International Geologic 

Sequestration Efforts: 

An Overview of the Sleipner, 

Weyburn, and In Salah Projects 

and Summary of International 

Regulatory Developments 
Office of Water (4606M)

EPA 816‐R‐10‐011  

November 2010

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

TABLE OF CONTENTS

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................................................................................................................................. 28
ii 

In Salah................................................................................................................................... 30

Conclusions ............................................................................................................................ 31

International Regulations (includes sources for the table in Appendix 1-A) ......................... 32

Appendix I: Reviewing International Regulations................................................................... 35

Appendix 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 CO2 Research Organizations Mentioned in this 

Report ................................................................................................................................... 43

Appendix III: Quick Reference Facts for Three Major Geologic Sequestration Projects............ 44

LIST OF FIGURES

Figure 1. Approximate location 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........................................................................................ 20
iii 

GLOSSARY

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 CO3

2- ion. Limestone, marble, and dolostone are 

common carbonate rocks.

Confining zone A geologic formation, 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 feature 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 sediments 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 or 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 CO2

through a well or wells associated with a GS project.

Lithology The 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 occurring, 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 drilling 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 The location where a porous, permeable formation 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.

Pore space Open spaces in rock or soil. These are filled with water, air, or other fluids such 

as brine. CO2 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 

connected or isolated.

Porosity The percent of a material occupied by pore spaces.

Saline formations Deep and geographically extensive sedimentary rock layers saturated with 

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

potential CO2 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 materials. 
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 Environmental Protection Agency (USEPA) defines underground waters 

with less than 10,000 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 that has sufficient permeability and vertical extent to allow 

fluids to move between formations.

Trapping The physical and geochemical processes by which injected CO2 is sequestered in 

the subsurface. Physical trapping occurs when buoyant CO2 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 CO2 and minerals in the formation 

lead to the precipitation 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

ACRONYMS AND ABBREVIATIONS

2D two dimensional

3D three dimensional

4D four dimensional (present through time)

AoR Area of Review 

CCS carbon capture and storage

CH4 methane (natural gas)

CO carbon monoxide

CO2 carbon dioxide

CO2-PENS CO2 Predicting Engineered Natural Systems

CO3

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

H2O water

H2S 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 megatonne or million metric tons (unit of mass)

NPD Norwegian Petroleum Directorate

NWSAS Northwest Sahara Aquifer System

OSPAR Convention for the Protection of the Marine Environment of the North-East 

Atlantic

OSS Sahara and Sahel Observatory

ppm parts per million
vii 

PSInSAR Permanent Scatter Interferometric Synthetic Aperture Radar

PTRC Petroleum Technology Research Centre

RISQUE Risk Identification and Strategy using Quantitative Evaluation

SACS Saline Aquifer CO2 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 profile
1 

INTRODUCTION

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, and Sleipner below the North Sea), all three projects 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 injection zones and confining zones is 

highlighted. 

Next, the conclusions 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 (CO2). 

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 programs. 

• Studied area/Area of Review. 

• Relationship to aquifers. 

• Problems. 

• Storage costs.

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

SLEIPNER

Project Background

The Sleipner CO2 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, CO2 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 CO2 had been injected at Sleipner

(Statoil, 2009). Due to the temperature and pressure of the formation, the injected CO2 is very close to

the critical point of phase change (Sasaki et al., 2008); however, most researchers agree that the CO2

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 CO2 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. The Utsira formation is shaded inyellow.

CO2 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 CO2 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 the 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 annual income (Statoil, 2009). Natural gas produced at Sleipner West has a CO2 content of 

up to 9.5% by volume (Holloway et al., 2004). Under the Troll Gas Sales Agreements, natural gas 

delivered to the export pipeline must have a maximum CO2 content of 2.5% by volume (Baklid and

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

geologically sequester the excess CO2 instead of venting it to the atmosphere during gas processing 

when Sleipner West came online in 1996. The CO2 sequestered at Sleipner represents approximately 3% 

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

Structure 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 km2 (Torp and Gale, 2004). The formation is more than 300 m 

thick near the Sleipner 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 depths 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 near 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 internal structure of the formation is composed of overlapping lobes (approximately 30 m 

thick) interlayered with 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 overlain by the Pliocene (approximately 5.3 to 2.5 Ma) 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 Nordland 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 Formation has been extensively studied in the 

