Module 5: Storage Options for CO2: Types of Geological...

StoraTypes of Ge

LEA

RN

ING

OB

JEC

TIVE

S

Geological storage is one option

climate change. These sinks are

with relatively pure CO2 waste str

retention times for carbon dioxide

By the end of this Module you wil

• Understand the concept of

• Know the different geolog

added and non-value adde

• Be familiar with current pra

• Know how CO2 and gas ha

• Appreciate the maturity of t

• Understand what is neede

media.

Asia-Pacific Economic Cooperation Buildin

MODULE 5

ge Options for CO2: ological Storage Projects

(W. D. Gunter)

for storing CO2 from the atmosphere as a means of combating

most suitable for utilization by large CO2 emission point sources

eams. Generally, with the exception of enhanced oil recovery, the

within these sinks are on the order of 105 to 10

6 years and longer.

l:

geological carbon storage;

ical CO2 storage options, including the difference between value

d storage options;

ctices and special issues related to each of these storage options;

ve been stored naturally in various reservoirs;

he technology and areas of development still required;

d to speed up commercialization of CO2 storage in geological

5-1 g Capacity for CO2 Capture and Storage in the APEC Region

GEOLOGICAL STORAGE

Geosphere sinks are naturally occurring reservoirs that historically, on a geologic time basis, have been

sinks for carbon. Humans have extracted carbon from these sinks in the form of oil, gas and coal, to use

for energy. These same reservoirs, including deep aquifers, can be used to store carbon dioxide,

reducing the amount of CO2 available in the global carbon balance.

CO2 STORAGE OPTIONS IN GEOLOGICAL MEDIA

Storage options for CO2 in geological media can be divided into two primary categories (see Figure 5.1),

and a secondary category:

Primary categories:

• Value-added options - reservoirs that typically began as a

commercially developed site to enhance recovery of fossil fuel fluids.

However, they have a secondary benefit of providing a storage site

for CO2 (through the recovery process); and

Value-added and non-value added options for CO2 storage are the two primary means of storage of CO2 in geological media. The advantages of value-added options such as EOR and EGR are that they provide suitable, secure reservoirs for carbon storage; off-set the cost of capture, transport and storage; and use technology and infrastructure which can be easily adapted to CO2 injection.

• Non-value added options – reservoirs that would only be

developed to contain CO2 emissions. Thus these are only

economically viable if CO2 emission reduction regulations were

imposed or a revenue stream could be generated from sales of CO2

credits. With the entry into force of the Kyoto Protocol on February

16, 2005, non-value added options are currently attractive. The

Kyoto Protocol is an international agreement that commits nations to

reduce their greenhouse gas emissions by a certain percentage

below 1990 levels. For more information, see Module 11: The Clean

Development Mechanism.

Asia-Pacific Economic Cooperation 5-2 Building Capacity for CO2 Capture and Storage in the APEC Region

Secondary category:

• Industrial and natural analogues - a third category of geological CO2 storage options exist that is

done for other reasons than reducing CO2 emissions. They have value but are either a natural

phenomena or done for other economic reasons without any enhanced recovery of fossil fuels.

Coalbed MethaneReservoir

Gas Reservoir

Saline Aquifer

Oil Reservoir

Coal Mine

CO2 pipelinenatural gas pipelineoil pipeline

Coalbed MethaneReservoir

Gas Reservoir

Saline Aquifer

Oil Reservoir

Coal Mine



Figure 5.1 Geological storage options (courtesy of ARC)


VALUE-ADDED CO2 STORAGE

Currently there are three types of projects which provide a value-added CO2 storage option (Figure 5.1

and Figure 5.2):

• Enhanced Oil Recovery (EOR);

• Enhanced Gas Recovery (EGR); and

• Enhanced Coalbed Methane Recovery (ECBM).

Figure 5.2 Geological storage options. (after Hitchon et al., 1999)

Enhanced Oil Recovery (EOR) Enhanced oil recovery refers to those methods that are used to increase the recovery of oil above the

amounts that could be recovered during primary or secondary recovery. The use of CO2 in miscible

floods is a proven technology (Figure 5.2, 5.3 and 5.4), and its activity continues to increase in the U.S.

When CO2 is injected into the reservoir, it dissolves in the oil, thus reducing its viscosity and moves the oil

towards the producing well. Inherently, there is always CO2 co-produced with the oil. However it will be


captured and reinjected into the reservoir. For immiscible floods, significantly more CO2 may be left in the

reservoir.

EOR is likely the first and most economic line of carbon dioxide mitigation processes, though other methods will become more viable as technology develops. There is a global potential of 20 – 65 Gt C for EOR. It permits 10-12% of additional oil reserves to be tapped. However, the return on investment for EOR is highly dependent on the price of oil, the price of CO2 and individual reservoir characteristics.

