Session 4C: Reservoir/Production

Enhanced Geothermal Systems (EGS) represent cutting-edge technologies designed to harness clean energy from the Earth's crust. However, the presence of short-circuits in certain geothermal reservoirs poses a significant threat to their sustained viability as reliable sources of clean energy. This issue arises when cold fluids injected into the reservoirs quickly traverse fractures with large apertures or directly communicate between injection and production wells without acquiring sufficient heat from the rock matrix. Effective control of flow dynamics outside the wellbore and within the reservoir is crucial to mitigate undesirable flow patterns.
Polymer gels, proven successful in managing preferential flow in oil and gas reservoirs, could be adapted for controlling flow in geothermal reservoirs. Nonetheless, the absence of hydrogel products capable of withstanding the harsh conditions of geothermal reservoirs (>150 °C) for extended periods has been a limiting factor. In response, funded by the US Department of Energy, our recent efforts have led to the development of innovative high-temperature resistant preformed particle gels (HT-PPG) specifically designed for this purpose.
This study provides a comprehensive overview of our research advancements, encompassing the creation of a series of innovative particle gel products. We explore their swelling behavior, rheology, thermal stability, and plugging efficiency to fractures, highlighting their applicability in geothermal contexts, even under elevated temperatures. These products are adaptable for reservoirs with preferential fluid flow paths which have temperatures ranging from 20 to 225 °C (the reservoir could have higher temperature), and can be customized with controllable sizes ranging from micrometers to a few millimeters. Our developed products feature controllable swelling times and demonstrate commendable long-term hydrolytic thermal stability, maintaining their effectiveness for over three months. Additionally, we have designed a micromodel to observe the swelling kinetics and transport mechanisms of a representative particle gel. Furthermore, we employ numerical simulation to model particle gel injection and assess blocking performance.
In summary, the HT-PPG developed in this work emerges as a reliable solution for controlling preferential fluid flow in geothermal reservoirs, addressing a critical challenge in the quest for sustainable and efficient geothermal energy extraction.

Fully coupled high resolution dynamic modeling of the subsurface is required to optimize geothermal field producibility while ensuring planned operations do not give rise to geohazards. In geothermal settings, understanding the thermo-hydro-mechanical behavior of natural and induced fracture networks is essential to assess the enhancement capacity of target reservoirs. The associated simulation of microseismic locations, magnitudes, and mechanisms is critical for evaluating stimulation success and the risk of induced seismicity.

A Discrete Fracture Network (DFN) hydrostructural approach that incorporates the geometry and properties of discrete features is dynamically calibrated against available reservoir hydrological tests to provide the central component controlling flow and transport through the reservoir. Enhancing the geothermal system through hydroshearing/hydraulic fracturing is simulated by Dynamic Fracture Modeling (DFM) through the natural fracture network. The DFM was carried out using numerical software XSite, which uses the lattice approach to implement the synthetic rock mass (SRM) method for simulation of hydraulic fracturing in naturally fractured rock masses. Fully coupled thermo-hydro-mechanical simulation is conducted in the model that explicitly represents pre-existing fractures and reservoir stimulation is combination of hydraulic fracture propagation and opening or shear of pre-existing joints (i.e., hydro-shearing). The DFN and DFM derived fracture permeability distribution was then used in dynamic fluid modeling to explore well engineering scenarios for optimal production.

This study presents the full link between subsurface characterization with dynamic modeling of natural and induced fracture networks for a geothermal exploration site in Zambia to provide a high resolution base for reservoir dynamic flow modeling. Results of this full-physics approach reveal the main drivers toward project success.

Understanding and characterizing the connectivity through the induced fractured network created between injection and production wells in an Enhanced Geothermal System (EGS) is imperative to maximize enthalpy output from the system. The high temperature sets special requirements for tracer stability, and the high injection rates set requirements for the tracers’ detectability.

In this paper we will present data from a field test with extensive utilization of advanced tracer technology to gain as much understanding as possible from an enhanced geothermal system. Unique tracers were injected during each of 8 stages of fracturing in an EGS well. In addition, several tracers were injected at different times during the fracturing of one of the stages. Tracer responses were established from samples collected during clean-up. Responses from the individual zonal tracer and tracers injected at different times during the individual stage were analyzed and interpreted. After initial clean-up, and fracturing of the production well, the injection well was put into operation and a circulation tracer was added to the injected water. Sampling from the production well was then initiated. Fracture Driven Interaction (FDI) analysis was carried out on the basis of the tracer data, and the fracture communication between individual perforations and fracture networks to the production well was characterized based on the tracer results. Tracer curve analysis based on the multiple tracers injected into one particular fracturing stage was used to further enhance understanding of the fracture network complexity created in the individual stages. Residence time distribution (RTD) analysis and mass balance calculations were used to assess the different stages and characterize the volume created by the induced fracture network.