Sleipner area. The formation is water-saturated, with a pressure of 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 to 
4 

18% of injected CO2 would be dissolved in formation water and that a pressure 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 CO2 stored 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 failure; their model predicts that the confining zone could contain a CO2 column an order of 

magnitude higher than the CO2 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 CO2 that is 100 m to 400 m 

high, depending on the density of the CO2. The study notes that, in the Utsira, the CO2 column heights 

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

Commercial Development History 

CO2 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 field. 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 

treatment platform at the Sleipner East field. At Sleipner T, CO2 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 CO2 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 CO2 per year (Statoil, 

2007). The Statoil Web site2 provides animated demonstrations of the CO2 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 approximately 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 dedicated monitoring wells was precluded by high costs; Statoil estimated that a 

permanent monitoring well could cost as much as $10 million3 (Torp and Gale, 2003). 

 

2 Available on the Internet at: 

http://www.statoil.com/STATOILCOM/SVG00990.NSF/web/sleipneren?opendocument. 3 All currency amounts 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 techniques employed at other carbon capture and storage (CCS) sites cannot be used 

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

phase of the injected CO2 complicate the interpretation of monitoring data. The primary forms of 

monitoring at Sleipner have been seismic 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 survey, 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 encountered by the waves, the strength 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 variations between 

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

CO2) 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 more complete 

monitoring profile. For example, seismic surveys would be more likely to detect small, thick CO2

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

may detect accumulations of CO2 that would be undetected by the seismic monitoring (Chadwick et al., 

2006). 

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

of images shows the evolution of the CO2 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). Reprinted 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, and 2002. These results indicate that CO2 injected at Sleipner is approaching a 

steady state, 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 CO2 movement, 

forcing the CO2 to spread laterally instead of rising. Seismic profiles displaying the extent of the CO2
6 

plume show this effect (see Figure 2). Additional seismic surveys, conducted in 2004 and 2006, confirm 

the earlier conclusion that CO2 is not spreading beyond the Utsira formation due to a combination of 

structural, 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 detect changes in the CO2

plume, though the success of such monitoring would be strongly dependent on CO2 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 on a remotely operated vehicle. A second gravity survey in 2005 (Nooner and Zumberge, 2005) 

produced results consistent with the amount of CO2 that had been injected since the previous study, 

suggesting that CO2 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-product 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 (2008a) provided the following account of the incident. On May 14, 2008 workers on a Tordisarea platform noticed oily 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 particular 

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

concluded that the immediate area surrounding the injection site had not been characterized fully 
7 

enough to understand the risks to subsurface injection posed by other industrial processes also taking 

place at the site.

The leak at Tordis does not directly relate to the CO2 injection at Sleipner: the two sites are located 

approximately 300 km apart in unconnected areas of the formation, and no CO2 injection 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 

CO2 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 in tandem with 

hydrocarbon production, CO2 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 activities (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 CO2. Applicants must submit an Environmental 

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 systems, as well as periodic and emergency reporting. Additional 

project-specific requirements can be specified in individual permits. Statoil will have financial liability for 

damage, loss, nuisance, or expenses related to the pollution (i.e., release of CO2) 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 persist 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 directive. 
8 

WEYBURN

Project Background

The Weyburn Project is a combination CO2 sequestration/enhanced oil recovery (EOR) project operated 

under a partnership between Cenovus Energy (formerly Encana) and the Petroleum Technology 

Research Centre (PTRC), a public-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 CO2 in an oil reservoir. The 

project will also result in the creation 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 research 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 

International 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 consulting 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 phase of the project (2005-2011), the area of study was expanded to include the adjacent 

104 km2

 Midale Field (Weyburn Field is 181 km2), 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 CO2 EOR site in Canada following the beginning of CO2 injection in late 2005. 

Structure and Stratigraphy 

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

km2 established oil-producing field in the Williston Basin in Canada (see Figure 4). The Williston Basin is a 

large (approximately 800,000 km2

), relatively undisturbed bowl-shaped structural basin. Sediments are 

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

nearly 5 km thick. The Williston Basin is a good analogue for other potential CO2 sequestration sites 

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

Powder River Basins) 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 CO2 in the basin attest to the suitability of the structures and seals

in the basin to contain CO2 over geologic time: natural gas derived from overlying units above such seals

contains only traces of CO2, demonstrating that the seals effectively block upward migration of CO2.

