P.7 Kaufmann

Pipeline Technology Conference 2008

P.7 Kaufmann Contact + Abstract + Paper 1/28

Topic CARBON DIOXIDE TRANSPORT IN PIPELINES - UNDER SPECIAL CONSIDERATION OF SAFETY-RELATED ASPECTS

Author Dr. -Ing. Klaus-Dieter Kaufmann Presenter Dr. -Ing. Klaus-Dieter Kaufmann Organization ILF Beratende Ingenieure GmbH, Werner-Eckert-Straße 7, D-81829

Munich Country: Germany Abstract: The capture of CO2 from power plants, its transportation through pipeline systems and its long term deposition in suitable storage reservoirs both on and offshore appears to be an effective method for preventing CO2 from entering the atmosphere, allowing to mitigate adverse greenhouse gas effects due to anthropogenic activities.

Depending on the process or power plant application, three main approaches to capturing the CO2 generated from a primary fossil fuel (coal, natural gas or oil), bio-mass, or mixtures of these fuels are presently considered: Post-combustion capture systems, Pre-combustion capture systems and Oxyfuel combustion capture systems. The production of SO2 or H2S as unintended and potentially dangerous by-products is also considered.

While existing CO2 pipelines in U.S.A. with predominantly relatively pure CO2 streams are running generally through sparsely populated areas, CO2 pipelines from projected fossil-fuelled power plants containing H2S and SO2 as ‘impurities’ may need to cross densely populated areas, for instance in Western Europe.

The availability of reliable calculation methods for the most relevant CO2 properties (density and viscosity), for the influence estimation of impurity concentrations on phase behavior and calculation methods for determination of the optimum techno-economic pipeline diameter, are therefore a pre-requirement for a safe, environment-friendly and economic pipeline design.

A potential new pipeline route has to be examined within the frame of a risk analysis to identify hypothetical hazard scenarios and to estimate potential consequences with regard to severity and estimated frequency. The examination covers the hypothetical case of leakage, evaluates the time-dependent CO2 leak rate (source term), estimates the CO2 outflow / jet formation in the immediate vicinity of the leak, and estimates the dispersion of cold CO2 clouds depending on atmospheric and topographic conditions like hilly terrain, depressions and big buildings.

The integrated approach which is partially an iterative process starts with the investigation of a suitable route avoiding exposed areas and close proximity to inhabited areas, under consideration of the special CO2 and impurity related properties and local conditions. The study continues with selection of appropriate



pipe material, wall thickness (design factor), burial depth and optimized number and locations of valve stations, increased quality control during pipe manufacturing, weld control and supervision during construction works. The study additionally refers to measures for leak detection and fast pipeline shutdown including quick closure of sectionalizing valves, as well as implementation of an integrated leak response plan in order to minimize the potential consequences of a hypothetical CO2 leakage to people, environment, assets and project reputation. These measures will be completed by integrated procedures and training measures for the pipeline operators and by pipeline maintenance measures including running of so-called intelligent pigs.

Nevertheless, there remain some challenging engineering tasks like comparison of dispersion models versus CO2 test release results, definition of measures to avoid / reduce potential rupture propagation, investigations referring to potential influence of H2S and H2 impurities on stress cracking promotion, potential interaction of co-absorbed H2S and SO2 (S2 generation) and investigations (based on reported transportation system failures) to minimize the remaining pipeline risk to a level “as low as reasonably practicable” (ALARP).



TABLE OF CONTENTS

1 INTRODUCTION 4

2 CO2 SEPARATION FROM POWER PLANTS AND MAX. LEVEL OF IMPURITIES 5

3 PHYSICAL PROPERTIES OF THE CO2 TRANSPORTED 10

4 TECHNO-ECONOMICAL DESIGN OF CO2 PIPELINES 12

5 DEHYDRATION AND PIPELINE MATERIAL SELECTION 15

5.1 Dehydration 15

5.2 Pipe Material Selection 15

6 HEALTH RELATED ASPECTS OF CO2, H2S AND SO2 16

7 SAFETY RELATED ASPECTS OF CO2 TRANSPORT IN PIPELINES 17

7.1 Overview 17

7.2 Main Influences on Pipeline Leak Frequencies 18

7.3 Most Probable Hazard Scenario Expected 18

7.4 Basic Data and Correlations for the ‘Source Term’ 19

7.5 Dispersion Calculation for CO2 Considering Heavy Gas Behavior 20

7.6 General Safety Aspects to be Considered for CO2 Pipelines 21

7.7 Risk Calculation for CO2 Pipelines 23

7.8 Measures for Risk Minimization 25

8 FURTHER INVESTIGATION DEMAND 27

9 REFERENCES 27



1 INTRODUCTION

Approximately 60% of the global carbon dioxide emissions (about 23.5 Gt in year 2000) is attributed to large stationary sources (Power Plants). The main clusters of emissions are located in North America, Europe (northwest region), East Asia (east coast of China) and South Asia (Indian sub-continent) /1/.

The capture of CO2 from power plants, its transportation through pipeline systems and its long term deposition in suitable storage reservoirs both on and offshore appears to be an effective method for preventing CO2 from entering the atmosphere, allowing to mitigate adverse greenhouse gas effects due to anthropogenic activities. The distances between CO2 sources and sinks can vary considerably and in some cases will amount to several hundreds of kilometres.

