Well control considerations for a global geothermal industry

MOHAMED AMER and ANDREW BARRY, Wild Well Control, and JULMAR SHAUN S. TORALDE and ROBBIE L. DARBY, Weatherford 

Geothermal formations are comprised of reservoirs of hot water that naturally occur—or are man-made—at varying temperatures and depths below the earth's surface. Publications from the U.S. Department of Energy’s Geothermal Technologies Office provide the classifications that follow. Naturally occurring geothermal formations (with heat, water and permeability) that have been developed historically for heating and electricity generation purposes are usually classified as the hydrothermal type, but there are other types, such as geopressured-geothermal systems, which contain water with somewhat elevated temperatures and with pressures well above hydrostatic for their depth, as well as magmatic systems, with temperatures ranging from 600°C to 1,400°C.  

Man-made geothermal systems usually target Hot Dry Rock (HDR) geothermal resources, with ideal temperatures from 200°C to 350°C, and these are usually referred to as enhanced geothermal systems (EGS), advanced geothermal systems (AGS) or advanced closed loop (ACL), depending on the technologies being used to develop the resource. Rock types are typically granite, granodiorite, quartzite, greywacke, basalt or volcanic tuffs, but geothermal reservoirs in sedimentary rock types are also possible. 

Because geothermal formations are usually under-pressured (where pore pressure is less than fluid pressure in a full wellbore), influx into the wellbore is rare. Geothermal well control considerations primarily stem from these two causes of loss of control: 

• An unexpectedly hot formation is encountered at a shallow depth, where the annulus pressure is insufficient to keep the drilling fluid or formation fluid from flashing to steam. 
• Lost circulation causes the fluid level and the pressure in the wellbore to suddenly fall far enough for the same thing to happen. 

If complete control is not lost, simply pumping cold water into the wellbore can usually kill the well. And if well control is lost, geothermal kick and potential outflows at the wellhead are controlled using blowout prevention equipment (BOPE; Fig. 1), just like in oil and gas drilling settings. 

Fig. 1. Examples of well control and blowout prevention equipment (BOPE).

Compared to the sedimentary formations of most oil/gas reservoirs, hydrothermal geothermal formations typically: 

• Are hot (production intervals from 160°C to above 300°C) 
• Are often hard (240+ MPa compressive strength) and abrasive (quartz content above 50%) 
• Are highly fractured (fracture apertures of centimeters) 
• Are under-pressured 
• Often contain corrosive fluids 
• Have some formation fluids with very high solids content. 

Fundamental differences between petroleum and geothermal environment systems lie in reservoir and fluid temperatures, rock permeability and pressure and the heterogeneity of the rock-forming systems. Experts have cautioned that the generalization of well control methods and blowout preventer (BOP; Fig. 2) designs between petroleum and geothermal can be dangerous because generally, well control methods and equipment in the petroleum industry are designed to anticipate pressure, while geothermal operations are likely to face a well control situation that is influenced by temperature. Also, the availability of a continuous supply of cold water, the ability and reliability of the pump on the rig and an adequate BOP temperature rating are the main factors that must be considered. 

Fig. 2. Selection of different types and sizes of blowout preventers (BOP).

Experts also have warned that though pressures in geothermal drilling are almost always lower than those encountered in oil and gas drilling, the key to control is having adequate casing setting depths, which will permit shutting the well, if a kick is detected in the early stages. Unexpected steam flow in a permeable formation that is not completely sealed by casing is particularly dangerous, because steam can begin to flow up the outside of the previous casing string (“underground blowout”) and eventually destroy the casing’s integrity, often causing loss of the drilling rig. 

Geothermal well blowouts pose a significant financial and reputational risk to companies exploring for, or developing, geothermal energy resources. Though most well control case studies come from historical geothermal development projects involving hydrothermal resources, the risks involved, and lessons learned, will have a high degree of applicability to the new technologies being tested or piloted. These technologies involve enhanced and advanced geothermal systems (EGS/AGS/ACL) that are receiving a lot of recent attention from the global energy community. 

Adaptations that might be required from a well control standpoint, to accommodate these new geothermal technologies and methods that have the potential to bring geothermal anywhere and everywhere, are presented in the section following the case studies. 

GEOTHERMAL WELL CONTROL INCIDENTS AND STATISTICS 

With the rapidly evolving and expanding geothermal energy industry’s future in mind, a review of publicly available well control-related information, publication and events in the geothermal projects was performed. It provides a foundation for determining current and future well control risks and blowout contingency requirements of the geothermal industry. 

