Carbon Capture and Storage:

Technological Advancements and

Worldwide Constraints

Project By:
Roushan Kumar (Regn no.-20030420069)
Shubham Kumar (Regn no.-200304220085)

Project Guide: Ms. Devina Ratnam

 Table of contents
Summary
Background
Global warming
How to achieve necessary reductions
Capture technologies
Post-combustion capture
Removing CO2 using amines
Removing CO2 using ammonia
Pre-combustion capture
Oxy-fuel combustion
Future technologies
Chemical looping combustion
ZEG
Hydrogen membrane reactor
CO2 capture from industrial sites
Cement production
Oil and gas processing
Steel Production
Ammonia production
Other processes
Bio CCS
Carbon Capture and Utilisation (CCU)
Clustering
Transporting CO2
Ship transport
Pipeline transport
Risks and safety
Challenges
CO2 infrastructure and transport in the North Sea
Carbon storage
Storage potential in geological formations
Experiences in CO2 storage
Storage safety
Side effects of CO2 storage
Monitoring
CO2 in enhanced oil recovery
Carbon capture and storage is safe, accessible and necessary
References
 Summary
In climate change humanity is facing its greatest challenge. Our energy production is dominated
by fossil fuels and, if the emissions from using these fuels continue to rise, the results will be
dramatic.

Among the consequences will be the melting of polar ice and rising sea levels, flooding and more
ex- treme weather, loss of plant and animal species diversity, deforestation, and adverse effects
on food and water supply. Even by limiting global warming to 2°C, we will not mitigate serious
effects on ecosystems and regions of the Earth.

Greenhouse gas emissions must be reduced by 85 percent to avoid the most serious consequences
of anthropogenic climate change. Important and well-established solutions are a shift from fossil
fuel to renewable sources of energy - such as wind, bio-energy and solar power - and efforts to
increase energy efficiency and reduce energy demand.

However, this is not sufficient to achieve the necessary emissions cuts within a short enough
timeframe. According to the International Energy Agency’s (IEA) World Energy Outlook (WEO
2011), the most opti- mistic picture - the 450ppm scenario - puts the share of fossil fuels in the
energy mix as declining from 81 percent to still as much as 62 percent in 2035.

Of course, prognoses are only predictions made on assumptions. Therefore, it is possible to get
more comprehensive climate policies. The question is whether it is possible to cover both the
growing de- mand for energy and to achieve the needed large reduction in emissions of
greenhouse gases based on renewable energy and increased energy efficiency alone by 2030.

According to the scenarios in IEA’s World Energy Outlook 2011, and to calculations of IEA, the
long eco- nomic lifetimes of much of the world’s energy-related capital stock mean that there is
little scope for de- laying action if we are to reach the 2°C target. This leaves very little
additional room for emitting green- house gases from additional sources.

Wind power is the fastest growing renewable energy source, besides hydropower and bio-energy.
In Europe - the leading region in wind power development - about 9.3GW of new wind power was
estab- lished in 2010, reaching a total installed effect of 84GW. In a normal year, this would
produce around 180TWh of electricity (European Wind Energy Association, EWEA 2011). To cover
the expected growth in energy consumption, this capacity would have to be installed 145 times
over. To replace all fossil energy with wind power, that multiplier is 6200.

Even given a massive change in energy policy, it is technically highly unlikely that the necessary
increas- es in renewable energy production and energy efficiency can be achieved. Therefore,
large amounts of fossil fuels will continue to be used for decades to come. This makes rapid
development of large-scale carbon capture and storage essential if we are to cut greenhouse gas
emissions fast enough.

CO2 capture
CO2 can be captured from large emission sources, such as power generation and industry. The
technol- ogy can also contribute to reducing emissions from transport, by powering vehicles with
electricity and hydrogen produced by facilities deploying CCS.

The technology to separate CO2 from other gases has been in industrial use for more than 80
years, and there are large-scale CCS projects already in operation worldwide. There are also
several new projects under construction. In fact, there are now at least 15 projects operating
and/or soon to be finalised. The total CO2 storage capacity of all these projects is more than 33
alent to preventing the emissions from more than six million cars from entering the atmosphere
every year.

The most mature CO2 capture technology separates CO2 from the exhaust gas after combustion,
known as post-combustion separation. A chemical is used to bind CO2 and separate it from the
other flue gases. Several plants use post-combustion technology to capture CO2 for industrial
use. A major advantage of this technology is that it can be retrofitted to the many emission
sources that already exist.

There are two other main groups of capture technologies - pre-combustion separation and
combustion with pure oxygen, or oxy-fuel.

Transporting CO2
Extensive experience exists in carrying CO2 by pipeline to sites where it can be used in other
processes. For example, in the USA tens of millions of tonnes of CO2 are transported to oilfields
every year for en- hanced oil recovery (EOR) projects. Pipeline is the most economical method
of transporting CO2 for dis- tances of up to 1000-1500km, depending on specific conditions and
the volume transported. Beyond this distance, transport by ship can be more economical (Zero
Emission Platform, ZEP, 2011).

The transport of CO2 is similar to and no more challenging than the transport of hydrocarbons
such as natural gas, petroleum gas and condensates, which are routinely transported by all
carriers under a wide variety of conditions.

Safe storage
The final phase of CCS is safely storing the captured CO2 underground. Large geological
formations exist that have stored CO2 and natural gas for millions of years.

The IPCC special report on CCS (2005) suggested that the technical potential for storing CO 2 in
different geological formations could be at least 2000 billion tonnes, and may even be
considerably higher.

Captured CO2 can be stored in a variety of geological settings - in sedimentary basins, in depleted
oil and gas fields, saline aquifers (underground rock formations containing fluids), and deep
unmineable coal seams. These can occur within both on and offshore sedimentary basins.

Storage safety is a fundamental aspect of carbon capture and storage. The stored CO2 must not
leak and cause harm. So, before a site is chosen, the geological setting must be studied to ensure
the overlying cap rock will provide an effective seal and that there is sufficient capacity and a
permeable structure. Techniques developed by the oil and gas exploration industry are suitable
for this characterisation of potential CO2 storage sites.

Monitoring is also an important part of the overall risk management strategy for geological
storage projects.
 Background
Many years have passed since the Rio conference of 1992, when world leaders agreed to take
action to prevent dangerous man-made climate change. In 2012, the first Kyoto commitment
period comes to an end, 15 years after the Kyoto Protocol to tackle global warming was
established.

The facts for increased emissions in this period, both since Rio and Kyoto are depressing.Without
much more effective mitigation efforts, the world is heading towards a 4°C temperature rise –
nearly the dou- ble of the maximum 2°C target, which the world leaders have agreed upon.

Global warming
In climate change, humanity is facing one of its greatest challenges. Despite the increasing
awareness of the severe consequences of climate change, global CO2 emissions from fossil fuels
in 2008 were nearly 40 percent higher than those in 1990 (Copenhagen Diagnosis 2009).

The United Nations established the Intergovernmental Panel on Climate Change (IPCC) in 1988.
IPCC does not carry out research on its own, its main activity being the evaluation of available
research on climate change. Its first report was presented in 1990 and warned about the
consequences of global warming. IPCC’s fourth assessment report, published in 2007, stated that
“most of the observed increase in global average temperatures since the mid-20th century is
very likely due to the observed increase in anthro- pogenic greenhouse gas concentrations.”

The IPCC predicts that in the period 1990–2100

the global average temperature will increase
by between 1.4°C and 5.8°C due to human
activity. Global warming and rising of sea
levels will con- tinue for decades, even if the
concentration of greenhouse gases is stabilised
immediately (IPCC 2007d).

All research and observations which have been

published after the fourth assessment report
show that global climate change is continuing
at a pace even faster than expected, i.e. the
observa- tions lie in the upper scores of IPCCs
projections in the third and fourth assessment
reports from 2001 and 2007.
Figure 1: Global sea level from 200 A.D. to 2100
A.D. Source: Dahl-Jensen, 2009
Figure 1 shows that the projections for
sea level rise have been adjusted to be
three times higher than the IPCC (2007)
projections.
Consequences
During the UN’s international climate change negotiations in Cancun in 2010, most countries
agreed upon the target to limit the global average temperature to 2°C above pre-industrial
levels.

heating mechanisms. With a temperature rise of 3°C, the melting of the ice cap on Greenland
will cause a two-metre global sea level rising.

From 1979 to 2005, the world has seen a 20 percent reduction of sea ice in the Arctic, and the
melting is accelerating. The area of Arctic sea-ice melt during 2007-2009 was about 40 percent
greater than the average prediction from IPCC AR4 climate models. Figure 2 shows the area of
surface melting across the Greenland Ice Sheet from 1978 to 2008.

Within this century the quantity of water

stored in glaciers and snow will be reduced.
This will dra- matically reduce access to water
in regions with mountainous water supplies.
One out of six peo- ple on Earth live in such
regions. Around 75-250 million people in Africa
will experience a similar loss in access to
drinking water because of the changing
climate.

The Himalayas will be exposed to frequent

floods, and fresh water quality and access will
be adverse- ly affected within the next two or
three decades. Central and south-eastern
parts of Asia will expe-
rience reduced availability to Figure 2: Area of surface melting across the Greenland Ice
Sheet, as inferred from satellite observations of the surface
drinking water and parallel rapid temperature. Source: Copenhagen Synthesis Report, 2009.
population growth, causing a billion
people to be severely affected.

