Christophe Pochari, Christophe Pochari Engineeering, Bodega Bay, CA.
707 774 3024, christophe.pochari@pocharitechnologies.com
Introduction:
Christophe Pochari Engineeering has devised a novel drilling strategy using existing technology to solve the problem of excessive rock temperature encountered in deep drilling conditions. The solution proposed is exceedingly simple and elegant: drill a much larger diameter well, around 450mm instead of the typical 250mm or smaller diameters presently drilled. By drilling large-diameter wells, a fascinating opportunity arises: the ability to pull away heat from the rock faster than it can be replenished, thereby cooling it as drilling progresses, preventing the temperature of the water coolant from reaching more than 150°C even in very high rock temperatures. A sufficiently large diameter well has enough cross-sectional area to minimize pressure drop from pumping a voluminous quantity of water through the borehole as it is drilled. The water that reaches the surface of the well will not exceed 150°C, this heat would be rejected at the surface using a large air-cooled heat exchanger. If the site drilling temperature exceeds the ambient of 20°C such as in hot climates, an ammonia chiller can be used to cool it down to as low as 10°C Any alternative drilling system must fundamentally remove rock either by mechanical force or heat. Mechanical force can take the form of abrasion, kinetic energy, extreme pressure, percussion, etc, delivered to the rock through a variety of means. 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 drilling 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. Thermal methods involve melting or vaporizing, since at least one phase change will occur, the energy requirements can be very substantial. This heat must then be introduced somehow, it can either be in the form of combustion gases directly imparting this heat or via electromagnetic energy of some sort. Regardless of the technical feasibility of the various thermal drilling concepts, they all share one feature in common: they require drilling with air. 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. This poses a nearly insurmountable barrier to their implementation since even the deep crust is assumed to contain at least 4-5% H2O by volume, (Crust of the Earth: A Symposium, Arie Poldervaart, pp 132). Water will invariably seep into the well and collect at the bottom, and depending on the local temperature and pressure, will either exist as a liquid or vapor. Additionally, even if the well is kept relatively dry, thermal methods such as lasers or microwaves will still incur high reflective and absorptive losses from lofted rock particles 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, they will be greatly attenuated by the presence of the drilling fluid, requiring the nozzle to be placed just above the rock surface. This presents overheating and wear issues for the tip nozzle material. Christophe Pochari Engineeering 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. In light of this fact, it is essential to evaluate and consider proven and viable methodologies to take existing diamond bit rotary drilling, and make the necessary design modifications to permit these systems to work in the very hot rock encountered at depths greater than 8 km. In order to access the deep crust, a method to deliver power to a drill bit as deep as 10 kilometers is needed. Due to the large friction generated when spinning a drill shaft such a distance, it is absolutely essential to develop a means to deliver power directly behind the drill bit, in a so-called “down-hole” motor. Rotating a drill pipe 10 or more kilometers deep will absorb much of the power delivered to the pipe from the rig and will rapidly wear the drill pipe, necessitating frequency replacement and increasing downtime. Moreover, due to the high friction, only a very limited rotational speed can be achieved placing an upper limit on rates of penetration. The rate of penetration for a diamond bit is directly proportional to the speed and torque applied, unlike roller-cone bits, diamond bits do not require a substantial downward force acting on them since they work by shearing, not crushing the rock. Down-hole motors have the potential to deliver many fold more power to the bit allowing substantially increased rates of penetration. Clearly, a far superior method is called for and this method is none other than the down-hole motor. But down-hole motors are nothing new, they form the core of modern horizontal drilling technology in the form of positive displacement “mud motors” which drives drill bits all over the U.S. shale play. Another method is the old turbodrill, widely used in Russia and discussed further in this text. But what all these methods have in common is a strict temperature threshold that cannot be crossed or rapid degradation will occur. A new paradigm is needed, one in which the surrounding rock temperature no longer limits the depth that can be drilled, a new method in which the temperature inside the borehole is but a fraction of the surrounding rock temperature. This method is called Active-Borehole Cooling using High Volume Water. Such a scheme is possible due to the low thermal conductivity and slow thermal diffusivity of rock. There is insufficient thermal energy in the rock to raise the temperature of this high volume of water provided the heat is removed at the surface using a heat exchanger. Christophe Pochari Engineeering appears to be the first to propose using very high-flow volume water to prevent the temperature of the down-hole equipment from reaching the temperature of the surrounding rock, no existing literature makes any mention of such a scheme, serving as an endorsement of its novelty.