So, in terms of risk, how do geothermal energy systems compare to other energy sources and what is the level of risk involved with well blowouts? A paper titled, “Comparative accident risk assessment with focus on deep geothermal energy systems in the Organization for Economic Cooperation and Development (OECD) countries,” provides several insights on the matter. The paper concludes that the drilling and stimulation phases of deep geothermal energy development are considered the riskier phases, due to the potential for blowouts or release of drilling muds and stimulation fluids during these operations.  

In both the stimulation phase and drilling phase of geothermal operations, blowouts are among the highest risks. This is related to the fact that if a blowout happens, the effect can be catastrophic, not only for the deep geothermal project itself but also for the workers in the area. It is interesting to note that risk of blowouts in the drilling phase is higher, compared to the stimulation phase; this could possibly be due to the fact that during a stimulation phase, the bore should have been stabilized in terms of pressures, while during the drilling phase, kicks could still happen in an unpredictable way, leading to an increased risk. 

It is interesting to note that the study also developed and compared deep geothermal cases (best and worst) against fossil, hydrogen and selected renewable technologies, in terms of expected accident risk. The lowest fatality rate (i.e., expected risk) was found for the deep geothermal energy best case. The deep geothermal energy worst case is similar to wind offshore and performs better than the fossil, hydrogen, hydropower and biogas energy chains. In contrast—in terms of extreme accident risk—maximum consequences (i.e., extreme risk) for both deep geothermal energy scenarios were similarly low, compared to other renewables, implying that they are substantially less prone to high-consequence events than fossil, hydrogen, and hydropower energy chains. 

Going further into the details of geothermal well blowout incidents and risks, Table 1 lists by country and approximate year the instances of the same available in published literature and in the worldwide web, using the search terms “blowout” or “well control” in the publication title or in the Internet or A.I. Chatbot search query. 

WELL CONTROL CONSIDERATIONS FOR A GLOBAL GEOTHERMAL INDUSTRY 

Several factors should be taken into consideration: the lessons of the various geothermal well control incidents that have been documented; the increasing geological and geographical distribution of geothermal projects; the introduction of new well architectures and advanced drilling technologies; and the drive towards hotter supercritical geothermal reservoirs to achieve greater global energy contribution and scale. In light of these, an assessment of the well control and blowout contingency considerations unique to the geothermal industry was done. Some of its findings are provided below. 

Hydrothermal: BOPE for mining drilling equipment used geothermal drilling operations. All drilling operations inside the geothermal environment, including mining drilling, have approximately similar risks on the well control side. Well control equipment is normally not required in mineral/mining drilling exploration, but for some mineral coring operations that intersect a geothermal area, high temperatures from water, steam and/or gases could be encountered during the drilling operation. Those who have previously used mining methods for geothermal drilling stipulate that to safely conduct drilling, the use of well control equipment for mineral or mining drilling operations in geothermal areas needs to be considered and for the application of the geothermal well control to mining drilling operations, the mining well schematic should be modified. 

Hydrothermal: Kick detection and temperature management. “The Sandia Handbook of Best Practices for Geothermal Drilling” mentions that better methods for inflow and returns metering are available, and if well control is expected to be an issue, these methods should be investigated. Other indicators of impending flow from the well are the influx of gas, rapid rise in the temperature of returning fluids and rapid drilling encountered—particularly if associated with a loss of returns. Technologies for early kick detection and inflow and returns flow and temperature measurement have already been partly deployed in geothermal settings through managed pressure drilling (MPD) methods. 

Enhanced and advanced geothermal systems/closed loop: BOPE for big-bore wells. Deeper and hotter plays come with requirements for bigger wellbores, to be able to increase the commercial viability of geothermal development projects. Well architectures associated with new geothermal technologies increasingly require larger BOP equipment to deliver the volumes of steam required while drilling fewer wells for their projects. However, BOP systems currently available—mostly geared towards oil and gas applications—do not usually go as large as those that are required by the geothermal big-bore designs (17 ½ in or larger). This could possibly put a constraint on implementing future EGS/AGS/ACL projects because of the very limited number of larger BOP systems available, unless more of these BOP systems are manufactured by BOP systems providers. 

