Monitoring, Verification, 

and Accounting 

of CO2

 Stored in Deep 

Geologic Formations 

BEST PRACTICES for: 

First Edition 
Disclaimer 

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of 

their employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

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recommendation, or favoring by the United States Government or any agency thereof. The views 

and opinions of authors expressed therein do not necessarily state or reflect those of the United 

States Government or any agency thereof. 
i 

Monitoring, Verification, and Accounting 

of CO2

 Stored in Deep Geologic Formations 

DOE/NETL-311/081508 

January 2009 

National Energy Technology Laboratory 

www.netl.doe.gov 
ii Table of Contents 

Table of Contents
 

List of Acronyms and Abbreviations _________________________________________________________________ iv
 

List of Tables ________________________________________________________________________________________ vii
 

List of Figures ______________________________________________________________________________________ viii
 

Executive Summary _______________________________________________________________________________ ES-1
 

1.0 Introduction ______________________________________________________________________________________ 1-1
 

1.1 Importance of CO2 Monitoring and Accounting Protocols _____________________________________________ 1-1
 

1.2 Regulatory Compliance _________________________________________________________________________ 1-2
 

1.3 Objective and Goals of Monitoring ________________________________________________________________ 1-2
 

1.4 Monitoring Activities ___________________________________________________________________________ 1-3
 

1.5 Need for Multiple Projects with Varying Geologic Characteristics ______________________________________ 1-3
 

2.0 Monitoring Techniques _____________________________________________________________________________ 2-1
 

3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities ___________ 3-1
 

3.1 Core R&D _____________________________________________________________________________________ 3-1
 

3.1.1 Atmospheric Monitoring Methods Developments ________________________________________________ 3-1
 

3.1.2 Near-Surface Monitoring Methods Developments ________________________________________________ 3-2
 

3.1.3 Subsurface Monitoring Methods Developments _________________________________________________ 3-4
 

3.1.4 Enhanced Coalbed Methane Methods _________________________________________________________ 3-6
 

3.1.4.1 Near-Surface Monitoring Methods ______________________________________________________ 3-6
 

3.1.4.2 Subsurface Monitoring Methods ________________________________________________________ 3-6
 

3.2 Core R&D Test Locations ________________________________________________________________________ 3-7
 

3.3 International Projects___________________________________________________________________________ 3-9
 

3.4 Regional Carbon Sequestration Partnerships ______________________________________________________ 3-10
 

3.5 	Applicable Core R&D, International, and Regional Carbon Sequestration 


Partnership Program Monitoring Efforts __________________________________________________________ 3-11
 

3.5.1 Simulation ______________________________________________________________________________ 3-11
 

3.5.2 Geophysical Approaches ___________________________________________________________________ 3-12
 

3.5.3 Crustal Deformation ______________________________________________________________________ 3-14
 

3.5.4 Geochemical Methods _____________________________________________________________________ 3-15
 

3.5.5 Surface Monitoring _______________________________________________________________________ 3-15
 

4.0 Review of EPA Permitting Requirements_______________________________________________________________ 4-1
 

4.1 RCSP Project UIC Classification Summary __________________________________________________________ 4-2
 

4.2 UIC Mandatory Requirements ____________________________________________________________________ 4-3
 

4.3 EPA’s 2008 Proposal for Developing New Requirements for CO2 Injection for GS __________________________ 4-3
 

5.0 Addressing the Objectives and Goals of Monitoring _____________________________________________________ 5-1
 

5.1 Role of Primary Technologies ____________________________________________________________________ 5-1
 

5.2 Role of Secondary MVA Technologies _____________________________________________________________ 5-1
 

5.3 Role of Potential Additional MVA Technologies _____________________________________________________ 5-1
 

5.4 Application of Monitoring Techniques and Regulatory Compliance ____________________________________ 5-2
 

5.5 Pre-Operation Phase ___________________________________________________________________________ 5-6
 

5.5.1 Pre-operation Monitoring ___________________________________________________________________ 5-7
 

5.6 Operation Phase ______________________________________________________________________________ 5-10
 

5.6.1 Operation Monitoring _____________________________________________________________________ 5-10
 
Table of Contents iii 

5.7 Closure Phase ________________________________________________________________________________ 5-13
 

5.8 Post-Closure Phase ____________________________________________________________________________ 5-14
 

5.9 Application of MVA Technologies at GS Field Projects _______________________________________________ 5-14
 

6.0 MVA Developments for Large-Scale Tests in Various Settings _____________________________________________ 6-1
 

6.1 Gulf Coast Mississippi Strandplain Deep Sandstone Test (Moderate Porosity and Permeability) _____________ 6-5
 

6.1.1 Target Formation __________________________________________________________________________ 6-5
 

6.1.2 Site Characterization _______________________________________________________________________ 6-6
 

6.1.3 Risk Assessment and Mitigation Strategy _______________________________________________________ 6-6
 

6.1.4 MVA Activities _____________________________________________________________________________ 6-6
 

6.2 Nugget Sandstone Test (Significant Depth, Low Porosity and Permeability) ____________________________ 6-10
 

6.2.1 Description of Target Formation _____________________________________________________________ 6-10
 

6.2.2 Risk Assessment and Mitigation Strategy______________________________________________________ 6-11
 

6.2.3 MVA Activities____________________________________________________________________________ 6-11
 

6.3 Cambrian Mt. Simon Sandstone Test (Moderate Depth, Low Porosity and Permeability) _________________ 6-11
 

6.3.1 Target Formation _________________________________________________________________________ 6-11
 

6.3.2 Site Characterization ______________________________________________________________________ 6-12
 

6.3.3 Risk Assessment Strategy __________________________________________________________________ 6-13
 

6.3.4 MVA Activities____________________________________________________________________________ 6-14
 

6.4 San Joaquin Valley Fluvial-Braided Deep Sandstone Test (High Porosity and Permeability) _______________ 6-16
 

6.4.1 Target Formation _________________________________________________________________________ 6-16
 

6.4.2 Site Characterization ______________________________________________________________________ 6-17
 

6.4.3 Risk Assessment and Mitigation Strategy______________________________________________________ 6-17
 

6.4.4 MVA Activities____________________________________________________________________________ 6-18
 

6.5 Williston Basin Deep Carbonate EOR Test _________________________________________________________ 6-23
 

6.5.1 Description of Target Formations ____________________________________________________________ 6-23
 

6.5.2 Regional Characterization _________________________________________________________________ 6-24
 

6.5.3 Site Development_________________________________________________________________________ 6-24
 

6.5.4 Risk Assessment and Mitigation Strategy ______________________________________________________ 6-25
 

6.5.5 MVA Activities____________________________________________________________________________ 6-26
 

6.6 Impact of Secondary and Potential Additional MVA Technologies on Large-Scale Storage ________________ 6-27
 

6.7 Future Implications from Case Study MVA Packages ________________________________________________ 6-28
 

Appendix I _________________________________________________________________________________________AI-1
 

Appendix II________________________________________________________________________________________ AII-1
 

Appendix III ______________________________________________________________________________________ AIII-1
 

Appendix IV ______________________________________________________________________________________ AIV-1
 

List of Reviewers _________________________________________________________________________________ LoR-1
 

References _________________________________________________________________________________________ R-1
 

Appendix V________________________________________________________________________________________ AV-1
 

Appendix VI ______________________________________________________________________________________ AVI-1
 
iv List of Acronyms and Abbreviations 

List of Acronyms and Abbreviations 

Acronym/Abbreviation Definition 

2-D________________________________________Two-Dimensional 

3-D _______________________________________Three-Dimensional 

4-D _______________________________________Four-Dimensional 

AC ________________________________________Accumulation Chamber 

ADRS ______________________________________Amargosa Desert Research Site 

ANSI_______________________________________American National Standards Institute 

AoR _______________________________________

API ________________________________________

Ar_________________________________________

ARI ________________________________________

ASTM______________________________________

BEG _______________________________________

BGS _______________________________________

Area of Review 

American Petroleum Institute 

Argon 

Advanced Resources International 

American Standard Test Method 

Bureau of Economic Geology 

British Geological Survey 

Big Sky_____________________________________Big Sky Carbon Sequestration Partnership 

BLM _______________________________________Bureau of Land Management 

BNL _______________________________________Brookhaven National Laboratory 

C _________________________________________Carbon 

Ca ________________________________________Calcium 

CASSM_____________________________________Continuous Active Seismic Source Monitoring 

CBL _______________________________________Cement Bond Log 

CBM_______________________________________Coalbed Methane 

CCS _______________________________________Carbon Capture and Storage 

CCX _______________________________________Chicago Climate Exchange 

CES _______________________________________Clean Energy Systems 

CGM_______________________________________Craig-Geffen-Morse Water Flooding Model 

CH4 _______________________________________Methane 

CIR ________________________________________Color Infrared 

Cl _________________________________________Chlorine 

CL ________________________________________Cathodoluminescense 

cm ________________________________________centimeter(s) 

CMG ______________________________________Computer Modeling Group 

CO2

________________________________________Carbon Dioxide 

CO2CRC ____________________________________Cooperative Research Centre for Greenhouse Gas Technologies 

CRT _______________________________________Cathode Ray Tube 

CSLF ______________________________________Carbon Sequestration Leadership Forum 

DIAL_______________________________________Differential Absorption LIDAR 

DOE _______________________________________

DTPS ______________________________________

EC ________________________________________

EDS _______________________________________

ECBM ______________________________________

EELS_______________________________________

EMIT ______________________________________

EOR _______________________________________

EPMA______________________________________

U.S. Department of Energy 

Distributed Thermal Perturbation Sensor 

Eddy Covariance 

Energy Dispersive X-Ray Spectroscopy 

Enhanced Coalbed Methane 

Electron Energy Loss Spectroscopy 

Electromagnetic Induction Tomography 

Enhanced Oil Recovery 

Electron Probe Microanalyzer 

EM ________________________________________Electromagnetic 

EPA _______________________________________U.S. Environmental Protection Agency 

ERT _______________________________________Electrical Resistivity Tomography 
List of Acronyms and Abbreviations v 

Acronym/Abbreviation Definition 

ES&H ______________________________________Environmental, Safety, and Health 

ft _________________________________________Feet 

FE_________________________________________DOE’s Office of Fossil Energy 

FLOTRAN___________________________________Flow and Transport Simulator 

g _________________________________________Gram(s) 

GFZ _______________________________________GeoForschungsZentrum 

GHG_______________________________________Greenhouse Gas(es) 

GIS ________________________________________Geographic Information System 

GPR _______________________________________Ground Penetrating Radar 

GPS _______________________________________Global Positioning System 

GS ________________________________________Geological Storage/Sequestration 

H/H2_______________________________________Hydrogen 

H2

O _______________________________________Water 

H2

S________________________________________Hydrogen Sulfide 

H2

SO4______________________________________Sulfuric Acid 

He ________________________________________Helium 

HC ________________________________________Hydrocarbon 

HCl________________________________________Hydrogen Chloride 

HVAC ______________________________________Heating, Ventilation & Air Conditioning 

Hz ________________________________________Hertz 

IEA GHG ___________________________________IEA Greenhouse Gas Programme 

in _________________________________________Inch(es) 

IR _________________________________________Infrared 

IRGA ______________________________________Infrared Gas Analyzer 

IEA ________________________________________International Energy Agency 

IOGCC _____________________________________Interstate Oil & Gas Compact Commission 

IP _________________________________________Induced Polarization 

ISO________________________________________International Organization for Standardization 

IPCC _______________________________________Intergovernmental Panel on Climate Change 

km ________________________________________Kilometer(s) 

Kr _________________________________________Krypton 

KHz _______________________________________Kilohertz 

LANL ______________________________________Los Alamos National Laboratory 

LBNL ______________________________________Lawrence Berkeley National Laboratory 

LCD _______________________________________Liquid Crystal Display 

LEERT______________________________________Long Electrode Electrical Resistance Tomography 

LIDAR______________________________________Light Detection and Ranging 

LLNL ______________________________________Lawrence Livermore National Laboratory 

LVST_______________________________________Large Volume Sequestration Test 

mD________________________________________Millidarcy 

MDT_______________________________________Modular Dynamic Tester 

m _________________________________________Meter(s) 

mi ________________________________________Mile(s) 

mg________________________________________milligram(s) 

Mg ________________________________________Magnesium 

MGSC _____________________________________Midwest Geological Sequestration Consortium 

MIT _______________________________________Mechanical Integrity Test 

MVA_______________________________________Monitoring, Verification, and Accounting 

MRSCP_____________________________________Midwest Geological Carbon Sequestration Consortium 

NaCl_______________________________________Sodium Chloride 
vi List of Acronyms and Abbreviations 

Acronym/Abbreviation 

N _________________________________________

Ne ________________________________________

NETL ______________________________________

NNSA______________________________________

O/O2_______________________________________

ORD_______________________________________

ORNL ______________________________________

OST _______________________________________

P _________________________________________

PC ________________________________________

Definition 

Nitrogen 

Neon 

National Energy Technology Laboratory 

National Nuclear Security Administration 

Oxygen 

NETL’s Office of Research and Development 

Oak Ridge National Laboratories 

DOE’s Office of Science and Technology 

Pressure 

Pulverized Coal 

PCOR ______________________________________Plains CO2

 Reduction Partnership 

PFC _______________________________________Perfluorocarbon(s) 

PFT _______________________________________Perfluorocarbon Tracers 

PNC _______________________________________Pulsed Neutron Capture 

ppm_______________________________________Parts per Million 

ppmv______________________________________Parts per Million by Volume 

psi ________________________________________Pounds per Square Inch 

PTRC ______________________________________Petroleum Technology Research Centre 

QC ________________________________________Quality Control 

R&D _______________________________________Research and Development 

RCSP ______________________________________Regional Carbon Sequestration Partnership 

RGGI ______________________________________Regional Greenhouse Gas Initiative 

Rn ________________________________________Radon 

RST _______________________________________Reservoir Saturation Tool 

S__________________________________________Sulfur 

SAPT ______________________________________Standard Annular Pressure Test 

SAR _______________________________________Synthetic Aperture Radar 

scfd _______________________________________Standard Cubic Feet per Day 

SDWA _____________________________________Safe Drinking Water Act 

SECARB ____________________________________Southeast Regional Carbon Sequestration Partnership 

SF6 ________________________________________Sulfur Hexafluoride 

SNL _______________________________________Sandia National Laboratory 

SO4

________________________________________Sulfate 

SP ________________________________________Self-Potential/Spontaneous Polarization 

STEM ______________________________________Scanning Transmission Electron Microscope 

SWP _______________________________________Southwest Regional Partnership 

T__________________________________________Temperature 

TAME ______________________________________The Andersons Marathon Ethanol (Plant) 

TDS _______________________________________Total Dissolved Solids 

USDW _____________________________________Underground Sources of Drinking Water 

UIC________________________________________Underground Injection Control 

USGS ______________________________________U.S. Geological Survey 

USIT _______________________________________Ultrasonic Imaging Tool 

VDL _______________________________________Variable Density Log 

VSP _______________________________________Vertical Seismic Profile 

WestCarb __________________________________West Coast Regional Carbon Sequestration Partnership 

Xe ________________________________________Xenon 

ZEPP-1 _____________________________________Zero-Emissions Power Plant 

ZERT ______________________________________Zero Emission Research and Technology 
List of Tables vii 

List of Tables
 

Table 1-1: DOE MVA Goals Outline and Milestones _________________________________________________________ 1-2 

Table 2-1: Comprehensive List of Proposed Monitoring Methods Available for GS Projects_________________________ 2-1 

Table 3-1: Classification of Primary Models Used by RCSPs __________________________________________________ 3-12 

Table 4-1: Breakdown of RCSP (Phase II and Phase III) UIC Permits by Sink Type __________________________________ 4-2 

Table 4-2: Summary of Current Mandatory Technical Requirements for for Class I, Class II, 

Class V, and Class VI (Proposed) UIC Injection Wells ________________________________________________ 4-4 

Table 5-1: List of RCSPs’ Monitoring Tools for Phase II and Phase III Projects _____________________________________ 5-3 

Table 5-2: MVA Technologies that Enable Recognition of Leakage to the Atmosphere and Shallow 

Subsurface in Order to Ensure 99 Percent Retention of CO2 _________________________________________ 5-16 

Table 6-1: Comparison of Site Geology for Each Case Study Project ___________________________________________ 6-3 

Table 6-2: Comparison of MVA Tools Used by Each of the Selected Case Studies _________________________________ 6-4 

Table 6-3: Summary of MVA Plans for Gulf Coast Mississippi Strandplain Deep Sandstone Test _____________________ 6-9 

Table 6-4: Summary of MVA Program to be Implemented at Large-Scale Injection Sites __________________________ 6-15 

Table 6-5: Basic and Enhanced Monitoring Packages and a Comparison to the Proposed Monitoring Program _______ 6-21 

Table 6-6: Summary of the Potential Risks Associated with Large-Scale Injection of CO2 __________________________ 6-25 
 

 

viii List of Figures 

List of Figures
 

Figure 3-1: Amplitude difference map at the Midale Marly horizon for the Weyburn Monitor 1 (a) 

and 2 (b) surveys relative to the baseline survey. The normalized amplitudes are RMS values 

determined using a 5-ms window centered on the horizon. ________________________________________ 3-13 

Figure 3-2: δ13C {HCO3} in produced fluids at Weyburn. The well locations (black dots) represent the 

locations of data points that are used to produce the contour plots. Values are per mil 

differences in the ratio of 12C to 13C relative to the PDB standard. ____________________________________ 3-13 

Figure 3-3: Time lapse seismic data collection and interpretation from large CO2 injection projects. Three 

successive seismic volumes from the Sleipner project, Norway. Upper images are cross-sections 

through the injection point; the lower images show impedance changes at the top of the CO2 

plume. Injection began in 1996, between the first two surveys. _____________________________________ 3-14 

Figure 5-1: Decision tree for pre-operational and operational phase monitoring techniques for 

GS project based on mandatory monitoring requirements and proposed Class VI requirements. 

Primary technologies are listed with black text and solid figure lines, whereas Secondary and 

Potential Additional Technologies are listed with red text and dashed figure lines. Light-grey lines 

depict proposed UIC regulatory changes for Class VI Wells. _________________________________________ 5-5 

Figure 5-2: Decision tree for post-injection monitoring techniques for a GS project based on mandatory 

monitoring requirements. Primary technologies are listed with black text and solid figure lines, 

whereas Secondary and Potential Additional Technologies are listed with red text and dashed 

figure lines. Light-grey lines depict proposed UIC regulatory changes for Class VI Wells.__________________ 5-6 

Figure 5-3: Potential leakage pathways along an existing well: between cement and casing (Paths a and b), 

through the cement (c), through the casing (d), through fractures (e), and between cement and 

formation (f). ______________________________________________________________________________ 5-12 

Figure 6-1: Hierarchical Monitoring Strategy_______________________________________________________________ 6-7 

Figure 6-2: Example of contingency plans for Gulf Coast Mississippian fluvial sandstone injection during 

initial injection period. Major risks during injection period: pressure and buoyancy-driven flow 

through damaged wells or fracture networks. Probability increases over time as CO2 quantity 

and pressure increases and as AoR increases. _____________________________________________________ 6-8 

Figure 6-3: Schematic Showing Overall Monitoring Approach for Saline Formation LVST __________________________ 6-20 

Figure AIII-1: Crustal deformation survey interpretations. (Left) Tiltmeter array interpretation from an oil 

field operation, revealing the location of a small change in surface elevation. Image courtesy 

of Pinnacle Technologies, Inc. (Right) InSAR difference map showing complex subsidence (red) 

and uplift (blue) associated with oil field production near Bakersfield, California, from 

August 1979 to September 1999. Color bands show roughly 60 millimeters of change from 

 red to blue; resolution is one millimeter deformation. The image shows large oil fields and 

illustrates how faults can affect the distribution of deformation. ____________________________________AIII-9 

Figure AIII-2: Schematic Drawing of the U-Tube Sampling Technology _________________________________________ AIII-11 
	 	 	 	 	

	 	 	 	

	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

 

Executive Summary ES-1 

Executive Summary 

This document should be of interest to a broad audience 

interested in reducing greenhouse gas (GHG) emissions 

to the atmosphere. It was developed for regulatory 

organizations, project developers, and national and state 

policymakers to increase awareness of existing and 

developing monitoring, verification, and accounting 

(MVA) techniques. Carbon dioxide (CO2

) sinks are 

a natural part of the carbon cycle; however, natural 

terrestrial sinks are not sufficient to absorb all the 

CO2

 emitted to the atmosphere each year. Due to 

present concerns about global climate change related 

to GHG emissions, efforts are underway to assess 

CO2

 sinks, both terrestrial and geologic, as a form of 

carbon management to offset emissions from fossil fuel 

combustion and other human activities. Reliable and 

cost-effective MVA techniques are an important part 

of making geologic sequestration (sometimes referred 

to as GS) a safe, effective, and acceptable method for 

GHG control. 

MVA of GS sites is expected to serve several purposes, 

including addressing safety and environmental 

concerns; inventory verification; project and national 

accounting of GHG emissions reductions at GS 

sites; and evaluating potential regional, national, and 

international GHG reduction goals. The primary goal 

of the U.S. Department of Energy’s (DOE) Carbon 

Sequestration and MVA Programs is to develop and 

demonstrate a broad portfolio of Primary, Secondary, 

and Potential Additional technologies, applications, and 

accounting requirements that can meet DOE’s defined 

goals of demonstrating 95 percent and 99 percent 

retention of CO2

 through GS by 2008 and 2012, 

respectively. The 95 percent and 99 percent retention 

levels are defined by the ability of a GS site to detect 

leakage of CO2

, at levels of 5 percent and 1 percent of 

the stored amount of CO2

, into the atmosphere. 

The MVA Program employs multiple Primary, 

Secondary, and Potential Additional Technologies (see 

Appendices I, II, and III for definitions) in several 

GS injection projects worldwide. Each GS site varies 

significantly in risk profile and overall site geology, 

including target formation depth, formation porosity, 

permeability, temperature, pressure, and seal formation. 

MVA packages selected for commercial-scale projects 

discussed are tailored to site-specific characteristics 

and geological features. The MVA packages for these 

projects were selected to maximize understanding of 

CO2

 behavior and determine what monitoring tools are 

most effective across different geologic regimes (as 

opposed to tailoring a site-specific MVA package). As 

defined in this report, available Primary technologies 

are already fully capable of meeting and exceeding 

monitoring requirements and achieving the MVA goals 

for 2008. It is believed that by 2012, modifications 

and improvements to monitoring protocols through the 

development of Secondary and Potential Additional 

technologies will reduce GS cost and enable 99 percent 

of injected CO2 to be credited as net emissions 

reduction. 

In the outlined approach, prior to operation, site 

characterization and associated risk assessment 

play a significant role in determining an appropriate 

monitoring program. Accredited projects are assumed 

to require a robust overall monitoring program for 

inventory verification for accounting of GHG emissions 

and GHG registries. The overall goal for monitoring 

will be to demonstrate to regulatory oversight bodies 

that the practice of GS is safe, does not create 

significant adverse local environmental impacts, and is 

an effective GHG control technology. In general, the 

goals of MVA for GS are to: 

•	 Improve understanding of storage processes and

confirm their effectiveness. 

•	 Evaluate the interactions of CO2

 with formation solids 

and fluids. 

•	 Assess environmental, safety, and health (ES&H)

impacts in the event of a leak to the atmosphere. 

•	 Evaluate and monitor any required remediation efforts

should a leak occur. 

• Provide a technical basis to assist in legal disputes

resulting from any impact of sequestration technology 

(groundwater impacts, seismic events, crop losses, etc.). 

As outlined in this report, GS of CO2

 requires preoperation, operation, closure, and post-closure 

monitoring activities at the storage site, as well as risk 

assessment and development of flexible operational 

plans, and mitigation strategies that can be implemented 

should a problem arise. Effective application of 

monitoring technologies ensures the safety of carbon 

capture and storage (CCS) projects with respect to both 

human health and the environment and provides the 
	 	 	 	 	 	

 

	 	 	 	 	 	

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ES-2 Executive Summary 

basis for establishing accounting protocols for GHG 

registries and carbon credits on trading markets for 

stored CO2

, if necessary. 

Since its inception in 1997, DOE’s Carbon Sequestration 

Program – managed within the Office of Fossil 

Energy (FE) and implemented by the National Energy 

Technology Laboratory (NETL) – has been developing 

both core and supporting technologies through which 

CCS can become an effective and economically viable 

option for reducing CO2

 emissions from coal-based 

power plants and other sources. Successful research 

and development (R&D) will enable CCS technologies

to overcome various technical, economic, and social 

challenges, such as cost-effective CO2

 separation 

and transport, long-term stability of CO2 storage in 

underground formations, monitoring and verification, 

integration with power generation systems, and public 

acceptance. 

In July 2008, the U.S. Environmental Protection 

Agency (EPA) proposed Draft Federal requirements 

under the Safe Drinking Water Act (SDWA) for 

the underground injection of CO2

 for GS purposes. 

EPA is tracking the progress and results of national 

and international GS research projects. DOE leads 

experimental field research on GS in the United States 

through the Regional Carbon Sequestration Partnerships 

(RCSP) Program. EPA is using the data and experience 

developed in the Core R&D Program, international

projects, and RCSP Program to provide a foundation 

to support decisions for development of an effective 

regulatory and legal environment for the safe, long-term 

underground injection and GS of GHGs. Furthermore, 

information gained from the RCSPs’ large- and smallscale geologic injection projects is predicted to provide 

the technical basis to account for stored CO2

 in support 

of any future GHG registries, incentives, or other policy 

instruments that may be deemed necessary in the 

future. Once the additional regulatory framework at the 

Federal and state levels is completed, based in part on 

the monitoring technologies and operational procedures 

employed by the demonstration projects undertaken by 

the RCSPs, proper standards will be in place to ensure 

a consistent and effective permitting and monitoring 

system for commercial-scale GS projects. 

The life cycle of a GS project involves four phases. 

Monitoring activities will vary among these phases: 

1. Pre-Operation Phase: Project design is carried 

out, baseline conditions are established, geology is 

characterized, and risks are identified. 

2. Operation Phase: Period of time during which 

CO2

 is injected into the storage reservoir. 

3. Closure Phase: Period after injection has stopped, 

during which wells are abandoned and plugged, 

equipment and facilities are removed, and agreed 

upon site restoration is accomplished. Only 

necessary monitoring equipment is retained. 

4. Post-Closure Phase: Period during which ongoing 

monitoring is used to demonstrate that the storage 

project is performing as expected and that it is 

safe to discontinue further monitoring. Once it is 

satisfactorily demonstrated that the site is stable, 

monitoring will no longer be required except in the 

very unlikely event of leakage, or legal disputes, 

or other matters that may require new information 

about the status of the storage project. 

Each monitoring phase (Pre-Operational, Operational, 

Closure, and Post-Closure) of a GS project will employ 

specialized monitoring tools and techniques that will 

address specific atmospheric, near-surface hydrologic, 

and deep-subsurface monitoring needs. 

DOE-sponsored RCSP projects will move CCS from 

research to commercial application. Such demonstrations 

are necessary to increase understanding of trapping 

mechanisms, to test and improve monitoring techniques 

and mathematical models, and to gain public acceptance 

of CCS. Testing under a wide range of geologic 

conditions will demonstrate that CCS is an acceptable 

GHG mitigation option for many areas of the country, 

and the world. 
	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

 

	 	 	 	 	 	 	 	 		

Executive Summary ES-3 

Modeling and monitoring R&D targets for RCSP

projects include: 

•	 Assessing the sweep efficiency as large volumes

of CO2 are injected to better quantify CO2 storage 


capacity.
 

•	 Quantifying the pressure effects and brine movement

though heterogeneous rock to better understand the 

significance of these effects on capacity and monitor 

pressure and brine migration. 

•	 Quantifying inter-well interactions as large plumes

develop, focusing on interaction of pressure, 

heterogeneity, and gravity as controls on migration. 

•	 Better understanding pressure and capillary seals.

•	 Developing and assessing the effectiveness of existing

and novel monitoring tools. 

•	 Assessing how these monitoring tools can be used

efficiently, effectively, and hierarchically in a mature 

monitoring environment. 

As outlined in this report, critical components of 

a robust MVA program include evaluating and 

determining which monitoring techniques are most 

effective and economic for specific geologic situations 

and obtaining information that will be vital in guiding 

future commercial projects. The monitoring programs 

of five selected GS projects taking place in the United 

States are provided. Each project is sited in an area 

considered suitable for GS and employs a robust 

monitoring program (for research purposes) to measure 

physical and chemical phenomena associated with 

large-scale CO2

 injection. The five projects discussed in 

this report are: 

1. Gulf Coast Mississippi Strandplain Deep 

Sandstone Test (Moderate Porosity and 

Permeability): GS test located in the southeast 

portion of the United States will be conducted in 

the down dip “water leg” of the Cranfield Unit in 

Southwest Mississippi. Large volumes of CO2 from 

a natural source will be delivered by an established 

pipeline. 

2. Nugget Sandstone Test (High Depth, Low Porosity 

and Permeability): Large volume sequestration test 

(LVST) in the Triassic Nugget Sandstone Formation 

on the Moxa Arch of Western Wyoming. The source 

of the CO2

 is the waste gas from a helium (He) and 

methane (CH4

) production facility. 

3. Cambrian Mt. Simon Sandstone Test (Moderate 

Depth, Low Porosity and Permeability): A largescale injection test in Illinois is being conducted in 

the Midwest Region of the United States. The main 

goal of this large-scale injection will be to implement 

geologic injection tests of sufficient scale to promote 

understanding of injectivity, capacity, and storage 

potential in reservoir types having broad importance 

across the Midwest Region. 

4. San Joaquin Valley Fluvial-Braided Deep 

Sandstone Test (High Porosity and Permeability): 

Large-scale injection of CO2

 into a deep saline 

formation beneath a power plant site (the Olcese 

and/or Vedder sandstones of the San Joaquin Valley, 

California). 

5. Williston Basin Deep Carbonate EOR Test: CO2 

sequestration and enhanced oil recovery (EOR) in 

select oil fields in the Williston Basin, North Dakota.

A minimum of 500,000 tons per year of CO2 from 

an anthropogenic source (pulverized coal [PC] plant) 

will be injected into an oil reservoir in the Williston 

Basin.

