Techno-Economic Investigation of Geothermal Development in Sedimentary Basins

Despite being one of the sustainable sources of energy, the consumption of geothermal energy has been only 0.24% of the total energy consumption with petroleum and natural gas comprising the 68% of total consumption according to the US Energy Information Agency (Fig. 1) [1]. The Western United States has emerged as the leading producer of geothermal energy (Fig. 2), owing to its abundance of conventional geothermal resources close to the surface and supportive policy framework [1]. Geothermal energy systems are primarily classified into three categories: direct-use and district heating systems, geothermal heat pumps, and geothermal power plants [2]. The rare distribution of naturally occurring hydrothermal reservoirs is one of the commonly mentioned reasons for significantly small numbers in geothermal energy production [3], whereas investigations of earth geothermal potential demonstrated that numerous amounts of energy are stored at reachable depths ranging up to 10 km/32,808 ft [2]. Based on the distribution of sedimentary basins in the United States illustrated in Fig. 3 [4], a considerable amount of thermal energy is stored in sedimentary rocks that have been explored for decades. According to Tester et al. [2], the recoverable thermal energy potential of the US is around 5.6 × 10⁶ EJ with more than 100,000 EJ of it being stored in sedimentary rocks. To put it into perspective, the annual energy consumption of the US has been 92.97 EJ in 2021 which means the existing recoverable geothermal energy has the potential to meet the energy demands of the US for more than 1000 years (Fig. 4).

The recent increasing trend in oil prices, the exploration cost of hydrocarbons, the importance of energy security in countries’ economy, and movement toward the net-zero energy production for a sustainable future has attracted attention to geothermal energy and multiple projects are planned to demonstrate the potential of geothermal energy to provide baseload power of the US. To achieve that efficiency, the development of top-notch drilling technology and advanced geothermal fluid production system is required, as well as the exploration of geothermal resources.

Through this work, the authors analyzed the drilling and completion time of 1,074,266 wells drilled from 1990 to 2022 at different locations in the US that are mainly impacted by changes in the geological parameters of the formations drilled. Also, the total well cost was derived using different correlations that consider total well depth, well complexity index, and well construction time. As a result, the time-to-hit temperature (THT) and cost-to-hit temperature (CHT) maps are plotted for the US. Finally, THT and CHT maps are combined with the subsurface temperature maps to generate the geothermal drilling favorability map for the US to pinpoint the best locations for enhanced geothermal systems (EGS) development in sedimentary basins.

The type of geothermal systems that can be developed in sedimentary basins are changing depending on the purpose, availability of the subsurface temperature, proximity to the end user, technology, and power plant development cost [5]. Some of the promising options are the installation of heat pumps at shallower depths for areal heating and cooling, the application of closed-loop systems or enhanced geothermal systems by repurposing idle oil and gas wells for direct heat or electricity generation, and the development of EGS in deep to super-deep hot reservoirs for electricity generation [6]. The total amount of energy production increases from heat pumps to super-hot EGS applications along with an increasing cost of installation [7].

To carry out a thorough techno-economic investigation, every aspect of the geothermal energy system development must be considered [8]. The process typically starts with the drilling of injection and production wells where upon successful completion, cold working fluid would be pumped to the hot geothermal reservoir through injectors and hot steam would be extracted through production wells to surface heat transfer and power generation units [9]. Although a significant amount of investment is required to build the power plant and grid systems, the economic feasibility of the geothermal projects is strongly dependent on the drilling expenditures and successful field exploration. According to Blankenship et al. [10], the overall well drilling and completion cost roughly comprises 30–60% of the total cost of hydrothermal power plant development which is prone to increasing remarkably in the case of super-hot EGS well drilling in igneous rocks primarily due to harsher conditions.

Vivas et al. [11] analyzed the technical challenges of EGS development in super-hot basins, and Salehi et al. [12] considered several advantages of geothermal energy systems application in sedimentary basins. Because of the higher cost-share and risk associated with geothermal projects, extensive emphasis is needed to be put on the economic analysis of the drilling process, especially the drilling time and well cost.

Geothermal drilling has undergone several analyses from various aspects in the past. [10,13,14] focused on the need for the technology developments while [2,15,16] investigated the drilling and completion of enhanced geothermal wells. In 2010, the US Department of Energy reported the summary of the research programs with great impacts on geothermal drilling, logging, and completion technology, as well as well design and well cost models.