Figure 3: Shares of energy sources in total global primary energy supply in 2008 (Total: 492 EJ). Source: IPCC 201
 The 2°C target also implies that the
global emis- sions must be reduced by
50-85 percent by 2050, compared to
1990 levels, and peak in 2020 at the
latest.

Figure 6 shows the trade-off between

emission reductions in Annex I
(developed) countries and non-Annex I
(developing) countries for the years 2020
and 2050. In (b), it becomes clear that if
the Annex I countries reduce their
emissions by 80- 95 percent compared to
1990, the non-Annex I countries will still
have to reduce their emissions by 70-75
percent compared to their baseline in
order to remain on the 450ppm path.
The base- line is the expected emission
development, which is calculated based
on the different coun- tries’ population
growth, economic growth etc.

How to achieve necessary

reductions Figure 6: The trade-off in reductions in 2020 (a) and
2050 (b) in Annex 1 and non-Annex 1 countries as a group
These challenges may seem
for three concentration stabilisation levels. The numbers
insurmountable, but an often ignored represent the averaged outcome over separate
fact is that many emission sources of the calculations for each of the six IPCC SRES baselines (IPCC
future have yet to be built. This means SRES average). (Den Elzen and Höhne 2008)
that we have a choice, and if we focus
on building emission-free sites,
emissions will even- tually be reduced.
Zero-emission solutions are no longer an
alternative but an obligation if the worst
climate changes are to be avoided.

Prognoses show significant increases in

the emissions of CO2. Of course,
prognoses are only predictions made on
assumptions. Therefore, it is possible to
get more comprehensive climate
policies. The question is whether it is
possible to cover both the growing
demand for energy and to achieve the
needed large reduction in emis- sions of
greenhouse gases based on renewable
energy and increased energy efficiency
alone by 2030.
According to the scenarios in IEA’s World Energy Outlook 2011, the long economic lifetimes of
much of the world’s energy-related capital stock mean that there is little scope for delaying
action if we are to reach the 2°C target. The IEA calculates that four-fifths of the total energy-
related CO2 emissions permis- sible by 2035 in the 2°C scenario are already “locked-in” by capital
stock (power plants, buildings, facto- ries, etc.) that either exists now or is under construction
and will still be operational by 2035. This leaves very little additional room for emitting
greenhouse gases from additional sources.

If internationally co-ordinated action is not taken by 2017, the IEA projects that all permissible
emissions in a 2°C scenario would come from the infrastructure then existing, so that all new
infrastructure from then until 2035 would need to be zero-carbon, unless emitting infrastructure
is retired before the end of its economic lifetime to make headroom for new investment (IEA
2011). Delaying action is a false economy: for every $1 of investment avoided in the power sector
before 2020, an additional $4.3 would need to be spent after 2020 to compensate for the
increased emissions (IEA 2011).
Large emission sources from industry
Carbon capture and storage from fossil fuel power plants and industry will enable reduction of
green- house gas emissions that would otherwise go straight into the atmosphere. It will serve as
a decisive addition to the use of renewable energy and increased energy efficiency in cutting
emissions fast and efficiently.

The IEA perceives CCS as a key abatement option, accounting for 18 percent of emissions savings
in the 2°C scenario (i.e. 450ppm scenario) relative to the New Policies Scenario (IEA 2011).

Carbon capture is possible at large emission sources, such as fossil power plants and industry.
The IPCC special report on CCS from 2005 identifies near 8000 large emission sources worldwide
(IPCC 2005a).

These sources are dispersed over the entire globe, but four regions stand out: North America,
north west- ern Europe, the east coast of South-East Asia, and the Indian subcontinent. In the
coming century the number of large emission sources is assumed to rise, especially in south and
south-eastern parts of Asia. The number of sources for CCS in Europe will, however, decrease
slightly (IPCC2005b).

In the longer term, carbon capture can reduce emissions in the transport sector by changing from
petro- leum fuels to electric and/or hydrogen fuels for vehicles (IPCC 2005a).

IPCC emphasises CCS as a key technology to enable cuts in the emissions from energy production
and the industry. The most ambitious scenarios have CCS in addition to increased focus on non-
fossil energy sources, to achieve necessary emissions reductions (2007a).
 Capture technologies
CO2 has been captured from industrial process streams for more than 80 years. It is also captured
in relatively large amounts for commercial uses in, for example, urea and ammonia production,
for the production of food grade CO2 used in the brewery industry and in greenhouses to maintain
optimal CO2 concentrations. In Lubbock, Texas CO2 was captured from a gas fired power plant
and used for enhanced oil recovery (EOR) as early as 1980. Extensive experiences from these
processes and other CO2 uses can be utilized to realise full-scale carbon capture plants.

Capture technologies can be distinguished as three main categories, depending on what stage of
the process the CO2 is removed.

Figur 7: Simplified diagram illustrating the three main approaches to carbon

capture. (Source: Freund & Kårstad 2007)
When separating CO2 from the exhaust gases after combustion (post-combustion separation), a
chemi- cal is utilised to bind CO2 and separate it from the other flue gases. This is a technology
that has been in use for decades. It is well developed commercially and suitable for both new
projects and post-fitting onto existing point sources.

Separating CO2 from fuel before combustion (pre-combustion separation) is another solution.
Under high temperatures it is possible to split hydrocarbons into hydrogen and CO2. The CO2 can
then be re- moved before combustion and the reactor is fuelled with hydrogen, which emits only
water when com- busted. The process to split hydrocarbons, by gasification of coal or reforming
of natural gas, is being used in many industrial processes, such as ammonia production. This also
applies for combustion and power production using gases with high hydrogen content.

Combustion with pure oxygen (oxy-fuel combustion) is the third major approach to CO2 capture.
In oxy- fuel combustion oxygen is extracted from the air and the fuel is combusted in pure oxygen.
When fuels are burned with pure oxygen, the exhaust gas consists of CO2 and water vapour. The
separation of CO2 is done by decreasing the temperature so that vapour condenses out as water.
Large-scale air separation units producing pure oxygen are in commercial use for different kinds
of industrial processes.
The world’s first gas power plant with CO2 capture, in Lubbock, Texas (1980).
 Post-combustion capture
Today, capturing (or separating CO2 from flue gases) CO2 using amines is the most widespread
method for post-combustion capture.

Amine technology has already been used for decades to capture CO2 from both flue gas and
natural gas. Several installations exist, of which several are operative. The first gas power plant
using this technology was built in 1980 in Lubbock, Texas. Today, companies like Fluor Daniel
from UK/USA, Mitsubishi Heavy Industries from Japan, Aker Clean Carbon from Norway and
CanSolv from Canada can deliver full-scale, amine based post-combustion separation equipment.

Among the different separation methods post-combustion separation is the most versatile; it can
be fit- ted to many different types of emitters – both power plants and industrial plants – and
separation equip- ment can be post-fitted on existing emission sources. However, such separation
equipment requires an available space close to the emission source.

The composition of the flue gas stream will differ depending on the emission source. While
exhaust gas from a conventional gas power plant contains 3-4 percent CO2, the equivalent figure
for coal power plants is 12-14 percent, and cement industry approximately 20 percent.
Differences in flue gas composi- tion, CO2 concentration and flue gas pressure affect the choice
of chemicals.

How much of the CO2 that can be separated is largely a matter of cost. It is possible to separate
practically all CO2 from a flue stream, but getting at the last few percents requires considerably
more energy and is therefore expensive. Typical CO2 recoveries from flue gas with amines are
about 85 percent, but it is pos- sible to have a higher capture rate.

Other chemicals, such as ammonia, can also be used to bind CO2. Ammonia has been extensively
tested in laboratories as a CO2 solvent and large demonstration plants have been built.

Removing CO2 using amines

The exhaust gas is released at the top.
In this process 3 The gas rises inside the tower. 85-90 % of the CO2 has been re
the flue gas Amines* run
downwards. CO2 is bound to the
amines, and the solution is
flows through collected at
the bottom.
a large tower
called an
absorber or
scrub- ber. In
this so-called
absorption
process, the
gas comes into
contact with
the ab-
sorption fluid
(amines mixed
with water)
 lion Nm³/hour. To treat this amount of gas, an absorption tower with a diameter of 20-30metres
and a height of 30-40 metres is required. This will be the largest single unit in the separation
facility. The tower is filled with packing to provide the largest possible surface for contact
between the upward-rising gas and downward-running amine solution. At the top, a washing
tower removes any amine residue that has followed the flue gas stream before the CO2-free flue
gas is released into the atmosphere.

The capture plant’s energy consumption

The most energy consuming part of the capture process is the heating required to separate CO2
from the amine solution. This heat is provided by steam holding 120-140°C. The energy can be
provided from dif- ferent sources e.g. excess energy from an industrial process. However, in the
case of capturing CO2 from a gas or coal-fired power plant, the most convenient alternative is to
use steam from a steam generator/ turbine.