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

impact the long‐term fate of injected CO2 (Wilson and Monea, 2004) if the CO2 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 CO2 as well as the solubility of CO2: one mol CO2/kg H2O can be

dissolved at low salinities, while only 0.78 mol CO2/kg H2O can be dissolved at high salinities. Mineral

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

that subsurface CO2 migration models may need to be adjusted in order to accurately predict the

potential CO2 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 formations 

(Czernichowski-Lauriol, 2006; Wilson and Monea, 2004). Higher flow rates can enhance an aquifer’s 

ability to adsorb CO2, but can also increase the distance over which sequestered CO2 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 adjacent carbonate layers approximately 1.4

km 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 chalky 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 of 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 early 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 sedimentary rocks is an unconformity, representing a gap in the rock record.

Several competent confining layers overlie the porous layers. Below the unconformity, the Midale 

Evaporite—a one to ten meter thick evaporite acts as a highly competent seal above 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 

Weyburn 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 requires 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 

data, 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 cut-away block diagram developed for the Weyburn project, showing the subsurface layers in the area. 

Barriers to upward migration are arranged 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 from Wilson and Monea (2004).

Reprinted with permission of PTRC. 

EOR efforts at Weyburn 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 in the Vuggy layer, hydrocarbons remain in the Marly layer (Riding and Rochelle, 

2005; Wilson and Monea, 2004). The injection of CO2 is aimed at reversing the decline in production, 

and, as of 2009, it has been highly successful. It is assumed that CO2 will circulate more readily than 

water in the less-permeable Marly layer, facilitating improved hydrocarbon recovery (EnCana, 2008). 

CO2 reduces the viscosity of oil and causes its volume to increase, helping to extract more oil from the 

reservoir. 

CO2 injection began on September 20, 2000. Water is injected alternately with the CO2 (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. CO2 injection has also lengthened the life of the field by 25 years 

and CO2 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 CO2 EOR.

Image courtesy of Cenovus Energy. Reprinted with permission.  

CO2 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 CO2 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 CO2 is 96% pure, with 0.9% H2S, 2.3% C2 + hydrocarbons, 0.7% CH4, 0.1% CO, 300 ppm N,

<50 ppm O2, and <20 ppm H2O. The composition is ideal because a small amount of H2S gas increases

the miscibility of CO2 in oil (SEED, 2008). Nearly five thousand tons/day of CO2 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 CO2 (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 vertical
13

offset wells—improvements in drilling technique limited damage to near‐wellbore rocks and resulted in

better production rates for 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) and 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 CO2. 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 CO2 injector scheme at Weyburn. Injection wells are in blue,

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

CO2 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 km2

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

Monea, 2004). Weyburn Field is predicted to store 26 Mt of CO2 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 CO2 flood. A full suite of monitoring studies,

including seismic, wireline logging, core analysis, electrical resistance tomography, geochemical, and
14

laboratory studies was planned, and some studies associated with Phase II are still in progress. Baseline 

measurements were 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 monitoring 

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 attributed 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 

CO2 flood is technically feasible. However, while active seismic monitoring is sensitive to low levels of 

CO2 (5-10 molar percent), sensitivity does not increase linearly with concentration. Therefore, while it 

may be easy to image the CO2 plume front, estimating the volume of CO2 could be much more difficult 

(IEA, 2006). The microseismic monitoring also confirms that microseismicity associated with CO2 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 collected from 40 wells every four months during 2001-2005. Changes in alkalinity, calcium 

concentration, and carbon isotopic signature as a result of subsurface CO2 migration are visible on data 

maps. Additionally, isotopic analysis of the carbon in the CO2 stream at production wells was used to 

track subsurface migration. Likewise, the isotopic composition of CO2 collected from soil gas surveys was 

compared to the isotopic composition of injected CO2 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. Conventional production data analysis was also used to help 

determine the migration of the CO2 (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 future 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 management, 

