot water going to the stream turbine and the temperature of the rock is greater than what can be allowed for in a cold region. So a sharp thermal gradient, such as in Iceland, some parts of Australia, the Pannonian basin in Hungary, and Western Anatolia, will allow for a higher energy density, but will be more quickly drawn down since the T2 is greater. The available power from a well is very easy to calculate. Simply find out how long the “thermal drawdown” period is in seconds (this is the desired well life and an entirely arbitrary number), multiply that by the thermal diffusivity coefficient, multiply it by two and then arrive at its square root. This will give the distance of thermal penetration across the elapsed time-frame. Then take this distance that heat travels in fifty years and add up the volume of rock that represents and find the energy that a given temperature drop represents. It is very simple and one cannot decide the mathematics with fancy technology. The velocity of thermal diffusion is the inverse square of the distance, if distance increases by two times, the time taken grows by four times. As the thermal drawdown region grows in a radius around the pumped liquid flow path, the power output of the unit declines. It makes no difference whether you extract heat from the sides of the well, a fissure at the bottom, or from horizontally drilled holes like EavorLoop is trying to do. The geometry, surface area, orientation, or number of flow paths has no bearing on the thermal budget of the region that surrounds these flow paths. In fact, many people assume going deeper results in more energy, but as most things are counterintuitive, the reality’s the opposite. While the total heat flux is always greater at high temperatures because the potential temperature difference can be raised, the rate at which heat is replenished actually drops significantly more than at lower temperatures. This is because the thermal diffusivity is thermally dependent, hotter molecules are vibrating more intensely and repel each other and inhibit heat transfer. Since we have mentioned many times before that thermal diffusivity is the sine qua none, drawing the bulk of the heat from greater depths actually slows down thermal penetration. This means that the thermal drawdown regions grows slower and hence the mean power density falls.
Thermal diffusivity drops for all rock types as temperature increases. Thermal diffusivity does increase with pressure since the atoms of the rock are packed more tightly together, but the increase is very gradual and thus the hydrostatic gradient does not compensate the loss from temperature. For a 55°C/km gradient, the mean temperature of the well be 465 C, at this temperature, the thermal diffusivity is only 0.65 mm2/s, dropping from over 1.5 at 100°C.
Because thermal penetration speed is the square of 2 which is an irrational number of 1.412, the decline is very sharp in the first few hundred hours and then drops gradually until reaching a roughly steady state point with negligible decline. If you drill in a region where the flux is say 55°C per kilometer, which is the average for approximately 12,000 square kilometers of the entire island of Iceland, if you sucked all the heat out of a radius of say 70 meters around your well, you would produce about 30 megawatts of power of a 50 year period. But you have cooled a mass of rock that weighs 6.7 x 10^11 kg by 300 degrees, that energy is now gone, and to get more energy the heat has to come from rock further away, and this takes time. Where thermal gradients are no greater than 35°C/km (many parts of the Western continental U.S), the energy density per well (not area) is lower, about half the 55°C number, since you cannot cool the rock by the same magnitude due to the limit imposed upon by the steam turbine’s minimum Carnot temperature. If you drilled a 15-kilometer hole at a 35°C/km gradient and cooled the rock by an average of half its nominal value, in this case, it would be an average well temperature of 297°C across the entire depth, the allowable drop in temperature is thus only 148 degrees, the power is 14 MW, or 722 MW/km over fifty years. If we then take all the land of the parts of the Western U.S that have a gradient of 35 degrees per kilometer, we get a number of about 12 times global energy consumption for only fifty years, then that heat is gone forever and you have to forage in the cooler regions. Painstakingly taking the U.S geothermal gradient map and adding up the fraction of the area at 350°C, I concluded about 2.89 percent of U.S land is at 350°C/km, about the minimum for cost-effective drilling, or about 232,947 km2 in the lower 48 states, of which 90% is West of the rocky mountain range in the high plateau deserts. If all this land were tapped, the output would be 168.18 million MW. This estimate is from a recent study on geothermal gradients, a report by the U.S DOE from the 1980s that a total area of 3 million square kilometers exists in regions with thermal gradients are in excess of 30 C/km, with a total potential heat flux of 1.74×10^12 terawatt hours, assuming a 20% conversion efficiency, 3.48×10^11 terawatt hours is available as electricity. The total U.S electricity grid uses 4,000 TWh, if all the geothermal sites were tapped out to 10 km, which is conceivable since the scalability is effectively unlimited due to the non-use of scarce elements, we could expect this reserve to last 87,000,000 years.
