1 Universität Stuttgart - Institut für Wasser- und Umweltsystemmodellierung Lehrstuhl für Hydromechanik und Hydrosystemmodellierung Prof. Dr.-Ing. Rainer Helmig Independent Study CO 2 as a working fluid in geothermal power plants:literature review, summary and outlook. Submitted by Waqas Ahmed Matriculation number Stuttgart, 8 April,2012 Examiners: apl. Prof. Dr.-Ing. Holger Class Supervisor: Dipl.-Ing. Alexander Kissinger
2 Abstract Conventional geothermal power plants work on a water based system, using hot water in underground reservoirs to produce electricity. Brown  in 2000 suggested that the rate of geothermal energy production using Super Critical CO 2 (SCCO 2 ) as a heat extraction fluid would be about 60% of a water based system. The concept of using CO 2 as the fluid for hydro fracturing the reservoir (reservoir creation) and heat extraction can solve two major problems of the present era  Demand for clean energy Reduction of green house gas emissions due to storage of CO 2 This Literature review summarizes different approaches for using CO 2 as working fluid for extraction of heat and producing electricity from geothermal reservoirs. The concept of Super Critical CO 2 - Hot Dry Rock (SCCO2-HDR) suggested by Brown is a novel approach for increasing the efficiency of a hot dry rock production (also known as Enhanced Geothermal system EGS) and the sequestration of CO 2 in a deep reservoir. In the SCCO2-HDR concept supercritical CO 2 acts as a heat transport fluid, the heat contained in SCCO2 is then transferred to the secondary fluid which drives an expansion turbine in a binary cycle to produce power. Working on the concept of Brown, Pruess  studied the operation of enhanced geothermal systems (EGS) with CO 2. Pruess s numerical analysis concludes that CO 2 would achieve a more favorable heat extraction rate than water and will also avoid unfavorable rock fluid interactions that can be encountered in water based systems. Brown and Pruess focused their studies on Enhanced Geothermal Systems (EGS) but the draw back in the EGS process was that it may induce seismicity when the critical fracture stresses of geological formation are exceeded during hydro fracturing , so Randolph instead of using hydro fracturing, used the existing reservoir with high permeability and porosity for his study, His approach is known as CO 2 -plume geothermal system (CPG). Salimi and Wolf  in their work come up with another concept of co-injecting a CO 2 -water mixture in the porous reservoir and gave one possible numerical solution for this kind of problem. This concept uses the approach of extended gas saturation to numerically overcome the problem of phase appearance and disappearance. In this work the effect of reservoir characterization (permeability and porosity heterogeneity) on the heat extraction and CO 2 storage is analyzed.
3 Buscheck  introduced a hybrid two-stage energy recovery approach to sequestrate CO 2 and produce geothermal energy. The hybrid two stage approach is carried out in two steps. In the first step brine works as a heat extraction fluid. The produced brine is used for fresh water production through desalination or as a working fluid for a neighboring reservoir. The second step begins when CO 2 reaches the production well, from this time on wards the co-produced brine and CO 2 act as working fluids. Studies till now suggest that a CO 2 based geothermal system has a larger heat extraction rate and better well bore hydraulics compared to a water based system in an EGS  as well as in a natural porous geological formation . Still the studies are in an early stage and require more detailed follow-up studies especially with respect to understand the chemical interaction between super critical CO 2 and rock minerals . II
4 Contents 1 Introduction Motivation Research question Report flow Literature review Supercritical CO 2 as working fluid in EGS system The Super Critical CO 2 - Hot Dry Rock (SCCO 2 -HDR) concept Advantages of using SCCO Concept of HDR (EGS) system CO 2 sequestration Model setup and numerical simulation Results and recommendation CO 2 storage with geothermal extraction in natural permeable, porous geological formation (CO 2 Plume geothermal (CPG) system ) The CO 2 -plume geothermal (CPG) concept Model setup and numerical simulation Results and recommendations Negative saturation (NegSat) solution approach The concept of Negative saturation (NegSat) solution approach Model setup and numerical simulation Results and recommendation Two stage integrated geothermal-ccs approach The concept of a hybrid two-stage energy-recovery approach Model setup and numerical simulation Results and recommendation Future scope and conclusion Summary and Future scope Concluding remarks Appendix A Typical reservoir conditions 38 I
5 CONTENTS II Appendix B Equations 40