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There have been many experimental studies on thermoelectric generators (TEG) for generating electricity using geothermal energy and waste heat from various industries in recent years. TEG power output has been measured at different flow rates of water, different temperatures, and other different conditions. However, there have been few large-scale field tests at geothermal wells and industry sited. Considering these experimental measurements and field test results, some questions arise. Are there any relationships among the TEG power outputs measured in laboratory and pilot test sites at different temperatures? Can we predict the power output at the field tests (larger scale) using the experimental results with a single TEG module? Does TEG have any advantages in terms of cost compared to solar PV (photovoltaic) panels? To answer the above questions, we have collected and analyzed the experimental and field test data of the TEG power output at different temperatures and temperature differential (TD). The power output data include those of single TEG module, TEG devices with 6, 10 and 20 layers (the highest number of layers reported) respectively. The 10- and 20-layer TEG devices were tested for power generation using the industrial waste heat from a gas power plant at a temperature of about 80 °C. The field test of the 6-layer TEG device was conducted at a geothermal field with higher temperatures up to 170 °C. The data analysis demonstrates that the TEG power outputs measured in laboratory and pilot test sites at different temperatures are closely consistent. An equation coupling TEG power outputs and TD has been established. We may predict the power output for large-scale field applications using the experimental results with a single TEG chip at different TD. The cost of TEG is lower than solar PV (photovoltaic) panels when TD is greater than about 80 °C.

Global demand continues to grow for a clean and renewable energy source for electricity generation. Geothermal power has the potential to contribute significantly to the global energy mix. However, most of geothermal wells produce below their potential because of the scales deposited around wellbore tubulars or the formation damage that occurs because of drilling fluid invasion, silica plugging, scales deposition in the natural fractures, and fines migration. To restore productivity from geothermal wells, it is often necessary to perform matrix acid stimulation. However, acid treatment fluids under the extremely high temperature environment of geothermal wells are very corrosive to the wellbore tubulars/downhole equipment and spends near-wellbore. This paper presents the next generation acid system that utilizes environmentally friendly non-corrosive fluids to generate acid in-situ in the formation for geothermal matrix stimulation.

The non-corrosive deep-penetrating acid is a neutral, non-reactive treatment fluid at the surface and only when it is injected in the formation, it generates acid at a controlled rate in situ under temperature and time. The in-situ generation of acid at a controlled rate allows for safe transport of the acid from the surface to the formation without exposing wellbore tubulars to an acidic fluid and also allows for deep penetration to dissolve deposited materials or scales in the porous formation or along the fractures. A series of solubility testing in HPHT reactor at temperatures above 450°F was first conducted to understand the chemical reactions that generate the acid as a function of temperature, concentration of acid generating components, and time, and to identify the optimum composition that maximize the dissolving of silica and calcite minerals. Coreflow testing was then conducted at 300°F and 475°F using 1.5” in diameter and 6” in diameter Berea sandstone cores to evaluate the penetration of the acid and its capability to provide remarkable permeability improvement.

This paper presents case studies on the application of the new fluid technology for matrix acid stimulation of geothermal wells in Indonesia. The present study explains how the use of the new fluid technology unlocks the full production potential of these wells and helped to eliminate the need for acid tanks on site, reduced transportation difficulties and logistics, and eliminated HSE concerns associated with acids handling on geothermal sites.

Understanding sedimentary rocks' mineralogy, petrophysical properties, and thermal behavior is crucial for the effective characterization of geothermal reservoirs. In this study, we investigate the relationship between textural properties, mineralogy, petrophysical properties, and thermal behavior of 30 core samples of sedimentary rocks using scanning electron microscopy (SEM).

The study reveals that well-sorted rocks exhibit superior porosity, permeability, thermal conductivity, diffusivity, and higher quartz content among the samples analyzed. Improved grain sorting enhances the interconnected pore network, facilitating fluid flow and heat transfer within the geothermal reservoir. Moreover, the higher quartz content in well-sorted rocks enhances thermal conductivity and diffusivity. The results provide valuable insights for reservoir characterization and geothermal resource assessment, emphasizing the significance of grain sorting as a controlling factor in the porosity, permeability, and thermal properties of reservoir rocks. Incorporating textural analysis into geothermal reservoir models can improve resource assessments and aid in site selection for geothermal projects.

This study contributes to geothermal energy exploration by highlighting the importance of textural analysis in understanding the geothermal behavior of sedimentary rocks. The findings offer practical implications for enhancing the accuracy of geothermal reservoir models, optimizing resource utilization, and promoting the development of sustainable geothermal energy.