# International Geologic

Sequestration Efforts:

An Overview of the Sleipner,

Weyburn, and In Salah Projects

and Summary of International

Regulatory DevelopmentsOffice of Water (4606 M)

EPA 816

‐ R

‐ 10

‐ 011

November 2010

http://water.epa.gov/drink/i 

# T

ABLE OF 

# C ONTENTS

Table of Contents

...................................................................................................................... i

List of Figures

........................................................................................................................... ii

Glossary

................................................................................................ .................................. iii

Acronyms and Abbreviations

.................................................................................................. vi

Introduction

............................................................................................................................. 1

Sleipner

................................................................................................ ................................... 2

Project Background

.................................................................................................................. 2

Structure and Stratigraphy

....................................................................................................... 3

Injection Zone and Confining Zone

.......................................................................................... 3

Commercial Development History

........................................................................................... 4

Well Construction

..................................................................................................................... 4

Monitoring

............................................................................................................................... 5

Liability and Long

- Term Assessments

...................................................................................... 6

Weyburn

................................................................................................ .................................. 8

Project Background

.................................................................................................................. 8

Structure and Stratigraphy

....................................................................................................... 8

Injection Zone and Confining Zone

........................................................................................ 10

Well Construction

................................................................................................................... 12

Monitoring

............................................................................................................................. 13

Liability and Long

- Term Assessments

.................................................................................... 14

In Salah

................................................................................................ .................................. 16

Project Background

................................................................................................................ 16

Structure and Stratigraphy

..................................................................................................... 16

Production, Injection, and Confining Components

................................................................ 16

Commercial Development History

......................................................................................... 18

Well Construction

................................................................................................................... 19

Monitoring

............................................................................................................................. 20

Liability and Long

- Term Assessments

.................................................................................... 21

Conclusions

............................................................................................................................ 22

Geologic Setting and Siting Requirements

............................................................................. 22

Construction

........................................................................................................................... 22

Geology

................................................................................................ .................................. 22

Monitoring

............................................................................................................................. 23

Leaks

................................................................................................ ....................................... 23

Liability and Long

- Term Assessments

.................................................................................... 24

Interaction Among Projects

................................................................................................... 24

Storage Capacity

.................................................................................................................... 25

Scale of Deployment

.............................................................................................................. 25

References

............................................................................................................................. 26

Sleipner

................................................................................................ .................................. 26

Weyburn

................................................................................................ ................................ . 28ii In Salah

................................................................................................ ................................... 30

Conclusion s

............................................................................................................................ 31

In ternational Regulations (includes sources for the table in Appendix 1

- A)

......................... 32

Appendix I: Reviewing International Regulations

................................................................... 35

A ppendix I

- A: International Regulations Comparison Chart

.................................................... 36

Appendix I

- B: Legislative Case Studies

.................................................................................... 38

European Union

..................................................................................................................... 38

Canada

................................................................................................ .................................... 39

Australia

................................................................................................ ................................ . 39

London Protocol/OSPAR

........................................................................................................ 41

Appendix II: Membership and Support of CO 2 Research Organizations Mentioned in this

Report

................................................................................................ ................................... 43

Appendix III: Quick Reference Facts for Three Major Geologi c Sequestration Projects

............ 44



# L IST OF 

# F IGURES

Figure 1. Approximate l ocation of the Sleipner project.

................................................................ . 2

Figure 2. Sleipner seismic profiles from 1994 (pre injection) through 2006

................................... 5

Figure 3. Location of the Tordis site relative to the Sleipner site and other hydrocarbon fields

on the Norwegian continental shelf

................................................................................................ 6

Figure 4. Location of the Weyburn project within the Williston Basin.

.......................................... 9

Figure 5. A cut

- away block diagram developed for the Weyburn project, showing the

subsurface layers in the area

......................................................................................................... 11

Figure 6. Historical production from Weyburn Field.

.................................................................... 12

Figure 7. A 3D and plan view of the horizontal CO2 injector scheme at Weyburn..

..................... 13

Figure 8. Location of the In Salah gas fields.

.................................................................................. 17

Figure 9. A schematic illustration of the geology at Krechba Field

............................................... 18

Figure 10. PSInSAR image from In Salah

........................................................................................ 20iii 

# G LOSSARY

Anticline A series of sedimentary beds or other geologic layers folded so that the oldest

beds are in the core of the fold, typically shaped like an arch.

Basin A large

- scale feature (usually hundreds of kilometers across) where existing

rocks have been warped downwards or eroded to create a large depression

.

Brittle The tendency to fracture (break) when exposed to a deforming stress.

Carbonate A mineral containing the CO 3 2- ion. Limestone, marble, and dolostone are

common carbonate rocks.

Confining zone A geologic formatio n, group of formations, or part of a formation

stratigraphically overlying the injection zone that acts as a barrier to fluid

movement.

Deformation The change of the shape or size of a geologic feature caused by the application

of force.

Deposition The accretionary (incrementally additive) process by which sediment (sand,

mud, etc.) is added to a landform, usually by wind or water

.

Dip The angle between a planar feature, such as a sedimentary bed or a fault, and

the horizontal plane.

Dome A geologic f eature consisting of symmetrically dipping anticlines and resembling

the architectural feature of the same name.

Ductile The ability of an object to deform without breaking.

Elastic The ability of an object to return to its original shape after a deforming force is

removed.

Evaporite Water

- soluble sediments left behind from the evaporation of a body of water.

Rock salt is a common evaporite mineral left behind after the evaporation of

seawater. Gypsum and anhydrite are other examples of evaporites.

Fan An accumulation of sediment s located where a stream or river deposits material

as it loses velocity ( i.e., when the terrain flattens or connects into a body of

water)

.iv Formation or

geological formation A layer of rock that is made up of a certain type o r types of mineral(s) emplaced

in a similar fashion.

Formation damage Unfavorable changes in the porosity, permeability, and other characteristics of a

subsurface layer due to the infiltration of drilling muds, abrasion or crushing of

sediments by drill bits, or other events that occur during the process of drilling a

well.

Injection zone A geologic formation, group of formations, or part of a formation that is of

sufficient areal extent, thickness, porosity, and permeability to receive CO 2 through a we ll or wells associated with a GS project.

Lithology T he description of rocks, based on color, mineral composition

, and grain size.

Lowstand The lowest depth reached by sea level during a specific geologic period.

Mineral A mineral is a naturally occurri ng , inorganic solid formed through geological

processes that has a characteristic chemical composition, a highly ordered

atomic structure, and specific physical properties. Common minerals include

quartz, calcite, and mica.

Overbalanced A method of drilli ng for petroleum where the pressure of the drilling fluids is

kept higher than the pressure in the formation being drilled.

Permeability A measure of the ability of a porous material to transmit fluids.

Pinch-out T he location where a porous, permeable f ormation that is located between

overlying and underlying confining formations thins to a zero thickness, and the

confining formations are in contact with each other.

Plastic The ability of a substance to be permanently deformed by a deforming force.

Por e space O pen spaces in rock or soil. These are filled with water , air, or other fluids s uch

as brine. CO 2 injected into the subsurface can displace pre

- existing fluids to

occupy some of the pore spaces of the rocks in the injection zone. Pores can be

conne cted or isolated.

Porosity The percent of a material occupied by pore spaces.

Saline formations D eep and geographically extensive sedimentary rock layers saturated with

waters or brines that have a high TDS content. Saline formations offer large

potentia l CO 2 storage capacity because they are geographically widespread.

Salinity The total amount of dissolved material, e.g. in water

.

Sandstone A sedimentary rock consisting of sand

- sized mineral grains (0.06 mm – 2 mm in

size) cemented together by other ma terials.v Shale A common, widespread sedimentary rock formed by the deposition of very fine

particles . Shales are typically not very permeable and may have the capacity to

self- heal fractures. Accordingly, they have been investigated as potential

confining formations.

Stratigraphic

zone (unit) A layer of rock (or stratum) that is recognized as a unit based on lithology, fossil

content, age

, or other properties.

Stratigraphy A branch of geology dedicated to studying the layering of geologic strata.

Structure A geologic feature produced by the deformation of rock layers.

Syncline A series of sedimentary beds or other geologic layers folded so that the newest

beds are in the core of the fold (e.g., shaped like the letter “U ” ).

Tectonic Referring to forces that are generated by the movement of the earth’s crust.

Total dissolved solids

(TDS) The total amount of dissolved inorganic and organic particles in a sample. This

term is commonly used to reflect the salinity of a water sample. The United

States Env ironmental Protection Agency ( USEPA ) defines underground waters

with less than 10,00 0 ppm TDS as underground sources of drinking water

(USDW) . The ocean typically has a TDS of approximately 35,000 ppm.

Transmissive fault

or fracture A fault or fracture t hat has sufficient permeability and vertical extent to allow

fluids to move between formations.

Trapping T he physical and geochemical processes by which injected CO 2 is sequestered in

the subsurface. Physical trapping occurs when buoyant CO 2 rises in the

formation until it reaches a layer that inhibits further upward migration or is

immobilized in pore spaces due to capillary forces. Geochemical trapping occurs

when chemical reactions between dissolved CO 2 and minerals in the formation

lead to the precipit ation of solid carbonate minerals.

Unconformity A break in the geologic record where one layer of sedimentary rock is overlain

by a layer which is not next in the stratigraphic succession. It is caused by a

hiatus in sediment deposition or by erosion and subsequent deposition of

additional material

.

Underbalanced A method of drilling for petroleum where the pressure of the drilling fluids in

the well bore is kept lower than the pressure of the formation being drilled in

order to minimize formation damage.vi 

# A CRONYMS AND 

# A BBREVIATIONS

2D two dimensional

3D three dimensional

4D four dimensional (present through time)

AoR Area of R eview

CCS carbon capture and storage

CH 4 methane (natural gas)

CO carbon monoxide

CO 2 c arbon dioxide

CO 2- PENS CO 2 Predicting Engin eered Natural Systems

CO 3 2- carbonate ion

DNV Det Norske Veritas

EOR enhanced oil recovery (sometimes referred to as ER

– enhanced recovery)

EU European Union

FEP features, events, and processes

GS geologic sequestration

H 2 O water

H 2 S hydrogen sulfide

IEA GHG R&D International Energy Agency Greenhouse Gas Research and Development

IPCC Intergovernmental Panel on Climate Change

ISG In Salah Gas

LWD logging while drilling

Ma millions of years ago

mD millidarcy (unit of permeability)

MPa megapascals (unit of pressure)

Mt m egaton ne or million metric tons (unit of mass)

NPD Norwegian Petroleum Directorate

NWSAS Northwest Sahara Aquifer System

OSP AR Convention for the Protection of the Marine Environment of the North

- East

Atlantic

OSS Sahara and Sahel Observatory

p pm parts per millionvii PSInSAR Permanent Scatter Interferometric Synthetic Aperture Radar

PTRC Petroleum Technology Research Centre

RISQUE Risk Identification and Strategy using Quantitative Evaluation

SACS Saline Aquifer CO 2 Storage

SEED Schlumberger Excellence in Educational Development

TDS total dissolved solids

USDOE United States Department of Energy

USDW underground source of drinking water

USEPA United States Environmental Protection Agency

VSP vertical seismic profile1 

# I NTRODUCTION

Sleipner, Weyburn, and In Salah are three active commercial

- scale geologic sequestration (GS) projects.

Mirroring their different physical environments (Weyburn on the Saskatchewan prairie, In Salah in the

Sahara Desert, a nd Sleipner below the North Sea), all three proje cts are also located in unique geologic

environments: a depleted oil reservoir, a natural gas dome, and a subsea saline formation, respectively.

Although the details of the projects differ, each of these three projects is a large, commercial

sequestration operation aiming to research and validate injection techniques and monitoring

technologies, as well as to develop best practice guidelines that will play important roles in making

industrial

- scale deployment of GS technologies a global reality.

This document first provides a detailed review of important background information as well as the

geology and technical operations at the Weyburn project in Canada, In Salah in Algeria, and Sleipner in

Norway. Key geologic information related to each project’s inje ction zone s and confining zone s is

highlighted.

Next, the conclusion s section compares and contrasts the three projects. This comparison helps

highlight lessons that may be used to further advance the deployment of GS of carbon dioxide (CO

2 )

.

For quick reference, there is a comparative table at the end of this document that summarizes each

project’s:

**•** Background

.

**•** Injection stream properties

.

**•** Wells.

**•** Geology.

**•** Monitoring p rograms

. **•** Studied area/Area of R eview.

**•** Relationship to a quifers

.

**•** Problems

.

**•** Storage c osts

.

The document concludes with a summary table comparing different national regulatory approaches to

governing GS along with several brief legislative case studies that provide additional detail and

regulatory context.2 

# S LEIPNER

Project Background

The Sleipner CO 2 injection project, operated by the Norwegian oil and gas company Statoil and its

partners, 1 was the first large, commercial GS project in the world designed specifically as a greenhouse

gas mitigation measure (Chadwick et al., 2006). The Sleipner area is located offshore in the North Sea,

approximately 250 km from the southwest coast of Norway (see Figure 1). Since 1996, CO 2 from the

Sleipner West gas field (Sleipner Vest in Norwegian) has been isolated and injected into the Utsira saline

formation. As of late 2008, over 11 million metric tons of supercritical CO 2 had been injected at Sleipner

(Statoil, 2009). Due to the temperature and pressure of the formation, the injected CO 2 is very close to

the critical point of phase change (Sasaki et al., 2008); however, most researchers agree that the CO 2

remains in a supercritical state in the subsurface (Arts et al., 2004b; Bickle et al., 2007; Torp and Gale,

2004; Arts et al., 2008). A small fraction of CO 2 in the injection formation may be in the gas phase, but

this assessment is limited by temperature and pressure uncertainties in the formation (Arts et al., 2008).

Figure 1. Approximate location of the Sleipner project. Th e Utsira forma tion is shad ed in yellow.

CO 2 sequestration at Sleipner has received a great deal of attention from the scientific, environmental,

and political communities. In 1998, a group of European energy companies, scientific institutes, and

environmental groups formed the interdisciplinary Saline Aquifer CO 2 Storage (SACS) Project Consortium

1 Licenses for the Sleipner West field are held by Statoil (49.50%, including 32.37% direct government financial

interest), Esso Norge (32.24%), TotalFinaElf Exploration Norge (9.41%), and Norsk Hydro (8.85%) (IEA, no date).3 to collect data from t he Sleipner injection project. Results from the SACS project, which ended in 2002,

were compiled into the SACS Best Practice Manual (Holloway et al., 2004). Currently, follow

- up research

projects are operated by CO2STORE, a similar consortium with 19 members from industry, research, and

government (see Appendix II for further details)

.