Each site varies significantly in overall site geology, 

including target formation depth, formation porosity, 

permeability, temperature, pressure, and seal formation. 

The MVA packages for these case studies were selected 

to maximize understanding of CO2

 behavior and 

determine what monitoring tools are most effective 

across different geologic regimes, as opposed to 

tailoring a site-specific MVA package. 
ES-4 
	 	 	 	 	 	 	 	

 

1.0 Introduction 1-1 

Monitoring, Verification, 

and Accounting of CO2 

Stored in Deep Geologic 

Formations 

1.0 Introduction 

Atmospheric levels of CO2 have risen significantly 

from preindustrial levels of 280 parts per million (ppm) 

to present levels of 384 ppm (Tans, 2008). Evidence 

suggests the observed rise in atmospheric CO2

 levels 

is the result of expanded use of fossil fuels for energy. 

Predictions of increased global energy use during 

this century indicate a continued increase in carbon 

emissions (EIA, 2007) and rising concentrations of CO2 

in the atmosphere unless major changes are made in the 

way energy is produced and used; in particular, how 

carbon is managed (Socolow et al., 2004; Greenblatt 

and Sarmiento, 2004). CO2

 sinks are a natural part of 

the carbon-cycle; however, natural sinks are unable to 

absorb all of the CO2

 emitted into the atmosphere each 

year. Due to present concerns about global climate 

change related to CO2 emissions, efforts are underway 

to better utilize both terrestrial and geologic CO2

 sinks 

as a form of carbon management to offset emissions 

derived from fossil fuel combustion and other human 

activities. 

The storage of industrially generated CO2 in deep 

geologic formations is being seriously considered as a 

method for reducing CO2 emissions into the atmosphere. 

This growing interest has lead to significant investment 

by governments and the private sector to develop the 

necessary technology and to evaluate whether this 

approach to CO2 control could be implemented safely 

and effectively. Depleted oil and gas reservoirs, 

unmineable coalbeds, and deep brine-filled (saline) 

formations are all being considered as potential storage 

options. Depleted oil and gas reservoirs are particularly 

suitable for this purpose, as they have shown by the test 

of time that they can effectively store buoyant fluids 

1 ISO 14064 is a published standard for GHG accounting and 

verification. ISO 14064 aims to promote consistency, transparency, 

and credibility in GHG quantification, monitoring, reporting, and 

verification. 

2 ISO 14065 specifies principles and requirements for bodies that 

undertake validation or verification of GHG assertions. 

like oil, gas, and CO2

. In principle, storage in deep 

brine-filled formations is the same as storage in oil or 

gas reservoirs, but the geologic seals that would keep 

the CO2 from rapidly rising to the ground surface need 

to be characterized and demonstrated to be suitable 

for long-term storage. Over hundreds to thousands of 

years, some fraction of the CO2

 is expected to dissolve 

in the native formation fluids. Some of the dissolved 

CO2

 will react with formation minerals and dissolved 

constituents and may precipitate as carbonate minerals, 

although this might take a long time. Once dissolved or 

precipitated as minerals, CO2

 is no longer buoyant and 

storage security may be increased (Benson and Myer,

2002). Coalbeds offer the potential for a different type 

of storage in which CO2

 becomes chemisorbed on the 

solid coal matrix. 

1.1 Importance of CO2 Monitoring and 

Accounting Protocols 

Reliable and cost-effective monitoring will be an 

important part of making GS a safe, effective, and 

acceptable method for CO2

 control. Monitoring will 

be required as part of the permitting process for 

underground injection and will be used for a number 

of purposes, such as tracking the location of the plume 

of injected CO2

, ensuring that injection and abandoned 

wells are not leaking, and verifying the quantity of 

CO2

 that has been injected underground. Additionally, 

depending on site-specific considerations, monitoring 

may be required to ensure that natural resources, 

such as groundwater and ecosystems, are protected 

and that the local population is not exposed to unsafe 

concentrations of CO2. 

An overview of various aspects of monitoring CO2 

storage projects is provided by the Intergovernmental 

Panel on Climate Change (IPCC) Special Report on 

Carbon Dioxide Capture and Storage (http://www. 

ipcc.ch/ipccreports/srccs.htm). The implementation of 

protocols that ensure that results can be confirmed is 

essential to an effective monitoring program. Approval 

of the International Organization for Standardization 

(ISO) 140641

 and 140652 by over 45 countries and the 

American National Standards Institute (ANSI, 2007) 

provides the foundation for developing protocols to 

validate and verify GS of CO2. Accredited projects 

will be required to develop an overall framework that 

defines the site characteristics and monitoring program 

for verification. Independent verification bodies assess 

the ability of the overall framework to verify stored 
 

 

 

 

 

 

 

 

 

	 	 	 	 	 	

	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

1-2 1.0 Introduction 

volumes of CO2. Evaluating a project by applying 

ISO 14064 and 14065 standards (ISO, 2006; ISO, 2007) 

recognizes that a balance must be established between 

practicality and cost for a monitoring program, while 

still providing accurate and transparent evidence to 

ensure that CO2 is effectively stored. The standards 

are applicable to a broad spectrum of industries and 

will support work already underway within established 

GHG programs, such as The Climate Registry, the 

California Climate Action Registry, the Chicago Climate 

Exchange (CCX), and the Regional Greenhouse Gas 

Initiative (RGGI). 

1.2 Regulatory Compliance 

Eventually commercial scale CO2 storage projects will 

require a new regulatory framework that addresses the 

unresolved issues regarding the regulation of a large, 

industrial-scale CCS program in order to facilitate 

safe and economic capture, transportation, subsurface 

injection, and long-term GS and monitoring of CO2. 

In July 2008, EPA proposed Federal Regulations 

under the SDWA for underground injection of CO2 for 

the purpose of GS (Federal Register, July 25, 2008). 

EPA is tracking the progress and results of national 

and international GS research projects. DOE leads 

experimental field research on GS in the United States 

in conjunction with the RCSP Program. EPA is using 

the data and experience of domestic and international 

projects. The RCSP Program is providing a foundation 

support decisions in the development of an effective 

regulatory and legal environment for the safe, long-term 

underground injection and GS of CO2

. Furthermore, 

information gained from large- and small-scale geologic 

injection projects will contribute to the accounting of 

stored CO2 to support future GHG registries, incentives, 

or other policy instruments that may arise in the future. 

A discussion on CCS regulatory issues, including 

specific mandatory monitoring requirements outlined 

by Underground Injection Control (UIC) permits, 

and a breakdown of the UIC permits issued (by well 

class) to the RCSP Phase II and Phase III projects is in 

Chapter 4. 

1.3 Objective and Goals of Monitoring 

The principal goal of DOE’s Carbon Sequestration 

Program is to gain a scientific understanding of 

carbon sequestration options and to provide costeffective, environmentally sound technology 

options that ultimately may lead to a reduction in 

CO2

 emissions. The program’s overarching goals 

are presented in Table 1-1. The primary Carbon 

Sequestration Program MVA goal is to develop 

technology applications that enable recognition of 

leakage to the atmosphere and shallow subsurface in 

order to ensure 95 percent retention of stored CO2 in 

2008 and 99 percent retention of stored CO2 in 2012. 

Table 1-1: DOE MVA Goals Outline and Milestones 

Year Goal 

2008 

Develop MVA protocols that enable recognition 

of leakage to the atmosphere and shallow 

subsurface in order to ensure 95 percent 

retention of stored CO2. 

2012 

Develop MVA protocols that enable recognition 

of leakage to the atmosphere and shallow 

subsurface in order to ensure 99 percent 

retention of stored CO2. 

Source: Carbon Sequestration Program Environmental 


Reference Document, 2007b
 

A range of techniques capable of ensuring that leakage 

pathways have not developed and that CO2 has remained 

in the subsurface are available for monitoring CO2 

storage. Further description of how monitoring will 

achieve specific NETL-based MVA goals is described 

in Section 5.7. 

Monitoring will be essential for the successful 

implementation of GS. The overall goals for monitoring 

are to demonstrate to regulatory oversight bodies that 

the practice of GS is safe, does not create significant 

adverse local environmental impacts, and that it is an 

effective CO2 control technology. In general, the goals 

of MVA for GS are to (Litynski et al., 2008): 

•	 Identify storage processes and confirm their integrity

•	 Evaluate the interactions of CO2

 with formation solids 

and fluids 

•	 Assess potential environmental, health, and safety

effects in the event of a leak 

•	 Evaluate and monitor mitigation efforts should a leak

occur 

•	 Assist in mediating legal disputes resulting from any

impact of sequestration technology (groundwater 

impacts, seismic events, crop losses, etc.) 
	 	 	 		 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 		 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	

1.0 Introduction 1-3 

1.4 Monitoring Activities 

GS of CO2 requires pre-operation, operation, closure, 

and post-closure monitoring activities (described 

in Section 5.0) at the storage site, as well as risk 

assessment and development of mitigation strategies 

that can be implemented should a problem arise. 

The effective application of monitoring technologies 

ensures the safety of CCS projects, with respect to 

both human health and the environment, and will 

contribute greatly to the development of relevant 

technical approaches for monitoring and verification. 

The development, application, and reporting of results 

from MVA strategies for projects must be integrated 

with the multidisciplinary team working to design 

and operate GS projects. Site characterization and 

simulation activities will help to design a robust MVA 

system that will provide data to validate expected 

results, monitor for signals of leakage, and provide 

confidence that the CO2 remains in the subsurface. 

All of these project activities will need to support 

an interactive risk assessment process focused on 

identifying and quantifying potential risks to humans 

and the environment associated with geologic CO2 

storage and helps to ensure that these risks remain low 

throughout the life cycle of a GS project. Through 

the development, modification, and application of 

well-selected and designed monitoring technologies, 

CCS risks are estimated to be comparable to those 

associated with current oil and gas operations 

(Benson et al., 2005a). Appendix IV presents a

summary of the purpose for monitoring during the 

various phases of a GS project. 

Considerable effort in the GEO-SEQ project was

devoted to assessing and demonstrating the application 

of geophysical methods for monitoring subsurface 

processes of interest in GS projects. GEO-SEQ is a

public-private applied R&D partnership, formed with

the goal of developing the technology and information 

needed to enable safe and cost-effective GS by the year 

2015. The workflow for application of geophysical 

methods in a GS project involves the following steps: 

•	 Identify subsurface processes or targets relevant to the

particular monitoring activity of interest 

•	 Select the suite of geophysical techniques best suited

for the subsurface measurements 

•	 Perform a baseline set of measurements before CO2 

injection 

•	 Repeat measurements at intervals during and after

injection 

•	 Interpret results, focusing on time-lapse changes

(LBNL, 2004)

1.5 Need for Multiple Projects with Varying 

Geologic Characteristics 

Although the types and quantities of point source CO2, 

as well as the cost of capturing the CO2 could influence 

commercial deployment rates of storage technologies, 

availability of CO2 is not expected to be a limiting 

factor in technology application. Rather, long-term 

carbon sequestration deployment would be influenced 

to a greater degree by the presence of suitable geologic 

resources (sinks). The best geologic carbon sink 

formations capable of storing CO2

 include oil and gas 

bearing formations, saline formations, basalt, deep coal 

seams, and oil- or gas-rich shales. Not all geologic 

formations are suitable for CO2 storage; some are too 

shallow and others have poor confining characteristics 

or low permeability (the ability of rock to transmit 

fluids through pore spaces). Formations suitable for 

CO2 storage have specific characteristics that include 

thick accumulations of sediments or rock layers, 

permeable layers saturated with saline water (saline 

formations), coupled with extensive covers of low 

porosity sediments or rocks acting as seals (cap rock), 

structural simplicity, and lack of faults (IPCC, 2005). 

Geographical differences across the United States in 

fossil fuel use and potential storage sites dictate the use 

of a regional approach to address carbon sequestration. 

To accommodate these differences, DOE created a 

nationwide network of seven RCSPs in 2003 to help 

determine and implement the technology, infrastructure, 

and regulations most appropriate for promoting carbon 

sequestration in different regions of the United States. 

Monitoring for CO2

 storage projects should be tailored 

to the specific conditions and risks at the storage site. 

For example, if the storage project is in a depleted oil 

reservoir with a well-defined cap rock and storage trap, 

the most likely pathways for leakage are the injection 

wells themselves or the plugged abandoned wells 

from previous reservoir operations. In this case, the 

monitoring program should focus on assuring proper 

performance of all wells in the area, and ensuring that 

they are not leaking CO2

 to the surface or shallow 

aquifers. However, if a project is in a brine-filled 

reservoir where the cap rock is less well defined, or 
 

	 	 	 	 	 	

1-4 1.0 Introduction 

lacks a local structural trap, the monitoring program 

should focus on tracking the migration of the plume and 

ensuring that it does not leak through discontinuities 

in the cap rock. Similar arguments can be made about 

projects where solubility or mineral trapping is a critical 

component of the storage security. In this case, it would 

be necessary to demonstrate that the geochemical 

interactions were effective and progressing as predicted. 

The value of taking a tailored approach to monitoring 

is two-fold. First, the monitoring program focuses on 

the largest risks. Second, since monitoring may be 

expensive, a tailored approach will enable the most 

cost-effective use of monitoring resources. However, 

it is likely that there will likely be a minimum set of 

monitoring requirements that will be based on experience 

and regulations from related activities like natural gas 

storage, CO2

 EOR, and disposal of industrial wastes in 

deep geologic formations (Benson et al., 2002b).
2.0 Monitoring Techniques 2-1 

2.0 Monitoring Techniques 

Table 2-1 is a list of MVA techniques tested or proposed to be employed in geologic CO2 storage projects being 

implemented by the RCSPs and others. A brief description of each method is provided in the table, along with the 

benefits and challenges. Further details are provided in Appendices I (atmospheric monitoring), II (near-surface 

monitoring), and III (subsurface monitoring). Note that the tools are used in more than one setting; however, the same 

technique can have different benefits at different depths. 

Table 2-1: Comprehensive List of Proposed Monitoring Methods Available for GS Projects 

Atmospheric Monitoring Techniques* 

Monitoring 

Technique Description, Benefits, and Challenges 

CO2 Detectors 

Description: Sensors for monitoring CO2

 either intermittently or continuously in air. 

Benefits: Relatively inexpensive and portable. Mature and new technologies represented. 

Challenges: Detect leakage above ambient CO2 emissions (signal to noise). 

Eddy Covariance 

Description: Atmospheric flux measurement technique to measure atmospheric CO2

 concentrations 

at a height above the ground surface. 

Benefits: Mature technology that can provide accurate data under continuous operation. 

Challenges: Very specialized equipment and robust data processing required. Signal to noise. 

Advanced Leak 

Detection System 

Description: A sensitive three-gas detector (CH4, Total HC, and CO2) with a GPS mapping system 

carried by aircraft or terrestrial vehicles. 

Benefits: Good for quantification of CO2 fluxes from the soil. 

Challenges: Null result if no CO2

. 

Laser Systems and 

LIDAR 

Description: Open-path device that uses a laser to shine a beam – with a wavelength that CO2 

absorbs – over many meters. 

Benefits: Highly accurate technique with large spatial range. Non-intrusive method of data collection 

over a large area in a short timeframe. 

Challenges: Needs favorable weather conditions. Interference from vegetation, requires time laps 

Signal to noise. 

Tracers (Isotopes) 

Description: Natural isotopic composition and/or compounds injected into the target formation 

along with the CO2. 

Benefits: Used to determine the flow direction and early leak detection. 

Challenges: Samples need analyzed offsite of project team does not have the proper analytical 

equipment. 

*See Appendix I for Details 
2-2 2.0 Monitoring Techniques 

Near-Surface Monitoring** 

Monitoring Technique Description, Benefits, and Challenges 

Ecosystem Stress 

Monitoring 

Description: Satellite or airplane-based optical method. 

Benefits: Easy and effective reconnaissance method. 

Challenges: Detection only after emission has occurred. Quantification of leakage rates 

difficult. Changes not related to CCS lead to false positives. Not all ecosystems equally 

sensitive to CO2. 

Tracers 

Description: CO2

 soluble compounds injected along with the CO2.into the target formation 

Benefits: Used to determine the hydrologic properties, flow direction and low-mass leak 

detection. 

Challenges: Many of the tested CO2-soluble tracers are GHGs, and therefore, add to risk 

profile. 

Groundwater Monitoring 

Description: Sampling of water or vadose zone/soil (near surface) for basic chemical analysis. 

Benefits: Mature technology, easier detection than atmospheric. Early detection prior to 

large emissions. 

Challenges: Significant effort for null result (no CO2 leakage). Relatively late detection of 

leakage. 

Thermal Hyperspectral 

Imaging 

Description: An aerial remote-sensing approach primarily for enhanced coalbed methane 

recovery and sequestration. 

Benefits: Covers large areas; detects CO2 and CH4. 

Challenges: Not a great deal of experience with this technique in GS. 

Synthetic Aperture Radar 

(SAR & InSAR) 

Description: A satellite-based technology in which radar waves are sent to the ground to 

detect surface deformation. 

Benefits: Large-scale monitoring (100 km x 100 km). 

Challenges: Best used in environments with minimal topography, minimal vegetation, and 

minimal land use. Only useful in time-laps. 

Color Infrared (CIR) 

Transparency Films 

Description: A vegetative stress technology deployed on satellites or aerially. 

Benefits: Good indicator of vegetative health, which can be an indicator of CO2 or brine 

leakage. 

Challenges: Detection only post-leakage. Need for deployment mechanism (i.e. aircraft). 

Tiltmeter 

Description: Measures small changes in elevation via mapping tilt , either on the surface or in 

subsurface. 

Benefits: Mature oil field technology for monitoring stream or water injection, CO2 flooding 

and hydrofracturing. 

Challenges: Access to surface and subsurface. Measurements are typically collected 

remotely. 

Flux Accumulation 

Chamber 

Description: Quantifies the CO2

 flux from the soil, but only from a small, predetermined area. 

Benefits: Technology that can quickly and effectively determine CO2

 fluxes from the soil at a 

predetermined area. 

Challenges: Only provides instantaneous measurements in a limited area. 

**See Appendix II for Details 
2.0 Monitoring Techniques 2-3 

Near-Surface Monitoring** 

Monitoring Technique Description, Benefits, and Challenges 

Induced Polarization 

Description: Geophysical imaging technology commonly used in conjunction with DC 

resistivity to distinguish metallic minerals and conductive aquifers from clay minerals in 

subsurface materials. 

Benefits: Detecting metallic materials in the subsurface with fair ability to distinguish 

between different types of mineralization. Also a useful technique in clays. 

Challenges: Does not accurately depict non-metallic based materials. Typically used only for 

characterization. 

Spontaneous (Self) 

Potential 

Description: Measurement of natural potential differences resulting from electrochemical 

reactions in the subsurface. Typically used in groundwater investigations and in 

geotechnical engineering applications for seepage studies. 

Benefits: Fast and inexpensive method for detecting metal in the near subsurface. Useful 

in rapid reconnaissance for base metal deposits when used in tandem with EM and 

geochemical techniques. 

Challenges: Should be used in conjunction with other technologies. Qualitative only. 

Soil and Vadose Zone Gas 

Monitoring 

Description: Sampling of gas in vadose zone/soil (near surface) for CO2

. 

Benefits: CO2

 retained in soil gasses provides a longer residence time. Detection of elevated 

CO2 concentrations well above background levels provides indication of leak and migration 

from the target reservoir. 

Challenges: Significant effort for null result (no CO2 leakage). Relatively late detection of 

leakage. 

Shallow 2-D Seismic 

Description: Closely spaced geophones along a 2-D seismic line. 

Benefits: Mature technology that can provide high resolution images of the presence of gas 

phase CO2. Can be used to locate “bright spots” that might indicate gas, also/ used in timelaps. 

Challenges: Semi-quantitative. Cannot be used for mass-balance CO2 dissolved or trapped 

as/mineral not monitored. Out of plane migration not monitored. 

**See Appendix II for Details 
2-4 2.0 Monitoring Techniques 

Subsurface Monitoring*** 

Monitoring Technique Description, Benefits, and Challenges 

Multi-component 3-D 

Surface Seismic Timelapse Survey 

Description: Periodic surface 3-D seismic surveys covering the CCS reservoir. 

Benefits: Mature technology that can provide high-quality information on distribution and 

migration of CO2. Best technique for map view coverage. Can be used in multi-component 

form (ex. three, four, or nine component), to account for both compressional waves (P-waves) 

and shear waves (S-waves). 

Challenges: Semi-quantitative. Cannot be used for mass-balance CO2 dissolved or trapped 

as/mineral not monitored. Signal to noise, not sensitive to concentration. Thin plumes or 

low CO2 concentration may not be detectable. 

Vertical Seismic Profile 

(VSP) 

Description: Seismic survey performed in a wellbore with multi-component processes. Can 

be implemented in a “walk-away” fashion in order to monitor the footprint of the plume as it 

migrates away from the injection well and in time-lapse application. 

Benefits: Mature technology that can provide robust information on CO2 concentration and 

migration. More resolution than surface seismic by use of a single wellbore. Can be used for 

calibration of a 2-D or 3-D seismic. 

Challenges: Application limited by geometry surrounding a wellbore. 

Magnetotelluric 

Sounding 

Description: Changes in electromagnetic field resulting from variations in electrical 

properties of CO2 and formation fluids. 

Benefits: Can probe the Earth to depths of several tens of kilometers. 

Challenges: Immature technology for monitoring of CO2 movement. Relatively low 

resolution. 

Electromagnetic 

Resistivity 

Description: Measures the electrical conductivity of the subsurface including soil, 

groundwater, and rock. 

Benefits: Rapid data collection. 

Challenges: Strong response to metal. Sensitivity to CO2

. 

Electromagnetic 

Induction Tomography 

(EMIT) 

Description: Utilizes differences in how electromagnetic fields are induced within various 

materials. 

Benefits: Provides greater resolution and petrophysical information than ERT. 

Challenges: Difficult to execute. Requires non-conductive casing downhole to obtain high– 

frequency data. Esoteric technique, not proven for GS. 

Injection Well Logging 

(Wireline Logging) 

Description: Wellbore measurement using a rock parameter, such as resistivity or 

temperature, to monitor fluid composition in wellbore (Specific wireline tools expanded in 

Appendix III). 

Benefits: Easily deployed technology and very useful for wellbore leakage. 

Challenges: Area of investigation limited to immediate wellbore. Sensitivity of tool to fluid 

change. 

Annulus Pressure 

Monitoring 

Description: A mechanical integrity test on the annular volume of a well to detect leakage 

from the casing, packer or tubing. Can be done constantly. 

Benefits: Reliable test with simple equipment. Engineered components are known to be 

areas of high frequency. 

Challenges: Periodic mechanical integrity testing requires stopping the injection process 

during testing. Limited to constructed system. 

***See Appendix III for Details 
2.0 Monitoring Techniques 2-5 

Subsurface Monitoring*** 

Monitoring Technique Description, Benefits, and Challenges 

Pulsed Neutron Capture 

Description: A wireline tool capable of depicting oil saturation, lithology, porosity, oil, gas, 

and water by implementing pulsed neutron techniques. 

Benefits: High resolution tool for identifying specific geologic parameters around the well 

casing. Most quantitative to CO2 saturation in time-lapse. 

Challenges: Geologic characteristics identified only in the vicinity of the wellbore. Not 

sensitive to dissolution trapped and mineral trapped CO2. Sensitive to borehole conditions, 

fluid invasion because of workover. Decreased sensitivity in lower salinity water, at low 

saturation. 

Electrical Resistance 

Tomography (ERT) 

Description: Use of vertical arrays of electrodes in two or more wells to monitor CO2 as a 

result of changes in layer resistivity. 

Benefits: Potential high resolution technique to monitor CO2 movement between wells. 

Challenges: Immature technology for monitoring of CO2 movement. Processes such as massbalance and dissolution/mineral trapping difficult to interpret. Poor resolution and limited 

testing in GS applications. 

Sonic (Acoustic) Logging 

Description: A wireline log used to characterize lithology, determine porosity, and travel time 

of the reservoir rock. 

Benefits: Oil field technology that provides high resolution. Can be used to time seismic 

sections. 

Challenges: Does not yield data on hydraulic seal. May have to make slight corrects for 

borehole eccentricity. Not a “stand alone” technology. Should be used in conjunction with 

other techniques. 

2-D Seismic Survey 

Description: Acoustic energy, delivered by explosive charges or vibroseis trucks (at the 

surface) is reflecting back to a straight line of recorders (geophones). After processing, the 

reflected acoustic signature of various lithologies is presented as a 2-D graphical display. 

Benefits: Can be used to monitor “bright spots” of CO2 in the subsurface. Excellent for shallow 

plumes as resolution decreases with depth. 

Challenges: Coverage limited to lines. 

Time-lapse Gravity 

Description: Use of gravity to monitor changes in density of fluid resulting from injection of CO2. 

Benefits: Effective technology. 

Challenges: Limited detection and resolution unless gravimeters are located just above 

reservoir, which significantly increases cost. Sensitivity. 

Density Logging (RHOB 

Log) 

Description: Continuous record of a formation bulk density as a function of depth by 

accounting for both the density of matrix and density of liquid in the pore space. 

Benefits: Effective technology that can estimate formation density and porosity at varying 

depths. 

Challenges: Lower resolution log compared to other wireline methods. 

Optical Logging 

Description: Device equipped with optical imaging tools is lowered down the length of the 

wellbore to provide detailed digital images of the well casing. 

Benefits: Simple and cheap technology that provides qualitative well integrity verification at 

depth. 

Challenges: Does not provide information beyond what is visible inside the well casing. 

***See Appendix III for Details 
2-6 2.0 Monitoring Techniques 

Subsurface Monitoring*** 

Monitoring Technique Description, Benefits, and Challenges 

Cement Bond Log 

(Ultrasonic Well Logging) 

Description: Implement sonic attenuation and travel time to determine whether casing 

is cemented or free. The more cement which is bonded to casing, the greater will be the 

attenuation of sounds transmitted along the casing. Used to evaluate the integrity of the 

casing cement and assessing the possibility of flow outside of casing. 

Benefits: Evaluation of quality of engineered well system prior to leakage, allows for 

proactive remediation of engineered system. Indicates top of cement, free pipe, and gives 

an indication of well cemented pipe. Authorized as an MIT tool for the demonstration of 

external integrity of injection wells. 

Challenges: Good centralization is important for meaningful and repeatable cement bond 

logs. Cement bond logs should not be relied on for a quantitative evaluation of zonal 

isolation or hydraulic integrity. The cement should be allowed to cure for at least 72 hours 

before logging. 

Gamma Ray Logging 

Description: Use of natural gamma radiation to characterize the rock or sediment in a 

borehole. 

Benefits: Common and inexpensive measurement of the natural emission of gamma rays by 

a formation. 

Challenges: Subject to error when a large proportion of the gamma ray radioactivity 

originates from the sand-sized detrital fraction of the rock. Limited to site characterization 

phase. 

Microseismic (Passive) 

Survey 

Description: Provides real-time information on hydraulic and geomechanical processes 

taking place within the reservoir in the interwell region, remote from wellbores by 

implementing surface or subsurface geophones to monitor earth movement. 

Benefits: Technology with broad area of investigation that can provide provides high-quality, 

high resolution subsurface characterization data and can provide effects of subsurface 

injection on geologic processes. 

Challenges: Dependence on secondary reactions from CO2

 injection, such as fracturing and 

faulting. Difficult to interpret low rate processes (e.g., dissolution/mineral trapping and slow 

leakage). Extensive data analysis required. 

Crosswell Seismic Survey 

Description: Seismic survey between two wellbores in which transmitters and receivers are 

placed in opposite wells. Enables subsurface characterization between those wells. Can be 

used for time-lapse studies. 

Benefits: Crosswell seismic profiling provides higher resolution than surface methods, but 

sample a smaller volume. 

Challenges: Mass-balance and dissolution/mineral trapping difficult to monitor. 

Aqueous Geochemistry 

Description: Chemical measurement of saline brine in storage reservoir. 

Benefits: Coupled with repeat analyses during and after CO2

 injection can provide massbalance and dissolution/mineral trapping information. 

Challenges: Cannot image CO2 migration and leakage directly. Only near-well fluids are 

measured. 

Resistivity Log 

Description: Log of the resistivity of the formation, expressed in ohm-m, to characterize the 

fluids and rock or sediment in a borehole. 

Benefits: Used for characterization, also sensitive to changes in fluids. 

Challenges: Resistivity can only be measured in open hole or non-conducive casing. 

***See Appendix III for Details 
		 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 		 	 	 	 	 	 	 	

	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 		 	

	 	 	 	 	 	 	 		 	

	 	 	 	 	 	 	 	

 

 

 

 

 

 

3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 3-1 

3.0 Developments in Monitoring 

Techniques from DOE Supported 

and Leveraged Monitoring 

Activities 

Since its inception in 1997, DOE’s Carbon Sequestration 

Program – managed within FE and implemented by 

NETL – has been developing both core and supporting 

technologies through which CCS can become an 

effective and economically viable option for reducing 

CO2

 emissions from coal-based power plants (NETL, 

2007a). Successful R&D will enable CCS technologies

to overcome various technical, economic, and social 

challenges, such as cost-effective CO2

 separation and 

transport, long-term stability of CO2 sequestration 

in underground formations, MVA, integration with 

power generation systems, and public acceptance. The 

programmatic timeline is to demonstrate a portfolio 

of safe and cost-effective CO2

 capture, storage, and 

mitigation technologies at the commercial scale by 

2012, leading to substantial deployment and market 

penetration beyond 2020. 

3.1 Core R&D 

DOE’s Core R&D Program focuses on developing

new MVA technologies and approaches to the point 

of pre-commercial application. The program’s core 

R&D agenda focuses on increased understanding of

CO2 GS, MVA technology and cost, and regulations 

and permitting. A major portion of DOE’s Core R&D

is aimed at providing an accurate accounting of stored 

CO2

 and a high level of confidence that the CO2 will 

remain permanently sequestered. MVA research seeks 

to develop: 

•	 Instruments that can detect CO2

 in a storage 

reservoir and/or measure its movement throughtime lapse measurements and determine its physical 

(supercritical, dissolved, gas phase, solid) and 

chemical state with precision. 

•	 The capability to interpret and analyze the results

from such instruments. 

•	 The ability to use modeling to predict how movement

and/or chemical reactions of CO2

 in the reservoir 

will affect: (1) the permanence of storage, (2) the 

environmental impacts within the reservoir, and (3) 

human health. 

