The influence of complicated fluid-rock interactions on the geothermal exploitation in the CO₂ plume geothermal system

Highlights

• Comprehensive fluid-rock interaction models were built for CPG system study.

• Back and down flow of water complicates fluid-rock interactions near injector.

• Salt precipitation can affect geochemical reaction during geothermal development.

• Geochemical reaction and salt precipitation reduce heat mining rate up to 2/5.

• Low salinity water injection can effectively reduce salt precipitation in CPG.

Abstract

The ubiquitous natural sedimentary reservoirs and their high permeability have made the CO₂ plume geothermal system increasingly attractive. However, the complicated fluid-rock interactions during the geothermal exploitation can cause severe reservoir damage, constraining the excellent heat mining performance of the CO₂ and decreasing the possible applications of the CO₂ plume geothermal system. In order to analyze and solve this energy issue affecting the geothermal exploitation, in this study, a comprehensive numerical simulation model was established, which can consider formation water evaporation, salt precipitation, CO₂-water-rock geochemical reactions, and the changes in reservoir porosity and permeability in the CO₂ plume geothermal (CPG) system. Using this model, the geochemical reactions and salt precipitation and their effects on the geothermal exploitation were analyzed, and some measures were proposed to reduce the influence of fluid-rock interactions on the heat mining rate. The simulation results show that the gravity and the negative gas-liquid capillary pressure gradient induced by evaporation can cause the formation water to flow toward the injector. The back flow of the formation water results in salt precipitation accumulation in the injection well region, which can cause severe reservoir damage and consequent reductions to the heat mining rate. The CO₂-water-rock geochemical reactions could result in the dissolution of certain minerals and precipitation of others, but its minimal influence on the heat mining rate can be ignored. However, salt precipitation can affect the geochemical reactions by influencing the CO₂ flow and distribution, which can reduce the heat mining rate up to 2/5 of the original. Sensitivity studies show that the reservoir condition can affect the salt precipitation and heat mining rate, so a sedimentary reservoir with high temperature, high porosity and permeability, and low salinity should be selected for CPG application, with an appropriately high injection-production pressure difference. The injection of low salinity water before CO₂ injection and the combined injection of CO₂ and water vapor can be applied to reduce the salt precipitation and increase the heat mining rate in the CPG system.

Introduction

Geothermal energy has several advantages, including large reserves, wide distribution, and low carbon emissions and was considered to be one of the promising supplements to fossil energy [1], [2]. The current surveys show that there are more than 14 × 10²⁴ J and 25 × 10²⁴ J of geothermal reserves, respectively, in the U.S. and China [3], [4]. However, the conventional geothermal reservoirs are usually located in the tectonically or volcanologically active regions and have small reservoir volumes, limiting wide developments and the utilization of the geothermal resources [5]. Therefore, some new methods will have to be developed to extract the abundant geothermal energy from the subsurface [6], [7], [8]. Meanwhile, the global warming induced by continuous emissions of greenhouse gases can result in the melting of mountain glaciers and the rise of the sea level [9], [10]. CO₂ is the primary greenhouse gas, and some measures must be taken to control and decrease the CO₂ concentration in the atmosphere [10], [11], [12].

In recent years, with the development of technology [13], [14], [15], [16], some fluids were proposed as the working fluid to exploit geothermal energy [17], [18] and CO₂ was also proposed as a heat transmission fluid this can combine the geothermal exploitation and CO₂ greenhouse gas emission reduction effectively [19], [20], [21], [22], [23], [24], [25], [26], [27]. Compared to water as a conventional heat transmission fluid, CO₂ has many advantages for geothermal exploitation. At normal reservoir conditions, CO₂ will be in its supercritical state of low viscosity, high density, and high heat capacity, which can increase the injectivity and heat mining rate [19], [22], [25]. Meanwhile, due to the large compressibility of CO₂, the temperature difference between injection and production wells can result in a significant thermo-siphon effect, which can be fully utilized to decrease the parasitic power consumption [20], [21], [26].

The concept of using supercritical CO₂ as a heat transmission fluid was first proposed in a geothermal exploitation from Hot Dry Rock by Brown (CO₂-EGS) [19]. Subsequently, Pruess et al. studied the flow characteristics and heat mining rate in the CO₂-EGS in detail [20], [21]. However, the ultra-deep well fracturing used in the CO₂-EGS may cause seismicity, which makes the economic benefits and reservoir sealing uncertain. To solve these questions, Randolph et al. proposed a concept of using CO₂ to exploit the geothermal from a natural high-permeability reservoir that is overlain by a low-permeability cap rock and this concept is called CO₂-plume geothermal (CPG) system [22]. Natural high-temperature reservoirs are ubiquitous throughout the world and have larger pore volumes than the tight hot dry rocks [28], which means more CO₂ can be sequestrated [29] and more geothermal can be exploited. Also, the CPG system can reduce or eliminate the need for complex and expensive hydraulic fracturing that is typically required in the EGS system [22], [23], [27]. These advantages make the CPG system attract more and more attention all over the world [30], [31].