There is also electricity consumption in the process. Fans and pumps are used to compensate for
loss in pressure in the absorption tower, to pump amine solution and the cooling water around
and to com- press or cool CO2 before transporting. The energy demands of this kind of CO2
removal process reduces the electricity generating efficiency of a typical new gas power plant
from about 58 percent to 51 per- cent. For coal, the efficiency loss is somewhat bigger - because
of larger amounts of CO2 - from about 45 percent to about 38 percent.

Choosing the right amine for separating CO2 depends on several conditions. The most used amine
com- pound for flue gas CO2 removal at atmospheric pressure is monoethanolamine (MEA). To
remove CO2 at higher pressures methyldiethanolamine (MDEA) is often used. Many suppliers of
amine separation plants supply their own mixture of amines and additives, adapted to the
intended use. Best known is KS-1 from Mitsubishi Heavy Industries. Considerable improvements
in energy efficiency have been achieved over the decades of commercial application of amine
technology. More efficient system designs and heat in- tegration in the process plants are two
areas where further development is taking place.

Efficiency
Plant efficiency is often termed as the percentage of fuel energy actually utilised in a given facility.

In gas-fired plants the gas turbine converts almost 40 percent of the energy in the fuel to electricity. The hot
exhaust gas is then used to produce steam which in turn drives a steam turbine converting another 20 percent
of input fuel energy into electrical power. The added amount of electricity generated is called the electrical
generation efficiency of the plant. The surplus energy now exists as heat, and when not used this is called waste
heat. A power plant may also deliver heat to industrial processes or district heating. If high temperatures are
required, steam will be tapped from the generation cycle, somewhat reducing electrical output. The amount of
energy utilised either as electrical power or heat compared to the energy input is called total plant efficiency.

When CO2 from a power plant is captured, transported and stored it is generally said that efficiency decreases
by some percentage points. This is not quite correct, as energy does not cease to exist. If capture equipment is
integrated within the power plant, some of the heat that would otherwise have been wasted can be used in the
capture process. The en- ergy required for CCS in a power plant is mostly distributed as seven percentage points
of electricity and 14 percentage points of heat. In conventional gas power plants 58 percent of the supplied fuel
is converted into power, the rest wasted as heat unless used for district heating; In fact, the total energy
utilisation for a plant with CCS would be 72 percent. If we acknowledge that CCS is at least as legitimate a use
of power as any other use, a plant with integrated CCS is therefore more efficient than a conventional plant.
 Removing CO2 using ammonia
Removing CO2 using ammonia is a similar process to using amines, but has the advantage that the
re- generation process requires less energy.

The challenge is that ammonia is highly volatile and vaporises easily. In CO2 separation this can
be solved by using energy to cool the flue gas before separation. This will slow down the reaction
speed and in- crease the size of the required absorber.

The chilled ammonia process has been extensively tested in several projects. The We Energies
Field Pilot, designed to capture over 15,000 tonnes per annum of CO2, was operated during
October 2009. This proj- ect demonstrated that chilled ammonia CO2 capture could be applied
to coal-fired applications.

American Electric Power (AEP) has built a demonstration plant for 100,000 t/y at the Mountaineer
Plant power plant in New Haven, West Virginia. The plant started in 2009 and the validation
programme has now been successfully completed. The full-scale plant, set to be operational by
2015, was postponed in 2011. This was due to lack of financial incentives. When operational, the
facility will test Alstom’s chilled ammonia technology for CO2 capture from flue gases − which is
of specific use at natural gas combined cycle power plants. The project will capture at least 90
percent of CO2 from 235MW of Mountaineer’s 1300 MW capacity, or about 1.5 million tonnes per
year.

The ammonia technology is approved for flue gas with high levels of CO2 such as from coal.
The flue gas is cooled, reaching a temperature between 0 and 10°C, and is transported to the
absorber where it meets ammonia in aqueous solution. The reaction with CO2 produces
ammonium carbonate and ammonium bicarbonate. The remaining flue gas is led through a
washing process to remove any re- maining ammonia. The solution is heated in a separate reactor
– a desorber – so that CO2 is released, and remaining ammonia is reused to capture more CO2.

Alstom are building a demo plant for the chilled ammonia process at Technology Centre Mongstad
(TCM) in Norway. This will be in operation in the first half of 2012. This testing is expected to
give answers on how well this technology is suited to capturing CO2 from gas streams with lower
CO2 concentrations, such as gas-fired power plants.

Energy
Recovery
Fl Process
Fluid
Regeneration
 Pre-combustion capture
When separating CO2 before combustion the fuel is converted into a mixture of hydrogen and
CO2, which can be separated relatively easily.

The same technological principles are applicable for power production using coal and gas, but
the gasifi- cation process in the first stage of the plant will vary.

Figure 10 shows a simple flowchart of the main processes in a hydrogen fuelled power plant with
natural gas reformation. Fuel, water vapour and air are mixed in a reactor for chemical reforming
of the fuel into carbon monoxide (CO) and hydrogen (H2). Reforming takes place at a high
temperature and pressure and requires a supply of energy. The synthesis gas is then further
converted to additional hydrogen in a so-called water shift reactor after being cooled to about
300°C. In this process CO reacts with water (H2O) to form CO2 and H2. CO2 is removed using amine
absorption and hydrogen is used to fuel a gas turbine. Combustion of hydrogen emits no CO2, only
water vapour.

Natural gas
* Heat recovery steam generator

Air CO2
Autoterm water CO2absorption/d
reformer shiftreacto esorption
r
Exhaust
Gasturbine HRSG* Steamturbine

Reforming of natural gas takes place at high temperatures and requires large amounts of energy.
This reduces the electrical generation efficiency by 11 to 14 percentage points compared to
conventional natural gas power plants. With the current technological level of gas turbines the
generation efficiency of a plant of this type would be 44-47 percent.

To improve efficiency, research is exploring ways to reform the natural gas at lower temperatures
and/ or using less steam. Another possibility is to have the CO2 separation and the feeding of
hydrogen to the turbine happen at higher temperatures. To achieve this, the equilibrium for the
reactions must be shifted by removing hydrogen or CO2 in the process.

A gas power plant using natural gas reforming has yet to be built, but both natural gas reforming
and gas turbines using high concentrations of hydrogen are technologies currently in use. This
means the tech- nology is considered to be mature and available and that such plants can be
built as fast as conventional gas power plants. An advantage for this technology is its potential
combination with the production of hydrogen for other purposes, such as hydrogen fuel.
Compared to post-combustion separation less en- ergy is required to pressurise CO2 for transport
using this technology. The equipment is also smaller and can be built on a smaller site.

Technological development is needed to achieve hydrogen combustion with low NOx emissions
com- bined with high efficiency. Hydrogen burns at a very high temperature. Current combustion
chamber technology cannot burn pure hydrogen, which has to be mixed with nitrogen and/or
water vapour to re- duce temperature and NOx emissions.
 Oxy-fuel combustion
In the so-called oxy-fuel process the combustion takes place using pure oxygen rather than air.
The ex- haust gas consists of water vapour and CO2, which is separated by cooling the flue gas so
that the water vapour condenses into liquid.

This method requires large quantities of oxygen that usually is extracted from air. Air consists of
78 per- cent nitrogen, 21 percent oxygen and smaller quantities of other gases, such as Argon
and CO2. Figure 11 is a simplified illustration on Vattenfall’s oxyfuel process where a separation
unit delivers oxygen to the combustion chamber.

Figure 11: Simplified flowchart for an oxy-fuel power plant . (Source: Kjell-design / Vattenfall)

Combustion with pure oxygen generates very high temperatures. Combustion chamber
technology must therefore be changed to allow for recycled CO2 or water vapour to be used as
inert gas in oxy-fuel projects.

Combustion with pure oxygen emits virtually no NOx as there is no nitrogen from the air from
which NOx could form; only small quantities of nitrogen in the fuel may lead to the forming of
some NOx. The exhaust gas consists almost exclusively of CO2 and water vapour. The water
vapour is removed by cooling the flue gas so that the water vapour condensates into liquid,
leaving almost pure concentrated CO2 in the exhaust gas.

Electrical generation efficiency in oxy-fuel plants may be higher than in conventional plants using
com- bustion with air. But air separation and CO2 compression requires energy, leading to an
overall loss in effi-
ciency of about 12 percent. The power
generation efficiency of a combined
cycle gas power plant with oxygen
combustion and CO2 compression is
therefore 43-48 percent.

The advantages of oxy-fuel technology

are that it provides a relatively simple
way to capture nearly all CO2 with
virtually no emissions. It can be re-
alised technically by using conventional
steam turbine technology, and air
separation is a well- known and mature
technology with many exist- ing
installations and suppliers. Oxy-fuel Figure 12: Offshore gas power plant with CO2
capture, from 1988 (Source: Holt & Lindberg).
technol- ogy is equally suited for gas and
coal power plants and can be an
alternative for post-fitting when ex-
isting plants are modernised or rebuilt.

Plans for an offshore gas power plant with oxy-fuel CO2 capture was made public as early as 1987.
In many ways this marked the beginning of efforts to provide an alternative energy supply to
Norwegian petroleum activity. In 1988 a report to Statoil contained a study of the concept, called
“Environmentally friendly gas power combined with EOR” (Holt & Lindeberg 1988). The concept
is illustrated in figure 12.

