Analysis and Application of a New Hybrid Drill Bit for Use in Hard Rocks

Harder formations in geothermal and deeper oil and gas wells typically see lower rates of penetration (ROPs) and higher bit wear. Recent drilling experience in the Utah FORGE observed higher ROPs and longer runs using lighter drilling muds and new cutter technologies. Questions have arisen regarding reasons for the improved ROP and if the higher ROP is due to increased spurt loss or reduced hydrostatic pressure from lighter drilling fluids. A study was performed on an inhouse rig using two polycrystalline diamond compact (PDC) bits (4-bladed vs 5-bladed) to analyze the effect of confinement on ROP in Sierra White Granite (SWG). Tests were performed at confinements of 0, 1000, and 2000 psi and at constant rotational speeds of 80 and 150 RPM. Results show that when confinement is increased, ROPs are similar in the ineffective cutting Phase I. However, results in Phase II indicate that ROP is largely different between the unconfined and higher confinement testing. No significant effect on ROP is observed between 1000 and 2000 psi. At zero confinement, the 4-bladed bit outperformed the 5-bladed bit while at 1000 and 2000 psi confinement, the performance was similar. This paper presents the laboratory results with potential applications to hard rock geothermal drilling. INTRODUCTION Confining pressure in drilling terms is the hydrostatic pressure at the bottom of the well while drilling in impermeable formations. Many studies have outlined the effects of confining pressure on rock deformation but the effect of confinement on drilling efficiency and ROP is yet to be thoroughly investigated. In recent years, hard rock drilling especially in geothermal reservoirs has faced great challenges such as low penetration rates and high bit wear leading to high drilling costs. Advanced bit technology is required to maneuver the unique physical and mechanical properties of hard and abrasive rocks at high confining pressures. Although roller cone bits were predominantly used to drill hard and abrasive formations, PDC bits with enhanced cutter properties and ‘special’ cutter geometries are at the forefront of drilling research and technology. During the past years, new PDC cutter technology has improved cutter wear resistance and its capability to carry higher loads. Recent drilling experience in the Utah FORGE observed higher ROPs and longer bit runs using lighter drilling muds and new cutter technologies including shaped cutters (Dupriest and Noynaert, 2022). Glowka, (1985) discussed the potential for developing a PDC drill bit for hard rock applications such as geothermal drilling. Different cutter geometrical shapes and designs are currently being designed to address heavy impact damage in hard formations, prevent thermal damage and extend drilling runs while maximizing ROP. Zhu et al. (2022) analyzed the loading performance and rock cutting mechanism of different PDC cutters by using single cutter analysis to study geometry, aggressiveness, and stress distribution in granite. Xiong et al. (2022) studied the performance of a stinger PDC cutter in granite to evaluate cutting force and mechanical specific energy (MSE). Barnett et al. (2022) studied the effects of drillstring torsional vibration on ROP with PDC bits in hard rock. Wang et al. (2020) designed a PDC hybrid drill bit to navigate hard and abrasive formations. Akhtarmanesh et al. (2021) designed an ROP model for drilling hard and abrasive formations for PDC bits. It was seen that distinct phases of drilling exist where Phase I is the inefficient drilling phase due to insufficient WOB and Phase II is the efficient drilling phase due to higher WOB which results in a higher ROP. Figure 1 shows the different phases of drilling as described by Akhtarmanesh et al. (2021). Due to the complexity of drilling in hard formations, more testing is crucial to completely understand the effects of temperature, rock behavior, and confining pressure on ROP and bit cutting mechanism. An understanding of bit cutting action in hard rock is crucial for successful ROP optimization and improving drilling efficiency.

