independent study co as a working uid in geothermal power ... · independent study co 2 as a...

Universitat Stuttgart - Institut fur Wasser- und UmweltsystemmodellierungLehrstuhl fur Hydromechanik und Hydrosystemmodellierung

Prof. Dr.-Ing. Rainer Helmig

Independent Study

CO2 as a working fluid in geothermal

power plants:Literature review, summary

and outlook.

Submitted by

Waqas Ahmed

Matriculation number 2708711

Stuttgart, 8 April,2012

Examiners: apl. Prof. Dr.-Ing. Holger Class

Supervisor: Dipl.-Ing. Alexander Kissinger

Abstract

Conventional geothermal power plants work on a water based system, using hot water

in underground reservoirs to produce electricity. Brown [3] in 2000 suggested that

the rate of geothermal energy production using Super Critical CO2 (SCCO2) as a heat

extraction fluid would be about 60% of a water based system. The concept of using CO2

as the fluid for hydro fracturing the reservoir (reservoir creation) and heat extraction

can solve two major problems of the present era [3]

• Demand for clean energy

• Reduction of green house gas emissions due to storage of CO2

This Literature review summarizes different approaches for using CO2 as working

fluid for extraction of heat and producing electricity from geothermal reservoirs. The

concept of Super Critical CO2 - 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 CO2 in a deep

reservoir. In the SCCO2-HDR concept supercritical CO2 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 [8] studied the operation of enhanced

geothermal systems (EGS) with CO2. Pruess’s numerical analysis concludes that CO2

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 [10],

so Randolph instead of using hydro fracturing, used the existing reservoir with

high permeability and porosity for his study, His approach is known as CO2-plume

geothermal system (CPG).

Salimi and Wolf [11] in their work come up with another concept of co-injecting a

CO2-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 CO2 storage is analyzed.

II

Buscheck [4] introduced a hybrid two-stage energy recovery approach to sequestrate

CO2 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 CO2 reaches the production well,

from this time on wards the co-produced brine and CO2 act as working fluids.

Studies till now suggest that a CO2 based geothermal system has a larger heat ex-

traction rate and better well bore hydraulics compared to a water based system in an

EGS [8] as well as in a natural porous geological formation [10]. 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 CO2 and rock minerals [9].

Contents

1 Introduction 1

1.1 Motivation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

1.2 Research question . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

1.3 Report flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

2 Literature review 4

2.1 Supercritical CO2 as working fluid in EGS system . . . . . . . . . . . . 5

2.1.1 The Super Critical CO2 - Hot Dry Rock (SCCO2 -HDR) concept 5

2.1.2 Advantages of using SCCO2 . . . . . . . . . . . . . . . . . . . . 5

2.1.3 Concept of HDR (EGS) system . . . . . . . . . . . . . . . . . . 6

2.1.4 CO2 sequestration . . . . . . . . . . . . . . . . . . . . . . . . . 6

2.1.5 Model setup and numerical simulation . . . . . . . . . . . . . . 7

2.1.6 Results and recommendation . . . . . . . . . . . . . . . . . . . . 7

2.2 CO2 storage with geothermal extraction in natural permeable, porous

geological formation (CO2 Plume geothermal (CPG) system ) . . . . . 10

2.2.1 The CO2-plume geothermal (CPG) concept . . . . . . . . . . . 10


2.2.3 Results and recommendations . . . . . . . . . . . . . . . . . . . 11

2.3 ”Negative saturation”(NegSat) solution approach . . . . . . . . . . . . 13

2.3.1 The concept of ”Negative saturation” (NegSat) solution approach 13



2.4 Two stage integrated geothermal-CCS approach . . . . . . . . . . . . . 21

2.4.1 The concept of a hybrid two-stage energy-recovery approach . . 21



3 Future scope and conclusion 31

3.1 Summary and Future scope . . . . . . . . . . . . . . . . . . . . . . . . 32

3.2 Concluding remarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Appendix A Typical reservoir conditions 38

I

CONTENTS II

Appendix B Equations 40

List of Figures

2.1 Five spot well pattern [8] . . . . . . . . . . . . . . . . . . . . . . . . . . 7

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. [8] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

2.3 Simulated rate and composition of produced fluid [13] . . . . . . . . . . 9

2.4 CO2 plume geothermal system (CPG) [10] . . . . . . . . . . . . . . . . 10

2.5 Simulation result done by Hamidreza and Karl-heinz wolf [11] . . . . . 18

2.6 Simulation result done by Hamidreza and Karl-heinz wolf [11] . . . . . 19

2.7 Cumulative heat-energy production and CO2 storage [11] . . . . . . . . 20

2.8 An actively managed, two-stage, integrated geothermalCCS system, us-

ing binary-cycle power [4] . . . . . . . . . . . . . . . . . . . . . . . . . 21

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. [4] . . . . . . . . . . . . . 22