•	 Best practices and procedures that can be used to

respond to any detected changes in the condition of 

the stored CO2 in order to mitigate losses of carbon 

and prevent negative impacts on the environment and 

human health. 

A successful MVA effort will enable sequestration 

project developers to ensure human health and safety 

and prevent damage to the host ecosystem. The goal 

is to provide sufficient information and safeguards to 

allow developers to obtain permits for sequestration 

projects. MVA also seeks to support the development 

of an accounting to validate the retention of CO2

 in 

deep geologic formation that approaches 100 percent, 

contributing to the economic viability of sequestration 

projects.. Finally, MVA should provide improved 

information and feedback to sequestration practitioners, 

resulting in accelerated technologic progress. 

DOE’s Core R&D activities for geologic carbon

sequestration and subsequent monitoring activities are 

generally divided into deep conventional reservoirs 

(saline formations, depleted oil and gas fields, and EOR 

fields) and deep, unmineable coal seams. Specific tools 

and techniques under the MVA Program are classified 

based on their intended application and purpose 

(atmospheric, near-surface, or subsurface monitoring). 

Monitoring techniques are listed in Table 2-1, and those 

used in saline formations, depleted oil and gas fields, 

EOR fields and coalbed methane (CBM) or enhanced

coalbed methane (ECBM) are outlined below. Core

R&D test locations are discussed in Section 3.2. The

following discussion highlights some of the research 

that DOE’s Core R&D program has supported through

external research projects focused on developing MVA 

technologies and their application. These technologies 

may be considered Primary, Secondary, or Potential 

Additional depending on their capabilities and designed 

purpose. Their application for a GS project is described 

in Chapter 5. 

3.1.1 Atmospheric Monitoring Methods 


Developments
 

The goal of geologic carbon sequestration is to 

identify CO2 leakage (should it occur) long before 

it reaches the surface. Geologically sequestered 

CO2 will encounter multiple barriers (seals) with 

respect to its flow path. CO2 leakage from a storage 

reservoir may create significant CO2 fluxes from 
 

 

 

 

 

 

 

 

 

	 	 		

	 	 		 	 	 	 	

	 	 		

	 	 		 	 	 	

	 	 	 	 	 	

	 	 	 	 	

3-2 3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 

the surface that may be difficult to distinguish 

from background CO2 fluxes. The magnitude 

of CO2 seepage fluxes will depend on a variety 

of factors, such as the mechanism of emission 

(e.g., focused CO2 flow along a near-surface fault 

or more diffuse emission through sediments) 

wind, and density-driven atmospheric dispersion. 

Anomalous surface CO2 fluxes may be detected 

using several well-tested and readily available 

techniques (LBNL, 2004).

Sensors for detecting and monitoring CO2

 in the 

air are a widely deployed technology (greenhouses, 

combustion emissions measurement, and 

breweries), but are mostly used for point sources 

of CO2

 and operate as infrared gas analyzers 

(IRGA). When monitoring a large area (several 

km2 in area), one solution is to employ an open-path 

device that uses a laser that shines a beam (with a 

wavelength that CO2 absorbs) over many meters. 

The attenuated beam reflects from a mirror and 

returns to the instrument for determination of the 

CO2 concentration. 

Current commercial instruments capable of this 

cost tens of thousands of dollars. Over the past 

four years, the California Institute of Technology 

has been developing an inexpensive (instrument 

cost of no more than a few hundred dollars), openpath laser instrument to measure CO2 concentration 

over the range of interest (300 to 500 parts per 

million by volume [ppmv]). This alternative 

differs from commercially available instruments 

because it detects exclusively CO2 and not other 

gases by implementing inexpensive, off-the-shelf 

components. The instrument is currently being 

tested and is estimated to have an operating range 

of 2.5 kilometers (five kilometers round trip). 

Eddy covariance (EC), or eddy correlation, is a 

technique whereby high frequency measurements of 

atmospheric CO2

 concentration at a certain height 

above the ground are made by an IRGA, along with 

measurements of micrometeorological variables 

such as wind velocity, relative humidity, and 

temperature. Integration of these measurements 

allows derivation of the net CO2

 flux over the 

upwind footprint, typically m2 to km2 in area, 

depending on tower height. The primary limitation 

of the EC method is that it assumes a horizontal 

and homogeneous surface, which is rarely found in 

natural systems. Also, the EC measurement should 

be made under statistically steady meteorological 

conditions; morning and evening periods, as well 

as times of changing weather conditions should be 

avoided (LBNL, 2004). The GEO-SEQ project has

investigated this technique as part of its work on 

tracers. 

3.1.2 Near-Surface Monitoring Methods 

Developments 

In addition to atmospheric gases, subsurface gases 

may need to be monitored to consider microbial 

signal, as well as barometric pumping and soil 

moisture changes. Monitoring for CO2

 migration 

from the storage reservoir should focus on the 

shallow subsurface gas geochemistry. Several 

methods are available to measure surface CO2 flux 

and subsurface CO2 concentration and to determine 

the origin of CO2 (LBNL, 2004).

Near-Surface Gas Monitoring – The accumulation 

chamber (AC) method measures soil CO2

 flux at 

discrete locations over an area of several square 

centimeters. In this technique, an AC with an 

open bottom is placed either directly on the soil 

surface or on a collar installed on the ground 

surface, and the contained air is circulated through 

the AC and an IRGA. The rate of change of CO2 

concentration in the chamber is used to derive the 

flux of CO2

 across the ground surface at the point 

of measurement (LBNL, 2004). The NETL Office

of Research and Development (ORD) GEO-SEQ

project has investigated this technique as part of its 

work on tracers and it has been used for CO2 flux 

measurements at the Frio Brine Pilot.

Two new monitoring systems developed by Los 

Alamos National Laboratory (LANL) that can 

detect CO2

 seepage at the soil surface have been 

engineered, tested in the laboratory, and are now 

being fitted for field application. The specific tools 

that have been created to detect CO2 seepage are 

oxygen (O2)/CO2 measurement systems and radon 

(

222Rn) detectors that are able to continuously 

measure small amounts of 222Rn (used as a 

surrogate for adjective flow) and portable stable 

isotope detectors of CO2

 that can be used for in 

situ analyses (high temporal resolution at a single 

point location) and remote analyses (large spatial 

coverage over a field). 
	 	 	 	 	 	 	 	

 

 

 

 

 

 

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	

		 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 		 	 	

	 	 	 	 	 	

3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 3-3 

Near-Surface Geochemistry – Near-surface 

geochemistry methods can be used to detect shortterm rapid loss or long-term intermittent leakage 

of CO2 from GS formations. These techniques 

are routinely employed in the environmental 

consulting industry and include monitoring soil gas 

and shallow groundwater. In general, both consist 

of purging the monitoring point and collecting a 

sample, followed by analysis and interpretation. 

Soil gas can be collected with sorbents, sample 

tubes, or Tedlar bags, depending on the compounds 

expected and the detection level. Groundwater 

samples are collected in laboratory glassware. 

Soil gas and groundwater monitoring for various 

tracers has been used in several Core R&D

projects. Natural tracers (isotopes of carbon [C], O, 

hydrogen [H], and noble gases associated with the 

injected CO2

) and introduced tracers (noble gases, 

sulfur hexafluoride [SF6], and perfluorocarbons 

[PFC]) may provide insight about the underground 

movement of CO2 and reactions between CO2 and 

the geologic formation. Perfluorocarbon tracers 

(PFT) added to the injected CO2 can be detected 

in soil gas at parts-per-quadrillion levels. Natural 

tracers (Rn and light HCs) can also be used in 

monitoring CO2 in soil gas. 

Sampling and analysis of local well water and 

surface soil gas (Strutt et al., 2005) were performed 

at the Weyburn field. The primary objectives of 

the soil gas analyses were to measure the natural 

background concentrations of CO2 and to ascertain 

whether CO2

 or associated reservoir tracer gases 

were escaping to the near surface. Samples were 

collected three times over the course of two years on 

a regular spatial grid; additional samples that could 

represent possible vertical migration pathways were 

also collected at other sites in the surrounding area. 

Near-surface monitoring at the Frio Brine Pilot

includes soil gas CO2

 flux and concentration 

measurements, aquifer chemistry monitoring, and 

tracer detection of PFC with sorbents in the soil and 

aquifer. Pre-operation baseline surveys for CO2 

flux and concentration-depth profiles over a wide 

area and near existing wells were done in 2004. 

The near-surface research team includes NETL, 

the Bureau of Economic Geology (BEG) at the

Jackson School of Geosciences, Colorado School of 

Mines, and Lawrence Berkeley National Laboratory

(LBNL). The suite of tracers injected with the CO2 

includes PFCs, the noble gases krypton (Kr), neon 

(Ne), and xenon (Xe), and SF6

 (Hovorka et al., 

2005; NETL Website, 2008). 

The West Pearl Queen reservoir project also used

soil gas surveys to detect PFC tracers that were 

injected into the reservoir with the CO2. Soil gas 

sampling was conducted before and after the CO2 

injection by using capillary tubes and adsorbent 

packets for the tracers. Brookhaven National

Laboratory (BNL) supplied the tracers and

performed the tracer concentration analysis (Wells 

et al., 2007). 

Near-Surface Geophysics – The use of 

magnetometers is another possible near-surface 

geophysical technique. Magnetometers measure 

the strength and/or direction of the magnetic field 

in the vicinity of the instrument. They are typically 

used in geophysical surveys to find iron deposits 

because they can measure magnetic field variations 

caused by the deposits. In an effort to develop 

comprehensive monitoring techniques to verify 

the integrity of CO2 reservoirs, NETL and their 

partners (listed in Appendix II) have used airborne 

and ground-based magnetometry in conjunction 

with CH4 detection to locate abandoned wells that 

can be a source of leakage from a potential CO2 

storage reservoir (depleted oil or gas field). 

Magnetotelluric surveys (soundings) are a naturalsource electromagnetic (EM) geophysical method 

that utilizes variations in the Earth’s magnetic field 

to image subsurface structures. A magnetotelluric 

sounding was attempted at Weyburn but has not 

produced results. Consequently, a final assessment 

of its utility is not available (Monea et al., 2008). 

Electrical resistance tomography (ERT) is a 

technique of imaging subsurface electrical 

conductivity. When deployed in time-lapse mode, 

it is capable of detecting conductivity changes 

caused by the injection of CO2. The method utilizes 

borehole casings as electrodes for both stimulating 

electrical current in the ground and measuring 

the electrical potentials that are induced. ERT 

may be tested in Weyburn Phase II using a single 

borehole configuration as an economical monitoring 

alternative for situations that require less detail 

(Monea et al., 2008). 
	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	

	 	 	 	 	 	 	 	

3-4 3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 

High precision gravity (microgravity) surveys are a 

near-surface geophysical technique used to detect 

changes in subsurface density. The densities of 

CO2, typical reservoir fluids, and their mixtures are 

known or can be obtained by sampling. For most 

of the depth interval for sequestration, CO2

 is less 

dense and more compressible than brine or oil, so 

gravity (and seismic) methods are a candidate for 

brine or oil bearing formations. The University of 

California, San Diego, and Statoil have performed 

two high-precision gravity surveys on the sea floor 

at the Sleipner gas field off the coast of Norway (an 

international project covered in section 3.3). The 

first survey was used to record the baseline gravity, 

and the second (three years later) was to measure 

the changes due to continued CO2

 injection. 

Microgravity surveys were successfully conducted 

in 2002 and 2005. 

3.1.3 Subsurface Monitoring Methods 

Developments 

Simulations – One of the most important purposes 

of monitoring is to confirm that the project is 

performing as expected based on predictive 

models or simulations. This is particularly 

valuable in the early stages of a project when there 

is the opportunity to alter the project if it is not 

performing adequately. Monitoring data collected 

early in the project are often used to refine and 

calibrate the predictive model. The refined model 

then forms the basis for predicting longer-term 

performance. 

Comparing model predictions with monitoring data 

is the key to model calibration and performance 

confirmation. While simple in principle, unless the 

linkage between the model results and monitoring 

data is considered during the design of the 

monitoring program, the data needed for model 

calibration and performance confirmation may 

not be available. Issues, such as which parameters 

should be monitored, timing of measurements, 

spatial scale and resolution of measurements, 

and location of monitoring points, all need to be 

considered (Benson, 2002).

The models can be used to predict several 

reservoir attributes, including fluid pressure, 

reservoir production and injection rates, numerical 

reservoir flow simulations, and geochemical 

simulations. The information used for calibration 

and performance confirmation include, but are 

not limited to, downhole pressure, actual injection 

and production rates, 3-D seismic data, tracer data 

(reservoir and near-surface), data from geophysical 

logs, geochemical data from cores, and reservoir 

fluid test data. 

EnCana Corporation, Natural Resources of Canada, 

and their partners (see Appendix III) at the 

Weyburn Field have matched reservoir modeling 

against production and injection statistics and 

performed repeated and frequent reservoir fluid 

sampling to understand geochemical mechanisms 

occurring in the reservoir during the four years of 

the initial phase of the project (2000 to 2004). 

At the Frio Brine Pilot, two groups of modelers,

LBNL, using TOUGH2 (non-isothermal multiphase

flow model), and the University of Texas Petroleum 

Engineering Department, using Craig-GeffenMorse (CGM) water flooding model, input 

geologic and hydrological information along with 

assumptions concerning CO2

/brine multiphase 

behavior to predict the evolving behavior of the 

injected CO2 through time. Geochemical modeling 

by Lawrence Livermore National Laboratory 

(LLNL) predicted changes in brine composition 

over time (Hovorka et al., 2005). 

At the West Pearl Queen reservoir, two types

of numerical simulations (one reservoir and 

two geochemical) were supervised by LANL. 

Reservoir flow simulations were run using 

Eclipse (Schlumberger’s oil reservoir simulator) 

to characterize the reservoir response to varying 

injection rates. Two types of numerical models 

were used to characterize the geochemical 

interactions. The first model, REACT (chemical 

kinetics simulator), was used to predict the most 

stable configuration of the system after equilibrium 

has been achieved along a reaction path with the 

steady addition of CO2. The second numerical 

model, flow and transport simulator (FLOTRAN), 

was used to explore both short- (months) and longterm (more than 1,000 years) geochemical behavior 

(Pawar et al., 2006). 

Advanced Resources International (ARI) is 

evaluating the effect of slow or rapid CO2

 leakage 

on the environment during initial operations and 

the subsequent storage period. The study will 
	 	 	 	 		 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 3-5 

include a comprehensive and multi-disciplinary 

assessment of the geologic, engineering, and safety 

aspects of natural analogs. Five large, natural 

CO2 fields, which provide a total of 1.5 billion ft3/ 

day of CO2 for EOR projects in the United States, 

have been selected for evaluation. Based on the

results of geomechanical modeling, an evaluation 

of environmental and safety related factors will be 

completed (Stevens et al., 2001). 

Geochemical – Geochemical surveys that monitor 

the reservoir characteristics have routinely been 

used in the oil and gas industry and have been 

successfully adopted for use in monitoring carbon 

sequestration. Initially, reservoir samples (solids, 

liquids, and gases) are collected to establish 

a baseline prior to CO2

 injection; tests can be 

repeated later to monitor CO2 migration (using 

tracers), or to assess geochemical changes, as CO2 

saturated brine reacts with the reservoir formation. 

Production fluid sampling and geochemical 

analyses were conducted at Weyburn at regular 

intervals of three to four months over a three year 

period, with the primary objective of tracing the 

distribution of CO2

 over time within the reservoir. 

The fluids were analyzed for a broad spectrum of 

chemical and isotopic parameters, including pH, 

total alkalinity, calcium (Ca), magnesium (Mg), 

total dissolved solids (TDS), chlorine (Cl), sulfate 

(SO4), and 
13C{HCO3}. The chemical analyses 

allowed the short-term chemical interaction of the 

CO2 with the reservoir fluids and rock matrix to be 

monitored. The distinct isotopic signature of the 

injected CO2

 also allowed its migration through the 

reservoir to be monitored (Monea et al., 2008). 

Geochemical analysis of the reservoir sandstone 

by LANL at the West Pearl Queen Field have led

to better understanding of CO2 reaction products 

in the sandstone reservoir. Understanding the 

kinetics of reaction with certain mineral formations 

(Dawsonite) is critical for sequestration in 

sandstone reservoirs (Pawar et al., 2006). 

An innovative geochemical sampling tool, 

developed and operated by LBNL to support

in-zone fluid chemistry sampling, is the U-tube 

(Appendix III). This technique was used with 

great success by LBNL at the Frio Brine Pilot in

2004 (Hovorka et al., 2005) and was redesigned 

for multi-level geochemical sampling at the Otway 

Basin Project in southern Australia (considered an

international project, see Section 3.3). 

Seismic – At the Weyburn Field, multi-component 

3-D surface seismic time-lapse surveys were 

conducted at intervals of approximately 12 

months, starting prior to the commencement of 

CO2

 injection in 2000, and repeated in 2001 and 

2002. The resultant time-lapse images (primarily 

seismic amplitude changes) acquired at Weyburn 

clearly map the spread of CO2

 over time within the 

reservoir, fulfilling a key objective set at the outset 

of the project. However, a detailed, quantitative 

estimate of CO2 volumes from the seismic surveys 

remains elusive due to the multi-phase composition 

(brine, oil, and CO2

) and pressure-dependent 

behavior of the reservoir fluids (Monea et al., 2008). 

In 2004, Sandia National Laboratory (SNL) and 

LANL conducted an extensive 3-D seismic survey 

prior to CO2 injection in the West Pearl Queen

reservoir to provide the best possible baseline 

subsurface image of the reservoir. After CO2

 was 

injected and allowed to “soak” into the reservoir 

for six months, a second 3-D seismic survey was 

conducted to determine the fate of the CO2

 plume 

and to provide data to calibrate and modify the 

simulation models (Pawar et al., 2006). 

Microseismic (passive) seismic monitoring was 

conducted at Weyburn to monitor the dynamic 

response of the reservoir rock matrix to CO2 

injection (i.e., stress release due to injectioninduced deformation) and assess the level of 

induced seismicity in regard to safety of existing 

surface infrastructure and as an alternative means 

of mapping the spread of CO2

 within the reservoir. 

An array of eight, three-component geophones was 

permanently installed just above the oil reservoir, 

which is located at approximately 1,450-meter 

depth. Microseismic (passive) seismic monitoring 

has been conducted semi-continuously since mid2003. During this time, microseismicity has been 

limited to a few small microseisms on average per 

month (Monea et al., 2008). 

In the West Pearl Queen reservoir, SNL and

LANL deployed a microseismic (passive) seismic 

monitoring system during injection in late 2003 

and early 2004. A receiver array was deployed 
 

 

 

 

 

	 	 	 	 	 	 	 	 	 	 	

 

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

 

	 	 	 	 		 	 	 	

	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 		 	

	 	 	 	 	

	 	 	 	 	 	 	

3-6 3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 

in a nearby well and the microseisms generated 

during injection were recorded. Analysis of the 

data did not show any significant microseismic 

events, suggesting that the injection rate was not 

high enough to cause any significant fracturing 

(Pawar et al., 2006). 

VSP and crosswell tomography were conducted at 

the Weyburn Field with mixed results. Although 

VSP provided higher resolution imaging of the 

reservoir zone than the surface time-lapse seismic 

images, it failed in the initial attempt to provide 

robust images of the distribution of injected 

CO2. At least part of this failure was due to nonrepeatability of the data. A time-lapse horizontal 

crosswell tomographic survey was planned at 

Weyburn. The baseline survey, acquired prior to 

the start of CO2

 injection, provided high resolution 

tomographic images of the reservoir zone of 

interest, but a follow-up survey was not successfully 

completed (Monea et al., 2008). 

VSP was used at the Frio Brine Pilot before and after

CO2 injection, and analysis showed that the tool was 

successful in detecting CO2 (Hovorka et al., 2005). 

Injection Parameters – Other measurements used 

in the subsurface include injection volumes, rates, 

and pressures. These measurements have been 

extensively used in the oil and gas industry and 

easily transfer to monitoring CO2

 injection. All 

injection wells should be equipped with meters and 

pressure sensors to accurately measure injection 

and production rates (if applicable to the project), 

surface casing pressure, injection pressure, and 

annulus pressure to verify that no casing, tubing, or 

packer leaks exist. Reservoir pressure data may be 

accomplished either with downhole pressure sensors 

or by inverting surface pressure and injection data 

given knowledge of the injection profile. The 

Weyburn field, Frio Brine Pilot, and the West Pearl

Queen reservoir all utilized these pressure sensors

and techniques. 

Cement Reactions – Cement reactions to CO2

 are 

also part of Core R&D. NETL, Carnegie Mellon

University (CMU), and RJ Lee Group, Inc., are 

conducting laboratory tests to determine any adverse 

reactions. That knowledge is used in conjunction 

with other wellbore information to help determine 

the integrity of the well (NETL Website, 2008). 

3.1.4 Enhanced Coalbed Methane Methods 

An attractive option for disposal of CO2

 is 

sequestration in deep, unmineable coal seams. Not 

only do these formations have high potential for 

adsorbing CO2

 on coal surfaces, but the injected 

CO2 can displace adsorbed CH4, thus producing 

a valuable by-product and decreasing the overall 

cost of CO2

 sequestration. Coal can store several 

times more CO2

 than the equivalent volume of 

a conventional gas reservoir, because it has a 

large internal surface area. To date, only a few 

experimental ECBM tests involving CO2

 injection 

have been conducted throughout the world. 

3.1.4.1 Near-Surface Monitoring Methods 

Geophysics – An innovative geophysical 

approach, developed by BP North America,

Sproule Associates, Inc., the University of 

California, Santa Cruz, and LBNL, is being

used to assess the ability of non-seismic 

techniques to adequately monitor gas movement 

in coalbeds under CO2

 flood at considerable 

cost savings over more conventional seismic 

techniques. An aerial remote-sensing approach 

is using cutting-edge thermal hyperspectral 

imagery to test the feasibility of monitoring 

large surface areas for CO2 and CH4 seeps 

(NETL Website, 2008). If successful, this 

approach could eliminate the need for an 

extensive ground-based monitoring system and 

associated operational costs. In development 

for three years, this technique was used in a 

CBM-CO2

 storage pilot demonstration at the 

Deerlick Creek Field, Black Warrior Basin in

Alabama, and in a ground-surface controlled 

leak experiment that released CO2

 and CH4, 

conducted at the Naval Petroleum Reserve 

Site #3 in Wyoming in 2006 (NETL Website, 

2008). 

3.1.4.2 Subsurface Monitoring Methods 

Simulations – Simulation techniques for 

ECBM have been under development for

the past three years by BP North America,

Sproule Associates, Inc., the University of 

California, Santa Cruz, and LBNL. The

program addresses optimization of ECBM

recovery using CO2

, in addition to monitoring, 

verification, and risk assessment of CO2 GS 

in coalbeds. A numerical modeling study 

is using a state-of-the-art CBM simulator to
	 		

	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

		 	 	 	

	 	 	 	 	 	 	 	 	 	

3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 3-7 

define the physical and operational boundaries 

and tradeoffs for safe and effective CO2 

storage accompanying CO2-ECBM recovery.

Geologic and reservoir engineering data from 

a CO2-CBM storage pilot demonstration at the

Deerlick Creek Field, Black Warrior Basin,

in Alabama were acquired, evaluated, and 

integrated into the reservoir simulation (NETL 

Website, 2008). 

CONSOL and NETL onsite researchers, in 

collaboration with the Zero Emission Research 

and Technology (ZERT) team and West 

Virginia University, conducted the essential 

computational modeling and monitoring for 

pretest injection simulations. The simulations 

will enable researchers to determine reservoir 

properties, CO2 injection and CBM production

rates, and structural responses of the reservoir. 

Simulations also dictate what monitoring 

networks are needed to predict both the 

migration of CO2 within the coal seam and the 

recovery of CH4 from the coal seam (NETL 

Website, 2008). 

3.2 Core R&D Test Locations 

The majority of field projects supported by DOE are 

being implemented by the RCSPs. Yet, since 1999 the 

DOE’s Core R&D Program directly supports a limited

number of GS field tests throughout North America 

in order to contribute towards gaining the knowledge 

necessary to one day employ GS of CO2 commercially 

across various geologic and regional settings. The 

program’s core R&D agenda focuses on increased

understanding of CO2 GS, MVA technology and cost, 

and regulations through field testing of GS technologies. 

A major portion of DOE’s Core R&D is aimed at

providing an accurate accounting of stored CO2

 and 

a high level of confidence that the CO2 will remain 

permanently sequestered. MVA research is being 

developed at these select Core R&D supported field

tests, including the Frio Brine Pilot, West Pearl Queens

Field Test, and the Weyburn Field test. 

Frio Brine Pilot, Texas – The Frio Brine Pilot in Texas

is a project testing MVA techniques (Hovorka et al., 

2005). This is the first field test in the United States to 

investigate the ability of brine formations to store CO2

. 

Phase I of the project involved the injection of 1,600 

tons of CO2

 into a mile-deep well drilled into the high 

porosity Frio sandstone formation. CO2 was injected 

on October 4, 2004, into a brine/rock system contained 

within a fault-bounded compartment with a top seal of 

200 feet of Anahuac shale. The site is representative of 

a large volume of the subsurface from coastal Alabama 

to Mexico and provides useful experience in the 

planning of CO2

 storage in high-permeability sediments 

throughout the world. 

The project is being extensively monitored to observe 

the movement of the CO2

. Before injection, several

monitoring techniques were executed, including 

baseline aqueous geochemistry, wireline logging, 

crosswell seismic, crosswell EM imaging, and vertical 

seismic profiling (VSP), along with hydrologic testing 

and surface water and gas monitoring. Monitoring was 

periodically repeated during injection and is continuing. 

Data gathered during this test will enable researchers to 

enhance conceptualization and calibrate models to plan, 

develop, and effectively monitor larger-scale, longertimeframe CO2

 injections and devise risk management 

strategies for CO2

 storage in geologic formations of this 

type (Monea et al., 2008). 

West Pearl Queen Field, New Mexico – This project 

represents a subset of saline reservoirs and depleted oil 

reservoirs that present both benefits and challenges in 

the application of MVA methodologies. The benefits 

include a comparatively extensive knowledge base 

of site-specific reservoir properties and subsurface 

gas/fluid rock processes developed during petroleum 

production operations, while the challenges include 

monitoring the impact of long-term CO2

 storage on the 

three-phase system (oil, brine, and gas). 

SNL, LANL, and NETL have partnered with an 

independent producer, Strata Production Company, 

to conduct the first DOE field demonstration of CO2 

storage in a depleted oil reservoir, the West Pearl Queen

Field (Pawar et al., 2006). About 2,100 tons of CO2 was 

injected into the field during 2002 and 2003. Shutting 

the injection well for six months allowed the injected 

CO2

 to interact with the reservoir. The injection well 

was then vented to release the injected CO2

. Data 

acquisition included geophysical surveys, including 

3-D surface seismic surveys before and after injection; 

microseismic (passive) seismic surveys during injection; 

and changes in reservoir rock properties due to CO2 

exposure, determined through laboratory examination 

of samples, including x-ray diffraction and scanning 

electron microscopy. Results of the planned integration 

of field and laboratory experimental results, numerical 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	

3-8 3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 

modeling, and geophysical monitoring will be beneficial 

in planning and implementing more complex field tests, 

as well as in identifying scientific and technological gaps 

relative to the implementation of long-term CO2 storage 

in depleted oil and gas reservoirs (Monea et al., 2008). 

Weyburn Field, Regina, Saskatchewan – In July 2000, 

a major research project to study the GS of CO2 was 

launched by the Petroleum Technology Research 

Centre (PTRC), located in Regina, Saskatchewan, in 

close collaboration with EnCana Resources of Calgary, 

Alberta. This CO2 monitoring and storage project was 

a field demonstration of CO2 storage in the subsurface, 

made possible by adding a research component to 

EnCana’s CO2 EOR project that has been underway 

since 2000 at its Weyburn Unit. Located in the southeast 

corner of Saskatchewan in Western Canada, the Weyburn 

Unit is a 180 km2

 (70 mi2) oil field discovered in 1954; 

production is 25 to 34 degree API medium gravity 

sour crude from the Midale beds of the Mississippian 

Charles Formation. Water flooding initiated in 1964, and 

significant field development, including the extensive use 

of horizontal wells, began in 1991. 

In September 2000, EnCana initiated the first phase 

(Phase 1A) of a CO2

 EOR scheme in 18 inverted ninespot patterns. The flood is to be expanded in phases 

over the next 15 years to a total of 75 patterns. The 

CO2

 is approximately 95 percent pure, and the initial 

injection rate is 5,000 tons/day (95 million standard 

cubic feet per day [scfd]). Approximately 30 million 

tonnes of CO2 is expected to be injected into the 

reservoir over the project’s life. The CO2 is a purchased 

by-product from the Dakota Gasification Company’s 

synthetic fuels plant in Beulah, North Dakota, and

is transported through a 320-kilometer pipeline to 

Weyburn. 

A broad, but not exhaustive, spectrum of monitoring 

techniques has been applied at Weyburn, including 

various seismic methods (time-lapse 3-D multicomponent surface seismic, multi-component vertical 

seismic profiling, and microseismic (passive) seismic 

monitoring), magnetotellurics, production fluid 

sampling, geochemical analysis, tracer studies, and soil 

gas sampling and analysis (Monea et al., 2008). 

Other Field Research Teams – ARI is evaluating the 

effect of slow or rapid CO2

 leakage on the environment 

during initial operations or the subsequent storage 

period. The study will include a comprehensive 

and multi-disciplinary assessment of the geologic, 

engineering, and safety aspects of natural analogs. 

Five large natural CO2 fields, which provide a total 

of 1.5 billion ft3/day of CO2 for EOR projects in the 

United States, have been selected for evaluation. 

Based on the results of a geochemical analysis of CO2 

impacts and geomechanical modeling, an evaluation 

of environmental and safety related factors will be 

completed. 