The Sleipner area (see Figure 1), which includes the Sleipner East and Sleipner West fields as well as

multiple production platforms, produces natural gas and is responsible for approximately 10% of

Statoil ’s total annua l income (Statoil, 2009). Natural gas produced at Sleipner West has a CO 2 content of

up to 9.5% by v olume (Holloway et al., 2004). Under t he Troll Gas Sales Agreements, natural gas

delivered to the export pipeline must have a maximum CO 2 content of 2.5% by volume (Baklid and

Korbøl, 1996). Partially motivated by the 1991 Norwegian tax on offshore emissions, Statoil decided to

geologically se quester the excess CO 2 instead of venting it to the atmosphere during gas processing

when Sleipner West came online in 1996. The CO 2 sequestered at Sleipner represents approximately 3%

of Norway’s total annual greenhouse gas emissions ( Statoil , 2007).

St ructure and Stratigraphy

The Miocene (approximately 23 to 5.3 million years ago, or Ma ) Utsira Formation is a saline formation

that extends more than 400 km from north to south and between 50 and 100 km from east to west,

covering an area of approximately 26,100 km 2 (Torp and Gale, 2004). The formation is more than 300 m

thick near the Sleip ner injection site (Chadwick, 1996)

. In this area, the Utsira is a highly porous (30

- 40%), very permeable (1000

- 3000 mD), weakly consolidated sandstone that occurs at d epths between

800 m and 1,100 m below the sea floor (Arts et al., 2008). The ocean depth at the site is approximately

80 m (Nooner et al., 2006). Due to the offshore location of the project site, there are no current sources

of drinking water located above or ne ar the Sleipner injection zone.

Macroscopic and microscopic analyses of core and cutting samples of the Utsira suggest that it consists

of primarily uncemented, fine

- grained sand with occasional medium and coarse grains (Torp and Gale,

2004). The i nternal structure of the formation is composed of overlapping lobes (approximately 30 m

thick) interlayered w ith thin (1 m thick) mudstones. Based on these characteristics, the formation is

interpreted as a composite lowstand fan that was deposited by mass flows in a marine environment

with water depths of 100 m or more (Arts et al., 2008). The underwater sediments moved downslope by

gravity and were deposited while sea level was at a low point in a cycle of rising and falling sea levels.

The Utsira is ove rlain by the Pliocene (approximately 5.3 to 2.5 M a) Nordland Formation, a thick shale

unit. The Nordland is generally interpreted as consisting of wedge

- like layers formed in a prograding

(building outward) delta setting (Arts et al., 2008). Samples of Nor dland core material are typically

composed of gray to dark gray silty mudstones that are uncemented, plastic, and generally homogenous

(Arts et al., 2008).

Injection Zone and Confining Zone

Because of its proximity to gas producing units , the Utsira Form ation has been extensively studied in the

Sleipner area. The formation is water

- saturated

, with a pressure o f 8

- 11 MPa (approximately 11 MPa at

the Sleipner injection site ) and a temperature of 37°C (Baklid and Korbøl, 1996). Formation fluid in the

Utsira has a salinity of approximately 35,000 mg/L total dissolved solids ( TDS ) (Michael et al., 2009).

Reservoir simulations (described in Baklid and Korbøl, 1996) run prior to injection predicted that up to4 18% of injected CO 2 would be dissolved in formation wa ter and that a pressu re increase of

approximately 3 MPa would occur close to the injection site.

Several studies have tested the strength of the Nordland shales to determine their ability to serve as a

cap or seal for CO 2 st ored in the underlying Utsira. Using mechanical parameters from Sleipner and

similar areas, Zweigel and Heill (2003) calculated that the confining layers are unlikely to experience

mechanical failu re; their model predicts that the confining zone could contain a CO 2 column an order of

ma gnitude higher than the CO 2 column at Sleipner. Zweigel and Heill only considered brittle rock failure

and not plastic rock failure, arguing that the grain size of the Nordland shales precluded plastic failure.

However

, Pillitteri et al. (2003) noted that the Nordland shales are extremely ductile and exhibit almost

elastic/entirely plastic (easily

- deformed or altered) behavior, indicating the possibility of plastic failure

under pressure. More recently, Harrington et al. (2008) performed tests on core material and

determined that the confining layers can contain a column of supercritical CO 2 that is 100 m to 400 m

high, depending on the density of the CO 2

. The study notes that, in the Utsira, the CO 2 column heights

are generally less than 10 m, allowing the overlying shales to provide a more than effective seal.

Commercial Development History

CO 2 injection at Sleipner is not intended to increase oil or gas production from the formation. However,

injection does operate in conjunction with production at the Sleipner West gas fi eld. Sleipner West came

online in August 1996 and the production period is estimated to end in 2022 (Baklid and Korbøl, 1996).

Natural gas produced at Sleipner West is transported by pipeline 12 km to the Sleipner T process and

treatm ent platform at the S leipner East field

. At Sleipner T, CO 2 is stripped from the gas by an active

amine process in which the gas passes through two 35 m absorption columns (IEA, no date). The amine

process generates considerable heat , which is used to run two generators that partially power the

platform. After extraction, the natural gas is treated and sent to continental Europe, while the CO 2 is

piped to the Sleipner A platform and injected into the Utsira formation in a non

- supercritical state

(Baklid and Korbøl, 1996 ) at a rate of approximately one million metric tons of CO 2 per year (Statoil,

2007). The Statoil Web site 2 provides animated demonstrations of the CO 2 separation and injection

processes.

Well Construction

The Sleipner project was the first major GS initiative not motivated by enhanced oil or gas recovery.

Because of this, injection infrastructure was not in place at the start of the project and a new injection

well was constructed. Statoil constructed one horizontal well that extends approxi mately 3

, 000 m from

the drill center to the injection site through the Utsira Formation . Solution annealed 25% duplex steel

was selected for the injection tubing and casing due to its resistance to corrosion (Baklid and Korbøl,

1996). Construction of dedic ated monitoring wells was precluded by high costs; Statoil estimated that a

permanent monitoring well could cost as much as $10 million 3 (Torp and Gale, 2003).

2 Available on the Internet at:

http://www.statoil.com/STATOILCOM/SVG00990.NSF/web/sleipneren?opendocument

. 3 All currency am ounts in this document are expressed in U.S. dollars. Approximate conversion rates used (in May

2009) were as follows: 1 U.S. dollar to 6.8 Norwegian kroner and 1 U.S. dollar to 0.66 British pounds.5 Monitoring

Some monitoring t echniques employed at other carbon capture and storage ( CCS ) sit es cannot be used

at Sleipner due to the remote offshore location and water depth. In addition, uncertainties about the

phase of the injected CO 2 complicate the interpretation of monitoring data. The primary forms of

monitoring at Sleipner have been seismi c and gravimetric studies. As a relatively shallow (relative to the

seafloor), thick, porous and permeable formation, the Utsira is particularly well suited to evaluation by

both of these monitoring techniques (Chadwick et al., 2006). During a seismic surv ey, seismic waves are

directed into the subsurface. The waves reflect off of various underground features (such as rock layers)

and these reflections are measured by monitoring equipment on the surface. Depending upon the

characteristics of the materials e ncountered by the waves, the st rength of the reflections varies

. These

differences can be used to create an image of the subsurface features of an area ( see Figure 2 ). During

gravimetric monitoring, small variations in gravity (due to mass or density varia tions between

subsurface layers— for example, due to porosity/permeability contrasts or rock that is saturated with

CO 2 ) are measured to create a similar image of underground features. These monitoring techniques

have different strengths and weaknesses and can be used in concert to provide a mo re complete

monitoring profile. For example, s eismic surveys would be more likely to detect small, thick CO 2

accum ulations in a porous material. Although the spatial resolution of gravimetric monitoring is lower, it

ma y detect accumulations of CO 2 that would be undetected by the seismic monitoring (Chadwick et al.,

2006)

.

Figure 2 . Sleipner seismic p ro files from 1994 (pre injection) through 2006. Injection began in 1996. The sequence

of image s shows the evolution of the CO 2 plume (blue and red shaded layers). The darkened horizontal layer

extending across the frame immediately over the blue and red shaded layers represents the top of the Utsira

Formation. Image from Arts et al. (2008). Reprint ed with permission of EAGE/First Break.

Arts et al. (2004) presented the results of four seismic surveys that were conducted in 1994 (before

injection), 1999, 2000, a n d 2002. These results indicate that CO 2 injected at Sleipner is approaching a

steady stat e, spreading through the Utsira formation but not leaking out of the injection zone. The thin

horizontal shale layers within the Utsira Formation appear to act as barriers to vertical CO 2 movement,

forcing the CO 2 to spread laterally instead of rising. Sei smic profiles displaying the extent of the CO 26 plum e show this effect (see Figure 2 ). Additional seismic surveys, conducted in 2004 and 2006, confirm

the earlier conclusion that CO

2 is not spreading beyond the Utsira formation due to a combination of

struc tural, stratigraphic, and chemical trapping mechanisms (Arts et al., 2008).

Chadwick et al. (2006) discussed a 2001 model

- based feasibility study of gravimetry at Sleipner. The

study concluded that gravimetric monitoring would theoretically be able to det ect changes in the CO

2 plume, though the success of such monitoring would be strongly dependent on CO

2 density (which is

influenced by temperature) and subsurface distribution

. Chadwick et al. also described a 2002 seabed

gravity study in which repeated gravity and water pressure measurements were taken by equipment

mounted o n a remotely operated vehicle. A second gravity survey in 2005 (Nooner and Zumberge, 2005)

produced results consistent with the amount of CO

2 that had been injected since the previous s tudy,

suggesting that CO

2 is not leaking from the Utsira Formation.

There have been no documented leaks at Sleipner. However, in 2008 there was an incident at Tordis

Field, a separate Statoil site where operators inject by

- prod uct water from gas production (called

produced water ) into the Utsira Formation (see Figure 3)

. The injected water serves to maintain fluid

pressure in the oil reservoir and is used in hydraulic fracturing.

Figure 3 . Location of the Tordis site relative to the Sleipner site and other hydrocarbon fields on the Norwegian

continental shelf. Map not to scale. Image adapted from the Norwegian Petroleum Directorate (NPD) (no date).

Reprinted with permission of NPD.

Statoil (2008 a ) provided the following account of the incident. On May 14, 2008 workers on a Tordis

area platform noticed oi ly water on the ocean surface. On May 30, 2008 the source of the oily water was

determined to be a crater approximately 60 m from the nearest Tordis well. Injection at that parti cular

well was shut down May 31, 2008 and the l eak stopped shortly thereafter. Further investigation

concluded that the immediate area surrounding the injection site had not been characterized fully7 en ough to understand the risks to subsurface injection po sed by other industrial processes also taking

place at the site.

The leak at Tordis does not directly relate to the CO 2 injection at Sleipner: the two sites are located

approximately 300 km apart in unconnected areas of the formation , and no CO 2 injectio n takes place at

Tordis. In addition, it appears that Statoil made assumptions about the conditions at Tordis that were

not fully supported by site

- specific data. This situation is not comparable to Sleipner, where abundant

data exist to support Statoil’s assumptions and suggest that the Utsira is indeed a good candidate for

CO 2 injection in certain, well characterized locations.

Liability and Long

- Term Assessments

Injection at Sleipner is estimated to continue until 2022. Since the project is operating i n ta ndem with

hydrocarbon production, CO 2 sequestration activities at the site are regulated under Norway’s

Petroleum Activities Act (1996)

. The Act includes emergency preparedness requirements and establishes

“safety zones” with restricted access and acti vities (e.g., fishing) around production

- related facilities.

Activities at the site also fall under the jurisdiction of the Norwegian Pollution Control Act (1981) , which

requires permits for emission of large quantities of CO 2 . Applicants must submit an En vironmental

Impact Assessment prior to permitting; this assessment must include conceivable incidents and their

predicted likelihood, as well as how the activity will restrict future planning. The Act also includes

requirements for emergency response syste m s, as well as periodic and emergency reporting. Additional

project

- specific requirements can be specified in individual permits

. Stato il will have financial liability for

damage, loss, nuisance, or expenses related to the pollution (i.e., release of CO 2 ) under certain

circumstances until the dissolution of the company. However, it is unclear who would pay for corrective

action in the event of a leak after the dissolution of Statoil, given that impacts and risks associated with

the injection operation may p ersist for longer than the life of the company.

The European Union (EU) CCS directive (EU, 2009) provides guidance on post

- closure activities;

however, Norway is not an EU member state and it is unclear whether closure of Sleipner will follow the

EU direc tive.8 

# W EYBURN

Project Background

The Weyburn Project is a combination CO 2 sequestration/ enhanced oil recovery ( EOR ) project operated

under a partnership between Cenovus Energy (formerly Enc ana) and the Petro le um Technology

Research Centre (PTRC), a pub lic- private research partnership. The project is divided into two phases,

Phase I (2000

- 2004) and Phase II (2005

- 2011). The principal aim of the project is to test the technologies

and techniques needed to predict and verify secure, economic storage of CO 2 in an oil reservoir. The

project will also result in the creat ion of a best practices guide for the implementation of GS projects

around the world ( Wilson and Monea, 2004). While Cenovus runs the production and commercial side

of the operation, project re search is handled by the PTRC. The founding members of the PTRC are

Natural Resources Canada, Saskatchewan Industry and Resources, the Saskatchewan Research Council

, and the University of Regina . In addition, a large group of U.S. and Canadian governmental agencies,

including the United States Department of Energy (USDOE), and private industry (including Cenovus,

Shell, and Chevron) have contributed to the project , which also has received support from the

Intern ational Energy Agency Greenhouse Gas Research and Development (IEA GHG R & D) program. The

government of Saskatchewan voiced strong and early support for the project and was instrumental in

ensuring regulatory support.

The project initially involved 22 cons ulting and research companies in addition to roughly 70 technical

and project staff in 6 countries

. Total funding for research for both phases of the project is $ 80 million

collected from the participating entities in cash and in

- kind contributions (PTRC

, no date ; Kristoff, 2007).

Cenovus , in addition to supporting research through the PTRC, also plans to spend approximately $ 1

billion on infrastructure, commercial investments, and other costs at the Weyburn Field (Preston et al.,

2004).

For the final phas e of the project (2005

- 2011), the area of study was expanded to include the adjacent

104 km 2 Midale F ield (Weyburn F ield is 181 km 2 ), which is operated by the Apache Corporation, a

Houston

- based oil and gas company (Preston et al., 2009). Midale Field had previously been the second

largest CO 2 EOR site in Canada following the beginning of CO 2 injection in late 2005.