Vattenfall builds oxy-fuel pilot

In 2008 Vattenfall opened a 30MW oxy-fuel pilot plant, located near the existing lignite fired
1600 MW power plant in Schwarze Pumpe, Germany. The plant has the capacity to capture 9
tonnes of CO2 per hour, which translates into 75,000 t/y at full load.

The purpose of the pilot plant is to validate and improve CO2 capture technology.
Originally, the separated and liquefied CO2 produced by the pilot plant should have been
transported by truck to the storage site in Altmark 350km away (see below). Public protests
together with a lack of fed- eral storage legislation have brought the Altmark project to a halt.
However, in May 2011, the first tonnes of CO2 captured at Schwarze Pumpe were stored
geologically in onshore saline aquifers transported by truck to the storage project in Ketzin.

Altmark
With a storage potential of 508Mt, the reservoir currently has the largest storage volume
available in depleted gas fields in Europe and is the only nearly exhausted gas field capable of
storing the CO2 from a power plant over its entire lifespan. Being already investigated, explored
and developed, this gas field therefore provides very favourable conditions for developing the
entire CO2 value chain. Vattenfall planned to inject up to 10,000 tonnes of CO2 in the 3000m
deep gas storage site.

The project is accompanied by the research project CLEAN (Geotechnologien), which will provide
sup- port for the development of technologies and methods for CO2 storage and enhanced gas
recovery (EGR). Seventeen research institutions and companies are involved. From 2008 to 2010,
injection tech- nologies, the characterisation the geological formations and process monitoring
were investigated.
 Future technologies
Many technologies require considerably more research and development to be considered mature
for full-scale implementation. The following technologies present a number of possibilities for
the future.

Chemical looping combustion

In this process pure oxygen for combustion is supplied by circulating metals that bind oxygen
from the air.

Two separate reactors are used. In the first one the metal reacts with oxygen under pressure and
a temperature of 400-500°C. The oxygen is bound to the metal, which oxidises to form a metal
oxide. This in turn is transported to the next reactor, where the oxygen is released at 500-900°C
in a reaction with natural gas. The metal is then recycled and transported back to the first
reactor. Instead of moving large volumes of metal from one reactor to another, it is possible to
have each reactor play a dual role, alternat- ing between supplying air and fuel to each reactor.

Air
Oxidation Generation Flue“air”

MeO Me CO2
CmHn
Reduction Generation Cooler H2O

Figure 13: Chemical looping combustion.

From the reactor the exhaust gas is led through a turbine to generate power. As in any other oxy-
fuel process CO2 is separated, by cooling the exhaust gas and condensing the water. In addition,
some pow- er may be generated in a turbine from the warm oxygen-lean air from the oxidation
process. Research on this technology is being carried out at the Norwegian University of Science
and Technology and Chalmers in Sweden, among other places.

Hydrogen membrane reactor

In hydrogen membrane reactors hydrogen is produced using a membrane that separates

hydrogen from a given gas mixture. This reaction is therefore more complete than in conventional
reactors, and the technology can improve efficiency of pre-combustion carbon capture.

With this membrane natural gas and steam is transported through a pipe filled with small spheres
of cat- alytic material. CO and H2 are formed in the reforming process, through which hydrogen
is continuously tapped through the pipe wall. The reaction is more complete and can take place
at a lower temperature with lower steam surplus and at a higher pressure – all in all reducing the
energy loss.
 CO2 capture from industrial sites
Large amount of the CO2 emitted around the world comes from production of industrial products
like ce- ment, ammonia, urea, pulp and petrochemical industry. Capture from most industrial
sites can undergo the same capture technologies used for power plants.

Within industry, iron and steel manufacturing now contributes the largest proportion (30 percent)
of CO2 emissions, followed by cement (26 percent) and chemical production (17 percent) (IEA,
2009a). But this picture is changing rapidly. As late as 2005 the IPCC said the production of iron
and steel was the third largest contributor of CO2 after cement production and refining. Most
current applications of CCS are in industry.

In the context of enabling CCS in general, industrial applications are important because they can
provide valuable experience with regards to capture techniques, transport infrastructure,
suitability of storage sites and the behaviour of stored CO2. This knowledge can then be
transferred to larger-scale and more complex CCS deployment in both industry and power
generation (IEA, 2009c). As a whole, industry is a major contributor to global CO2 emissions,
although the extent may vary depending on each country and region. Therefore, the application
of CCS in industry could become a catalyst for more widespread use of CCS in other areas as well.

Cement production
Production of cement, involving the calcination of limestone, is the largest industrial source of
CO2 emis- sions globally apart from the power sector, accounting for about 1000Mt/y of CO2. In
addition, large quantities of heat energy are needed to drive the process and this energy is
usually taken from fossil fuels.

The concentration of CO2 in the flue gases from

IndustrialuseofCO2 cement production is 15-30 percent by volume. With
For decades a number of countries have captured, this high CO2 concentration, post-combustion
transportedandusedCO2inthefoodindustry,inthechemical capture technolo- gies are well suited to cement
industryandforEOR.CO2iscapturedfromnaturalgas,industri production plants. It is possible to utilise waste heat
alpro-cesses,andcoalorgaspowerplants. from the cement kilns in the capture facility, but
capture of a high percentage of the emitted CO2
would require additional generation of steam for the
CO2is used in the production of soft drinks and beers,
regeneration process.
forkeeping optimal CO 2concentrations in greenhouses, in
fireextinguishers,infertilisersandintheproductionofchemic
alproductssuchasmethanol.Itcanalsobeusedforcoolingand Oil and gas processing
wrappinginfoodproduction.
Emissions from the processing of natural gas and
The production of CO 2for commercial purposes is a well- from oil refineries account for about 850 Mt/y of
es- CO2. The majority of these emissions come from oil
tablishedindustry,andthegasisanimportantcommodityinth refineries. Emissions from the generation of electric
e food industry. The European market is continually grow- energy, heat energy and steam used in the various
ing, and in 2004 sales were at almost 3 million tonnes, of processes on the plant, and emissions from the
which70percentwasusedasadditivesinbeverageproduction. production of hydrogen, would be most viable for
capture. In principle, most capture methods suitable
for power plants could be in- tegrated into a
However, most of the current industrial uses do not
refinery. Limitations in the area available and
reduceCO2emissions.Indays,weeksormonthstheCO2thathas
specific needs in modes of energy delivery may limit
beencapturedisemittedbackintotheatmosphere.
 The processing of natural gas from sources with high CO2 content involves removing CO2 from the
gas stream. This process produces an almost pure stream of CO2. Gas captured from natural gas
processing is used in several EOR projects in the USA.

The Sleipner plant in the North Sea, the Snøhvit plant at Melkøya in northern Norway and the In
Salah plant in Algeria are three operating natural gas plants that currently capture and store CO2
from natural gas processing.

Steel Production
The iron and steel industry is a major industrial emission sector, accounting for about 650 Mt/y
of CO2. The integrated steel plants are used predominantly to produce steel from iron ore in a
blast furnace, us- ing coal as the primary fuel.

In many blast furnace operations, CO2 removal is already integrated in the process. The blast
furnace process involves reacting iron ore with CO to remove carbon from the ore, producing
CO2. The top gas in these furnaces is a mixture of CO, CO2 and H2O, where the CO can be recycled
to the bottom of the furnace to improve steel production. This requires the CO2 and water to be
removed. Water can then be removed from this stream, using condensation, leaving a pure CO2
stream, ready for capture, compres- sion and storage.

In mini-mills, the direct reduction of iron ore is an opportunity for CO2 capture. This involves
reacting high oxygen content iron ore with H2 and CO to form reduced iron and H2O and CO2.
Around 90-95 per- cent of the CO2 may be captured from this process. In addition, CO2 can be
captured from the production of H2, in a process similar to pre-combustion capture in power
plants.

Capture from steel production has been studied extensively in the ULCOS (Ultra–Low Carbon
dioxide Steelmaking) project. It is a consortium that consists of all major European Union steel
companies from 15 European countries supported by the European Commission. The aim of the
programme is to reduce the CO2 emissions of today’s best routes by at least 50 percent.

Ammonia production
Ammonia production is one of several petrochemical processes that produce CO2 as a part of the
indus- trial process. Ammonia is produced through reformation of hydrocarbons. The CO2 must
be removed from the reformer as part of the process. This is done using amine technology in
most existing plants.

In many cases ammonia plants are set up so as to use the produced CO2 in other processes. Some
CO2 captured from ammonia plants is currently used in EOR and in food grade industry.

Other processes
Other petrochemical processes, such as the production of ethylene, hydrogen and methanol, are
also vi- able for CO2 capture and storage. The petrochemical industry combined accounts for
nearly 300Mt/y of CO2.

CO2 can also be captured from processes involving biomass, such as the fermentation of sugar to
produce bio ethanol. One full-scale capture plant of this type is planned by Archer Daniels
Midland Company in Illinois, USA
 Carbon Capture and Utilisation (CCU)
CO2 has been in use in a wide range of industries for decades. Most of them have no climate
mitigation effect, but some can have a good GHG impact. It is also an important learning process
for industry, which plays a role in scaling up CCS processes for large-scale use.