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 4D; 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

database 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 Rochelle, 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 CO2 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 CO2 (Wilson and Monea, 2004). The 

model suggested that the most likely scenario for CO2 migration will result in no significant migration 

beyond the Watrous Formation. The long-term fate of the injected CO2 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 CO2 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 abandoned wells over 5,000 years. In total, the model found a 95% 

probability that 98.7-99.5% of injected CO2 at Weyburn would remain sequestered for at least 5,000 

years. This result is consistent with current field monitoring, which has not detected any CO2 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 regulated 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 CO2 and 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 postabandonment 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 liability insurance, although it is unclear if that insurance 

includes risks associated with the CO2 itself (Sengupta, 2006). 
16

IN SALAH

Project Background

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

an Algerian state-owned company. Research at the site is run by a Joint 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 the project is estimated at $1.7 billion for production infrastructure, $100 

million for CO2 capture and storage infrastructure, and $30 million for CO2 monitoring, verification, and

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

improve tools for the prediction and performance of geological CO2 sequestration through extensive 

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

increase global visibility of GS and establish it as technology eligible for greenhouse gas mitigation 

credits. 

The site sequesters CO2 separated from produced natural gas to avoid venting it into the atmosphere, in 

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

because the CO2 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 

CO2 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, Injection, 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 supplement production at the 

upper three fields to help maintain a production rate of 9 billion cubic meters per year (Wright, 2007). 

Although production occurs or will occur at all fields, CO2 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 CO2. 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 a
18

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 CO2 injection wells, respectively. CO2 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 CO2 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 km2 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 CO2 stripping unit

located near Krechba Field. This design minimizes the cost, since CO2 stripping units are expensive
19

(Wright, 2007). At the stripping unit, CO2 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 CO2 could not be injected at the anticipated volume. 

To date, these problems have resulted in the atmospheric venting of 1 Mt of CO2 to the atmosphere—

approximately 25% of the total CO2 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 vertical 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) program 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 

feedback 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 portions 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 

perpendicular 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 three horizontal 

CO2 injection wells are located around the perimeter of the field. The logic behind this arrangement is 

that injected CO2 will migrate updip (towards the top of the dome) over time as natural gas is produced 

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

after injection, CO2 will be held in the saline formation near the injection sites and reach the production 

zone only after 25 years, by which time production will have ceased (Haddadji, 2006). 

The injected CO2 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 lowpermeability sandstone, but is kept below 41.4 MPa to avoid needing specialized high-pressure

compression equipment (Riddiford 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 CO2 (BP, 2008; Michael et al., 

2009). 
20

Monitoring

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

Monitoring commenced prior to injection, with baseline data acquired in early 2004 (Riddiford et al., 

2004). Monitoring is expected 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 measurements (both head gas 

and isotubes) and pressure analyses are part of the monitoring program at each wellhead. Production 

wells and injection wells are continuously monitored, while Krechba’s seven inactive 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 infer subsurface pressure changes. Images have been collected from 2004-2007, with data collection 

currently occurring at a rate of one image with a resolution of 3 m2 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 of 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 Ringrose 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 CO2 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 CO2 has not 

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

to explore possible future scenarios. Modelers have created a shared-earth model of the underlying 

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

sources (Ringrose et al., 2009).

One leak has occurred at Krechba. In June 2007, surface leakage of CO2 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 August 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 CO2 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 CO2-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 require 

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 CO2 sequestration risk model CO2

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 from the CO2 were not included in the insurance (Sengupta, 2006). 
22

CONCLUSIONS

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 CO2. They include Otway 

(Australia), Zama (Canada), Gorgon (Australia), 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 guide 

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 here are located in very different environments, CO2 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 brine 

formation (Sleipner), a heterogeneous, fractured carbonate hydrocarbon reservoir within an intracontinental 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 CO2 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 horizontal 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 those 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 CO2 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 underlying 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 to 

judge how important these additional layers may be when ensuring storage safety or security. While the 
23

lack of major failures is certainly positive, it has resulted in a lack of direct experience with the 

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

especially if CO2 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 largescale containment breaches, these projects suggest that single, thick confining zones may be sufficient 

to protect aquifers (including sources of drinking water) and successfully sequester CO2. The safe 

injection of CO2 between aquifers at Weyburn illustrates the ability 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 CO2 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 CO2. Although the techniques that have proved most 

useful were not always the ones initially flagged 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-expensive 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 limitations 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 cutting-edge seismic methods. Although seismic 

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

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

very high cost. The 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, multifaceted testing and monitoring regime.