Structure and Stratigraphy

The Weyburn Project is located in the grasslands of southeastern Saskatchewan in Weyburn Field, a 181

km 2 establ ished oil

- producing field in the Williston Basin in Canada (see Figure 4). The Williston Basin is a

large (approximately 800,000 km 2 ), relatively undisturbed bowl

- shaped structural basin. Sediments are

thinner near the edges of the basin and thickest in th e center, near Williston, ND, where deposits are

nearly 5 km thick. The Williston Basin is a good analogue for other potential CO 2 sequestration sites

because some of the most promising locations currently under investigation ( the Illinois, High Horn, and

Powder River Basin s ) are also large sedimentary basins.9 Figure 4. Location of the Weyburn project within the Williston Basin (green shaded area).

The Williston Basin is seismically stable, though faults are found in the basin and within the units that

comprise the oil reservoir. The last significant seismic activity in the basin occurred near the end of the

Cretaceous (65

‐ 50 Ma) and was related to the Laramide Orogeny (the uplift and building of the Rocky

Mountains). Post

‐ depositional tectonic activity led to the deformation of the sediments in the Williston

Basin, specifically the creation of anticlines which serve as hydrocarbon traps today (Fischer et al., 2005).

Since then, the region has been tectonically quiescent. Faults extending from the units in the oil

reservoir to the surface do occur in the basin but have minimal displacement (Peirce et al., 2004).

Examination of hydrologic data, the compartmentalization of hydrocarbons in the reservoir, and the lack

of migration of hydrocarbons into regions overlying the reservoir all suggest that these faults are sealing

(Peirce et al., 2004). Additionally, these faults have not compromised hydrocarbon retention for the past

50 million years (IEA, 2006). Widely spaced, undersampled two

‐ dimensional (2D) seismic lines were

combined with a High

‐ Resolution Aeromagnetic (HRAM) survey to further characterize faults (Goussev

et al. 2004).

Naturally occurring accumulations of CO 2 in the basin attest to the suitability of the structures and seals

in the basin to contain CO 2 over geologic time: natural gas derived from overlying units above such seals

contains only traces of CO 2 , demonstrating that the seals effectively block upward migration of CO 2

.

Recent sampling has also confirmed that Weyburn Field lies on a steep salinity gradient, which could

impact the long

‐ term fate of injected CO 2 (Wilson and Monea, 2004) if the CO 2 were to leak into

overlying units. Water density varies with salinity, from approximately 1,010 g/L to 1,210 g/L through

the field (Riding and Rochelle, 2005). This difference in density can have a strong effect on the regional

hydrodynamics and the migration of CO 2 as well as the solubility of CO 2 : one mol CO 2 /kg H 2 O can be

dissolved at low salinities, while only 0.78 mol CO 2 /kg H 2 O can be dissolved at high salinities. Mineral

trapping reactions may also be influenced by salinity (Riding and Rochelle, 2005). These findings suggest

that subsurface CO 2 migration models may need to be adjusted in order to accurately predict the

potential CO 2 spread in saline formations.10 Formation water flow velocities are generally very low in the reservoir beds: the average flow rate is less

than 1 m/yr. However, flow velocities are significantly higher (1

- 10 m/yr) in the overlying formation s

(Czernichowski -Lauriol, 2006; Wilson and Monea, 2004)

. Higher flow rates can enhance an aquifer’s

ability to adsorb CO 2 , but can also increase the distance over which sequestered CO 2 can spread over

time (Wilson and Monea, 2004). There is no sign of any inter- connectivity or through

- flow vertically

between any of the formations below, in, or above Weyburn Field (Khan and Rostron

, 2004; Wilson and

Monea, 2004 ).

Injection Zone and Confining Zone

Hydrocarbons in Weyburn Field are hosted in two different a djacent carbonate layers approximately 1.4

k m below the surface . The lower of the two is the Midale Vuggy, a 17 m thick highly fractured and

moderately permeable (10

- 300 mD) low porosity (8

- 20%) limestone. The upper unit is the Midale Marly,

a 6 m thick ch alky low permeability (1

- 50 mD) high porosity (16

- 38%) dolostone (White, 2006; Hutcheon

et al., 2008). The injection zone is at a temperature of 63°C and a pressure o f 14 MPa (White, 2008). The

Marly layer contains the majority of the hydrocarbon reserves (EnCana, 2008) and is less fractured than

the Vuggy. A northeast

- southwest trending fracture set controls flow within the formation (Wilson and

Monea, 2004). These fractures likely developed shortly after deposition as a result of in

- situ tectonic

stresses . There is currently no evidence of similar conductive fractures in the overlying confining zones.

The two reservoir units

— along with underlying and some overlying rocks

— were tilted slightly

(approximately two degrees ) and exposed to erosion during the ea rly Mesozoic/late Paleozoic,

approximately 250 Ma (Riding and Rochelle, 2005). When deposition recommenced, thick sedimentary

sequences were deposited. The boundary between the lower , slightly dipping evaporite and carbonate

units and the overlying sedimen tary rocks is a n unconformity , representing a gap in the rock record.

Several competent confining layers overlie the porous layers. Below the unc onformity, the Midale

Evaporite

— a one to ten meter thick evaporite acts as a highly competent seal abo ve the Midale Marly

. The rocks are further sealed against leakage where they intersect the unconformity by a zone of

anhydrite (an evaporite sulfate mineral) cementation. Anhydrite fills the pore space and prevents

hydrocarbon migration. Above the unconformity, numerous thick, impermeable sedimentary sequences

act as seals. The lowermost of the sedimentary confining layers, the Watrous Formation, is located

immediately above the unconformity. It is a thick mudstone and siltstone formation that creates a

regionally extensive confining layer across Saskatchewan (Whittaker, 2005; Wilson and Monea, 2004).

The Watrous is overlain by several thick and regionally extensive shales interspersed with more porous

units ( see Figure 5 ).

Commercial Development History

Weybur n Field was discovered in 1954 and has estimated reserves of 1.4 billion barrels. Production

began in 1955 (Wilson and Monea, 2004). Today, over 1,072 wells have been drilled into Weyburn Field

as a result of hydrocarbon exploration. Because Saskatchewan r equires that all geophysical logs and

cores be registered and available to the public in a centralized repository, there is a substantial

, readily

available database of geologic information for the Weyburn area (Brown et al., 2001). The availability of

dat a, the relatively simple structure of the basin, the lack of seismic activity, and the ease of access led

to the selection of the site for GS.11 Figure 5

. A c ut

- away block diagram developed for the Weyburn project, showing the su bsurface layers in the area.

Barriers to upward migration are arra nged on the left, while aquifer units are on the right. The color of the Midale

beds (the Vuggy and Marly formations ) varies depending on their salinity

. Image f ro m Wilson and Monea ( 2004).

Reprinted with permission of PTRC

.

EOR efforts at Weyb urn Field have a long history. Water flooding began in 1964, but hydrocarbon

returns began to decrease steadily in the 1960s (see Figure 6 ). While water flooding has mobilized most

of the hydrocarbons i n the Vuggy layer, hydrocarbons remain in the Marly layer (Riding and Rochelle

, 2005; Wilson and Monea, 2004). T he injection of CO 2 is aimed at reversing the decline in production

, and

, as of 2009, it has been highly successful. It is assumed that CO 2 will circulate more readily than

water in the less

- permeable Marly layer, facilitating improved hydroc arbon recovery (EnCana, 2008).

CO 2 reduces the viscosity of oil and causes its volume to increase, helping to extrac t more oil from the

reservoir.

CO 2 injec tion began on September 20, 2000. Water is injected alternately with the CO 2 (water

alternating gas) to help push the released oil to the production wells (SEED, 2008). Since then, oil

production has increased by 65% ( an additional 18,000 barrels per day ) over the predicted 10,000

barrels per day on water flood alone. CO 2 injection has also lengthened the life of the field by 25 years

and CO 2 injection is expected to continue for at least another 20 years (Whittaker, 2005)

.12 Figure 6. Historical production from Weyburn Field. Note the enhanced production after the start of CO 2 EOR.

Image courtesy of Cenovus Energy. Reprinted with permission.

CO 2 used at Weyburn Field is purchased from a coal gasification plant located 320 km to the south in

Beulah, North Dakota. It is compressed to approximately 15 MPa, and the supercritical CO 2 is piped to

Weyburn Field. Currently, Cenovus only uses 40% of the capacity of the pipeline, which was purposely

overbuilt to accommodate future demand from other nearby oil producers, such as Apache (Bergman et

al., 2003). The CO 2 is 96% pure, with 0.9% H 2 S, 2.3% C 2 + hydrocarbons, 0.7% CH 4 , 0.1% CO, 300 ppm N,

<50 ppm O 2 , and <20 ppm H 2 O. The composition is ideal because a small amount of H 2 S gas increases

the miscibility of CO 2 in oil (SEED, 2008). Nearly five thousand tons/day of CO 2 are injected from the

pipeline, and an additional 1,000 tons/day are recycled and reinjected from the production wells (IEA,

2006).

Well Construction

Cenovus injects supercritical CO 2 (Wilson and Monea, 2004) through 29 wells, 16 vertical and 13

horizontal, making Weyburn the world’s largest horizontal injection program (Brown et al., 2001). In

addition, with over 215 horizontal production wells and 284 lateral legs in total, Weyburn is also one of

the world’s most extensive users of horizontal well technology (Wilson and Monea, 2004; Davis et al.,

2002)

. The horizontal well program started in 1991, when it became clear that drilling more vertical

wells was no longer economically viable due to the thinness of the formation and the need to avoid

propagating fractures into the underlying Frobisher Formation. Full commercial deployment of

horizontal wells began in 1993 (Wilson and Monea, 2004; Simpson et al., 1996). Although some early

horizontal wells did have unexpectedly low production rates—occasionally lower than nearby vertical13 offset wells—improvements in drilling technique limited damage to near

‐ wellbore rocks and resulted in

better production rates fo r subsequent horizontal wells (Simpson et al., 1996).

Although vertical wells still account for the majority of Weyburn’s wells, horizontal wells account for

60% of current daily oil production (Simpson et al., 1996) an d have been favored recently since

horizontal injectors and producers are better suited at targeting the lower

‐ porosity Marly Unit.

Complexity of the horizontal wells has also increased. While the first horizontal wells were short (350 m)

single lateral, single build legs drilled under overbalanced conditions, later horizontal wells were drilled

in underbalanced conditions and featured more complex dual, tri and quad leg configurations (Simpson

et al, 1996). Recently, horizontal wells were drilled with a 177.8 mm intermediate casing in the vertical

section and a 158.8 mm open hole bore for the horizontal sections, which can exceed 1,100 m (Simpson

et al., 1996 ; Wilson and Monea, 2004 ). Underbalanced technology was used with later wells to minimize

formation damage.

Horizontal wells within Weyburn are oriented parallel to the predominant fracture direction (Wilson and

Monea, 2004). The current deployment configuration consists of a horizontal well sandwiched between

two production wells approximately 300 m from the injection wells. (Majer and Korneev, 2001; Simpson

et al., 1996) (see figure 7). This type of quad leg horizontal well has over 4,000 m of horizontal exposure

to the formation (Simpson et al., 1996). For water

‐ alternating gas purposes, the horizontal wells are

never used to inject water, only CO 2

. Preexisting vertical wells between the horizontal legs (see Figure 7)

are used to inject water when necessary (Asghari et al., 2007).

Figure 7. A 3D and plan view of the horizontal CO 2 injector scheme at Weyburn. Injection wells are in blue,

producer wells are in red. Image from Majer and Korneev (2001). Reprinted with permission.

CO 2 is also injected using an inverted nine

‐ spot pattern (one injector well surrounded by eight producer

wells), with a typical spacing of roughly 150 m between wells (SEED, 2008). This pattern will be

expanded into a total of 75 patterns, each 1 km 2

, as the flood grows over the next 15 years (Wilson and

Monea, 2004). Weyburn Field is predicted to store 26 Mt of CO 2 before a tentative closure date in 2033.

Monitoring

Injection is monitored at two scales. Regional investigations were carried out over a 200 km by 200 km

by 4 km deep block centered on Weyburn Field. More detailed examinations will be undertaken in an

area extending 10 km beyond the limits of the planned CO 2 flood. A full suite of monitoring studies,

including seismic, wireline logging, core analysis, electrical resistance tomography, geochemical, and14 laboratory studies was planned, and some studies associated with Phase II are still in progre ss. Baseline

measurements wer e taken prior to injection.

Geophysical monitoring using three

- dimensional ( 3D ) and four

- dimensional ( 4D ) seismic technologies

was seen as a great success and included both active and passive systems. Active seismic monitorin g

includes (4D, 3c) 4 surface, (4D, 9c) surface, (3D, 3c) vertical profile, and crosswell seismic between both

vertical and horizontal wells ( Majer and Korneev, 2001) . Crosswell seismic creates images at a resolution

of 1 m or less (Majer and Korneev, 2001) . The (4d, 9c) seismic imaging was not as successful as the other

types, in part due to the fact that operators with field experience deploying the array and processing the

data for this new technology were not available. Passive seismic monitoring was not fully deployed until

several years into the project. Currently, one abandoned vertical well houses eight geophones dedicated

to passive monitoring. Drilling of a nearby injection well caused a number of microseismic events, which

are provisionally attribu ted to fracturing due to injection

- driven fluid migration within the formation.

The monitoring program verified that it is possible to image a thin formation (20

- 30 m) at great depth

(1

, 450 m) with seismic techniques (although individually the Midale Marly and Midale Vuggy sections of

the unit were not resolvable with seismic data) and recording microseismicity in a large oilfield under

CO 2 flood is technically feasible. However, while active seismic monitoring is sensitive to low levels of

CO 2 (5

- 10 molar percent), sensitivity does not increase linearly with concentration. Therefore, while it

may be easy to image the CO 2 plume front, estimating the volume of CO 2 could be m uch more difficult

(IEA, 2006). The microseismic monitoring also confirms that microse ismicity associated with CO 2 flood

does not exceed the magnitudes associated with water floods or gas injection in other monitored

oilfields.

Detailed geochemical samples were also collected. Samples of produced fluids from production wells

were collecte d from 40 wells every four months during 2001

- 2005. Changes in alkalinity, calcium

concentration, and carbon isotopic signature as a result of subsurface CO 2 migration are visible on data

maps. Additionally, isotopic analysis of the carbon in the CO 2 strea m at production wells was used to

track subsurface migration. Likewise, the isotopic composition of CO 2 collected from soil gas surveys was

compared to the isotopic composition of injected CO 2 to assess the possibility of leakage. The soil gas

surveys and flux monitoring were conducted from 2001

- 2003 in and around the Phase 1A injection area

and found no evidence of leakage. Convention al production data analysis was also used to help

determine the migration of the CO 2 ( Wilson and Monea, 2004 ) . Tracer monitoring was considered a

failure due to technical and operational problems (Wilson and Monea 2004)

.