Impetus for adoption
There is currently tremendous interest in exploiting the vast untapped potential that is geothermal energy, and a number of companies are responding by offering entirely new alternatives in an attempt to replace the conventional rotary bit using exotic methods including plasma, microwaves, and some have even proposed firing concrete projectiles from a cannon! The greatest inventions and innovations in history shared one thing in common, they were elegant and simple solutions that appeared “obvious” in hindsight. There is no need whatsoever to get bogged down with exotic, unproven, complicated, and failure-prone alternative methods when existing technologies can be easily optimized. Conventional drilling technology employs a solid shaft spun at the surface using a “Kelly bushing” to transmit torque to the drill bit. This has remained practically unchanged since the early days of the oil industry in the early 20th century. While turbo drills have enjoyed widespread use, especially in Russia for close to a century, they have a number of limitations. Russia developed turbodrills because the quality of Russian steel at the time was so poor that drill pipes driven from the surface would snap under the applied torque. Russia could not import higher quality Western steel and thus was forced to invent a solution. Early Russian turbodrills wore out rapidly and went through bits much faster than their American shaft-driven counterparts due to the higher rotational speeds of the turbine even with reduction gearing. Diamond bits did not exist at the time and low-quality carbide bits, principally tungsten carbide and roller cones, were used. Bearings would break down as early as 10-12 hours of operation. Reduction gearboxes, essential for a turbodrill to work due to the excessive RPM of the turbine wheels, wore out rapidly due to the loss in viscosity from the high down-hole temperature. The principal challenge of deep rock drilling lies not in the hardness of the rock per se, as diamond bits are still much harder and can shear even the hardest igneous rocks effectively. Existing diamond bits are several orders of magnitude harder than quartz, feldspar, pyroxene, and amphibole, and newer forms of binder-less bits are even more so. From a physics standpoint, it seems absurd to argue that drill bits are not already extremely effective. Rather, the challenge lies in preventing thermal damage to the down-hole components. If only a small flow of drilling fluid is pumped as is presently done, flowing just enough fluid to carry cuttings to the surface, the latent thermal energy in the radius surrounding the well is sufficient to raise the temperature of this fluid, especially a lower heat capacity oil, to the mean temperature along that particular well. For example, in existing small-diameter wells drilled, especially deeper boreholes, are usually around 9-10” or 250mm in diameter. If the well is too much narrower than 350mm in diameter, it is difficult to flow enough water to cool it. Assuming a 100-hour thermal diffusion time, we draw a 1.26-meter radius of rock, that is in a hundred hours, heat moves this distance. By growing the diameter of the well from 250mm to 460mm, the ratio of cross-sectional area which is proportional to the available flow rate at a constant pressure drop, drops from 125 cubic meters of rock per m2 of cross-sectional area to less than 42 cubic meters of rock per m2 of cross-sectional area, or around 3 times less. Flow rates in previous deep drilling projects were usually less than 500 GPM or around 110 m3/hr. The German deep drilling program had mud flow rates of between 250 and 400 GPM (81 m3/hr) for well diameters of 20 cm and 22.2 cm. The average thermal flux from the well is around 70 MWh-t so the water is rapidly warmed to the surrounding well temperature. The minimum flow rate to warm the water to no more than 180°C is around 400 cubic meters, far too high to be flowed in such a small annulus, especially if the drilling mud is viscous and the drill pipe takes up much of the space leaving only a small annulus. The volume of rock cooled per 100 hours is 6.8 cubic meters or 18,000 kg. If this mass of rock is cooled by 300°C, the thermal energy is 1,280 kWh, or a cooling duty of 12.8 kW/m of well-bore length. Since water has a heat capacity of 3850 J/kg-K at the average temperature and pressure of the well, 1800 cubic meters of water, a flow rate achievable with 600 bar of head in a 460mm diameter well, results in a cooling duty of 343,000 kWh or 34.3 kWh/m of wellbore length. Clearly, our well will not produce 350 MWt, equal to a small nuclear reactor, otherwise we would be drilling millions of holes and getting virtually free energy forever! But since drilling occurs over a relatively long period of close to 1500 hours, the thermal draw-down radius is 4.87 meters, or a rock volume of 81.7 cubic meters. The thermal energy in this rock mass is 15,400 kWh or only 10.26 kW/m of cooling duty at a temperature drop of 240°C. But such a large temperature drop is entirely unrealistic, since a 12 km deep well will have an average rock temperature of only 210°C, so a temperature drop of only say 100°C is needed, resulting in a cooling duty of 4.3 kW/m or 6300 kWh/m over 1500 hours. This means a 12 km well will produce 51.6 MWt of heat resulting in a water temperature of only 27°C. If a 12 km well is drilled in a geothermal gradient of 35°C /km, the maximum temperature reached will be 420°C and the average temperature will be 210°C This means in the last 3.5 km, the temperature will be above 300°C, which is far too hot for electronics, lubricants, bearings, and motors to operate reliably without accepting a severe reduction in longevity. Geothermal wells, unlike petroleum and gas wells, must penetrate substantially below the shallow sedimentary layer and for effective energy recovery, rock temperatures over 400°C are desired. As the temperature of the well reaches 300-400°C, the alloys used in constructing the drill equipment, even high-strength beta titanium, begin to degrade, lose strength, become supple, warp, and fail from stress corrosion cracking when chlorides and other corrosive substances contact the metallic surfaces. It can thus be said that proper thermal management represents the crucial exigency that must be satisfied in order for the upper crust to be tapped by human technology. Christophe Pochari Engineeering‘ Active-Cooled Electro-Drill (ACED) methodology employs the following processes and components to achieve low down-hole temperatures. A number of technologies are concatenated to make this methodology possible.