Leaks

There have been no major containment breaches or large-scale leaks of injected or stored CO2 at any of 

these three projects. (This does not include the unplanned venting of CO2 at In Salah, where CO2 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 not 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 CO2. The actual CO2 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 CO2 reached the surface through 

the casing of an abandoned exploration well. This incident confirms that 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 potential 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 underscores 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 secure 

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 the 

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 CO2 into 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 CO2 into 

saline formations in dry or high 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 CO2 are usually well defined in legal terms, the legal 

landscape associated with long-term liability of geologically sequestered CO2 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 potentially host multiple sequestration projects, especially in areas that are 

more heavily developed and/or contain multiple point sources of CO2. The pressure fronts from these 

operations (the area where subsurface pressure remains elevated due to the displacement 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 interactions, 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 CO2

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 regions 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, CO2 emissions for the United States alone in 2007 were 6,021 Mt CO2 (EIA, 

2008), while the total CO2 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. CO2 emissions. 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 governmental 

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 areas for future research 

and development.
26

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Krechba, Algeria. 9th International Conference on Greenhouse Gas Control Technologies (GHGT-9), 

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Ringrose, P., M. Atbi, D. Mason, M. Espinassous, Ø. Myhrer, M. Iding, A. Mathieson, and I. Wright. 2009. Plume 

development around well KB-502 at the In Salah CO2 storage site. First break volume 27. 

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a transboundary water basin. Tunis: 2008. ISBN 978-9973-856-30-2. Available on the Internet at: 

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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 CO2 Storage Project. International Petroleum Technology Conference, Dubai. IPTC 

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Conclusions 

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32

Gouveia, F.J., and S.J. Friedmann. 2006. Timing and prediction of CO2, eruptions from Crystal Geyser, UT. Lawrence 

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DOE/EIA-0573(2007). Available on the Internet 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. Available 

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 June 1985 on the assessment of the effects of certain public and private 

projects on the environment. 1985. Available on the Internet at: http://eurlex.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 

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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. 

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carbon dioxide and amending Council Directive 85/337/EEC, European Parliament and Council Directives 

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Speicherung von Kohlendioxid" [In German]. 2009. 

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33

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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. 

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Storage: Australian Regulatory Guiding Principles. Available on the Internet at: 

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concerning waste.

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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 CO2 Streams in Geological Formations. Reference number 

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Petroleum Act 2006, and for other purposes. 2008. Draft, as read a third time.

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34

Queensland Parliamentary Counsel. 2004. Petroleum and Gas (Production and Safety) Act 2004. Act No. 25 of 

2004. 

Risk Assessment and Management Framework for CO2 Sequestration in Sub-Seabed Geological Structures (CSSSGS) (Source LC/SG-CO2 1/7, annex 3). 2006. Adopted at the joint session of the 28th Consultative 

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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.

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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: Discussion paper- Choices for regulating CO2 capture and storage in the EU. 

Zakkour, P., M. Haines. 2007. Permitting issues for CO2 capture, transport and geological storage: A review of 

Europe, USA, Canada and Australia. International Journal of Greenhouse Gas Control 1: 94–100.
35

APPENDIX I: REVIEWING INTERNATIONAL REGULATIONS

To provide context on the international regulatory environment, the following section presents GS 

regulations, both current and in development, from jurisdictions around the world. 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 

subtle differences in regulatory strategies and underscore the diverse array of approaches to 

regulating GS.
36

APPENDIX I-A: INTERNATIONAL REGULATIONS COMPARISON CHART
 37

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 CO2 stream monitoring (injection rate and pressure)

Requires CO2 stream purity/composition monitoring

Operator must specify/report total volume of CO2 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 X noniean 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 X Germany

X X X X X V X X X Norway

X V X

 Poland

X X X X X X X X United Kingdom

X X X X X X X Canada

X X X X X X X Australia

X X X X

X X X Japan

X X X X X X X IPCC Guidelines

X X X X X X X X

X X X X X X X X X London 

X X X X X X X X X

Protocol/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 jurisdictions; Numbers where appropriate
38

APPENDIX I-B: LEGISLATIVE CASE STUDIES

European Union

The European Union (EU) currently has seven directives that are at least partially relevant to geologic 

sequestration of CO2. EU directives are issued by the 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 since CO2 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, Directive 2003/87/EC would require operators of GS 

sites to return emissions trading credits for any leaked CO2. 