2.10 Reservoir specification for simulation . . . . . . . . . . . . . . . . . . . 23

2.11 Liquid saturation is plotted for a 8 CO2 injectors, 10 km from the center

and 4 producers, 2 km from the center [4] . . . . . . . . . . . . . . . . 26

2.12 Geothermal and CO2-sequestration performance is shown for five cases,

with geothermal heat fluxes of 50, 75, and 100 MW/m2, and for reservoir

bottom depths of 2500 and 5000 m [4] . . . . . . . . . . . . . . . . . . 27

2.13 Geothermal and CO2-sequestration performance is shown for 5-spot well

patterns, with a geothermal heat flux of 75 MW/m2 and a reservoir bot-

tom depth of 2500 m. The case with 120 kg/sec injection and produc-

tion 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 [4] . . . . . . . . . . 28

III

LIST OF FIGURES IV

2.14 Geothermal and CO2-sequestration performance is shown for 5-spot well

patterns, with a geothermal heat flux of 75 MW/m2 and a reservoir

bottom depth of 2500 m. Histories are shown for the first 100 years.Area

shows the area of thermal footprint [4] . . . . . . . . . . . . . . . . . . 29

2.15 The geothermal and CO2-sequestration performance is plotted for 5-

spot well patterns with 2.8284-km well spacing and 2 indicated reservoir

thicknesses. These cases have a geothermal heat flux of 75 MW/m2 and

a reservoir bottom depth of 2500 m [4] . . . . . . . . . . . . . . . . . . 30

List of Tables

2.1 Comparision of average fluid Properties ( Across an HDR reservoir at 4

km for injection pressure of 30 MPa [14] . . . . . . . . . . . . . . . . . 5

2.2 Typical HDR reservoir condition assumed for the study [3] . . . . . . . 8

2.3 Typical reservoir condition assumed for the study [10] . . . . . . . . . . 11

2.4 Simulation result [10] . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

2.5 Typical reservoir condition assumed for the study [11] . . . . . . . . . . 14

2.6 Typical Reservoir Conditions Assumed [4] . . . . . . . . . . . . . . . . 23

A.1 Typical reservoir condition assumed for the study [10] [9] . . . . . . . . 38

A.2 Typical reservoir condition assumed for the study [13] . . . . . . . . . . 39

V

Chapter 1

Introduction

1.1 Motivation 2

1.1 Motivation

After industrial revolution there are significant increase in green house gas concentra-

tions, which have led to a positive radiative forcing of climate, tending to warm the

surface of earth [6]. Many greenhouse gases remain in the atmosphere for a long time

(CO2 is one of them), hence they affect radiative forcing on long time-scales [6].

CO2 concentration can be reduced in large amounts relatively to other as it is mainly

emitted by point sources (power plants and industrial units) [2]. There are different

mitigation techniques to reduce CO2 concentration, which includes energy efficiency

improvements, the switch to less carbon-intensive fuels, nuclear power, renewable en-

ergy sources, enhancement of biological sinks and CCS (CO2 capture and storage) [7].

CCS has the potential to reduce overall mitigation costs and increase flexibility in

achieving greenhouse gas emission reductions [7].

Geothermal energy offers clean, consistent, reliable electric power with no need for

grid-scale energy storage, unlike most renewable power alternatives [10]. 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 [5]. 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 [9].

CO2 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 [12]. Coupling CCS with geothermal energy production can improve

the economic viability of CCS [10] with an advantage of favorable properties of super

critical CO2 (SCCO2) as [9],

• The large expandability of CO2 which increase the buoyancy forces and thereby

reduce the power consumption of the fluid circulation.

• The lower viscosity of CO2 which yields in larger flow velocities.

• CO2 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 CO2 has begun recently and

this study summarizes the up to date research on CO2 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 CO2

as a working fluid ?

1.3 Report flow 3

• The performance of CO2 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 CO2 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 SCCO2-HDR. It

then summarizes the research of Pruess and others on EGS systems working with CO2

plume approach. The concept introduced by Randolph of a CO2-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 CO2-water

mixture introduced by Salimi and Wolf and a review of a recently introduced hybrid

two-stage energy recovery approach to sequestrate CO2 and produce geothermal energy.

At last it gives a base line for the future work to be based on this literature review.

Chapter 2

Literature review

4

2.1 Supercritical CO2 as working fluid in EGS system 5

2.1 Supercritical CO2 as working fluid in EGS sys-

tem

2.1.1 The Super Critical CO2 - Hot Dry Rock (SCCO2 -HDR)

concept

The SCCO2-HDR concept uses supercritical CO2 as the heat transfer fluid, the heat

contained in the SCCO2 is transferred to the working fluid on the surface to run a

turbine.