Any technology that relies on consumables for its operation must be shown to be compatible with current production capacities. In our case, we must consume a substantial volume of explosive material, drilling fluid, and electricity. The explosive, due to producing a somewhat larger mean fragment size, requires a higher viscosity drilling fluid to reduce its free-fall velocity. Compared to a rotary drill, up to twice the pumping power will be required. Many people mistakenly believe that alternative or new technologies must invariably be “cheaper”, but this is a flawed notion. Vacuum tubes are clearly cheaper to engineer and manufacture than integrated circuits and silicon transistors. Rather, it is the expected performance of the superior silicon transistor that justifies its higher cost. Mechanical drilling is an archaic technology that has remained virtually unchanged for centuries, and while there exist countless alternatives, all of them share one thing in common, they are expected to be a higher-performance system but with added complexity and cost. Explosive drilling is no different. It is not expected that explosive drilling should be any cheaper than rotary drilling. But what is expected is that unlike rotary drilling, explosive drills will penetrate through the hardest rocks with ease. The cost of the total system, including the capsule delivery mechanism, explosive capsule manufacturing, shock-wave attenuation system, shaft and nozzle assembly, electricity, fluid, and explosive consumption, will amount to a sum of around $20 million for a 12.5 km well. Consumables are expected to account for over half of this cost. It should be remembered that “cost” is not a subject of scientific or technical interest, since it in an inherently variable and economic factor, depending on non-technical factors such as local policy, wages, and financial/monetary aspects.
Total explosive consumption to drill enough holes to meet all U.S energy demand. If we assume a 500mm dia well can produce 30 MWe of power with aggressive fissure stimulation, and 600 tons of explosive (5x over-use for rock comminution) are used to drill the well and 100 tons are used to induce fissuring, then we assume per MW explosive use is 23 tons. Since the U.S electricity grid is 456,000 MW, we will need 10.5 million tons of RDX. Interestingly, the U.S produced 15 million lbs of RDX monthly or 81,000 tons in the 1970s. This means to produce the entire U.S electricity grid over a period of say two decades, RDX production capacity would not have to increase by very much.
It should be remembered that these estimates are purely for scientific interest, they have no practical bearing whatsoever since extreme scenarios by definition occur in reality. It is extremely unlikely a single energy source will ever power 100% of a country’s energy budget, except for cases where it is as simple as building a demand, such as in Norway.
The realities of “hot dry geothermal”.
The idea of pumping water into a rock body to induce fissuring is not new, it was developed by multiple individuals independently in the 1970s motivated by the energy crisis. Bob Potter issued the first patent on the principle. The idea is extremely simple, use a slight excess of pressure above the formation pressure to slowly enlarge existing micro-fissures. The crust is thought to be rich in tiny fissures or faultlines that exist perpendicular to the hydrostatic gradient. Since the force of gravity manifests in the vertical plane, displacing the rock tangent to the surface plane is much easier. While the permeability of the crust is estimated to be in the nano-darcy range, existing microcracks are liable to be expanded slowly over time with enough pressure, although there is considerable variability in the presence of pre-existing microcracks. Many hot dry geothermal projects were attempted in the 70s and 80s. Most notable is the Fenton hill well in New Mexico. While there were several successful runs where fissures were formed after substantial pumping effort, many wells refuse to “open” and power output remained low. An article by Richard A Kerr in SCIENCE entitled “Hot Dry Rock: Problems, Promise” chronicles some interesting findings without placing a positive spin on it. Kerr is quoted as saying “After a decade of hard lessons and limited success, tapping the enormous heat reserves in rock too dry to yield steam or hot water on its own faces more challenges”. He goes on to say: “No one has figured out why some fractures open and others do not”. “Hot dry rock has proved to be a recalcitrant, even devious foe, demanding greater respect and subtlety of design than pioneers in the field imagined”. Kerr describes how some of the wells drilled and hydraulically stimulated that performed well were because of natural openings and not due to the hydraulic fracturing itself. A major scientific error made by geothermal proponents is comparing existing hydraulic fracturing strategies used in highly brittle, soft sedimentary shale rock. Many geothermal proponents have made totally unfounded claims that somehow they can apply shale fracturing technology to extremely hard, strong, highly compressed igneous and metamorphic rock, which is highly erroneous. There is little reason to believe the mild pressures used to stimulate fractures in shale will ever produce even close to the results in deep crystalline rocks. While our proposed strategy to use the immense detonation pressure of explosives to generate thousands of bar of pressure of the background hydrostatic pressure may not even be sufficient, it is at least an attempt. One thing can be said, regardless of how successful the efforts at developing new drilling technologies are, the entire effort is ultimately determined by how much and if we can fissure deep rock strata. If it should be too difficult to reliably induce fissuring to achieve the necessary surface area and flow path, geothermal energy will remain in obscurity. This will mean any alternative drilling technology will be seen as an asset to aid in deep gas exploration in hard rock strata. It is quite astounding to see so many geothermal startups makes claims with utter confidence and certitude that once we have this magic bullet that is some new drill apparatus, all we have to do is effortlessly pump water into the hole and “voilà”, a huge volume of pore space will suddenly be generated. Considering the only successful and proven site was Fenton which was only 3 km where hydrostatic pressure is much less than at 12 km, one cannot extrapolate these results.