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Summary. Part 1 (June JPT, Pages 675–84) discussed the characteristics, development, and outlook for polycrystalline diamond compact (PDC) bits. Thissecond part treats applications of PDC bits, including suitable locations, types of hole, and uses. Introduction This paper is intended as a quick reference for operational staff who may beconsidering the application of PDC bits. Unfortunately, these bits cannot yetcope with all formations. Consequently, bit selection is of paramountimportance to avoid misruns, as will be indicated. Suitable Formations PDC bits usually can be used with success only in soft, soft to PDC bitsusually can be used with success only in soft, soft to medium-hard, andmedium-hard, non-abrasive formations. Success, however, is fully dependent on agood match between the bit, the formation to be drilled, and the operatingconditions. (See PDC-Bit Development in Part 1, where performance of thecorrect PDC bits with both oil- and performance of the correct PDC bits withboth oil- and water-based muds is explained.) Experience has shown that, forPDC bits, the type of mud, the bit hydraulics, and bit design PDC bits, thetype of mud, the bit hydraulics, and bit design affect bit performance muchmore than variations in mud properties. Over and over again, it has been foundthat it properties. Over and over again, it has been found that it pays todevelop the best bit design for a particular field rather pays to develop thebest bit design for a particular field rather than to select one from a range.PDC bits can be tailored to the job to provide surprisingly goodperformance. Hard and/or abrasive formations are taboo for PDC bits in that they causeexcessive wear. Streaks of limited extent, lenses, or thin sections of suchrocks within thick sections of a suitable formation can be drilled. It isimperative to consult wireline logs, mud logs, and bit records of neighboringwells. With local expertise at hand, available from bit suppliers and withinthe oil company, it is then decided where to spot the bits, if at all. Refs. 1through 3 and 5 through 15 provide detailed examples of recent case histories. Mudstone and siltstone have been drilled well; sandstones, particularly ifcoarse-grained and cemented, are virtually impossible to drill economically andare highly destructive to the bit. Hard limestone, dolomite, etc., can be cutwith great difficulty. Consult PDC Cutters in Part 1 for an understanding, Sections on TSP Diamond Bits and Hybrid Bits, also in Part 1, provideassistance in seeking alternative bits. Applications PDC bits may play a significant role in a number of drilling PDC bits mayplay a significant role in a number of drilling related applications ashighlighted here. A wealth of referenced literature is available to elaborateon the various aspects. Depleted Reservoirs. Because such reservoirs usually cannot be drilled at areasonable overbalance, the drilling may become extremely slow and costly. Inthe case of roller-cone bits, the common excessive overbalance causes them tocrush the rock to a very thick, dense layer that is hardly removed at all. Diamond bits can often do better because of their plowing action. PDC bitsshave the rock and expose the permeable rock to mud filtration, which can bepromoted by hydraulics to lessen the effective overbalance. Koskie and Appenreport a side benefit of "fishtail" PDC bits in Colombia: their ability todrill depleted sands rapidly at an overbalance of as much as 10 Ibm/gal [1198kg/m3]! Apparently, the sand was not really abrasive and the bit and the mudwere well selected. Others report economically successful runs of TSP diamondbits in depleted sands in south Louisiana. The TSP diamond bit is of limitedversatility; if much shale is encountered, the bit may slow down too much. Deviation Control. PDC bits require only light weight on bit (WOB) to drillrapidly. Because of this feature, the bits have become popular where deviationcontrol is needed, particularly for use in a crooked-hole area. If theformations are suitable for PDC bits, impressive savings can be achieved inthis application. Even less suitable formations, causing accelerated bit wear, can be tolerated to benefit from the PDC bit's favorable characteristic, if thealternative bits performed very poorly. The bit's profile can affect thebuilding or drop of poorly. The bit's profile can affect the building or dropof bottomhole assemblies (BHA, s). Refs. 5 and 17 report local experience. Directional Control. The directional characteristics of PDC bits differpronouncedly, but not unfavorably, from those of roller cone bits. PDC bits, particularly matrix-body bits, have been used to arrest the right-walktendencies experienced with roller-cone bits. JPT P. 817

U.S. Bureau of Mines field test results show that polycrystalline diamond compact bits used for coal-mine roof bolting, can last 200 to 600 times longer than tungsten carbide bits. During these tests it was also noted that the cutting edges of polycrystalline diamond compact bits remained sharp, they did not show any decrease in penetration rate, and it appeared that they generated less airborne dust. During these tests, however, it was not possible to measure the amount of respirable dust generated under controlled conditions. Laboratory tests were subsequently conducted to compare the respirable dust generated by new tungsten carbide and polycrystalline diamond compact bits. These tests were performed using a rotary drill test facility at the Rock Mechanics and Explosives Research Center, University of Missouri at Rolla. Respirable dust, as defined by a lognormal particle penetration curve with 50 percent penetration of 3.5-μm aerodynamic diameter, and a geometric standard deviation of [sgrave]...