6 List of Figures 2.1 Five spot well pattern  Pressure and temperature profiles along a line from production (distance = 0) to injection well (distance = 707 m) after a simulation time of 25 years.  Simulated rate and composition of produced fluid  CO2 plume geothermal system (CPG)  Simulation result done by Hamidreza and Karl-heinz wolf  Simulation result done by Hamidreza and Karl-heinz wolf  Cumulative heat-energy production and CO 2 storage  An actively managed, two-stage, integrated geothermalccs system, using binary-cycle power  Schematics of tandem-formation ACRM with (a) binary-cycle power from stage two in the CO2 storage reservoir and from stage one in the brine-storage reservoir and (b) tandem-formation ACRM with binarycycle power from stage two of integrated geothermal-ccs in the CO2 storage reservoir and either flash or dry steam geothermal power from the brine-storage reservoir in crystalline rock.  Reservoir specification for simulation Liquid saturation is plotted for a 8 CO2 injectors, 10 km from the center and 4 producers, 2 km from the center  Geothermal and CO 2 -sequestration performance is shown for five cases, with geothermal heat fluxes of 50, 75, and 100 MW/m 2, and for reservoir bottom depths of 2500 and 5000 m  Geothermal and CO 2 -sequestration performance is shown for 5-spot well patterns, with a geothermal heat flux of 75 MW/m 2 and a reservoir bottom depth of 2500 m. The case with 120 kg/sec injection and production rates has a reservoir thickness of 250 m.the case with 280 kg/sec injection and production rates has a reservoir thickness of 305 m and is similar to the case analyzed by Randolph and Saar  III
7 LIST OF FIGURES IV 2.14 Geothermal and CO 2 -sequestration performance is shown for 5-spot well patterns, with a geothermal heat flux of 75 MW/m 2 and a reservoir bottom depth of 2500 m. Histories are shown for the first 100 years.area shows the area of thermal footprint  The geothermal and CO 2 -sequestration performance is plotted for 5- spot well patterns with km well spacing and 2 indicated reservoir thicknesses. These cases have a geothermal heat flux of 75 MW/m 2 and a reservoir bottom depth of 2500 m 
8 List of Tables 2.1 Comparision of average fluid Properties ( Across an HDR reservoir at 4 km for injection pressure of 30 MPa  Typical HDR reservoir condition assumed for the study  Typical reservoir condition assumed for the study  Simulation result  Typical reservoir condition assumed for the study  Typical Reservoir Conditions Assumed  A.1 Typical reservoir condition assumed for the study   A.2 Typical reservoir condition assumed for the study  V
9 Chapter 1 Introduction
10 1.1 Motivation Motivation After industrial revolution there are significant increase in green house gas concentrations, which have led to a positive radiative forcing of climate, tending to warm the surface of earth . Many greenhouse gases remain in the atmosphere for a long time (CO 2 is one of them), hence they affect radiative forcing on long time-scales . CO 2 concentration can be reduced in large amounts relatively to other as it is mainly emitted by point sources (power plants and industrial units) . There are different mitigation techniques to reduce CO 2 concentration, which includes energy efficiency improvements, the switch to less carbon-intensive fuels, nuclear power, renewable energy sources, enhancement of biological sinks and CCS (CO 2 capture and storage) . CCS has the potential to reduce overall mitigation costs and increase flexibility in achieving greenhouse gas emission reductions . Geothermal energy offers clean, consistent, reliable electric power with no need for grid-scale energy storage, unlike most renewable power alternatives . Geothermal energy resource base is too high which corresponds to 6000 times the current primary energy consumption in the US but it only contributes to 0.3% of the primary energy consumption of the US . Conventional geothermal power plants work as water based system, these plants have some short comings like low heat extraction, precipitation and dissolution of rock minerals, large power requirements for the circulation of water, scarcity of water in some regions . CO 2 capture and storage (CCS) in geological formations and geothermal energy both help in reducing the green house gas emission and thereby help in controlling the climate change . Coupling CCS with geothermal energy production can improve the economic viability of CCS  with an advantage of favorable properties of super critical CO 2 (SCCO 2 ) as , The large expandability of CO 2 which increase the buoyancy forces and thereby reduce the power consumption of the fluid circulation. The lower viscosity of CO 2 which yields in larger flow velocities. CO 2 is less effective as a solvent for minerals hence reducing the scaling problem. 1.2 Research question Research aimed at developing a quantitative understanding of potential advantages and disadvantages of operating geothermal plants with CO 2 has begun recently and this study summarizes the up to date research on CO 2 based geothermal systems and focuses on finding out the answers of different questions such as, What are different numerical setups for describing geothermal systems with CO 2 as a working fluid?
11 1.3 Report flow 3 The performance of CO 2 as a heat transmission fluid in fractured reservoirs for a range of temperature and pressure conditions. The Effect of well spacing and arrangement on the pressure relief and CO 2 plume migration. What are the different approaches to make geothermal power plants economically viable? Where is future research potential based on the up to date research? 1.3 Report flow The report is organized according to the hierarchy of the research done till now. It starts with the introduction and a detailed review of the concept of SCCO 2 -HDR. It then summarizes the research of Pruess and others on EGS systems working with CO 2 plume approach. The concept introduced by Randolph of a CO 2 -plume geothermal system (CPG) is then summarized. Further it gives an overview of a numerical solution for dealing with the phase appearance and disappearance when injecting CO 2 -water mixture introduced by Salimi and Wolf and a review of a recently introduced hybrid two-stage energy recovery approach to sequestrate CO 2 and produce geothermal energy. At last it gives a base line for the future work to be based on this literature review.