#1: High volume/pressure water cooling using large diameter beta-titanium drill pipes:
Using high strength beta-titanium drill pipes to deliver 600 bar+ water at over 1700 cubic meters per hour, a cooling duty of up to 400 megawatts can be reached if the temperature of the water coolant is allowed by 180°C. The rock mass around the 450mm diameter well is insufficient to come close to heating this mass of water by this magnitude and an expected 60-80 MW of thermal energy will be delivered to the surface in the first 1500 hours of drilling. The drill string incorporates a number of novel features. Being constructed out of ultra-high strength titanium, it is able to reach depths of 12 km without shearing off under its own weight. It is also designed with an integrated conductor and abrasion liner. The integrated conductor is wrapped around the drill pipe between a layer of insulation and the out-most abrasion liner.
#2: High Power density down-hole electric machines:
A high-speed synchronous motor using high-temperature permanent magnets and mica-silica coated winding generates 780-1200 kW at 15-25,000 rpm. Owing to the high speed of the motor, it is highly compact and can easily fit into the drill string within a hermetic high-strength steel container to protect it from shock and abrasive and corrosive fluids. The motor is cooled by passing fresh water through sealed flow paths in the winding. Compared to the very limited power of Russian electro-drills in the 1940s to 1970s, the modern electro-drill designer has access to state-of-the-art high-power-density electrical machines.
#3 High Speed Planetary Reduction Gearbox:
The brilliance of the high volume active cooling strategy is the ability to use a conventional gear-set to reduce the speed of the high power density motor to the 300-800 RPM ideal for the diamond bit. Using high-viscosity gear oils with 30 CSt at 180°C, sufficient film thickness can be maintained and gearbox life of up to 1000 hours can be guaranteed.
#4: Silicon Thyristors and Nano-Crystalline Iron Transformer Cores:
Silicon thyristors are widely used in the HVDC sector and can be commercially procured for less than 3¢/kW.
The maximum voltage of electrical machines is limited by winding density constraints due to corona discharge, requiring thick insulation and reducing coil packing density. For satisfactory operation and convenient design, a voltage much over 400 is not desirable. The problem then becomes, how to deliver up to 1 MW of electrical power over 10 km? With low voltage, this is next to impossible. If a voltage of 400 is used, the current would be a prohibitive 2500 amps, instantly melting any copper conductor. As any power engineer knows, in order to minimize conductor size and losses, a high operating voltage is necessary, 5,000 or more volts. To deliver 1000 kW or 1340 hp to the drill bit, with a 15mm copper wire at 100°C, the average resistance is 0.8 Ohms, resulting in a Joule heating of 22 kWh, or 2.2% of the total power. To deliver current to the motor, DC is generated at 6-10 kV, this DC is then inverted to 100-150 kHz to minimize core size and the voltage is reduced to the 400 required by the motor. This high-frequency low voltage power is then rectified back into DC to change the frequency back to 1000 Hz for the high-speed synchronous motor. Silicon thyristors can operate at up to 150°C in oxidizing atmospheres (thermal stability is substantially improved in reducing or inert atmospheres). Nano-crystalline iron cores have a Curie temperature of 560°C, well above the maximum water temperature encountered with 1700 m3/hr flow rates.