Battelle Memorial Institute is completed a DOE

sponsored project that designed an experimental CO2 

injection well and prepare it for permitting. Tasks 

involved include subsurface geologic assessment 

in the vicinity of the experimental site, seismic 

characterization of the site, borehole drilling to 

characterize the reservoir and cap rock formations, 

injection and monitoring system design, and risk 

assessment. The well site is located at a large coal 

fired power plant in west-central West Virginia. The 

site has the advantage of providing access to both 

saline formations and deep coalbeds. Another benefit 

of the geology in the site vicinity is the formation 

depth of about 9,000 feet, which provides significant 

cap rock containment potential and separation from 

freshwater. The project involved site assessment to 

develop the baseline information necessary to make 

decisions about a potential CO2

 geologic disposal field 

test and verification experiment at the site. MVA efforts 

included; (1) a completed characterization of subsurface 

formations using 2-D seismic and evaluated the possible 

use of seismic technologies for monitoring and (2) 

completed an approximately 9,200 foot well that was 

designed from the outset to be capable of retrofit to an 

injection well. 

LBNL, LLNL, Oak Ridge National Laboratories

(ORNL), and their partners are developing innovative 

monitoring technologies to track migration of CO2

. The 

project, called GEO-SEQ, will develop and use seismic

techniques, electrical imaging, and isotope tracers for 

optimizing value added sequestration technologies for 

brine, oil and gas, and CBM formations.

ZERT group, in conjunction with Montana State 

University is conducting studies at a newly-developed 

controlled CO2 release facility established on the 

campus of Montana State University in Bozeman,

Montana. The field facility was built for the intended 
	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 		 	

	 	 	 	 	 	 	 	

	 	 	 	 	 		

	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 3-9 

purpose of evaluating CO2 monitoring instrumentation 

and techniques in order to detect the controlled CO2 

release. The ZERT site uses a packer system capable 

of injecting CO2 into several isolated and independent 

zones in the shallow subsurface. CO2 flow into each 

zone can be controlled independently. In August 2007, 

a controlled release at a uniform flow rate was delivered 

to the six zones resulting over an eight-day period in 

which a total release of 0.3 tons CO2

 day. ZERT has 

been developing the use of laser-based instruments to 

detect CO2 both above ground and in the subsurface. 

Both the above ground and subsurface instruments

were capable of detecting CO2

 concentrations above 

background CO2 levels, demonstrating the instrument’s 

capability for carbon sequestration site monitoring 

(Humphries et al., 2008 & Lewicki, J. et al., 2007b).

3.3 International Projects 

The DOE’s Carbon Sequestration Program also 

supports global initiatives, such as the Carbon 

Sequestration Leadership Forum (CSLF), an 

international climate change initiative that focuses on 

the development of technologies to cost-effectively 

capture and sequester CO2, and the International Energy 

Agency (IEA). The Carbon Sequestration Program 

is also providing technical and financial support to 

international projects through the Core R&D MVA

Program. Projects include the Weyburn Project (see 

Section 3.2) in Canada, the Sleipner Project in Norway, 

the In Salah Project in Algeria, the CO2

SINK Project 

in Germany, and the Otway Basin Pilot Project in

Australia. 

Sleipner West (Sleipner) – The Sleipner West natural 

gas field in the North Sea (Norway) produces associated 

CO2

. To avoid paying a tax on CO2 emitted into the 

atmosphere, Statoil, which owns the field, has been 

injecting most of the recovered CO2 into a saline 

aquifer, the Utsira formation, about 1,000 meters 

beneath the sea in Sleipner East. The Utsira formation 

is a permeable sandstone saline formation about 200 to 

250 meters thick overlain by mudstone. The studied 

site, with an average water depth of about 80 meters, 

covers an approximately three by seven kilometer 

area (Chadwick et al., 2008 & NETL, 2006). NETL

has directly supported the application of microgravity 

surveys at the Sleipner project 

In Salah – In Salah Gas is a joint venture between 

BP (33 percent), Sonatrach (35 percent) and Statoil

(32 percent). The project comprises a phased 

development of eight gas fields located in the 

Ahnet-Timimoun Basin in Algerian Central Sahara.

The initial development focuses on the exploitation of 

the gas reserves in the three northern fields. These gas 

fields contain CO2

 concentrations ranging from one to 

nine percent, which is above the export gas specification 

of 0.3 percent and, therefore, requires CO2 removal 

facilities. Instead of venting the CO2 to the atmosphere, 

In Salah Gas re-injects the produced CO2 (up to 

70 million scfd or 1.2 million tonnes per year) into 

the aquifer zone of one of the shallow gas producing 

reservoirs. This project is the world’s first CO2 

storage operation in an actively produced gas reservoir 

(Riddiford et al., 2004). 

CO2SINK Project – CO2SINK is a European 

Commission funded mid-scale (60,000 tonnes over 

two years) demonstration project that aims to increase 

the knowledge-base of CO2 storage in saline formations 

and increase public confidence and awareness of GS. 

The CO2SINK field site is located in Ketzin, Germany, 

approximately 20 km west of Berlin at the site of a

former natural gas storage field. Storage will be at an 

approximate depth of 650 meters in the saline Stuttgart 

Formation. The CO2SINK project deploys numerous 

monitoring and measurement technologies that are 

focused on increasing the understanding of subsurface 

transport of CO2 in saline formations. In particular, the 

application of surface and wellbore seismic, wellbore 

logging, electrical resistivity tomography, geochemical 

sampling, and thermal logging provide a unique 

opportunity to compare and contrast the different 

measurement methods. CO2SINK incorporates a 

robust MVA program in order to assess the efficacy of 

various monitoring approaches, including several that 

have never before been used during a CO2

 sequestration 

demonstration project (Cohen and Plasynski, 2008). 

In 2007, LBNL began working collaboratively with

GeoForschungsZentrum (GFZ), Postdam in order to 

collect, interpret, and disseminate selected ata sets 

relating to two specific tasks: (1) conducting Distributed 

Thermal Perturbation Sensor (DTPS) Measurements, 

and (2) performing laboratory measurements of seismic 

properties as a function of variable CO2

 saturation to 

facilitate accurate interpretation of field seismic data. 

LBNL and GFZ, Postdam are implementing the first-
	 	 	 	 	 	 	 	 	

	 	 	 		 	 	 	 	

 

 

 

	 	 	 	 	 	

	 	 	 	

	 	 	 	 	

	 	 	 	 	

	 	 	 	 	

	 	 	 	

3-10 3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 

ever DTPS study aimed at monitoring the replacement 

of formation brine. The DTPS unit is comprised of 

a fiber-optic temperature sensor and a line source 

heater that runs along the axis of a wellbore. The 

DTPS will monitor the heating and cooling phases of 

a thermal perturbation, in which formation thermal 

properties can be estimated. This technique has been 

successful in the past at monitoring groundwater 

transport, however the application to CO2 sequestration 

is very new. The DTPS data is being compared to 

other monitoring technique data being deployed at 

CO2SINK (high-resolution ERT and wellbore logging). 

The DTPS technique offers the possibility of a simple 

and inexpensive measurement that can be performed 

periodically to assess the distribution of CO2 within a 

storage field, and replace more expensive monitoring 

methods. To date, the DTPS has been deployed in two 

observation wells at the CO2SINK, Ketzin site, in 

which baseline data have been acquired (Cohen and 

Plasynski, 2008). 

Otway Basin Pilot Project – The $36 million Otway 

Basin Pilot Project, located in southern Australia, is one

of 19 sequestration projects endorsed by the CSLF. The 

project is directed by Australia’s Cooperative Research 

Centre for Greenhouse Gas Technologies (CO2CRC). 

Project partners include DOE and a variety of other 

public and private organizations. The Otway Basin has

a large source of natural CO2

 and an abundance of nowdepleted gas fields consisting of geologic formations 

with a history of storage permanence. CO2

 will be 

produced from an existing well then compressed to 

a supercritical state for more efficient movement and 

storage at a final location. This project will allow for 

new insight to be gained about GS in Australia as well 

as improvements to MVA techniques. MVA practices at 

Otway include: (1) identifying an optimal suite of MVA 

technologies to deploy by using forward and inverse 

geophysical simulators, (2) deploy unique capabilities 

such as U-tube sampler (Appendix III), noble gas tracers, 

and seismic techniques, and (3) participate in integrated 

interpretation and simulation of the fate and transport of 

the injected CO2 (Cohen and Plasynski, 2008). 

3.4 Regional Carbon Sequestration Partnerships 

The growing concern over the impact of CO2 on global 

climate change led DOE to form a nationwide network 

of seven RCSPs to help determine the best approaches 

for capturing and permanently storing CO2

. RCSPs are 

tasked with determining the most suitable technologies, 

regulations, and infrastructure for carbon capture, 

transport, and storage in their respective areas of the 

United States and, for some partnerships, portions of 

Canada. The seven partnerships include more than 

350 state agencies, universities, national laboratories, 

private companies, and environmental organizations, 

spanning 42 states and four Canadian provinces. The 

seven RCSPs created under the DOE program are: 

•	 Big Sky Carbon Sequestration Partnership (Big Sky)

•	 Midwest Geological Sequestration Consortium

(MGSC) 

•	 Midwest Regional Carbon Sequestration Partnership

(MRCSP) 

•	 Plains CO2

 Reduction Partnership (PCOR) 

•	 Southeast Regional Carbon Sequestration Partnership

(SECARB)

•	 Southwest Regional Partnership on Carbon

Sequestration (SWP) 

•	 West Coast Regional Carbon Sequestration

Partnership (WESTCARB)

The RCSP initiative is being implemented in three 

phases: Phase I, known as the Characterization Phase 

(2003 to 2005), focused on collecting data on CO2 

sources and sinks and developing the human capital 

to support and enable future carbon sequestration 

field tests (Litynski et al., 2006a); Phase II, known 

as the Validation Phase (2005 to 2009), focuses on 

implementing small-scale field tests using storage 

technologies; and Phase III, known as the Development 

Phase (2008 to 2017) involves developing large-scale 

(1 million tones or more of CO2

) CCS projects, which 

will demonstrate that large volumes of CO2 can be 

safely, permanently, and economically injected into 

geologic formations representative of formations with 

large storage capacity. Currently, the partnerships 

are conducting over 20 small-scale geologic field tests 

and 11 terrestrial field tests (Litynski et al., 2006a,b). 

Each field test incorporates extensive characterization, 

permitting, reservoir modeling, site monitoring, risk 

assessment, public outreach, and technology transfer 

efforts aimed at ensuring safe and permanent carbon 

storage and wide dissemination of the information 

developed (NETL Website, 2008). 
	 	 	 	 	 	 	

 

	 	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 		 	

	 	 	 	 	 	 	

	 	 		 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 		

	 	 	 	 	

 

	 	 	 	 	 	

	 	 	 	 	 	 	 	

 

 

 

 

 

 

 

 

 

 

3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 3-11 

To overcome the challenges associated with MVA, 

RCSPs are developing technologies for cost-effective 

instrumentation and protocols that accurately monitor 

carbon storage, protect human and ecosystem health, 

and improve computer modeling for CO2 plume 

tracking. The monitoring activities that occurred 

during all three phases are described in Section 3.5. 

3.5 Applicable Core R&D, International, and 

Regional Carbon Sequestration Partnership 

Program Monitoring Efforts 

Applicable Core R&D projects, RCSP projects, and

international projects are referenced in the discussion 

of monitoring methods below. 

3.5.1 Simulation 

Following site characterization, working hypotheses 

about important mechanisms that control the 

behavior of injected CO2

 are developed and tested. 

This approach has been studied extensively over 

the last decade from a risk assessment perspective 

(Savage et al., 2004; Lewicki et al., 2006). The 

mechanisms that have controlled past behavior, 

and will control future behavior, need to be 

understood through fluid flow simulation based 

on an understanding of the fluid and chemical 

processes active at the pore level and guided by 

available injection/production and monitoring 

data. Simulations are utilized to predict the 

following: temporal and spatial migration of the 

injected CO2

 plume; the effect of geochemical 

reactions on CO2 trapping and long-term porosity 

and permeability; cap rock and wellbore integrity; 

the impact of thermal/compositional gradients in 

the reservoir; pathways of CO2

 out of the reservoir; 

the importance of secondary barriers; effects 

of unplanned hydraulic fracturing; the extent of 

upward migration of CO2 along the outside of the 

well casing; impacts of cement dissolution; and 

consequences of wellbore failure. 

Simulation is a critical step in the systematic 

development of a monitoring program for a GS 

project, because selection of an appropriate 

measurement method and/or instrument is based 

on whether the method or instrument can provide 

the data necessary to address a particular technical 

question. Effective monitoring can confirm 

that the project is performing as expected from 

predictive models. The linkage between model 

results and monitoring data can be complicated if 

monitoring programs are not designed to address 

which parameters should be monitored, timing of 

measurements, location, spatial scale, and resolution 

of measurements to match with model parameters. 

This is particularly valuable in the early stages of 

a project when the opportunity exists to alter the 

project to ensure long-term storage and improve 

efficiency. Monitoring data collected early in the 

project are often used to refine and calibrate the 

predictive model, improving the basis for predicting 

the longer-term performance of the project. 

Simulations have been used in Core R&D test

projects, including Weyburn, Frio Brine Pilot,

and West Pearl Queen (see Section 3.2), and at

Deerlick Creek and in Marshall County, West 

Virginia, for ECBM (see Section 3.1.4). Several

modeling programs have been used by SECARB,

WESTCARB, and MRCSP. SECARB has used

Comet3, a reservoir simulator, to determine the 

precise location of the observation wells for a CBM

project in the Black Warrior basin. WESTCARB,

working with the Arizona Utilities CO2

 Storage 

Pilot demonstration, will conduct preliminary 

computer simulations (by LBNL) using TOUGH2/

EOS7C in support of the pilot tests. The 

simulations will be used to determine: 

•	 CO2

 quantity and rate of injection. 

•	 The expected pressure and temperature changes

in the reservoir associated with the injection. 

•	 The kind of monitoring and sampling that should

be conducted in the injection well. 

CO2 storage simulations for the Mt. Simon 

formation in west-central Ohio near the TAME 

Ethanol site have been carried out in earlier 

research by members of the MRCSP team. While 

these early models did not simulate the exact 

location as the proposed projects, the results are 

similar to what may be expected for these general 

areas. Key input parameters in the simulations 

were based on best available regional data. The 

parameters are not site specific, but they are fairly 

reasonable for the Mt. Simon formation in the 
 

 

 

 

 

	 	 	 	 	 	 	 	

3-12 3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 

area. These initial model studies indicate that 

injection rates over 1 million tons of CO2 per year 

may be sustained in the Mt. Simon formation at 

the TAME site. 

Several types of reservoir simulators being 

used by the RCSPs’ large-scale field projects 

are important for sequestration of CO2

 in brinesaturated formations or sequestration in formations 

that contain both brine and oil and are briefly 

described in Table 3-1. These include simulators 

for multiphase flow through porous media, 

geomechanical simulators, simulators for “leakage” 

of CO2 from wells or from deep underground 

back to the atmosphere, and simulators for flow 

through fractured geologic formations. Many of the 

simulators are used to predict underground multiphase flow, flows to the surface, geomechanical 

computation, or flow through fractured media. For 

historical reasons, the phrases “reservoir simulator” 

and “reservoir simulation” often refer, respectively, 

only to computer codes and calculations that treat 

the flow of fluids deep underground. 

In general, three key areas of simulation – focusing 

on faults/fractures, subsurface behavior and fate of 

CO2, and geomechanical/mechanical/flow models – 

demonstrate how simulation technology is critical to 

sequestration evaluation and risk assessment. 

3.5.2 Geophysical Approaches 

Single or multi-component 2-D and 3-D surface 

seismic surveys are a widely deployed technology 

in oil and gas exploration that utilizes surface 

sources (e.g., dynamite or vibrating machines) to 

generate downward propagating elastic waves that 

are reflected from subsurface features and return 

to the surface where they are recorded by ground 

motion sensors (geophones). In the case of a 3-D 

survey, a regular 2-D grid of surface sources and 

sensors is deployed. The data recorded in this 

manner is combined to produce a 2-D or 3-D image 

of the subsurface. In a monitoring program, an 

initial seismic survey contributes to geological site 

characterization. In addition, the survey provides 

an initial baseline survey that can be compared 

to subsequent seismic surveys to create a time 

lapse image of CO2

 plume migration and to detect 

significant leakage and migration of CO2

 from 

the storage site. International projects, including 

Sleipner, CO2SINK, and Weyburn, and selected 

RCSP demonstration projects (MRCSP and SWP) 

are using surface seismic surveys (Figures 3-1, 3-2, 

and 3-3). The Weyburn project is one example of 

a Core R&D project that is implementing seismic

profiling. Seismic studies at small CO2 test 

injections (e.g., Frio [crosswell seismic] and Hobbs) 

demonstrate that seismic reflection is sensitive to 

plumes as small as a few thousand tons. 

Table 3-1: Classification of Primary Models Used by RCSPs 

Type of Code Names Main Sequestration Application 

Geomechanical GMI-SFIB, ABCUS Modeling stresses applied to reservoirs during 

and after injection 

Non-isothermal multi-phase flow in 

porous media 

Eclipse, 

GEM-GHG, NUFT 

Model plume dispersion 

Non-isothermal multi-phase 

chemically reactive flow in porous 

media 

PFLOTRAN, STOMP Model plume dispersion and CO2 interaction with 

reservoir fluids 

Non-isothermal multi-phase flow in 

porous media with geomechanical 

coupling 

TOUGH-FLAC Model plume dispersion and impact of stresses 

due to CO2

 interactions 

Non-isothermal multi-phase flow 

in porous media with reactive 

geochemistry 

TOUGHREACT, VIP Reservoir Model plume dispersion and CO2 trapping 

Flow in fractured media NFFLOW-FRACGEN CO2

 flow through fractured networks 
3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 3-13 

Figure 3-1: Amplitude difference map at the Midale Marly horizon for the Weyburn 

Monitor 1 (a) and 2 (b) surveys relative to the baseline survey. The normalized 

amplitudes are RMS values determined using a 5-ms window centered on the horizon. 

Figure 3-2: δ13C {HCO3

} in produced fluids at Weyburn. The well locations (black dots) 

represent the locations of data points that are used to produce the contour plots. Values 

are per mil differences in the ratio of 12C to 13C relative to the PDB standard. 
	 	 	 	 	 	 	 	 	

		 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 		 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 		 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 		

 

 

3-14 3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 

Figure 3-3: Time lapse seismic data collection and 

interpretation from large CO2 injection projects. Three 

successive seismic volumes from the Sleipner project, Norway. 

Upper images are cross-sections through the injection point; 

the lower images show impedance changes at the top of the 

CO2 plume. Injection began in 1996, between the first two 

surveys. From Arts et al. (2004). 

VSP techniques provide information in the 

vicinity of the borehole. VSP is a class of seismic 

measurements that can obtain high resolution 

images near the wellbore (Hardage, 2000). VSP 

acquisition utilizes sensors deployed within a 

borehole and sources located at the surface, whereas 

crosswell tomography uses sources and receivers 

both deployed in boreholes. The advantage of 

VSP, crosswell seismic, and other high resolution 

methods is to obtain more precise estimations of 

the CO2

 induced effects on seismic properties. 

Results from high resolution testing can be used as 

a calibration for lower resolution surface seismic. 

A potential advantage of these borehole methods, 

relative to surface seismic methods, is higher 

vertical resolution imaging. This approach has been 

deployed and tested at the Frio Brine Pilot project

to characterize the reservoir and to monitor CO2 

movement (Hovorka et al., 2005). At Weyburn VSP 

provided higher resolution imaging of the reservoir 

zone than the surface time-lapse seismic images. 

However, due to non-repeatability, the VSP failed 

to provide images of the distribution of injected 

CO2

. Core R&D test projects using geophysical

monitoring methods include Weyburn, Frio Brine

Pilot, and West Pearl Queen (see Section 3.2). VSP

will be used by RCSPs (MRCSP, SECARB, SWP,

and WESTCARB) during their Phase II projects to

evaluate cap rock integrity in the vicinity of the CO2 

injection well. VSP can be implemented in a “walkaway” fashion in order to monitor the footprint of 

the plume as it migrates away from the injection 

well. Walk-away VSP is employed by placing the 

source progressively further and further downgradient from the injection well in order create an 

offset at the surface as the receivers are held in a 

fixed location. This technique yields a mini 2-D 

seismic line that can be of higher resolution than 

surface seismic data and provides more continuous 

coverage than an offset VSP. Furthermore, 

walkaway VSPs with receivers placed above the 

reservoir can be an effective method to quantify 

seismic attributes and calibrate surface seismic 

data. 

Microseismic arrays were tested at Weyburn and 

are currently installed and collecting data at In 

Salah. In general, microseismic tools work best in 

areas with moderate permeability and where rock 

formations contain abundant natural fractures. 

RCSPs employing microseismic technology include 

MRCSP, PCOR, and SECARB. In general, no

significant activity has been observed at Australia’s 

Otway project, as part of DOE funded GEO-SEQ

project, regarding the use of microseismic arrays. 

3.5.3 Crustal Deformation 

Injection of large fluid volumes into the shallow 

crust causes surface deformation that can 

be measured. This information can help to 

identify the location and volume of subsurface 

CO2

, detect anomalous shallow build-ups, and 

provide operational and hazard information. 

Two techniques are commonly used to measure 

deformation: tiltmeters and synthetic aperture 

radar. The CONSOL project in West Virginia 

is an example of one of the Core R&D projects

using tiltmeters. Several RCSPs have proposed 

employing tiltmeter surveys in their monitoring 

programs, including MRCSP (Mt. Simon reservoir, 

TAME site), PCOR, SECARB, and SWP (San Juan

Basin ECBM project – under Core R&D).
	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 		 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	

	 	 	 	 	 	 	 	 	

 

 

 

	 	 	 	 	 		 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

3.0 Developments in Monitoring Techniques from DOE Supported and Leveraged Monitoring Activities 3-15 

3.5.4 Geochemical Methods 

When CO2

 dissolves in water, a number of 

geochemical changes occur. These can be due 

to direct effects (e.g., formation of carbonic acid) 

or indirect effects (e.g., mineral dissolution). In 

addition, chemicals can be injected with CO2 and 

used as tracers in the subsurface. Geochemical 

monitoring and analysis have been used routinely in 

oil field operations. Several important sequestration 

projects have deployed geochemical surveys to 

monitor CO2 location and fate, including Weyburn 

(Hirsch et al., 2004), CO2SINK (Cohen and 

Plasynski, 2008), West Pearl Queen (Wilson et al.,

2007), and the Frio Brine Pilot (Doughty et al.,

2004). In these applications, the surveys considered 

for hazard management and to provide some insight 

into processes at depth. 

Tracers have been used at Weyburn (Core R&D

and international project) and the Frio Brine Pilot,

as well as by several RCSPs (MRCSP, SECARB,

SWP, and WESTCARB). Core R&D test projects

using groundwater monitoring methods include 

Weyburn, the Frio Brine Pilot, and West Pearl

Queen (see Section 3.2).

3.5.5 Surface Monitoring 

Common field applications in environmental 

science include the measurement of CO2 

concentrations in soil air, including the flux from 

soils. Diffuse soil flux measurements are made 

using simple infrared (IR) analyzers. Closed 

chambers can be used to measure the flux into and 

out of the soil, including CO2

. The gases measured 

this way can be collected and analyzed isotopically 

to understand their origin. This method has been 

developed and field tested to monitor CO2 injections 

at the Rangely Field in northwestern Colorado 

(Klusman, 2003). 

As part of the Core R&D Program, the California

Institute of Technology developed an open-path 

device that uses a laser to detect CO2 (Section 3.1.1). 

Researchers at Montana State University have 

developed instruments for carbon sequestration site 

monitoring based on tunable laser spectroscopy. These 

instruments utilize continuous wave temperature 

tunable distributed feedback diode lasers that are 

capable of identifying several CO2 absorption features. 

These instruments are being employed at the ZERT 

field site located in Bozeman, Montana. As mentioned

in Section 3.2, the ZERT project is investigated the 

ability of the lasers to detect CO2

 above background 

levels in the atmosphere and subsurface by conducting 

a controlled release of CO2

 from the ground surface. 

Laser instruments were successful in detecting 

significant variations from background CO2

 levels in 

both the atmosphere and subsurface after CO2 had been 

injected and subsequently released, indicating that the 

instrument is capable for use in carbon sequestration 

site monitoring (Humphries et al., 2008 & Lewicki, J et

al., 2007b). 

Additionally, LANL has developed CO2 monitoring 

instruments that detect O2

/CO2, as well as developing 

radon (222Rn) detectors. These secondary technologies 

are described in Appendix II. RCSPs using nearsurface gas monitoring techniques for Phase II and 

Phase III projects include MRCSP, SECARB, SWP, and

WESTCARB.
3-16 
	 	 	 	 	 	 	 	

 

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

 

	 	 	 	 	 	 	 	

4.0 Review of EPA Permitting Requirements 4-1 

4.0 Review of EPA Permitting 

Requirements 

Existing regulations in the United States relevant to 

GS of CO2

 involve protection of groundwater meeting 

underground sources of drinking water (USDW) 

standards from brine and CO2

 plume infiltration (from 

the CO2

 injection process) under the UIC Program. 

The UIC Program is responsible for regulating the 

construction, operation, permitting, and closure of 

injection wells that place fluids underground for storage 

or disposal (http://www.epa.gov/safewater/uic/index. 

html). Once EPA promulgates final regulations for GS 

wells for states and at the Federal level, proper criteria 

and standards will be in place to ensure a consistent and 

effective permitting system for commercial-scale GS 

projects. 

EPA has proposed regulatory changes to the UIC 

Program and invites the public and stakeholders to 

provide input throughout the rule development process 

(Federal Register, July 25, 2008). The UIC Program 

provides standards, technical assistance, and grants 

to state governments for regulating injection wells 

and protecting drinking water resources. At present, 

EPA defines the five classes of wells (Classes I to V) 

according to the type of fluid they inject and where 

the fluid is injected. EPA is proposing to create a 

new category of injection well under its existing UIC 

Program with new Federal requirements to allow for 

permitting of the injection of CO2 for the purpose of 

GS. The proposal builds on existing UIC regulatory 

components for key areas including siting, construction, 

operation, monitoring and testing, and closure for 

injection wells that address the pathways through which 

USDWs may be endangered. In addition to protecting 

USDWs, the proposed rule provides a regulatory 

framework to promote consistent approaches to 

permitting GS projects across the United States. 

EPA has promulgated regulations for siting, drilling, 

completing, operating, monitoring, and closing each of 

the existing injection well classes. A detailed discussion 

of the five existing UIC well classes is available on 

EPA’s UIC website (http://www.epa.gov/safewater/uic/ 

wells.html). 

Federal and state agencies have permitted the wells for 

the RCSP Program’s Validation Phase field projects 

across various geologic sink formations under the 

UIC Program’s current regulatory framework for the 

five well classes (with a sixth class proposed in July 

2008). The wells are classified under the following five 

categories: 

•	 Class I – Wells injecting hazardous, industrial, and

municipal wastes below USDWs. 

•	 Class II – Wells related to oil and gas production,

mainly injecting brine and other fluids. 

•	 Class III – Wells injecting fluids associated with

solution mining of minerals, such as salt (sodium 

chloride [NaCl]) and sulfur (S). 

•	 Class IV – Wells injecting hazardous or radioactive

wastes into or above USDWs; generally only used for 

bio-remediation. 

•	 Class V – Injection wells not included in Classes I

through IV that are typically used as experimental 

technology wells. 

•	 Class VI – Proposed new class of injection well

specific for GS of CO2 (Section 4.3 and Table 4-2). 

Currently, wells for GS of CO2

 fall under Classes 

I, II, and V. The proposed EPA rulemaking, when 

finalized, would establish a new class of injection 

well – Class VI – for GS projects based on the unique 

challenges of preventing potential endangerment to 

USDWs and leakages from the subsurface from these 

operations (Federal Register, July 25, 2008, p 43502). 

The variations in the current permitting process and 

well classification reflect differences in project type, 

institutional architecture, primacy, and the local 

regulations of individual states or provinces within the 

context of overall Federal oversight. 

EPA has been actively working with DOE’s R&D

Program to evaluate potential impacts on health, 

safety, and the environment through coordinating 

efforts like Program Guidance #83, “Using the Class V 

Experimental Technology Well Classification for Pilot 

GS Projects.” The guidance is intended to assist state 

and EPA regional UIC Programs in processing pilot 

permit applications for projects designed to assess the 

efficacy of CO2

 injection for the purpose of GS (http:// 

www.epa.gov/safewater/uic/wells_sequestration.html). 
	 	 	 	 	 	 	 	

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4-2 4.0 Review of EPA Permitting Requirements 

Of the five well classes, EPA believes that the Class 

V experimental technology well subclass provides the 

best mechanism for authorizing and permitting CCS 

pilot projects. Class V experimental technology wells 

are intended to demonstrate unproven but promising 

technologies. On the other hand, wells that inject CO2 

for the purposes of EOR and enhanced gas recovery 

(EGR) are designated as Class II wells. While there 

are similarities between CO2

 injected for oil and gas 

extraction and for CCS, EPA believes that there are also 

important differences that require the creation of a new 

class of injection well. For example, CO2

 injection for 

CCS will eventually involve much greater volumes that 

will require containment for hundreds of years. 

Additional regulatory guidance by the Interstate Oil 

and Gas Compact Commission’s (IOGCC) Task Force 

on Carbon Capture and GS led to producing a legal 

and regulatory model framework for the GS of CO2 

that addresses the unique requirements of individual 

states and Canadian provinces. The 30 member states 

and four Canadian member provinces have jurisdiction, 

experience, and expertise in the regulation of oil and 

natural gas wells (Class II), particularly in the injection 

of petroleum wastes and CO2 for EOR. In addition, 

natural gas storage statutes provide a starting point for 

operational plans addressing public health and safety 

during injection. The IOGCC model rules are subject to 

revision as they are reviewed by more people and more 

knowledge about geological sequestration is developed. 

Although custody issues for long-term GS are not 

addressed in its report, IOGCC’s work is a first step in 

considering appropriate regulatory requirements. 

The EPA proposed rules use a combination of 

fixed timeframe and a performance standard. EPA 

is tentatively proposing a post-injection site care 

(monitoring) period of 50 years with the UIC Program 

Director having discretion to change that period to 

lengthen or shorten the 50 year period if appropriate. 

The default timeframe could be lengthened if potential 

for endangerment to USDWs still exists after 50 years 

or if modeling and monitoring results demonstrate 

that the plume and pressure front have not stabilized 

in this period. Conversely, the 50-year time period 

could be reduced if data on pressure, fluid movement, 

mineralization, and/or dissolution reactions support a 

determination that movement of the plume and pressure 

front have ceased and the injectate does not pose a risk 

to USDWs. This combination of fixed timeframe and 

performance standard emphasizes the importance of 

developing robust technologies for measurement and 

monitoring of CO2 stored in deep geologic formations. 