The monitoring program has not reported any leakage from the injection zone.

Liability and Long

- Term Assessments

Several methods were used to predict futur e changes at the Weyburn project site. Methods included

systems analysis and probabilistic risk assessment (Wilson and Monea, 2004; Riding and Rochelle, 2005).

Systems analysis was applied at Weyburn because it is widely used in radioactive waste manageme nt,

which also deals with sequestered storage on very long timescales. This method works by defining the

system and identifying features, events, and processes (FEPs ) that may occur. At Weyburn, a FEP

4 Time lapse studies are 4 D ; the c denotes component. 9c is a relatively new technique, using controlled

polarization shear, compressional source, and three

- component geophones to make a three

- by

- three matrix of

source

- receiver orientation combinations (Thompson

, 2005).15 data base was constructed that could be used for any GS project ; each FEP was assigned a name,

description, relevance to performance, safety issues, and references. The database is available on the

Internet at http://www.quintessa

- online.com/co2 (Riding and Ro chelle, 2005). This list of FEPs was used

to develop a number of potential scenarios used for risk management and planning at the site.

Detailed numerical modeling of CO 2 fate and transport was also conducted. Using the stratigraphic

knowledge of the area and the detailed geochemical information obtained from the well monitoring

program, programmers created a 5,000

- year migration model for CO 2 ( Wilson and Monea, 2004 ). The

model suggested that the most likely scenario for CO 2 migration will result in no si gnificant migration

beyond the Watrous Formation. The long

- term fate of the injected CO 2 was modeled to be 44%

dissolution in oil, 28% sequestration in mineral trapping , and 28% sequestration in solution trapping.

The model also predicted that 35.4% of the CO 2 would migrate, with 0.002% above the injection zone in

5,000 years, although none would migrate into potable aquifers. Predictions also included less than

0.001% cumulative leakage along aba ndoned wells over 5,000 years. In total, the model found a 95 %

probability that 98.7

- 99.5% of injected CO 2 at Weyburn would remain sequest ered for at least 5,000

years. This result is consistent with current field monitoring, which has not detected any CO 2 leakage

(IEA 2006).

Because much more geologic information is available for Weyburn compared to other sequestration

sites, researchers also plan on creating models with reduced data sets in order to determine the

minimum data needed to generate a robust model (Wilson and Monea, 2004).

In Alberta, GS wells are r egulated under Directives 51 and 65 as Class III wells, the same well class as acid

gas injection wells, as well as under the Alberta Oil and Gas Conservation Act . However, these Directives

do not specifically address many of the unique attributes of CO 2 a nd it is unlikely that liability would

apply to leaks caused by natural faults or fractures, although liability would apply to leaks from wells,

pipelines, or other facilities. Leaks would also be difficult to detect, as neither Directive requires post

aba ndonment monitoring (Griffiths, 2008). It is also unclear if sufficient funds would be available for

remediation from the operator or the province. Additionally, it appears that Weyburn/Cenovus currently

holds between $100 million and $250 million in liabi lity insurance, although it is unclear if that insurance

includes risks associated with the CO 2 itself ( Sengupta , 2006).16 

# I N 

# S ALAH

Project Background

In Salah is a combined natural gas production/CCS storag e operation run by Statoil, BP, and Sonatrach,

an Algerian state

- owned company. Research at the site is run by a Join t Industry Project that includes

the three major stakeholders as well as several research and development groups in Europe and the

United States , including representatives from industry , academia, government, and non

- governmental

organizations. The cost of th e project is estimated at $1.7 b ill ion for production infrastructure, $100

m illion for CO 2 capture and storage infrastructure, and $ 30 m illion for CO 2 monitoring, verification, and

r esearch and development (Wright, 2007; Haddadji, 2006 ). The goal of the project is to validate and

improve tools for the prediction and performance of geological CO 2 sequestration th r ough extensive

monitoring and verification of storage in a field environm ent. It is also hoped that the project will

inc rease global visibility of GS and establish it as technol ogy eligible for greenhouse gas mitigation

credits.

The site sequesters CO 2 separated from produced natural gas to avoid venting it into the atmospher e, in

accordance with BP and Sonatrach’s efforts to reduce greenhouse gas emissions. Separation is necessary

because the CO 2 content of the produced gas (1

- 9%) is above the acceptable standard (0.3%) in the

export market where the gas is sold, principally Spain and Italy (Wright, 2007). As a result, the excess

CO 2 must be stripped from the natural gas before it leaves the field for compression and export

.

Structure and Stratigraphy

In Salah is located in the Sahara Desert of Algeria, 1,200 km south of Algiers in the Ahnet

- Timmimoun

Basin (Figure 8 ). The Ahnet

- Timmimoun Basin formed when tectonic forces first pulled apart the area,

thinning the crust and creating a linear depression that accumulated sediments. Later, tectonic forces in

the region compressed, squeezing the sediments that had accumulated in the basin and causing uplift,

erosion, and deformation. Low

- relief anticlines and domes were created as the sediments deformed and

today act as hydrocarbon traps (Iding and Ringrose, 2008)

.

Production, In jection, and Confining Components

Seven hydrocarbon

- producing fields are part of the In Salah project in the Ahnet

- Timmimoun Basin:

Gour Mahmoud, In Salah, Hassi Moumene, Garet El Befinat, Reg, Teguentour, and Krechba. The

Krechba, Reg, and Teguentour fields are currently in production and the lower four fields will join the

line as needed, most likely around 2011, when it will be necessary to supp lement production at the

upper three fields to help maintain a production rat e of 9 billion cubic meters per y ear (Wright, 2007).

Although production occurs or will occur at all fields, CO 2 injection takes place solely at Krechba field.

The detailed geological description below is specific to Krechba Field, which has been the most

comprehensively studied. However, the geology of all seven fields is similar.17 Figure 8. Location of the In Salah gas fields. Map not to scale. Red lines show the distribution of produced gas.

Krechba field is a dome, or symmetrical arch

‐ shaped fold, that covers an area approximately 20 km by 5

km. Natural gas is located at the top of the structure (the gas leg), while water, which is denser than

natural gas, fills the rest of the formation (the water leg) (see Figure 9). In the core of the dome, below

the injection formation, are Devonian (416

‐ 360 Ma) sandstones interbedded with siltstones and

mudstones. Deep

‐ seated, extensional faults intersect these Devonian rocks and propagate upwards, but

none is predicted to intersect the injection zone layers above (Raikes et al., 2009; Ringrose et al., 2009).

This rock is a Lower Carboniferous (359

‐ 345 Ma) sandstone that averages 20 m thick and is

approximately 1,800 m below the surface (Ringrose et al., 2009). These sandstones were deposited in an

estuarine and tidal flat environment that filled the basin during the period of extensional tectonics

(Bishop, 2003). Because estuaries are dynamic, heterogeneous environments, the sandstone layer is also

laterally heterogeneous with several large sinuous sand bodies within the main axis of the dome and

smaller, “feeder” sand bodies toward the edges of the formation (Riddiford et al., 2004). The formation

has a low permeability of 10 mD

‐ 20 mD and a porosity of 13

‐ 20% (Ringrose et al., 2009). The

temperature of the formation is 90°C and it is at a pressure of 17.9 MPa (Iding and Ringrose, 2008). For

comparison, typical oil and gas reservoirs have a permeability of several hundred mD and a porosity of

30% (Knopp, 1965). A 15 m thick fine

‐ grained sandstone/mudstone subunit lies directly on top of the

sandstone.

The sediments above the injection zone are flat

‐ lying and regionally extensive. Numerous surveys have

not detected major faults in the area, and natural gas has been stored for at least 20 million years (BP,

2008). This suggests that major faults will not provide escape paths for sequestered CO 2

. However, the

nature and extent of smaller scale faulting and fracturing in the area is still not well understood. Directly

above the injection zone is 950 m of Carboniferous mudstones that are interbedded with thin dolomite

layers. The mudstone layer contains fractures, as demonstrated by mud losses (periods when drilling

fluid escapes the bore shaft through regions of high permeability or fractures) in the layer. Furthermore,

some parts of the overlying confining sequence above the injection zone display open fractures that

have been shown to influence gas flow. These features still need to be investigated as they might have a18 Figure 9. A schematic illustration of the geology at Krechba Field. Blue

‐ shaded areas represent the water leg of

the dome and red

‐ shaded areas represent the gas leg; the blue and red solid vertical lines represent gas

production wells and CO 2 injection wells, respectively. CO 2 is injected into closer to the bottom of the dome,

while the gas production wells are located more centrally at the top of the dome.

strong influence over CO 2 migration and distribution within the formation (Iding and Ringrose, 2008).

Their influence has the potential to be especially strong because of the low permeability of the injection

zone.

The next major accumulation of sediment above the injection zone is a 900 m block of Cretaceous (145

‐

65 Ma) sandstones and mudstones separated from the Carboniferous mudstones by an erosional

surface, the Hercynian Unconformity. The Cretaceous sediments contain the North

‐ Western Sahara

Aquifer System (NWSAS), a regionally important aquifer (1,000

‐ 3,500 mg/L TDS). The aquifer itself

covers more than 1 million km 2 and serves a population of at least 8.8 million. The annual extraction

amount is approximately 2.2 billion cubic meters and is rapidly increasing, with most water used for

agriculture (OSS, 2008). Risk of contamination from the In Salah site is thought to be very low (Statoil,

2009).

Commercial Development History

All natural gas produced by Krechba and the other active fields is sent to a centralized CO 2 stripping unit

located near Krechba Field. This design minimizes the cost, since CO 2 stripping units are expensive19 (Wright, 2007). At the stripping unit, CO

2 is isolated from the natural gas by an amine process,

dewatered, and compressed at high pressure. It is then piped as a supercritical fluid 14 km to the

injection wells at Krechba field. The compressors have required several repairs since the beginning of

the project, resulting in downtime when separated CO 2 could not be injected at the anticipated volume.

To date, these problems have resulted in the atmospheric venting of 1 Mt of CO 2 to the atmosphere

—

approximate ly 25% of the total CO 2 extracted from the natural gas ( ISG, no date)

.

Well Construction

In Salah relies on horizontal wells; there are currently no vertical production or injection wells at the In

Salah site. Because of the thin production zone, 25 ve rtical wells would have been needed to produce

the required amount of natural gas, a capital investment that would have rendered the project

uneconomical (Foster et al., 2004). Instead, eight horizontal wells were drilled: five for production and

three for injection. Four production wells were drilled at the beginning of the project and a fifth was

drilled when production declined. Fewer wells were needed than previous development plans predicted

because of a highly successful logging while drilling (LWD) p rogram that allowed the horizontal sections

to be completed nearly 100% in the intended formation, while the original feasibility model estimated

the wells would be within the formation 60% of the time.

Horizontal wells were particularly beneficial at In Salah not only because of the thinness of the

formation, but also because of porosity variability of sediments within the formation. Horizontal wells

allowed for targeting several high

- quality sections of the injection zone with a single well. Real

- time

fe edback on reservoir conditions allowed the on

- site drilling team and the off

- site modeling team to

communicate, update models, and make decisions on how to deviate from the planned well trajectory

(“geosteer” ) to improve injectivity.

The horizontal porti ons of the wells are up to 1

, 500 m long (IPCC, 2005) and are fitted with a 11.4 cm

pre

- perforated liner (Riddiford et al., 2004) The horizontal section also has a non

- return valve so that

completion brines can be isolated from this section (Foster et al., 2004). To improve injectivity, the well

was treated with organic acid to dissolve any mud filter cake (Foster et al., 2004). After completion, the

well was tested by injecting brine into the formation. Horizontal sections of all wells run approximately

per pendicular to the maximum regional tectonic stress (which is also the dominant fracture orientation)

to maximize injectivity (Ringrose et al., 2009; Foster et al., 2004).

The production wells are located more centrally above the gas leg of the field, while the t hree horizontal

CO 2 injection wells are located arou nd the p erimeter of the field . The logic behind this arrangement is

that injected CO 2 will migrate updip (towards the top of the dome) over time as natural gas is produced

by the four production w ells at the top of the dome (BP, 2008). It is believed that for the first ten years

after injection, CO 2 will be held in the saline formation n ear the injection sites and reach the production

zone only after 25 years, by which time production wil l have cea sed (Haddadji

, 2006).

The injected C O 2 is 98% pure and is injected as a supercritical fluid at 250 °C and 18 .5- 20 MPa (BP, 2008;

Iding and Ringrose, 2008; Raikes et al., 2009) . This pressure is necessary to penetrate the low

permeability sandstone, but is kept below 41

. 4 MPa to avoid needing specialized high

- pressure

comp ression equipment (Ridd iford et al., 2004 )

. Injection began in August 2004 and is predicted to

continue for 25 to 30 years. The estimated injection volume is 17 Mt of CO 2 (BP, 2008; Michae l et al.,

2009).20 Monitoring

Geophysical, geochemical, and geomechanical monitoring techniques are being tested at the site.

Monitoring commenced prior to injection, with b ase line data acquired in early 2004 (R iddiford et al.,

2004 ). Monitoring is expect ed to continue throughout the project; to allow the utility of a wide variety

of methods to be tested, the exact technologies will be rotated over time. Advanced wireline logging,

core sampling, fluid sampling , water chemistry analyses, downhole gas measur ements (both head gas

and isotubes) and pressure analys e s are part of the monitoring program at each wellhead. P roduction

wells and injection wells are continuously monitored, while Krechba’s seven in active exploration wells

are checked every few weeks ( ISG , no date) 5

.

Various seismic techniques have also been tested; 4D seismic and vertical seismic profile (VSP)

monitoring has worked well and is recommended by BP as a potential monitoring technology for other

sites, while 4D gravity and 4D electrical/electromagnetic monitoring have been only marginally

successful. There is also a dedicated monitoring well for microseismic monitoring ( Ringrose et al., 2009 ).

Permanent Scatter Interferometric Synthetic Aperture Radar (PSInSAR) ( see Figure 10) has also been

used with success at Krechba. PSInSAR uses land surface elevation data collected from satellite flyovers

to inf er subsurface pressure changes. Images have been collected from 2004

- 2007, with data collection

cu rrently occurring at a rate of one image with a resolution of 3 m 2 every 26 days (Mathieson et al.,

2008). Comparison and analysis of the images, which are calibrated with DGPS and tiltmeters, has been

able to detect a maximum of 15 mm uplift in portions o f the field (BP, 2008). Areas where the uplift is

minimal correspond to areas where the formation has the highest porosity (Raikes et al., 2009).

Figure 10. PSInSAR image from In Salah. Dark blue areas have a maximum uplift of 8 mm. Red areas indicate

subsidence. The red and yellow line at left is erosion along a streambed at the site. Notice that uplift tends to

elongate NW

- SE, mirroring the orientation of fracturing in the confining layers (Mathieson et al 2008). Image

from R ingrose et al. (2009)

. Reprinted with permission of EAGE/First Break.