Rock hardness is not the limiting factor
Feldspar, the most common mineral in the crust, has a Vickers hardness of 710 or 6.9 Gpa. Diamond in the binderless polycrystalline form has a hardness of between 90-150 GPa, or 35 times greater. Diamond has a theoretical wear rate of 10^-9 mm3/Nm. Where cubic millimeters represent volume losses per unit of force applied (Newtons) over a given travel distance. We can thus easily calculate the life of the bit using the specific wear rate constant. Unfortunately, it is more complex than this, and bit degradation is usually mediated by spalling, chipping, and breakage. Due to the extrusion of the cobalt from the diamond, the poly-crystalline diamond degrades faster than otherwise predicted by its hardness alone. This means the wear rate is extremely slow unless excessive temperature and shock are present. Archard’s equation states that wear rates are proportional to the load and hardness differential. In light of this thermal constraint, it might seem obvious to any engineer to exploit the low thermal conductivity of rock and simply use coolant, of which water is optimal, to flush heat out of the rock and back to the surface. But in conventional oil and gas drilling, a very heavy viscous drilling mud is employed, this mud is difficult to pump and places stringent requirements on compression equipment. Elaborate filtration systems are required and cooling this mud with a heat exchanger would lead to severe erosion of the heat exchanger tubes. The principal reason why “active” cooling of the well bore is not presently an established process is the fact that there is no present application where such a scheme would be justified. For example, in order to cool a 450mm diameter 10 km borehole that would flux close to 70000 kWh of thermal energy in the first 1200 hours, a pumping power of up to 32,000 hp is required. The average power costs would therefore be close to $1.5 million per well assuming a wholesale power cost of $70/MWh. The added cost of site equipment, including heat exchangers, a larger compressor array, multiple gas turbines, and the necessary fuel delivery to drive the gas turbines make this strategy entirely prohibitive for conventional oil and gas exploration. Even if this could be tolerated, the sub-200°C temperatures encountered could not possibly justify such a setup. What’s more, pumping such a massive amount of water requires a larger diameter drill pipe that can handle the pressure difference at the surface. Since the total pressure drop down the pipe and up the annulus is close to 600 bar across 10 km, the pipe must withstand this pressure without bulging, compressing the water coming up the annulus thus canceling the differential pressure and stopping the flow. High-strength beta-titanium alloys using vanadium, tantalum, molybdenum, and niobium are required since they must not only withstand the great pressure at the surface, but also carry their own mass. Due to its low density (4.7 g/cm3), beta-titanium represents the ideal alloy choice. With its excellent corrosion resistance and high ductility, few materials can surpass titanium. AMT Advanced Materials Technology GmbH markets a titanium alloy called “Ti-SB20 Beta” with high ductility that can reach ultimate tensile strengths of over 1500 MPa. For conventional oil and gas drilling to only a few km deep, the weight of the drill with the buoyancy of heavy drilling mud allows the use of low-strength steels with a yield strength of less than 500 MPa. This high-end titanium would be vacuum melted and the drill pipes forged or even machined from solid round bar stock. The cost of the drill piper set alone would be $5 million or more for the titanium alone, and several additional millions for machining. In addition, titanium has poor wear and abrasion resistance and tends to gall so it cannot be used where it is subject to rubbing against the rock surface. Because an electro-drill does not spin the drill pipe within the well, the only abrasion would be caused by the low concentration of rock fragments in the water and by the sliding action of the pipe if it is not kept perfectly straight, which is next to impossible. To prevent damage to the titanium drill pipe, a liner of manganese steel or chromium can be mechanically adhered to the exterior of the drill pipe and replaced when needed. Another reason that high-volume water cooling of the drilling wells is not done is due to the issue of lost circulation and fracturing of the rock. In the first few kilometers, the soft sedimentary rock is very porous and would allow much of the water pumped to leak into pore spaces resulting in excessive lost circulation. Since a high volume of water requires a pressure surplus at the surface, the water is as much as 250 bar above the background hydrostatic pressure, allowing it to displace liquids in the formation. Fortunately, the high-pressure water does not contact the initial sedimentary later since this pressure is only needed when the well is quite deep and by the time the water flows up the annulus to contact the sedimentary formation, it has lost most of its pressure already. The initial 500-600 bar water is piped through the drill pipe and exits at the spray nozzles around the drill bit. In short, a number of reasons have combined to make such a strategy unattractive for oil and gas drilling. Sedimentary rocks such as shale, sandstone, dolomite, and limestone can be very vugular (a cavity inside a rock), this can cause losses