4.1 RCSP Project UIC Classification Summary 

One of the goals of the RCSP large-scale field projects 

is to not only develop the necessary technologies, but 

also to contribute to progress in the development of 

permitting requirements. Validation and Development 

Phase projects require permits for well drilling and 

injection that are enforced by Federal (i.e., EPA 

or Bureau of Land Management [BLM]) and state

governments and other organizations, such as the 

Navajo EPA, although the overall permitting process is 

ongoing and in flux. Nevertheless, RCSP field projects 

have initiated the administrative activity necessary to 

develop the framework for validating and potentially 

deploying GS of CO2

 as a GHG mitigation option. 

Federal and state agencies have permitted the wells 

for Validation Phase field projects across various 

geologic sink formations under UIC Classes I, II, and 

V. The variations in the permitting process and well 

classification reflect the differences in project type, target 

formation characteristics, institutional architecture, 

primacy, and the local regulations of individual states or 

provinces within the context of overall Federal oversight. 

Almost 80 percent of the wells for Phase II projects were 

permitted by state agencies under the UIC Program, 

while 20 percent were permitted by Federal agencies. 

Applications for nearly all of the large-scale Development 

phase UIC permits will be as Class V wells. Table 4-1 

presents a breakdown of the RCSPs’ Validation and 

Development Phase UIC permits by sink type. 

Table 4-1: Breakdown of RCSP (Phase II and Phase III) UIC 


Permits by Sink Type (as of April, 2008)
 

Oil & Gas Coal Saline Total 

Class I 1 1 

Class II 11 5 16 

Class V 14 14 

Total 11 5 15 31 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4.0 Review of EPA Permitting Requirements 4-3 

Appendix V provides a detailed list of the target 

formation, sink type, injection volume and depth, UIC 

permit class, and the permitting agency for each RCSP 

project (Phase II and Phase III). Typical UIC permits 

for Classes I and V wells include the Archer Daniels 

Midland Company’s Permit (Illinois Environmental 

Protection Agency, 2008) and the Core Energy, LLC 

Permit (EPA, 2007) respectively. 

4.2 UIC Mandatory Requirements 

The UIC Program, authorized under Part C of the 

SDWA, regulates the injection of fluids (including liquids, 

gases, and semi-solids) into the subsurface in order to 

protect USDWs. The UIC Program’s primary mission 

is to protect USDWs, and no injection operations may 

endanger USDWs or the health of persons. 

The UIC mandatory (primary) regulations and program 

elements reflect the ways in which injection activities 

could potentially endanger USDWs. Each injection 

well class is subject to siting, construction, operating, 

monitoring, and closure requirements that address the 

types of fluids injected and the use of the wells. For 

example, injection wells are sited in geologically suitable 

areas and a study is conducted to determine whether 

any conduits (e.g., abandoned wells) for fluid movement 

to USDWs exist. Injection wells are constructed of 

materials that can withstand exposure to injected fluids; 

operating requirements and testing throughout the 

injection operations help assure that the well remains in 

proper working order and that no unintended movement 

occurs. Finally, injection wells must be closed in a 

manner that prevents the well from inadvertently serving 

as a conduit for future fluid migration. 

Three classes of injection wells covered in Section 4.1 

(Class I, Class II, and Class V) offer potential technical 

analogues for GS. In general, Class I wells are subject 

to more stringent requirements than Class II and Class 

V wells. However, all EPA well classes must meet 

the non-endangerment of USDW standard. Table 4-2 

briefly summarizes the requirements for Class I, Class 

II, and Class V wells. Monitoring requirements for 

each well class typically remain the same across the 

different phases (pre-operation, operation, closure, or 

post-closure) of the project, but vary in monitoring 

frequency, depending on the project phase. 

Although there are no Federal requirements written 

specifically for Class V experimental technology wells, 

the EPA has issued a guidance document in 2007 that 

applies to GS projects that are to be permitted as Class 

V experimental technology wells. It provides suggested 

guidelines for permitting and operating near-term pilot 

GS projects prior to commercial-scale implementation 

of GS. It is designed to provide a timely and consistent 

framework to assist regional and state directors to 

permit pilot CO2 injection wells. The guidance does 

not, however, substitute for the SDWA or EPA’s UIC 

regulations; nor is it a regulation itself. Thus, it cannot 

change or impose legally binding requirements on EPA, 

states, or the regulated community, and may not apply 

to a particular situation based upon the circumstances. 

The suggested guidance makes Class V requirements 

for monitoring nearly as stringent as Class I UIC 

regulations (EPA, 2007). 

Currently, all CO2

 injection in the United States is 

conducted in Class I, Class II, or Class V experimental 

technology wells. CO2 injection into Class II wells is 

limited to EOR/EGR operations; when oil and/or gas 

recovery is complete, this classification would no longer 

apply. To date, all pilot-scale GS operations have been 

permitted as Class V experimental technology wells. 

4.3 EPA’s 2008 Proposal for Developing New 

Requirements for CO2 Injection for GS 

EPA recently announced proposed regulations to 

establish a path for commercial geologic carbon 

sequestration (Federal Register, July 25, 2008, p 53492). 

Once completed and adopted, the regulations will 

ensure there is a consistent and effective permit system 

under the SDWA for commercial-scale GS projects. 

EPA (Federal Register, July 25, 2008, p 53492) has 

proposed regulatory changes to the UIC Program and 

has invited the public and stakeholders to provide input 

via the rule development process. 

The proposed plan is to establish a new class of 

injection well – Class VI – and technical criteria for 

geologic site characterization; Area of Review (AoR) 

and corrective action; well construction and operation; 

mechanical integrity testing (MIT) and monitoring; 

well plugging; post-injection site care; and site closure 

for the purposes of protecting USDWs. The elements of 

this proposal are built upon the existing UIC regulatory 

framework, with modifications based on the unique 

nature of CO2

 injection for GS. 
4-4 4.0 Review of EPA Permitting Requirements 

Table 4-2: Summary of Current Mandatory Technical Requirements for 

Class I, Class II, Class V, and Class VI (Proposed) UIC Injection Wells 

Class I1 and Class V2 Class II Class VI 

Siting Demonstrate the presence 

and adequacy of injection and 

confining zones by presenting 

information on the local 

geologic structure and faults; 

geomechanical information; 

and maps and cross sections of 

the regional geology. 

Demonstrate the presence 

and adequacy of injection 

and confining zones by 

presenting information on 

geologic formations; map of 

the injection well and AoR3; 

and maps, cross sections and 

a list of penetrations into the 

injection zone geomechanical 

information; and maps and 

cross sections of the regional 

geology. 

Extensive site characterization 

needed, including well logs, 

maps, cross-sections, USDW 

locations, determine injection 

zone porosity, identify any 

faults, and assess seismic history 

of the area. 

Fluid Movement No fluid movement to a USDW4 

, 

except for municipal wells, 

injectate is treated. 

No fluid movement to a USDW. No fluid movement to a USDW. 

AoR Define the AoR as a radius of at 

least 1/4 mile or calculate by a 

formula; identify and address 

any improperly completed or 

abandoned wells in the AoR. 

Define the AoR as a radius of at 

least 1/4 mile or calculate by a 

formula; identify and address 

any improperly completed or 

abandoned wells in the AoR. 

Determined by computational 

model and reevaluated during 

project duration. 

Construction Wells must have at least 2 

layers of casing and cement 

in a multilayer design, with 

surface casing cemented to the 

surface, in addition to tubing 

and a packer. Engineering 

designs must be approved 

by regulatory agency. Tests 

performed during drilling to 

ensure no vertical migration of 

fluid. 

Wells must be cased and 

cemented to prevent 

movement of fluids into or 

between USDWs 

Two layers of corrosion-resistant 

casing required and set through 

lowermost USDW. Cement 

compatible with subsurface 

geology. 

Operation Injection pressures may not 

initiate or propagate fractures 

into the confining zone or 

cause fluid movement into 

USDWs. Quarterly reporting 

on injection, injected fluids 

and monitoring of USDWs 

within the AoR. Must report 

changes to facility, progress 

on compliance schedule, lose 

of mechanical integrity, or 

noncompliance with permit 

conditions. Permit valid for 

10 years. 

Injection pressures may not 

initiate or propagate fractures 

into the confining zone or 

cause fluid movement into 

USDWs. Make monthly 

observations of injection 

pressure, flow rate, and 

cumulative volume. 

Injection pressures may not 

initiate or propagate fractures 

into the confining zone or 

cause fluid movement into 

USDWs. Quarterly reporting on 

injection, injected fluids and 

monitoring of USDWs within the 

AoR. Must report changes to 

facility, progress on compliance 

schedule, lose of mechanical 

integrity, or noncompliance 

with permit conditions. Permit 

valid for 10 years. 
4.0 Review of EPA Permitting Requirements 4-5 

Class I1 and Class V2 Class II Class VI 

MIT5 Conduct internal and external 

MITs every five years. 

Conduct internal and external 

MITs every five years. May 

use cement records as an 

alternative. 

Continuous internal integrity 

monitoring and annual external 

integrity testing. 

Monitoring Analyze injectant; continuously 

monitor annular pressure; 

monitor for fluid movement 

into USDWs within AoR; 

conduct ambient groundwater 

monitoring 

Analyze injectant Analyze injectant. Continuous 

temperature and pressure 

monitoring in the target 

formation. Plume tracking 

required. 

Closure Ensure that the well ins in a 

state of static equilibrium, plug 

with cement; tag well, test 

plugs, submit plugging and 

abandonment report 

Ensure that the well ins in a 

state of static equilibrium, plug 

with cement; tag well, test 

plugs, submit plugging and 

abandonment report 

50 day notice and flush well. 

Must be plugged to prevent 

injectent from contaminating 

USDWs. 

Proof of 

Containment 

and Post-Closure 

Care6 

Site dependant – typically 

30 years post-injection care. 

Site dependant – typically 30 

years post-injection care. 

Post-closure site care for 

50 years or until proof of 

non endangerment to USDWs 

demonstrated. 

Financial Trust fund, surety bond, Trust fund, surety bond, Periodically update the cost 

Responsibility financial test, insurance or 

corporateguarantee that meets 

estimate cost of post-closure 

plan. 

financial test, insurance or 

corporateguarantee that meets 

estimate cost of post-closure 

plan. 

estimate for well plugging, 

post injection site care and site 

closure, and remediation to 

account for any amendments 

to the area of review and 

corrective action plan. EPA is 

also proposing that the owner 

or operator submit an adjusted 

cost estimate to the Director if 

the original demonstration is 

no longer adequate to cover 

the cost of the injection well 

plugging, post-injection site 

care, and site closure. 

Source: 40 CFR, Parts 144 and 146. 

Note: This table provides an brief overview of the mandatory requirements for Class I, II, and V wells. Complete information on 

geologic storage of CO2 in wells can be found at the UIC website at http://www.epa.gov/OGWDW/uic/wells_sequestration.html 

1

 Class I wells have additional requirements for hazardous waste wells (Annual MIT Required), which are not covered in this table 

2

 Class V wells may have additional requirements for motor vehicle waste disposal wells, which are not covered in this table. 

3

 “AoR” is the Area of Review surrounding the well. 

4

 USDW is an Underground Source of Drinking Water 

5

 MIT is a Mechanical Integrity Test 

6

 No-migration petition demonstration (fluids remain in injection zone for 10,000 years) required for Class I Hazardous wells. See Section 5.4 for 

discussion. 
4-6 4.0 Review of EPA Permitting Requirements 

EPA-proposed monitoring efforts for the Class VI 

injection well are similar, in many cases, to existing 

UIC regulation. However, several additional monitoring 

requirements have been proposed for Class VI wells 

that exceed existing UIC regulation, including; siting 

requirements, AoR determination, well design and 

construction, MIT, tracking plume location, and postclosure care. Additional siting requirements to the 

existing UIC regulations include providing data on 

target formation porosity, information on the seismic 

history of the site and in-situ fluid pressures, and 

extensive geochemical data on fluids in the injection 

zone, confining zones, overburden layers and USDWs. 

Additional siting requirements can be fulfilled with 

many Primary Technologies, including wireline logs, 

sample cores, downhole pressure monitors, and fluid 

sampling. 

The proposed AoR determination procedure for Class 

VI requires extensive computational models designed 

for the specific site conditions and injection regime 

to assess potential plume migration and pressure 

propagation, as opposed to relying on a one-fourth 

mile fixed radius around the injection well location. 

The models should be based on site characterization 

data collected regarding the injection zone and 

confining system, taking into account any geologic 

heterogeneities, and potential migration through faults, 

fractures, and artificial penetrations. In addition, the 

proposal would require that the owner or operator 

periodically reevaluate the AoR during the injection 

operation as site conditions may change from the 

baseline state and directly impact AoR. 

Well construction procedures for Class VI wells would 

require that surface casing for GS wells be set through 

the base of the lowermost USDW and cemented to the 

surface. The long-string casing would be cemented 

in place along its entire length. GS wells would also 

be constructed with a packer that is set opposite a 

cemented interval. Also, the use of corrosion-resistant 

materials that are compatible with the injectate and 

subsurface fluids is required. MIT of the wells would 

require owners or operators of Class VI GS projects to 

monitor internal mechanical integrity of their injection 

wells by continuously monitoring injection pressure, 

flow rate, and injected volumes, as well as the annular 

pressure and fluid volume to assure that no anomalies 

occur that may indicate an internal leak. Continuous 

internal mechanical integrity monitoring of GS project 

injection wells, instead of periodic testing (which is 

required for most other types of deep injection wells) 

is important because the corrosive nature of GS waste 

streams makes immediate identification of corrosionrelated well integrity loss critical. The proposal would 

also require automatic downhole shut-off mechanisms 

in the event of an mechanical integrity loss. The 

proposal would require owners or operators of CO2 

wells to demonstrate injection well external mechanical 

integrity (accomplished through the use of down-hole 

geophysical logs or surveys designed to detect such 

leaks) at least once annually. This increase in testing 

frequency (from once every five years to once a year) is 

justifiable for the protection of USDWs. 

EPA considers CO2 plume and associated pressure 

front monitoring to be necessary for verification of 

model predictions. The proposal requires owners or 

operators to track the subsurface extent of the CO2 

plume and pressure front using pressure gauges in the 

first formation overlying the confining zone or using 

indirect geophysical techniques or other downhole CO2 

detection tools, monitor for geochemical changes in 

subsurface formations, and if directed, monitor at the 

surface. Current UIC regulations only require certain 

operational monitoring practices (flow rate, injection 

pressure, etc.) (Same operational monitoring required 

for Class VI) and prevention of USDW contamination. 

One of the major differences between current UIC 

monitoring regulations and Class VI proposal is the 

post-closure monitoring requirements. Today’s proposal 

would also require that owners or operators: 1) develop 

a post-injection site care and closure plan, 2) monitor 

the site following cessation of the injection activity, and 

3) plug all monitoring wells in a manner that prevents 

movement of injection or formation fluids that could 

endanger a USDW. Post-closure care includes recording 

certain formation pressures and determining location 

of the plume front. EPA is tentatively proposing a postinjection site care (monitoring) period of 50 years with 

Director’s discretion to change that period to lengthen 

or shorten the 50-year period if appropriate (Federal 

Register, July 25, 2008, p 43540). 
	 	 	 		 	 	 	 	

5.0 Addressing the Objectives and Goals of Monitoring 5-1 

5.0 Addressing the Objectives and 

Goals of Monitoring 

The principal goal of DOE’s Carbon Sequestration 

Program is to gain scientific understanding of carbon 

sequestration options and provide cost-effective, 

environmentally sound monitoring technologies and 

accounting protocols. The goals set for GS are that 

by 2008, MVA protocols are sufficiently accurate so 

that 95 percent of stored CO2

 can be credited as net 

emissions reduction and by 2012, 99 percent can be 

credited. It is believed that the 2008 goal for MVA to 

accurately measure 95 percent of the amount of CO2 

retained in geologic formations has already been met 

or exceeded (NETL, 2007b). A 95 percent credit 

means that at least 95 percent retention is assured and 

implies that leakage rates to the atmosphere and shallow 

subsurface are between 0.01 and 0.001 percent per year 

(90 to 99 percent retention over a 1,000-year period) 

(Hepple and Benson, 2004). The IPCC Special Report

concluded that at least 99 percent retention is likely for 

well selected and managed sites (Metz et al., 2005). 

5.1 Role of Primary Technologies 

The monitoring objectives outlined by the UIC 

regulations in 40 CFR § 146 are aimed at ensuring 

that storage projects are carefully designed and that 

measures are undertaken to mitigate leakage pathways 

so that CO2 remains entirely in the subsurface over 

significant time spans (hundreds to thousands of years). 

The primary technologies listed in Table 5-1 are fully 

capable of meeting and exceeding the UIC monitoring 

requirements of 40 CFR § 146 and achieving the 

MVA goals for GS (Litynski et al., 2008). MVA 

technologies (Table 5-1) are aimed at assessing CO2 

storage efficiency within the target reservoir, protecting 

against environmental health and safety impacts 

associated with injection and storage, and addressing 

possible leakage situations. A wide array of advanced 

monitoring technologies has also been used/evaluated 

by the Weyburn Project, the Frio Project, Sleipner, and 

DOE’s RCSP Program, as discussed at the end of this 

chapter. This additional monitoring was guided by 

the ongoing complexities of injection and storage and 

the results showed that CO2

 remained entirely in the 

subsurface over significant time spans. 

Primary Technologies are considered proven 

technologies capable of satisfying the monitoring 

requirements under UIC regulations for Class I (nonhazardous), Class II, and Class V injection wells and 

that could be used in meeting the 95 percent and 99 

percent demonstrated CO2

 containment goals for 

CCS projects for 2008 and 2012, respectively. These 

technologies are typically well-known and been 

effectively used in applications similar to GS, including 

for oil and natural gas exploration and geological 

subsurface characterization. 

5.2 Role of Secondary MVA Technologies 

Secondary technologies are typically routine, often 

low-cost, technologies that have been applied in 

other applications, such as oil field monitoring or 

environmental remediation. These technologies often 

help in the characterization of a storage formation and 

the overlying strata to support the development of site 

specific reservoir simulations and provide information 

on the design of the GS project. The use of these 

technologies for CO2

 monitoring shows promise, but 

the technologies require additional demonstration 

that they are sufficiently precise and quantitative to 

detect, locate, and quantify emissions from a CCS 

project for an appropriate monitoring program. If a 

secondary MVA technology has too high a detection 

limit, it could compromise the effectiveness of CCS, 

provide misleading inventory of CO2 in storage and 

not provide the needed assurances for protection of 

the environment. The secondary technologies for CO2 

monitoring are shown in Table 5-1 and elaborated upon 

in the appendices. 

5.3 Role of Potential Additional MVA 

Technologies 

Through Federal and private sector funding, promising 

additional technologies are being developed to better 

understand the long-term behavior of CO2 in the 

broad portfolio of potential GS sites (e.g., oil and 

gas reservoirs, deep coal beds, saline aquifers). In 

addition, new technologies can be improved and 

modified for detailed monitoring of CO2 in GS. These 

potential additional technologies may currently be 

cost or time prohibitive and lack required precision. 

Potential additional monitoring techniques may have 

significant advantages over existing MVA technologies 

by improving the assessment and confirmation of the 

migration of CO2 (free and dissolved) in the storage 

formation, long-term storage integrity, volume and rate 

of potential leakage in the overlying and underlying 

formations, and detection of potential leakage pathways 

from the storage formation to the atmosphere. Several 
	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

5-2 5.0 Addressing the Objectives and Goals of Monitoring 

of the Secondary and Potential Additional Technologies 

can be used in non-invasive applications to assess 

plume location and areas of potential leakage over 

larger spatial scales compared to Primary Technologies. 

Techniques like seismic reflection, ground swell, and 

vegetative stress monitoring can provide a strong 

indication of the extent of the CO2 plume and pressure 

front (and any indication of leakage) over a relatively 

large area compared to the Primary Technologies, 

which require investigation through invasive techniques 

(well drilling, sample coring, etc.) and are constrained 

to fixed, spatially–limited locations. The potential 

additional technologies are shown in Table 5-1 and 

elaborated upon in the Appendices II and III. 

It is believed that by 2012 modifications and 

improvements to monitoring protocols through the 

development of secondary and potential additional 

technologies will reduce GS cost and enable 99 

percent of injected CO2

 to be credited as net emissions 

reduction. The use of one or more primary technologies 

can address the retention requirements for each of the 

MVA goals for GS outlined in Section 1.3 (Table 5-1). 

Achieving these MVA technology goals will provide the 

confidence that specified retention rates are achieved 

for injected CO2

 stored underground at a GS project 

(on a mass balance basis). Ultimately, a robust MVA 

program will likely be critical in establishing CCS as a 

viable GHG mitigation strategy. 

5.4 Application of Monitoring Techniques and 

Regulatory Compliance 

While a broad range of safety and environmental issues 

must be addressed to ensure safe and effective storage, 

the majority of the issues hinge on two primary factors: 

•	 The extent, location, and nature of possible CO2 

leakage out of the primary storage horizon and 

potential leakage from the subsurface back into the 

atmosphere. 

•	 Implementation of effective controls on injection

well completion, injection rates, and wellhead and 


formation pressures.
 

To address the first of these issues from a monitoring 

perspective, it is necessary to be able to monitor the 

plume location of a separate CO2

 phase, either as a 

supercritical fluid or gas, in the subsurface. If there 

were evidence that significant leakage had occurred 

from the primary storage structure and CO2

 had 

migrated to the land surface, methods for monitoring 

the concentration and flux of CO2

 at the land surface 

would be highly desirable. 

Meeting the second need, ensuring effective injection 

well control, will require monitoring the condition of 

the injection well, injection rates, wellhead pressures, 

and the formation pressure (Benson and Myer,

2002). A number of specific monitoring objectives, 

recommended to achieve monitoring goals, have been 

identified by Benson et al. (2004), including:

•	 Establishing baseline conditions from which the

impacts of CO2

 storage can be assessed. 

•	 Assessing the integrity of shut-in, plugged, or

abandoned wells. 

•	 Monitoring to ensure injection effectiveness.

•	 Monitoring to detect the location of the injected CO2 

plume. 

•	 Comparing model predictions to monitoring data.

•	 Detect and quantify leakage from the storage

formation to other strata or the surface. 

•	 Assess health, safety, and environmental impacts of

leakage. 

•	 Monitoring to detect micro-seismicity associated with

CO2

 injection. 

•	 Monitoring to aid in the design and evaluation of

remediation efforts, if needed. 

•	 Evaluating interactions with, or impacts on, other

geological resources. 

•	 Reassuring the public, where visibility and

transparency are of prime importance. 
5.0 Addressing the Objectives and Goals of Monitoring 

Table 5-1: List of RCSPs’ Monitoring Tools for Phase II and Phase III Projects 

5-3 

Objectives Primary 

Technologies 

Secondary 

Technologies 

Potential Additional 

Technologies 

Atmospheric 

Monitoring 

Objectives: 

• Ambient CO2 

Concentration 

• CO2

 surface flux 

CO2

 Detectors 

(Ambient CO2

 Concentration) 

Laser systems and LIDAR* 

(Ambient CO2

 Concentration) 

Eddy Covariance (Surface Flux) 

Advanced Leak Detection System 

(Surface Flux) 

Isotopes 

Near-Surface 

Monitoring 

Objectives: 

• Groundwater 

Monitoring 

• Fluid Chemistry 

• Soil gas monitoring 

• Crustal Deformation 

• Leak Detection 

• Vegetative Stress 

Monitoring 

• Vadose Zone 

Characterization 

Geochemical Analysis 

(Groundwater Monitoring) 

(Fluid Chemistry) 

Advanced Water Quality 

Analysis 

• Inorganics & Organics 

• Isotopes 

• Total Organic and Inorganic 

Carbon 

Aerial Photography 

(Vegetative Stress) 

(Crustal Deformation) 

Seismic Surveying 

(Vadose zone characterization) 

(Leak Detection) 

• Shallow 2-D Seismic 

Soil and Vadose Zone Gas 

Monitoring (Gas sampling) 

Flux Accumulation Chamber 

(Surface Flux) 

Tracers (Leak Detection) 

• Noble Gases 

• Mercaptans 

• Stable Isotopes 

• Perfluorocarbons 

Geophysics (Leak Detection) 

(Vadose zone characterization) 

• Conductivity 

• Induced Polarization 

• Self-Potential 

Tiltmeters (Crustal Deformation) 

Remote Sensing (Crustal 

Deformation) 

• Color Infrared Transparency 

Film 

• Hyper-spectral – multispectral 

• Synthetic Aperture Radar & 

InSar 

Subsurface Water Quality Analysis Seismic Surveying (Reservoir Geophysical Techniques 

Monitoring • Injection Fluid Monitoring 

• Formation Fluid Monitoring 

Integrity) 

• Acoustic (2-D and 3-D) 

(Leak Detection) 

(Subsurface and Reservoir 

Objectives: • Water Level • VSP Characterization) 

• Groundwater • 2-D and 3-D (Plume Tracking) 

Monitoring Caprock Integrity (Subsurface and 

• Soil Gas Monitoring Reservoir Characterization) Geochemistry (Reservoir • Crosswell Seismic 

• Leak Detection 

• Subsurface 

• Geomechanical Analysis 

• Core Collection 

Integrity) 

• Brine/Fluid Composition • Microseismic (Passive) 

and Reservoir • Tracer Injection/Monitoring • EMIT 

Characterization Wireline Logging (Well Integrity) • Magnetotelluric Sounding 

• Plume Tracking 

• Well Integrity Testing 

• Temperature 

• Noise 

• Cement Bond 

• Density 

• Gamma Ray 

• Sonic (Acoustic) 

Physical Testing (Well Integrity) 

• Annulus Pressure 

• Injection Volume/Rate 

• Wellhead Pressure 

• Downhole Pressure 

• Downhole Temperature 

Injection Well Logging 

(Wireline Logging) 

(Plume Tracking) 

(Reservoir Integrity) 

• Temperature Logging 

• Reservoir Saturation Tool 

• Optical 

• Resistivity and EM 

• Electrical Resistivity Tomography 

• Time-lapse Gravity Survey 

• Electromagnetic Resistivity 

• Wireline Logging (Well integrity 

and Subsurface Characterization) 

- Resistivity 
	 	 	 	 	 	 	 	 	 		

 

	 	 	 	 	 	 	

	 	 	 	 	

	 	 	 	 	 	 	 	

		 	 	 	 	 	 	 	

5-4 5.0 Addressing the Objectives and Goals of Monitoring 

The concept of four distinct phases in the life cycle of 

a GS project was introduced by Benson et al. (2004).

Monitoring activities will vary among these phases, 

which are defined as follows: 

1. Pre-operation Phase: Project design is carried 

out, baseline conditions are established, geology is 

characterized, and risks are identified. 

2. Operation Phase: Period of time during which 

CO2

 is injected into the storage reservoir. 

3. Closure Phase: Period after injection has stopped, 

during which wells are abandoned and plugged, 

equipment and facilities are removed, and the 

agreed upon site restoration is accomplished. Only 

necessary monitoring equipment is retained. 

4. Post-closure Phase: Period during which ongoing 

monitoring is used to demonstrate that the storage 

project is performing as expected and that it is safe to 

discontinue further monitoring. This phase will last 

for decades. Once it is satisfactorily demonstrated 

that the site is stable, monitoring will no longer 

be required except in the event of leakage, legal 

disputes, or other matters that may require new 

information about the status of the storage project. 

Each monitoring phase (pre-operational, operational, 

closure, and post-closure) of a GS project will employ 

specialized monitoring tools and techniques that 

will address specific atmospheric, near-surface, 

and subsurface monitoring needs. Atmospheric 

monitoring techniques are critical in identifying CO2 

concentrations above ambient background levels. Nearsurface techniques play a vital role in the preservation 

of shallow groundwater sources and supply critical 

information on any major vertical migration of injected 

CO2

. Subsurface monitoring techniques can identify 

CO2 plume location, pressure propagation, and reservoir 

and seal integrity. Monitoring packages for a particular 

GS project will depend heavily on site-specific geologic 

conditions and project objectives. 

The recommended steps for selection of suitable 

geophysical techniques include: 

•	 Developing geologic models for the sequestration site

that includes the reservoir, the seals, and overlying 

geology, aquifer(s), vadose zone, and surface. 

•	 Performing reservoir simulations of the sequestration

processes of interest, such as prediction of changes 

and the distribution of fluid phases resulting from CO2 

injection. 

•	 Using the geologic model and results of reservoir

simulations to perform numerical simulations to 


predict the response of candidate geophysical and 


geochemical monitoring techniques.
 

In addition to site selection, determining the appropriate 

monitoring technique is a key factor for successful GS 

of CO2

. Monitoring techniques can provide information 

to address safety and environmental concerns, address 

research questions, and provide verification for national 

accounting of GHG emissions and support GHG 

registries. Based on risk assessment, evaluation of the

project goals, and mandatory monitoring requirements, 

a decision tree for selection of monitoring techniques 

for a particular research or operational GS project 

can be constructed (Figure 5-1 for pre-operation 

and operation phases; Figure 5-2 for post-injection 

monitoring). 

The results of monitoring throughout the life cycle of 

GS project from pre-operation to post-closure phases 

will provide information to operators and regulators. 

This information will provide the flexibility to revise 

operational and monitoring activities that may persist 

for many decades. The goal is to limit unnecessary 

burden on owners, operators, or permitting agencies and 

provide a strong foundation for national consistency in 

permitting and safe operation of GS projects. 
5.0 Addressing the Objectives and Goals of Monitoring 5-5 Figure 5-1: Decision tree for pre-operational and operational phase monitoring techniques for GS project based on mandatory monitoring requirements and proposed Class VI requirements. Primary technologies are listed with black text and solid fi gure lines, whereas Secondary and Potential Additional Technologies are listed with red text and dashed fi gure lines. Light-grey lines depict proposed UIC regulatory changes for Class VI wells. 
	 	 	 	 	 	 	

	 	 	 	 	

	 	 	 	 	 	 	 	

	 		 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

5-6 5.0 Addressing the Objectives and Goals of Monitoring 

Figure 5-2: Decision tree for post-injection monitoring techniques for a GS project based on mandatory monitoring requirements. 