When drilling wells for hydrocarbon extraction, completing a specific interval of the well in the fastest time possible is a key requirement. One of the main contributing factors for improved performance is the drill bit. It is well known in the drilling industry that the stress state of the formation around the bit and drilled well is significantly lowered once penetrated by the bit. Conventional single diameter polycrystalline diamond compact (PDC) drill bits are not capable of taking advantage of this reduced effective rock strength. Dual-diameter bits address the identified challenges through the use of elegant physical principles and offer an efficient, reliable means of drilling. The concentric, dual-diameter design lowers the effective rock strength encountered by the critical shoulder-to-gauge area of the bit's cutting structure. The smaller pilot section of the bit design drills a pilot hole, which reduces the confinement and thus strength of the rock drilled by the larger reamer section. The reamer section of the bit is able to utilize the bedded pilot bit for stabilization to offset the greater forces associated with larger diameter drilling. The offset blade configuration of the bits also offers 360-degree contact the borehole and helps deliver a gun barrel hole quality. This paper introduces the development of a unique, two-stage, dual-diameter profile, and polycrystalline diamond compact drill bit for an application in Indonesia. Typically, multiple drill bits are required to finish the section, which consists of abrasive sandstone with some layers of coal. The objective was to improve the drilling performance while also minimizing non-productive time (NPT) for a bit trip. The paper provides and in-depth evaluation of the bit performance over several field trials. The first bit was run in a motor assembly and improved 14% rate of penetration (ROP) with exceptional dull condition. The drilling parameters indicated that the bit generated higher ROP with lower weight on bit (WOB) compared to other bit types. This performance convinced the operator to run the dual-diameter PDC bit in a more challenging field where its remarkable performance achieved field records. In comparison to the closest offset well, dual-diameter drill bits replaced three-bit runs with 56% longer intervals drilled and improved overall ROP by 41%. In addition, rig time was reduced by 5.3 days. The operator was extremely pleased with the bit performance and decided to use a dual-diameter PDC bit as the primary option to drill this section in every field.

Summary As oil and gas exploration progresses to ultradeep and 10 000-m depths, insufficient energy supply during rock breaking by downhole polycrystalline diamond compact (PDC) bits presents a critical challenge. Quantifying the energy consumed in PDC cutter/rock interactions is therefore essential for enhancing bit efficiency and minimizing nonproductive energy losses during drilling. Consequently, for this study, we analyzed and calculated the mechanical work and energy consumption associated with cutter/rock interactions in the rock-cutting process of PDC cutter. First, through indoor single-cutter rock-cutting experiments and methods such as high-speed camera real-time observation and 3D morphology analysis of cuttings, the single-cutter rock-cutting mechanism was revealed, and the pivotal role of the rock crushing zone ahead of the cutter in force transmission during single-cutter cutting was clarified. Based on the rock-cutting mechanism, an improved calculation model for rock-cutting mechanical specific energy (MSE) during single-cutter rock cutting was derived, which comprehensively considered the essential force interactions of PDC cutters. Furthermore, starting from the principle of MSE calculation for full-scale drill bits, the same calculation result was derived, achieving mutual validation between the rock-cutting mechanism and mathematical derivation. Finally, the effectiveness of the improved rock-cutting energy calculation model in evaluating the efficiency of single planar cutters and the rate of penetration (ROP) of full-scale drill bits was verified through indoor single-cutter cutting experiments and full-scale bit rock-breaking experiments using two planar cutter profiles. The findings of this work are of significant reference value for the rational application of PDC bits and technological innovation in ROP improvement.

Ultra-large diameter Polycrystalline Diamond Compact (PDC) bit drilling is a fast growing cost-effective solution in high-tier deepwater drilling operations in the U.S. Gulf of Mexico (GOM) where salt is encountered in the shallow part of the wellbore. Conventional design called for roller cone (RC) (IADC Code 111-115) drill bits on positive displacement motors (PDM) in these ultra-large diameter intervals. Cost savings on drilling fluid alone, in the form of Rate of Penetration (ROP) gains through the salt interval, has the industry trending to drill these riserless sections with the use of PDC drill bits on Rotary Steerable System (RSS) drilling assemblies. New robust high torque capacity top drives, stronger drillpipe connections, larger diameter RSS tools and improved mud programs have all largely contributed to this step change in drilling performance. Additionally, evolved bit and BHA design, efficient operating parameters, improved hydraulics and vibration prediction modeling have all aided in the success of these runs. Although this emerging new trend reduces drilling times and associated cost, experience has shown there are multiple challenges that must be overcome to complete a successful run in a single trip. These challenges vary from well to well and include, but are not limited to: BHA steerability, rig equipment limitations, efficient operating parameters, identification of both sediment and salt formations, hole cleaning and hydraulics, salt creep, drilling fluid displacement, drillpipe torque limitations, stabilization placement, lateral/ torsional BHA vibrations, and others. This paper will concentrate on the multiple aspects of ultra-large diameter riserless PDC bit drilling applications and the considerations that have been used to optimize them. Prior SPE papers and data from previous deepwater GOM case histories were heavily researched and scrutinized to support the conclusions provided within the body of this paper. Together with industry experience available, these findings have resulted in a set of defined recommendations, providing operators with a guide to justify a lower cost per foot approach through the potential reduction of drilling time in these challenging applications.