of drilling fluid of up to 500 bbl/hr (80 cubic meters per hour. A lost circulation of 250 bbl/hr is considered severe and rates as high as 500 bbl/hr are rarely encountered. With water-based drilling, the cost is not a great concern since no expensive weighting agents such as barite or bentonite are used, nor are any viscosifing agents such as xanthan gum. Little can be done to prevent lost circulation other than using a closed annulus or drilling and casing simultaneously, but both methods add more cost than simply replacing the lost water. Water has no cost (infinitely available) besides its transport and pumping cost. If 80 cubic meters are lost per hour, an additional 1200 kW is used for compression. The depth of the water table in the Western U.S. (where geothermal gradients are attractive) is about 80 meters. In Central Nevada for example where groundwater is not by any means abundant, the average precipitation is 290 mm, or 290,000 cubic meters per square kilometer. Multiple wells could be drilled to the 80-meter water table with pumps and water purification systems installed to provide onsite water delivery to minimize transport costs. Water consumption for drilling a deep well using active cooling pales in comparison to agriculture or many other water-intensive industries such as paint and coating manufacturing, alkali and chlorine production, and paperboard production. If water has to be physically transported to the site via road transport if well drilling proves impossible for whatever reason, a large tanker trailer with a capacity of 45 cubic meters which is allowed on U.S roads with 8 axles can be used. If the distance between the water pickup site and the drill site is 100 km, which is reasonable, then the transport cost assuming driver wage of $25/hr and fuel costs of $3.7/gal (avg diesel price in the U.S in December 2022), would total of $150 each way to transport 45 cubic meters, or less than $4 per cubic meter or around $320/hr. The total cost of replacing the lost circulation at the most extreme loss rates encountered is thus $450,000 for a 10 km well drilled at a rate of 7 meters per hour.
Summary
The drilling technology landscape is ripe for dramatic disruption as new forms of more durable and thermally stable metal-free materials reach the market. But this upcoming disruption in drilling technology is not what many expect. Rather than exotic entirely new drilling technologies such as laser beams or plasma bits, improvements in conventional bit material fabrication and down-hole power delivery present the real innovation potential. Improvements in power delivery and active well cooling allow engineers to supersede the bulky turbodrill into obsolescence. Investors in this arena should be cautious and conservative, as the old adage “tried and true” appears apt in this case. Binder-less polycrystalline diamond has been successfully synthesized at pressures of 16 GPa and temperatures of 2300°C by Saudi Aramco researchers. Conventional metallic bonded poly-crystalline diamond bits begin to rapidly degrade at temperatures over 350°C due to the thermal expansion of the cobalt binder exceeding that of diamond. Attempts have been made to remove the metallic binder by leaching but this usually results in a brittle diamond prone to breaking off during operation. Binderless diamond shows wear resistance around 4 fold higher than binder formulations and thermal stability in oxidizing atmospheres up to 1000°C. The imminent commercialization of this diamond material does not bode well for alternative drilling technologies, namely those that propose using thermal energy or other exotic means to drill or excavate rock. If and when these higher performance longer lasting bits reach maturity, it is likely most efforts at developing alternative technologies will be abandoned outright. In light of this news, it would be unwise to invest large sums of money into highly unproven “bitless” technologies and instead focus efforts on developing thermally tolerant down-hole technologies and or employing active cooling strategies. It is therefore possible to say that there is virtually no potential to significantly alter or improve the core rock-cutting technology. The only innovation left is therefore isolated to the drilling assembly, such as the rig, drill string, fluid, casing strategy, and pumping equipment, but not the actual mechanics of the rock cutting face itself. Conventional cobalt binder diamond bits can drill at 5 meters per hour, using air as a fluid the speed increases to 7.6 meters per hour. Considering most proposed alternatives cannot drill much over 10 meters per hour and non have been proven, it seems difficult to justify their development in light of new diamond bits that are predicted to last four times longer, which in theory would allow at least a doubling in drilling speeds holding wear rates constant. A slew of alternative drilling technologies has been chronicled by William Maurer in the book “Novel Drilling Techniques”. To date, the only attempts to develop these alternative methods have ended in spectacular failure. For example, in 2009 Bob Potter, the inventor of hot dry geothermal, founded a company to drill using hot high-pressure water (hydrothermal spallation). As of 2022, the company appears to be out of business. Another company, Foro Energy, has been attempting to use commercial fiber lasers, widely used in metal cutting, to drill rock, but little speaks for its practicality. The physics