This concept uses SCCO2 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).

2.1.2 Advantages of using SCCO2

The use of SCCO2 as the working fluid seems less beneficial when comparing its heat

capacity with water but under HDR reservoir conditions the viscosity of SCCO2 is

only 40 % that of water [3]. Table 2.1 compares the different properties for SCCO2

to water across a 4 km deep HDR reservoir for injection pressure of 30 MPa and it

concludes that using SCCO2 as the geo fluid provides a 50% increase in the mass flow

rate across the HDR reservoir as compared to water.

Circulating Fluid SCCO2 Water

Temperature ◦ C 260 260

Pressure MPa 56.5 55.7

Density kg/m3 520 835

Viscosity kg m−1 s−1 474 × 10−7 1162 × 10−7

Density/Viscosity 1.10 0.72

Ratio SCCO2/Water 1.53

Table 2.1: Comparision of average fluid Properties ( Across an HDR reservoir at 4 km

for injection pressure of 30 MPa [14]

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 CO2 is not a

solvent for inorganic material found in the deep formation, it is possible to operate a

geothermal reservoir with SCCO2 at high temperatures without the problem of silica


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 SCCO2 is used

the pore fluid dissolves in the SCCO2 leaving behind a small amount of precipitate

within the micro crack pore structure [3].

2.1.3 Concept of HDR (EGS) system

The SCCO2-HDR concept works in two stages

1. Creation of an engineered HDR reservoir by using SCCO2 as a fracturing fluid.

2. Circulation of the SCCO2 as a heat extraction fluid.

Creation of an engineered HDR reservoir is done by injecting SCCO2 at rates in the

range of 20 to 40 kg s−1 [3] 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 CO2-water mixture [8], with passage of time the fluid will be the

CO2 phase. Working on the concept of Brown, Fouillac [1] indicated that there will be

three zones during the reservoir development.

1. Core zone ( single phase dry supercritical CO2)

2. Surrounding zone (Two Phase CO2-water mixture)

3. Outer zone (Single Phase water with some dissolved CO2)

After the creation of the reservoir the pure SCCO2 circulates in the close loop to

extract heat while some amount of CO2 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/cm3) between the hot fluid rising from production well and the cold fluid in the

injection well creating a significant buoyant drive across the reservoir.

2.1.4 CO2 sequestration

Brown [3] 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 CO2 which is the amount

produced by a 10 MW power plant, this amount will be equivalent to the 100,000 ton

per year.


2.1.5 Model setup and numerical simulation

Different researchers have tested different model setups to analyze and compare the

working of EGS systems with CO2 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 [8]

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 [9] analyzed two

different conditions,

• A water system.

• A CO2 system.

Spycher [13] analyzed anhydrous CO2 injection into the water saturated reservoir. In

both studies the simulations were performed with the TOUGH2 simulator with the

ECO2N fluid property module.

Preuss [9] 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.

2.1.6 Results and recommendation

This paragraph will summarize the performance of the EGS system working with the

SCCO2 as a working fluid based on different studies.


Reservoir thickness 4 km

Mean geothermal gradient 60 ◦C km−1

Reservoir rock temperature 260 ◦C

Mean reservoir Porosity (After reservoir creation) 0.9 × 10−4

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 [3]

Simulation done by Preuss in 2007 [8] concludes that initially the heat extraction

rates are approximately 50 % larger with CO2 in comparison to water. The difference

becomes smaller with time, due to the more rapid thermal depletion when using CO2.

Mass flow rates in the CO2 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 CO2 more than compensate for the smaller density and specific heat of

CO2. 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 CO2 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 CO2 viscosity does not

change in this magnitude with temperature.

For the linear flow geometry the heat extraction rate for CO2 is 15% larger compared to

water, the reason for this difference as compared to the five well arrangement described

by Preuss [9] 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 [9] suggested that 1 kg s−1 MW−1, or 1

t/s/1.000MW will be sequestrated.

Spycher [13] studied the water plume break through after the injection of CO2, he

concluded that the production of a free aqueous phase from an EGS operated with

CO2 will occur for only a limited time (a few years), he also found that the dissolved

water will persist in the CO2 production stream for decades. His simulation results are

concluded in Figure 2.3


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. [8]

Figure 2.3: Simulated rate and composition of produced fluid [13]

2.2 CO2 storage with geothermal extraction in natural permeable, porousgeological formation (CO2 Plume geothermal (CPG) system ) 10

2.2 CO2 storage with geothermal extraction in nat-

ural permeable, porous geological formation

(CO2 Plume geothermal (CPG) system )

2.2.1 The CO2-plume geothermal (CPG) concept

The research summarized in the previous chapter was related to the SCCO2 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 [10] is summarized, in which SCCO2 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 CO2 sequestration then EGS

system [10]. He differentiated this approach from EGS and refers to it as CO2-plume

geothermal (CPG) system.