Oil and gas well conversion to geothermal: Well control considerations for both environments. Geothermal fields in which hydrocarbon resources are also found require that well control procedures and equipment must be capable of handing the somewhat different characteristics of both drilling environments. With the advent of “geothermal everywhere,” and initiatives to be able to convert legacy oil and gas assets into geothermal systems—especially in existing petroleum basins—it is important that both the geothermal and oil and gas aspects of well control be properly taken into consideration when planning operations in these hybrid environments. 

Supercritical geothermal systems: BOPE elastomer seals good for 260°C. Detailed local regulatory requirements for the BOPE in geothermal applications are usually available, but experts reveal that the critical factors to consider involve making sure that the BOP pressure rating is adequate and that all the elastomer seals in the equipment are qualified for high temperature. Most BOPE are dressed with normal-temperature rubbers, which have a working temperature limit of 121°C, because of the high cost and limited availability of high-temperature BOP rubbers.  

Dressing the BOPs with high temperature rubbers may not provide adequate safety, as they have a working temperature limit of 177°C, and even these higher temperatures can be exceeded, as pressures increase when circulating out a high-temperature kick. For this reason, some geothermal operations deploy a cooling line below the pipe rams, to pump cool water down through the inside of the BOP and out the choke line during a kill operation, if the temperature might exceed the working temperature of the BOPE.  

Research on the high temperature capability of elastomeric sealing elements used in ram type blowout preventers has been undertaken that requires that they must be capable of operating in steam and brine up to 500°F (260°C). Typical well drilling equipment used for oil and gas drilling is designed to operate up to 250°F and under special conditions up to 350°F. 

CONCLUSION 

The incident case studies and considerations for future development highlight that geothermal well control can be a complex topic, but these considerations are clearly critical to a successful geothermal drilling operation, so a holistic approach to well control should be adopted. As such, well control engineering, procedures and risk management should be part of well planning, so that the proper casing design is developed during the planning stage. Careful planning, modeling and execution of geothermal projects should also comprise a robust well control contingency plan.  

Sound engineering, multi-disciplinary engineering design and analysis will ensure a successful outcome. It is essential that proper well control preparations are established and that crews are familiar with them when drilling begins. That way, rig crews can be trained to react quickly and appropriately to an unexpected event that might jeopardize the well. 

Given the rapidly increasing volume of geothermal wells being drilled globally—both of the natural and man-made reservoir types—as well as the intention of geothermal operating companies to drill larger, deeper and hotter wells to improve the commercial viability of geothermal energy, it is important that the industry be made aware of the potential catastrophic impact of a major geothermal blowout and mitigate against or prepare for it. Failure to do so might squander the immense gains of the global renaissance that the resurgent and expanding geothermal industry is experiencing. 

ACKNOWLEDGMENT 

This article is based on a poster/paper that was presented during Geothermal Rising 2024 in Waikoloa, Hawaii, U.S.A., with the title “Well control considerations for a global geothermal industry: A historical review and an assessment of current and future requirements.” The paper and its complete list of references are available in GRC Transactions, Vol. 48, 2024, pages 411-425.  

ABOUT THE AUTHORS

Mohamed Amer is general manager for Well Control Engineering at Wild Well Control, responsible for the delivery of day-to-day well control projects, which covers planning, intervention and operations phases. He has more than 20 years of experience working on numerous complex and high-profile blowouts, relief wells, and intersection P&A projects worldwide. Mr. Amer holds a bachelor’s degree in petroleum engineering from Cairo University and a master’s degree in energy and petroleum engineering from Texas A&M University. 

Andrew Barry has more than 42 years of experience in oil and gas, the last decade of which has been at Wild Well Control. He has held positions spanning from field service operations, global account management, and global product line management to senior management roles. `Mr. Barry’s global experience in drilling, completions and production operations provides a broad spectrum of understanding of the oil and gas and energy transition markets. He is a member of the IADC Geothermal Committee, IADC DEC Committee, SPE and AADE. 

Julmar Shaun S. Toralde graduated magna cum laude and was one of the pioneering graduates of the Geothermal Engineering program of Negros Oriental State University, Philippines, where he earned a bachelor’s degree. He is the Global Segment leader for Geothermal at Weatherford International, based in Houston, Texas. He has produced multiple international patents, technical papers/trade articles and training courses on advanced drilling and energy development technologies. He is currently vice-chair of the IADC Geothermal Committee. 

Robbie L. Darby is a subject matter expert with more than 20 years of hands-on and field experience in well control and blowout prevention equipment and operations. He is currently serving as United States Technical Manager for Drilling Rental Tools and Pressure Control Equipment, of Weatherford, based in Houston, Texas.