Primary technologies are listed with black text and solid figure lines, whereas Secondary and Potential Additional Technologies are 

listed with red text and dashed figure lines. Light-grey lines depict proposed UIC regulatory changes for Class VI wells. 

5.5 Pre-Operation Phase 

Site characterization and selection is the first step 

in a monitoring program that can assure the safety 

and integrity of a GS project. Most elements of 

site characterization are considered to be normal 

operational practice, based on existing regulations for 

natural gas storage, injection of water for secondary oil 

recovery, and disposal of produced water, acid-gases, 

and hazardous wastes. Site characterization to establish 

a baseline can include: 

•	 Determination of baseline characteristics of the target

formation. 

•	 Bounding formation information, including continuity

and thickness of caprock, lithology, integrity, presence 

of fracturing, and how containment can be assured. 

•	 Well completion and casing data, well logs, and

well testing requirements, such as those developed 

for Alberta (EUB, 1994) and the UIC Program

administered by either EPA or the designated state 

agency under the 1974 SDWA (EPA, 2008a). 

•	 Information (well location, status, and completion and

casing data) on all wells in the vicinity of the project, 

including any wells that have been shut down, had 

workovers or remedial actions. 

•	 Emergency response plans and mitigation actions

(Monea et al., in press). 

At the close of site characterization, the GS site and 

proposed monitoring plan must be permitted by the 

appropriate regulatory agency prior to operations. The 

RCSPs’ GS field projects have developed not only 

monitoring technologies, but have also contributed to 

the development of monitoring requirements for CCS. 

The RCSPs’ demonstration projects have initiated a 

high-level of activity by Federal (EPA, BLM), state, and
	 	 	 	 	 	

5.0 Addressing the Objectives and Goals of Monitoring 5-7 

other organizations (Navajo EPA and IOGCC). Activity 

to develop monitoring requirements for CCS is still 

underway and has contributed to the proposed Federal 

EPA rules establishing a new UIC class for injection 

wells associated with GS projects (Federal Register, 

July 25, 2008). The Phase II projects have helped 

initiate the necessary regulatory activity to develop 

monitoring requirements to validate and potentially 

deploy large-scale geologic CCS. 

5.5.1 Pre-operation Monitoring 

Monitoring during the pre-operation phase of a 

GS project is used to establish baseline conditions, 

including characterization of geologic features 

within the vicinity of the site, and identifying 

potential risks and leakage pathways (LBNL,

2004). Pre-operation monitoring involves all 

activities prior to injection, including: site screening 

and selection, baseline characterization, welldrilling and installation, well-integrity testing, and 

caprock and formation integrity testing. The suite 

of monitoring tools and techniques implemented 

during this project phase should be capable of 

determining wellhead and formation pressure; 

establishing baseline soil gas, groundwater, and 

atmospheric CO2

 concentrations; verifying injection 

rate (and production rate if it is an EOR or gas 

extraction project); and assessing site geology. 

A summary of the purpose for each phase of 

monitoring for a GS project can be found in 

Appendix IV. 

Monitoring packages for a particular storage project 

will heavily depend on site-specific objectives and 

characteristics. In addition, specific monitoring 

tools and their application, including the spatial and 

temporal scales in which they are used, will vary 

across project phases (pre-operation, operation, 

closure, and post-closure) and may vary due to 

specific project events (i.e., change in direction 

in CO2

 plume migration, discovery of a leakage 

pathway, shift in target formation integrity, etc.). 

Pre-operation monitoring tools and applications are 

described below according to their function. 

Geophysical Approaches – Geophysical monitoring 

in the pre-operation phase of a GS project is used 

to assess the baseline geological conditions in and 

around the site vicinity prior to CO2

 injection. 

Integration of the geophysical approaches is 

needed to get the best quantitative estimate of 

CO2

 in place. Available geophysical monitoring 

techniques include seismic surveys, EM imaging, 

well logging, sample core collection and analysis, 

and pressure and temperature monitoring. Results 

of baseline geophysical testing can be compared 

to subsequent monitoring during the injection and 

post-closure phases to observe time-lapse changes 

resulting from the injection process. Requirements 

under UIC regulations for Class I (non-hazardous) 

and II wells indicate that injection pressures 

must be monitored so as to not cause fracturing 

into the confining zone or cause fluid movement 

into USDWs. Additional requirements demand 

monitoring and reporting of the CO2 injection flow 

rate and volume, injection and annulus pressure, 

as well as periodic well MIT (EPA, 2008a). Steprate tests conducted prior to injection can indicate 

the maximum allowable injection pressure without 

inducing failure or formation parting pressures 

(usually, injection pressure will be some fraction 

of estimated formation pressure, with maximum 

injection pressure capped by regulation). Downhole 

pressure sensors can be used to obtain pressure 

readings inside the well casing. Step-rate tests only 

need to be conducted once for each project injection 

well drilled during the pre-operation period. 

Refer to the EPA step-rate testing procedure for 

additional details on conducting a step-rate well 

test (http://www.epa.gov/region8/water/uic/INFOStepRateTest.pdf). 

CO2 injection flow rate and volume can be 

easily monitored at the wellhead. Flow rate 

and volume readings will obviously be zero 

during the pre-operation phase. Pressure sensors 

placed in the wellhead and annulus can provide 

instantaneous, real-time pressure readings for 

all project operational phases. Although not a 

primary practice at GS sites, downhole pressure 

(P) and temperature (T) sensors can be used to 

detect baseline conditions (P and T) in the target 

formation prior to injection. These readings can 

be helpful in assessing overall caprock and target 

formation integrity once the injection phase begins, 

as P and T readings will definitely change from 

baseline conditions. 

An MIT is needed to satisfy requirements set 

forth in 40 CFR § 146.8(b) for Class I and II wells 

to ensure the absence of significant leaks in the 

tubing, packer, or casing and to ensure that no 
	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

		 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

5-8 5.0 Addressing the Objectives and Goals of Monitoring 

significant fluid movement into a USDW through 

vertical channels adjacent to the injection wellbore 

will occur. No specific MIT is required for Class 

V wells; however, permit conditions will likely 

require operators to demonstrate internal and 

external integrity during the lifetime of the project, 

and this may require more frequent testing. One 

of the three following methods is considered a 

suitable MIT according to 40 CFR § 146.8(b): 

(1) conduct an initial pressure test and monitor 

the tubing-casing annulus pressure with sufficient 

frequency to be representative while maintaining 

an annulus pressure different from atmospheric 

pressure measured at the surface; (2) pressure 

test with liquid or gas; or (3) record of monitoring 

showing the absence of significant changes in 

the relationship between injection pressure and 

injection flow rate for certain existing Class II 

enhanced recovery wells. The MIT should be 

conducted once the well is complete and is required 

to be repeated at least once every five years or 

when packer reseating is conducted. Noise logs 

and cement bond logs (CBL) can be used to assess

the integrity of the cement component of the well. 

Cement records are required for new and existing 

Class II injection wells in all EPA regions except 

Region 6 (Arkansas, Louisiana, New Mexico, 

Oklahoma, and Texas), where State or BLM records

are used (unless a state has primacy over UIC 

regulations). CBLs are also required for new and

existing Class II injection wells in all EPA regions 

except Region 5 (Illinois, Indiana, Michigan, 

Minnesota, Ohio, and Wisconsin). Surface casing 

cement is typically required to be circulated to the 

surface, while the production casing is typically 

cemented at least 100 feet above the injection 

zone. Refer to Table 4-2 for a complete summary 

of the monitoring, construction, and operation 

requirements for Class I, II, and V UIC injection 

wells. Appendices II and III provide detailed 

descriptions of monitoring tools available for GS 

projects to assess geophysical parameters. 

Siting requirements for Class I and II UIC wells 

under CFR § 146.14 require demonstration of 

the presence and adequacy of injection and 

confining zones by presenting information on 

local geologic structures, faults, and other relevant 

geomechanical information. Maps and cross 

sections of site lithology, USDWs, and AoR are 

also required. For Class I and II injection wells, 

Federal UIC regulations require that the AoR be 

defined as either a fixed radius of one-fourth mile 

surrounding the well (or wells, for an area permit) 

or an area above the injected fluid and pressure 

front determined by a computational model. Class 

II well regulations also require a list of penetrations 

into the injection zone. Available monitoring 

tools for assessing subsurface geology include: 

core sampling, wireline logging (sonic, density, 

gamma ray, RST, and resistivity); EM techniques 

(electromagnetic induction tomography [EMIT] and 

magnetotelluric sounding); and seismic surveying 

(VSP, 2-D seismic, 3-D seismic, crosswell seismic, 

microseismic (passive) seismic, microseismic). 

Core sampling is a relatively simple technique that 

can be used to assess the lithology at the sampling 

location as a function of depth. Sample cores can 

be taken as part of the well drilling process and at 

additional locations in and around the site. Sample 

cores only provide geologic information at their 

specific location. Site geology can be interpolated 

between coring locations and by the use of data 

gathered from other wells within the vicinity. 

Spatial placement and frequency of core samples 

will likely be based on the project operator’s 

judgment and the available budget. Wireline 

logging is a common method for evaluating 

geologic formations by lowering an instrument 

and obtaining a profile of one or more physical 

properties along the length of the well. A variety 

of different well logs are available that can measure 

several different parameters – from the condition 

of the well to the composition of pore fluids and 

the mineralogy of the formation. Wireline logging 

can provide detailed information on rock and 

fluid characteristics in the immediate vicinity 

of the wellbore casing. Additional wells, either 

observation wells, monitoring wells, or production 

wells (for ECBM or EOR) would need to be placed

in and around the site for any added geologic 

characterization. 

EM and seismic survey methods are capable of 

providing a graphic depiction of the subsurface 

over a large area and are not limited to a specific 

sampling point (like sample cores and wireline 

logging). But they in exchange give up resolution,

and quantitative properties. These techniques can 

provide detailed information of the subsurface 

(beyond UIC regulatory requirements) that can be 
	 	 	 	 	 	 	 	

	 	 	 	 	 	 		 	

	 	 	 		

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 		 	

	 	 	 		 	 	 	

5.0 Addressing the Objectives and Goals of Monitoring 5-9 

used to in combination with well – based subsurface 

characterization methods (see Section 5.6). These 

available techniques can provide the necessary data 

needed to meet the siting requirements in 40 CFR § 

146.14. The spatial scales at which the tools will be 

implemented will be based strictly on specific site 

characteristics, operator preference, and available 

budget. 

Geochemical Methods – Geochemical monitoring 

approaches in the pre-operation phase of a GS 

project are used to assess the baseline groundwater 

quality and composition. Groundwater sources 

of interest include USDW around the injection 

site, as well as saline formation fluids (brine) 

and production well water from EOR and ECBM

projects. Available geochemical monitoring 

techniques include basic groundwater quality 

monitoring, analysis for inorganics and isotopes, 

brine composition studies, and groundwater CO2 

tracer monitoring (all geochemical tools described 

in detail in Appendices II and III). Baseline

groundwater samples can be collected to ensure 

data availability prior to first injection of CO2. 

This will provide the basis against which further 

sampling and analytic work can be compared 

(Brown et al., 2001).

Requirements under UIC regulations under 40 § 

CFR 146.12 for Class I, II, and V wells indicate 

that no fluid movement is permitted to any USDWs 

and that the chemical composition of the injected 

fluid must be properly analyzed. Preventing 

fluid movement into USDWs is primarily based 

on high quality well construction rather than 

monitoring (refer to 40 CFR § 146.12 & 146.22 for

respective Class I and Class II well construction 

requirements). Groundwater monitoring can be 

used to determine USDW integrity during and after 

the injection phase of the project. 

The main geochemical technique used in the 

pre-operation project phase will be to conduct 

initial groundwater quality monitoring to identify 

USDWs in the vicinity of the project, establish 

back groundwater quality, as well as confirm that 

fluids in the target formation meet the criteria 

outlined in 40 § CFR 146.4, exempting them from 

USDW status. Additional permitting requirements 

include annual formation fluid analysis and 

quarterly analysis of the physical characteristics 

of the injected fluid (both require reporting to the 

permitting body following analysis). 

Crustal Deformation – UIC standards do not 

mandate monitoring for surface deformation 

as a result of CO2

 injection under Class I (nonhazardous) and Class II wells. Two techniques 

that are commonly used to measure deformation, 

tiltmeters and synthetic aperture radar, are 

considered “promising technologies” and are 

discussed in Section 5.6. 

Surface and Atmospheric Monitoring – Surface 

and atmospheric monitoring approaches in the 

pre-operation phase of a GS project are used 

to assess the baseline ambient CO2

 and soil gas 

CO2

 concentrations within the vicinity of the 

injection site. Natural and anthropogenic nonpoint sources of CO2

 in the vicinity of the site need 

to be addressed in order to prevent false-positive 

CO2

 readings once injection has commenced. 

Available near-surface and atmospheric monitoring 

techniques include atmospheric CO2

 detectors, 

flux ACs, Advanced Leak Detection Systems, 

EC, and soil and vadose zone gas sampling. (All 

near-surface and atmospheric tools are described 

in detail in Appendices I and II.) Baseline

atmospheric and soil gas CO2 concentrations 

provide the basis against which further sampling 

and analytic work can be compared in the 

operations and post-injection project phases 

(Brown et al., 2001). Requirements under UIC

regulations for Class I, II, and V wells do not 

indicate continuous or periodic atmospheric or 

soil gas monitoring for CO2 concentrations for any 

project phase. However, UIC permits normally 

require immediate reporting of CO2 releases into 

the atmosphere. Pre-operation CO2

 releases could 

result from a wellhead breach or damage to the CO2 

transporting system (pipeline, truck, tanker, etc.). 

CO2 detectors should continuously operate in the 

vicinity of site workers to establish baseline CO2 

concentrations prior to injection and to detect and 

warn site personnel of elevated and unsafe levels 

of CO2

. Flux accumulation chambers, Advanced 

Leak Detection Systems, and eddy covariance 

techniques can be used to detect CO2 fluxes from 

the soil surface. These techniques are typically 

used only in research applications and are discussed 

in Sections 5.5 and 5.6. 
5-10 5.0 Addressing the Objectives and Goals of Monitoring 

5.6 Operation Phase 

As a GS project is permitted and approaches operational 

status, three types of monitoring (operational 

monitoring, verification monitoring, and environmental 

monitoring) are initiated. These monitoring levels 

represent an increasing progression of monitoring 

intensity, duration, and technology application, as 

briefly described below. 

Operational Monitoring – Minimum requirements 

(specified by regulations) for baseline/operational 

monitoring can closely resemble those of a CO2 EOR 

flood and provide a basis for verification. Additional 

operations monitoring is guided by the ongoing 

complexities of injection and production. Monitoring 

of injection volume, wellhead and downhole pressure, 

and the injection zone is expected during operations, 

which has been the case at Weyburn, In Salah, Sleipner, 

and the RCSPs’ Phase II and Phase III demonstration 

projects. Some of these parameters (e.g., produced oil 

volume) are not relevant for saline formation storage 

projects. Key components of operational monitoring 

used in CO2

 EOR (Jarrell et al., 2002) and applicable to 

CCS include: 

•	 Injection Metering and Pressure Monitoring: 

All injection wells should have meters and pressure 

sensors to accurately measure injection and 

production rates, surface casing pressure, bottom-hole 

injection pressure, and annulus pressure to verify that 

no casing, tubing, or packer leaks exist. 

•	 Injection Profiles: This logging reveals where 

the injectant is flowing; such measurements are not 

continuous, but may be required early in the injection 

and on an occasional basis afterwards (e.g., once a 

year). 

•	 Reservoir Pressure Data: This data may be 

acquired either with downhole pressure sensors or by 

inverting surface pressure and injection data, given 

knowledge of the injection profile. 

•	 Step-rate Tests: These tests are performed before 

injection to reveal the maximum allowable pressure 

without inducing failure or exceeding formation 

parting pressures. Usually, injection pressure will be 

some fraction of estimated formation pressure, with 

the maximum injection pressure cap set by regulation. 

Verification Monitoring – This refers to additional 

measurements that improve the understanding of 

complex processes occurring in situ. This level of 

monitoring is specified by regulatory agencies and 

independent verification bodies and involves tracking 

and quantifying the volume of injected CO2

. 

Environmental Monitoring – This refers to monitoring 

aimed at safeguarding against risks to health, safety, 

and the environment. Depending on the risk level of the 

project, aspects of environmental monitoring may be 

part of operational monitoring. 

Monitoring requirements for the operation phase are 

discussed in more detail in the next section. 

5.6.1 Operation Monitoring 

Monitoring during the operation phase of a GS 

project is used to ensure safety with all procedures 

associated with fluid injection. Operational 

monitoring involves all fluid injection activities, 

including: site screening and selection, baseline 

characterization, well drilling and instillation, 

well integrity testing, and caprock and formation 

integrity testing. The suite of monitoring tools and 

techniques implemented during this project phase 

should be capable, at a minimum, of determining 

wellhead and annulus pressure; measuring 

soil gas, groundwater, and atmospheric CO2 

concentrations; continuously monitoring injection 

rate (and production rate, if it is an EOR or gas 

extraction project); and tracking cumulative injected 

volumes. A summary of the purpose for each 

phase of monitoring for a GS project is located in 

Appendix IV. 

Minimum requirements (specified by regulations) 

for baseline/operational monitoring closely 

resemble those of a CO2 EOR flood and provide 

a basis for CO2 accounting. Supplemental 

operations monitoring is influenced by sitespecific complexities of injection and production. 

Monitoring of injection volume and flowrate, 

wellhead and annulus pressure, and the well 

integrity is expected during operations. This has 

been the case at Weyburn, In Salah, and Sleipner, 

and is being applied widely across the RCSPs’ 
	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	

5.0 Addressing the Objectives and Goals of Monitoring 5 -11 

Phase II and Phase III demonstration projects. 

Some parameters (e.g., produced oil volume) are 

not relevant for saline formation storage projects. 

Key components specific to CO2 EOR operational 

monitoring that are applicable to CCS include 

injection metering and pressure monitoring, 

injection profiles, and reservoir pressure data 

(Jarrell et al., 2002) (as described in 5.6). 

Monitoring tools used for a particular storage 

project to satisfy mandatory monitoring 

requirements will heavily depend on site-specific 

objectives and characteristics. In addition, specific 

monitoring tools and their application, including 

the spatial and temporal scales in which they are 

used, will vary across project phases (pre-operation, 

operation, closure, and post-closure) and may 

vary due to specific project events (e.g., change in 

direction in CO2

 plume migration, discovery of a 

leakage pathway, shift in target formation integrity, 

etc.). Operational monitoring tools and applications 

are described below according to their function. 

Geophysical Approaches – Available geophysical 

monitoring techniques practical for both preoperation and operation phase include seismic 

surveys, EM imaging, well logging, sample 

core collection and analysis, and pressure and 

temperature monitoring. Results of baseline 

geophysical testing can be compared to operational 

monitoring data obtained during injection to 

observe time-lapse differences between baseline 

conditions and conditions after injection. UIC 

regulations for Class I and II wells require 

monitoring and reporting of the CO2

 injection flow 

rate and volume, injection and annulus pressure, as 

well as periodic well MIT (EPA, 2008a). While 

complete Class V well operational monitoring 

requirements are usually project specific, complete 

Class I requirements differ significantly from Class 

II requirements (mostly due to the production 

expected from Class II wells). 

As mentioned in Section 5.6, CO2

 injection flow rate 

and volume can be easily monitored at the wellhead 

using a flow meter that reads instantaneous and 

cumulative flows. Flow rate and volume readings 

are required to be continuously monitored 

throughout the injection period. Pressure sensors 

placed in the wellhead and annulus can provide 

instantaneous, real-time pressure readings for 

all project operational phases. Specific Class I 

operational geophysical monitoring requirements, 

as outlined by 40 CFR § 146.13, include at a 

minimum: 

•	 Analysis of the injected fluids with sufficient

frequency to yield representative data on their 

characteristics (quarterly). 

•	 Installation and use of continuous recording

devices to monitor injection pressure, flow rate 

and volume, and the pressure on the annulus 

between the tubing and the long string of casing 

(continuous). 

•	 Demonstration of mechanical integrity pursuant

to § 146.8 at least once every five years during the 

lifetime of the well. 

•	 The type, number, and location of wells within

the AoR to be used to monitor any migration 

of fluids into, and pressure in, the USDW, the 

parameters to be measured, and the frequency of 

monitoring. 

Specific Class II operational monitoring 

requirements as outlined by 40 CFR § 146.23 

include at a minimum: 

•	 Monitoring injected fluids at sufficiently frequent

time intervals to yield data representative of their 

characteristics. 

•	 Observation of injection pressure, flow rate, and

cumulative volume at least with the following 

frequencies: 

- Weekly for produced fluid disposal operations. 

- Monthly for enhanced recovery operations. 

- Daily during the injection of liquid 

hydrocarbons and injection for withdrawal of 

stored hydrocarbons. 

- Daily during the injection phase of cyclic steam 

operations and recording of one observation of 

injection pressure, flow rate, and cumulative 

volume at reasonable intervals no greater than 

30 days. 
	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

5-12 5.0 Addressing the Objectives and Goals of Monitoring 

•	 A demonstration of mechanical integrity pursuant

to § 146.8 at least once every five years during the 

life of the injection well. 

•	 Maintenance of the results of all monitoring until

the next permit review (see 40 CFR 144.52(a)(5)). 

•	 Hydrocarbon storage and enhanced recovery may

be monitored on a field or project basis rather 

than on an individual well basis by manifold 

monitoring. Manifold monitoring may be used 

in cases of facilities consisting of more than 

one injection well operating with a common 

manifold. Separate monitoring systems for 

each well are not required, provided the owner/ 

operator demonstrates that manifold monitoring is 

comparable to individual well monitoring. 

40 CFR § 146.13 also requires the development of 

an Ambient Monitoring Plan by the well operator 

that, at a minimum, annually monitors the pressure 

buildup in the injection zone (obtained by downhole 

pressure monitoring devices), including the 

shutdown of the well to conduct an observation of 

the pressure fall-off curve. Additional geophysical 

monitoring tasks may be prescribed by the 

Director (Regional Administrator, State director, or 

Tribal director) to any Ambient Monitoring Plan, 

including: 

•	 Continuous monitoring for pressure changes in

the first aquifer overlying the confining zone. 

Quarterly sampling of aquifer constituents

(specified by the Director) may also be required. 

Class V well operation monitoring requirements 

may be similar to many of the Class I well 

requirements listed above. Additional Class V 

monitoring may be required compared to Class I; 

however, permit conditions, dictated by site-specific 

situations and scenarios, are likely to vary across 

different projects. 

The MIT procedure will not change from the initial 

test in the pre-operation phase to the periodic 

testing schedule required for operation phase 

monitoring. UIC requirements for Class I and 

Class II wells require an MIT at least once every 

five years during the lifetime of the injection well 

or when packer reseating is conducted. Figure 

5-3 shows the CO2

 pathways around an injection 

well that may be tested by the MIT. Refer to Table 

4-2 for a complete summary of the monitoring, 

construction, and operation requirements for Class 

I, II, and V UIC injection wells. Appendices II 

and III provide detailed descriptions of monitoring 

tools available for GS projects to assess geophysical 

parameters. 

Figure 5-3: Potential leakage pathways along an existing 

well: between cement and casing (Paths a and b), through the 

cement (c), through the casing (d), through fractures (e), and 

between cement and formation (f) (Celia et al., 2004). 

Geochemical Approaches – Geochemical 

monitoring approaches in the operation phase 

of a GS project are used to detect any changes 

in groundwater and formation fluid quality and 

composition from baseline conditions. Monitoring 

requirements under UIC regulations specific to 

geochemical applications include monitoring 

the physical characteristics of the injected fluid 

(sampled and analyzed quarterly) for Class I and 

Class II wells. Additional requirements particular 

to site-specific Class I Ambient Monitoring 

Program include: 

•	 The use of indirect geophysical techniques to

determine the position of the waste front, the 

water quality in a formation designated by the 

Director, or provide other site specific data. 

•	 Periodic monitoring of the groundwater quality in

the lowermost USDW. 
	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

5.0 Addressing the Objectives and Goals of Monitoring 5-13 

•	 Any additional monitoring necessary to

determine whether fluids are moving into or 

between USDWs. 

Class V well permits may require analysis of 

formation fluid or groundwater (annually or 

monthly, if performed) in addition to monitoring the 

injected fluid (as indicated by UIC Class V permit 

monitoring requirements for Core Energy, LLC in 

Otsego County, Michigan (EPA, 2007)). 

Crustal Deformation – UIC standards do not 

mandate operational monitoring for surface 

deformation as a result of CO2

 injection under Class 

I (non-hazardous) and Class II wells. 

Surface and Atmospheric Monitoring – Surface 

and atmospheric monitoring approaches in the 

operations phase of a GS project are used to assess 

ambient CO2 and soil gas CO2 concentrations in the 

vicinity of the injection site. (All near-surface and 

atmospheric tools described in detail in Appendices 

I and II.) Requirements under UIC regulations for 

Class I and II wells do not indicate continuous or 

periodic atmospheric or soil gas monitoring for CO2 

concentrations for any project phase. UIC permits 

do require immediate reporting of CO2 releases 

into the atmosphere. Operation phase CO2 releases 

could result from a breach from the wellhead, 

damage to the system transporting CO2 to the 

site (pipeline, truck, tanker, etc.), leakage around 

the well casing (at the injection well, monitoring 

wells, or abandoned wells within the AoR), or from 

movement from the target formation (via caprock 

fracturing, faults, or other leakage pathways). CO2 

detectors should continuously operate in the vicinity 

of site workers and warn site personnel of elevated 

CO2 concentrations during site operation. Flux 

accumulation chambers, Advanced Leak Detection 

Systems, and eddy covariance techniques can be 

used to detect CO2

 fluxes from the soil surface; 

however, they are typically used primarily in 

research applications and are discussed further in 

Appendix I and II. 

5.7 Closure Phase 

Well and site closure are important for protecting 

against leakage to the atmosphere and USDWs. GS 

well operators will need to maintain recordkeeping and 

reporting information and plugging and abandonment 

reports during the operations phase of the project, as 

well as for a significant period after site closure. The 

time extent of this recordkeeping is not defined under 

present rules. Prior to closure and the plugging of 

a well, operators will need to notify the appropriate 

regulatory authority and close the well(s) in accordance 

with the approved post-injection site care plan or 

specify the differences between the plan and the actual 

closure. 

Operators will need to plug wells in a manner 

specified by the regulatory authority. This may be 

accomplished in a number of ways using a variety of 

different materials. The materials must be compatible 

with the fluids that they may come into contact with 

and must prevent the movement of fluids outside the 

storage horizon. Specialized cements, resistant to 

CO2

 for long periods of time, may be required. To 

ensure that wells at a closed site are in a state of static 

equilibrium, tagging the cement, integrity testing, and 

other mechanical techniques may be required to test the 

adequacy of cement plugs. All records and the postclosure monitoring plan will need to be submitted to 

the appropriate regulatory agency. Important steps in 

injection well plugging as outlined by 40 CFR 144.12 

include: 

•	 Well shall be plugged with cement in a manner which

will not allow the movement of fluids either into or 

between USDWs. 

•	 The well to be abandoned shall be in a state of static

equilibrium with the mud weight equalized top to 

bottom. 

•	 Prior to abandoning a Class V well, the owner or

operator shall close the well in a manner that prevents 

the movement of fluid containing any contaminant 

into a USDW. 

•	 Materials must be compatible with the fluids with all

subsurface fluids and must prevent the movement of 

fluids outside the storage horizon. 

•	 Tagging the cement, integrity testing, and other

mechanical techniques may be required to test the 

adequacy of cement plugs. 
	 	 	 	 	 	

	 	 	 	 		 	 	 	

	 	 	 	 	 	 	 	

5-14 5.0 Addressing the Objectives and Goals of Monitoring 

For the proposed Class VI well, EPA is proposing to 

provide owners or operators flexibility in meeting the 

well plugging requirements by allowing the owner or 

operator to choose from available materials and tests 

to carry out the proposed requirements. EPA is not 

specifying the types of materials or tests that must 

be used during well plugging because a variety of 

appropriate methods exists and new materials and tests 

may become available in the future. 

Injection well plugging must comply with requirements 

of 40 CFR 144.12(a). Additional post-closure 

monitoring is also required (as mentioned in Section 

4.3), which is an additional requirement to current 

UIC regulations. The Class VI proposal would require 

that owners or operators develop a post-injection site 

care and closure plan and monitor the site following 

cessation of the injection activity. Post-closure 

care includes recording certain formation pressures 

and determining location of the plume front. EPA 

is tentatively proposing a post-injection site care 

(monitoring) period of 50 years, with the Director 

retaining discretion as to whether the 50-year period 

should be lengthened or shortened. Additional 

requirements demand that owners or operators 

demonstrate and maintain financial responsibility for 

corrective action described in 40 CFR 146.84, and 

have the resources for activities related to closing and 

remediating GS sites. Financial assurance is typically 

demonstrated through two broad categories of financial 

instruments: 1) third party instruments, including surety 

bond, financial guarantee bond or performance bond, 

letters of credit (the above third party instruments must 

also establish a trust fund), and an irrevocable trust 

fund and 2) self-insurance instruments, including the 

corporate financial test and the corporate guarantee 

(Federal Register, July 25, 2008). 

5.8 Post-Closure Phase 

During the post-closure phase, operators would 

periodically report on the results of monitoring. 

Monitoring would focus on: 1) recording the pressure 

differential between pre-operation and anticipated postinjection pressures in the injection zone; 2) predicted 

position of the plume and associated pressure front 

at the time the site is closed; 3) description of post 

injection monitoring location(s), methods, and proposed 

frequency of monitoring; and 4) assuring that vertical 

leakage to the surface through wellbores and other 

pathways is minimal. Monitoring tools, such as 3-D 

seismic and instrumented monitoring wells, could be 

used to track the position of the CO2

 plume and pressure 

front and to identify any potential vertical leakage 

toward the surface. A record of the pressures in the 

injection formation and surrounding areas, as well and 

the pressure decay rate, can confirm that the injected 

CO2 is not moving beyond the specified GS horizon. 