5 However, this statement is inconsistent with the leak at kb

- 5, which went undetected for up to 10 months. It is

possible that this monitoring approach was implemented after the leak was discovered.21 Computer models are not fully able to explain the pattern of uplift, or the migration of CO 2 to well kb

- 5,

which occurred three times faster than was calculated by a model using a homogenous cylindrical plume

(Iding and Ringrose, 2008, Ringrose et al., 2009). Movement may have occurred along a suspected fault

(Iding and Ringrose, 2008). Undiscovered or poorly

- understood fault or fracture systems are likely

reasons that monitoring and modeling do not agree and merit further investigation. To this end, rock

mechanical data have also been more important than expected, helping to model fracture and flow

processes (Ringrose et al., 2009).

Modeling has also been an important contributor to the monitoring program. Because the CO 2 has not

behaved as anticipated due to unknown faults in the area, models have allowed researchers at In Salah

to explore possible future scenarios. M odelers have created a shared

- earth model of the underlying

geology th at incorporates data from well logging, core analysis, seismic data, image logs, and other

sources (Ringrose et al

., 2009).

O ne leak has occurred at Krechba. In June 2007

, surface leakage of CO 2 was detected though the

annulus of an old exploration well ( kb

- 5) by an In Salah gas well monitoring team

. The leak volume was

estimated to be a few cubic feet per day and began some between Aug ust 2006 and June 2007 (Statoil,

2009). Perflourcarbon tracers were injected in June 2007. The tracer from well kb

- 502 was detected in

kb

- 5 10 months later, confirming that injected CO 2 from kb

- 502 had contributed to the leak (Ringrose et

al., 2009). This well, which had been the most prolific injector prior to the incident , was temporarily shut

down (Raikes et al., 2009). The injector is expected to come back online once closure of kb

- 5 is

complete. Plans for well closure include use of CO 2 - resistant cement to prevent further leakage. This

incident demonstrates the importance of identifying and addressing deficient wells in the sequestration

zone.

Liability and Long

- Term Assessments

Long

- term leakage risks were estimated at In Salah using the RISQUE (Risk Identification and Strategy

using Quantitative Evaluation) method, which is commonly used in a variety of settings that r equire

quantification of risk in financial terms (Dodds, 2009). This method uses an expert panel that identifies

risks, their likelihoods, and options. Each potential alternative is then assessed and assigned a cost

benefit (Bowden, 2001). In Salah’s long

- term risk assessment strategy is still in progress; plans to have a

risks workshop with European Regulatory Authorities are in development. In Salah also plans to

compare different risk assessment processes, including RISQUE, the CO 2 sequestration risk mod el CO 2 Predicting Engineered Natural Systems (CO2

- PENS), and methods developed by Det Norske Veritas

( DNV), a Norwegian risk

- management organization. They hope to find the best method to understand

and communicate containment risks, as well as how to best identify knowledge gaps and development

strategies that could be used to reduce risks (Dodds, 2009). While BP does not usually buy insurance on

its projects, Sonatrach did buy a minimum of $200 million liability insurance for In Salah, although

effects fro m the CO 2 were not included in the insurance ( Sengupta , 2006)

.22 

# C ONCLUSIONS

Although Sleipner, Weyburn, and In Salah are three of the highest -profile GS projects currently in

operation, many other projects have been completed, are underway, or are in the planning stages.

These other projects reflect an even wider array of geologic environments and will continue GS

investigation efforts with a total planned injection volume of over 200 Mt of CO 2 . They include Otway

(Australia), Zama (Canada), Gorgon (Aust ralia), KB

- 12 (The Netherlands), Mongstad (Norway), CarbFix

(Iceland), Ketzin (Germany), Aracas (Brazil), Lacq (France), Snohvit (Norway), and Minami

- Nagaoka

(Japan). The insights and experiences gained at Sleipner, Weyburn, and In Salah not only help guid e

injection and monitoring operations at these sites, but can also continue to inform the development of

regulations governing sequestration in countries around the world.

Geologic Setting and Siting Requirements

Although the three projects discussed he re are located in very different environments, CO 2 has been

successfully sequestered and monitored in the subsurface at each site. All three projects occur in

different geologic settings: a sub

- seafloor, thick, undeformed, homogenous, porous sandstone brin e

formation (Sleipner), a heterogeneous, fractured carbonate hydrocarbon reservoir within an intra

continental sedimentary basin (Weyburn), and a thin, “tight,” heterogeneous sandstone with low

permeability influenced by a fault and fracture network within a natural

- gas bearing dome (In Salah).

Each setting successfully supported CO 2 sequestration and monitoring, suggesting that GS may be

applicable to a wider range of geologic environments than previously envisioned. The innovative

reservoir imaging and “measurement while drilling” well placement techniques used at In Salah highlight

how current technologies are capable of addressing challenging site

- specific geologic conditions . In

Salah and Weyburn also highlight how heterogeneous formations are suitable for GS , in addition to the

better-researched homogenous sands such as those found at Sleipner.

Construction

Experience from all three sites shows that h orizontal drilling techniques are helping to expand storage

capacity and improve injection proficiency by targeting injection into the most promising sections of

ideal and less ideal formations. Horizontal wells play a key role at all three sites reviewed in this

document and are likely to be an essential component of many other GS operations, especially t hose in

less than ideal conditions where maximizing wellbore contact with high

- permeability intervals and/or

pay zones is critical. For example, In Salah uses horizontal wells exclusively for both CO 2 injection and

gas production. This experience can help guide the creation of reasonable and safe permitting

conditions for horizontal wells.

Geology

These three projects have confining units with varying characteristics and different relationships to fresh

water aquifers. While Weyburn has both multiple unde rlying and overlying aquifers that alternate with

confining units, In Salah and Sleipner have only limited confining layers and few

— if any —overlying

aquifer units. Because none of the sites has experienced large

- scale or systemic failure, it is difficult t o

judge how important these additional layers may be when ensuring storage safety or security. While the23 lack of major failures is certainly positive, it has resulted in a lack of direct experience with the

implementation of remediation technologies and to ols designed to detect the extent of contamination,

especially if CO 2 were to migrate to regions where it may undergo phase transitions that would

necessitate a change in monitoring methods. However , in the absence of better data regarding large

scale cont ainment breaches, these projects suggest that single, thick confining zones may be sufficient

to protect aquifers (including sources of drinking water) and successfully sequester CO

2

. The safe

injection of CO 2 between aquifers at Weyburn illustrates the ab ility to successfully inject into zones that

lie above or between aquifers provided appropriately protective permitting conditions are in place.

Monitoring

The variety of monitoring techniques deployed to track subsurface migration of CO 2 also offers an

important lesson. While these three projects operate in vastly different settings, teams at each site have

successfully monitored the subsurface migration of CO 2 . Although the techniques that have proved most

useful were not always the ones initially flag ged as high priority (e.g.

, PSInSAR at In Salah), workable

monitoring strategies were found within a short period of time for all sites. This suggests that regardless

of the number, thickness, or other properties of the overlying units or the geologic properties of the

formation, successful monitoring can be accomplished. Experience has also revealed the value of

flexible, site

- specific monitoring plans capable of detecting surprises, such as the complex geometry of

the plume distribution at In Salah. Monitoring should be adaptable enough to be able to focus on areas

or features that originally may not have been a priority.

Monitoring methods at all sites have been, by and large, evaluated independently. However, it is

possible that lower

- quality, less

- exp ensive monitoring methods can be combined to produce results

with a greater degree of certainty than the results of a single method. No matter how high the

resolution of a single method, it will still be hampered by the technical and interpretive limitatio ns of

the technology. Co

- processing of two or more monitoring methods may alleviate this problem, as the

strengths of one method can compensate for the weaknesses of another. Combined monitoring

approaches may also help to avoid a reliance on costly cuttin g- edg e seismic methods. Although seismic

methods are the most developed and are familiar to the oil and gas industry, they

— like all method s—

suffer drawbacks that improvements in technology alone cannot overcome or that will come only at a

very high cost. T he variety of monitoring techniques used at all three sites attests to the variety of

alternative methods that could be economically used to complement and inform geophysical data in

new ways and the importance of a robust, adaptable, multi faceted testing and monitoring regime.

Leaks

There have been no major containment breaches or large

- scale leaks of injected or stored CO 2 at any of

these three projects. (This does not include the unplanned venting of CO

2 at In Salah, where CO 2 was

purposefully released to the atmosphere.) There have been small incidents, however, in the Utsira

Formation and at In Salah. Although the Utsira leak may appear the most alarming because the

formation is often described as the ideal storage site, on closer examination it is no t as problematic to

the Sleipner project as it first seems. Although the leak did occur in the Utsira Formation, it occurred 300

km from Sleipner and involved the leakage of brine, not CO 2 . The actual CO 2 injection site, which was

subject to extensive site characterization and monitoring, continues to be a successful demonstration of

GS

.24 Less discussed is the subsurface leak at In Salah, where sequestered CO 2 reached the surface through

the casing of an abandoned exploration well. This incident confirms th at older or poorly completed or

plugged wells may serve as leakage pathways, as well as the importance of corrective action programs.

Additionally, there were only six abandoned wells, all with known locations, at the In Salah site. In

contrast, many poten tial sequestration sites have hundreds of abandoned wells, with only fragmentary

data describing the locations, conditions, or drill depths of each well. The leak at In Salah highlights the

importance of abandoned wells as potential leakage pathways and un derscores the need to carefully

locate any abandoned wells within the sequestration zone and address them through proper corrective

action. Weyburn, a mature field with a minimum of several hundred wells, demonstrates that se cure

sequestration is possible even when many perforations into the formation exist.

A complex fracture system within the confining units may have also contributed to the leak at In Salah.

Subsequent characterization of the fracture system confirmed that fractures did connect one of th e

injection wells to the abandoned exploration well, emphasizing the need to carefully characterize the

local geology on a fine scale before beginning GS operations.

Another consideration In Salah raises is the desirability of injecting CO 2 in to potential water resources in

desert or near -desert regions. Scarcity of water resources in Algeria has already led to implementation

of desalinization projects. Therefore, special consideration may be called for when injecting CO 2 into

saline formations in dry or h igh water use environments, given that even very saline waters may be

needed for drinking water or irrigation in the future.

Liability and Long

- Term Assessments

Although monitoring and leak detection are a key component at all sites, it appears that none of the

three sites has a transparent, holistic approach to long

- term liability. While liability issues associated

with separation, transport, and injection of CO 2 are usually well defined in legal terms, the legal

landscape associated with long

- term liability of geologically sequestered CO 2 remains uneven: some

jurisdictions define liability while others

— as is the case with the three projects discussed here

— do not.

Many decisions related to when and who will be responsible for long

- term care at sites need to be

reached at a more consistent level before widespread adoption of GS can become a reality.

Interaction Among Projects

It is important to note that these studies occurred in isolation from other sequestration activities.

Sedimentary basins could pot entially host multiple sequestration projects, especially in areas that are

more heavily developed and/or contain multiple point sources of CO

2 . The pressure fronts from these

operations (the area where subsurface pressure remains elevated due to the displ acement of fluids) are

likely to be very large, on the order of 100 km or more, and simulation studies have shown a large

potential to interact (Birkholzer and Zhou, 2009). The effects from the pressure fronts may be additive

where they intersect, leading to regions of elevated pressure that could be sufficient to push brines

upward into other layers if pathways through the confining layers (such as abandoned wells) exist. While

the projects discussed here did not take into account pressure front interactio ns, such interactions could

potentially occur in some basins and need to be considered in order to ensure the safety of water

resources

.25 Storage Capacity

Success at In Salah using improved well drilling technologies may force a recalculation of global CO 2 storage estimates (Cook, 2006). Currently, some estimates only include high

- quality “ideal” homogenous

and porous sandstones when calculating total storage capacities. The success at In Salah could have

global impacts on storage estimates, as some region s which were previously deemed marginal or

inappropriate for GS may now be considered as potential sequestration sites.

Scale of Deployment

While these projects offer valuable insight into appropriate GS sites and technologies, much work

remains. As an example, CO 2 emissions for the United States alone in 2007 were 6,021 Mt CO 2 (EIA,

2008), while the total CO

2 stored at Sleipner, In Salah, and Weyburn will be 68 Mt over a period of about

25 years. This comprises roughly 1.2% of a single year’s U.S. CO 2 e missions. Government support will be

a key ingredient in the successful adaptation of GS technologies: all three projects succeeded in part

because of government support. In the United States, the Carbon Capture and Storage Interagency Task

Force developed a set of recommendations for U.S. CCS implementation and delivered their findings in

August 2010. The Task Force concluded that widespread, cost

- effective CCS implementation will only

occur with legislative support because policy can provide the largest incentive for the development of

new CCS technologies ( Interagency Task Force on Carbon Capture and Storage , 2010).

However, as adoption and implementation of GS grows, public opinion may influence governm ental

decision making . Therefore, it is important to develop outreach programs and allow forums for public

input and interaction. These projects

— especially Sleipner and In Salah, and to a lesser extent

Weyburn

— did not have to consider this due to their remote locations or, in the case of Weyburn, the

high degree of familiarity with hydrocarbon operations in the local community.

GS promises to be a valuable tool to help mitigate global greenhouse gas emissions. These projects

showcase the variety and applicability of current technologies and highlight are as for future research

and development.26 

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European Research Team. British Geol ogical Survey Research Report RR/05/03.

Sengupta, P. 2006. Is Geosequestration a unique liability exposure for insurers? IEA, 3rd Monitoring Network

Meeting, Melbourne; 30th October 2006.30 Simpson, J.G., A.C. Edmunds, T. Bittner, and L. Muir. 1996. Perfo rmance Optimization of Horizontal Wells: A

Company's Experience with Horizontal Well Acid Stimulations. International Conference on Horizontal

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Thom pson, C. 2005. Multicomponent Seismic: A Pragmatist's Primer. Search and Discovery Article #40155. Posted

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Torp, T.A., and K.R. Brown. 2006. CO 2 Underground Storage Costs as Experienced at Sleipner and Weyburn.

Available on the Internet at: http://faculty.jsd.claremont.edu/emorhardt/159/pdfs/2006/Torp.pdf

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Whittaker, S. 2005. Geological Characterization of the Weyburn Field for Geological Storage of CO 2 : Summary of

Phase I Results of the IEA GHG Weyburn CO 2 Monitor ing and Storage Project. In Summary of

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White, D. 2006. Seismic Monitoring of CO 2 Injection at the IEA Weyburn CO 2 Monitori ng and Storage Site:

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http://www.rite.or.jp/English/lab/geological/geowse/21 -1- 1 White v2.pdf

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Wilson, M., and M. Monea, eds. 2004. The IEA GHG Weyburn CO 2 Monitoring and Storage Project Summary Report

2000

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## In Salah

Bishop, C. 2003. Carbon Dioxide Storage in the In Salah Gas Project Central Algeria. BP : 2003. Available on the

Internet at: http://www.netl.doe.gov/publications/proceedings/03/carbon

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Bowden, A.R., M. R. Lane, and J.H. Martin. 2001. Triple Bottom Line Risk Management. John Wiley & Sons, Canada.