In the case of EOR, the oil-carbon dioxide mixture is separated at the

surface and the oil is used as fuel in the normal way. While this produces

more carbon dioxide, the solution to that problem is clear. The carbon

dioxide that is returned to the surface could be re-used for more oil

recovery or disposed of in deep aquifers. It should be noted that EOR is

likely the first and most economic line of carbon dioxide mitigation

processes, though other methods will become more viable as technology

develops. The recycling of gases in EOR and EGR is possible because

there is a close association of the fossil fuel resources of sedimentary

basins and the greenhouse gas emitting industry that is based on those

fuels.

Figure 5.3 Schematic of a miscible CO2 flood for enhanced oil recovery, EOR (courtesy of ARC)


Globally, the EOR–CO2 sink has an estimated capacity of 20 to 65 Gt C. Use of this sink is restricted to

economies that have oil reservoirs suitable for EOR–CO2 recovery techniques (refer to Module 13: The

Potential of CO2 Capture and Storage in the APEC Region). Use of CO2 for EOR is capable of storing a

large quantity of CO2, resulting in a net reduction in CO2, but the overall return on investment (either

positive or negative) is highly dependent on factors such as the price of oil, price of CO2 and individual

reservoir characteristics.

In Canada, availability and cost have

favoured the use of ethane over carbon

dioxide as the miscible solvent of choice.

Recently, however EnCana Ltd. of Calgary,

Alberta are buying carbon dioxide from the

Great Plains coal-gasification plant at Beulah,

North Dakota, USA. The plant produces

pipeline quality synthetic natural gas, and

other products, by gasification of lignite from

local mines. The carbon dioxide (up to

13,000 tonnes/day) is piped 330 km to be

used for EOR in the Weyburn Field,

Saskatchewan, Figure 5.4 (See the Weyburn

CO2 Monitoring and Storage Project Case

Study in the Case Study section of this

training guide for more information about this

project).

This will be the largest EOR operation in Canada and will extend the life of the field as much as 25 years

through a 20% increase in cumulative production by the year 2008. This association of available waste

carbon dioxide and a distant oil field using carbon dioxide for enhanced oil recovery is economically

viable after expenditures of more than a billion dollars—surely one of the best illustrations of the possible

synergies of “waste and want” in sedimentary basins.

Figure 5.4 EOR operations in Weyburn, Saskatchewan, Canada (courtesy of EnCana)


If the carbon dioxide is injected into the gas cap of an oil reservoir there is additional pressure drive

provided for oil recovery. In the oil sand deposits of Alberta, the production rate and recovery of bitumen

during Steam Assisted Gravity Drainage (SAGD) can be affected by the production of gas from

associated reservoirs. It has been proposed to re-pressurize the gas reservoirs with carbon dioxide to

enhance the economic production of bitumen.

he advantages of using carbon dioxide for EOR operations and injecting it into depleted oil and gas

- The main attraction to

nd gas recovery operations

m a reservoir. In general,

be tapped through primary

rocesses. The use of CO2

ximately 10 to 12% of the

sed opportunity to

ources, EOR provides an

c ase production from

stream

rbon dioxide;

Availability of secure storage – there is an opportunistic

association between hydrocarbon production and the presence of

e adapted for carbon

dioxide injection; this ranges from knowledge of exploration for and

production from reservoirs, through all aspects of gas separation,

the handling of high pressure fluids and pipelining, to ensuring safe

operations and appropriate environmental studies.

T

reservoirs are:

• Opportunity to increase productionusing CO2 storage techniques for oil a

is the higher recovery of the fuel fro

approximately 40% of oil reserves can

(~25 to 30%) and secondary (~10%) p

can aid in the recovery of up to appro

remaining fuel;

• Cost effectiveness – following from increa

produce additional hydrocarbon res

economically attractive way to in

operational oil reservoirs. This revenue

of capture, transport and injection of ca

•

The advantages of EOR are: • It provides an

opportunity to increase existing hydrocarbon production;

• It is a cost effective re

can offset the cost means of financing a CO2 storage project;

• Hydrocarbon reservoirs are often ideal storage sites for CO2;

• Supporting infrastructure often reservoirs suitable for CO2 injection. The geological processes that

allowed the accumulation of hydrocarbons also permit the secure

storing of injected carbon dioxide;

• Availability of supporting infrastructure - the technology and

infrastructure for oil and gas production can b

exists, which also decreases the cot of the CO2 storage project.