speaks for itself, as a 10-micron thick layer of water will absorb 63% of the energy of a CO2 laser. No one could possibly argue the limit of human imagination is the reason for our putative inability to drill cost-effective deep wells. Maurer lists a total of 24 proposed methods over the past 60 years. The list includes Abrasive Jet Drills, Cavitating Jet Drills, Electric Arc and Plasma Drills, Electron Beam Drills, Electric Disintegration Drills, Explosive Drills, High-Pressure Jet Drills, High-Pressure Jet Assisted Mechanical Drills, High-Pressure Jet Borehole Mining, Implosion Drills, REAM Drills, Replaceable Cutterhead Drills, Rocket Exhaust Drills, Spark Drills, Stratapax Bits, Subterrene Drills, Terra-Drill, Thermal-Mechanical Drills, and Thermocorer Drill. This quite extensive list does not include “nuclear drills” proposed during the 1960s. Prior to the discovery of binder-less diamond bits, the author believed that among the alternatives proposed, explosive drills might be the simplest and most conducive to improvement, since they had been successfully field-tested. What most of these exotic alternatives claim to offer (at least their proponents!), are faster drilling rates. But upon scrutiny, they do not live up to this promise. For example, Quaise, a company attempting to commercialize the idea of Paul Waskov to use high-frequency radiation to heat rock to its vaporization point, claims to be able to drill at 10 meters per hour. But this number is nothing spectacular considering conventional binder poly-crystalline diamond bits from the 1980s could drill as fast as 7 meters per hour in crystalline rock using air. (Deep Drilling in Crystalline Bedrock Volume 2: Review of Deep Drilling Projects, Technology, Sciences and Prospects for the Future, Anders Bodén, K. Gösta Eriksson). Drilling with lasers, microwaves, or any other thermal delivery mechanism, is well within the capacities of modern technology, but it offers no compelling advantage to impel adoption. Most of these thermal drilling options require dry holes since water vapor will absorb most of the energy from electromagnetic radiation since water vapor is a dipole molecular. While new binderless polycrystalline diamonds can withstand temperatures up to 1200°C in non-oxidizing atmospheres, down-bore drivetrain components are not practically operated over 250°C due to lubricant limitations, preventing drilling from taking place with down-hole equipment at depths above 7 km, especially in sharp geothermal gradients of over 35°C/km. Electric motors using glass or mica-insulated windings and high Curie temperature magnets such as Permendur can maintain high flux density well over 500°C, but gearbox lubrication issues make such a motor useless. In order to maximize the potential of binder-less diamond bits, a down-hole drive train is called for to eliminate drill pipe oscillation and friction and to allow optimal speed and power. Of all the down-hole drive options, a high-frequency high power density electric motor is ideal, possessing far higher power density than classic turbodrills and offering active speed and torque modulation. Even if a classic Russian turbodrill is employed, a reduction gear set is still required. Russian turbodrills were plagued by rapid wear of planetary gearsets due to low oil viscosity at downhole temperatures. A gearset operating with oil of 3 Cst wears ten times faster than one at 9 Cst. In order to make a high-power electric motor fit in the limited space in the drill pipe, a high operating speed is necessary. This is where the lubrication challenges become exceedingly difficult. While solid lubricants and advanced coatings in combination with ultra-hard materials can allow bearings to operate entirely dry for thousands of hours, non-gear reduction drives are immature and largely unproven for continuous heavy-duty use. The power density of a synchronous electric motor is proportional to the flux density of the magnet, pole count, and rotational speed. This requires a suitable reduction drive system to be incorporated into the drill. Although a number of exotic untested concepts exist, such as traction drives, pneumatic motors, high-temperature hydraulic pumps, dry lubricated gears etc, none enjoy any degree of operational success and exit only as low TRL R&D efforts. Deep rock drilling requires mature technology that can be rapidly commercialized with today’s technology, it cannot hinge upon future advancements which have no guarantee of occurring. Among speed-reducing technologies, involute tooth gears are the only practical reduction drive option widely used in the most demanding applications such as helicopters and turbofan engines. But because of the high Hertzian contact stress generates by meshing gears, it is paramount that the viscosity of the oil does not fall much below 10 centipoises, in order to maintain a sufficient film thickness on the gear face, preventing rapid wear that would necessitate the frequent pull up of the down-hole components. Fortunately, ultra-high viscosity gear oils are manufactured that can operate up to 200°C. Mobil SHC 6080 possesses a dynamic viscosity of 370 Cst at 100°C, the Andrade equation predicts a viscosity of 39 at 180°C. In an anoxic environment, the chemical stability of mineral oils is very high, close to 350°C, but at such temperatures, viscosity drops below the film-thickness threshold, so viscosity, not thermal stability is the singular consideration. It is expected that by eliminating