The presence of physical and geochemical trapping 

mechanisms is likely to reduce the mobility of CO2 

over time and research also suggests that pressure 

within the storage system will drop significantly when 

injection ceases, thus decreasing the risks of induced 

seismic activity, faulting, and fracturing (Birkholzer

et al., 2005), making storage more secure over longer 

timeframes. However, the timeframe over which this 

happens and the frequency and duration of post-closure 

monitoring are difficult to define, because it is based 

on site-specific geologic considerations. Although site 

dependent, UIC Classes I II and V typically use 30 

years as the duration for post-closure monitoring. The 

UIC Class VI proposed regulations require 50 years of 

post-closure monitoring of future CO2

 injection wells. 

If it can be determined that no plume migration outside 

of the target formation occurs within these post-closure 

monitoring periods (normally by matching favorable 

monitoring and modeling results), then no further 

monitoring is needed as the plume is considered to be 

contained within its’ target formation. 

5.9 Application of MVA Technologies at GS Field 

Projects 

DOE has supported the application of MVA 

technologies at several field sites through both the 

Core R&D and the RCSPs. The following summarizes

some of the key point on how primary and secondary 

technologies have been used to satisfy regulatory 

permitting requirements under the UIC program. 

Weyburn is an example of a project using MVA 

techniques to track the behavior of injected CO2. In 

2000, IEA launched a comprehensive geological study 

of the Weyburn CO2 storage site. Production fluid 

sampling and geochemical analyses (Shevalier et al., 

2004; Quattrocchi et al., 2004) were conducted at

Weyburn at regular intervals of three to four months 

over a three-year period, with the primary objective 

of tracing the distribution of CO2 over time within 

the reservoir. The chemical analysis allowed the 

short-term chemical interactions of the CO2

 with the 
	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

5.0 Addressing the Objectives and Goals of Monitoring 5-15 

reservoir fluids and rock matrix to be monitored. The 

primary advantage of geochemical monitoring is 

that it is capable of providing detailed and sensitive 

measurements of CO2 concentrations in sampled 

subsurface fluids at a relatively low cost. The primary 

disadvantage of this technique is that the spatial 

sampling is typically sparse, as it is limited by the 

distribution of boreholes where fluids can be sampled. 

In the case of non-EOR CO2 storage, the number of 

wells available for sampling is likely to be limited. IEA 

concluded that the geology of Weyburn field is suitable 

for long-term CCS, that the primary reservoir seals 

are competent, forming thick and extensive barriers to 

upward fluid migration, and that faults and fractures in 

the region show no fluid conductance. Risk-assessment 

modeling suggests that approximately 0.02 percent 

of the initial CO2

 in place after EOR operations are 

complete will migrate above the reservoir after 5,000 

years; of this small percentage of CO2, most will diffuse 

into the overlying caprock, and none will reach nearsurface strata containing potable aquifers. Moreover, 

the cumulative leakage through existing wells in the 

field is expected to be less than 0.001 percent of the 

initial CO2 in place (Zhou et al., 2004). 

For accurate CO2

 volume estimation, seismic data 

require calibration (e.g., time-lapse downhole seismic 

logging, pressure monitoring, sample coring) and 

integration with detailed reservoir flow simulations 

as a complementary constraint. Reservoir simulation 

models require site-specific geologic parameters to 

properly simulate plume fate and transport over time. 

Primary technologies (Tables 5-1 and 6-1) needed to 

satisfy UIC mandatory monitoring requirements can 

provide the necessary site-specific physical (lithology, 

pressures, temperatures) and chemical (groundwater 

and formation fluid compositions, soil gas composition) 

data needed to generate in-depth reservoir simulation 

models. However, the application of primary 

technologies is spatially limited and normally only 

generates data at or in the vicinity (as in many wireline 

logging applications) of a specific monitoring location. 

At the Frio Brine pilot, a detailed characterization

was conducted using primary reservoir assessment 

technologies. This effort included use of log analysis 

and seismic surveys to define facies, structure, and 

diagenetic evolution and estimation of petrophysical 

and geochemical properties using core from analogous 

facies in Chambers County to build a quantitative 

reservoir model. Wireline logging, pressure and 

temperature measurement, and geochemical sampling 

were also conducted during injection (Hovorka, et 

al, 2006). A wireline sonic log taken three months 

after injection showed a weak and slower arrival of 

compressional wave over the perforated injection 

interval when compared to the baseline sonic log. 

The successful measurement of plume evolution is 

an effective method to monitor CO2

 in reservoirs and 

document migration (Sakurai, et al, 2005). 

Seismic monitoring can be useful for detecting 

significant leakage or migration of CO2

 from the 

reservoir. Estimates from the Weyburn project suggest 

that CO2

 leakage in the order of 2,500 to 10,000 tonnes 

(a mere 0.0.008 to 0.03 percent of the total anticipated 

injection amount of approximately 30 million tonnes) 

would be detectable, assuming that the CO2 remains 

concentrated within the overlying strata. This is in 

the range of 90 to almost 99 percent retention and 

new technologies developed at Weyburn and other 

demonstration projects are improving resolution and 

detection levels. Time-lapse 3-D seismic surveys at 

the Sleipner gas field saline injection indicate that 

no detectable leakage of CO2 into the caprock has 

occurred (7 million tonnes of CO2 injected over 12 

years) (Chadwick et al., 2008). Crosswell seismic 

surveying at the Frio test site indicates plume migration 

throughout the “C” Sandstone (deepest sandstone layer) 

injection region and successful plume confinement 

by the “B” Sandstone (middle sandstone layer)

formation. Monitoring of site geophysical (downhole 

and well pressure and temperature) and geochemical 

(gas composition analysis and water chemistry: pH, 

alkalinity) parameters using primary technologies 

(Tables 5-1 and 5-2) confirmed the plume images 

obtained via seismic surveying and verified that the 

CO2 plume had not breached the “B” Sandstone layer

(Hovorka et al., 2005). 
5-16 5.0 Addressing the Objectives and Goals of Monitoring 

Table 5-2: MVA Technologies that Enable Recognition of Leakage to the Atmosphere 

and Shallow Subsurface in Order to Ensure 99 Percent Retention of CO2 

Primary Technologies 

MVA Goals for Geologic Sequestration 

Identify 

storage 

processes 

and confirm 

their 

efficiency. 

Evaluate the 

interactions 

of CO2 with 

formation 

solids and 

fluids. 

Assess 

environmental, 

health, and 

safety impacts 

in the event of 

a leak. 

Evaluate 

and monitor 

remediation 

efforts should 

a leak occur. 

Assist in mediating legal 

disputes resulting from any 

impact of sequestration 

technology (groundwater 

impacts, seismic events, 

crop losses, etc.). 

Water Quality 

Analysis 

Groundwater 

Monitoring* X X X X 

Injection Fluid X X X 

Formation Fluid* X X X X 

Water Level X X X 

CoreCollection Geomechanical 

Analysis X X 

Wireline 

Logging (Well 

Integrity) 

Temperature X X X X 

Noise X X X X 

Cement Bond 

(Ultrasonic) X X 

Density X X X X 

Gamma Ray X X X 

Sonic (Acoustic) X X X 

Resistivity X X X 

Physical Testing 

(Well Integrity) 

Annular 

Pressure* X X X 

Injection 

Volume/Rate* X X X X X 

Wellhead 

Pressure* X X X X X 

Downhole 

Pressure* X X X X X 

Downhole 

Temperature 

X X X X X 

Geophysical 

Techniques 

Seismic, Gravity, 

Electromagnetic 

Surveys, etc.* 

X X X X 
	 	 	 	 	 	 	

	 	 	 	 	

	 	

	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-1 

6.0 MVA Developments for 

Large-Scale Tests in Various Settings 

The first step towards continued use of fossil fuels 

within a broad climate change mitigation strategy is 

to demonstrate the viability of GS of CO2

 in a variety 

of settings. A serious effort will require large-scale 

tests of geological sequestration in formations with 

diverse characteristics that are representative of many 

regions throughout the United States and Canada. 

DOE is currently sponsoring projects to move CCS 

from research to commercial application. Such 

demonstrations are necessary to increase understanding 

of trapping mechanisms, to test and improve monitoring 

techniques and mathematical models, and to gain public 

acceptance of CCS. Testing under a wide range of 

geologic conditions will demonstrate that CCS is an 

acceptable GHG mitigation option for many areas of the 

United States. 

The proposed large volume sequestration test (LVST) 

activities will provide valuable opportunities for R&D

in carbon sequestration. Major R&D targets/activities

include: 

•	 Determination of CO2 behavior in the subsurface. 

•	 Comparison of multi-phase flow models with realworld data to assess predictive capabilities and refine 

the models. 

•	 Determination of efficacy and detection limits of

monitoring tools for CO2 in oil and gas reservoirs and 

saline target formations. 

•	 Development and application of a comprehensive risk

assessment framework. 

•	 Development and refinement of coupled models, such

as reactive transport and geomechanical models. 

•	 Refinement of regional storage capacity estimates

based on LVST information. 

Modeling and monitoring R&D targets for these

projects include: (1) assessing the sweep efficiency as 

large volumes of CO2

 are injected to better quantify 

capacity; (2) quantifying the pressure effects and 

brine movement though heterogeneous rock to better 

understand the significance of these effects on capacity, 

monitor pressure, and brine migration; (3) quantifying 

inter-well interactions as large plumes develop, focusing 

on interaction of pressure, heterogeneity, and gravity as 

controls on migration; (4) better understanding pressure 

and capillary seals; (5) developing and assessing the 

effectiveness of available and novel monitoring tools; 

and (6) assessing how monitoring tools can be used 

efficiently, effectively, and hierarchically in a mature 

monitoring environment. 

Critical to the successful implementation of this 

approach is the development of a robust MVA program, 

including evaluating and determining which monitoring 

techniques are most effective and economic for specific 

geologic situations; this information will be vital in 

guiding future commercial projects. The monitoring 

programs of five GS projects taking place in the United 

States are outlined below. These projects are sited in 

areas considered suitable for GS and are employing 

robust monitoring programs (for research purposes) to 

measure physical and chemical phenomena associated 

with large-scale CO2

 injection. The five selected 

projects are: 

1. Gulf Coast Mississippi Strandplain Deep 

Sandstone Test (Moderate Porosity and 

Permeability): GS test located in the southeast 

portion of the United States will be conducted in 

the down dip “water leg” of the Cranfield Unit in 

Southwest Mississippi. Large volumes of CO2 from 

a natural source will be delivered by an established 

pipeline. 

2. Nugget Sandstone Test (Significant Depth, Low 

Porosity and Permeability): LVST in the Triassic 

Nugget Sandstone Formation on the Moxa Arch of 

Western Wyoming. The source of the CO2

 is the 

waste gas from an He and CH4 production facility. 

3. Cambrian Mt. Simon Sandstone Test (Moderate 

Depth, Low Porosity and Permeability): A largescale injection test in Illinois is being conducted in 

the Midwest Region of the United States. The main 

goal of this large-scale injection is to implement a 

geologic injection test of sufficient scale to generate 

understanding of injectivity, capacity, and storage 

potential in reservoir types having broad importance 

across the Midwest Region 
 

	 	 	 	 	 	 	 		 	

	 	 	 	 	 	

	 	 	 	 	 	 	

6-2 6.0 MVA Developments for Large-Scale Tests in Various Settings 

4. San Joaquin Valley Fluvial-Braided Deep 

Sandstone Test (High Porosity and Permeability): 

Large-scale injection of CO2

 beneath a power plant 

site into a deep saline formation (the Olcese and/ 

or Vedder sandstones) of the San Joaquin Valley, 

California. 

5. Williston Basin Deep Carbonate EOR Test:	 CO2 

sequestration in conjunction with EOR in select 

oil fields in the Williston Basin, North Dakota. A

minimum of 500,000 tons per year of CO2 from an 

anthropogenic source (PC plant) will be injected into 

an oil reservoir in the Williston Basin.

Each site varies significantly in overall site geology, 

including target formation depth, formation porosity, 

permeability, temperature, pressure, and seal 

formation (see Table 6-1). MVA packages selected for 

commercial projects will be tailored to site specific 

characteristics and geological features (Benson et al,

2004). The MVA packages for these case studies were 

selected to maximize understanding of CO2

 behavior 

and to determine which monitoring tools are most 

effective across different geologic regimes (as opposed 

to tailoring a site-specific MVA package). 

An overview of the MVA tools for each case study 

project is presented in Table 6-2. Although each project 

site has distinct geology, the projects employ many 

of the same Primary Technologies. Many Secondary 

and Potential Additional Technologies are used to 

expand the information obtained from the Primary 

Technologies. The MVA protocols outlined herein 

do not replace or supersede statutory or regulatory 

requirements for protection of human health and the 

environment. 
6.0 MVA Developments for Large-Scale Tests in Various Settings 6-3 

Table 6-1: Comparison of Site Geology for Each Case Study Project

Project Geographic

Location 

Geologic

Formation 

Geologic

Storage 

Class 

Reservoir

Type 

Attributes Injection Schedule Geologic 

Porosity Permeability Thickness Avg. Depth Temperature Pressure Tons CO2 Seal 

Gulf Coast Tuscaloosa Deep Sandstone Test 

Mississippi Lower 

Tuscaloosa 

Fluvial

Sandstone Saline 15% to 30%, 

avg. 20% 50 to 1,000 mD 150 to 250 ft 10,000 to 

10,500 ft 220 °F to 270 °F 4,300 to 

4,400 psi 1.5 MM Total 

Tuscaloosa

Marine

(300 ft) 

Austin 

Chalk 

Midway Fm 

NuggetSandstone

Test Southwest

Wyoming 

Nugget

Sandstone 

Eolian 

Sandstone Saline 12% to 15% 70 to 300 mD 150 to 250 ft 11,000 to 

13,000 ft 209 °F 3,850 psi 1 MM/yr, 3 MM Total 

Twin Creek 

Limestone

(500 ft) 

StrumpPruess 

Shale

(1,000’) 

Mt. Simon Shallow 

Sandstone Test 

Ohio Mt. Simon 

Sandstone 

Strandplain 

Sandstone Saline 8% to 18% <1 to 300 mD 200 to 300 ft 3,300 to 

3,600 ft 88 °F 1,435 psi .28 MM/yr, 

1.2 MM Total 

Eau Claire 

Shale

(500 ft) 

San Joaquin Valley 

FluvialBraided Deep Sandstone Test 

California Olcese and Vedder FluvialBraided Saline 20% to 40% 31 to 2,400 mD 500 to 800 ft 8,000 to 

9,000 ft Not Available Not 

Available 

0.25 MM/yr, 

1.0 MM Total 

Freeman 

Siltstone,

Jewett

Shale

(1,000 ft) 

WillistonBasin Deep 

CarbonateEOR Test 

North Dakota To be 

Determined 

Shallow

Open Shelf 

Carbonate 

EOR To be 

Determined 

To be 

Determined 

To be 

Determined >10,000 ft To be 

Determined 

To be 

Determined 

0.5 MM to 

1.0 MM Total 

Charles

Formation 
6-4 6.0 MVA Developments for Large-Scale Tests in Various Settings 

Table 6-2: Comparison of MVA Tools Used by Each of the Selected Case Studies 

Monitoring Techniques 

Gulf Coast 

Tuscaloosa 

Sandstone 

Injection 

Deep Eolian 

Nugget 

Sandstone 

Injection 

Cincinnati 

Arch Mt. 

Simon 

Sandstone 

Injection 

San Joaquin 

Valley FluvialBraided 

Sandstone 

Injection 

Williston 

Basin 

Shallow 

Shelf Open 

Carbonate 

EOR Test 

Atmospheric 

Primary 

Technologies CO2

 Detectors X X X 

Secondary 

Technologies Laser Systems and LIDAR X 

Potential 

Additional 

Technologies 

Eddy Covariance X X 

Advanced Leak Detection 

System 

Isotopes X X X X 

Near-Surface 

Primary 

Technologies Geochemical Analysis X X X X X 

Secondary 

Technologies 

Advanced Water Quality X X X 

Aerial Photography 

Shallow 2D Seismic X 

Soil and Vadose Zone Gas 

Monitoring X X X 

Flux Accumulation 

Chamber X X 

Potential 

Additional 

Technologies 

Tracers X X X 

Conductivity 

Induced Polarization 

Self-Potential 

Tiltmeters X X 

Remote Sensing (CIR, SAR, 

Hyperspectral) X X 

Subsurface 

Primary 

Technologies 

Water Quality Analysis X X X X X 

Wireline Logging X X X X 

Physical Testing X X X X X 

Secondary 

Technologies 

Acoustic (2D and 3D) 

Seismic X 

VSP X X 

2D and 3D Seismic X X X 

Geochemistry Analysis X X X 

Wireline Logging (Optical, 

Gamma Ray, CBL, etc.) X 

Potential 

Additional 

Technologies 

Crosswell Seismic X X X X 

Microseismic X X X X X 

EMIT 

ERT 

Magnetotelluric Sounding 

Resistivity and EM X X 

Induced Polarization 

Time-lapse Gravity Survey X 
	 	 	 	 	 	

	 		 	 	 	 	 	

	 		 	 	 	 	 	 	

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-5 

6.1 Gulf Coast Mississippi Strandplain Deep 

Sandstone Test (Moderate Porosity and 

Permeability) 

A GS test located in the southeast portion of the United 

States will be conducted in the down dip “water leg” 

of the Cranfield unit. A large volume of CO2 from 

a natural source will be delivered by an established 

pipeline. The goals of the project are to: (1) assess the 

feasibility and logistics of injecting 1.1 million tons 

(1 million metric tons) of CO2

 per year into a regionally 

significant brine-bearing formation in the Gulf Coast; 

(2) monitor the subsurface movement of CO2

 and its 

storage as dissolved and residually trapped phases 

along the flow path; and (3) document lack of harm to 

surface resources through close monitoring of injection 

activities. High purity, commercial-grade CO2 will be 

transported through a pipeline from a natural source to 

the site. 

The unique features of this project are that it involves 

injection of natural source CO2 into a deep (~10,000 

ft [3,050 m]) saline sandstone formation of moderate 

porosity (20 percent average) and permeability (up to 

1,000 millidarcy [mD]). This project will provide data 

on the behavior of CO2

 in this type of venue and help 

validate mathematical models. 

6.1.1 Target Formation 

The target formation is the massive sandstone of 

the Lower Tuscaloosa Formation, a Cretaceous 

age sandstone saline reservoir that occurs in the 

subsurface along the Gulf of Mexico Coastal 

Plain from Western Florida to Texas (where it is 

defined as the Woodbine Formation). The Lower 

Tuscaloosa contains an upper section of alternating 

shales and sands and a sand-rich basal section. The 

formation was deposited during a major period of 

global sea-level rise, and its deposition has been 

interpreted as an upward gradation from fluvial 

and deltaic sedimentation to shelf deposition 

(alternating sands and shales) (Mancini, 1987). The 

well-sorted, clean, coarse-grained nature of the 

Massive Sand is a result of this environment and 

makes it an ideal candidate for injection due to its 

moderate permeability and porosity. 

The Lower Tuscaloosa Formation occurs at 

10,000 to 10,500 feet at the site location along 

the flanks of the Cranfield oil field with reservoir 

pressures of about 4,300 to 4,400 pounds per square 

inch (psi). The lower Tuscaloosa at Cranfield 

is well characterized by more than 70 wireline 

logs, sidewall cores, whole cores, a well known 

production history, and a 3-D seismic survey. The 

lower complex flow system, locally known as the 

“E and D” sandstones and conglomerate, is 10 to 

50 ft (15 m) thick, highly heterogeneous, and 

complexly incises fluvial deposits. Red and gray 

shales and siltstones form within lower Tuscaloosa 

flow-unit barriers, isolating the younger sand 

bodies. These units are less amalgamated, and 

therefore sand is less continuous. 

The mineralogy of the lower Tuscaloosa complex, 

including conglomerate, coarse sandstone, muddy 

sandstone and mudstone, carbonate and chlorite 

cementation, are common and variable (MDEQ

Bulletin 108). The permeability of the lower

Tuscaloosa varies from 50 to 1,000 mD (GSA 

Bulletin 104). The Gulf Coast Basin contains a

thick interval of sandstones and shales, which were 

deposited over a series of transgressive-regressive 

cycles from the Jurassic Period to the present. 

Formations generally thicken towards the Gulf 

and offshore and occur in thicknesses of up to 

20,000 feet. 

The seals for this project have demonstrated prior 

retention of oil and gas in the structure. Local seals 

within the lower Tuscaloosa have confined oil to 

the lowermost sands. Regional seals, including the 

middle Tuscaloosa marine shale, the Austin Chalk, 

and the Midway Formation, are present at Cranfield 

and are presumed to function as seals in the saline 

aquifer, as well as over the producing field, because 

they have retained hydrocarbons. Low permeability 

carbonate and shale form a seal beneath the 

injection interval. 
6-6 6.0 MVA Developments for Large-Scale Tests in Various Settings 

6.1.2 Site Characterization 

Detailed information that can be applied to this 

test from previous field investigations in the area 

is being assessed. A 3-D seismic survey adds 

coverage into the saline aquifer part of the field that 

was not available and enhances the inter-well detail 

needed to better interpret structure and stratigraphy. 

Work conducted during the investigation phase will 

include the assessment of new down dip injection 

wells by using data from coring, core analysis, and 

open-hole logs available for the first time from the 

saline portion of the Tuscaloosa Formation. To 

develop an interpretable and significant research 

result from monitoring the CO2

 flood, an integrated 

program will be employed, beginning with 

characterization and extending through several 

types of predictive modeling, to monitoring 

planning, injection strategy, baseline monitoring, 

injection, and post-injection monitoring. It is 

important to use modeling to assess uncertainties 

that will result from data collection efforts and to 

focus data collection on reducing key uncertainties. 

6.1.3 Risk Assessment and Mitigation Strategy 

CO2

 injection is a low risk experiment because 

nearby production in the oil rim will minimize 

pressure buildup and will influence CO2 migration; 

therefore, a low-budget risk assessment approach 

will be implemented. 

Mitigation will follow normal oil field processes 

and best practices. Substandard well performance 

(poor injectivity or non-conformance) will be 

corrected by well handling with dense “kill” 

fluids and workover. Wellhead pressure will be 

monitored to assure that injection occurs below 

fracture pressure. While considered to present 

minor risk, potential complications include: (1) CO2 

deliverability through the pipeline, which is a new 

retrofit; (2) injectivity below expected rates in the 

saline part of the reservoir; and (3) logistical and 

timeline mismatches. The project team will work 

with DOE and others to develop various schedules 

to be prepared should a problem arise. 

6.1.4 MVA Activities 

A robust MVA program is anticipated. The site 

will be well instrumented with multiple sensor 

arrays. Standard, off-the-shelf technologies will 

be tested in this carbon sequestration application. 

In addition, novel tools and techniques will be 

tested and evaluated. The project will include an 

extensive program to monitor performance during 

its 10-year duration. 

Sweep efficiency is one of the primary unknowns 

in assessing capacity. Sweep efficiency is estimated 

in DOE’s Carbon Sequestration Atlas of the United 

States (2008) and has a large effect on the capacity 

of saline formations. Methods used to measure 

sweep efficiency are (a) saturation measurements 

along wellbores, (b) crosswell measurements, and 

(c) special measurements—VSP and/or surface 

seismic. Time lapse changes compared to baseline 

and measurements with multiple instruments are 

most likely to lead to a unique solution. 

Pressure and brine migration are less sensitive 

to heterogeneity than multiphase flow. However, 

improved understanding of these potential risk 

factors under sub-fracture injection conditions 

is needed. Collection of data that allows 

quantification of the components of pressure 

response (fluid flow, rock and water compression, 

dilatancy and tilt) in high and low permeability 

units is a goal. Models show that plume 

interactions are a major factor controlling capacity. 

The project setting will provide a unique laboratory 

to history match as saline injection wells are 

started. Pulsing injection and measuring bottomhole pressure response in the signal source well 

and distant monitoring points is also a powerful 

tool for history matching. Interaction with cones of 

pressure reduction around producers in the oil ring 

will also be included. 
6.0 MVA Developments for Large-Scale Tests in Various Settings 6-7 

Figure 6-1: Hierarchical Monitoring Strategy 

Tools are needed to better understand the 

performance of pressure and capillary seals. The 

seals at the injection site are known to hold gas; 

their performance under CO2 flood will help to 

extrapolate this critical factor in assuring retention 

of CO2

 in zone. 

One focus of the project is experimentation with 

a prototype hierarchical mature monitoring 

strategy (see Figure 6-1). It starts with baseline 

characterization, which includes measurement of 

the change of selected key parameters over time 

prior to injection and then as injection proceeds. A 

good temporal baseline is required to determine if 

the monitoring parameter changes outside of normal 

variability and may indicate nonconformance of the 

injection, such as leakage. A follow–on strategy 

and development of contingency plans are required 

for each type of non-conformance, as indicted in 

Figure 6-2. 
6-8 6.0 MVA Developments for Large-Scale Tests in Various Settings 

Figure 6-2: An example of contingency plans for Gulf Coast Mississippian fluvial sandstone injection during initial 

injection period. Major risks during injection period: pressure and buoyancy-driven flow through damaged wells or 

fracture networks. Probability increases over time as CO2

 quantity and pressure increases and as AoR increases. 
 

 

 

 

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-9 

Components of this monitoring plan include the The primary monitoring strategies included for this 

assessment of wellbore integrity, annual assessment of project are aimed at accomplishing specific goals. Each 

the areal extent of the plume, target reservoir leakage task focuses on some aspect of subsurface or nearmonitoring, shallow subsurface and surface seepage surface monitoring as can be seen in Table 6-3. 

monitoring, and reservoir simulation modeling. Data 

from monitoring will be used to calibrate and resolve 

inconsistencies with simulation models. 

Table 6-3: Summary of MVA Plans for Gulf Coast Mississippi Strandplain Deep Sandstone Test 

Measurement Technique Measurement Parameters Application 

Introduced—noble gasses/ 

partitioning tracers 

Dissolution of CO2 into brine Significant uncertainties in pressure response is the 

amount of CO2

 dissolved. The SECARB Early Test will 

deploy the U-tube to reservoir depths to obtain tracer 

chromatography to assess dissolution via chromatography. 

This is a follow-on to Frio with a larger volume and longer 

flow-path using the same techniques. The SECARB team 

recognizes that laboratory measurements of fractionation 

into relevant fluids and rocks is key to quantifying this test. 

Produced fluid composition CO2

 via mass, DIC, DOC; Selected 

major and minor cations, organics 

Validation of well log and cross-well CO2 detection, index of 

rock-water reaction. 

Bottom-hole pressure Pressure transducers on wireline 

with real-time readout 

Key measurement assessing relationship between pressure 

field and multiphase field. 

Distributed down hole 

temperature 

Measure zones of fluid movement Additional data to constrain flow units, especially to 

determine flow-unit thicknesses under relevant conditions. 

Also indicates well integrity. 

Pulsed neutron reservoir 

saturation; Cased hole sonic if 

modeling predicts sensitive 

CO2

 saturation Distribution of CO2 at measurements points, model match, 

validation and quantification of CASSM and cross-well ERT. 

Key input to capacity calculation term “E.” 

Time-lapse 3-D seismic 

imaging (surface deployed) 

Change from baseline, only 

if baseline assessment shows 

reasonable sensitivity to the 

expected CO2

 saturation change 

Extent of CO2

 plume: especially down-dip. May substitute 

VSP if sensitivity is higher. 

Continuous Active Source 

Seismic Monitoring (CASSM); 

Cross-well seismic tomography 

Detect timing of CO2

 movement 

cross the plane of measurement 

History match model, with high frequency temporal 

records with pressure signal 

Passive seismic monitoring Assess stress distribution Development of stress in formation 

Above-zone pressure and fluid 

monitoring 

Assess leakage signal (possible 

through well completions-poor 

cement bond) 

Continuation from Phase II to obtain long record (if Phase II 

results justify) 

Cross-well electrical resistance 

tomography (ERT) 

Improve measurement of 

saturation; will be used if proves 

feasible and economic 

Tool development will extend tie range of cross-well 

measurement of saturation and improve the rigor of history 

match and seismic inversion. 

Subsurface deformation Tilt; Measurements at surface to 

assess depth-effectiveness of tool 

under high injection rates 

Quantify geomechanical effects on storage formation as 

part of pressure-field assessment. 

C02

 land surface-soil gas 

assessment 

Measure natural CO2 fluxes— 

aquifer-vadose zone-soil-landsurface and atmosphere in depth 

over time. 

Determine sensitivity of these techniques under regional 

conditions. Possible follow-on-tracer test to validate 

hypothesis. 

Aquifer monitoring Alkalinity, DIC, DOC, isotopes, 

chloride selected cations and 

anions. 

Assessment of method in compact possibly contaminated 

setting, directly regulated recourse. Possible follow-ontracer test to validate hypothesis. 
	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 		 	 	 	 	 	

	 	 	 	 	 	 	 	

	 		 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 		 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 		 	 	 	 	 	

6-10 6.0 MVA Developments for Large-Scale Tests in Various Settings 

6.2 Nugget Sandstone Test (Significant Depth, 

Low Porosity and Permeability) 

The goal of this LVST is to demonstrate that the Nugget 

sandstone in the LaBarge Platform, Wyoming, and

other analogous sandstones are a viable and safe target 

for sequestration of a large portion of the northwestern 

United States’ CO2 emissions. This test will improve 

understanding of injectivity, capacity, and storability 

in a regionally significant formation and promote 

commercialization of carbon sequestration. 

This project will conduct an LVST in the Triassic 

Nugget Sandstone Formation on the Moxa Arch. The 

test will inject approximately 1 million tons of CO2

 a 

year for three years into the saline aquifer at depths 

of 11,000 to 13,000 feet. The source of the CO2

 is the 

waste gas from an He and CH4 production facility. CO2 

will be injected into the Nugget Formation utilizing 

a single vertical wellbore. Injectivity into the Nugget 

Formation will be approximately 5,360 tons/day 

according to testing in the target formation. Since 

the mid-1970s, the vicinity of the site has been, and 

continues to be, subjected to significant oil and gas 

exploration and production. Regional Characterization 

activities include acquiring and analyzing new data, 

field measurements, refining capacity estimates, and 

collaboration and data sharing with industry and 

agencies. The regional characterization work will 

include geologic, terrestrial, economic, and geographic 

information system (GIS) components. 

The unique features of this project are that it involves 

injection of by-product CO2 from He and natural gas 

production into a deep (~12,000 ft [~3,700 m]) saline 

sandstone formation of low porosity (12 to 15 percent) 

and permeability (up to 300 mD). This project will 

provide data on the behavior of CO2

 in this type of 

venue and help validate mathematical models. 