Nonetheless, not all operations are equally suited for EOR or EGR. The most economically viable

s Recovery

he much higher densities and viscosities of CO2 compared to a natural gas composed predominantly of

met n tural gas reservoir would

act as a produced from the top of the

reservoi logy for the appropriate gas

reservoi eferential higher permeability

paths a r. For

of these ch a ater or gels.

Howeve en and so no efficiencies or capacities can be assigned to

ir can through

r rat

is due

ity. Oil is less comp es not

expand as much as gas. It therefore requires a seconda

on. Ga

quire ssure for

ed for E

trates h

scenario, in a CO2 constrained world, would be a large, deep reservoir with good permeability, and high

residual oil saturation. The specific criteria which should be considered when screening reservoirs for

suitability to CO2 storage are outlined in detail in Module 6: How to Screen Reservoirs for Suitability of

CO2 Storage.

Enhanced Ga T

ha e, imply that injection of CO2 into the base of a depleted homogenous na

push gas, Figure 5.5. This would mean that the natural gas could be

r. Simulation has confirmed that this could be an attractive techno

rs. In the case of heterogeneous reservoirs, the CO2 would follow pr

nd early break through of the CO2 to the production well would occu

pathways has been proposed using standard oilfield techniques su

r, EGR is unprov

these cases, blockage

s foams, w

it.

be extractedApproximately 90% of the gas in a given reservo

primary processes. The reason for a much highe

primary processes (as compared with oil)

compressibility and lower viscos

EGR e of extraction through

to the fuel’s high

ressible and do

ry or tertiary recovery

s, on the other hand,

permits additional gas to be extracted from a reservoir, but not to the same degree as EOR. Because of the reduced economic gain, EGR has not been used in

process to provide sufficient pressure for extracti

is already in a compressed state so does not re

extraction. For these reasons, CO

additional pre

OR in practice, but is

ow these processes2 has been us

only proven in theory for EGR. Figure 5.5 illus

could work.

practice. It is, however, proven in theory.


Figure 5.5 Schematic of enhanced gas recovery using CO2to displace the natural gas, EGR (courtesy of ARC)

Enhanced Coalbed Methane Recovery


The use of coal beds as a reservoir rock for storing CO2 is novel. Coal

beds contain significant amounts of methane gas - called coalbed

methane or CBM - adsorbed in the coal. Current commercial

technologies first dewater the coal in order to release the adsorbed gas,

Figure 5.6. On the other hand, by injecting CO2 into the coal beds, the

CO2 is adsorbed in the coal pore matrix, releasing the methane.

Experimental results show that two to ten molecules of CO2 can be

adsorbed in the coal matrix for every molecule of methane it displaces.

The use of CO2 for CBM recovery would have the same effect as

enhanced oil recovery and is classified as an enhanced coalbed

methane recovery (ECBM).

By injecting CO2 into the coal beds, the CO2 is adsorbed in the coal pore matrix, releasing the methane. The methane can be sold as a revenue source. There is a global storage capacity of between 82 to 263 Gt C in coal beds.


Burlington Resources in the US ran the world’s first large scale ECBM pilot utilizing CO2 injection located

rrently leading a consortium of

o e

BM

,980 rd

2 st g

82 to

The bulk of the world’s coalbed methane resource

occurs in United States, China, the Asian portion

of Russia, Kazahkstan, and India. Australia,

portions of Africa, Central Europe, and Canada

also contain varying amounts of this resource.

It is too early to determine the value of CO2 for

this application, as it is still in piloting stage. The

attractiveness of disposing of CO2 in coal beds is

that it can be coupled directly with the production

of methane. Carbon dioxide is much more

strongly adsorbed to the coal than methane and

premature breakthrough of the injected CO2 is not

expected. Therefore recycling of the CO2 would

not be necessary.

ECBM is different compared to other storage

options, as a pure stream of CO2 is not required.

Separation of the gas takes place in the coalbed

due to the coals varying sorption selectivity for

different gases. For example if the gas (a mixture

of N2 and CO2) is injected into a coal seam, the N2

will pass through and be produced with the

methane while the CO2 will remain trapped in the

coal seam, Figure 5.2.

Figure 5.6 Example of a coalbed methane well (courtesy of ARC)

in the San Juan Basin, New Mexico. The Alberta Research Council is cu

government and industry partners in micro-pilot field tests to gather reserv

feasibility of storing CO

ir data to determine th

reservoirs of Alberta.

to 9,260 x 10

2 while producing methane in the lower permeability C

The global estimates of coalbed methane resources are on the order of 2

cubic feet (84 – 262 x 10

12 standa

orage capacity (assumin

263 Gt C.

12 cubic meters). Converting these estimates to CO

two molecules of CO2 displacing one molecule of CH4) yields a potential of


Alternatively, N2 in the flue gas can be separated and released to the atmosphere, and a pure stream of

CO2 can be directly injected into the coal seam, Figure 5.7. The choice depends on the economics of the

project.