12 Chapter 2 Literature review 4
13 2.1 Supercritical CO 2 as working fluid in EGS system Supercritical CO 2 as working fluid in EGS system The Super Critical CO 2 - Hot Dry Rock (SCCO 2 -HDR) concept The SCCO 2 -HDR concept uses supercritical CO 2 as the heat transfer fluid, the heat contained in the SCCO 2 is transferred to the working fluid on the surface to run a turbine. This concept uses SCCO 2 as a fracturing fluid for reservoir creation as well as the heat transfer fluid. Model setup contain three well arrangement which include two production wells and one injection well with an initial temperature gradient of 60 C and a mean depth of 4km(see Table 2.2). The further research done by Preus and Spycher to verify this concept considers different temperatures and pressures conditions to understand different processes (see appendix for these conditions) Advantages of using SCCO 2 The use of SCCO 2 as the working fluid seems less beneficial when comparing its heat capacity with water but under HDR reservoir conditions the viscosity of SCCO 2 is only 40 % that of water . Table 2.1 compares the different properties for SCCO 2 to water across a 4 km deep HDR reservoir for injection pressure of 30 MPa and it concludes that using SCCO 2 as the geo fluid provides a 50% increase in the mass flow rate across the HDR reservoir as compared to water. Circulating Fluid SCCO 2 Water Temperature C Pressure MPa Density kg/m Viscosity kg m 1 s Density/Viscosity Ratio SCCO 2 /Water 1.53 Table 2.1: Comparision of average fluid Properties ( Across an HDR reservoir at 4 km for injection pressure of 30 MPa  Water based geothermal systems are limited by the critical temperature and pressures (384 C and 22 MPa). Temperatures above causes dissolution of silica, which negatively impacts the geothermal reservoir operation. As supercritical CO 2 is not a solvent for inorganic material found in the deep formation, it is possible to operate a geothermal reservoir with SCCO 2 at high temperatures without the problem of silica
14 2.1 Supercritical CO 2 as working fluid in EGS system 6 dissolution. Water based geothermal systems also contain significant amounts of dissolved minerals and other trace materials such as arsenic, boron, Fluoride etc, which could cause environmental problems when flashed to the surface. However when SCCO 2 is used the pore fluid dissolves in the SCCO 2 leaving behind a small amount of precipitate within the micro crack pore structure  Concept of HDR (EGS) system The SCCO 2 -HDR concept works in two stages 1. Creation of an engineered HDR reservoir by using SCCO 2 as a fracturing fluid. 2. Circulation of the SCCO 2 as a heat extraction fluid. Creation of an engineered HDR reservoir is done by injecting SCCO 2 at rates in the range of 20 to 40 kg s 1  in the hot impermeable rock. First the most favorable joints intersecting the well bore starts to open and as the pumping continues more joints opens and interconnect, forming a region of pressure dilate joints in the rock mass, thus creating a HDR reservoir. At first the pore water in the system moves from the central zone. During this phase the fluid act as the single water phase and later by the two phase flow of CO 2 -water mixture , with passage of time the fluid will be the CO 2 phase. Working on the concept of Brown, Fouillac  indicated that there will be three zones during the reservoir development. 1. Core zone ( single phase dry supercritical CO 2 ) 2. Surrounding zone (Two Phase CO 2 -water mixture) 3. Outer zone (Single Phase water with some dissolved CO 2 ) After the creation of the reservoir the pure SCCO 2 circulates in the close loop to extract heat while some amount of CO 2 sequestrates in the surrounding rock mass. At the reservoir condition mentioned in Table 2.2 there is a huge density difference (i.e 0.57 g/cm 3 ) between the hot fluid rising from production well and the cold fluid in the injection well creating a significant buoyant drive across the reservoir CO 2 sequestration Brown  with his extensive field research suggests that for 0.5 km of reservoir with an injection pressure of 30 MPa there will be a loss of 3 kg s 1 of CO 2 which is the amount produced by a 10 MW power plant, this amount will be equivalent to the 100,000 ton per year.
15 2.1 Supercritical CO 2 as working fluid in EGS system Model setup and numerical simulation Different researchers have tested different model setups to analyze and compare the working of EGS systems with CO 2 as a working fluid. The most common setup is the five spot EGS injection production system with the consideration of a two dimensional domain as a reservoir. Figure 2.1: Five spot well pattern  Considering the reservoir condition as described in Table 2.2, Table A.1, TableA.2(see appendix A) simulations were performed. Different initial fluids in the reservoir were considered to analyze and compare the EGS production. Preuss  analyzed two different conditions, A water system. A CO 2 system. Spycher  analyzed anhydrous CO 2 injection into the water saturated reservoir. In both studies the simulations were performed with the TOUGH2 simulator with the ECO 2 N fluid property module. Preuss  also analyzed a linear three well arrangement instead of typical five well arrangement and compared them for the same thermodynamic reservoir conditions and for the same injected fluid. The results are summarized in the following paragraph Results and recommendation This paragraph will summarize the performance of the EGS system working with the SCCO 2 as a working fluid based on different studies.