In CO2-plume geothermal (CPG) concept the CO2 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

CO2 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) [10]


Randolph’s [10] research is the extension of Preuss [8] research, same model setup of

a five well arrangement is used, see Figure 2.1. In this work first EGS system working

with SCCO2 is simulated and then the porous media system working with SCCO2.

The porous medium in the domain is homogeneous with a permeability of 5 × 10−14m2


Geological Formation

Reservoir thickness 305 m

Well separation 707.1 m

Permeability 5 × 10−14m2

Porosity 0.20

Rock grain density 2650 kg/m2

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 km2

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 [10]

and a porosity of 0.2. The domain is a two dimensional horizontal plain. The grid is

equidistant with a discretization length of 70.71 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 5 × 10−14 m2 for the permeability was used for both

reservoirs. Considering CO2 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

ECO2N.

2.2.3 Results and recommendations

Research done by Jimmy B. Randolph [10] concludes that heat extraction rates de-

creases with time as the reservoir heat is depleted and the temperature at the pro-

duction 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 [9] 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.


Case Heat extraction rate (25 year average) MW

EGS system 47

Deep Reservoir 62.6

Shallow Reservoir 64.1

Table 2.4: Simulation result [10]

25 years of simulation shows that 7% of the CO2 can be permanently sequestered in

the reservoir (which is greater than the finding of the Preuss [9] in EGS i.e 5%) which

makes a total amount of CO2 sequestrated of 2.0 × 107 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 CO2 sequestered whereas the deep reservoir (temperature = 100 ◦C, reservoir

depth = km) has net revenue of 5.9 $U.S.A per ton CO2 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 SCCO2 and what will be done with the brine extracted from the produc-

tion (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 CO2 sequestration in permeable soil because it is much cheaper than

EGS and do not induce seismic activities.

2.3 ”Negative saturation”(NegSat) solution approach 13

2.3 ”Negative saturation”(NegSat) solution ap-

proach

Salimi and Wolf [11] in their work come up with another concept of co injecting CO2-

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 CO2-water

mixture into a geothermal reservoir.

2.3.1 The concept of ”Negative saturation” (NegSat) solution

approach

Injection of CO2 at a high rate can have negative effects like drying out the reser-

voir and over pressurizing the aquifer, which can lead to fracturing and therefore also

to leakage [11] of CO2. Salimi and Wolf proposed to inject moderate amounts of a

mixture of CO2 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

CO2 injection which avoids confining the CO2 to the upper part of the reservoir hence

decreasing the leakage risk via the cap rock [11].

As this concept involves the injection of a CO2-Water mixture so phase disappearance,

appearance as well as the phase transition between sub cooled and super critical behav-

ior is a problem in model formulation, therefore they formulated the NegSat solution

approach for non-isothermal compositional two-phase flow. This approach gives a uni-

form system of equations for the entire reservoir that properly deal with different phase

states of the reservoir without changing the primary variables and thermodynamic-

constraint conditions.

Formulating such a situation the NegSat solution approach assumes a cold mixed CO2-

water injection into a geothermal reservoir, in the reservoir two phases could coexist

at most (a CO2-rich phase and a water-rich phase), therefore the equation of single-

phase 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 postu-

lates the equivalent saturation is defined as a limiting parameter to control appearance

and disappearance of a phase [11],

• 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.


• 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 Sg is called the extended gas saturation, given by

Sg=zi−xilxig−xilg

i=1,2,3....

zi = Mole fraction at specfic time and space

xil = Mole fraction of liquid

xig = Mole fraction of gas

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 353.15 ◦C

Injection temperature 293.15 ◦C

Maximum water-injection rate 0.04167 m3/s

Rock grain density 2650 kg/m2

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 (Nx x Ny)

Table 2.5: Typical reservoir condition assumed for the study [11]



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 CO2-water is done through out the reservoir. In the model CO2

behave as a non ideal fluid due to high pressure and temperature [11]. Therefore

Peng-Robinson-Stryjek-Vera equation of state with the modified Huron-Vidal second-

order mixing rule is formulated to define non ideal behavior of CO2 (see appendix for

the relationships used to describe different parameters).

The discretization of the reservoir is 23× 35 cells. Table 2.5 shows the input date for

simulation and for the following cases system was analyzed ,

• Case 1: CO2 mole fraction of 0.02 (or about 49.9 kg of CO2 per t of water),

injection in a homogeneous permeability and porosity field.

• Case 2: CO2 mole fraction of 0.02 (i.e same as in case 1), injection in the hetero-

geneous permeability and porosity field.

• Case 3: CO2 mole fraction of 0.03, injection in the heterogeneous permeability

and porosity field.