Although it is approximated that more than 4000 geothermal wells have been drilled and 3200 of them are currently active wells [17], the cost of the drilling and completion have rarely been disclosed due to the confidential nature of the data. Also, the number of geothermal wells drilled in different geological settings is insufficient to confidently derive a statistical trendline to approximate the well cost considering the risks and uncertainties. However, the well drilling and construction processes of hydrocarbon and geothermal wells (see the cost breakdown in Fig. 5) in sedimentary basins are very similar which enables to derive a relationship between measured depth (MD) and cost of the well for hydrocarbon wells and apply it to the geothermal drilling operations.

This equation only uses the MD as input and does not account for the geologic complexity, well deviation, and any other factors affecting the well cost. Yost et al. [19] took the next step to consider the uncertainty in the cost calculation of EGS wells by modeling the time and cost of each major step and operation in drilling and completion. Lukawski et al. [20] incorporated the uncertainty model into the geothermal well cost equation by using probabilistic methods to estimate the distribution of well costs for a range of well depths that considers the contribution of individual cost categories for an EGS well given in Fig. 5.

Monte Carlo simulation of the cost of geothermal wells drilled from 2009 to 2013 showed that probability distributions for the shallower wells are more peaked and less wide while it is the opposite for the deeper wells (Fig. 8), meaning the deeper wells are rare and it is difficult to predict the well cost because of unexpected geological complications and more frequent failures [20].

Palmer et al. [21] carried out a similar study to determine the favorable locations for the development of geothermal energy systems in Northeastern British Columbia, Canada by creating a favorability map that took geological and economic criteria into account with 50% weight factor each. Geologic criteria represented the existence of potential reservoirs with adequate temperatures and economic criteria included the availability of electrical infrastructure and distance to the end user.

Blackwell et al. [22] published the underground temperature map of the US in seven vertical depths (from 3.5 km/11,483 ft to 10 km/32,808 ft) using over 35,000 data sites (Fig. 9). The variables considered in the analysis are the thermal conductance of the rocks, the heat flow of the area, and the rock density. The main data requirement for assessing non-conventional geothermal resources on a regional to sub-regional scale is provided by these temperature models. In comparison with the sedimentary basins, the highest temperatures are mostly distributed in the basaltic igneous basins while some sedimentary basins with high temperatures are attractive enough for EGS development.

A recent work by SMU [23] has suggested that these temperature maps have some degree of error, particularly in certain counties such as Webb County, Crockett County, and Jackson County where the newly assessed temperatures are on average 25–50 °C higher than previous studies.

The objective of the study is to create THT, CHT, and favorability maps for the US to visually demonstrate where the geologic and economic factors overlap to generate favorable conditions for the development of EGS systems. A summary of the methodology is illustrated in Fig. 10. The workflow consists of three main parts:

• Digitization of temperatures from Blackwell et al. [22] temperature maps;

• Analysis of the drilling and completion time of oil and gas wells drilled for the last two decades and derivation of trendlines;

• Estimation of well drilling and completion cost at different fields in the US.

The methods were investigated to extract the temperature data from Blackwell et al. [22] and matlab code was developed to extract the color codes from temperature maps. The color codes were converted to temperatures at 3.5, 4.5, 5.5, 6.5, 7.5, 8.5, and 10 km/32,808 ft, and temperature-depth gradients were derived for each county individually to find temperatures at any given depth. Using the temperature-depth equation, the depth of 100 °C, 150 °C, 200 °C, 250 °C, and 300 °C temperatures was calculated. The depth values calculated for different temperatures were inputted into the geothermal well cost equation to derive the CHT.

The drilling and completion time data of the wells that are drilled in 26 US states from 2000 to 2022 were cleaned from outliers using statistical methods. The depth-time cross-plots of the states showed huge scattering, and therefore identification of a precise trendline to correlate drilling and completion time with total measured depth was hardly possible. For the existing 26 states, linear and exponential trendline equations were derived and data were averaged for the counties. The exponential trendline equations yield extremely high values for depths more than 23,000 ft (7 km) depth. Thus, the linear trendline equation was used to extrapolate and predict the drilling and completion time for the pseudo wells for the depth extracted from subsurface temperature maps, and the resulting THT values were plotted.