Perhaps the most common operations from which commercially-produced CO2 is recovered are
indus- trial plants that produce hydrogen or ammonia. In Norway, Yara produces more than
200,000 tonnes of CO2 for use in the food-grade industry from their ammonia production.

The following table is taken from a report produced by the Global CCS Institute (GCCSI) and gives
a very good overview of existing uses for CO2.

Uses of CO2 for industrial applications

Uses of CO2 Description

EOR (EOR) CO2 is injected into depleted oil fields. The CO2 acts
as a sol- vent that reduces the viscosity of the oil,
enabling it to flow to the production well. The CO2
can potentially be perma- nently stored in the
reservoir.
Urea yield boosting (non-captive use only)2 Urea production usually gives surplus ammonia as a bi-
prod- uct. CO2 can be compressed and combined with
the surplus ammonia to produce additional urea.
Other oil and gas industry applications CO2 as a fluid for the stimulation/fracturing of oil and
gas wells. It is injected as liquid carrying propping
agents
Beverage carbonation Carbonation of beverages with high-purity CO2.
Wine making Seal gas to prevent oxidation of the wine during
maturation. CO2 is produced during the fermentation
process, and is already captured on-site for reuse for its
inert gas properties.
Food processing, preservation and packaging Cooling while grinding powders such as spices.
Maintaining of inert atmospheres
Packaging applications, CO2 is used in modified
atmosphere packaging (Carbon dioxide is commonly
used because of its ability to inhibit growth of bacteria
that cause spoilage.
Coffee decaffeination Supercritical CO2 is used as the solvent for
decaffeinating coffee.
Pharmaceutical processes Inserting, chemical synthesis, supercritical fluid
extraction, product transportation at low temperature,
and acidification of wastewater.
 Transporting CO2
Captured CO2 can be transported in a number of different ways, including by road tankers and
railway, but for the volumes involved in CCS, pipeline and ship are the most practical and
economical options.

Extensive experience exists in the transport of CO2 by pipeline, while the use of ships and other
carriers is still in its infancy and is so far only applied to small quantities of food grade CO 2.
However, natural gas, petroleum gas and condensates are routinely transported by all of the
mentioned carriers under a wide variety of conditions - including across deserts, mountain
ranges, heavily populated areas, arctic areas and in deep sea. Therefore, the transport of CO2 is
similar to, and no more challenging than, the transport of hydrocarbon gases.

Pipeline is the most economical method for distances up to 1000-1500 km, depending on specific
con- ditions and the volume transported. Beyond this distance, transport by ship may be more
economical (IPCC, 2005). At present, no planned CCS projects are based on marine transport of
CO2 from the capture site to the storage site, but future projects may require it, particularly if
no suitable storage site is found within the vicinity of a large emission source or a cluster of large
emission sources.

Ship transport
The key elements in ship transport are liquefaction, intermediate storage, loading, unloading
(onshore or offshore) and heating. These are illustrated in figure 15. When unloading offshore, a
pumping station is needed. Here, the liquid is pumped to injection pressure and heated to
ambient temperature, at least 15°C, to avoid hydrate formation before injecting.

Offshore processing is considered costly and can be avoided by unloading the CO2 from the ship
to an onshore hub located close to the offshore storage site. This requires an additional onshore
intermediate storage tank, compression and an offshore pipeline.

Until the ship reaches its destination, the CO2 is stored in semi-pressurised intermediate storage
tanks, which keep it in a liquid state, with a pressure higher than atmospheric pressure and a
temperature low- er than the surroundings. The intermediate storage capacity should match the
amount of CO2 produced between the ship calls. Transport of CO2 by ship requires intermediate
storage since the gas is in most cases captured continuously.

A loading system on the quay

trans- fers the liquid CO2 to the
ship. The CO2 then arrives at the
storage site or at an onshore hub
in a ship at around 7-9 bar and -
50°C. The slight increase in
pressure is because the tanks hold-
ing the liquid CO2 will heat up
slight- ly during transport. This
increase will be dependent on
transport duration.

A hub is defined as intermediate

storage and can either be in a ship
transport solution, where the CO2
continuously captured is stored
Transport of CO2 by ship. For almost 20 years Yara has transported liquid CO 2 on ships, being both the European and world
leader in the field. Each year, the company delivers about 850-900,000 tonnes of CO2, or around 30 percent of the European
market.
Pipeline transport
Transport of CO2 by pipeline is most
effective when the gas is in liquid or
supercritical state (dense phase). The
reason for this is that the friction loss
along the pipeline per mass unit of
CO2 is lower compared with its trans-
port as a gas or a two-phase (liquid
and gas).

The pressure in the pipeline de-

creases due to friction and the tem-
perature drops due to heat transfer
with the outside medium along the
length of the pipeline. The CO2 will
gradually move from a supercriti- cal
fluid into a liquid, but will still be in Figure 16: Illustration of pipeline transport.
single phase. The pressure at the end
of the pipeline must be above
~ 74 bar (critical pressure of CO2) to
ensure that the gas is kept in liquid
dense phase. 82 NumberofCO-EORprojects
2
Natural
CO2sourcesIndustrial
CO2sourcesCO2pipeli
Dakota ne
Coal Proposed
Gasificatio
n Plant CO2pipelieCommercialCO2-
Antrim
EORproject
Gas
Plant
LaBarge 3
Gas Plant 9
2
Enid Fertilize
1
1
 The initial pressure at the beginning of the pipeline depends on the associated pressure drop
over the pipeline length. The pressure drop in the pipeline depends on the flow rate, pipe
geometry, pipeline route, and other factors. An illustration of pipeline transport is given in figure
16.

Pipelines have been used for CO2 transport in the USA for a relatively long time, transporting
large vol- umes to oilfields for EOR. Pipeline infrastructure there has the capacity to carry 50
million tonnes of CO2 a year, and according to experiences, pipeline transport is safe and reliable.
Valuable lessons have been learned. For example, gas must be dried before transported through
steel pipes to avoid corrosion, and the sulphur level (in the form of hydrogen sulphide, H2S) must
be low in case of leakages, particularly when pipelines go through inhabited areas. Pipelines
must be constructed to shut down automatically in case of leakage.

Large compressors are in current use, for example, at the Dakota Coal Gasification plant in North
Dakota, where one compresses and delivers 1.2 million tonnes a year to the Weyburn oilfield in
Canada (Freund & Kårstad 2007).

Risks and safety

Land pipelines are built according to defined standards and are subject to regulatory approval to
assure a high level of safety, particularly in densely populated areas. Pipelines in operation are
monitored inter- nally by pigs (piston-like inspection devices that are driven through the pipeline
by gas pressure) and externally by corrosion monitoring and leak detection systems. In the case
of a leak, transport of CO2 is shut down automatically.

The risk involved in transport by ship is low. New tankers are generally well designed to avoid
loss of cargo in the case of a collision, stranding or fire. There have been no accidental losses of
cargo from liq- uefied natural gas (LNG) tankers. Should an accident happen to a liquid CO2
tanker, liquefied CO2 might be released onto the surface of the sea. The environmental effects
of such an event are not fully known and require further study. However, the long-term effects
are anticipated not to have the long-term environmental impacts of crude oil spills.
 CO2 infrastructure and transport in the North Sea
Situated on each side of the North Sea, the UK and Norway are both struggling to fulfil their
commit- ments to reduce greenhouse gas emissions. Both countries are looking for solutions to
cut CO2 emis- sions on short and long term through clean energy initiatives. Governments in both
countries see CCS as an important instrument to combine fossil energy production with measures
which efficiently reduce emissions.

The One North Sea study, which concluded with a final report titled “A study into North Sea CO2
cross- border transport and storage” (One North Sea, 2010), was carried out for the Norwegian
and UK govern- ments on behalf of the North Sea Basin Task Force. The aim was to investigate
and plan for the possible joint regulation of CCS in the North Sea. This taskforce includes the
Netherlands and Germany in addition to the two aforementioned countries.

A main driver for the One North Sea study was the fact that there is both an abundant storage
capacity and a large cluster of CO2 sources in and around the North Sea basin. Combined with
the presence of world-class research institutes and commercial stakeholders, this suggested that
the North Sea countries could be natural leaders of the development and deployment of CCS
technology in Europe.

About 50 percent of the European storage potential for CO2 is located under the North Sea. The
cluster- ing of sources and possible storage sites provides opportunities to develop efficient
transportation and storage networks. It is concluded in the One North Sea study that in the initial
period no cross-border transport is necessary. Several countries are possibly involved, and at a
later stage, i.e., beyond 2020, cross-border transportation of CO2 could become increasingly
important, and eventually account for up to 25 percent of the CO2 stored.

The North Sea Basin Task Force

analysis concludes that the rapid 250MtScale
deployment of large-scale low
cost infrastructure by 2030 is
technically achievable and is
necessary for full deployment
(e.g. the ‘Very High’ scenario
described in this report which
stores over 270Mt/y of CO2 in
2030).