Demonstration projects are underway worldwide to investigate the feasibility of commercial scale carbon capture and storage (CCS) technology. Some major carbon capture facilities already exist for example in Sleipner (Norway), Weyburn (Canada), In Salah (Algeria) and two projects in Germany (RWE IGCC & Ketzin).

Pipeline systems for the safe transportation of oil, gas and speciality products are already widely accepted around the world as a means for the long distance transfer of large quantities of these products. It is also noted that there exists commercial scale pipeline systems for the transportation of CO2 mainly from enhanced oil recovery (EOR) projects in U.S.A. (approx. 2,600 km in 2002) which have been operated for about 30 years /1/.

Despite this, there are two significant differences between existing CO2 pipelines installed in U.S.A. and those foreseen for projected carbon capture and storage projects elsewhere:

a) Existing CO2 pipelines in U.S.A. are running generally through sparsely populated areas, while in Western Europe, potentially densely populated areas may need to be crossed

b) CO2 streams from natural CO2 storage fields (within the frame of EOR projects) in U.S.A. are predominantly relatively pure CO2 streams, while CO2 streams from projected fossil-fuelled power plants will contain small amounts of co-absorbed components like H2S and SO2.



Safety related aspects are therefore of high importance and represent, in addition to the techno-economical aspects, a special focus of this presentation.

Figure 1-1 shows the basic scheme for CO2 capture, pipeline transportation and storage options.

Figure 1-1: Basic Scheme of CO2 Capture, Pipeline Transportation and Storage Options

CO2 Capture Facilities CO2 Pipeline System CO2 Storage

Enhanced Oil Recovery

Pre Combustion

Saline AquifersEnhanced Coal Bed Methane

Depleted Oil and Gas Reservoirs

Head StationPipeline Sections

Line Valve StationsIntermediate Transport

Station(s)Terminal Station

Oxy-Fuel Systems

Post Combustion

2 CO2 SEPARATION FROM POWER PLANTS AND MAX. LEVEL OF IMPURITIES

Figure 2-1 shows the basic scheme of a typical conventional power plant. Heat and power is generated in a boiler plant with steam turbines, optional selective catalytic reduction (SRC) for nitrogen oxides (NOx), particulate collection and cooling, and optionally, flue gas desulphurization (FGD). Carbon dioxide (CO2) leaves the power plant via the stack into the environment at near atmospheric pressure with large proportions of diluents and contaminants. The capture of CO2 in this condition (a concentration of around 8%) is both very expensive and requires substantial, additional expenditure of energy.

Figure 2-1: Basic Scheme of a Typical Conventional Power Plant

Typical Conventional Power Plant N2, O2, H2O,CO2*)

to Stack

CoalGas

Biomass

AirAsh CaSO4

to Disposal

Elaborated / Simplified from IEA GHG Report (8/2004) ILF

Power and Heat Generation

Selective Catalytic Reduction

(NOx Removal)

Particulate Collection and

Cooling

Flue Gas Desulphuri-

zation



Depending on the process or power plant application, there are three main approaches to capturing the CO2 generated from a primary fossil fuel (coal, natural gas or oil), bio-mass, or mixtures of these fuels:

a) Post-combustion systems b) Pre-combustion systems c) Oxyfuel combustion systems.

Figure 2-2 shows the basic scheme of a typical post-combustion CO2 capture process with co-absorption of sulphur dioxide (SO2) in a common liquid solvent process. CO2 and SO2 impurities are compressed to pipeline transportation pressure, dehydrated e.g. by triethylene glycol (TEG) in an intermediate compression stage, and injected into the CO2 pipeline. The CO2 stream contains SO2 and O2 /12/ as major impurities.

Figure 2-2: Basic Scheme of a Typical Post-Combustion CO2 Capture Process with Co-Absorption of Sulphur Dioxide (SO2)

Typical Post-Combustion Process N2, O2, H2Oto Stack

Alternative 2:

Flue Gas

CoalGas

Biomass(probably required)

AirAsh


CO2 Pipeline(co-absorbed SO2)

Without SO2 Removal Upstream the CO2 Absorption


Selective Catalytic Reduction

(NOx Removal)

Particulate Collection and

Cooling

CO2-Absorber & Regenerator,

(SO2 co-absorbed)

CO2 Compression(SO2 co-absorbed)

TEG-Dehydration

Figure 2-3 shows the basic scheme of a typical pre-combustion CO2 capture process with co-absorption of hydrogen sulphide (H2S) in a common liquid solvent process.

Primary fuel is processed to generate synthesis gas (H2, CO2, CO), which is reformed to mainly CO2 and H2; while H2 is used for power and heat generation, the CO2 including H2S impurities are compressed to pipeline transportation pressure, dehydrated, and injected into the CO2 pipeline. The CO2 stream contains H2S as major impurity (also H2 has to be considered in terms of how the properties of CO2 are affected /12/). The CO2 stream leaves the process at above atmospheric pressures which saves on compression investment costs and energy expenditure.