• Case 4: CO2 mole fraction of 0.2, injection in the heterogeneous permeability

and porosity field.


For Case 1 the extended gas saturations are all negative (0.0213 < Sg <0.0011) indicat-

ing the absence of a gas (CO2-rich) phase for 30 years of simulation time. Therefore,

Figure 2.5a describes single-phase aqueous regions. The temperature increases mono-

tonically 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 CO2 for 30 years sim-

ulation.

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 CO2 is completely dissolved into the aque-

ous 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 perme-

able 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 CO2 storage of Case 2 is higher than that of Case 1 by


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 CO2 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: CO2 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 > Sg > 0) with a gas phase mainly super critical CO2

and an aqueous phase with mainly water in the high permeable zones.

• A two-phase region of a sub cooled (liquid) CO2-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, CO2 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 maxi-

mum value of 0.2549 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

CO2 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 CO2 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 thermal-

diffusion coefficient of the reservoir rock and for the zones with high values of the

extended gas saturation the overall CO2 mole fraction is also high.

For Case 4 CO2 mole fraction is 0.20 and injection is done in the heterogeneous per-

meability 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 CO2 plume develops along the highly permeability streaks (i.e. the

progress of CO2 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


into the reservoir. This is attributes to the fact that as the amount of CO2 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-CO2-mole-fraction distribution at t = 6.5 yr. The overall

CO2 mole fraction reaches a maximum of z = 0.7621 at t = 6.5 yr, which are much

larger than the overall injected value of z = 0.20 which shows the CO2 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 CO2 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

CO2 storage. Also the character of heterogeneity and the mobility ratio control the

displacement regime. For the heterogeneous-reservoir structure considered here, a tran-

sition 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 CO2 storage and energy extraction. For all cases analyzed the

compositional wave that runs a head of the thermal wave, limits the period of simulta-

neous CO2 storage and heat extraction to the end of the project. For overall injected

CO2 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 CO2 mole fractions larger than 0.1.


(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 dis-

tribution for case 1 t=30yr

(f) Overall CO2 mole fraction dis-

tribution for case 2 t=30yr

Figure 2.5: Simulation result done by Hamidreza and Karl-heinz wolf [11]


(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 CO2 mole fraction dis-

tribution for case3 t=51yr

(f) Overall CO2 mole fraction distri-

bution for case4 t=6.5yr

Figure 2.6: Simulation result done by Hamidreza and Karl-heinz wolf [11]


(a) Cummulative heat extraction

and CO2 for case1 and case2.

(b) Cumulative heat-energy pro-

duction and energy invested ver-

sus maximally stored CO2 at CO2

breakthrough either in the aqueous

or in the gaseous phase

Figure 2.7: Cumulative heat-energy production and CO2 storage [11]

2.4 Two stage integrated geothermal-CCS approach 21

2.4 Two stage integrated geothermal-CCS ap-

proach

Buscheck [4] introduces a hybrid two-stage energy-recovery approach to sequestrate

CO2 and produce geothermal energy by integrating geothermal production with CO2

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 CO2 injection is the working fluid for energy recovery. During stage

two, which begins as CO2 reaches the production wells; co produced brine and CO2 are

the working fluids. This chapter summarizes the result of a hybrid two-stage energy-

recovery approach.

Figure 2.8: An actively managed, two-stage, integrated geothermalCCS system, using

binary-cycle power [4]

2.4.1 The concept of a hybrid two-stage energy-recovery ap-

proach

Introducing this approach Buscheck kept in mind the concept of Active CO2 Reservoir

Management (ACRM) which combines brine extraction and treatment and residual-

brine re-injection with CO2 injection. It is found that if the reservoir has sufficient

trapping characteristics, brine disposition options, reasonable formation temperature,

proximity to CO2 emitters then Active CO2 Reservoir Management can be applied

to the separate formations with one formation being utilized for CO2 storage and a

separate formation being utilized for the purpose of brine re injection (see Figure2.9).

This approach is named ”Tandem-formation ACRM.”


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. [4]


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 con-

dition 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

0.7071, 1.0, 1.4142, 2.0, and 2.8284 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 reser-

voir thickness 125m and 250m respectively is run to see the effect of flow rate.


Property Storage formation Caprock seal

Horizontal and vertical permeability (m2) 1.0 × 10−13 1.0 × 10−18

Pore compressibility Pa−1 4.5 × 10−10 4.5 × 10−10

Porosity 0.12 0.12

van Genuchten (1980) m 0.46 0.46

van Genuchten α Pa−1 5.1 × 10−5 5.1 × 10−5

Residual supercritical CO2 saturation 0.05 0.05

Residual water saturation 0.30 0.30

Table 2.6: Typical Reservoir Conditions Assumed [4]

Figure 2.10: Reservoir specification for simulation



The aim of this study was to achieve pressure relief and delaying the breakthrough time

of CO2 to increase the life time of brine production and maximize the CO2 storage [4].