16 2.1 Supercritical CO 2 as working fluid in EGS system 8 Reservoir thickness 4 km Mean geothermal gradient 60 C km 1 Reservoir rock temperature 260 C Mean reservoir Porosity (After reservoir creation) Closed-Loop Reservoir Circulating Conditions Injection pressure 30 MPa Injection temperature 40 C Surface production back pressure 30 MPa Surface Production temperature 250 C Table 2.2: Typical HDR reservoir condition assumed for the study  Simulation done by Preuss in 2007  concludes that initially the heat extraction rates are approximately 50 % larger with CO 2 in comparison to water. The difference becomes smaller with time, due to the more rapid thermal depletion when using CO 2. Mass flow rates in the CO 2 system are larger than for water by factors ranging from 3.5 to almost 5. These results show that the mass flow increases due to the much lower viscosity of CO 2 more than compensate for the smaller density and specific heat of CO 2. Figure 2.2 shows pressures and temperatures after 25 years of fluid circulation along a line connecting injection and production wells. It is seen that for CO 2 the pressure profile is almost symmetrical between injector and producer, while for water there is a much steeper pressure gradient near the injection well. This is due to the strong increase in water viscosity with decreasing temperature, which causes much of the pressure drop available for pushing fluid from the injector to the producer to be used up in the cold region near the injector. In contrast, the CO 2 viscosity does not change in this magnitude with temperature. For the linear flow geometry the heat extraction rate for CO 2 is 15% larger compared to water, the reason for this difference as compared to the five well arrangement described by Preuss  is the increase in water viscosity near the injection point. The radial flow geometry around the injection well in the five-spot problem amplifies the mobility block for water and the associated enhancement in the pressure gradient, as compared to the linear flow geometry in the linear system. At an estimated fluid loss rate of 5%, Preuss  suggested that 1 kg s 1 MW 1, or 1 t/s/1.000mw will be sequestrated. Spycher  studied the water plume break through after the injection of CO 2, he concluded that the production of a free aqueous phase from an EGS operated with CO 2 will occur for only a limited time (a few years), he also found that the dissolved water will persist in the CO 2 production stream for decades. His simulation results are concluded in Figure 2.3
17 2.1 Supercritical CO 2 as working fluid in EGS system 9 Figure 2.2: Pressure and temperature profiles along a line from production (distance = 0) to injection well (distance = 707 m) after a simulation time of 25 years.  Figure 2.3: Simulated rate and composition of produced fluid 
18 2.2 CO 2 storage with geothermal extraction in natural permeable, porous geological formation (CO 2 Plume geothermal (CPG) system ) CO 2 storage with geothermal extraction in natural permeable, porous geological formation (CO 2 Plume geothermal (CPG) system ) The CO 2 -plume geothermal (CPG) concept The research summarized in the previous chapter was related to the SCCO 2 as a working fluid in an Enhanced geothermal system, which includes the step of reservoir creation (hydro fracturing). In this chapter a new concept introduced by the Randolph  is summarized, in which SCCO 2 is used as a working fluid in the high-permeability and high-porosity geologic reservoirs that are overlain by a low-permeability cap rock. The sizes of such reservoirs is much larger then that of hydro fractured reservoirs and has a potential of greater CO 2 sequestration then EGS system . He differentiated this approach from EGS and refers to it as CO 2 -plume geothermal (CPG) system. In CO 2 -plume geothermal (CPG) concept the CO 2 is pumped into a naturally porous and permeable reservoir where it heats up via the underlying hot rock and then circulates through the pipe system to generate the electricity. Some of the injected CO 2 is sequestered in the reservoir and stores permanently. The Figure 2.4 gives the schematic of this system, Figure 2.4: CO2 plume geothermal system (CPG)  Model setup and numerical simulation Randolph s  research is the extension of Preuss  research, same model setup of a five well arrangement is used, see Figure 2.1. In this work first EGS system working with SCCO 2 is simulated and then the porous media system working with SCCO 2. The porous medium in the domain is homogeneous with a permeability of m 2
19 2.2 CO 2 storage with geothermal extraction in natural permeable, porous geological formation (CO 2 Plume geothermal (CPG) system ) 11 Geological Formation Reservoir thickness 305 m Well separation m Permeability m 2 Porosity 0.20 Rock grain density 2650 kg/m 2 Rock specific heat 1000 J kg 1 C 1 Thermal conductivity 2.1 W m 1 C 1 Injection/ production conditions Formation map-view area 1 km 2 Temperature of injected fluid 20 C Injection/production rate max 300 kg s 1 (variable) Downhole injection pressure 260 bar Downhole production pressure 240 bar Injection/production duration 25 years Formation boundary conditions Top and sides No fluid or heat flow Bottom Heat conduction, no fluid flow Table 2.3: Typical reservoir condition assumed for the study  and a porosity of 0.2. The domain is a two dimensional horizontal plain. The grid is equidistant with a discretization length of m. For the simulations the input parameters are given in table2.3. Two reservoirs are considered in the simulation: one deep reservoir at a depth of 4 km and a temperature of 150 C, the second reservoir is shallow at a depth of 1 km and a temperature of 100 C. A conservative value of m 2 for the permeability was used for both reservoirs. Considering CO 2 as the only fluid in the system and neglecting brine in the formation (although it is important to consider it in the simulation) simulations were performed with the numerical simulator TOUGH2 and the fluid property module ECO 2 N Results and recommendations Research done by Jimmy B. Randolph  concludes that heat extraction rates decreases with time as the reservoir heat is depleted and the temperature at the production wells decreases although the mass flow rates remain relatively constant with time. Heat extraction rates in the CPG approach generally increase with formation temperature. Comparing his results with the Preuss  setup for EGS system, he found that the heat extraction rate is higher in both cases (deep and shallow reservoir). The result for the simulations is given in the table 2.4.