Experimental study on motion and mechanical characteristics of the vertical wheel in the rock-breaking process

The Khurais project, located in the central part of Saudi Arabia near Riyadh, is the largest project in Saudi Arabia. Comprising drilling and completion of 168 horizontal producer wells at 12,000 ft measured depth (MD) each, one of the success measures of this project revolves around its expeditious completion. With the focus on this objective, a collaborative effort was implemented to analyze and assess the drilling challenges, how best to address them, and to apply the lessons learned throughout the duration of the project. This collaboration included service companies, drilling engineers and rig foremen coupled with an on-site bit design engineer. As a result of this teamwork, improvements were achieved in a short period of time, providing the confidence that the objective will be met. One of the primary objectives was to produce a drill bit that would provide the highest rate of penetration (ROP) possible without compromising steerability. The 12¼-in. hole section of the wells is particularly demanding, with a build section from 0° to 87° through interbedded formations. Achieving a desired buildup rate with good ROP can be negated by a bit that may be too aggressive and that has poor directional control. Through the group effort, the team was able to develop an optimized 12¼-in. polycrystalline diamond compact (PDC) bit that resulted in a ROP increase by over 40% since the project’s onset, in only three months. With the ultimate goal of increasing ROP more than 50%, the new bit design is proving to be a definitive solution. The authors will describe the process and design analyses that were used to develop the PDC bit design for the application, from the collaboration to the use of post-design/parameter analysis after the run. They will also illustrate the importance of post-action reviews of lessons learned to apply the correct operating practices, the desired bottom-hole assembly (BHA), and bit design in the achievement of record ROPs.

This paper details the step by step process undertaken by a dedicated focus group established to provide a solution to inconsistent drilling performance with the 16" section in a deep gas field on the Arabian Peninusular. The paper reviews the analysis undertaken as well as focusing on new design concepts and improved technology introduced. Drilling in these deep gas fields, especially the 16" sections has always been a challenge for Polycrystalline Diamond Compact (PDC) drill bits due to the complex lithology that consists of a variety of carbonates with high interfacial severity, followed by a highly abrasive sandstone and dense dolomite formations. Despite improving the ability to consistently drill the 16" sections in a single run over the past few years, the new challenge is to make further improvements to the consistency while at the same time providing further improvements in rate of penetration. Having experienced inconsistent performance and a series of premature PDC bit failures in these applications over the last few years the vendor assembled an integrated project team to investigate the issue. This team carried out an in depth analysis of all the available field data and identified several factors that were responsible for PDC bit damage, such as bit/BHA whirl, poor operating parameters with their associated vibrations and the limited ability of existing PDC cutters to drill such formations. The findings led to the development of a new PDC bit design solution with high lateral and torsional stability capable of drilling with high drilling efficiency, the introduction of new cutter technology; along with optimised operating parameters. The successful implementation of the new drill bit and recommended drilling parameters has enabled the operator to more consistently drill these challenging 16" sections in a single run at higher ROPs than previously achieved. This has resulted in significant cost saving for the operator.

This paper describes the field experience of a new hybrid bit based on proven polycrystalline diamond compact (PDC) bit designs with rolling cutters on the bit periphery. A hybrid bit can drill shale and other plastically behaving formations up to three or four times faster than a roller-cone bit by being more aggressive and efficient. The penetration rate of a hybrid bit responds linearly to revolutions per minute (RPM) unlike roller-cone bits, which have an exponential response with an exponent of less than one. In other words, the hybrid bit drills significantly faster than a comparable roller-cone bit in motor applications. Another benefit is the effect of the rolling cutters on the bit dynamics. Compared to conventional polycrystalline diamond cutter bits, torsional oscillations are as much as 50% lower; stick/slip is reduced at low RPM, and whirl at high RPM. This gives the hybrid bit a wider operating window and greatly improves toolface control in directional drilling. The hybrid drill bit technology combines roller-cone and PDC bits into a single patented design, employing the best attributes of each bit type to improve reliability and efficiency, while ensuring performance consistency in the most problematic applications. This revolutionary technology has a large spectrum of applications, excelling in typically troublesome formations for PDC and roller-cone bits, such as interbedded hard and soft stringers or hard nodular inclusions. The results of a field test in an inland application will be presented, comparing the performance of hybrid bits with conventional PDC and roller-cone bits used on offset wells. A planning and engineering process was applied, ensuring high-quality support to the operator in the office and at the rigsite. The client saved multiple conventional tungsten carbide insert bit runs and drilled 100% farther, ultimately achieving a rate of penetration (ROP) two times faster than the best tungsten carbide insert (TCI) bit run in the same well.