Figure 2-3: Basic Scheme of a Typical Pre-Combustion CO2 Capture Process with Co-Absorption of Hydrogen Sulphide (H2S) in a common liquid solvent process

Typical Pre-Combustion Process

Alternative 2:Without H2S Removal

N2, O2, H2Oto Stack

CO2 + H2S

Coal H2

Biomass

O2

SteamGas, Oil Air

Elaborated / Simplified from IEA GHG Report (8/2004) and mod.: only O2 blown into process (A. Brown) ILF

Gasification(H2+CO2+CO)

Reformer + Acid Gas Separation

(CO2 & H2S)


CO2 Pipeline(co-absorbed H2S)

CO2 Compression(H2S co-absorbed)

TEG-Dehydration

Finally, Figure 2-4 shows the basic scheme of a typical oxyfuel process with CO2 capture with co-absorption of sulphur oxides (SOx) and of nitrogen oxides (NOx).

Primary fuel is combusted in oxygen-rich atmosphere, flue gas is recycled from down-stream the particulate collection to combustion inlet. The CO2 with SOx and NOx impurities at above atmospheric pressures, which saves on compression costs and energy expenditure, is compressed to pipeline transportation pressure, dehydrated, and injected into the CO2 pipeline.



Figure 2-4: Basic Scheme of a Typical Oxyfuel Process with CO2 Capture with Co-Absorption of Sulphur Oxides (SOx) and of Nitrogen Oxides (NOx).

Typical Oxyfuel Combustion Process

Alternatives:Alternatives with NOx/SOx separation to be evaluated

95-99% O2 CO2 Compression

CO2 (+ SOx + NOx)

Flue Gas Recycle

Coal

Ash


CO2 Pipeline(co-absorbed SOx,

NOx)

Cooling and Water KO

Cryogenic Air Separation Unit (ASU)


Particulate Collection

CO2 Compression(SOx, NOx co-

absorbed)

TEG-Dehydration

If not anyway required, all the carbon capture processes mentioned above can have additional steps to adsorb the impurities like H2S and SO2, however, from the economic point of electrical energy production, it is advantageous to co-absorb these components into the CO2 stream /2/.

The following Figure 2-5 shows the maximum level of impurities that migh be produced in captured CO2 streams.



Figure 2-5: Maximum Level of Impurities Potentially Produced in Captured CO2 Streams

Component Concentration Component Concentrationmole-% mole-%

Hydrogen Sulfide H2S 3.4 Water H2O 0.3Sulphur Dioxide SO2 2.9 Carbon Monoxide CO 0.2Oxygen1) O2 1.9 Nitrogen Oxides NOx 0.14Hydrogen H2 1.8 Argon Ar 0.05Nitrogen N2 0.6 Methane2) CH4 traces1) Value for Membrane Process (Much lower for Other Priocesses)2) Value might be considerably higher for gas-fired power plants

Values from IEA GHG Report No. PH4/32 August 2004 (for Coal Fired Power Plants only) ILF

Maximum Level of Relevant Impurities in Captured CO2

The levels shown in Figure 2-5 can be used to define a worst-combination envelope for impurities potentially produced in CO2-streams from power plants equipped with carbon capture technology. The most relevant impurity expected in co-captured CO2 is sulphur either as H2S from integrated gasification combined cycle plants (IGCC) which use pre-combustion capture, or as SO2 from conventional steam plants which use post-combustion capture.

There are additional issues to be considered from:

a) additional requirements referring to the maximum admissible water content for internal corrosion protection

b) maximum H2S and SO2 concentrations from safety related aspects (hypothetical leakage case)

c) maximum allowable oxygen content from reservoir mechanical aspects (e.g. bacteriological aspects); the answer is to have a very tight control on the admissible oxygen content /12/

d) maximum allowable H2 and H2S concentrations with respect to potential influences on pipe material properties

e) potential interaction of H2S and SO2 impurities in CO2 streams which might undergo catalyzed Claus reaction and potentially could cause equipment blockages or plug reservoirs /2/.



3 PHYSICAL PROPERTIES OF THE CO2 TRANSPORTED

The following figures show the vapor pressure curve (Fig. 3-1), and further the density (Fig. 3-2) and the kinematic viscosity (Fig. 3-3) of pure CO2 as function of pressure and temperature, calculated with high-accurate property calculation routines /3,10/. Additionally, the diagrams show the typical process condition variations (black curves) of CO2 transport in a 24” land based pipeline system of assumed length of 300 km, able to transport 1,200 t/h CO2 originating e.g. from a 1,200 MWel power plant equipped with carbon capture technology.

As long as the pressure inside the CO2 pipeline system remains above the so-called critical point of CO2 (30.98 °C, 73.77 bar), the CO2 can be transported as single phase in the pipeline system which is a pre-condition for continuous operation at quasi-steady operating conditions. Transportation in the ‘liquid’ or in the ‘supercritical’ state (physically only a question of definition); is also known as transport in the ‘dense-phase’; in UK, from legislative aspects, transportation in the ‘supercritical state’ has to be avoided /12/). The typical transport density amounts to approximately 740-800 kg/m³ (see Fig. 3-2) and the typical kinematic viscosity (see Fig. 3-3) to approximately 0.08-0.09 cSt (mm²/s).