Figure 5.7 Schematic of enhanced coalbed me NON-VALUE ADDED CO2 STORAGE

thane recovery, ECBM (courtesy of ARC)

Currently there are three types of projects which prov

added CO2 storage option:

• Depleted oil and gas reservoirs;

• Salt caverns.

ide a non-value

• Deep aquifers; and

CO2Deep Coal bed CH4 CH4CH4

CH4 to Sales

N2

Coal

Flue Gas CO2 N2

Injection

Green Power Plant

Separation

Asia-Pacific Economic Cooperation Building Capacity for CO2 Capture and Stora

Depleted oil and gas reservoirs can make ideal storage reservoirs for CO2 as their properties are well known and some of the necessary infrastructure may be available. It is most likely that some form of EOR will be incorporated into the CO2 storage scheme to tap remaining oil resources first

5-12 ge in the APEC Region

Depleted Oil & Gas Reservoirs

There are advantages for using depleted oil and gas reservoirs as CO2 sinks, as the trapping

echanisms and reservoir properties are well known and some of the existing infrastructure can be

tilized (Figure 5.8).

n abandoned oil reservoir can often have a large quantity of oil remaining in it. As such, it is very unlikely

that it will be used as a storage facility unless some form of enhanced oil recovery is incorporated into the

CO2 storage scheme. trasted w a usted rvoir, where normally up to 90%

of the original content would have been re ve he r oir can genuinely be regarded as

depleted and available for CO2 storage.

m

u

A

This can be con ith

mo

n exha

d and t

gas rese

eserv

rvoir. of ARC)

e of CO2 in a depleted oil or gas rese

ar to acid gas injection (AGI) (courtesy

Figure 5.8: StoragThe process is simil


and gas is 150 Gt CO2 (40 Gt C) and 520 Gt CO2 (140 Gt C) respectively. This is

omparable to the estimates in the Second Assessment Report of the Intergovernmental Panel on

There is not a

case of EOR,

As oil prices i

depletion of th

emitting CO2 b

atmosphere, E

sliding scale b

processes will

reservoir reach

The total global storage potential of all oil and gas fields in the world is estimated to be 670 Gt of CO2

(180 Gt C) assuming the entire volume can be displaced with CO2 at some time in the future. The

distribution between oil

c

Climate Change (IPCC). An estimate for the cost of disposing CO2 into an abandoned onshore gas

reservoir was about 1.93 ECU/t CO2 or $ US 2.22/t CO2 (about $ US 8/t C). The reservoir used for the

analysis was under-pressured, at a depth of 2,500 meters.

Asia-Pacific Ec

The total global storage potential of oil and gas fields is approximately 670 Gt of CO2 (180 Gt C). The distribution between oil and gas is 150 Gt CO2 (40 Gt C) and 520 Gt CO2 (140 Gt C) respectively. The primary difference between EOR/EGR and Depleted Oil and Gas Field CO2 storage is based on the cost of producing oil versus the value of the oil. As oil prices increase, the amount of oil recovered by EOR processes will increase as well because it will be economically viable. Similarly, as restrictions on CO2 begin to occur, industry will place a value on minimizing CO2 emissions from their operations.

sharp division between the EOR/EGR and Depleted Oil and Gas Fields categories. In the

for example, it is strictly based on the cost of producing the oil versus the value of the oil.

ncrease, the amount of oil recovered by EOR processes will go up and result in more

e reservoir before it is abandoned and available for storage only. Similarly as the value of

ecomes an economical burden, and industry is paid to prevent the CO2 from entering the

OR pro Thus there exists a

ase ines when EOR

be halted (i.e. production ceases) and only storage continues (i.e. injection of CO2) until the

es its maximum pressure or volume for safe storage.

jects will extend the depletion of oil reservoirs even further.

d on the economics of oil recovery and CO2 storage that determ

onomic Cooperation 5-14 Building Capacity for CO2 Capture and Storage in the APEC Region

For the future, better CO2 capture techniques will be needed for the CO2 purification and pressurization

steps in order to develop the best approach. This is because impurities in the CO2 can significantly

quifers in

sedimentary basins has been shown to be a technically feasible

torage option. Carbon dioxide is an ideal candidate for aquifer storage

because of its high density and high solubility in water at the relatively

igh pressures which exist in deeper aquifers, Figure 5.2 and 5.9. Deep

quifers are the

the world.