However this would require a

step change in co-operation in
planning by numerous UK
stakeholders, favour- able
economic conditions and CCS cost oilfieldsUK
reduction. With only modest
gasfieldsUK
further intervention, the market
is likely to deliver only a few of aquifers
the most straightforward CCS
projects by 2030, storing up to Norway
oilfields
46Mt/y of CO2 under the North
Sea in a ‘Medium’ scenario. The Norwaygasfi
elds
shortfall between ‘Very High’ and 50
Norwayaqui
‘Medium’ scenarios would need fers
to be met by other approaches
The CO2 Storage Atlas (Dec 2011), Norwegian North Sea, prepared by the Norwegian Petroleum
Directorate (NPD), shows that this area has a total storage capacity of around 70 billion tonnes -
or 70 Gt - of CO2. By comparison, the oil refinery at Mongstad, which is the largest single source
of CO2 emissions in Norway, releases about 1.5 Mt/y of CO2. The atlas is based on studies and
data from more than 40 years of petroleum operations. Twenty-one geological formations have
been identified and assessed in terms of reservoir quality and presence of the sealing layer.
Reservoirs that are considered suitable are discussed in detail.

The NPD has considered abandoned oil and gas fields in addition to producing fields that are
sched- uled to be shut down in 2030 and 2050. Reservoirs that may be used in conjunction with
EOR are also described.

Making North Sea carbon storage a reality is a longstanding matter of high priority for ZERO.
Know-how from Sleipner and the large storage capacity in the Utsira field is of key importance.
For Norway and the UK pipeline transport to the North Sea is the most practical solution for
offshore carbon sequestration.

Studies indicate that 28 pipelines on the British side of the North Sea would have the capacity to
carry be- tween 10 and 50 MtCO2 a year, but if existing infrastructure is to be used, this needs
further clarification. Within a few years, many oil and gas fields in the North Sea will close down
and an inter-governmental plan will be necessary to fully exploit the potential of existing closed-
down installations for CO2 storage
 Carbon storage
The last but not least step in the CCS
process is to store it safely under-
ground. This can be achieved by find-
ing deep geological formations that
can be monitored and controlled for
thousands of years.

Natural accumulations of virtually

pure CO2 can be found all over the
planet in a wide range of geological
settings: particularly in sedimentary
basins, intra-plate volcanic regions
and in faulted areas, or in dormant
volcanic structures. Natural gas and
oil reservoirs have demonstrated that
a great many formations are ca- pable
of storing gas for millions of years.
Figure 19: Geological storage options (Source: IPCC 2007)

In CO2 sequestration, long term storage safety is paramount. Further geological surveys are
necessary to map the global storage potential, but in areas of petroleum activity the geology is
already well mapped. Gas and liquid injections for EOR has also provided valuable information
on how CO2 can be safely stored for global warming mitigation purposes.

CO2 can be stored in a variety of geological settings, in sedimentary basins, in depleted oil and
gas fields, saline formations, and deep unmineable coal seams. Suitable storage formations can
occur both in on- shore and offshore sedimentary basins.

Storage potential in geological formations

Not all sedimentary basins are suitable for CO2 storage; some are too shallow and others are
dominated by rocks with low permeability or poor confining characteristics. Basins suitable for
CO2 storage have characteristics such as thick accumulations of sediments, permeable rock
formations saturated with sa- line water (saline formations), extensive covers of low porosity
rocks (acting as seals) and structural sim- plicity (IPCC 2005).

The IPCC special report on CCS (2005) estimates the worldwide technical potential for storage in
geologi- cal formations to be at least 2,000 Gt CO2. This is only the lower bound, and the IPCC
believes the capacity may be many times higher, but the upper limit estimates are uncertain due
to insufficient charting and disagreements on methodology. The capacity for storing CO2 in
depleted petroleum reservoirs is known with larger certainty. In most cases this kind of storage
is considered as safe, since the formations have already proven themselves capable of storing
gas for millions of years, and since the geology of the for- mations has been extensively surveyed.
 Estimated capacity for some storage options
Globalcapacity, Globalcapacity,
Storageoption
lowestestimate(GtCO2) highestestimate(GtCO2)

Depletedoilandgasreservoirs 675* 900*

Deepsalineaquifers 1000 Uncertain,butpossibly10,000
Deepunmineablecoalseams 3-15 200
* These estimates may increase by 25 percent, when undiscovered oil and gas fields are included (IPCC 2005b).

Potential storage sites are likely to be broadly distributed in many of the world’s sedimentary
basins, lo- cated in the same regions as many of the world’s greatest emission sources.

Experiences in CO2 storage

The engineered injection of CO2 into subsurface geological formations was first undertaken in
Texas, USA, in the early 1970s, as part of EOR projects.

There are four industrial-scale storage projects in operation today: the Sleipner project and the
Snøhvit project in Norway, the In Salah project in Algeria, and the Weyburn EOR project in
Canada. Annually, about 4 MtCO2 that would otherwise have been released into the atmosphere,
are captured and stored in geological formations.

Sleipner: 10 million tonnes stored since 1996

At the Sleipner field in the North
Sea, situated about 250 km off the
coast of Norway and operated by
Statoil. This was the first large
scale geo- logical CO2 storage
project, started in 1996.
Approximately 1 Mt CO2 is stored
each year. The produced natu- ral
gas in the Sleipner field contains
up to 9 percent CO2. To meet com-
mercial specification this
concentra- tion must be reduced
to 2.5 percent. When a tax on CO2
emissions was in- troduced in
Norway in 1991, this was a
sufficient economic incentive for
Statoil to start the Sleipner
storage project for the CO2 they
were already
removing from their natural gas. Figur 20: Sleipner CO2 Storage Project (Source: IPCC 2007)

The CO2 from Sleipner is injected into the Utsira formation – a brine saturated unconsolidated
sandstone about 800-1000m below the sea floor. At its widest, this saline formation is 50 km
wide and it stretches for 500 km in length. The Utsira formation has a very large storage capacity,
in the order of 1-10 GtCO2.
 The In Salah Gas Project (Algeria)
The In Salah Gas Project, located in the central Saharan region of Algeria and operated by BP, is
the world’s first large-scale CO2 storage project in a gas reservoir. The Krechba Field at In Salah
produces natural gas containing up to 10 percent CO2 from several geological reservoirs and
delivers to markets in Europe after processing and stripping the CO2 to meet commercial
specifications.

The CO2 is re-injected into a sandstone reservoir at a depth of 1800m. The top seal is a thick
succession of mudstones up to 950m thick. CO2 is injected in the water-filled parts of the
reservoir, below the gas- bearing part. The injected CO2 is expected to eventually migrate into
the area of the current gas field after depletion of the gas zone.

Injection started in April 2004 and up to 1.2 MtCO2 are stored annually. Over the life of the
project, it is estimated that 17 MtCO2 will be stored.

Figure 21: Schematic of the In Salah Gas Project, Algeria (Source: IPCC 2007)

Ketzin onshore storage (Germany)

The Ketzin (former: CO2SINK) project started in 2004, with the aim of demonstrating long- term
geo- logical storage of CO2 in a saline aquifer. Eighteen industrial partners and research
institutions from nine European countries are involved in the project, coordinated by the GFZ
German Research Centre for Geosciences.

In summer 2008, the asset went into operation. Over a period of three years, around 60,000
tonnes of highly pure (›99 percent) CO2 has been stored at a depth of between 600 and 800m.

The storage site is near a small town, Ketzin, west of Berlin. As the test site is close to a
metropolitan area, it provides a unique opportunity to develop a European showcase for onshore
CO2 storage. The site is therefore equipped with an information centre which is open to the
public.

The project has developed an in-situ laboratory for CO2 storage to fill the gap between the
numerous conceptual engineering and scientific studies on geological storage and a fully-fledged
onshore storage demonstration.
 Storageofnaturalgas
Underground natural gas storage proj-
ects have operated successfully for al-
most a century in many parts of
theworld, and provide know-how
relevantto CO2storage. These projects
providefor peak loads and balance
seasonalfluctuations in gas supply and
demand.The majority of gas storage
projects
areindepletedoilandgasreservoirsands
aline formations, although caverns
insalthavealsobeenusedextensively.
A total of 634 geological deposits
forproduced natural gas have been
estab-lished in 25 countries. The total
volumeofgasstoredinthiswayis340billi
onm³, equivalent to 270 GtCO2(Freund
&Kårstad2007).
Figure22:NaturalgasstorageinEurope,CentralAsiaandUSA(Sourc
e:IPCC)

To characterise the underground environment and understand the processes which happen there,
detailed analysis are being made of samples of rocks, fluids and micro-organisms gathered there.
The project involves intensive monitoring of the injected CO2 using a broad range of geophysical
and geo- chemical techniques, the development and benchmarking of numerical models, and the
definition of risk-assessment strategies.

Post-injection measurements, including time-lapse vertical seismic profiling transects along

selected azimuths, cross-well seismic topography, and saturation logs, show that CO2 migration
under gravity slowed greatly two months after injection, matching model predictions that
significant CO2 is trapped as relative permeability decreases. As expected, CO2 dissolved rapidly
into brine, causing pH to fall and calcite and metals to be dissolved.

Storage safety
Storage safety is a fundamental aspect of CCS. It is of utmost importance that the stored CO 2
does not leak and cause harm. For climate purposes, the CO2 has to remain in the storage
reservoir as long as re- quired in a climate perspective. The IPCC estimates the probability for
the CO2 to remain in the storage reservoir in a long-term scenario as high.