Summary High-torque, low-speed drilling mud motors are typically used to drive rotary-steerable systems (RSS) to improve the rate of penetration (ROP) of the RSS bottomhole assemblies (BHA). Downhole drilling dysfunctions are common when powered RSS BHAs are pushed to the limit for maximum drilling performance. High-frequency (HF) continuous recording compact drilling dynamics sensors were embedded into the bit, bit box of the RSS, slow-rotating housing (SRH) of the RSS, bit box of the mud motor, and top subassembly (sub) of the mud motor to better understand drilling conditions in different shale plays throughout North America. Embedded sensors placed on the outer diameter of the BHA vs. centerline-mounted sensors give a different measurement response and a different vision of the actual dynamics being experienced in the BHA. The HF sensors were deployed in the in-house developed push-the-bit RSS and mud motors, allowing us to model the motor-assist RSS BHAs with analytical models and finite-element analysis models to predict the HF torsional oscillation (TO) and axial oscillation (AO) frequencies. The derivation of the high-frequency axial oscillation (HFAO) and TO analytical equations is detailed in the paper. In one of the example motor-assist RSS BHA analyses, the simulation results reveal that the fundamental high-frequency torsional oscillation (HFTO) frequency is 11.1 Hz whereas the fundamental HFAO frequency is 32.9 Hz, which is approximately three times higher than the fundamental-mode HFTO frequency. A good correlation was observed between the simulation result and the field data gathered from the HF accelerometer and gyro sensors embedded in the RSS and mud motors. Two new types of HF axial drilling dynamics with a polycrystalline diamond compact (PDC) bit—(1) the third-order-mode HFAO and (2) the harmonics of the HFTO coupled to the longitudinal axis—were discovered and reported in detail. One example in this paper shows that the dominant HFTO frequency shifts occurred in the middle of drilling a stand with no connection involved and no surface parameter changes. The examination of the time-domain signal reveals that (1) the “baseline” HFTO-induced tangential accelerations are due to the mud motor output revolutions per minute (RPM) (2) the variation of the HFTO-induced peak tangential accelerations comes from the drillstring stick/slip, which is transmitted to the drill bit through the mud motor, and (3) the 76 and 114 Hz HFTO-induced accelerations are both approximately in a sinusoidal waveform, except in the 3-second transition period, where the mixture of both frequencies is observed. The 114 Hz-HFTO-induced tangential acceleration measured at the bit box is coupled with the 0.16 Hz drillstring stick/slip oscillation. The analytical equation is provided to describe the HFTO coupled with stick/slip as an analogy to communication theory. In addition, the extensive modeling and field measurement of the HFTO and HFAO lead to the mitigation measure of the harmful HF drilling dynamics in motor-assist RSS BHAs. The proposed HFTO mitigation mechanism is modeled, simulated, and demonstrated in the paper. The latest-generation embedded HF drilling dynamics sensors are placed on the outside diameter of the BHA, as well as along the centerline of the BHA. The different responses of the sensors due to their placement are reported and analyzed. The quality of 1000 Hz continuous-sampled gyro data are discussed, comparing against low-frequency-sampled gyro data. Additionally, this paper shows the downhole HFTO-damping mechanism and lesser known drilling dynamics, such as HFAO with a PDC bit in detail. CORRECTION NOTICE: This paper has been updated from its original version to correct the provenance statement. In addition, the equation numbering on pages 567 and 568 has been corrected from Eqs. 9, 10, and 11 to Eqs. 5, 6, and 7.

A performance model for Polycrystallíne Diamond Compact (PDC) bits has been modified to include the wear prediction of individual cutters. Wear predictions are based on the geometry of each cutter, the rock, type, the forces acting on the cutter, cutter velocity, and cutter temperature. The results of predicted and actual cutter wear for different 8-1/2 in. field worn PDC bit designs are shown. The worn geometry of each cutter was measured and compared to the model's prediction. Laboratory performance tests were also conducted with similar bit designs to quantify the effect of bit imbalance. Reduced ROP, drilling an overgage hole, and increased cutter wear and breakage can be the result of bit imbalance.