• Directive 2004/35/EC. If a GS project resulted in pollution that damaged habitat, 

harmed protected 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 extra 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 CO2). Directive 2009/31/EC also 

mandates fair access to CO2 transport networks (pipelines) and storage sites to allow 

potential operators such as electrical utilities the opportunity to transport and 

geologically sequester their CO2 streams. Additionally, Directive 2009/31/EC lists 
39

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 

applicable 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. Greater legal specificity from the outset may 

encourage development 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 CO2 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 H2S (derived from the 

production of sour oil and natural gas), they also cover CO2. For example, CO2 is often co-injected with 

H2S 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 Testing 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 oldest 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 Reservoirs (revised 2009), added a few more requirements 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). CO2 is regulated under the category of “natural gas,” which includes all nonpetroleum fluid hydrocarbons, hydrogen sulfide, CO2, and helium. CO2 injection is 

subject to restrictions similar to those under Directive 051 in Alberta.

Australia 

Australia possesses about 9% of 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 state 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 the 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 Review, 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 responsibility 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 Australian 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 and Gas (Production and Safety) Act of 2004 regulates transport in pipelines 

and storage in natural reservoirs of substances including CO2. 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 Queensland 

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 perpetuity. 

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 has 
41

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 exception 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 Energy Act of 

2000 (as amended October 1, 2009). CO2 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 operating 

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 specified list (Annex 1) of substances and circumstances. Geologic 

sequestration of CO2 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 changed 

the list of Annex 1 substances to allow for injection of CO2 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:

• CO2 must be injected at least several hundred meters below unconsolidated seafloor 

sediments. 

• Impurities in the CO2 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 mind and do not cover use of CO2 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 considered for CO2 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 

vaguer 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 International 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 North-East Atlantic. OSPAR is a treaty organization comprised 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 Atlantic. The OSPAR-published “Guidelines for Risk Assessment 

and Management of Storage of CO2 Streams in Geological Formations” (2007) are essentially a minor 

update to the London Convention guidance. The OSPAR document also integrates several other 

existing marine protection measures affecting the North-East Atlantic. 
43

APPENDIX II: MEMBERSHIP AND SUPPORT OF CO2 RESEARCH ORGANIZATIONS 

MENTIONED IN THIS REPORT

Weyburn/Midale Project Consortium

Alberta Energy Research Institute

Apache Canada

Aramco Services Company

BP 

Cenovus Energy (formerly EnCana)

Chevron

Dakota Gasification Company

Engineering Advancement Association of Japan

IEA GHG 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 Resources

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 

minière) 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

CO2STORE

BP Exploration Operating Company 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

Geological 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, Norway,

Norwegian Geological Survey

Progressive Energy Limited, United Kingdom

Schlumberger Stavanger Research, Norway

SINTEF Petroleum Research

Statoil ASA, Norway,

Total, France

Vattenfall, Sweden
44

APPENDIX III: QUICK REFERENCE FACTS FOR THREE MAJOR GEOLOGIC SEQUESTRATION 

SLEIPNER WEYBURN 

PURPOSE

Strip excess CO2 from natural gas to fulfill export

agreements (Baklid & Korbøl, 1996) and inject to

avoid a carbon tax (Statoil, 2007)

EOR ‐ Increase the production of liquid hydrocarbons

(Wilson & Monea, 2004)

CO2 separated fr

sale, reinjected 

Verify that 20 yea

s

LOCATION

North Sea (Norway), 250 km southwest from

Stavanger, Norway (Arts et al., 2004a; Baklid &

Korbøl, 1996)

Weyburn, Southern Saskatchewan. CO2 from Beulah, North

Dakota (Wilson & Monea, 2004)

Krechba fie

One centralize

Background

START DATE 3 quarter 1996 (Baklid & Korbøl, 1996; Arts et al., 2008; IEA, no date) September 15, 2000 (Wilson & Monea, 2004) August 2004 (Ridd