BP . 2008. Sealed under the Sahara. Frontiers, December 2008, pp 18

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Dodds, K. 2009. The In Salah CO 2 JIP: Status and Overview. 5th IEA monitoring meeting, Tokoyo, Japan; June 2

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2009.

Foster, L., A. Aidoo, A. Tourqui, J. Castle

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Delivers Outstanding Krec hba Horizontal Well Performance. 6Th Journees Scientifiques et Techniques,

Hôtel Hilton, Algiers, Algeria; June, 2004.

Haddadji, R. 2006. The In

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Development Mechanism s, September 19

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Iding, M., and P. Ringrose. 2008. Evaluating the impact of fractures on the long

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Washington, DC.31 In Salah Gas (ISG). 2008. Data Acquisition to Support the In Salah Gas CO

2 Injection Monitoring and Verification

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ISG. No date. In Salah Gas Project Web Site

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Intergovernmental Panel on Climate Change (IPCC). 2005. IPCC Special Report on Carbon Dioxide Capture and

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New York.

Knopp, C.R. 1965. Gas

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Technology 17(9):1111

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Mathieson, A., I. Wright, D. Roberts, and P. Ringrose. 2008. Satellite Imaging to Monitor CO 2 Movement at

Krechba, Alg eria. 9th International Conference on Greenhouse Gas Control Technologies (GHGT

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Washington DC. Paper 307, Technical Session 7A.

Massachusetts Institute of Technology (MIT). 2009c. Carbon Capture & Sequestration Technologies @ MIT: In

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Raikes, S., A. Mathieson, D.M. Roberts, and P. Ringrose. 2009. Integration of 3D seismic wit h satellite imagery at In

Salah CO 2 sequestration project, Algeria. Published by Statoil & BP.

Riddiford, F., I. Wright, C. Bishop, T. Espie, and A. Tourqui. 2004. Monitoring Geological Storage: The In Salah Gas

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(GHGT

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development around well KB

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Sahara and Sahel Observatory (OSS). 2008. The North

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a transboundary water basin. Tunis: 2 008. ISBN 978

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Statoil. In Salah CCS. 2009. Available on the Internet at:

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Wright, I. 2007. The In Salah Gas CO 2 Storage Project. Intern ational Petroleum Technology Conference, Dubai. IPTC

IPTC

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Wright, I., M. Keddam, and P. Ingsoy. 2005. Carbon Dioxide Storage Assurance Project: Report on Year 1. May 4,

2005. In Salah CO 2 Project – NETL Conference.



## Conclusion s

Birkholzer, J.T ., and Q. Zhou. 2009. Basin

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2 Storage: Regulatory and Capacity

Implications. Lawrence Berkley National Laboratory: Paper LBNL

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http ://repositories.cdlib.org/lbnl/LBNL

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.

Cook, P. 2006. Perspectives on Carbon Dioxide Capture & Storage. ECOAL: 5

- 7; January 2006.32 Gouveia, F.J., and S.J. Friedmann. 2006. Timing and prediction of CO
2 , eruptions from Crystal Geyser, UT. Lawrence

Live rmore National Laboratory, Report: UCRL

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Interagency Task Force on Carbon Capture and Storage. 2010. Report of the Interagency Task Force on Carbon

Capture and Storage. August 2010. Available on the Internet at:

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United States Energy Information Administration (EIA). 2008. Emissions of Greenhouse Gases Report. Report #

DOE/EIA

- 0573(2007). Available on the Inter net at: http://www.eia.doe.gov/oiaf/1605/ggrpt/

.



## International Regulations (includes sources for the table in Appendix 1

- A)

Alberta Oil and Gas Conservation Act, R.S.A. 2000, C. O

- 6. Available on the Internet at:

http://www.canlii.org/en/ab/laws/stat/rsa

- 2000 -c-o- 6/latest/

.

Barton, Barry. 2009. Requirements for a Legal Regime for Carbon Capture and Storage in New Zealand. Avai lable

on the Internet at: http://neri.org.nz/pdfs/conference09/Barton.pdf

.

British Columbia Petroleum and Natural Gas Act [RSBC 1996] Chapter 361. 1996.

Council Directive 85/337/EEC of 27 Jun e 1985 on the assessment of the effects of certain public and private

projects on the environment. 1985. Available on the Internet at: http://eur

lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:31985L0337:EN:HTML

.

Department of Energy and Climate Change (United Kingdom). 2009. A Consultation on the Proposed Offshore

Carbon Dioxide Storage Licensing Regime. URN 09D/753. Published by the Department of Energy and

Cl imate Change.

Directive 2008/1/EC of the European Parliament and of the Council of 15 January 2008 concerning integrated

pollution prevention and control. 2008. Official Journal of the European Union; L 24/8 29.1.2008.

Directive 2009/29/EC of the Europe an Parliament and of the Council of 23 April 2009 amending Directive

2003/87/EC so as to improve and extend the greenhouse gas emission allowance trading scheme of the

Community. 2009. Official Journal of the European Union; l 140/63 5.6.2009.

Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of

carbon dioxide and amending Council Directive 85/337/EEC, European Parliament and Council Directives

2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC, 2008/1/EC and Regulation (EC) No 1013/2006. 2009.

Official Journal of the European Union; L 140/114 5.6.2009.

Draft German Legisitation

- "Entwurf Gesetz zur Regelung von Abscheidung, Transport und dauerhafter

Speicherung von Kohlendioxid" [In German]. 2009.

Dulk, J.L. Den. 2009. Unofficial Translation of the Mining Act of the Netherlands as amended in 2006, 2008, and

2009 prepared for NAM. Available on the Internet at:

http://www.nlog.nl/resources/Legislation/Engelse%20vertaling%20Mijnbouwwet1.pdf

.

Forbes, S.M., P. Verma, S. J. Friedmann, T. E. Curry, S. M. Wade, and J. Venezia. 2008. WRI CCS Guidelines and

Emerging Geologic Sequestration Regulations: A Comparativ e Assessment. Presented at 9th International

Conference on Greenhouse Gas Control Technologies (GHGT

- 9), 16

- 20 November; Washington DC.33 Hallenstvedt, N.K. 2008. Current CCS Regulation in Norway. UCL Faculty of Laws Centre for Law & the Environment

Carb on Capture Legal Programme. Available on the Internet at:

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.

Haszeldine, R.S., D. M. Reiner, S. Shackley, M. Kendall. 2007. Reg ulation for CCS beneath the UK offshore and

onshore: Deep geological storage and sequestration of CO 2 . International Risk Governance Council.

Available on the Internet at: http://www.irgc.o rg/IMG/pdf/IRGC CCS Haszeldine07.pdf

.

Hinc, A. 2010. How to efficiently implement CCS in Poland? [Draft English version; original in Polish].

demosEUROPA

- Centre for European Strategy: Warsaw, Poland.

Holloway, S., A. Karimjee, M. Akai, R. Pipatti, a nd K. Rypdal. 2006. 2006 IPCC Guidelines for National Greenhouse

Gas Inventories; Chapter 5. Volume 2: Energy, Carbon Dioxide Transport, Injection and Geological Storage.

Industrial Science and Technology Policy and Environment Bureau; Ministry of Economy, Trade and Industry

(Japan). 2009. For safe operation of a CCS demonstration project. Carbon Dioxide Capture and Storage

(CCS) Study Group.

International Risk Governance Council. Draft Version, November 2007. Policy Brief: Regulation of Carbon Capture

and Storage. Available on the Internet at: http://www.irgc.org/IMG/pdf/IRGC CCS Haszeldine07.pdf

.

Law Relating to the Prevention of Marine Pollution and Maritime Disaster (Extracts) (Law No. 136 of 1970 as

amended through Law No. 68 of 1998). Japan.

Ministerial Council on Mineral and Petroleum Reserves (MCMPR). 2006. Carbon Dioxide Capture and Geological

Storage: Australian Regulatory Guiding Principles. Available on the Internet at:

http://trove.nla.gov.au/work/30967080?selectedversion=NBD40004701

.

Ministry of the Environment (Norway). Act of 13 March 1981 No.6 concerning protection against pollution and

con cerning waste.

North Sea Basin Task Force. 2007. Storing CO 2 under the North Sea Basin. Available on the Internet at:

http://www.regjeringen.no/en/dep/oed/Documents -and-publications/reports- 2/2007/Storing

- CO2

-

under

- the -North- Sea

- Basin.html?id=473307

.

Norwegian Petroleum Directorate. Act 29 November 1996 No. 72 relating to petroleum activities. Last amended by

A ct 14 December 2001 No 98, 28 June 2002 No 61, 20 December 2002 No 88, 27 June 2003 No 68, 7

January 2005 No 2, 30 June 2006 No 60 and 26 January 2007 No3. Available on the Internet at:

http://www.npd.no/en/Regulations/Acts/Petroleum -activities-act/#Sectio n 1 -1

.

Odeh, N., H. Haydock. No date. International CCS Policies and Regulations. WP5.1a/WP5.4 Report. Available on the

Internet at: http://www.nzec.info/en /assets/Reports/International- Policies

- Regulations

- English.pdf

.

OSPAR Convention for the Protection of the Marine Environment of the North

- East Atlantic: OSPAR Guidelines for

Risk Assessment and Management of Storage of CO 2 Streams in Geological Formatio ns. Reference number

2007

- 12.

Parliament of the Commonwealth of Australia House of Representative: A Bill for an Act to amend the Offshore

Petroleum Act 2006, and for other purposes. 2008. Draft, as read a third time.

Queensland Parliamentary Counsel. 2 009. Greenhouse Gas Storage Act.34 Queensland Parliamentary Counsel. 2004. Petroleum and Gas (Production and Safety) Act 2004. Act No. 25 of

2004.

Risk Assessment and Management Framework for CO 2 Sequestration in Sub

- Seabed Geological Structures (CS

SSGS) (Source LC/SG

- CO2 1/7, annex 3). 2006. Adopted at the joint session of the 28th Consultative

Meeting of Contracting Parties under the London Convention and the 1st Meeting of Contracting Parties

under the London Protocol.

Simpson, Judith Clerk of the Privy Council. 2009. Gas Environmental Protection. The Gas Importation and Storage

Zone (Designation of Area) Order 2009.

South Australia Petroleum and Geothermal Energy Act 2000.

South Australia Petroleum and Geothermal Energy Regulations 2000 under the Petroleum and Geothermal Energy

Act 2000.

United Kingdom. Energy Act 2008; Chapter 32.

U.S. Energy and Information Administration (EIA)

. 2010. International Energy Statistics. Available on the Internet

at: http://tonto.eia.doe.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=1&pid=7&aid=6

.

Zakkour, Paul. 2007. Technical support for an enabling policy framework for carbon dioxide capture and geological

storage, Task 2: D iscussion paper

- Choices for regulating CO 2 capture and storage in the EU.

Zakkour, P., M. Haines. 2007. Permitting issues for CO 2 capture, transport and geological storage: A review of

Europe, USA, Canada and Australia. International Journal of Greenhouse Gas Control 1: 94

– 100.35 

# A PPENDIX 

# I: R EVIEWING 

# I NTERNATIONAL 

# R EGULATIONS

To provide context on the international regulatory environment, the following section presents GS

regulations, both current and in development, from jurisdictions around the worl d. First, a

comparison chart presents the basic characteristics of GS regulations in the European Union,

Germany, Norway, Poland, the United Kingdom, Canada, Australia, and Japan, as well as guidelines

from the Intergovernmental Panel on Climate Change (IPCC) and requirements from the London

Protocol and Convention for the Protection of the Marine Environment of the North

- East Atlantic

(OSPAR). Second, a set of short case studies provides more detail on four selected

jurisdictions/agreements: the European Union, Canada, Australia, and the London Protocol. These

case studies delve deeper into some of the requirements presented in the comparison chart, as well

as the regulatory mechanisms used to enforce them. These case studies highlight some of the more

subt le differences in regulatory strat e gies and underscore the diverse array of approaches to

regulating GS.36 

# A PPENDIX 

# I-A: I NTERNATIONAL 

# R EGULATIONS 

# C OMPARISON 

# C HART37 

# International Regulations Governing

Geologic Sequestration of CO

2

Activity Requirements/Characteristics

General

Permit

Application &

Siting

Area of Review

(AoR)

Construction

Monitoring

Reporting

Closure

Enforcement &

Fees

Liability Transfer Legislation finalized and adopted

Covers offshore storage

Covers onshore storage

Regulator has broad authority to add additional requirements

Requires assurance of complete retention forever, no risk,

or similar absolute

Specifies permitting application process

Multi-stage permitting process

Parallel permitting process (permits for >1 law)

Length of exploration permit (years)

Exploration permits are exclusive

Potential sites auctioned by regulator

Permits only issued in designated zones

Size limits specified for permit area

Requires environmental impact assessment or similar

(effects on humans, property, wildlife)

Designates an area of review (AoR) or similar

Operator must remediate faults/wells in AoR before operating

Requires reservoir model

Requires hydrogeological assessment

Requires caprock assessment

Special materials required in wells

Requires wellhead safety features to prevent blowout

Plugging/cementing material or length requirements

Requires CO 2 stream monitoring (injection rate and pressure)

Requires CO 2 stream purity/composition monitoring

Operator must specify/report total volume of CO

2 stored

Operator must report emergencies/accidents

Operator must report any changes in operations

Operator must report results of monitoring at regular intervals

Operator must submit well plugging/closure report

Regulator can remediate damage, collect cost from operator

Financial security required from operator

Storage taxed on per-unit basis

On-site inspections

Transfer of liability to state after closure

Period of post-closure prior to transfer of liability (years) X X X X X

X X X X X X X X

X X X X X X Xnoniean Upour E

X X X X X NA

X X X X X

X X X X X X X X

X X X X X X X V

X X X X X V

V NA 3 NA 3 1 V NA NA V

X X NA X V NA NA V

V X V

X X X NA V

X X V NA V

X X X X X X X X XGermany

X X X X X V X X XNorway

X V XPoland

X X X X X X X XUnited Kingdom

X X X X X X XCanada

X X X X X X XAustralia

X X X X

X X XJapan

X X X X X X XIPCC Guidelines

X X X X X X X X

X X X X X X X X XLondon

X X X X X X X X XProtocol/OSPAR

X X X X X

X

X X X X V X X

X X X X

X X X X X X

X X X X X X X

X X X

X X X X X X X

X X X X X NA

20 30 NA 20 V NA 15 NA NA NA



### Key: X = Yes; Blank = No; NA = Not Applicable; V = Varies among member jurisdiction s; Numbers where appropriate38 

# A PPENDIX 

# I-B: L EGISLATIVE 

# C ASE 

# S TUDIES

European Union

The European Union (EU) current ly has seven directives that are at least partially relevant to geologic

sequestration of CO 2 . EU directives are issued by th e Council of the European Union and all member

states are required to create or amend legislation to include the requirements of the directive. Because

the EU functions as a single economy, this is vital to creating a fair market in which no member state

has a competitive advantage in attracting industry based on less restrictive legislation. However, given

the latitude allowed in translating directives into law as well as differences in enforcement levels

among countries, there can still be some variation in how the directives are applied.