Figure 3-1: CO2 Vapor Pressure Curve and Phase / State Definition (also included are typical operating conditions of a CO2 pipeline system)

Vapor Pressure Curve and CO2 Phases

0

20

40

60

80

100

120

140

160

180

200

-80 -50 -20 10 40 70 100

Temperature (°C)

Pres

sure

(bar

)

liquid supercritical

gas

solid

Critical Point30.98 °C, 73.77 bar

Triple Point-56.6 °C 5.18 bar

Pipeline 24" (DN 600),300 km,1200t/h

ILF

(Vapor pressure curve calculated w ith FLUIDCAL Routines)



Figure 3-2: Density of CO2 as Function of Pressure and Temperature (typical

operating conditions ca. 740-800 kg/m³)

CO2 Density as Function of Pressure and Temperature

0

200

400

600

800

1,000

1,200

20 50 80 110 140 170 200

Pressure (bar)

Den

sity

(kg/

m³)

0 °C 10 °C 20 °C 30.98 °C 40 °C 50 °C 60 °C DEW BUB P IP E

ILF

Pipeline 24" (DN 600),300 km,1200t/h

0 °C

60 °C


0 °C

10 °C

20 °C

30.98 °C 40 °C 50 °C

Figure 3-3: Kinematic Viscosity of CO2 as Function of Pressure and

Temperature (typical operating conditions ca. 0.08-0.09 cSt (mm²/s))

CO2 Viscosity as Function of Pressure and Temperature

0.00

0.05

0.10

0.15

20 50 80 110 140 170 200

Pressure (bar)

Visc

osity

(mPa

s)

0 °C 10 °C 20 °C 30.98 °C 40 °C 50 °C 60 °C DEW BUB P IP E

ILF

Pipeline 24" (DN 600),300 km,1200t/h

60 °C


0 °C

10 °C

20 °C 30.98 °C 40 °C 50 °C

In order to estimate the influence of impurities in real CO2 streams on the transport properties, available literature /4/ has been evaluated. Figure 3-4 shows the increase of the critical pressure of CO2 streams with impurity concentration. As long as the amount of impurities remains moderate (e.g. 2.5 %), the pressure increase remains also moderate (< 5 bar). By corresponding increase of the operating pressure, single-phase transportation of the CO2 stream can thus be assured.



Figure 3-4: Increase of the Critical Pressure of CO2 Streams with Impurity Concentration

Increase of Critical Pressure of CO2 Streams with Impurity Concentration

0

5

10

15

20

25

0 2.5 5 7.5 10Impurity Concentration (%)

Pre

ssur

e In

crea

se

(bar

) N2

H2

NO2

5%N2+5%NO2

5%N2+5%CH4

Impurity

(Basis: Seevam/Race/Dow nie: J. Pipel. Engng., 3rd. Qu. 2007, pp. 140-141)

ILF

4 TECHNO-ECONOMICAL DESIGN OF CO2 PIPELINES

The optimized design of a CO2 pipeline system requires the determination of the optimum pipeline diameter. For this purpose, the specific transportation costs are determined as a function of assumed CO2 throughput and pipeline diameter values. The specific transportation costs are hereby calculated considering the annuity of the capital investment and the annual operating cost (mainly energy cost for transportation, and maintenance cost).

The techno-economically optimum diameter can then be determined from an optimization diagram as shown in Figure 4-1. The diagram shows e.g. that for transportation of annually 10 million tons (MTA) of CO2, a 24“ (DN 600) pipeline system would represent the optimum techno-economic solution. It has however to be considered that Fig. 4-1 shows only the ‚comparable‘ transportation cost comprising the main diameter-dependent cost factors. In case CO2 must be compressed at the head station from approx. atmospheric conditions to approx. 80 bar (theoretical intermediate reference pressure level), the related specific compression cost would by far dominate the specific transportation cost; 80 bar is hereby considered to be a realistic minimum transportation pressure in order to keep the CO2 steadily in its dense phase.



Figure 4-1: Pipeline Diameter Optimization Diagram OPTIMISATION OF CO2 PIPELINE TRANSPORTATION SYSTEM

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

0 MTA 5 MTA 10 MTA 15 MTA 20 MTA 25 MTA 30 MTA

Throughput (MTA)

Com

para

ble

Spec

ific

Tran

spor

tatio

n C

ost

(Eur

o/to

n/10

0 km

)C

ompr

essi

on in

Hea

d S

tatio

n (1

to 8

0 ba

r)

excl

uded

16 Inch 20 Inch 24 Inch 28 Inch 32 Inch 36 Inch 40 Inch

Remark: For compression of CO2 from 1 bar to approx. 80 bar (ca. 275 kJ/kg), approx. 11.5 €/t energy cost and approx. 2 €/t annuity cost are to be added

Pipeline Diameter

ILF

The following Figures 4-2 and 4-3 show the pressure and temperature profiles as well as the density and elevation profiles of a hypothetical land-based CO2 pipeline system able to transport 1,200 tons per hour of CO2 over a distance of 300 km.