LIFESPAN

rd

25 years (Baklid & Korbøl, 1996; Holloway et al.,

2004) Approx. 25 years (MIT, 2009b; Riding & Rochelle, 2005) 25‐30 years (BP

RUN BY Statoil (Statoil, 2009; IEA, no date)

Cenovus in charge of EOR and production, research program

run by the PTRC with support of the IEA GHG R&D

Programme (Wilson & Monea, 2004)

Statoil, Sonatrach

PROJECT CAPACITY Approx. 25 Mt CO2 (Torp & Brown, 2006) Predicted to store >30 Mt gross, >26 Mt net (Kristoff, 2007) 17 Mt 

INJECTION RATE Approx. 1 Mt CO2 per year (IEA, nd; MIT 2009a; Torp & Gale, 2004) Approx. 1.8 Mt per year from Beulah pipeline, plus 0.4 Mt per year recycled from production wells (IEA, 2006) Approx. 1.2 Mt pe

tapering off to l

SUPPORTERS SACS/CO2STORE (research consortium) (Holloway

et al., 2004)

US & Canadian governmental agencies, Industry agencies,

>70 researchers from >20 organizations (Wilson & Monea,

2004; Czernichowski‐Lauriol, 2006)

Joint Industry P

Statoil as well as s

COST

>$US500 million (IEA, no date), with $1.9 million

(1996 dollars) for site characterization.

Dedicated monitoring well not built due to cost of

US$10 million (Torp & Gale, 2004)

$US80 million for research (PTRC, no date; Kristoff, 2007)

$US 1 billion for infrastructure (Preston et al., 2004)

Approx $US10

Approx. $US30 

$US1.7 bill

2 COCO2 SOURCE Extracted from natural gas on site (Statoil, 2007) Beulah (North Dakota) Synfuels Plant. Transported 320 km to Weyburn by pipeline. Some CO2 also recycled from production wells (Wilson & Monea, 2004) Extracted from n

to 0.3% for s

Note: Blank cells indicate that Quick Reference Facts for Three Major Geologic Seques

no information was available.
45

Geology 

SLEIPNER WEYBURN IN SALAH

PURITY OF CO2

Wet and contaminated with CH4 (Hansen et al., 

2005)

Approx. 1.5–2% CH4 and heavier hydrocarbons (Arts 

et al., 2008)

96% CO2, 0.9%H2S, 2.3% C2+hydrocarbons, 300 ppm N, 

0.7%CH4, 0.1% CO, O2 <50 ppm, H2O <20 ppm (Riding & 

Rochelle 2005)

98% (BP, 2008)

PHASE

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)

CO2 SEPARATION 

TECHNOLOGY Amine (IEA, no date) Rectisol-cold methanol wash (Perry & Eliason, 2004) Amine (BP, 2008)

TOTAL # OF WELLS 

FOR CO2 INJECTION

One horizontal well (2.3 km) at a cost of $15 million 

(1996 dollars) (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)

TOTAL # 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 wells, including 5 used for production (Iding & 

Ringrose, 2008)

SETTING Sedimentary - marine fan (Arts et al., 2008) Relatively undisturbed sedimentary basin (Wilson & Monea, 

2004)

Inverted, uplifted extensional sedimentary basin (Ringrose 

et al., 2009)

FAULTS AND 

FRACTURES

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)

DEPTH 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)

1,400-1,500 m (EnCana, 2008; White, 2008) Approx. 1,800 m (Ringrose et al., 2009); variability due to 

structural dome

RESERVOIR 

TEMPERATURE 37°C (Baklid & Korbøl, 1996) 63°C (White, 2008) 93°C (Iding & Ringrose, 2008)

RESERVOIR PRESSURE 8-11 MPa (Baklid & Korbøl, 1996) 14 MPa (White, 2008) 17.5 MPa (Iding & Ringrose, 2008)

INJECTION PRESSURE 8 MPa (Baklid & Korbøl, 1996) 15 MPa (Torp & Brown, 2006)

10-11 MPa (Mourits, 2008) 18.5 MPa (BP, 2008)

SEALS Sedimentary Layers - Pliocene Nordland Group 

mudstones and siltstones (Arts et al., 2008)

Sedimentary Layers-Anhydrite and mudstones (Whittaker 

2005; Wilson & Monea, 2004)

Sedimentary layers, mostly mudstones and sandstones up 

to interbedded with thin anhydrite, dolomite, and siltstone 

layers. (ISG, 2008; Wright, 2006)

RESERVOIR 

LITHOLOGY

Miocene Utsira Formation (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)

Carboniferous low permeability sandstone. 