Another important factor is establishing the energetic inputs of pressuring the hydraulic fluid. If we assume we need a few hundred bar of additional pressure of 500 bar, and to generate a seismic volume of 80 million cubic meters we must inject 25,000 cubic meters, a total of 300,000 kWh is required, or about 12.2 kWh/m3 at a pressure of 500 bar. These numbers seem to endorse the overall energetic efficiency of hydraulic fracturing. Even if an order of magnitude more water was required, the power still only amount to 3 million kWh, which is a reasonable number.
It’s interesting to note that currently, there’s yet a consensus on the exact mechanism at play during hydraulic fracturing. It’s assumed the planar fractures propagating along the rock layers are slowly enlarged, but evidence suggests crack also propagate parallel to the hydrostatic gradient. Either way, until more certitude, exists on the viability of inducing or enlarging micro-fissures in the rock bed, one cannot make claims on the scalability of geothermal energy.
Liquid explosive drilling, while a much inferior method, can still be used, but a number of issues arise. The principal issue is the very long propagation of pressure waves encountered in liquid and the production of heavy rock fragments that are difficult to remove using fluid motion. The long propagation of pressure waves in liquid limits capsule ejection frequency since the maximum interval is limited by the propagation distance of a pressure wave possessing sufficiently powerful to cause sympathetic detonation. In water, a small 20-gram charge of RDX produces an 80-bar pressure wave at a distance of 1.6 meters. This not only requires a sufficient distance to be maintained, but it also limits the maximum size of the charge that can be detonated, since larger charges produce even greater pressures, although at a linear rate. It also requires that the extendable nozzle (needed to perform flushing or suction of fragments) be extended since the offset of the nozzle must ergo increase.
But most critically, something that ultimately cannot be solved merely with better engineering, is the matter of fragment removal.
With liquid drilling, what emerges is a hydrodynamically determined fragmentation and comminution cycle, which acts as the rate limiting step.