Figure 4-2: Pressure and Temperature Profile of a 24“ (DN 600) CO2 Pipeline System

CO2 Pipeline Pressure and Temperature Profile

020406080

100120140

0 50 100 150 200 250 300

Length (km)

Pre

ssur

e (b

ar)

0102030405060

Tem

pera

ture

(°C

)

Pipeline 24" (DN 600), 1200 t/h

ILF

Figure 4-3: Density and Elevation Profile of a 24“ (DN 600) CO2 Pipeline

System

CO2 Pipeline Density and Elevation Profile

0

200

400

600

800

1000

0 50 100 150 200 250 300

Length (km)

Dens

ity (k

g/m

³)

0100200300400500600700800

Elev

atio

n (m

aSL

)

Pipeline 24" (DN 600), 1200 t/h

ILF

Pipeline inlet conditions were assumed to be 130 bar and 40 °C; if the CO2 had to be compressed from atmospheric conditions to the pipeline inlet pressure, the power requirement for a four-stage compression plant would amount to approximately 130 MW shaft rated power; the optimum number of compression stages (4-7) has to be determined during the more detailed design. The maximum allowable inlet temperature into the pipeline system has to be reviewed project-specifically with respect to environmental and authority requirements.



5 DEHYDRATION AND PIPELINE MATERIAL SELECTION

5.1 Dehydration

Due to the high corrosion potential of CO2, it is not considered to be practicable to transport wet CO2 in low-alloy carbon steel pipeline systems. However, once dehydration has been performed, corrosion is not considered a major issue for transport of CO2 streams /2/.

The review of different literature showed maximum admissible water concentrations in the CO2 stream between 0.039 g/m³ /5/ and 0.48 g/m³ /2/, but these dehydration requirements for CO2 streams can be met by glycol dehydration which is typically performed at an intermediate stage of compression (approx. 50 bar) /2/. However, potential hydrate formation at low temperature must be considered /12/.

5.2 Pipe Material Selection

Experiences with carbon steels (e.g. with API X-60 and X-65) for transportation of CO2 streams are already available since more than 30 years e.g. from EOR projects /5/. For pipeline systems operated with dry supercritical CO2 streams, the corrosion rate is low (approx. 0.01 mm/year at temperatures of 160°C-180°C). Field experience confirms this; for a carbon-steel pipeline system operated with high-pressure CO2 during 12 years, a corrosion rate of only 0.25-2.5 micrometer per year was reported /1/.

For wet service prior to dehydration, 304L stainless steel has been found a suitable material /5/.

For carbon dioxide service at high pressures in valves, control seals and packing special CO2 resistant materials like nylon or viton are considered appropriate /5, 12/.

When specifying the requirements for dry supercritically operated carbon steel pipelines, in addition to the potential corrosion aspect (specifying a corrosion allowance), especially the following must be respected:

• Low temperatures down to approx. -20°C (normal operation /6/) or even to approx. -78.5°C (during depressurization) may occur; material specification and pipeline operation must respect this.

• Susceptibility to long running brittle fracture should be avoided / prevented by a series of measures, e.g. minimization of defects introduced during pipe manufacture, construction supervision and specification of appropriate toughness requirements (Charpy V-notch (CVN) energy, drop-weight tear test (DWTT) shear area /7/).



• The installation of mechanical crack arrestors is not the only option for fracture-propagation control, considering the capability of modern pipe mills to produce high-toughness linepipe steel /7/.

• The potential influence of the presence of H2S and H2 potentially promoting stress cracking of the pipeline shall be considered; this concern is usually lessened by selection of softer pipe steel /2/ or by careful attention to the amount of H2S in the CO2 /12/.

6 HEALTH RELATED ASPECTS OF CO2, H2S AND SO2

Carbon Dioxide

• CO2 (relative density to air: 1.52) is a colorless, odorless, non-combustible gas, non-toxic at moderate concentrations

• Natural ambient concentration ca. 0.04%; Human expired air contains ca. 4% CO2, physical discomfort at 5%, life-threatening at concentrations > 20% CO2 /2/ (to be critically reviewed)

Hydrogen Sulphide

• H2S (relative density to air: 1.18) is a flammable, extremely toxic gas with strong odor at low concentrations

• Maximum exposure level 10 ppm /11/, 50 ppm in air causes headaches and nausea, 100 ppm can cause unconsciousness within a few minutes /2/

Sulphur Dioxide

• SO2 (relative density to air: 2.21) is a non-combustible gas with strong odor, key component in air pollution

• Levels of 100 ppm in air can be considered life-threatening /2/

Comparable Life-Threatening Impact of H2S and SO2 in CO2 Streams

Based on the Life-Threatening Impact of H2S and SO2 in CO2 Streams as reported above, Table 6-1 below shows the calculated concentrations of equal life-threatening impact in CO2 streams with ‚impurities‘ H2S and SO2.

Table 6-1: Concentrations of Equal Life-Threatening Impact of H2S and SO2 in CO2 Streams

Component Unit Concentration

CO2 vol-% 100H2S ppm 500SO2 ppm 500



From the results shown in Table 6-1, the following can be concluded:

• In order to avoid, that the ‚impurity‘ components H2S and SO2 dominate the health-related impact in case of a leakage, the maximum allowable concentrations of these components in the CO2 stream must be limited to certain values which were preliminary estimated to be in the order of magnitude of 500 ppm for H2S as well as for SO2.

• This requirement may have considerable consequences on the design of the carbon capture processes / technologies foreseen / required for installation, especially if the pipeline route runs through densely populated areas.

• Because CO2 itself has no smell, a small leak can remain undetected. For comparison, methane (as natural gas) is also without odour, so in the UK ethyl mercaptan a foul-smelling odourising compound is added at a concentration of about 5ppb. Allowing some H2S to remain in the CO2 will allow early detection of any leaks, as H2S is initially detectable by smell at levels <1ppm in air /12/

• If the level of H2S in CO2 is set as low as possible, then the potential exists to end up with a plant that is technologically excellent but commercially unaffordable /12/.