Deep aquifers

f CO2 trapped

ssure a

seals. At reser

nd pressure of the CO2 would be above the supercritcal condition,

which is desirable from a storage perspective.

Refer to Module 6 for the conditions that must be satisfied for injection

2. Global estimates of the capacity of this storage option vary

reduce the amount which can be stored, enhance corrosion and increase capital costs. Legal questions

also need to be resolved regarding ownership of the residual hydrocarbons.

Deep Aquifers

Carbon dioxide storage into low to high permeability deep a

s

h

largest potential for CO2 storage in landlocked areas of a

Storage of CO2 in low permeability, deep aquifers in sedimentary basins is technically feasible, but is only in the piloting stage.

contain high salinity water and could host large amounts

by the formation pressure. The determining factors are

nd temperature in the reservoir and the integrity of the

voir depths of 800 meters and greater, the temperature

o

the pre

a

of CO

greatly due to different assumptions with respect to aquifer volumes,

percent of the reservoir filled, density of CO2 under reservoir

conditions, and the volume suitable for storage. It ranges from 87 Gt C

to 14,000 Gt C if structural traps are not required for secure storage.


Current Demonstration Projects Currently, there are three projects which could serve to illustrate the feasibility of aquifer storage.

a is a large scale project in the

n tonnes of CO2

ndix

r operation). Preliminary economic

assessment indicated that significant costs will be incurred due

mainly to carbon dioxide capture, purification and compression, and

secondarily due to the field facilities required. Despite these

expenses, a recent report on the Sleipner Vest Field in the North Sea

indicates that the 9.5% carbon dioxide will be reduced to 2.5% in the

sales gas, with about 1 million tonnes per year of the waste carbon

dioxide being injected into sandstones of the 200-metre thick

Tertiary Utsira Formation about 1000 metres below the sea bed.

Figure 5.9: Storage of CO2 in deep aquifers (courtesy of ARC)

• Sleipner Vest Field in the North Se

Sleipner Vest Field in the North Sea, where 1 millio

are injected into the aquifer per year (See Figure 5.10 and Appe

A for a Case Study of the Sleipne

There are three projects designed to investigate and illustrate the feasibility of aquifer storage: Sleipner Vest Field (North Sea, Norway); Natuna Field (Indonesia) and the Alberta Basin (Canada).


• Natuna Field, Indonesia is a project that may develop in the Natuna Field that contains up to 71%

CO , and is one of the largest gas fields in the world with reported 1270 billion cubic meters of

ral gas,

and inject the waste gas into two carbonate aquifers near the Natuna Field. Construction of the

facilities is scheduled to last eight years.

• Canada arbon dio

rta Basin

hod of con

ide, as can

timated a

from pulv

included amine separation, CO

Figure 5.10: Storage of CO2 from the Sleipner Field into the Utsira Formation, a deep aquifer (modified after Adam, 2001)

2

recoverable hydrocarbon reserves. It is proposed to remove the carbon dioxide in the natu

The Alberta Basin,mineral trapping of c

capacity of the Albe

procedures and met

be emulated world-w

Alberta Basin was es

disposing the CO

has been used to demonstrate the concepts of hydrodynamic and

xide injected into deep aquifers in the work by Hitchon (1996). The

aquifers for storage of carbon dioxide exceeds 20 gigatonnes. The

ducting a hydrogeological evaluation of a potential injection site can

the geochemical modelling. The cost of disposing CO2 into the

t $ Cdn 52 /t CO2 ($ US 133 / t C). This was based on capturing and

erized coal-fired power plants, typically 500 MW in size. The cost 2

2 compression and injection. Injection rate was 15,000 t CO2/day.


Although initial injection of carbon dioxide into aquifers in sedimentary basins

will likely be into aquifers containing hydrocarbons (reservoirs), in the long

term it is the deep, non-hydrocarbon producing aquifers that will be the

ultimate sink for carbon dioxide. Not only do these deep aquifers have an

overwhelmingly greater capacity as carbon dioxide sinks, but they occur

throughout all sedimentary basins, at all depths, with a wide variety of

lithologies. Further, it should be possible to locate a suitable aquifer close to

a carbon dioxide source (unlike hydrocarbon reservoirs, of which there is a

paucity in some sedimentary basins).

Salt Caverns

Mining of salt caverns is a mature but expensive

technology. It has been developed for the

underground storage of petroleum, natural gas

and compressed air or for salt mining (see

Figure 5.11). Caverns up to 5x105 m3 in volume

have been developed by solution mining

techniques. Depending on the depth, a single

cavern could hold from 0.2 to 0.5 megatonnes

of CO2. This could store the emissions from a

500 megawatt coalfired power plant for

approximately two months. Salt caverns,

although ideal because of their “zero”

permeability and self-healing properties, are too

expensive to be a major component in

geological storage of CO2 but may have niche

applications where the underlying geologic

media have low permeabilities and porosities.