Stick-slip vibration analysis of a coupling drilling-rock system with two delays and one delay-dependent coefficient

Geothermal projects will require drilling substantial footages through harder rocks. This is challenging for existing technologies as the abrasive nature of the rock and higher cutting forces required increase the wear rates of drill bits. We have identified a rock weakening process that when used to assist a single Polycrystalline Diamond Compact (PDC) cutter can reduce the force required to drive such a cutter through granite by up to 50% (2mm depth of cut in atmospheric conditions). Integrating this technology into a fixed cutter drill bit has the potential to increase the rate of Penetration (ROP) and reduce the wear rate of PDC cutters when working in hard rock and thus improve drilling economics. Over the last decade or more several alternative "drilling" processes have shown a similar level of promise in early testing and yet worldwide we have seen few of these alternative technologies progressing to higher technology readiness levels (TRL) or commercialization. The reason for this lack of advancement in the drilling of hard rock is that barriers to market entry and commercialization for downhole drilling become apparent once the supporting systems required by these alternative technologies are examined. If the new technology requires specialized drill strings, adaptation or replacement of surface equipment, this raises the cost of getting into field trials by several orders of magnitude and the project quickly goes beyond the capacity of most single organizations. The company the authors work for formed a new project team with the intention of finding a more "plug and play" approach to introducing an alternative drilling system into hard rock drilling for the geothermal market. This approach quickly focused on the concept of assisting the current highly developed fixed cutter drill bits with alternative technology, rather than replacing them outright. If alternative technology could weaken the hard rock, the mechanical cutters could drill faster and further and thus it would improve geothermal project economics and allow faster transition to this clean energy source.

_ The first geothermal power plant powered just a handful of light bulbs. That was more than 120 years ago. Since then, geothermal energy has advanced to become a major player in power generation. “Geothermal is actually a rather unique energy source,” said Henning Bjørvik, head of renewables research at Rystad Energy, during the 2025 Offshore Technology Conference (OTC). “It is a clean and firm source. If you look at solar and wind, these are clean sources, but they are not firm. … I mean, a solar panel basically generates during daylight hours; wind turbines basically generate when you when have wind. So, you always have gaps that you have to deal with.” Hydrocarbon-based energy, he added, is firm but not clean. Geothermal is clean and firm, working regardless of weather conditions, but its development has been hampered by geography and technology. Some parts of the world are blessed with favorable geothermal geology. As of 2025, the Icelandic Energy Authority reported that geothermal energy accounts for 60% of the country’s primary energy consumption. Of course, that’s in Iceland, where the heat and water needed for geothermal energy production is plentiful and near the surface. What about the rest of the world? The US has plentiful subterranean heat (Fig. 1), enough to generate at least 90 GW of geothermal electricity-generating capacity across the US by 2050, according to a US Department of Energy (DOE) analysis. Accessing it, however, is a challenge. Near Milford, Utah, the Frontier Observatory for Research in Geothermal Energy (FORGE) initiative is working on that challenge. The dedicated field site is funded by the DOE and managed by the Energy & Geoscience Institute at The University of Utah. FORGE is focusing on understanding the key mechanisms of enhanced geothermal systems (EGS). EGS uses wellbores to reach the underground heat and fractures to increase surface area for fluids pumped down the wells to collect that heat. Immediately adjacent to the FORGE site, Fervo is working on the multiphase Cape Station geothermal development, which it says could ultimately deliver 500 MW of power. Fervo says Phase I is expected to begin delivering power to the grid this year. Also funded by the DOE, the Geothermal Energy from Oil and Gas Demonstrated Engineering (GEODE) consortium is tackling the challenges of geothermal energy production. GEODE is led by Project InnerSpace and the Society of Petroleum Engineers. Project InnerSpace says on its website that, if drilling for geothermal energy were conducted at the rate it currently is for oil and gas, 77% of global demand for electricity could be met by 2050. Hard Rock Geothermal resources often exist in rock that is difficult to drill, such as hard granitic rock and abrasive volcanic rock. These environments can quickly chew up drill bits. Polycrystalline diamond compact (PDC) bits are often the preferred choice, but research has suggested that these, too, may be at the limits of their abilities. While conventional roller-cone bits degrade rapidly while chewing through hard crystalline granite, at the FORGE site, for instance, PDC bits have demonstrated increased durability and rates of penetration. Researchers are now looking at the geometry of the bits to boost these features.