the oscillation of the drill pipe caused by eccentric rotation within the larger borehole and removing the cobalt binder, diamond bits could last up to 100 hours or more. This number is conjectural and more conservative bit life numbers should be used for performance and financial analysis. It is therefore critical that the major down-hole drive train components last as long as the bits so as to not deplete their immense potential. If bit life is increased to 100 hours, the lost time due to pull-out is reduced markedly. With a bit life of 50 hours to be conservative, and a drill-pipe length of 30 meters, pull-up and reinsertion time is reduced to only 544 hours, or 40% of the total drilling time. If the depth of the well is 10,000 meters, the average depth is 5000 meters, the average penetration rate is 7 m/hr, and the drill pipe is 30 meters, then the number of drill pipe sections is 333. During each retrieval, if the turn-around time can be kept to 3 minutes, the total time is 8.3 hours per retrieval one way, or 16.6 hours for a complete bit-swap. If the total drilling time is 1430 hours, then a total of 29-bit swaps will be required, taking up 481 hours, or 33% of the total drilling time. If bit life is improved to 100 hours, downtime is halved to 240 hours or 17%. If a drill-pipe length of 45 meters is employed with a bit life of 100 hours and a rate of penetration of 7 m/hr, the downtime is only 211 hours or 14.7%.
Some may be suspicious that something as simple as this proposed idea has not been attempted before. It is important to realize that presently, there does not exist any rationale for its use. Therefore, we can conclude that rather than fundamental technical problems or concerns regarding its feasibility, a lack of relevant demand can account for its purported novelty. As mentioned earlier, this new strategy has not been employed in drilling before since it imposes excessive demands on surface equipment, namely the need for close to 16000 hp (32,000 hp at full depth) to drive high-pressure water pumps. Such power consumption is impractical for oil and gas drilling where quick assembly and disassembly of equipment is demanded in order to increase drilling throughput. Water, even with its low viscosity, requires a lot of energy to flow up and down this very long flow path. The vast majority of the sedimentary deposits where hydrocarbons were laid down during the Carboniferous period occur in the first 3 km of the crust. The temperatures at these depths correspond to less than 100°C, which is not close to a temperature that warrants advanced cooling techniques. Deep drilling in crystalline bedrock does not prove valuable for hydrocarbon exploration since subduction rarely brings valuable gas and liquid hydrocarbons deeper than a few km. There has therefore been a very weak impetus for the adoption of advanced technologies related to high-temperature drilling. Geothermal energy presently represents a minuscule commercial contribution, and to this date, has proven to be an insufficient commercial incentive to bring to market the necessary technical and operational advances needed to viably drill past 10 km in crystalline bedrock. Cooling is essential for more than just the reduction gearbox lubricant. If pressure transducers, thermocouples, and other sensor technology is desired, one cannot operate hotter than the maximum temperature of integrated circuit silicon electronics. For example, a very effective way to reduce Ohmic losses is by increasing the voltage to keep the current to a minimum. This can easily be done by rectifying high-voltage DC using silicon-controlled diodes (SCR or thyristors) and nano-crystalline transformer cores. But both gearbox oil and thyristors cannot operate at more than 150°C, cooling thus emerges as the enabling factor behind any attempt to drill deep into the crust of the earth, regardless of how exactly the rock is drilled. Incidentally, the low thermal conductivity and heat capacity of the crust yield a low thermal diffusivity, or thermal inertia. Rock is a very poor conductor of heat, in fact, rock (silicates) can be considered insulators, and similar oxides are used as refractory bricks to block heat from conducting in smelting furnaces. The metamorphic rock in the continental crust has a thermal conductivity of only 2.1 W-mK and a heat capacity of under 1100 J/kg-K at 220°C, translating into a very slow thermal diffusivity of 1.1 mm2/s, corresponding to the average temperature of a 12 km deep well. This makes it more than feasible for the operator to pump a high volume of water through the drill pipe and annulus above and beyond the requirement for cutting removal. If rock had an order of magnitude faster thermal diffusivity, such a scheme would be impossible as the speed in which heat travels through the rock would exceed even the most aggressive flow rates allowable through the bore-hole. The motivation behind the use of down-hole electric motors. With satisfactory cooling, electric motors are the most convenient method to deliver power, but they are not the only high-power density option. A turbo-pump (a gas turbine without a compressor) burning hydrogen and oxygen is also an interesting option, requiring only a small hose to deliver the gaseous fuel products which eliminate the need for any down-hole voltage conversion and rectification equipment. But despite the superior power density of a combustion power plant, the need to pump high-pressure flammable gases presents