7 SAFETY RELATED ASPECTS OF CO2 TRANSPORT IN PIPELINES

7.1 Overview

The hypothetical leakage of a CO2 pipeline represents the major risk of CO2 transportation in pipelines.

In case of a leak, the CO2 will be released at a very low temperature (the therodynamic phase diagrams predict approx. -78.5 °C) as mixture of cold gas and fine solid particles into the environment.

While in case of smaller leaks, the CO2 clouds formed just disperse after short time, in case of larger leaks, the cold gas/solid mixture forms dense-gas clouds which move (driven by the wind and by the own weight) slowly over the terrain and can gather at low points (depressions, low-situated rooms in buildings), displacing hereby the ambient air (danger of asphyxiation, toxic effects at higher concentration).

The cooling effect in the CO2 rich plume can cause localized condensation of atmospheric water into fine aerosol droplets which create regions of very low visibility that can drift with the prevailing wind. Whilst this is a distinct advantage in the early identification of a large scale release, it can also represent e.g. a driving hazard in an extreme scenario.



Cooling down of the pipeline material due to the leakage could result in local embrittlement of the pipe material potentially forming the starting point of long running ruptures.

7.2 Main Influences on Pipeline Leak Frequencies

As reported in literature /8/, the following can be concluded referring to anticipated pipeline leak frequency:

• The external interference activities causing most incidents are those which involve excavators for digging (39%), drainage works (8%), public works (8%), and the activities related to agriculture (8%).

• The leak frequency decreases dramatically with increasing pipeline diameters; for all 24“ pipelines investigated, the average leak frequency amounts to approx. 0.02 leakages per 1,000 km * year

• The leak frequency decreases with increased pipe wall thickness (> 10 mm) dramatically

• Increased soil cover depth has only limited influence on decrease of leak frequency

• Pipeline systems installed since approx. 1980 show considerable lower leak frequencies than older ones.

7.3 Most Probable Hazard Scenario Expected

The most probable hazard scenario expected could potentially be described as follows:

• Pipeline damage by an excavator ‚tooth‘ e.g. during third-party construction works

• typical hole diameter expected: 50 mm

• gaseous CO2 with fine dispersed CO2 solid particles is injected as vertical or inclined jet stream into the atmosphere

• dispersed fine CO2 particles in the jet stream de-sublimate

• formation of a cold CO2 - air mixture cloud (density higher than air)

• movement of the cold CO2 cloud is influenced by meteorologic and topographic conditions (e.g. hilly terrain, depressions, buildings)

• dispersion / dilution of the CO2 - air mixture cloud after some time to non-dangerous concentration

• leak condition will quickly be detected by leak detection system

• adjacent line valves close quickly to minimize the CO2 mass loss



7.4 Basic Data and Correlations for the ‘Source Term’

In order to perform CO2 dispersion calculations, a suitable ‘source term’ must be determined considering

• the length and diameter of the pipeline section affected by the leak

• the pressure and temperature conditions inside the pipeline

• the location of the leak inside the pipe section affected; in worst-case, the leak would be assumed to occur at the lowest point of the pipe section considered

• a suitable correlation for the description of the (approximately isenthalpic) chocked leak flow through the orifice as function of pressure and temperature inside the pipe and of the leak size, considering gas/liquid and gas/solid phase equilibria during release

• a suitable calculation method for the (approximately isentropic) pressure and temperature change inside the pipeline system, respecting hereby also heat transfer between pipe and surrounding soil material.

The following Figure 7.4-1 shows the calculated leak flow rate as function of time for a hypothetical leak situation at a 24” (DN 600) pipeline section of 3 km length, start conditions 150 bar, 30°C with an assumed leak diameter of 50 mm.

Figure 7.4-1: Calculated Leak Flow Rate as Function of Time (Source Term)

CO2 Leak Flow Rate as Function of Time

0

50

100

150

200

250

0 20 40 60 80 100 120 140 160 180 200

Time (Minutes)

Leak

Flo

w (k

g/s)

Pipeline Section 24" (DN 600), Length 3 km, Start Pressure 150 bar, Start Temp. 30 °C

ILF

Leak Diameter 50 mm



7.5 Dispersion Calculation for CO2 Considering Heavy Gas Behavior

Different models for dispersion calculations are available in literature and on the market, but these must be reviewed for their potential application. These models shall respect heavy-gas behavior for CO2 dispersion in the atmosphere. For our estimations we used a special dense gas model of IBS /9/, which has been developed for dispersion of heavy gases and vapors in case of hazardous releases, including estimation of toxicity. Figure 7.5-1 shows a vector graphic of the simulated CO2 jet released from a 50 diameter hole, calculated with the extended model.

Figure 7.5-1: Vector Graphic of a Simulated CO2 Jet in Case of a Leak (50 mm), Jet Length ca. 70 m, Width ca. 28 m (3 Dim. Model of IBS /9/)



Figure 7.5-2: Typical Results of the CO2 Dispersion Calculations, Top View (3 Dim. Model of IBS /9/)

The results show a maximum CO2 concentration on soil level of approx. 4 %.