As salt will flow due to external stresses, the

long-term behaviour of these caverns has not

been properly evaluated for long-term storage.

Figure 5.11: A salt cavern used for storage of natural gas. CO2 storage in salt caverns is similar, but CO2 must remain stored for geological times (modified

after Lambton Industrial Society, 1995)

Initially, CO2 injection is likely to take place in aquifers containing hydrocarbons. Ultimately, deep, non-hydrocarbon producing aquifers will be the ultimate sink for CO2 because of their great abundance.


INDUSTRIAL AND NATURAL ANALOGUES

This class of projects provides examples of geological storage of gases for other reasons than reducing

CO2 emissions that is either caused by a natural phenomenon or driven by other economic reasons.

Acid Gas Injection

In the last 15 years, oil and gas producers in the Alberta basin in western

Canada have been faced with a growing challenge to reduce

atmospheric emissions of hydrogen sulphide (H2S), which is produced

from “sour” hydrocarbon pools. Since surface desulphurization is

uneconomic, increasingly more operators are turning to the disposal of

acid gas (H2S and CO2 with minor traces of hydrocarbons) by injection

into deep geological formations.

Acid gas (a mixture of

solution gas, dependi

operations approved to date in western Canada is relatively small, with

approved injection rates and volumes generally less than 0.1 million m3/d

and 1000 million m3, respectively. Compared to other options, acid gas

injection has less environmental consequences than sulphur recovery

(w er

conta

atmos

opera

on the , no safety incidents have

een reported. Given that H2S is more toxic and corrosive than CO2, the

uccess of these acid-gas injection operations indicate that the

engin

and r

addre

inject

opera

By th

deple e

onsiders also the 16 or so operations in the United States, this experience shows that CO2 storage in

CO2 and H2S) can be injected as a dry gas or a

ng on the wastewater available. The size of the 48 Industrial applications (acid gas injection and natural gas storage) and natural analogues illustrate how gases of various sorts have been stored in geological formations. These illustrate that CO2 storage is feasible and practical.

h e leaching of the sulphur piles can lead to groundwater

mination) or flaring (which essentially substitutes SO2 for H2S in the

phere, as well as releasing CO2). In the 15 years since the first

tion in the world started injecting acid gas into a depleted reservoir

outskirts of the city of Edmonton, Alberta

b

s

eering technology for CO2 geological storage is in a mature stage

eady for large-scale deployment. The major issues that need

ssing in the near future are the long-term containment of the

ed gases in the subsurface, and the safety of large-scale

tions.

e end of 2003, approximately 2.5 Mt CO2 and 2.0 Mt H2S has been successfully injected into deep

ted hydrocarbon reservoirs (including one EOR case) and saline aquifers in Canada alone. If on

c


geological media is a technology that can successfully be expanded to and applied in large-scale

o C

o gh

o

N

S gas injection

depleted oil and gas reservo to store produced natural gas until the

emand peaks. Typically, storage would occur in the summer and the gas recovered in the winter for

eating purposes.

ntain a high percentage of CO2 and have been used as

throughout the world and offer examples of natural

ogical time periods. In the southwestern US,

s in Colorado, and the Bravo Dome in New Mexico is

for EOR floods. Their characterization is currently

ment of CO2 entails.

CO2 STORAGE

perations that will reduce

f emission trading throu

il and gas producers.

atural Gas Storage

imilar to acid

O2 emissions into the atmosphere from large point sources. With the advent

the Kyoto Protocol, acid gas injection should become even more appealing to

, natural gas storage is an industry that has existed for half a century where

irs, salt caverns and aquifers are used

d

h

Natural Analogues

Natural analogues are natural reservoirs which co

commercial CO2 sources in the past. They exist

geological storage of CO2 which have held CO2 over geol

CO2 from the Sheep Mountain and McElmo Dome

greater than 95% pure and is piped to west Texas

being carried out to characterize what safe contain

MATURITY OF TECHNOLOGY FOR

By 2010, it is expected that the technology for regi

hydrogeological characterization, reservoir cha

engineering will achieve maturity.

Between 2010 and 2020, short term monitoring,

remediation, well characterization, containment e

will reach maturity.

onal scale geological and

racterization and storage

s

ngi

eyond 2020, long term monitoring, long term mitigation and well technology

ill mature.