Estuarine/Deltaic sequences of channel sands that are 

laterally heterogeneous (Bishop 2003; Ringrose et al., 2009)

slleW
46

Monitoring

SLEIPNER WEYBURN IN SALAH

RESERVOIR POROSITY 35-40% (Arts et al., 2008; Baklid & Korbøl, 1996) Vuggy = 8-20%; Marly = 16-38% (White, 2008) Average porosity 13-22% (ISG, 2008; Ringrose et al., 2009)

RESERVOIR 

PERMEABILITY

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) Variable: 10-20 mD (BP,2008); 0.1-300 mD (Ringrose et al., 2009)

RESERVOIR 

THICKNESS

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., 2009)

UNDERLYING 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)

RESERVOIR 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)

SEISMIC

4D 3D, 5 different surveys 1999-2006 (plus a 

baseline in 1994) with 2.3-8.4 Mt in reservoir

(Arts et al., 2008); surveys taken by ship

Active seismic - 3D & 4D, 3c & 9c surface and 3D,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) 

GRAVITY

4D surveys collected with ROVs on seafloor in 2002 

and 2005 with 5.14 Mt & 7.76 Mt CO2 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)

MAGNETIC

High-Resolution Aero Magnetic Survey used in conjunction 

with undersampled 2D Seismic lines to characterize faults

(Goussev et al., 2004)

Initial modeling suggested no response (Wright, 2006)

MONITORING LENGTH 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)

SATELLITE 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 m2

(Mathieson et al., 2000)

GEOCHEMICAL AND 

ISOTOPIC STUDIES

Rock mechanical tests (Pillitteri et al., 2003; Zweigel 

& Heill, 2003)

Formation water sampling failed because the 

formation was too friable (Torp & Brown, 2006)

Fluid monitoring surveys with ion geochemistry from over 

40 wells sampled every 4 months for 4 year period. He, CH4, 

and Radon also measured (Wilson & Monea, 2004)

Formation water chemistry (Wright, 2006)

TRACER STUDIES

Carbon isotopes used as a tracer for injected CO2. Other 

tracer studies not very successful due to “technical and 

operational problems” (Wilson & Monea, 2004)

Each well has its own unique perfluorocarbon (Ringrose et 

al., 2009; BP, 2008)
47

Storage Predictions & Study Aquifers Cost Problems Area

SLEIPNER WEYBURN IN SALAH

SOIL GAS Not applicable offshore

Measure soil gas concentrations and flux monitoring, 2001-

2003 around Phase 1 injection area (Riding & Rochelle, 

2005; Wilson & Monea, 2004)

Originally considered, not included in final monitoring plan

(Mathieson et al., 2000)

STUDIED AREA/ 

AREA OF REVIEW 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 CO2 flood (Wilson & Monea, 2004)

20 km x 5 km (ISG, no date)

NEARBY AQUIFERS 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)

MODELS

CO2 will be at maximum distribution less than 300 

years after injection, then dissolution dominates 

resulting in a gradual shrinking and sinking of the 

injected CO2, 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 

CO2 will stay in reservoir for 5000 years

(Wilson & Monea, 2004)

CO2 will be held in aquifer zone near the injector locations

CO2 will migrate slowly updip and reach the production 

zone after 25 years, when production has ceased (Haddadji, 

2006) 

PROBLEMS

Leakage of injected fluid into seawater from other 

locations in Utsira (not related to Sleipner or CCS)

(Statoil, 2008a) 

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) 

COST PER TONNE CO2

SEQUESTERED

$11.80-$17 per tonne (Haszeldine, 2006; MIT, 2009)

The Norwegian tax is approx. $USD50 per tonne

(CO2Net, 2004) 

$20USD per tonne (Haszeldine, 2006) $6USD per tonne (Haddadji, 2006; MIT, 2009c)