7.6 General Safety Aspects to be Considered for CO2 Pipelines

General

In U.S.A., CO2 pipelines are mostly routed through low densely populated areas. Careful routing would especially be required in densely populated areas with regard to safety distances to be realized there. Dispersion



modeling considering especially topographic (terrain slopes, valleys) and meteorological conditions would assist to select the optimum pipeline route.

Pipeline Design Codes, Authority Requirements

Safety distances between intended CO2 pipeline routes and populated areas would have to be designed according to the country-related standards and regulations as well as considering international standards and rules, Authority related requirements and expert opinions.

Exemplary Reference Codes

U.S.A.: 49 CFR, Part 195: Law applies for hazardous liquids and CO2;

ASME B31.4 / B31.8

UK: BS EN 14161:2003: UK recommends combination with PD 1810-

1:2004 (defining “the minimum distance for routing purposes

between the pipeline and occupied buildings”); CO2 classified as

„Cat. C“ (same as N2, Argon, Air); HSE guidance in UK is that,

until the source terms are better defined (and maybe not even

then) bulk transport of high pressure CO2 such as that in CCS

applications should be class E /12/

Germany: DIN EN 14161 (July 2004): CO2 also classified as „Cat. C“

substance; this is under review for the same reasons as above

/12/

Remark: In USA, code 49 CFR, Part 195 refers in most parts to “hazardous

liquids and carbon dioxide”; CO2 is therefore treated legally very

similar a “hazardous liquid”.

In the European Standard EN 14161, CO2 is ‘only’ classified as a

“Cat C” fluid which falls into the category “Non-flammable fluids

which are non-toxic gases at ambient temperature and pressure

conditions. Typical examples are nitrogen, carbon dioxide, argon

and air“.

According to the Author’s opinion, within the frame of future CO2

transportation projects, this divergent classification of CO2

between US codes and EU codes should be subjected to re-

consideration, in order to incorporate the relative extensive



experiences especially in USA referring to the hazard potential of

existing CO2 pipelines into the EU legislation.

7.7 Risk Calculation for CO2 Pipelines

General Risk Definition

Risk in general is defined as product of severity of an unintended event and the expected frequency of this event.

Individual Risk along the Pipeline Route

The individual risk along the pipeline can be calculated as the chance of fatality of one individual living at a certain distance to the pipeline.

Societal Risk along the Pipeline Route

The societal risk along the pipeline can be calculated as the cumulated chance of fatality of the individuals living in the influence / impact area of the pipeline.

Pipeline Route Related Risk Calculation

The following Figure 7.7-1 shows typical results of hypothetical “Societal Risk” calculations based on population density and hazard severity along the pipeline route. The “peaks” in the cumulated risk curve indicate hereby especially those locations along the pipeline route where the risk created by pipeline installation should be further reduced by special measures to a level “as low as reasonably practicable” (ALARP principle).



Figure 7.7-1: Typical Results of Hypothetical “Societal Risk” Calculations

Range 1Range 2Range 3Total

Hypothetical Societal Risk in the Vicinity of the Pipeline

Pipeline Location (m)

Cum

ulat

ive

Ris

k (1

/(km

*yr)

)

Distance Range to

Pipeline Axis

ILF

Range 1Range 2Range 3Total

Hypothetical Population Density in the Vicinity of the Pipeline

Pipeline Location (m)Pop.

Den

sity

(Per

s./m

)Distance Range to

Pipeline Axis

ILF



7.8 Measures for Risk Minimization

The following shows the main measures considered to reduce the risk from new CO2 pipeline transportation system to a level “as low as reasonably practicable” (ALARP).

a) General

• Minimization of distances between power plants with CC technology and CO2 storage sites.

• Consideration of CC technologies avoiding higher levels of toxic components (H2S, SO2) in the captured CO2 stream.

b) CO2 Pre-Processing

• Dehydration of CO2 streams to the level required to prevent hydrate formation / internal corrosion.

c) Pipe Routing

• Selection of pipeline routes avoiding densely populates areas. Site conditions (e.g. hilly terrain) influencing heavy gas dispersion must be considered.

• Performance of route related risk assessment / minimization studies.

d) Pre-Optimization of the Pipeline System

• Determination of the technically and economically optimized pipeline system. The CO2 compression energy demand (especially at the head station) should be minimized.

• Consideration of throughput extension strategies by implementation of additional loops lines and transport stations.

• Consideration of blow-down system installation for emergency cases. Consideration will need to be given to the dispersion of the CO2 following blow-down to avoid possible impacts on humans present downwind /12/.

e) Pipe Material

• Specification of carbon steel grades with appropriate material properties respecting occurrence of low temperatures under normal operating conditions and in case of line depressurization, e.g. due to a leak. Steel toughness shall be high enough to prevent ductile fracture propagation.

f) Pipe Wall Thickness

• Consideration of additional corrosion allowance (to cope for inadvertent moisture ingress); stringent control and monitoring of CO2 moisture may be potentially the better strategy /12/.

• Increase of pipe resistance against third party impact by increased pipe wall thickness.



g) Pipe Manufacturing

• Selection of experienced manufacturing companies.

• Careful supervision of pipe manufacturing process.

• Use of pre-coated pipes /12/. h) Pipeline Construction

• Selection of experienced construction companies and welders.

• Increase of welding inspection by increased number non-destructive tests.