CO2 technology is not fully mature. However, characterization and storage engineering will achieve maturity in time to make it a viable medium-term solution to reducing greenhouse gases and climate change.

hort term mitigation and

neering and pipelining

B

w


CHALLENGES IN COMMERCIAL DEVELOPMENT

There is a mismatch between capture and storage projects in going from pilot to demonstration to

apture pilots are generally in the range of 1 to 10 tonnes of CO2 produced daily

hile storage pilots are in the range of 50 to 200 tonnes injected daily. Storage pilots are distinguished by

hile small demonstrations may

re further apart). Pilots test

g and d

(e.g. r trength,

rvoir porosity & permeability,

tion water composition, and

ites must be done addressing

commercial activities. C

w

their non-commercial spacing (distance between injector and producer), w

have the same number of wells but are on a commercial spacing (i.e. wells a

the technology while demonstrations test the commerciality.

Existing commercial projects offer unique opportunities for parallel testin

technologies. In addition, sites for pilots must address geological variability

reservoir type, reservoir complexity, reservoir depth & thickness, rese

reservoir temperature & pressure, faults, abandoned wells, forma

hydrocarbon composition). Therefore, evaluation of additional potential s

geological variability for storage and CO

Better coordination of CO2 capture and storage research would benefit commercial development of the technology. This includes marrying the supply and demand needs of capture and storage demonstrations, bringing consistency to commercialization paths between pilot and demonstration projects and focusing characterization and research efforts on areas where one well can penetrate a variety of reservoirs and aquifers.

evelopment of storage

ock type, rock s

2 supply.


SUMMARY

Geological storage targets or reservoirs fall in the following categories:

Value added storage:

ry - A relatively immature field due to the high depletion by primary recovery

methods.

albed Methane Recovery - An immature field that needs piloting. Gas shales fall in the

same category but are less advanced.

on-value added storage:

based on oil field water disposal

and acid gas injection. Aquifers have the biggest capacity for storage but are the least

characterized of all the reservoirs.

pensive and relatively small

volume.

erc

the supply and demand needs of capture and s

ringing consistency to commercialization paths between pilot and demonstration

a variety of reservoirs and

• Enhanced Gas Recove

• Enhanced Oil Recovery - A mature field but the focus needs to be changed to co-optimization of

production and storage. A special case is gas-over-bitumen.

• Enhanced Co

N

• Depleted Hydrocarbon Reservoirs - Examples of storage in these reservoirs are found in depleted

oil and gas reservoirs and coal beds. Long-term issues still have to be addressed.

• Saline Aquifers - A very different storage reservoir. It is the only reservoir type where injection

pressures substantially exceed reservoir pressure. Experience is

• Salt Caverns – Mainly used for Gas Storage and are manmade, ex

Better coordination of CO2 capture and storage research would benefit comm

technology. This includes marrying

ial development of the

torage demonstrations,

projects and focusingb

characterization and research efforts on areas where one well can penetrate

aquifers.


BIBLIOGRAPHY

General Gunter, W.D., Rick Chalaturnyk, Stefan Bachu, Don Lawton, Doug Macdonald, Ian Potter, Kelly

itchon, B., Gunter, W.D., Gentzis, T., and Bailey, R.T., (1999). Sedimentary basins and greenhouse gases: a serendipitous association. Energy Conversion and Management, 40, 825-843.

nhanced Oil Recovery

haw, J. and S. or CO2- flood EOR an 51-61.

nhanced Gas

ldenburg, C. M nto natural gas reservoi on sequestration and enhanced gas production, Energy and Fuels, 15, 293-298.

cid Gas Injection

achu, Stefan and W.D. Gunter (2004) Acid gas re-injection: An innovative CO2 storage opportunity, in (Baines, S and Worden, R.H. eds) Geological Storage of Carbon Dioxide for Emissions

ng, Collingwood, VIC, AU, 543-548.

epleted Oil and Gas Reservoirs Bachu, S. and J. Shaw (2003) Evaluation of the CO2 sequestration capacity in Alberta’s oil and gas

reservoirs at depletion and the effect of underlying aquifers. J. Canadian Petroleum Technology 42 #9, 51-61.

Adam, D., (2001). The North Sea bubble. Nature, 411, 518. Deep Aquifers Gunter, W.D., S.Bachu, D.Law, V.Marwaha, D.L.Drysale, D.E.MacDonald and T.J.McCann (1996)

Technical and economic feasibility of CO2 disposal in aquifers within the Alberta Sedimentary Basin, Canada, , Energy Convers. Mgmt. 37, 1135-1142 (1996).

Thambimuthu, Malcolm Wilson and Michelle Heath (2004) The CANiSTORE Program: Planning options for technology and knowledge base development for the implementation of geological storage research, development and deployment in Canada. Alberta Research Council, Inc., Canada, 94p.