20 2.2 CO 2 storage with geothermal extraction in natural permeable, porous geological formation (CO 2 Plume geothermal (CPG) system ) 12 Case Heat extraction rate (25 year average) MW EGS system 47 Deep Reservoir 62.6 Shallow Reservoir 64.1 Table 2.4: Simulation result  25 years of simulation shows that 7% of the CO 2 can be permanently sequestered in the reservoir (which is greater than the finding of the Preuss  in EGS i.e 5%) which makes a total amount of CO 2 sequestrated of tons over the simulated 25-year life of the CPG power plant. Performing a cost analysis based on 100 $U.S.A (value per MW*hour) he suggested that the CPG system could result in higher net revenue values due to fixed construction and low maintenance costs. His results for the shallow reservoir (temperature = 150 C, reservoir depth = 4 km) give a net revenue of 7.9 $ per ton CO 2 sequestered whereas the deep reservoir (temperature = 100 C, reservoir depth = km) has net revenue of 5.9 $U.S.A per ton CO 2 sequestrated. As this is a new concept further numerical simulations are required to investigate its feasibility. Randolph in his research does not include in situ brine in the reservoir, so it has to be investigated how much time will be required until the reservoir is fully occupied with SCCO 2 and what will be done with the brine extracted from the production (can it be used directly or does it need to be treated). The chemical and thermal behavior of the permeable reservoir formations for different regions in Europe still has to investigated. His work is a bench mark to start investigating the possibilities of clean energy and CO 2 sequestration in permeable soil because it is much cheaper than EGS and do not induce seismic activities.
21 2.3 Negative saturation (NegSat) solution approach Negative saturation (NegSat) solution approach Salimi and Wolf  in their work come up with another concept of co injecting CO 2 - water mixture into a porous reservoir and give one possible numerical solution for this kind of problem. This chapter summarizes their research on co injecting CO 2 -water mixture into a geothermal reservoir The concept of Negative saturation (NegSat) solution approach Injection of CO 2 at a high rate can have negative effects like drying out the reservoir and over pressurizing the aquifer, which can lead to fracturing and therefore also to leakage  of CO 2. Salimi and Wolf proposed to inject moderate amounts of a mixture of CO 2 combined with cooled production water into a geothermal reservoirs. There are several advantages as to enhance residual trapping, reducing the mobility ratio, to enhancing the spreading, and also to take advantage of single-phase dissolved CO 2 injection which avoids confining the CO 2 to the upper part of the reservoir hence decreasing the leakage risk via the cap rock . As this concept involves the injection of a CO 2 -Water mixture so phase disappearance, appearance as well as the phase transition between sub cooled and super critical behavior is a problem in model formulation, therefore they formulated the NegSat solution approach for non-isothermal compositional two-phase flow. This approach gives a uniform system of equations for the entire reservoir that properly deal with different phase states of the reservoir without changing the primary variables and thermodynamicconstraint conditions. Formulating such a situation the NegSat solution approach assumes a cold mixed CO 2 - water injection into a geothermal reservoir, in the reservoir two phases could coexist at most (a CO 2 -rich phase and a water-rich phase), therefore the equation of singlephase region (i.e over saturated and under saturated) is replaced with the equations for equivalent fictitious two phase regions with equivalent specific properties (such as molar density, concentration, flux and saturation). Working with the following postulates the equivalent saturation is defined as a limiting parameter to control appearance and disappearance of a phase , The single-phase molar density should be equal to the total molar density of the fictitious two phases. The single-phase density must be calculated from an equation-of-state (EOS) program, apart from the temperature and pressure it also depends on the overall composition of each component.
22 2.3 Negative saturation (NegSat) solution approach 14 The overall concentration of component in the single-phase must be equal to that in the fictitious two phases. The single-phase flux must be equated to the total flux of the fictitious two phases. The energy conservation equation for the single-phase must be equivalent to that for the fictitious two phases. The saturation of the equivalent gas Ŝg is called the extended gas saturation, given by Ŝ g = z i x il x ig x ilg z i = Mole fraction at specfic time and space x il = Mole fraction of liquid x ig = Mole fraction of gas i=1,2,3... The possible phases which can exists base on the extended gas saturation are as follows, If the extended gas saturation is between zero and one, it is the same as the actual gas saturation and there are two phases. If the extended gas saturation is above one, we have a single gaseous phase and the actual gaseous saturation is one. If the extended gas saturation is below zero, we have a single liquid phase and the actual gas saturation is zero. Maximum injection pressure 255 bar Bottom hole production pressure 205 bar Initial temperature C Injection temperature C Maximum water-injection rate m 3 /s Rock grain density 2650 kg/m 2 Rock specific heat 1000 J kg 1 C 1 Thermal conductivity 2.1 W m 1 C 1 Porosity 0.17 Residual water saturation 0 Residual gas saturation 0 Number of grid cells 2335 (N x x N y ) Table 2.5: Typical reservoir condition assumed for the study 
23 2.3 Negative saturation (NegSat) solution approach Model setup and numerical simulation A model setup considers a geothermal reservoir having a length of 1500 m, a width of 1500 m and a height of 60 m, initially saturated with hot water. Then injection of cold mixture of CO 2 -water is done through out the reservoir. In the model CO 2 behave as a non ideal fluid due to high pressure and temperature . Therefore Peng-Robinson-Stryjek-Vera equation of state with the modified Huron-Vidal secondorder mixing rule is formulated to define non ideal behavior of CO 2 (see appendix for the relationships used to describe different parameters). The discretization of the reservoir is cells. Table 2.5 shows the input date for simulation and for the following cases system was analyzed, Case 1: CO 2 mole fraction of 0.02 (or about 49.9 kg of CO 2 per t of water), injection in a homogeneous permeability and porosity field. Case 2: CO 2 mole fraction of 0.02 (i.e same as in case 1), injection in the heterogeneous permeability and porosity field. Case 3: CO 2 mole fraction of 0.03, injection in the