All processes possess what could be called a “rate-limiting step”, a term borrowed from the catalysis literature. Our technology is by no means immune to such a phenomenon. In the case of explosive drilling, it is predicted that drilling rates will be rate limited by the efficiency of the hole-cleaning nozzle, the viscosity of the fluid, and the attainable fluid velocity. The nozzle flushing efficacy is determined by its distance from the rock fragment bed and the available overpressure and velocity needed to accelerate and lift the fragments into the drilling fluid. The number of apertures in the nozzle and its residence time is expected to have the greatest influence on its efficacy. Once the fragments are elevated by the nozzle, they need to possess enough drag to minimize their free fall velocity. It is expected a very large amount of power will be required to provide sufficient fluid viscosity, this may be up to 6-10 MW depending on the velocity and volumetric flow capacity required. The overall process is bottlenecked by the removal of stubborn heavier particles, while particles over 40mm in diameter have not been shown to occur at significant frequencies, if these particles are not comminuted by subsequent explosions, the drilling speed may be slowed considerably since larger fragments represent an appreciable share of the mass removed. It is expected that these heavier fragments will cluster into the rock bed and experience further comminution until their sizes reach a level that can be carried by the fluid. In order to determine what the particle cut-off size is, we can use a number of mathematical approximations. Unfortunately, Stokes’s law can only be used for spherical particles but since rock fragments possess highly irregular geometries and high roughness surfaces, we must use the drag equation to predict their free-fall or terminal velocity. Since the drag coefficient changes dramatically with the Reynolds number, we have to ascertain the specific Reynolds number that the fragment will correspond to manually by finding the fluid viscosity, density, characteristic length, and flow velocity. The drag coefficient increases substantially when the Reynolds number is low, a low Reynolds number means the flow is laminar, and viscous drag predominates over inertial drag. This is the regime in which the rock fragments find themselves, inertial drag plays a smaller role than fluid viscosity. Unfortunately, there exists a large discrepancy in the results yielded by the two formulas, highlighting the limitations of mathematical prediction unless the precise conditions are specified. The fundamental reason for these discrepant results is due to the assumptions made by the stokes equation. Stoke’s initially developed the equation assuming the settling speed of particles in a liquid was entirely due to viscosity, discounting any other inertial causes. A smooth sphere, what the Stokes law is based on, is predicted to have a drag coefficient of around 3 at a Reynolds number of 52. The characteristic length of a 20mm sphere is 0.003 m, yet the Stokes law calculation predicts a free-fall velocity of 3.77 m/s against 0.47 m/s using the drag equation. If we run the calculations and hold the free-fall constant, the only variable that is liable to change is the drag coefficient used in the drag equation, since fluid density and viscosity are not labile and flow velocity is determined afterward, we must dispense with one of the methods. The reason for this discrepancy is that Stoke’s law is only applicable in a regime with a Reynolds number of less than 1, where essentially only viscous forces are at play, hence Stokes’ law assumes only viscosity is acting on the sphere, even though there is still appreciable inertial resistance due to the density of the fluid and a small degree of flow separation. It has also been empirically found that Stokes’s law is valid only for particle size between 0.002mm to 0.2mm and up to a maximum Reynold’s number of 1. Since we have concluded our Reynolds number will be below 40, Stoke’s law must be replaced by a model that incorporates inertial forces. But identifying the Reynolds number is not sufficient, we must arrive at a reasonably confident estimate of the drag coefficient of the object in question. Since a smooth sphere is predicted to have a drag coefficient of over 3, we can assume a highly irregularly shaped fragment will have a drag coefficient substantially larger than that. Although this may not be the case since we know that as turbulence increases, drag drops. This is why golf balls have dimples in them, to encourage flow separation and reduce the velocity needed for the onset of the drag crisis. A DTIC report titled “Drag Coefficients for Irregular Fragments”, they found that rock fragments traveling through the air at velocities of around 25-30 m/s had drag coefficients ranging from 0.8 to 1.3 which was not sensitive to fragment size. Since the Reynolds number of such fragments would be in excess of a 1000, we can assume the equivalent drag coefficient at low velocity would be much higher. We can therefore confidently assign a drag coefficient of around 1.5 for the 20mm rock fragment falling through a 100 centipoise oil. We can therefore find that the free-fall velocity is around 0.5 m/s. This would suggest that carrying these heavier fragments to the surface should not pose a technical challenge.
The ideal explosive charge geometry.
It is not certain that a hockey-puck-shaped gauge charge is ideal, a number of novel geometries may provide a greater degree of fragmentations due to focusing the shockwaves in a manner that exploits the rock’s anisotropy. It is well known that most silicate materials have very low tensile strength but moderately high compressive strength. It is thus expected that the most effective disintegration will be when the shockwaves travel along the X and Y coordinates.
The decay of brisance with depth is due to rock compaction and porosity reduction. As the depth increases, hydrostatic pressure squeezes the rock crystals together increasing their density and hence its bulk modulus. Feldspar has a bulk modulus of 69 GPa, while lead, used in the famous Trauzl lead block test, is 46 GPa. Rock at depths above around 5 km is expected to be highly compressed and feature very low pore volume, and hence its behavior can be treated as a pore-less solid like metal. Thermostable Explosives and their Effects in Deep Boreholes by Filipp Abramovich Baum is the only dataset that compares the brisance of explosives in rocks as a function of hydrostatic pressure. The results show a negligible reduction in saturated limestone but a significant reduction in brisance for unsaturated marble. The reduction in brisance for unsaturated marble was 50% from 1-1500 atm, and the reduction for the saturated rocks was only 15%. Since its highly unlikely that there exists any significant amount of unsaturated rock in the crust, a 50% reduction in brisance is not likely to occur. It is therefore expected that explosive consumption should not markedly increase with depth as William Maurer claims.