Gunter, W.D., S. Wong, D.B. Cheel and G. Sjostrom (1998) Large CO2 Sinks: Their role in the mitigation

of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective. Applied Energy 61, 209-227.

H

E S Bachu (2002) Screening, evaluation, and ranking of oil reservoirs suitable f

d carbon dioxide sequestration. J. Canadian Petroleum Technology 41 #9,

Recovery

., K. Pruess & S.M. Benson (2001). Process modeling of CO

E

2 injection irs for carb

O

A B

Reduction: Technology. Spec. Pub. of Geological Society (Bath). (in press) Coal Beds Wong, S., W.D. Gunter, D.H.-S. Law, & M.J. Mavor, (2001). Economics of flue gas injection and CO2

sequestration in coalbed methane reservoirs, In: Fifth International Conference on Greenhouse Gas Control Technologies (GHGT-5), (eds. D.J. Williams, R.A. Durie, P. McMullan, C.A.J. Paulson and A. Y. Smith), CSIRO Publishi

D


Salt Caverns Dusseault, M.B., S. Bachu, & L. Rothenburg, L. (2002). Sequestratio

2002-237, CIM Petroleum Society 53rd Annual Technical Mn of CO2 in salt caverns. Paper

eeting, Canadian International Petroleum Conference. Calgary, AB, June 11-13, 2002, 11p.

ustrial Society, (1995). Deep-Well Storage in Salt Caverns - Lambton County. Monograph L4, p. 4.

Natural An Benson, S., Hepple, R., Apps, J., Tsang, C.F., and Lippmann, M., (2002). Comparative Evaluation of Risk

SOU N AND RELATED INTERNATIONAL ACTIVITIES

Lambton Ind

alogues

Assessment, Management and Mitigation Approaches for Deep Geologic Storage of CO2. E.O. Lawrence Berkeley National Laboratory. p. 133.

RCES OF INFORMATIO

FutureGen (w

US in erate a nominal

275-megawatt (net equivalent output) that produces electricity and hydrogen with near-zero emissions.

T s

requir

opera

will p 10% increase in cost compared to non-sequestered systems,

produce hydrogen at $4.00 per millio

$0.22/gall ss than today’s wholesale price of gasoline.

egional Sequestration Partnerships

ternational Energy Agency (www.ieagreen.org.uk)

The Greenhouse Gas Research and Development Programme evaluates greenhouse gas mitigation

technologies, and holds an International Conference every two years.

ww.netl.doe.gov/coalpower/sequestration, www.fe.doe.gov/coal_power/sequestration)

tegrated Sequestration and Hydrogen Research Initiative: Design, construct and op

he ize of the plant is driven by the need for producing commercially-relevant data, including the

ement for producing one million metric tonnes per year of CO2 to adequately validate the integrated

tion of the gasification plant and the receiving geologic formation. By 2020, the FutureGen project

roduce electricity with less than a

n Btu (wholesale) equivalent to $0.48/gallon of gasoline, or

on le

R(www.netl.doe.gov/coalpower/sequestration, www.fe.doe.gov/coal_power/sequestration)

US program to engage local government agencies and non-governmental organizations, along with the

research community and private sector participants, in a number of partnerships centered in areas of the

economy with potential for CO2 capture and storage.

In


The Carbon Capture Project (www.co2captureproject.org)

he CCP aims to develop new breakthrough technologies to reduce the cost of carbon dioxide

, capture, transportation and sequestration from fossil fuel streams by 50% for existing energy

The Sle www.ieagreen.org.uk/sacshome.htm)

quifer d transport modeling activity to

ject (www.ieagreen.org.uk/weyburn4.htm)

EnCana

lanned Projects

T

separation

facilities and by 75% for new energy facilities by the end of 2003 compared to currently available

alternatives.

ipner Project (Roughly one million metric tonnes per year of CO2 from a natural gas processing platform in the North

Sea is being captured and injected into the Utsira saline clastic aquifer by Statoil. The SACS (Saline

CO2 Storage) project uses a robust measurement, verification anA

compliment and enhance the injection project.

Weyburn Monitoring ProInjection of 5000 tonnes/day of CO2 into the Midale carbonate oil reservoir in an EOR scheme by

. A parallel monitoring program is being carried out under the direction of PTRC.

PIn Salah (BP), Snohvit (Norway, Statoil), Teapot Dome (US), Gorgon (Australia, Chevron Texaco)


Date post:	16-Jul-2018
Category:	Documents
Upload:	dinhdiep
View:	217 times
Download:	0 times

Module 5: Storage Options for CO2: Types of Geological...

Documents