As the pressure relief from brine production increases with decreasing spacing between

the CO2 injectors and brine producers, while CO2 breakthrough time increases with

well spacing therefore various conditions are investigated to tradeoff between achieving

pressure relief, while delaying CO2 breakthrough.

First the 12 well arrangement with 8 injection and 4 central production wells is sim-

ulated. The result shows that this type of arrangement increases CO2 storage due to

following reasons,

• Producing from the center is an effective means of controlling the influence of

buoyancy on CO2 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 CO2) pro-

duction rate of 760 kg/s is observed for injection of 760 kg/s of CO2.

The second approach includes the 16 well arrangement with 8 injection and 8 produc-

tion wells. The result of the simulation is summarized in Figure 2.12. 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 CO2 reaches production well between 30 to 100 years, hence the small temper-

ature decline during that time frame corresponds to the arrival of the slightly cooler

CO2 plume. Figure 2.12c represents the cumulative net CO2 storage, which shows that

720 million tons of CO2 are stored for the 30 year simulation before the breakthrough

of CO2 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 2.13. During

this simulation the effect of following conditions are analyzed,

• The Effect of different well spacings ( i.e 0.7071, 1.0, 1.4142, 2.0, and 2.8284 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.


Figure 2.14 shows the reservoir geothermal and CO2 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 0.7071,

1.0, 1.4142, 2.0, and 2.8284 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 CO2 that is permanently

stored is 10.2, 21.3, 40.8, 65.0, and 85.9 percent for well spacing of 0.7071, 1.0, 1.4142,

2.0, and 2.8284 km, respectively and at 100 years, the percentage of injected CO2 that

is permanently stored reduces to 3.3, 7.2, 14.6, 27.7, and 46.7 percent for well spacings

of 0.7071, 1.0, 1.4142, 2.0, and 2.8284 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 2.8284 km with reservoir thickness of 250 m.

• The well spacing of 2.8284 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 CO2 for both thickness is same for 10 years then the ratio of cumu-

lative net CO2 storage approaches two, directly proportional to the relative reservoir

thickness.


(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 [4]


(a) Production well temperature (b) Mass fraction of CO2 in the total

fluid production

(c) Cumulative net CO2 storage

Figure 2.12: Geothermal and CO2-sequestration performance is shown for five cases,

with geothermal heat fluxes of 50, 75, and 100 MW/m2, and for reservoir bottom

depths of 2500 and 5000 m [4]



fluid production


Figure 2.13: Geothermal and CO2-sequestration performance is shown for 5-spot well

patterns, with a geothermal heat flux of 75 MW/m2 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 [4]



fluid production


Figure 2.14: Geothermal and CO2-sequestration performance is shown for 5-spot well

patterns, with a geothermal heat flux of 75 MW/m2 and a reservoir bottom depth of

2500 m. Histories are shown for the first 100 years.Area shows the area of thermal

footprint [4]



fluid production


Figure 2.15: The geothermal and CO2-sequestration performance is plotted for 5-spot

well patterns with 2.8284-km well spacing and 2 indicated reservoir thicknesses. These

cases have a geothermal heat flux of 75 MW/m2 and a reservoir bottom depth of 2500

m [4]

Chapter 3

Future scope and conclusion

31

3.1 Summary and Future scope 32

3.1 Summary and Future scope

This report compiles the various concepts for the coupling of CCS and geothermanl

energy, each of the concept previously explained has advantages and shortcoming in

them. This chapter will give a summary, comparison between different approaches and

future scope of the work.

The concept of using SCCO2 as a working fluid in the geothermal power plant coined

by Brown [3] in 2000 became base for the research on this topic. His findings showed

that using SCCO2 instead of water in a closedloop HDR system offers three significant

advantages,

• The large buoyant force due to high density difference between cold and hot

SCCO2.

• The inability of SCCO2 to dissolve mineral.

• Operation of HDR reservoir on high temperatures.

Beside these advantages there is a possibility of CO2 sequestration, Brown’s [3] studies

shows that 30 MPa of CO2 can be sequestrate using the same reservoir condition as of

his study. His study is preliminary study of the SCCO2-HDR concept, as it assumes

the single-fluid system and limited data to define the reservoir condition therefore there

is a possibility to further evaluate the concept for different permeability, different well

arrangement, and also consider insitu brine in the system.