Favorability maps are derived from the weighted average of well drilling and completion time, cost, and subsurface temperature with 30%, 30%, and 40% factors accordingly. The data are normalized to the scale from 1—least favorable to 10—most favorable.

As a result of the analysis, seven different THT, CHT, and favorability maps were plotted from 3.5 km/11,483 ft to 10 km/32,808 ft. For THT maps, the drilling and completion time increases from 10 days to 180 days. In CHT maps, well costs increase from 5 mln US$ or less to 50 mln US$ or more. Unlike the CHT and THT, the favorability map compares only the different targets given at the specific depth as given in the map heading, with the highest favorability score of 10 and the lowest score of 1. Figures 11–17 illustrate the THT and CHT maps in depth from 3.5 km/11,483 ft to 10 km/32,808 ft. Favorability maps have been provided in Figs. 18–21.

Although drilling deeper wells might take longer time and cost more, the investment on return will be higher in the long term because of increasing geothermal energy with increasing depth. South to south-east TX and south LA, are some of the most favorable locations for deep EGS applications with relatively faster and cheaper drilling operations and temperatures up to 275 °C at 7.5 km/24,606 ft. North-east MT and western ND are other examples of favorable targets with reasonably high geothermal energy potential, 225 °C at around 7 km/22,966 ft. Central to western CO and eastern UT are also prime candidates for EGS thanks to significantly higher temperatures of more than 300 °C starting from 7 km/22,966 ft in sedimentary formations.

Further analysis of the drilling and completion time data is essential. The data reported to the enverus platform are skewed toward a higher limit of time data since in some wells, the completion operations were not carried out right after the drilling operation ends because of the availability of the stimulation services. Also, completion operations were put on hold in some wells during a significant oil price drop in 2015. Thus, extensive research is required to integrate uncertainty generated by the source of data.

Predicting well drilling and completion time and cost for deeper wells is a complex and challenging task due to several limitations. One of the primary limitations is the difficulty of accurately predicting the subsurface geology and rock properties. Deeper wells often encounter more challenging geological formations, which can lead to unexpected delays and increased costs. Additionally, drilling deeper wells requires more advanced and specialized equipment, which can be more expensive to operate and maintain. Another limitation is the unpredictable nature of the drilling process itself. Drilling conditions can change rapidly and unexpectedly, such as encountering unexpected obstacles or having to change drilling techniques to accommodate unexpected geologic features. These factors can make it challenging to accurately predict drilling and completion time and cost, particularly for deeper wells. Further investigation of the challenges related to geological variability and considering thermal conductivity/heat flow equations as a variable would improve the techno-economic understanding of the geothermal projects.

In general, deep sedimentary formation and high-temperature gradients are two features that many sedimentary oil and gas basins in the US possess. Sedimentary formations allow faster and cheaper with more conventional drilling operations and the existence of the high temperatures makes those formations desirable for deep EGS applications. As a result of the improved drilling technologies, the increasing rate of well cost with depth has reduced and rate-of-penetration values increased over time. The cost of the well completion is another important variable. High-permeability sedimentary basins could have good productivity with less costly completion techniques than non-sedimentary basin geologies. The combination of the drilling and completion time, well cost, and subsurface temperatures highlighted areas of enormous geothermal energy potential such as in TX, LA, CO, MT, and ND. Further study of the subsurface pressures, geologic settings, and cost of the necessary infrastructure is required to build an economic model to demonstrate the feasibility of the concept.

Primary authors would like to thank Dr. Saeed Salehi (University of Oklahoma) for continuous supervision throughout the project, Dr. Runar Nygard (University of Oklahoma) for sharing data sources and providing proper feedback on data analysis, and Danny Rehg (Criterion Energy Partners) for providing industry insights and making sure the results are relevant and applicable.

• This study was supported by funding from the United States Department of Energy (DOE) under Award Number DE-EE0009962. The opinions, findings, conclusions, or recommendations presented in this publication are solely those of the authors and do not necessarily represent the views or opinions of the United States Department of Energy (DOE).

There are no conflicts of interest. This article does not include research in which human participants were involved. Informed consent not applicable. This article does not include any research in which animal participants were involved.

The data and information that support the findings of this article are freely available¹.

CHT =

cost-to-hit temperature, million US$

MD =

measured depth, m

THT =

time-to-hit temperature, days