heterogeneous permeability and porosity field. Case 4: CO 2 mole fraction of 0.2, injection in the heterogeneous permeability and porosity field Results and recommendation For Case 1 the extended gas saturations are all negative ( < Ŝg <0.0011) indicating the absence of a gas (CO 2 -rich) phase for 30 years of simulation time. Therefore, Figure 2.5a describes single-phase aqueous regions. The temperature increases monotonically and becomes constant as the extended saturation becomes constant Figure 2.5c. The overall mole fraction decreases monotonically with increasing distance from the injection well (see Figure 2.5e. There is no breakthrough of CO 2 for 30 years simulation. For Case 2 the extended gas saturation Figure 2.5b is below zero for the entire 30 year time span, indicating that all the injected CO 2 is completely dissolved into the aqueous phase, thus Figure 2.5b displays a single-phase-displacement process in the entire domain. Whenever the extended gas saturation is equal to zero in simulation (which indicates that the system is at the bubble point) the computed extended saturation is dispersive. The temperature distribution Figure 2.5d is smooth and the temperature profile in the highly permeable zones is slow down and it accelerates in the less permeable zones. For the 30 year simulation there is no breakthrough. By comparing the results of Case 1 with Case 2 Figure 2.7a it can be seen that the rate of heat extraction and CO 2 storage of Case 2 is higher than that of Case 1 by
24 2.3 Negative saturation (NegSat) solution approach 16 a factor of 2.5. This is due the fact that in Case 2 (there is permeability variation at the injection side) the injectivity index is larger than the injectivity index of Case 1 (where the homogeneous permeability is used). Although the stored CO 2 and heat energy are proportional to the constant injection rate the only difference is due to the heterogeneous permeability and porosity field in Case 2. Case 3: CO 2 mole fraction is 0.03, injection is done in the heterogeneous permeability and porosity field. Three distant regions are seen in the simulation, A single-phase region of an aqueous phase, upstream, downstream and in the less permeable zones. A two-phase region (i.e 1 > Ŝg > 0) with a gas phase mainly super critical CO 2 and an aqueous phase with mainly water in the high permeable zones. A two-phase region of a sub cooled (liquid) CO 2 -rich phase and an aqueous phase in the cold highly permeable zones. These regions occurs because the extended gas saturation is below zero at the injection and initial reservoir conditions, indicating single-phase aqueous regions. However, close to the injection side, CO 2 banks (high gaseous-saturation values) are seen where the extended gas saturation is above zero and below one, indicating two-phase regions. Moreover, Figure 2.6a illustrates that the extended gas saturation attains a maximum value of at t = 51 yr in the heterogeneous case. This highest value of the extended gas saturation is much larger than the injection value (0.0092) and value (0.1226) attained in the homogeneous reservoir structure with the same overall injected CO 2 mole fraction. The reason for this behavior is as follows. When the gas phase is formed it travels rapidly upward due the large density difference between gas phase and the aqueous phase, as the gas phase reaches high permeable zones it is trapped due to capillary forces, In this case the high permeability zones are surrounded by the less permeable zones, Therefore, the gaseous CO 2 banks while being supplied from the injected side will be trapped between the less permeable zones for a while until the gas pressure is higher than the entry pressure of the less permeable zones, after which they will be able to pass slowly through these zones. This process in turn, leads to the accumulation of the gas phase in the highly permeable parts. The temperature profile is relatively smooth due to the high value of the thermaldiffusion coefficient of the reservoir rock and for the zones with high values of the extended gas saturation the overall CO 2 mole fraction is also high. For Case 4 CO 2 mole fraction is 0.20 and injection is done in the heterogeneous permeability and porosity field. For this case the two phases are seen at the injection side Figure 2.6b as the extended gas saturation is above zero (i.e 0.32). It can also be observed that the CO 2 plume develops along the highly permeability streaks (i.e. the progress of CO 2 plumes are dominated by the permeability distribution in combination with a high mobility ratio), this is known as channeling pattern. Figure 2.6d illustrates that the cold-temperature front does not considerably penetrate
25 2.3 Negative saturation (NegSat) solution approach 17 into the reservoir. This is attributes to the fact that as the amount of CO 2 injection increases, the difference between the speed of the thermal front and the speed of the compositional front becomes larger. The reason for this is that heat transfer of the aqueous phase is more efficient than the gas phase. Figure 2.6f shows the overall-co 2 -mole-fraction distribution at t = 6.5 yr. The overall CO 2 mole fraction reaches a maximum of z = at t = 6.5 yr, which are much larger than the overall injected value of z = 0.20 which shows the CO 2 trapping due to heterogeneous permeability and porosity field. Figure 2.6f also clearly describes the channeling pattern. For analyzing the efficiency of the system the energy balance for different mole fraction is compared and it is observed that an overall injected CO 2 mole fraction less than 0.10 produces more energy than they consume. However, the cases with z > 0.10, which fall below the energy-invested triangular points in figure 2.7b, eventually consume more energy than they produce. From the analysis of the results it can be concluded that the permeability and porosity heterogeneity in a geothermal aquifer significantly influence both heat extraction and CO 2 storage. Also the character of heterogeneity and the mobility ratio control the displacement regime. For the heterogeneous-reservoir structure considered here, a transition from a dispersive to a channeling regime occurs as the mobility ratio increases from M <= 1 to M > 1. Hence, reservoir characterization plays an important role in assessing the benefits of CO 2 storage and energy extraction. For all cases analyzed the compositional wave that runs a head of the thermal wave, limits the period of simultaneous CO 2 storage and heat extraction to the end of the project. For overall injected CO 2 mole fractions smaller than 0.1, the net energy balance is positive, indicating that the process produces more energy than consumes. However, the net energy balance becomes negative for overall injected CO 2 mole fractions larger than 0.1.