Preuss [9] evaluates the concept of Brown by doing an numerical simulation, consider-

ing the insitu brine and two different well arrangement (i.e Linear and five spot well

arrangement). His modeling studies indicates that CO2 would achieve heat extrac-

tion at larger rates than aqueous fluids. The development of an EGS-CO2 reservoir

would require replacement of the pore water by CO2 through persistent injection. He

found that in a fractured reservoir, CO2 breakthrough at production wells would oc-

cur rapidly, within a few weeks of starting CO2 injection. Subsequently a two-phase

water-CO2 mixture would be produced for a few years, followed by production of a

single phase of SCCO2. Even after single-phase production conditions are reached, sig-

nificant dissolved water concentrations will persist in the CO2 stream for many years.

Preuss [9] did not considered the chemical interactions between SCCO2 and rock min-

erals so further research is possible to understand the geochemical reactions in the

EGS-CO2 reservoir. He also recommends to go beyond theoretical estimations and

paper studies, and begin to design, implement, and analyze practical tests in the lab-

oratory and the field.

This report also includes the reference to the work done by Spycher [13] but does not

include details about the phase partitioning model for high temperatures and its ap-

plication in simulation of CO2-EGS system so it can be studied in detail to see how

phase partitioning between CO2 and formation waters is done in the CO2-EGS system.

Randolph [10] introduces the concept of CO2-plume geothermal system (CPG)in which


he injected SCCO2 in homogeneous porous media instead of EGS system. He used 5

spot well arrangement, permeability of 5 × 10−14 m2 and two reservoirs one 4 km deep

(deep reservoir) and a temperature of 150 ◦C , the second reservoir 1 km deep (shallow

reservoir) and a temperature of 100 ◦C. Comparing his results with the Preuss [9]

setup for EGS system, he found that the heat extraction rate is higher in both cases

(deep and shallow reservoir). 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 re-

quired until the reservoir is fully occupied with SCCO2 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 CO2 sequestration in permeable soil

because it is much cheaper than EGS [10] and do not induce seismic activities.

Salimi [11] work is the extension of randolph’s [10], he injects CO2-Water mixture in the

porous media and gives a numerical solution for phase appearance and disappearance.

He simulated the reservoir for different mole fraction and permeabilities. He concludes

it is beneficial to integrate heat-energy recovery and carbon sequestration with cold

mixed CO2-Water injection into a geothermal reservoir and Permeability and porosity

heterogeneities in a geothermal aquifer significantly influence both heat extraction and

CO2 storage. Hence, reservoir characterization plays an important role in assessing the

benefits of CO2 storage and energy extraction. His studies also include detail economic

analysis for evaluating the CCS-geothermal system, it is recommended to do detail

study of the economic analysis because this report do not address it.

Buscheck [4] introduces a hybrid two-stage energy-recovery approach to sequestrate

CO2 and produce geothermal energy by integrating geothermal production with CO2

capture and sequestration (CCS) in saline, sedimentary formations. His study shows

the effect of well configuration, well spacing, reservoir thickness and injection rate on

the CO2 sequestration and heat extraction. His result for 16-well configuration shows

greater than 2 billion tons of CO2 sequestration for 100 yr simulation, two orders

of magnitude greater than in the CPG example analyzed by Randolph [10].The two-

stage, integrated geothermal-CO2-storage approach uses highly idealized conceptual

model, Real reservoir systems will be heterogeneous, with the storage formation possi-

bly being compartmentalized, and with regions of lower permeability which will cause

early breakthrough of CO2 [4], it is recommended to do further research for reservoir

geospatial, and economic investigations of various permutations and extensions of this

approach.

Based on this literature review and recommendation by the researchers following rec-

ommendations can be given to do further research,

• Studies can be done to understand the chemical process in EGS system and

porous media.


• This report also includes the reference to the work done by Spycher [13] but does

not include details about the phase partitioning model for high temperatures and

its application in simulation of CO2-EGS system so it can be studied in detail

to see how phase partitioning between CO2 and formation waters is done in the

CO2-EGS system.

• 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 SCCO2 and what will be done with the brine extracted from the

production (can it be used directly or does it need to be treated).

• This report includes the model setup and results of the NegSat approach but do

not includes the details about how this approach is formulated and implemented

in the model,it will be good to look the formulation and implementation of this

approach.

• Reservoir characterization plays an important role in assessing the benefits of

CO2 storage and energy extraction. It is therefore recommended to analyze the

different approach using different reservoir properties.

• Most of the studies includes the homogeneous reservoir condition which is highly

idealized. Studies can be done to study the effect of heterogeneous reservoir on

the break through of CO2 plume.

• Detail analysis for the economical viability of the different approaches can be

done.

• Well configuration and spacing enhances the CO2 and energy extraction, so dif-

ferent configuration can also be studied.

3.2 Concluding remarks 35

3.2 Concluding remarks

Different studies done till now suggest that the CO2 as working fluid is feasible but

still it has to be worked out that which configuration can make this process the most

feasible and publicly acceptable. This is the time to apply this concept on different

research site and come up with more data set to encourage investors to commercialize

this approach.Cost is the key factor in applying this approach, so more work can be

done to find configurations which can be applied practically.