The critical nature of casing thickness
Once a hole is drilled, even in a very stable rock formation, there is a need to eliminate leakage in the well from over-pressurized formations. The use of metallic casings is likely the only feasible option to maintain long-term wellbore vitality. Since a geothermal well has a limited life before thermal drawdown becomes excessive, casing corrosion can be accepted as long as it does result in premature failure. It is very difficult to estimate corrosion rates since the alkalinity, chloride, and hydrogen sulfide content cannot be known until the well is drilled, it is next to impossible to estimate the casing life. Additionally, the worst-case scenario assumes no cathodic protection is incorporated. An aggressive polarization regime can largely negate degeneration of the casing pipe provided a large sacrificial anode is maintained at the site. If we assume a thick steel case is inserted between a layer of concrete, we can immediately see the benefits of large-bore drilling afforded by explosives. A larger diameter bore permits the natural hydrostatic pressure difference between the cold inlet water and the hot outlet to be well in excess of the pressure drop, affording large flow rates which accelerate hydraulic fracturing and power output. Additionally, the use of a large diameter allows the introduction of explosives for additional stimulation efforts.
A critical factor that would dramatically influence cost is site and country specificity. For example, this would be prohibitive in Europe at the moment since we couldn’t produce the pumping energy affordably since even renewable power is in short supply. We need a steady and moderately priced supply of fuel (regardless of type) for the pumps, this might force us to selectively favor locations where this is available. The U.S is a good location because we can use our idea of small nh3 plants to produce fuel from wind power in the Midwest and transport it to our drilling site wherever that may be. Once we have this setup, we can do it in Europe by shipping the fuel to the site.
porosity is a critical parameter for thermal extraction. There may be a point where the loss in porosity at increased depth cancels out the added temperature since thermal drawdown is ultimately limited by liquid permeability.
“For one thing, the temperature rose much more quickly than expected. This caused discussion and a reformulation of theories about the temperature gradient of very deep drill holes. Other theory changes were also required – it had been expected that the large tectonic pressures and high temperatures would create metamorphic rock. Unexpectedly the rock layers were not solid at the depths reached. Instead, large amounts of fluid and gas were poured into the drill hole. Due to the heat and fluids, the rock was of a dynamic nature which changed how the next super-deep drilling needed to be planned”
“large amounts of fluid and gas poured into the drill hole”.
“The drilled crustal segment is distinguished by large amounts of free fluids down to mid-crustal levels”
“The ZEV (Zone of Erbendorf Vohenstrau), which represents a variegated association of paragneisses and orthogneisses and metabasic rocks with minor metapegmatite rocks) contain a surprisingly large amount of free fluids, either in the form of hydrocarbon-rich “dry” gases or as formation waters. Dry gases were only detected in the gas logs and could not be sampled directly. They mainly consist of methane with minor helium and radon and are invariably associated with graphitized faults. Formation waters were first encountered at 400 m depth, and they occur very commonly from 3200 m down to the final depth in numerous distinct zones of up to several tens of meters in vertical thickness. Below 2000 m the first saline peaks were detected, and at 3200 m the first open fissures and porous alteration zones containing highly saline fluids were penetrated. Significant fluid inflow (up to 30 m •) occurred at various depth levels associated with major fault zones or were stimulated by draw down test”
“The size of the rock particles breaking off in the shatter and hydraulic zones of explosive activity substantially influences the served cleaning of the bottom and the removal of the particles from the hole. It has been observed during experiments that individual large pieces of rock (up to 200 g) are torn off the upper layers, The breaking away of such pieces ceases when the hole deepens to approximately one meter. Without considering these pieces, individual fragments do not exceed a dimension of 20 mm, according to sieve analysis, The concentration of particles larger than 10 mm is 20%, 3 to 10 mm 70%, and less than 3 mm 10%”. Ostrovskii, p48
Advanced Energy Systems 