26 2.3 Negative saturation (NegSat) solution approach 18 (a) Extended gas saturation for case 1 t=30yr (b) Extended gas saturation for case 2 t=30yr (c) Temperatur distribution (K) for case1 t=30yr (d) Temperatur distribution (K) for case2 t=30yr (e) Overall CO2 mole fraction distribution for case 1 t=30yr (f) Overall CO2 mole fraction distribution for case 2 t=30yr Figure 2.5: Simulation result done by Hamidreza and Karl-heinz wolf 
27 2.3 Negative saturation (NegSat) solution approach 19 (a) Extended gas saturation for case 3 t=51yr (b) Extended gas saturation for case 4 t=6.5yr (c) Temperature distribution (K) for case3 t=51yr (d) Temperature distribution (K) for case4 t=6.5yr (e) Overall CO 2 mole fraction distribution for case3 t=51yr (f) Overall CO 2 mole fraction distribution for case4 t=6.5yr Figure 2.6: Simulation result done by Hamidreza and Karl-heinz wolf 
28 2.3 Negative saturation (NegSat) solution approach 20 (a) Cummulative heat extraction and CO 2 for case1 and case2. (b) Cumulative heat-energy production and energy invested versus maximally stored CO 2 at CO 2 breakthrough either in the aqueous or in the gaseous phase Figure 2.7: Cumulative heat-energy production and CO 2 storage 
29 2.4 Two stage integrated geothermal-ccs approach Two stage integrated geothermal-ccs approach Buscheck  introduces a hybrid two-stage energy-recovery approach to sequestrate CO 2 and produce geothermal energy by integrating geothermal production with CO 2 capture and sequestration (CCS) in saline, sedimentary formations. During stage one of the hybrid approach, formation brine, which is extracted to provide pressure relief for CO 2 injection is the working fluid for energy recovery. During stage two, which begins as CO 2 reaches the production wells; co produced brine and CO 2 are the working fluids. This chapter summarizes the result of a hybrid two-stage energyrecovery approach. Figure 2.8: An actively managed, two-stage, integrated geothermalccs system, using binary-cycle power  The concept of a hybrid two-stage energy-recovery approach Introducing this approach Buscheck kept in mind the concept of Active CO 2 Reservoir Management (ACRM) which combines brine extraction and treatment and residualbrine re-injection with CO 2 injection. It is found that if the reservoir has sufficient trapping characteristics, brine disposition options, reasonable formation temperature, proximity to CO 2 emitters then Active CO 2 Reservoir Management can be applied to the separate formations with one formation being utilized for CO 2 storage and a separate formation being utilized for the purpose of brine re injection (see Figure2.9). This approach is named Tandem-formation ACRM.
30 2.4 Two stage integrated geothermal-ccs approach 22 Figure 2.9: Schematics of tandem-formation ACRM with (a) binary-cycle power from stage two in the CO2 storage reservoir and from stage one in the brine-storage reservoir and (b) tandem-formation ACRM with binary-cycle power from stage two of integrated geothermal-ccs in the CO2 storage reservoir and either flash or dry steam geothermal power from the brine-storage reservoir in crystalline rock.  Model setup and numerical simulation This concept uses a 3-D model with quarter symmetry to represent a 250-m-thick storage formation (reservoir) (see Figure 2.10 ) and Table 2.6 shows the reservoir condition for simulation. The analysis is done for 12, 16 and 5 well configuration. NUFT (Non isothermal Unsaturated-saturated Flow and Transport) code is run to simulate multi-phase multi component heat, mass flow and reactive transport in unsaturated and saturated porous media. The following different configurations were simulated 12 well configuration with 8 injectors ring at 10 km from center and 4 producer at 2 km from center. 16 well configuration with 8 injectors ring at 10 km from center and 8 producer at 3 km from center. 5 well configuration with areas of 1, 2, 4, 8, and 16 km2, with well spacing of , 1.0, , 2.0, and km, respectively. All configurations considers heat flux of 50,75 and 100 MW/m2 for reservoir depth of 2500 km and 5000km. For 5 well configuration the flow rate of 280kg/s and 120 kg/s for different reservoir thickness 125m and 250m respectively is run to see the effect of flow rate.