For large-scale CO2 storage projects, assuming that the sites are well selected, designed,
operated and appropriately monitored, it is likely that the fraction of stored CO2 retained is more
than 99 percent over the first 1000 years. Similar fractions retained are likely for longer periods
of time (IPCC 2005).

Before selecting a site the geological setting must be characterised to determine if the overlying
cap rock will provide an effective seal and if there is a sufficiently voluminous and permeable
storage forma- tion. Techniques developed for the exploration of oil and gas reservoirs, natural
gas storage sites and liquid waste disposal sites are suitable for characterising geological storage
sites for CO2.
Many natural gas deposits are situated in populated areas. The 1085 million
m³ deposit underneath the Berlin Olympic Stadium is a good example.
(Source: GASAG)
When geological storage formations are properly selected and operated, leakage is highly
unlikely. But there are scenarios in which CO2 can escape its storage reservoir, either as abrupt
leakage through injec- tion well failure, or up an abandoned well, or as gradual leakage through
undetected faults, fractures or wells.

Several techniques are available to remedy a leakage situation. In many cases standard well
repair tech- niques would suffice. In more serious cases, the injected CO2 can be produced back
from the storage res- ervoir and reinjected into a more suitable storage structure. These are
nevertheless extreme cases. The main assumption is that properly stored CO2 will not leak.

Even if there should be a leakage in a worst case scenario, there can be no catastrophic failure.
CO2 can- not explode, and if accidents did occur in the injection phase, the emissions would be
small and only dangerous in the immediate vicinity of the injection well where the accident
happened.

A report on the best practice for the storage of CO2 in saline aquifers has been developed by the
EU projects SACS and CO2STORE. The report aims at providing technically robust guidelines for
effective and safe storage.

What happens when CO2 is geologically stored?

Storage of CO2 will differ according to what type of storage reservoir you choose. The two options
that are in use today are depleted oil and gas field and saline aquifers.

After injection of CO2, there are various physical and geochemical trapping mechanisms that
prevent the injected gas from migrating to the surface from a suitable saline formation or oil or
gas field: an impen- etrable cap rock, the sponge-like property of the reservoir, dissolution and
eventually mineralisation of the CO2 (CO2GeoNet, 2009).

The storage reservoirs consist of porous rock, mainly sandstone. The billions of microscopic pores
in the sedimentary rock allow CO2 to be stored in much the same way as water is contained in a
sponge. CO2 is injected at depths of below 800-1000m, where the pressure and temperature
keeps it in a natural su- percritical form. Supercritical CO2 has properties midway between a gas
and a liquid, expanding to fill its containment space like a gas but with a density like that of a
liquid. This is the ideal state for efficient utilisation of the storage space in the pores of
sedimentary rocks.

The residual trapping mechanism can most easily be compared with that of filling a sponge with
water - the liquid is contained in many individual chambers within it.

A thick layer of shale and clay rock above the storage formation blocks upward migration of CO2.
This impermeable layer is known as the cap rock. Capillary forces also retain the CO2 in the pore
spaces of the formation, providing additional physical trapping. In gas reservoirs CO2 will
eventually migrate down- wards, because it is denser than natural gas.

In the long term, geochemical trapping mechanisms like dissolution and mineralisation increase
stor- age safety. The CO2 reacts with the host rock and the water inside it. Water saturated with
CO2 is slightly denser than the original formation water, and therefore sinks down into the
formation rather than rising toward the surface. Some of the dissolved CO2 reacts chemically
with the rock minerals, and is converted to solid carbonate minerals. The multiple trapping
mechanisms make the risk of leakage lower over time, as most of the gas eventually settles deep
in the formation in a diluted or mineralised form.
 Side effects of CO2 storage
There are objections against storage of CO2, pointing at still unknown risks for humans and the
environ- ment. These are risks aspects which have to be included in investigations of potential
storage sites.

Drinking water
In depleted oil and gas reservoirs, there used to be oil and gas in the tiny pores of the stone. For
saline aquifers, the sandstone is already filled with brine (very salty water). When CO2 is stored
in the aquifer, some of the CO2 is dissolved in the brine, and the rest of the brine is replaced and
pushed sideward to- wards the fringes of the reservoir. The major increase in reservoir pressure
will occur directly around the injection site. The pressure then drops rapidly the further one
moves away from the injection site/bore hole. At the fringes of the reservoir, there will hence
only be a smaller increase in pressure.

The amount of CO2 which dissolves in the water varies according to in situ temperature, pressure
and wa- ter salinity and composition. Rates of solution can be estimated from published datasets
and site specific laboratory measurements.(Cooper et al., 2009)

The pressure inside the reservoir increases with the CO2 injection, in the same way as it decline
when producing natural gas and oil. One fear is whether increase in pressure could lead to upward
movement of brine through a sequence of layers into shallow groundwater bodies.

Various studies (Bergman and Winter, 1995, Birkholzer et al, 2009) nevertheless claim that such
brine mi- gration is very unlikely. Firstly, examination of storage sites will be done along the
fringes of the reservoir and make sure that there are no potential leakage paths for brine to
migrate along. Secondly, the brine will only migrate as much as the overpressure allows it to.
With one bar pressure increase, water can mi- grate 10m upwards. For water to reach potable
ground water layers, the pressure in the fringe areas of the reservoirs will have to increase by
more than 80 bars, and this can be prevented through careful and continuous monitoring of the
reservoir pressure.

Cap rock breakage

Another risk concerns the
resistance and strength of the cap
rock. If the pressure in the
reservoir becomes too high, the cap
rock could eventu- ally break,
leading to migration of CO2 and
brine into shallower layers. The risk
can be handled by making tests of
the cap rock before starting injec-
tions. Based on such tests, the
resis- tance values and strength of
the cap rock are calculated. During
injection, the operators make sure
that these values are not
exceeded. Based on
experiences from the oil and gas sec- Figure 23: The pressure development in Tubåen
tor, there are well known methods reservoir at Snøhvit. (Source: Teknisk Ukeblad, 2011)
for monitoring the pressure in the
reser- voir and in the wells.
 Lacq, Total (France)
In January 2010, Total launched Europe’s first industrial-scale CCS chain demonstration
project at its gas processing plant at Lacq in south-west France.

The €60 million project uses oxyfuel combustion technology developed by Air Liquide. The
project aims to capture around 120,000 tonnes of CO2 over a two year period. Alstom supplied
the retrofit of a 30MW conventional boiler for oxy-firing combustion for the pilot plant. The
captured gas is trans- ported by pipeline and injected into a depleted natural gas reservoir
4500m below ground at Rousse, 27 kilometres from Lacq.

The Rousse gas field was chosen as a suitable CO2 storage site following studies in 2006 of
depleted gas fields operated by Total in the region. Its geological structure is well known and
is generally con- sidered suitable for safe, long-term storage of CO2 from the Lacq pilot.

This reservoir is made of porous rock which becomes impregnated with CO2 and the gas is then
trapped there just as the natural gas (also containing CO2) was for thousands of years. The
quantity of CO2 to be injected during the demonstration project is much smaller than the
volume of natural gas originally contained in the reservoir.

Above the Rousse reservoir is a gastight “lid” of marl and clay 2000m thick. This formation is
more than 35 million years old and remained intact when the Pyrenees were formed. Rousse
is geologically isolated from other reservoirs in the region and is not connected to any active
aquifer (i.e. porous un- derground rock impregnated with water). Therefore, Rousse offers
optimum conditions for long-term safety.

Mountaineer (USA)
American Electric Power (AEP) and Alstom began operating a small-scale test of the technology
at the coal power plant Mountaineer in New Haven, West Virginia, in September 2009,
capturing up to 90 percent of CO2 from 20MW of generating capacity. The captured gas – at a
rate of more than 100,000 t/y – has been compressed and injected for permanent storage
about 1609m below ground. The proj- ect ended, as planned, in spring 2011.

through the storage formation and the reservoir pressure rose quickly. After only three years of
injection, the reservoir was full. Figure 23 shows the development of the reservoir pressure
during the injection period from 2008 to 2011.

The experiences from Snøhvit clearly show that it is feasible to measure the pressure in a
reservoir and hence avoid exceeding the maximum pressure limit.

Earthquakes
Even an earthquake is unlikely to release large amounts of CO2 that is properly stored. Firstly,
CO2 will not be stored in areas where high magnitude earthquakes or other geological events are
likely to occur. Secondly, earthquakes happen regularly in areas where water, oil or gas is stored
in the ground the same way CO2 will be stored. As yet, there are no known occurrences of massive
eruptions of water or petro- leum from the ground during such events. The trapping mechanisms
are too strong for more than small amounts of the CO2 to be released even under such dramatic
circumstances.
In order to be sure that the CO2 is behaving as expected in the reservoir, the storage site has to be care- fully monitored
throughout the storage process and after injection has ended. Before injections starts, geoscientists carry out a site
characterisation. After injection has started, they will observe the injection performance and on-going reservoir properties.

Monitoring includes different technologies, of which the most important are seismic data, gravity and direct measurements
of the CO2 concentrations, pressure or fluid composition in the injected storage reservoir (Cooper et al, 2009). The choice of
monitoring methods depends on the storage site and factors as depth, temperature and compositional properties of the
geological layers. The characteristics of the surface play a role in the selection process.