Bibliography

[1] ] Fouillac, C., B. S. S. G. and Czernichowski-Lauriol, I. Could sequestration of

co2 be combined with the development of enhanced geothermal systems? Third

Annual Conference on Carbon Capture and Sequestration, 2004.

[2] Bielinski, A. Numerical simulation of CO2 sequestration in geological formations.

Inst. fur Wasserbau, 2006.

[3] Brown, D. A hot dry rock geothermal energy concept utilizing supercritical co2

instead of water. In Proceedings, S. 233–238, 2000.

[4] Buscheck, T., Chen, M., Sun, Y., Hao, Y., and Elliot, T. Two-stage, integrated,

geothermal-co2 storage reservoirs: An approach for sustainable energy production,

co2-sequestration security, and reduced environmental risk. Forschungsbericht,

Lawrence Livermore National Laboratory (LLNL), Livermore, CA, 2012.

[5] (ed.), M. The future of geothermal energy. Forschungsbericht, Massachusetts

Institute of Technology, Cambridge, MA, 2006.

[6] Houghton, J., Meiro Filho, L., Callander, B., Harris, N., Kattenburg, A., and

Maskell, K. Climate change 1995: The science of climate change: contribution of

working group I to the second assessment report of the Intergovernmental Panel

on Climate Change, Band 19390. Cambridge University Press, 1996.

[7] Metz, B., Davidson, O., De Coninck, H., Loos, M., and Meyer, L. Ipcc special re-

port on carbon dioxide capture and storage. Forschungsbericht, Intergovernmental

Panel on Climate Change, Geneva (Switzerland). Working Group III, 2005.

[8] Pruess, K. Enhanced geothermal systems (egs) comparing water with co2 as heat

transmission fluids. 2007.

[9] Pruess, K. Enhanced geothermal systems (egs) with co2 as heat transmission

fluid–a scheme for combining recovery of renewable energy with geologic storage

of co2. 2010.

[10] Randolph, J. and Saar, M. Coupling carbon dioxide sequestration with geothermal

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BIBLIOGRAPHY 37

[11] Salimi, H. and Wolf, K. Integration of heat-energy recovery and carbon seques-

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Appendix A

Typical reservoir conditions

Reservoir Depth 305 m

Reservoir rock temperature range 150-200 ◦C

Down hole over Pressure 10 bar

Reservoir Pressure 200 bar


Well arrangement Five well one injection and four production

Interfacial Tension 0.028 N m−1

Pcap(Dry out regions) −1000 bar

Simulator TOUGH2,ECO2 N

Table A.1: Typical reservoir condition assumed for the study [10] [9]

38

39

Reservoir Depth 305 m

Fracture spacing 50 m

Capillary pressure (van Genuchten 1980) λ 0.4438

Strength coefficient for fractures P0,f 0.0416 bar


Strength coefficient for matrix Po,m 6.734 bar

Fracture domain

Volume fraction 2 %

Intrinsic porosity φf 50 %

Fracture network permeability Kf 50 × 10−15 m2

Matrix domain

Volume fraction 98 %

Intrinsic porosity φm 1 %

Matrix permeability Km 1.9 × 10−19 m2

Thermal Parameters

Rock grain density ρR 2650 kilogram/m3

Rock specific heat cR 1000 J kg−1 ◦C−1

Rock thermal conductivity K 2.1 W m−1 ◦C−1

Initial Condition

Reservoir fluid All water

Temperature Tin 200 ◦C

Pressure Pin 200 bar

Production/Injection

Pattern area ”A” 2 km2

Injector-producer distance ”L” 707.1 m

Injection temperature Tinj 20 ◦C

Injection pressure (downhole)Pinj Pin+10 bar

Injection pressure (downhole)Ppro Pin-10 bar

Table A.2: Typical reservoir condition assumed for the study [13]

Appendix B

Equations

Krw = (1 − Sg)4 (B.1)

Krg = S2g (1 − (1 − Sg)

2) (B.2)

Pc = σgl2√ϕ/k(0.51/λ)(1 − Sg)

−1/λ (B.3)

µg = 1.6128 × 10−3 − 9.0436 × 10−6T + 0.0135 × 10−6T 2 − 1.9476 × 10−12T 3 (B.4)

µw = 2.414 × 10−5 × 10(247.8/(T − 140)) (B.5)

Cp,CO2 = 45.369 + 8.6881 × 10−3 − 9.619 30 × 106 × T−2 (B.6)

Cp,H2O = 276.37 + 2.0901T − 8.125 × 10−3T 2 − 0.014 116 × 10−3T 2 − 9.3701 × 10−9T 4

(B.7)

40

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