31 2.4 Two stage integrated geothermal-ccs approach 23 Property Storage formation Caprock seal Horizontal and vertical permeability (m 2 ) Pore compressibility Pa Porosity van Genuchten (1980) m van Genuchten α Pa Residual supercritical CO 2 saturation Residual water saturation Table 2.6: Typical Reservoir Conditions Assumed  Figure 2.10: Reservoir specification for simulation
32 2.4 Two stage integrated geothermal-ccs approach Results and recommendation The aim of this study was to achieve pressure relief and delaying the breakthrough time of CO 2 to increase the life time of brine production and maximize the CO 2 storage . As the pressure relief from brine production increases with decreasing spacing between the CO 2 injectors and brine producers, while CO 2 breakthrough time increases with well spacing therefore various conditions are investigated to tradeoff between achieving pressure relief, while delaying CO 2 breakthrough. First the 12 well arrangement with 8 injection and 4 central production wells is simulated. The result shows that this type of arrangement increases CO 2 storage due to following reasons, Producing from the center is an effective means of controlling the influence of buoyancy on CO 2 plume migration. Reduction in the pore space competition. Reduction in the interface pressure with neighboring sub surface. Figure 2.11 shows the results of this simulation(which shows the liquid saturation for different simulation time).the breakthrough is observed for simulation of 70 year (see Figure 2.11b) and for the 1000 year simulation, the total fluid (brine plus CO 2 ) production rate of 760 kg/s is observed for injection of 760 kg/s of CO 2. The second approach includes the 16 well arrangement with 8 injection and 8 production wells. The result of the simulation is summarized in Figure The result shows that there is decline in temperature for about 30 years in the production well due to thermal mixing (see Figure 2.12a) and it can also be seen from the Figure 2.12b that the cold CO 2 reaches production well between 30 to 100 years, hence the small temperature decline during that time frame corresponds to the arrival of the slightly cooler CO 2 plume. Figure 2.12c represents the cumulative net CO 2 storage, which shows that 720 million tons of CO 2 are stored for the 30 year simulation before the breakthrough of CO 2 at the production wells is observed. Third approach includes the 5 well arrangement with 4 injector wells and one central production well. The result of the simulation is summarized in Figure During this simulation the effect of following conditions are analyzed, The Effect of different well spacings ( i.e , 1.0, , 2.0, and km) on the economic life time and storage capability of the reservoir. The Effect of different injection rates (120 kg/s and 280 kg/s) on the thermal footprint of the reservoir. The Effect of different reservoir thicknesses (i.e 250m and 125m) on economic life time of reservoir.
33 2.4 Two stage integrated geothermal-ccs approach 25 Figure 2.14 shows the reservoir geothermal and CO 2 sequestration performance for a 100 year simulation of the 5 well arrangement. The Simulation shows that the economic life time increases with an increase in the well spacing. The well spacing with , 1.0, , 2.0, and km has 50, 100, 200, 430, and 950 years economic life time respectively. It can be seen that the at 30 years, the percentage of injected CO 2 that is permanently stored is 10.2, 21.3, 40.8, 65.0, and 85.9 percent for well spacing of , 1.0, , 2.0, and km, respectively and at 100 years, the percentage of injected CO 2 that is permanently stored reduces to 3.3, 7.2, 14.6, 27.7, and 46.7 percent for well spacings of , 1.0, , 2.0, and km, respectively. To observe the effect of reservoir thickness on the life time of the reservoir, the following two cases are analyzed, The well spacing of km with reservoir thickness of 250 m. The well spacing of km with reservoir thickness of 125 m. Thermal draw down of 125m thick reservoir is 4 C which is slightly greater then 250m (i.e 1 C). Initially the thermal draw down is 1 C for 100 and 200 year for 125 m thick reservoir then it becomes greater then 250m thick reservoir resulting in an economic lifetime less than that of the 250-m-thick-reservoir case (750 versus 950 years). The cumulative net CO 2 for both thickness is same for 10 years then the ratio of cumulative net CO 2 storage approaches two, directly proportional to the relative reservoir thickness.
34 2.4 Two stage integrated geothermal-ccs approach 26 (a) Liquid saturation 30 yr (b) Liquid saturation ( 70 yr, shortly after CO2 breakthrough occurs) (c) Liquid saturation for 200yr (d) liquid saturation for 1000 yr Figure 2.11: Liquid saturation is plotted for a 8 CO2 injectors, 10 km from the center and 4 producers, 2 km from the center 
35 2.4 Two stage integrated geothermal-ccs approach 27 (a) Production well temperature (b) Mass fraction of CO2 in the total fluid production (c) Cumulative net CO2 storage Figure 2.12: Geothermal and CO 2 -sequestration performance is shown for five cases, with geothermal heat fluxes of 50, 75, and 100 MW/m 2, and for reservoir bottom depths of 2500 and 5000 m 
36 2.4 Two stage integrated geothermal-ccs approach 28 (a) Production well temperature (b) Mass fraction of CO2 in the total fluid production (c) Cumulative net CO2 storage Figure 2.13: Geothermal and CO 2 -sequestration performance is shown for 5-spot well patterns, with a geothermal heat flux of 75 MW/m 2 and a reservoir bottom depth of 2500 m. The case with 120 kg/sec injection and production rates has a reservoir thickness of 250 m.the case with 280 kg/sec injection and production rates has a reservoir thickness of 305 m and is similar to the case analyzed by Randolph and Saar 
37 2.4 Two stage integrated geothermal-ccs approach 29 (a) Production well temperature (b) Mass fraction of CO2 in the total fluid production (c) Cumulative net CO2 storage Figure 2.14: Geothermal and CO 2 -sequestration performance is shown for 5-spot well patterns, with a geothermal heat flux of 75 MW/m 2 and a reservoir bottom depth of 2500 m. Histories are shown for the first 100 years.area shows the area of thermal footprint 
38 2.4 Two stage integrated geothermal-ccs approach 30 (a) Production well temperature (b) Mass fraction of CO2 in the total fluid production (c) Cumulative net CO2 storage Figure 2.15: The geothermal and CO 2 -sequestration performance is plotted for 5-spot well patterns with km well spacing and 2 indicated reservoir thicknesses. These cases have a geothermal heat flux of 75 MW/m 2 and a reservoir bottom depth of 2500 m 
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