However, there are still some issues with using CO₂ to exploit geothermal energy. Compared with the CO₂-EGS, more formation water is initially stored in the natural high-permeability reservoirs, which means there is a period for water production before CO₂ production in the CPG system. Some literature has indicated that the production of formation water can decrease the heat mining rate because of the high viscosity of the water [23], [25]. Moreover, the formation water will react with the injected CO₂ and then change the reservoir porosity and permeability [32], [33], which can affect the exploitation of geothermal energy. Usually, three distinct zones can form and develop with the continuous CO₂ injection during geothermal exploitation [19], [32]: a single phase of dry CO₂, two phases of CO₂-water mixture, and a single phase of water with some dissolved CO₂. The injected CO₂ and the water will chemically react with the rock minerals in the zones of the two-phase CO₂-water mixture and the single-phase water with dissolved CO₂, which results in mineral changes. Whereas in the zone of the two-phase CO₂-water mixture, the formation water, especially the irreducible water, will evaporate into the CO₂ phase and then increase the dissolved Na⁺ and Cl⁻ concentration; this can result in salt precipitation and damage the reservoir [32], [34]. Meanwhile, the development of the three zones can affect the geochemical reactions and salt precipitation, which complicates the geochemical reactions and salt precipitation and may intensify their influence on the heat mining rate.

Studies on CO₂ storage in conventional aquifers and sedimentary formations have demonstrated that the chemical equilibrium in the formation water can be broken after CO₂ injection, which can result in different geochemical reactions involving mineral dissolution and precipitation [10], [35], [36], [37], [38]. Moreover, high reservoir temperature in the CPG system can accelerate the reaction rate and induce simultaneous changes to the reservoir porosity and permeability, which can significantly affect the heat mining rate [32], [39], [40]. Some researchers have performed the CO₂-formation water-rock geochemical reactions. Ueda et al. conducted laboratory experiments in a CO₂-water-rock system, which indicated that the presence of CO₂ could promote the dissolution of plagioclase and anorthite minerals and the precipitation of carbonate substances [40]. Wan et al. proposed a two-dimension reactive transport simulation model to study the geochemical reactions in a CO₂-water-rock system and assessed their impact on fluid flow [41]. Xu et al. studied the influence of CO₂-water-rock interactions on the heat mining rate through a two-dimension reactive transport simulation model in a CPG system [32]. All of these studies showed that the CO₂-water-rock geochemical reactions could change the reservoir porosity and a certain amount of CO₂ can be trapped or stored in the products of mineral reactions.

For the salt precipitation, some experiments and simulation research has been conducted. The core flooding experiments indicated that the CO₂ injection could result in salt precipitation, which can lead to low permeability and decrease the CO₂ injectivity [42], [43], [44], [45]. Further, some CT scans revealed that a locally higher salt precipitation could occur in the area near the injection well [45], [46]. Regarding the simulation aspects, many multi-phase reactive flow simulations suggested that the evaporation of formation water can result in salt precipitation, which would damage the reservoir and reduce the heat mining rate [29], [31]. For example, the Spycher et al. [47] model of geothermal exploitation from Hot Dry Rock showed that significant salt precipitation clogging occurred in the production region for a low-salinity system, while clogging in the injection area occurred for a high-salinity system. Our previous research also indicated that local high salt precipitation could severely damage the reservoir due to a back flow of the formation water under some conditions [25]. All of these research indicated that salt precipitation could change the reservoir porosity and permeability and affect the fluid flow in the geothermal exploitation using CO₂.

As the description above, although the geochemical reactions and salt precipitation are just physical and chemical reactions from a geophysical perspective, they will become directly relevant to the energy issues when these fluid-rock interactions occur in the geothermal exploitation in the CPG system. These fluid-rock interactions can damage the reservoir, decreasing the permeability and CO₂ flow rate, and resulting in the heat mining rate decreasing eventually during geothermal exploitation. In some cases, these fluid-rock interactions even may totally clog local porosity and interrupt the continuity of geothermal exploitation, which will seriously restrict the development of geothermal energy. More importantly, the geochemical reactions and salt precipitation affect each other in the CPG system, and these reactions can affect the formation and development of seepage zones, which, in turn, can also affect these reactions. Moreover, some studies show that the formation water will flow back to the injection well under the actions of evaporation and capillary pressure, which may intensify the reservoir damage caused by the geochemical reactions and salt precipitation. However, there is a lack of systemic research work on the geochemical reaction and salt precipitation, particularly on their combined effects on the reservoir properties and heat mining rate in the CPG system. Therefore, it is essential and helpful to study their combined effect on the reservoir properties and geothermal energy exploitation in the actual application of the CPG system.

Therefore, the primary objectives of this work are to study the combined phenomenon of geochemical reactions and salt precipitation and their effects on the heat mining rate in the CPG system and thereby propose some measures to solve this energy issue affecting the geothermal exploitation. In this study, a comprehensive model for geothermal exploitation via CO₂ recycling from a natural high-permeability reservoir was established that considers various processes, including the dissolution and diffusion of CO₂ in formation water, the evaporation of formation water, geochemical reactions, salt precipitation, and the variations of porosity and permeability. The flow behavior of the CO₂, geochemical reactions, salt precipitation, and their combined effects on the heat mining rate was analyzed, and the influences of reservoir pressure and temperature, the porosity, the permeability, the salinity of formation water, and the injection-production pressure difference were studied. In the end, techniques for preventing and mitigating the formation damage caused by these fluid-rock interactions are proposed and evaluated to enhance the heat mining rate during the real application of the CPG system.