Direct measurement normally means that different properties are measured via access into the storage reservoir via the well-
bores. Measuring emissions at the surface above the injection site is another form of direct measurement.

The indirect monitoring tools – seismic, gravity and electromagnetic – are the most important way to depict the properties
of the underground geological formations. The results are fed into 3D computer models that can describe reality with high
degree of precision.

Seismic imaging is carried out by sending out energy waves into geological formations. Because the un- derground consists of
different layers of stone, they will reflect this energy back in the form of different sound waves. The reflected signals are
stored and seismic profiles or images created.

Seismic imaging is an extremely powerful tool. However, it also has some restrictions, such as limited vertical resolution for
features less than 10m thick and unreliable images for formations below some rock types which to a certain degree inhibit
the seismic waves. It is more challenging to carry out seismic monitoring on than offshore. On land, surface properties can
have implications for seismic acquisitions, and it is more expensive to carry out.

Gravity measures reveal changes in density for a vertical rock column. Such measurements are for in- stance suitable in order
to detect where CO2 displaces saline brine in a subsurface reservoir as displace- ment causes lower density.

CO2 in enhanced oil recovery

EOR is mainly achieved by injecting different substances into the oil reservoir, i.e. gas injection,
chemical injection or microbial injection. The most commonly used option for EOR is the
injection of gas.

Oil displacement by CO2 injection relies on the phase behaviour of the mixtures of the gas and
the crude oil, which depends on reservoir temperature, pressure and the composition of the
crude oil.

In these applications, more than half and up to two thirds of the injected CO2 returns with the
produced oil and is usually re-injected into the reservoir to minimise operating costs. The
remainder is trapped in the oil reservoir by various means.
Figure 24: CO2 can be used to improve oil recovery. CO2 is usually pumped into the reservoir for
one month, and then water injected for one month, in a continuing cycle. The diagram shows how
tertiary recovery increases oil production at the Weyburn oil field in Canada (Source: Freund &
Kårstad 2007).

In the USA, 30Mt of CO2 are injected into 82 different oilfields every year. Initially, CO2 separated
in indus- trial processes was used, but this has gradually been replaced by cheaper gas from
natural CO2 reservoirs in geological formations. Only 10 percent of the CO2 used in EOR today
comes from industrial sources. In these projects there has been no environmental motivation for
injecting CO2 into the oil reservoirs. Therefore, little is known about the storage safety of the
reservoirs in Northern America, with the excep- tion of the Weyburn project in Canada (IPCC
2005b).

In the early stages of CCS development, EOR projects may prove useful to CO2 capture
technology. Using CO2 in EOR would also contribute to the deployment of necessary and costly
infrastructure. The extra revenue from EOR can finance CO2 pipelines, injection installations and
power plants with CO2 capture, which will enable CO2 injections for a long time after oil
production has been closed down.

The EOR projects should nevertheless be carefully planned and designed. It should also be made
sure that as large a share of CO2 as possible is permanently stored. In this context, it is especially
important that all the CO2 that returns with the produced oil is re-injected into the reservoir.

Weyburn & Great Plains Synfuels Plant

The Weyburn oilfield is situated in Canada, close to the USA border. In October 2000 EnCana
started in- jection of CO2 into the field to improve oil recovery. The CO2 is transported through
a 325 km pipeline from Dakota Gasification Company’s coal gasification plant in North Dakota.
Around 20 Mt of CO2 will be injected, extending the expected life span of the field by 25 years.
Great Plains Synfuels Plant (GPSP) produces syngas from lignite, which is manufactured into many
dif- ferent products, such as natural gas, methanol and fertiliser. This is a commercial project
where the company separates and sells CO2. The CO2 is separated in the industrial process, so no
separate capture equipment is needed. The plant has been running since 1984, using 6 Mt of
lignite a year. It is the first gasification plant in the world to sell CO2 for EOR.

The geological conditions around Weyburn are well suited for long-term CO2 storage. The
Petroleum Technology Research Center has conducted a four-year cross-field study of the storage
conditions, in cooperation with field operator EnCana. Seismic surveys have charted the
distribution of CO2 in the geo- logical formations, and a model to calculate storage capacity has
been developed. A risk evaluation con- cluded that most of the injected CO2 will remain in the
reservoir for more than 5000 years.
 Carbon capture and storage is
safe, accessible and necessary
There is a great deal we can do to prevent global warming. We need to replace as much fossil
fuel energy as possible with renewable alternatives, and we need to replace fossil fuels in our
cars with alternative fu- els. We have to end deforestation of the rainforests, and we need to
conserve energy. In addition to this, we need to capture and store CO2. These are the most
important reasons why:

• We use so much fossil fuel energy that it will take many decades to replace it all with
renewable al- ternatives. In fact, world energy consumption is likely to increase in the next
decades because world population is growing and more people are moving from poverty to
demand the same commodities as those enjoyed in developed nations such as Europe and the
USA.

• A relatively small number of emission sources are responsible for a very large portion of the
total global emissions. That means a relatively small number of CCS plants can cut global
ssemissions by a very large amount.

• Some emissions cannot be removed in any other way. Certain industrial processes, such as the
manu- facturing of cement and steel, emit massive amounts of CO2. In fact, a fifth of all CO2
emitted comes from industrial processes and, while some of these can be improved or
replaced to reduce their im- pact, these emissions cannot be completely eliminated as long
as we need the products they produce.

• We have no time to lose. CCS means we can start removing CO2 right now from power plants
and industrial facilities that already exist and that we know will continue emitting CO2 for
decades to come. Opportunities like this cannot be ignored when climate action is so urgently
needed to save the planet.

Fossil fuel energy

More than half of the global emissions of greenhouse gases come from the use of oil, coal and
natural gas. There is no way we can stop climate change unless we drastically reduce these
emissions. The obvi- ous solution is to stop using fossil fuels, and in long term we should. This
will require a massive change of energy policy and markets globally.

In 2009, we used about 115,000 TWh of fossil energy. If we were to build enough wind turbines
to replace all this fossil energy, it would take approximately 50 million new turbines. If
construction began now - one new turbine every minute - it would take almost 100 years to finish.
We do not have that much time to play with.

Until enough wind turbines, hydro-power plants, solar panels and other renewable alternatives
have been built, we will continue using fossil fuels. And as the global population grows, and
poorer coun- tries develop, energy demand will increase, making the quick replacement of fossil
fuels even harder to achieve.

Large emission sources

The 2000 largest CO2 point sources in the world account for 40 percent of the total global
emissions. That makes CCS a potentially very effective way of achieving considerable cuts in
emissions. Some of these emission sources literally emit as much CO2 as a small country.
Figure 25: Large emission sources in the world (Source: IPCC).

Figure 26: Global storage capacity (Source: IPCC).

Figure 27: Global oil and gas fields. According to the IPCC the world’s oil and gas regions are very
well surveyed. Many empty petroleum fields can hold huge amounts of CO 2 (Source: Freund &
Kårstad 2007).
Also, quite often large sources of CO2 are clustered together within a small geographical area,
making them even better suited for CCS, as they can share some of the infrastructure, such as
using the same pipelines to transport the captured gas and sharing storage locations.

Industrial emissions
Most people are unaware of concrete as a source of pollution. But production of cement is
actually one of the greatest industrial sources of CO2 in the world.

Cement is made from limestone or chalk - natural minerals that contain carbon, calcium and
oxygen. To make cement, you remove some of the oxygen and most of the carbon in a process
that involves heat- ing the limestone until the carbon is released as CO2. At present there are no
practical alternatives to this process.

Production of steel is another huge emitter of CO2, as is the production of important chemicals,
such as ammonia and methanol.

We have no time to lose

Cutting greenhouse gases is becoming increasingly urgent, as it becomes ever clearer how
dramatic the consequences will be if we don’t. The longer it takes for the first large-scale
facilities to be realised, the longer it will take for the next hundred to be built. To be able to
reduce emissions fast enough, it is im- perative to have the first ten full-scale CCS plants
operating now.

We cannot afford not to use the solutions available to us. CCS alone will not remove all emissions
but it can take a large share. And in combination with renewable energy, energy conservation
and other climate change mitigation solutions, it can make a very big difference. For all these
reasons, we need carbon capture and storage.
 References
Bergman, M. and Winter, E.M., 1995, Disposal of carbon dioxide in aquifers in the U.S. Energy
Convers. Manage. 36, 523-526

Birkholzer, J.T., Zhou, Q., Fu Tsang, C., 2009: Large-scale impact of CO2 storage in deep saline
aquifers: A sensitivity study on pressure response in stratified systems, International Journal of
Greenhouse Gas Control 2009, 181

CAIT, Climate Analysis Indicators Tool, http://cait.wri.org/

Copenhagen Synthesis Report, 2009, Richardson, K., Steffen, W., Schellnhuber, H.J., Alcamo, J.,
Barker, T., Kammen, D.M., Leemans, R., Liverman, D., Munasinghe, M., Osman-Elasha, B., Stern,
N., Wæver, O. www. climatecongress.ku.dk

Cooper, C. et al. (2009): “A Technical Basis for Carbon Dioxide Storage”, prepared by the CO2
Capture Project. Published in the UK by CPL Press, Printed in the UK and USA by Chris Fowler
International, London and New York