a safety concern at the rig, since each time a new drill string must be coupled, the high-pressure gas lines have to be closed off and purged. In contrast, an electric conductor can simply be de-energized during each coupling without any mechanical action at the drill pipe interface, protecting workers at the site from electric shock. In conclusion, even though a turbo-pump using hydrogen and oxygen is a viable contender to electric motors, complexity and safety issues arising from pumping high-pressure flammable gases rule out this option unless serious technical issues are encountered in the operation down-hole electric motors, which are not anticipated. Conventional turbodrills require large numbers of turbine stages to generate a significant amount of power, this results in a substantial portion of the fluid pumped from the surface being used up by the turbine stages, resulting in considerable pressure drop, which reduces the cooling potential of the water since there is now less head to overcome viscous drag along the rough borehole on the way up the annulus. According to Inglis, T. A. (1987) in Directional Drilling, A 889 hp turbodrill experiences a pressure drop of 200 bar with a flow rate of 163 m3/hr, since the large diameter drill-bit requires at least 1000 kW (1350 hp), the total pressure drop will be 303 bar, or half the initial driving head. This will halve the available flow rate and thus the cooling duty.
Electric motors confer to the operator the ability to perform live and active bit speed and torque modulation, while turbodrills cannot be efficiently operated below their optimal speed band. Moreover, even if turbodrills could be designed to operate efficiently at part load, it is not practical to vary the pumping output at the surface to control the turbodrill’s output. And even if turbodrills were used, they would still need to employ our novel active-cooling strategy since they too need speed reduction. It should be emphasized that it is not the use of down-hole motors themselves that makes our drilling concept viable, but rather the massive water flow that keeps everything cool. In hard crystalline bedrock, well-bore collapse generally does not occur, rather a phenomenon called “borehole breakout” occurs. Breakout is caused by a stress concentration produced at the root of two opposing compression domes forming a crack at the point of stress concentration between these two opposing “domes”. Once this crack forms, it stabilizes and the stress concentration is relieved growing only very slowly over time. Imagine the borehole is divided into two parts, each half forms a dome opposite to one other, there is a maximum of compressive stress at the crest of each dome, while there is a minimum of compressive stress at the root or bottom of each dome, this causes the roots of each dome to elongate and fracture. Overburden pressure is an unavoidable problem in deep drilling. Overburden pressure is caused by the sharp divergence between the hydrostatic pressure of rock which experiences a gradient of 26 MPa/km and that of water, which only experiences 10 MPa/km. Technical challenges. It’s important to separate technical problems from operational problems. For example, regardless of what kind of drill one uses, there is always the issue of the hole collapsing in soft formations and equipment getting stuck. Another example would be lost circulation, such a condition is largely technology invariant, short of extreme options such as casing drilling. Operational challenges While there are no strict “disadvantages”, namely features that make it inferior to current surface-driven shaft drills, there are undoubtedly a number of unique operational challenges. Compared to the companies touting highly unproven and outright dubious concepts, this method and technological package faces only operational, not technical challenges. The massive flow of water and the intense removal of heat from the rock will result in more intense than normal fracture propagation in the borehole. The usual issues that pertain to extreme drilling environments apply equally to this technology and are not necessarily made any graver than with conventional shaft-driven drills. For example, the down-hole motor and equipment getting stuck, a sudden unintended blockage of water flow somewhere along the annulus that results in rapid heating, or a snapping of the drill string, are likely to happen occasionally especially in unstable formations, or in regions where over-pressurized fluids are stored in the rock. Another potential downside is intense erosion of the rock surface due to the high annulus velocity of over 8 meters per second. Since a large volume of water must be pumped, a large head is required of at least 600 bar. This pressure energy is converted into velocity energy according to Bernoulli’s principle. Because the concentration of fragments in the water is extremely low (<0.06% vs over 2% in drilling mud), the rate of erosion on the hardened drill pipe liner is not a concern. It is likely that the relatively short period of time where drilling is actually taking place, around 2000 hours including bit replacement and pull up every 50 hours, it is unlikely this water will have time to significantly erode away the well-bore. Even if it does, it will merely enlarge the well diameter, and is not expected to significantly compromise its structural integrity.
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christophepocharienergietechnik.com 