**•** Directive 85/337/EEC

. As noted above, several EU directives could be applied to GS.

Directive 85/337/EEC (1985) requires an environmental impact assessment for all

public and private projects that are likely to have a significant impact on the

environment. GS falls under the category of “deep drilling,” which is listed in Annex II

to the Directive. This means that GS projects would be subject to an environmental

impact assessment at the discretion of the member state.

**•** Directive 96/82/EC

. Directive 96/82/EC controls the storage of dangerous substances

and could be applied to GS s ince CO 2 is mildly corrosive in water. This directive

requires notification to the appropriate government of intent to create or expand a

storage site, as well as requiring a major accident prevention policy and regular

reporting.

**•** Directive 2003/87/EC

. In essence, Directiv e 2003/87/EC would require operators of GS

sites to return emissions trading credits for any leaked CO 2

.

**•** Directive 2004/35/EC

. If a GS project resulted in pollution that damaged habitat,

harmed protecte d species, or contaminated land Directive 2004/35/EC would require

the operator to pay for remediation.

**•** Directive 2008/1/EC

. Directive 2008/1/EC is a very broad directive that requires certain

basic environmental considerations for all industrial sites.

**•** Directive 2009/29/EC

. Directive 2009/29/EC makes ext ra allowances (carbon credits)

available for up to 12 GS demonstration sites.

**•** Directive 2009/31/EC

. Directive 2009/31/EC lists detailed requirements for permitting,

construction, monitoring, reporting, enforcement, and liability for GS projects (but

does not apply to projects storing under 0.1 Mt of CO 2 ). Directive 2009/31/EC also

mandates fair access to CO 2 transport networks (pipelines) and storage sites to allow

potential operators such as electrical utilities the opportunity to transport and

geologica lly sequester their CO 2 streams. Additionally, Directive 2009/31/EC lists39 Directives 2008/1/EC, 85/337/EEC, 2003/87/EC, and 2004/35/EC as being applicable

for regulating certain aspects of CCS.

As the above descriptions demonstrate, the EU already had a considerable amount of legislation

ap plicable to GS before adding three additional directives (2003/87/EC, 2009/29/EC, and 2009/31/EC)

to clarify the requirements and incentivize the practice. G reater legal specificity from the outset may

encourage develop ment of GS sites. Specific legislation allows operators to know exactly what

regulatory standards they would be held to, alleviating the scenario where future development of

stricter rules or unfavorable interpretations of existing vague rules would mandate unprofitable

changes in the operation of GS sites.

These new directives may encourage GS and help the EU reach its 20% target for total CO 2 emission

reduction by 2030. Deployment of GS could result in as much as a 3% reduction in total emissions, 15%

of the target reduction goal.

Canada

The Canadian provinces of Alberta and British Columbia developed laws to regulate underground

injection of acid gas, water, and industrial wastes for storage or enhanced recovery in the mid

- 1990s.

Although these laws were mainly intended for sulfurous acid gases such as H 2 S (derived from the

production of sour oil and natural gas), they also cover CO

2 . For example, CO 2 is often co

- injected with

H 2 S because it is co

- occurs in sour oil and natural gas and it is costly to separate. The laws described

below do not apply nationally, but only to the provinces of Alberta and British Columbia , respectively.

**•** Directive 051 [Alberta]

. Directive 051 (Injection and Disposal Wells - Well

Classifications, Completions, Logging, and Te sting Requirements) was passed in 1994.

This law lists specific requirements for injection wells based on five classes of wells. GS

wells are grouped with EOR and acid gas wells and are subject to the same

requirements. Although this law is among the oldes t legislation regulating the injection

of gases underground for permanent storage, it includes many of the same provisions

as more recent GS legislation.

**•** Directive 065 [Alberta]

. Directive 065, Resource Applications for Conventional Oil and

Gas Reservoir s (revised 2009)

, added a few more requir ements for acid gas injection. It

also provided a guide to applicants on the requirements for injection and the

application process.

**•** British Columbia Petroleum and Natural Gas Act

. The law relevant to GS in British

Columbia is the British Columbia Petroleum and Natural Gas Act (1996, last updated

2009). CO

2 is re gulated under the category of “natural g as,” which includes all non

petroleum fluid hydrocarbons, hydrogen sulfide, CO 2 , and helium. CO 2 injection is

subjec t to restrictions similar to those under Directive 051 in Alberta.

Australia

Australia possesses about 9% o f the world’s coal reserves ( EIA, 2010) and only 0.3% of the world’s

population. Given these rich coal reserves, and the greenhouse gases released by burning them,40 Australia’s rapid development of GS legislation may reflect an attempt to continue developing

domestic energy sources while pursuing more environmentally friendly strategies.

Currently, Australia has five laws (at both national and stat e levels) that are relevant to GS. The

Australian Ministerial Council on Mineral and Petroleum Resources (MCMPR) released regulatory

guiding principles in 2005, which influenced the development and/or amendment of several of those

laws. These are very general and broad suggestions with no specific enforcement suggestions;

however, they served as the basis for legislation that was more specific and enforceable.

**•** Offshore Petroleum and Greenhouse Gas Storage Act of 2006 [National]

. In 2008, an

amendment to t he Offshore Petroleum Act of 2006 renamed it the Offshore Petroleum

and Greenhouse Gas Storage Act of 2006 and added GS provisions to that Act. These

provisions include requirements for permitting, siting /Area of R eview, monitoring,

reporting, financial responsibility, and post

- injection site care. The Act specifically

excludes EOR operations, and clarifies that holders of a GS permit do not have any

rights to incidentally discovered petroleum. As its name implies, the Offshore

Petroleum and Greenhouse Gas Storage Act of 2006 only covers offshore storage.

More specifically, it covers offshore storage in national waters, which generally include

areas between “coastal waters” (administered by the states) and the edge of the

continental shelf. Therefore, the re sponsibility for regulating storage onshore and in

coastal waters has been left to the states. To date, Queensland and Victoria have

developed legislation specifically for GS, and South Australia has amended legislation

to cover GS. The other three Austral ian states (Tasmania, New South Wales, and

Western Australia), as well as Australia’s various territories, currently lack a legislative

framework for onshore GS.

**•** Queensland Petroleum and Gas (Production and Safety) Act of 2004

. The Queensland

Petroleum a nd Gas (Production and Safety) Act of 2004 r egulates transport in pipelines

and storage in natural reservoirs of substances including CO 2

. GS operators are

required to apply for a petroleum lease, and to pay the state rent for use of the

reservoir. Financial penalties (e.g., for violating terms of a permit or failure to report

monitoring data) are specified in “penalty units,” which allow for fines throughout the

legal code to be easily adjusted for inflation without requiring an amendment to each

law. This law does not specify construction, monitoring, reporting, closing, or liability

requirements for GS.

**•** Greenhouse Gas Storage Act of 2009 [Queensland]

. The Greenhouse Gas Storage Act

of 2009 includes more comprehensive requirements for GS than the Queensl and

Petroleum and Gas (Production and Safety) Act of 2004. The Act covers both onshore

activities and offshore activities that take place within three miles of the shoreline. All

greenhouse gas reservoirs are established to be property of the state in perp etuity.

Operators are required to submit a work plan, which describes monitoring, operating,

and reporting strategies, as part of a competitive tender permit application process.

Because of this, the work plan will vary by site. Like the Petroleum and Gas (Production

and Safety) Act, this law also uses “penalty units.”

**•** Greenhouse Gas Geological Sequestration Act of 2008 [Victoria]

. Victoria has one law

relevant to GS: the Greenhouse Gas Geological Sequestration Act of 2008 . This Act has41 fairly comprehensive requirements for permitting, construction, monitoring, reporting,

enforcement, and liability transfer. Overall

, its requirements are similar to the 2008

amendment to the Offshore Petroleum and Greenhouse Gas Storage Act of 2006 . The

only notable exceptio n is a lack of specific emergency response requirements. Like

Queensland’s regulations , this regulation uses “penalty units.” Injection licenses are

issued by competitive tender; in addition to describing their expertise, financial

resources, and proposed work program, applicants submit a bid on how much money

they are willing to pay for the license. All greenhouse gas reservoirs are established to

be property of the state in perpetuity. Operators can (with the appropriate licenses)

use the reservoirs; however, the injected greenhouse gases also become property of

the state upon termination of the license.

**•** South Australian Petroleum and Geothermal Energy Act of 2000 South Australia has

one law relevant to GS: the South Australian Petroleum and Geothermal En ergy Act of

2000 (a s amended Oct ober 1, 2009) . CO 2 is included as a “regulated substance” under

the Act. Although this law was not designed specifically for GS, it covers some of the

requirements common in other GS legislation, such as reporting and operat ing

requirements (through a work plan). The law’s flexibility, as well as the power it gives

regulators, suggests that it could be used to regulate GS.

London Protocol/OSPAR

The London Convention of 1972 (in effect since 1975) was one of the first international agreements

protecting the marine environment, with 86 nations as signatories. In 1996, the London Protocol (with

37 signatories) revised and expanded the London Convention to, among other things, prohibit ocean

dumping, with the exception of a spe cified list (Annex 1) of substances and circumstances. Geologic

sequestration of CO 2 under the seabed was prohibited by default under the London Protocol because it

was not on the list of acceptable substances or circumstances. However, a 2006 amendment ch anged

the list of Annex 1 substances to allow for injection of CO 2 into sub

- seabed geological formations.

The amendment also provides generic guidelines for member countries. These are explained in a Risk

Assessment and Management Framework document, intended as guidance for signatory countries and

potential owners or operators of geologic sequestration sites. Some requirements of note are:

**•** CO 2 must be injected at least several hundred meters below unconsolidated seafloor

sediments.

**•** Impurities in the CO 2 stream must originate with the source of the stream (i.e. power

plant exhaust) and must not be added for disposal purposes.

**•** Geologic sequestration is allowed below continental shelves only. The guidelines were

developed with deep saline formations in mi nd and do not cover use of CO 2 for

enhanced oil or gas recovery. According to the Risk Assessment and Management

Framework, “ [u]nminable coal beds, basalts, oil and gas shales, salt caverns and other

geological formations and structures may also be conside red for CO 2 storage.”

However, specific guidelines were not developed for these formation types.42 Compared to other legal frameworks for geologic sequestration, the London Protocol amendment is

vague r and more generic, leaving the particulars of most requirements to signatory countries.

Enforcement is entirely at the discretion of signatory countries and their environmental/maritime

regulatory agencies.

Many of the recommendations in the Risk Assessment and Management Framework are taken from

the Internat ional Panel on Climate Change Special Report on Carbon Capture and Storage.

The London Convention also served as the basis for the OSPAR Convention for the Protection of the

Marine Environment of the No rth

- East Atlantic. OSPAR is a treaty organization com prised of Belgium,

Denmark, Finland, France, Germany, Iceland, Luxembourg, The Netherlands, Norway, Portugal, Spain,

Sweden, Switzerland, the United Kingdom, and the European Union. OSPAR was solely created for the

purposes of protecting the North

- East Atl antic. The OSPAR

- published “Guidelines for Risk Assessment

and Management of Storage of CO 2 Streams in Geologic al Formations” (2007) are essentially a minor

upd ate to the London Convention guidance. The OSPAR document also integrates several other

existing marine protection measures affecting the North

- East Atlantic

.43 

# A PPEN DIX 

# II: M EMBERSHIP AND 

# S UPPORT OF 

# CO 2 

# R ESEARCH 

# O RGANIZATIONS



# M ENTIONED IN THIS 

# R EPORT

Weyburn/Midale Project Consortium

Alberta Energy R esearch Institute

Apache Canada

Aramco Services Company

BP

Cenovus Energy (f or merly EnCana)

Chevron

Dakota Gasification Company

Engineering Advancement Association of Japan

IEA GH G R&D Programme

Natural Resources Canada

Nexen Inc.