• Increase of soil covering depth; in rural areas below level of cultivation.

• Implementation of measures to mitigate the effects of fracture propagation (e.g. installation of mechanical crack arrestors, specification of high-toughness steel).

• Running intelligent pig(s) after pressure testing for reference purposes.

• Additional protection for the pipe in critical locations (e.g. at crossings with roads)

i) Sectionalizing Line Valve Stations

• Increase of number of line valve stations for leak volume reduction; the additional risks for leakages introduced by the line valve stations themselves are to be considered as well.

• Optimization of line valve station localization considering elevation profile.

j) Leak Detection, Localization and Emergency Shut-Down Systems

• Installation of high-efficient and reliable leak detection and localization systems.

• Installation of a pipeline-related Geographical Information System (GIS), also for cross-checking / validation of potential leaks reported by third party.

• Implementation of a controlled operational emergency shut-down system and of procedures (COESD) for minimization of CO2 releases quantities in case of a leak by means of mainly remote-controlled operational actions.

k) Operation and Maintenance

• Continuous training of operators to take necessary actions to avoid / minimize potential releases of CO2.

• Implementation of a systematic, comprehensive and integrated integrity management program to investigate / maintain / improve the safety of the CO2 pipeline system



• Regular pigging to assess e.g. potential pipe wall damage to external corrosion

l) Emergency Prevention and Response Plans

• Implementing appropriate measures to alert the public on the existence and routing / location of below-ground pipelines; use of pipe markers and tape.

• Introducing measures to prevent accidental pipeline damage by third parties carrying out digging and construction activities nearby (e.g. one-call systems).

• Establishing and maintaining liaison with police and organizations to respond quickly to a hazardous release.

Development of emergency response plan and establishment / performance of a continuing training program for emergency situations.

8 FURTHER INVESTIGATION DEMAND

In the opinion of the Author the following main areas within the frame of the design of CO2 pipeline systems require further detailed investigations:

• Comparison of dispersion model calculation results with dispersion test results for potential larger CO2 releases and, if required, adaptation of the theoretical models to fit the measurement results

• Potential rupture propagation scenarios in CO2 pipeline systems and counter measures, respecting the actual pipe steel grades and properties available from the pipe manufacturers

• The potential influence of the presence of H2S and H2 in CO2 streams potentially promoting stress cracking of the pipeline

• Potential interaction of H2S and SO2 impurities in CO2 streams which might undergo a catalyzed Claus reaction and potentially could cause equipment blockages or plug reservoirs and

• Evaluation of reported failures of CO2 transportation systems to minimize the pipeline risk.

9 REFERENCES

/1/ IPCC 2005: IPCC Special Report on Carbon Dioxide Capture and Storage;

Prepared by Working Group III of the Intergovernmental Panel on Climate

Change [Metz, B., O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer

(eds.)]. Cambridge University Press, Cambridge, United Kingdom and New

York, NY, USA, 442 pp.



/2/ Impact of Impurities on CO2 Capture, Transport and Storage; Report No.

PH4/32; IEA Greenhouse Gas R&D Programme, Rev. 2, Date: Aug. 2004

/3/ Overhoff, U. Wagner, W., Software FLUIDCAL, Lehrstuhl für Thermodynamik,

Ruhr-Universität Bochum (2005)

/4/ P. N. Seevam, J. M. Race and M. J. Downie: Carbon Dioxide Pipelines for

Sequestration in the UK: An Engineering Gap Analysis; The Journal of

Pipeline Engineering, 3rd Quarter, 2007, pp. 133-146

/5/ James M. West, Chevron Oil Company: Design and Operation of a Super-

critical CO2 Pipeline-Compression System, SACROC Unit, Scurry County,

Texas, SPE 4804, Permian Basin Oil and Gas Recovery Conference, March

12, 1974 (11 pages + 4 figures)

/6/ Holloway, S.; Geological Survey: The Underground Disposal of Carbon

Dioxide; Final Report of Joule II Project N. CT92—0031, 28.Feb. 1995, 355

pp.

/7/ A. Cosham, R. Eiber: Fracture Control in Carbon Dioxide Pipelines, The

Journal of Pipeline Engineering, 3rd Quarter, 2007, pp. 147-158

/8/ 6th EGIG-Report 1970-2004, Gas Pipeline Incidents, Doc. Number EGIG

05.R.0002, December 2005

/9/ R. Schenk: Development of a time-dependent calculation method for

dispersion of heavy gases and vapors in case of hazardous releases including

estimation of toxicity. Project sponsored by European Funds for Regional

Development and by country Sachsen-Anhalt (FKZ 76213/07/02-2, 2005)

/10/ Span, R., Wagner, W.: A new equation of state for carbon dioxide covering the

fluid region from the triple-point temperature to 1100 K at pressures up to 800

MPa; J. Phys. Chem. Ref. Data 25 (1996), 1509-1596

/11/ NIOSH (1994), Documentation for Immediately Dangerous to Life or Health

Concentrations, Cincinnati, OH: U.S. Department of Health and Human

Services, Public Health Service, Centers for Disease Control and Prevention,

National Institute for Occupational Safety and Health, NTIS Publication No.

PB-94-195047

/12/ Information by Andy Brown, Engineering Director of Progressive Energy Ltd.

P.7 Kaufmann

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