OMV Group

PTRC (Petroleum Technology Research Centre)

Research Institute of Innovative Technology for

the Earth (RITE)

Saskatchewan Industry and Resourc es

Saskatchewan Research Council

SaskPower

Schlumberger

Shell Canada Limited

Total

TransAlta Ultilites

United States Department of Energy (USDOE)

University of Regina

CO2SACS

BP

BRGM (Bureau de recherche géologique et

minièr e) France

British Geological Survey

ExxonMobil

GEUS (Geological Survey of Denmark and

Greenland)

IEA GHG R&D Programme

Institut Francais du Petrole

Nansen ERS Centre

Norsk Hydro

NTIG

- TNO ( Dutch Institute for Applied Geosciences - Netherlands Organisation for

Schlumberger Geco

- Prakla

SINTEF Petroleum Research

Statoil

TotalFinaElf

Vattenfall

CO2 STORE

BP Exploration Operating C ompany PLC , United

Kingdom

British Geological Survey , United Kingdom

Bundesanstalt für Geowissenschaften und

Rohstoffe , BGR, Germany

Bureau de Recherches Geologiques et Minieres

, BRGM, France

Energi E2, Denmark

ExxonMobil

Geologi cal Survey of Denmark and Greenland,

GEUS, Denmark

IEA Greenhouse Gas Program , United Kingdom

Industrikraft Midt

- Norge AS , Norway

Institut Français du Petrole , IFP, France

Netherlands Organisation for Applied Scientific

Research , NITG

- TNO, The Netherlands

Norsk Hydro ASA , N orway,

Norwegian Geological Survey

Progressive Energy Limited , United Kingdom

Schlumberg er Stavanger Research, Norway

SINTEF Petroleum Research

Statoil ASA , Norway,

Total, France

Vattenfall , Sweden44APPENDIXIII:QUICKREFERENCEFACTSFORTHREEMAJORGEOLOGICSEQUESTRATIONPROJECTSSLEIPNERWEYBURNINSALAHPURPOSEStripexcessCO2fromnaturalgastofulfillexportagreements(Baklid&Korbøl,1996)andinjecttoavoidacarbontax(Statoil,2007)EOR‐Increasetheproductionofliquidhydrocarbons(Wilson&Monea,2004)CO2separatedfromnaturalgastomeetrequirementsforsale,reinjectedtomeetcorporatesustainabilitygoals(Wright,2007)Verifythat20yearsofmonitoringcanensure1000yearsofsafeCO2storage(BP,2008)LOCATIONNorthSea(Norway),250kmsouthwestfromStavanger,Norway(Artsetal.,2004a;Baklid&Korbøl,1996)Weyburn,SouthernSaskatchewan.CO2fromBeulah,NorthDakota(Wilson&Monea,2004)Krechbafield,Algeria,1,200kmsouthofAlgiersOnecentralizedinjectionsiteamongsevennaturalgasfields(Haddadji,2006)

BackgroundSTARTDATE3quarter1996(Baklid&Korbøl,1996;Artsetal.,2008;IEA,nodate)September15,2000(Wilson&Monea,2004)August2004(Riddifordetal.,2004;Wright,2007;Wrightetal.,2005)LIFESPANrd25years(Baklid&Korbøl,1996;Hollowayetal.,2004)Approx.25years(MIT,2009b;Riding&Rochelle,2005)25‐30years(BP;2008;Riddifordetal.,2004;Haddadji,2006)RUNBYStatoil(Statoil,2009;IEA,nodate)CenovusinchargeofEORandproduction,researchprogramrunbythePTRCwithsupportoftheIEAGHGR&DProgramme(Wilson&Monea,2004)Statoil,Sonatrach,andBP(Haddadji,2006;Riddifordetal.,2004)PROJECTCAPACITYApprox.25MtCO2(Torp&Brown,2006)Predictedtostore>30Mtgross,>26Mtnet(Kristoff,2007)17Mt(BP,2008;Michaeletal.,2009)INJECTIONRATEApprox.1MtCO2peryear(IEA,nd;MIT2009a;Torp&Gale,2004)Approx.1.8MtperyearfromBeulahpipeline,plus0.4Mtperyearrecycledfromproductionwells(IEA,2006)Approx.1.2Mtperyear(Riddifordetal.,2004;MIT,2009c),taperingofftolessthan1Mt/yrby2020(Bishop,2004)SUPPORTERSSACS/CO2STORE(researchconsortium)(Hollowayetal.,2004)US&Canadiangovernmentalagencies,Industryagencies,>70researchersfrom>20organizations(Wilson&Monea,2004;Czernichowski‐Lauriol,2006)JointIndustryProject(JIP):includesSonatrach,BPandStatoilaswellasseveralR&DgroupsinEuropeandtheUSA(Riddifordetal.,2004)COST>$US500million(IEA,nodate),with$1.9million(1996dollars)forsitecharacterization.DedicatedmonitoringwellnotbuiltduetocostofUS$10million(Torp&Gale,2004)$US80millionforresearch(PTRC,nodate;Kristoff,2007)$US1billionforinfrastructure(Prestonetal.,2004)Approx$US100millionforCO2storage(Wright,2006)Approx.$US30millionformonitoring(BP,2008;Wright,2006)$US1.7billionforinfrastructure(Wright,2006)

2

COCO2SOURCEExtractedfromnaturalgasonsite(Statoil,2007)Beulah(NorthDakota)SynfuelsPlant.Transported320kmtoWeyburnbypipeline.SomeCO2alsorecycledfromproductionwells(Wilson&Monea,2004)Extractedfromnaturalgasonsite‐‐reduceCO2from4‐10%to0.3%forsaleinEurope(Riddifordetal.,2004)QuickReferenceFactsforThreeMajorGeologicSequestrationProjectsNote:Blankcellsindicatethatnoinformationwasavailable.45Geology S LEIPNER W EYBURN I N S ALAH

P URITY OF CO 2 Wet and contaminated with CH

4 (Hansen et al.,

2005)

Approx. 1.5 –2% CH 4 and heavier hydrocarbons (Arts

et al., 2008) 96% CO 2 , 0.9%H 2 S, 2.3% C 2 +hydrocarbons, 300 ppm N,

0.7%CH 4 , 0.1% CO, O 2 <50 ppm, H 2 O < 20 ppm (Riding &

Rochelle 2005) 98% (BP, 2008)

P HASE Close to critical point (Sasaki et al., 2008). Most

likely in supercritical state ( Arts et al., 2004b; Bickle

et al., 2007; Torp & Gale, 2004; Arts et al., 2008),

but part may be gaseous (Arts et al., 2008) Supercritical

(Wilson & Monea, 2004) Supercritical (BP, 2008; Raikes et al., 2009)

CO 2 S EPARATION

T ECHNOLOGY Amine (IEA, no date ) Rectisol

- cold methanol wash (Perry & Eliason, 2004) Amine (BP, 2008)

T OTAL # OF WELLS

FOR CO 2 INJECTION One horizon tal well (2.3 km) at a cost of $15 m illion

(1996 d ollars) (Baklid & Korbøl, 1996; Haszeldine,

1996) 29 wells, 16 vertical and 13 horizontal, plus 4 observation

wells (2 horizontal, 2 vertical ) (Brown et al., 2001) Three 1

- 1.5 km long horizontal wells (BP; 2008)

T OTAL # OF OTHER

ACTIVE AND

ABANDONED WELLS IN

AREA 30 wells within 20 km of the injection site, data

available for approx. 300 wells total (Holloway et al,

2004) >1

, 072 in Weyburn field, dating from 1954 onward (Wilson

& Monea, 2004) 18 total wel ls

, including 5 used for production (Iding &

Ringrose, 2008)

S ETTING Sedimentary

- marine f an (Arts et al., 2008) Relatively undisturbed sedimentary basin (Wilson & Monea,

2004) Inverted, uplifted extensional sedimentary basin (Ringrose

et al., 20 09)

F AULTS AND

F RACTURES No significant faulting or fracturing in reservoir or

seals (Holloway et al., 2004) No major, regionally extensive faults. Minor faults with

limited displacement or movement and have not

compromised storage in the last 50 million years

(IEA, 2006; Pierce et al., 2004) No major faults; carboniferous rock sequence displays open

fractures which have been shown to influence gas flow,

may impact long

- term performance (Ringrose et al., 2009;

Iding & Ringrose, 2008)

D EPTH TO

FORMATION TOP Water depth is approx. 80 m (Nooner et al., 2006) ;

the top of the Utsira is 800 m BSF; injection occurs

at the bottom of the Utsira (approx. 1

, 012 m below

sea floor ) (Arts et al., 2008; IEA, nd) 1, 400 -1 ,5 00 m ( EnCana , 2008; White, 2008) Approx. 1,800 m (Ringrose et al., 2009) ; v ariability due to

structural dome

R ESERVOIR

T EMPERATURE 37°C (Baklid & Korbøl, 1996) 63°C (White, 2008) 93°C (Iding & Ringrose, 2008)

R ESERVOIR P RESSURE 8- 11 MPa (Baklid & Korbøl, 1996) 14 MPa (White, 2008) 17 .5 MPa (Iding & Ringrose, 2008)

I NJECTION P RESSURE 8 MPa (Baklid & Korbøl, 1996) 15 MPa (Torp & Brown, 2006)

10

- 11 MPa (Mourits, 2008) 18.5 MPa (BP, 2008)

S EALS Sedimentary Layers

- Pliocene Nordland Group

mudstones and siltstones (Arts et al., 2008) Sedimentary Layer s- Anhydrite and mudstones (Whittaker

2005; Wilson & Monea, 2004) Sedimentary l ayers, mostly mudstones and sandstones up

to interbedded with thin anhydrite, dolomite, and siltstone

layers. (ISG, 2008; Wright, 2006)

R ESERVOIR

L ITHOLOGY Mi ocene Utsira Forma tion (sandstone with

intermittent thin mudstone layers)

– deposited as

part of a marine fan (Arts et al., 2008) Carbonate Midale Beds of Mississippian Age, a lower vuggy

shoal limestone and an overlying tight dolomitic marly zone

(Wilson & Monea, 2004) Car boniferous low permeability sandstone.

Estuarine/Deltaic sequences of channel sands that are

laterally heterogeneous (Bishop 2003; Ringrose et al., 2009)slleW46Monitoring S LEIPNER W EYBURN I N S ALAH

R ESERVOIR P OROSITY 35

- 40% (Arts et al., 2008; Baklid & Korbøl, 1996) Vu ggy = 8

- 20%; Marly = 16

- 38% (White, 2008) Average porosity 13

- 22% (ISG, 2008; Rin g rose et al., 2009)

R ESERVOIR

P ERMEABILITY 1, 000 -3, 000 mD (Arts et a., 2008)

1, 000 -8, 000 mD (Baklid & Korbøl, 1996) Vuggy = 10

- 300 mD ; Marly = 1

- 50 mD (White, 2008) Variabl e : 10

- 20 mD (BP,2008) ; 0.1

- 300 mD (Ringrose et al.,

2009)

R ESERVOIR

T HICKNESS Approx. 250 m total; overlapping 30 m thick

sandstone lobes and 1 m mudstones (Arts et al.,

2008) Vuggy = 17 m; Marly = 6 m (White, 2008) 20

- 22 m (ISG, 2008; Ringrose et al., 2 009)

U NDERLYING Other Miocene sedimentary units (Torp & Gale,

2004) Limestone, dolostone, other clastic & evaporitic basin fill.

(Wilson & Monea, 2004) Devonian sandstone, dolomitic with interbedded siltstones

and mudstones (ISG, 2008)

R ESERVOIR TDS

(mg/L) Saline aquifer at 35,000 ppm (Michael et al., 2009) Not a saline aquifer

- hydrocarbon bearing formation

(Wilson & Monea, 2004) Saline aquifer (Michael et al., 2009)

S EISMIC 4 D 3D , 5 different surveys 1999

- 2006 (plus a

baseline in 1994) wi th 2.3

- 8.4 Mt in reservoir

(Arts et al., 2008) ; s urveys taken by ship Active seismic - 3D & 4 D , 3c & 9c surface and 3 D ,3c VSP

Also, cross

- well (vertical & horizontal wells) seismic,

Borehole microseismic, and passive seismic

(Wilson & Monea, 2004; Majer & Korneev., 2001) 4D 3D seismic surveys (Mathieson et al., 2000),

microseismic, & VSPs ( Ringrose et al., 2009; Wright, 2006)

G RAVITY 4D surveys collected with ROVs on seafloor in 2002

and 2005 with 5.14 Mt & 7.76 Mt CO 2 in reservoir

Uncertainty approx. 3

- 5uGal depending on survey

(Arts et al., 2008; Nooner et al., 2006) 4D gravity at a lower resolution than seismic (Wright, 2006)

M AGNETIC High

- Resolution Aero Magnetic Survey used in conjunction

with undersampled 2 D Seismic lines to characterize faults

(Goussev et al., 2004) Initial modeling suggested no response (Wright, 2006)

M ONITORING L ENGTH Since beginning of injection For the first 4 years, most likely for an additional 4

- 8

(Wilson & Monea, 2004) Since beginning of injection (Wright, 2006)

S AT ELLITE Not applicable offshore Some remote imagery used to locate faults (Wilson &

Monea, 2004) Permanent Scatter Interferometry (PSInSAR), currently

collected at one pass every 26 days at a resolution of 3 m 2

(Mathieson et al., 2000)

G EOCHEMICAL AND

I SO TOPIC S TUDIES Rock mechanical tests (Pillitteri et al., 2003; Zweigel

& Heill, 2003)

Formation water sampling failed because the

formation was to o friable (Torp & Brown, 2006) Fluid monitoring surveys with ion geochemistry from over

40 wells sampled ever y 4 months for 4 year period. He, CH 4 , and Radon also measured (Wilson & Monea, 2004) Formation water c hemistry (Wright, 2006)

T RACER S TUDIES Carbon isotopes used as a tracer for injected CO

2

. Other

tracer studies not very successful due to “technical a nd

operational problems” (Wilson & Monea, 2004) Each well has its own unique perfluorocarbon (Ringrose et

al., 2009; BP, 2008)47StoragePredictions &StudyAquifersCostProblemsArea S LEIPNER W EYBURN I N S ALAH

S OIL G AS Not applicable offshore Measure soil gas concentrations and flux monitoring, 2001

-

2003 ar ound Phase 1 injection area (Riding & Rochelle,

2005; Wilson & Monea, 2004) Originally considered, not included in final monitoring plan

(Mathieson et al., 2000)

S TUDIED A REA /

A REA OF R EVIEW 3 km x 7 km (NETL, 2009) General 200 km x 200 km x 4 km area centered on Weyburn

Field and a more detailed area extending 10km beyond the

limits of the planned CO

2 flood (Wilson & Monea, 2004) 20 km x 5 km (ISG, no date)

N EARBY A QUIFERS Utsira is a saline aquifer, >>10,000 ppm (Arts et al.,

2008) ; no nearby sources of drinking water Low fluid flow in Midale beds (<1 m/yr).

Salinity in deeper basin reached 310g/l, but is approx. 1.4g/l

in shallower aquifers (Wilson & Monea, 2004; Riding &

Rochelle, 2005) Northwest Saharan Aquifer System located above injection

site <<10,000 ppm TDS (OSS, 2008)

M ODELS CO 2 will be at maximum distribution less than 300

years after injection, then dissolution dominates

resulting in a gradual shrinking and sinking of the

injected CO

2 , which is complete around 4000 years

(Torp & Gale, 2004) Models based on site

- specific data suggest that less than

0.001% cumulative leakage along abandoned wells over 5000

years and that there is a 95% probability that 98.7

- 99.5% of

CO 2 will stay in reservoir for 500 0 years

(Wilson & Monea, 2004) CO 2 will be held in aquifer zone near the injector locations

CO 2 will migrate slowly updip and reach the production

zone after 25 years, when production has ceased (Haddadji,

2006 )

P ROBLEMS Leakage of injected fluid into s eawater from other

locations in Utsira (not related to Sleipner or CCS)

(Statoil, 2008 a) No known leaks to date (Wilson & Monea, 2004) June 2007: surface leakage through the annulus of an old

exploration well (Kb

- 5). Well plugged and sealed. Leak

volume a few cubic feet per day, lasted sometime between

August 2006 and June 2007 (Statoil, 2009; Ringrose et al.,

2009 )

C OST PER T ONNE CO 2

S EQUESTERED $11.80

- $17 per tonne (Haszeldine, 2006; MIT, 2009)

The Norwegian tax is approx. $USD50 per tonne

(CO

2 Net, 2004 ) $20 USD per to n ne (Haszeldine, 2006) $6USD per ton ne (Haddadji, 2006 ; MIT, 2009c )