6.2.1 Description of Target Formation 

The LaBarge Platform encompasses a large

structural closure at the northern limit of the 

Moxa Arch. The Moxa Arch is a large northsouth trending anticline bound on the south by the 

Uinta Mountains and trending north for 120 miles 

before plunging beneath the leading edge of the 

Wyoming Thrust Belt. The west flank of the

anticline dips below the Wyoming Thrust Belt, and

the east flank is the western margin of the Green 

River Basin. The closure of the LaBarge Platform

encompasses approximately 800 square miles on 

the northern region of the Moxa Arch. Three small, 

mature Nugget oil fields are present on the LaBarge

Platform and produce from smaller anticlines 

superposed on the much larger structural feature. 

The Nugget Sandstone is an extensive brine aquifer 

located in the LaBarge Platform and extending

across the remainder of the Moxa Arch and into the 

Green River Basin. This saline formation of the

Nugget Sandstone within the closure of the LaBarge

Platform is the target of this injection project. The 

LaBarge Platform has the potential to store a large

volume of CO2 in the Nugget Formation and takes 

on even greater long-term significance, as the 

Nugget Formation on the remainder of the Moxa 

Arch and within the Green River Basin is also a

potential sequestration target. 

The Nugget Sandstone is a Jurassic-aged regional 

sheet sandstone that underlies southwestern 

Wyoming. The thickness of the Nugget Sandstone 

in the area of LaBarge is approximately 650 to

700 feet. It is equivalent to the Navajo Sandstone 

(Utah) and has similar properties to the Tensleep 

Sandstone (Montana and Wyoming), Weber 

Sandstone (Colorado, Utah, and Wyoming), 

Quadrant Sandstone (Montana), and the Sundance

Sandstone (Wyoming) and, thus, has important 

regional significance. The Nugget Sandstone was 

deposited as a series of sand dunes and interdunal 

deposits in an Eolian depositional environment. 

The porous sandstones that are the injection target 

have an average thickness of 150 to 250 feet, an 

average porosity of greater than 15 percent, and are 

highly permeable. The seal formation consists of 

500+ feet of the overlying Twin Creek limestone 

capped by 1,000+ feet of the Jurassic StrumpPruess shale section. These seals maintain integrity 

in the structurally more complex Wyoming/Utah 

thrust Belt and have also been proven to be an

effective seal for the three small oil fields located 

on the LaBarge Platform. There is no reason to

suspect any issues pertaining to seal integrity for 

CO2 storage. 
	 	 	 	 	 		 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

6.0 MVA Developments for Large-Scale Tests in Various Settings 6 -11 

6.2.2 Risk Assessment and Mitigation Strategy 

Major effort will include the development of 

the system level model CO2

-PENS, as well as 

detailed work on the integrity of wellbores and 

seals in the context of CO2 storage. Other work 

will include dynamic fracture simulations for 

the risk assessment portion of the project. This 

work will directly assess important aspects of site 

performance and risk due to pressure and stress 

changes in fracture networks. 

6.2.3 MVA Activities 

MVA activities will include extensive monitoring 

and simulations to ensure that the injected CO2 

remains contained in the target formation. The 

basic well configuration will consist of a single 

injection well with a minimum of four installed 

monitoring wells. Additional monitoring capacity 

will depend on existing wells, if available within 

the plume dimensions. The fundamental direct 

monitoring methods employed will include soil gas 

surveys, geophysical detection of subsurface CO2 

(2-D or 3-D seismic, single or multi-component) 

and sampling of monitoring wells for geochemical 

indicators of the presence of CO2. Sampling of 

multiple vertical intervals is planned to allow 

detection of CO2 in the target formation, the 

overlying seal interval, and a shallow subsurface 

aquifer. Additional surface methodologies may 

include EC towers, LIDAR and IR detection tools, 

and hyperspectral tools, as well as traditional soil 

gas analysis. 

Subsurface measurements will focus on borehole 

logs that provide physical and chemical information 

about the reservoir rocks and gases and fluids 

within the pore space. Gravity and other borehole 

log measurements, when measured between 

boreholes and during and after CO2 injection (timelapse), can be used to map changes in physical and 

chemical properties of rocks and fluids. Borehole

wireline logging will also be conducted to assess 

geologic characteristics as a function of depth in the 

well vicinity. 

Other subsurface methodologies may be employed, 

depending on specific site conditions and costs. 

These include downhole methods such as electrical 

resistance tomography, crosswell tomography, 

microseismic (passive), sparse array seismic 

in-situ probes, and syn-injection tracers. These 

methodologies can be used to address storage 

feasibility, make point measurements of state 

functions (P and T), and track the disposition of 

injected CO2

. 

All surface and subsurface data from the project 

will be integrated using a stochastic inversion 

approach. Stochastic inversion is extremely well 

suited to integration of uncorrelated (orthogonal) 

subsurface data sets. It is robust, fast, handles 

non-linear and non-unique solutions well, and 

calculates the likelihood for each of multiple 

solutions. This approach can also be used to help 

plan a field monitoring network. 

6.3 Cambrian Mt. Simon Sandstone 

Test (Moderate Depth, Low Porosity and 

Permeability) 

The goal of this large-volume storage test is to 

demonstrate the ability of the Mt. Simon Sandstone, a 

major regional saline reservoir in the Illinois Basin, to

accept and retain 1 million tons of CO2

 injected over 

a period of three years. The proposed site is near an 

ADM ethanol fermentation facility. The ethanol facility 

serves as the source of the injected CO2. 

The key research and development targets for the 

large-scale injection test relate to acceptance by the 

saline reservoir of the CO2

 (injectivity), ability of 

the reservoir to store the CO2

 (storage capacity), the 

integrity of the seals, and the entire process of preinjection characterization, injection monitoring, and 

post-injection monitoring to understand the fate of 

the CO2. These targets can be summarized under the 

general processes of modeling, capture, injection, and 

monitoring. 

6.3.1 Target Formation 

The thickest and most widespread saline reservoir 

in the Illinois Basin is the Cambrian-age Mt. Simon

Sandstone. It is overlain by the Eau Claire 

Formation, a regionally-extensive low-permeability 

shale, and underlain by Precambrian granitic 

basement. 
	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

6-12 6.0 MVA Developments for Large-Scale Tests in Various Settings 

There are only about 20 wells in the target region 

of southern Illinois that reach into the Mt. Simon 

(greater than 4,500 feet measured depth) and many 

of these wells penetrate only a short interval at the 

top. Most of these are old wells that lack a suite of 

modern geophysical logs suitable for petrophysical 

analysis. Although comprehensive reservoir data, 

where injection will occur, are currently lacking, 

there are sufficient data to demonstrate the regional 

presence of the Mt. Simon. The Mt. Simon is 

used extensively for natural gas storage in the 

northern half of Illinois, and detailed reservoir 

data are available from these projects. The ten 

gas storage projects show that the upper 200 feet 

of the Mt. Simon has the necessary porosity and 

permeability to be a good sequestration target. No 

current seismic reflection data are available at the 

proposed site. The project team plans to acquire at 

least two new 2-D seismic reflection profiles across 

the proposed site. 

The Mt. Simon is more than 1,000 feet thick at 

the site and has an average porosity, calculated 

from wireline logs, of about 12 percent. The 

top of the Sandstone at the site location lies at a 

depth of approximately 5,500 feet, in agreement 

with wells in the area that suggest that the 

top of the Mt. Simon would occur between 

5,000 and 6,000 feet. Using a linearly extrapolated 

temperature gradient of 1 °F/100 ft (1.7 °C/100 m), 

the bottom hole temperature at 5,500 feet (1,675 m) 

is estimated to be about 116  ̊F (46.6 °C). To 

calculate the pressure at 5,500 feet (1,675 m), a 

pressure gradient of 0.4 psi/ft (0.083 atm/100 m) 

was used, because Illinois reservoirs tend to 

be slightly underpressured compared to the 

standard freshwater gradient of 0.433 psi/ft 

(0.09 atm/100 m). At 5,500 feet (1,675 m) the 

expected reservoir pressure is about 2,200 psi 

(149 atm). 

Within the Illinois Basin, three thick shale units

function as significant regional seals. These are 

the Devonian-age New Albany Shale, Ordovician 

age Maquoketa Formation, and the Cambrian-age 

Eau Claire Formation. There are also many minor, 

thinner Mississippian- and Pennsylvanian-age shale 

beds that form seals for known hydrocarbon traps 

within the basin. Just as important, the lowermost 

seal, the Eau Claire, has no known penetrations 

within a 15-mile radius surrounding the site; 

therefore, integrity of existing wellbores is not as 

important an issue as in some shallower formations. 

All three significant seals are laterally extensive and 

appear, from subsurface wireline correlations, to 

be continuous within a 100-mile radius of the test 

site. There are two secondary seals at the site. The 

Ordovician Maquoketa Shale is laterally continuous 

across the projected test site and is estimated to be 

over 200 feet thick at the ADM site. This shale is 

a regional seal for production from the Ordovician 

Galena (Trenton) Limestone. The DevonianMississippian New Albany Shale is about 140 feet 

thick in the ADM study area. Extensive well control 

from oil fields shows that this shale is a good seal 

for hydrocarbons; hence, it should also be a good 

secondary seal against the vertical migration of 

CO2

. 

6.3.2 Site Characterization 

The characterization and modeling task will be 

implemented according to a Performance and 

Risk analysis program. Based on a systemic

approach, this program will allow defining the 

characterization, modeling and monitoring needs 

in order to optimize the performance of the specific 

site and reduce risks to a minimum. Specific site 

characterization tasks include: 

1. System definition; specification of the boundaries 

of the system that will be analyzed and definition 

of the assessment phases (site development, 

operations, long-term storage). 

2. Data collection and interpretation: collection 

of all the relevant data available from previous 

project phases, their interpretation, and 

identification of the main uncertainty areas. 

3. Initial performance and risk analysis: initial 

characterization of the ADM site in terms of 

capacity, injectivity and containment (static 

analysis) based on the current knowledge and 

understanding of the storage behavior and the 

main risks. This study will allow identifying the 

information needed for a complete analysis. In 

particular, it may point out the need for further 

characterization of features or properties. 
6.0 MVA Developments for Large-Scale Tests in Various Settings 6-13 

A comprehensive characterization program will be 

defined from the results of the initial performance 

and risk analysis, and be performed to properly 

assess the storage performance factors and evaluate 

risks. The effort is outlined in Figure 6-3. This 

will be achieved by recording two 2-D seismic 

lines on the roads adjacent to the injection site to 

pre-qualify the site on a gross basis, drilling a data 

well to collect data and samples, from which a 

full formation evaluation study will be conducted, 

and recording a high-resolution 3-D seismic 

survey for use as baseline and detailed reservoir 

characterization. Well testing and/or a small-scale 

CO2 injection test will also be considered.

 6.3.3 Risk Assessment Strategy 

The relevant risk pathways addressing loss of 

performance (capacity, injectivity, containment) 

during operations and long-term storage will be 

identified. Existing generic databases will be 

cross-referenced to project-specific information and 

location to identify the relevant risk pathways. The 

risk pathways so identified will be analyzed, and 

selected representative scenarios will be built. 

The representative scenarios identified will be 

analyzed in detail by means of dynamic analysis. 

The associated uncertainties will be estimated 

for sensitivity analysis. The likelihood of each 

representative scenario (operations and long term 

storage) will be assessed based on the results of 

the previous step, dedicated analysis/simulations, 

field data, and expert judgment. The consequences 

of each scenario will be assessed based on its 

impact on the relevant stakes (health, environment, 

properties/assets, authorities, public opinion, etc.) 

(scenario severity). The likelihood of each scenario 

will be combined with the consequence values 

to provide a risk estimate. The approach will be 

semi-quantitative and will provide the best estimate 

based on the current knowledge of the site and CO2 

behavior underground. 

Figure 6-3: Site characterization workflow plan designed to assess injectivity, capacity, and containment. 
		 	 	 	 	 	 	

 

	 	 	 	 	 	 		 	

		 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 		 	

6-14 6.0 MVA Developments for Large-Scale Tests in Various Settings 

6.3.4 MVA Activities 

Initial site environmental monitoring is designed 

to obtain a baseline of environmental parameters 

for at least one year before CO2

 is injected. This 

monitoring will benefit from experience to date at 

the small-scale enhanced oil recovery (EOR) pilots 

at which reservoir fluids, groundwater, gases in 

the vadose zone, and wellbore gas were sampled 

and analyzed. In addition, air monitoring will take 

place and will assist with monitoring as injection 

proceeds for the large-scale saline reservoir test. 

Reservoir monitoring will be baselined against a 

pre-injection 3-D seismic survey and possibly a preinjection vertical seismic profiles (VSP), depending 

upon the results of the initial 2-D survey and the 

cultural constraints with respect to the layout of the 

3-D survey. Geophysical techniques may include 

permanently placing geophones in the injection well 

that would facilitate microseismic monitoring and 

repeat VSPs. This appears especially appropriate 

given the cultural features on the surface. 

Monitoring will continue during injection and for 

two years post-injection. 

The MVA program will have operational, 

verification, environmental, and mitigation 

components. Data collection for each of these 

components will occur pre-, during, and postCO2

 injection. The operational component will 

provide information on the injected CO2

, injection 

formation, its response to CO2 injection, and the 

migration of the CO2 plume within the injection 

formation. The verification component will provide 

information to evaluate whether leakage of CO2 

through the caprock seal is occurring, and the 

environmental component will determine whether 

CO2

 is seeping into the biosphere. The mitigation 

component will describe action trigger levels to 

initiate additional monitoring and/or increase 

monitoring frequency to verify that CO2 leakage 

is occurring, the extent of leakage, and to provide 

actions to reduce or curtail the leakage. 

Tailoring the MVA program to the specific site with 

a yearly review will allow the monitoring program 

to focus on the greatest potential risks, as well 

as provide for a cost effective use of monitoring 

resources. Because of the limited data available

regarding the heterogeneity of the injection 

formation’s properties, it is envisioned that the 

program will be dynamic such that, as information 

is collected through the life of the project, 

monitoring can be directed toward areas that pose 

the greatest risk (Benson et al., 2004). Extensive

monitoring will initially occur at the injection well 

and in the anticipated plume footprint formed by 

the injection of 330,000 tons CO2

 annually for three 

years. Based on data collected during the initial

year of CO2 injection, with emphasis on 3-D seismic 

surveys to determine plume size and migration, the 

MVA program will be evaluated to ensure that data 

collection is occurring in areas where the plume is 

located and where it will migrate during the project 

period. 

Multiple techniques will be required to monitor CO2 

migration in the injection formation and to assess 

the potential for CO2 to breach the confining layer. 

Benson et al. (2004) provide an excellent summary

of the most common potential techniques that could 

be used in CO2 sequestration projects. Because

CO2

 sequestration is a fairly new concept, there are 

very limited field scale projects, so these techniques 

have not been fully tested and evaluated as to their 

suitability for this application. Table 6-4 provides 

a summary of potential monitoring techniques that 

could be used in each component of the monitoring 

program. A composite of these techniques will 

provide information regarding the (1) atmospheric, 

soil pore gas, groundwater, and formation CO2 

and hydrocarbon gas concentrations and isotopic 

signatures, (2) integrity of injection, production, and 

abandoned wells, (3) vegetative cover profiles in the 

vicinity of the site, (4) geophysical characterization 

of the injection formation and shallower geologic 

formations, and (5) shallow groundwater and 

formation geochemistry. 

In addition CO2

 transport model simulations 

in conjunction with operational monitoring, 

that includes injection volumes, injection well 

pressures, injection formation temperatures, and 

annulus pressures, will provide the information 

necessary to determine whether there is potential 

CO2

 leakage through the caprock. Modeling of 

the shallow groundwater will provide insights into 

groundwater flow directions and the potential for 

transport of groundwater that may be impacted by 

the CO2 injection process and require migration off 

site. Geochemical modeling will provide insights 

into the reactions and products of injected CO2 
 

 

 

 

 

 

	 	 	 	

 

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-15 

with formation matrix and fluids. Inconsistencies 

between field data and model predictions, which 

may suggest a leak, would trigger another level of 

monitoring to determine the CO2 plume location. 

The potential movement of CO2 in the unsaturated 

zone and the near-surface environment—in addition 

to atmospheric releases—will be evaluated using the 

multicomponent and multiphase reservoir simulator 

TOUGH2 (transport of unsaturated groundwater and 

heat) (Pruess et al., 1999). TOUGH2 will be coupled 

with LSM, (land-surface model) to account for plantcarbon dioxide interactions (Bonan, 1998).

Reactive transport and geochemical modeling of 

the fate of injected carbon dioxide and its effects 

on the chemical and mineralogical composition of 

the injection formation and confining layers will 

be studied using NUFT (non-isothermal/thermal, 

unsaturated/saturated, flow and transport model), 

a collection of databases and software (Nitao, 

1998). The geochemical database is applicable 

to a pressure range of 1 to 4,935 atm, and a 

temperature range of 32 to 1742 °F (0 to 1,000 °C). 

The geomechanical model LDEC (distinctelement geomechanical model) will be used in 

conjunction with NUFT to predict pressure-stress 

relationships. LDEC will be applied to assess caprock geomechanical deformation by simulating the 

evolution of microfractures created by the pressure 

of injected carbon dioxide (Johnson et al., 2004). 

Table 6-4: Summary of MVA Program to be Implemented at Large-Scale Injection Sites. 

Monitoring Technique Monitoring Period 

Pre-CO2 Injection During Injection Post-CO2 Injection 

Air quality monitoring 

Measure CO2 concentrations at injection well 

Measure CO2 fluxes using Eddy Covariance 

X 

X 

X 

X 

X 

X 

3-D seismic surveys, Vertical Seismic Profiles (VSP) X X X 

Injection well logging X X 

Measure pressure, gas content and isotopic signature in injection well X X X 

Monitor formation pressure, temperature, gas content, and formation fluid 

chemistry X X X 

Conduct High Resolution. Electrical Resistivity surveys X X X 

Measure CO2

 concentrations and isotopic signature in vadose zone X X X 

Determine shallow groundwater flow direction, install monitoring wells, 

geophysical logs, measure water quality X X X 

Measure water quality from potential residential and other potable water wells X X X 

Aerial imaging of injection site using satellite imagery X X 

Measure CO2 injection rates and volumes X 

Isotropic characterization of injected CO2 X 

Model potential geochemical reactions and CO2

 migration in injection formation, 

cap rock, and land surface X X X 

Add perflourocarbon tracer to injected CO2

 and monitor for tracer in vadose zone 

soil gases and groundwater. X X X 

Measure CO2 surface fluxes using accumulation chambers X X X 

Monitor microseismic activity near injection well X X X 

Wireline logs to assess subsurface characteristics X X X 
	 	 	 	 	 	 	 	 	 	

 

	 	 	 		 	 	 	 	 	

	 		 	 	 	 	 	 	

6-16 6.0 MVA Developments for Large-Scale Tests in Various Settings 

6.4 San Joaquin Valley Fluvial-Braided Deep 

Sandstone Test (High Porosity and Permeability) 

This project consists of an LVST at a power plant site 

in the Western United States. The location, which 

will provide both the CO2 and the injection site, is of 

particular interest because it overlies the San Joaquin 

Basin, part of the Great Valley province, which has the

largest potential storage capacity in California. 

The test will store 250,000 tons of CO2 per year for 

four years in a deep saline formation beneath the power 

plant. Clean Energy Systems’ (CES) Zero-Emissions 

Power Plant (ZEPP-1) will supply the CO2 for the test. 

Pre-operational phase activities will include permitting, 

public outreach, site characterization, and infrastructure 

development. Three formations beneath Kimberlina 

are possible targets: the Stevens at 7,000 feet, the 

Olcese at 8,000 feet, and the Vedder at 9,000 feet. 

Characterization activities will include reservoir 

modeling and a capacity assessment of these formations. 

An appraisal well will be developed and a test injection 

will be conducted using a smaller quantity of CO2. 

The actual selection of the target formation(s) will 

depend on the results from these early characterization 

activities. 

This will be one of the first large-scale GS efforts in 

the United States storing CO2 emitted by an industrial 

or power generation operation. The site will be 

thoroughly characterized before any injection begins, 

providing information for later commercial activities 

in which larger amounts of CO2

 may be sequestered. 

As the program develops, new methods for monitoring 

and validating capture and storage will be developed, 

demonstrated, and certified. 

A major aspect of developing new monitoring and 

modeling technologies and systems will be to accurately 

determine the amount of CO2

 being stored and retained. 

All aspects of the injection process will be rigorously 

monitored to check for leakage and to validate the 

volume of stored CO2

. This information will be 

critical in the development of any future measuring and 

monitoring systems for valuing and providing carbon 

credits for similar projects. 

The unique features of this project are that it involves 

injection of CO2

 recovered from power plant flue gas 

into a deep (~8,500 ft [~2,600 m]) saline sandstone 

formation of high porosity (up to 40 percent) and 

permeability (up to 2,400 mD). This project will 

provide data on the behavior of CO2

 in this type of 

venue and help validate mathematical models. 

6.4.1 Target Formation 

The site is located in the southern portion of the San 

Joaquin Basin in California. The focus of the study

is injection into saline formations, but the presence 

of nearby oil fields that could be potential EOR 

locations is an important consideration for future 

commercial business development. 

There are two sandstone units of primary interest— 

the Olcese and the Vedder. The Olcese, at a depth 

of about 8,000 feet (2,400 meters), is a regionally 

continuous, fluvial-estuarine unit of moderate 

injectivity. Its thickness at the site is up to 800 feet 

(240 meters). The Vedder, at a depth of 9,000 feet 

(2,700 meters), is also regionally continuous. At 

the site is a braided stream unit with a thickness 

up to 500 feet (150 meters). The combined storage 

estimate for the two units in the area beneath the 

site is about 440 million tons (400 million metric 

tons) of CO2

 in dissolved and residual capacity 

and about 1,650 million tons (1,500 million metric 

tons) of CO2 in physical capacity. Thick shale units 

provide a good overlying seal. 

Definition of the lithology near the site was 

provided by logs from site reference wells. The 

wells provided sufficient data to enable target 

sequestration formations and capacity estimates. 

The shallowest injection target is the 400-foot thick 

Stevens Sandstone located at about 7,000 feet depth. 

The depositional environment for the Stevens is a 

deep-water fan. Below the Stevens is the Olcese

and below that is the Vedder. 
	 	 		 	 	 	 	

	 	 	 	 	 	

 

 

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-17 

6.4.2 Site Characterization 

The LVST will take place on a 40-acre site in 

which the California ZEPP-1 and associated CO2 

storage and injection systems will be constructed. 

The site is located in the southern portion of the 

San Joaquin Basin. The largest potential storage

capacity for saline formations in the region is in the 

Central Valley. 

Successful GS of CO2

 requires thorough site 

characterization, especially for storage in 

saline formations that have not previously been 

considered an economic resource, as well as a clear 

understanding of the processes and mechanisms by 

which CO2

 is transported and trapped. A potential 

storage site must have the capacity to accept a large 

quantity of CO2 and the ability to effectively trap 

the CO2

 for a long time, thus demonstrating the 

economic feasibility of the project and its safety. A 

geologically realistic mathematical model of the 

multiphase, multi-component fluid flow produced by 

CO2

 injection is indispensable for determining the 

viability of a potential storage site, because capacity 

and trapping ability are both strongly impacted 

by the coupling between buoyancy flow, geologic 

heterogeneity, and history-dependent multi-phase 

flow effects, which is impossible to calculate by 

simpler means. Modeling may also be used to: 

(1) optimize CO2 injection by assessing the impact 

of various parameters, such as rates, volumes, 

and depths; (2) choose monitoring sensitivity 

and range by providing the expected formation 

response to CO2

 injection; and (3) assess the state 

of understanding by comparing model predictions 

to field observations. The following describes the 

site characterization activities that will take place 

during the three phases of the project: 

Site Characterization Phase: Regional geological 

information will be used to build an initial 

mathematical model of the storage site, including 

insights from oil field models of nearby petroleum 

resources. Data acquired from the first well drilled 

will be used to improve the model. Core data will 

be used to obtain estimates of permeability and 

porosity, fluid samples to assess water chemistry, 

well-test data to infer field-scale permeability, flow 

geometry, and boundaries of storage formation. If 

ambiguous results are obtained, alternative models 

will be developed to bound possible behavior. 

Data acquired from the second well will be used 

to improve the model and assess variability and 

continuity between the two wells. As was the 

case with the first well, if ambiguous results are 

obtained, alternative models will be developed 

to bound possible behavior. The planned CO2 

injection will be modeled to assess the capacity of 

storage formations. 

Injection Phase: The injection phase will include 

modeling of actual CO2 injection using all available 

models. Modeling results will be compared to field 

observations: 

•	 Pressure response at injection and observation wells

•	 CO2

 distribution in injection well (RST, sampling) 

•	 CO2

 arrival at observation well (RST, sampling) 

Second-generation model(s) will be generated based 

on incorporating lessons learned from comparison 

to field observations. This new model(s) will be 

used to simulate multiple years of CO2

 injection and 

storage. 

Post-Injection Phase: Modeling of the injected CO2 

plume using the improved model in order to predict 

plume fate and transport over hundreds of years. 

6.4.3 Risk Assessment and Mitigation Strategy 

Risk assessment will be a key ongoing activity that 

will drive the future activities of the project. At 

each project decision point, the risk assessment 

will be reviewed, and the decision to proceed to the 

next phase will depend on the ability of the project 

partners to manage the assessed risks. 

The plan is to inject 250,000 tons of CO2 per 

year for four years into the saline formations. 

The geology, structure, tectonics, and reservoir 

properties of this subsurface volume are well 

recognized from experience with drilling and 

production from nearby oil fields. This geology 

makes prediction of injectivity, injection-induced 

pressure increases, brine flow pathways, CO2 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6-18 6.0 MVA Developments for Large-Scale Tests in Various Settings 

migration, and trapping behavior relatively 

straightforward, and the general effects and potential 

impacts of the injection of CO2 can be anticipated. 

First, CO2 injection will increase pressure in the 

formations, altering the ambient stress state and 

potentially causing induced seismicity (microearthquakes) during injection activities. Second, 

CO2 injection will displace saline groundwater in the 

formation. Displaced brine will follow the path of 

least resistance and, depending on the magnitude and 

direction of displacement, saline groundwater could 

affect shallower aquifers or hydrocarbon reservoirs. 

Third, injected CO2 will tend to migrate under 

buoyancy forces, generally upward along the path of 

least resistance. During migration, CO2 will dissolve 

in formation waters and undergo residual phase 

trapping, thereby attenuating the migration rate. 

To constrain risk assessment and mitigation, it is 

essential to target some fraction of characterization 

efforts toward obtaining information about the 

most important features and properties relevant 

to evaluating potential impacts. For example, 

pre-injection testing to determine injectivity to 

minimize the potential for induced seismicity for 

a given planned injection rate. Hydrologic well 

testing to determine the extent of connectivity of 

the injection zone with shallower aquifers will help 

establish the extent and effectiveness of sealing 

formations. Artificial flow pathways created by 

exploration and water production wells need to 

be identified and evaluated. Historical records of 

water or HC seepage in the area may also be useful 

in understanding flow pathways between reservoirs 

and the near-surface environment. Finally, fluid 

sampling and analysis of deep and shallow HC and 

aqueous, gas, and liquid phases could be useful to 

establish whether flow paths exist from the deep 

subsurface to shallower formations. Fluid analyses 

could include bulk composition, trace gases, and 

isotopic composition to establish relationships 

between the fluids, their origins, and their ages. 

Consideration of the results of the risk assessment 

will allow prioritization of mitigation planning. 

For example, a high risk of CO2

 migration up 

abandoned exploration boreholes in the area 

would point to the need for a plan to mitigate this 

potential conduit. Similarly, contamination of 

shallow potable water by CO2

, although highly 

unlikely, may prove to be the highest risk of several 

very low risk events. As the highest risk event, a 

plan to produce CO2 charged water and re-inject 

it in deeper formations, or to otherwise stop the 

CO2 migration from entering the aquifer, may 

be needed. Planning for near-surface mitigation 

measures may also be needed, even though the 

probability of such an event is exceedingly small, 

because the potential impact would be large given 

the urban setting. Near-surface mitigation might 

include capping of leaking wells and establishing an 

exclusion zone around a seep until it can be sealed 

or stopped by subsurface fluid withdrawals. 

6.4.4 MVA Activities 

Monitoring the injection of CO2

, pressure buildup, 

and associated plume migration will be an essential 

component of the project. First and foremost, 

monitoring will be used to detect and identify any 

safety hazards or environmental risks associated 

with the demonstration project. Data collected on 

rates of CO2 plume migration, pressure buildup, and 

geochemical interactions will also provide valuable 

scientific information that will be used to refine 

and enhance computer models that predict storage 

performance. 

Monitoring will begin during the characterization 

phase of the project and continue over the entire 

nine-year duration of the project. The monitoring 

program will be carried out in three phases, in 

conjunction with the activities being carried out 

at the site, namely the pre-operational phase, 

operational phase and closure phase of the project. 

During the preoperational phase, the geology of 

the site is characterized; the environmental, health 

and safety risks are identified; baseline conditions 

are established; small-scale injection tests may 

be conducted to understand and help optimize 

storage processes and injection operations; the 

injection operation is defined; monitoring plans 

are developed; environmental and operational 

permits are obtained; injection wells are drilled; 
	 	 	 	 	 	 	

	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	

	 	 	 	 	

	 	 	 	

	 	 	 	 	

	 	

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-19 

and surface facilities are constructed. During the 

operational phase of the project, which is expected 

to last four-years, CO2

 will be injected into the 

reservoir; surface facilities and injection rates will 

be monitored; the location of the plume will be 

tracked; and other monitoring activities will be 

conducted. The closure phase of the project begins 

when CO2 injection has stopped. This phase of the 

monitoring program will be used as a confirmatory 

period to detect continued movement of the plume, 

detect any potential leakage, and to assess whether 

the storage project is performing as expected. 

Computer simulation with the TOUGH2 and 

TOUGHREACT models will also be used 

throughout all phases of the project. During 

the pre-operational phase, simulation models 

will be used to predict plume migration and the 

effectiveness of solubility, residual gas (capillary) 

and mineral trapping. During operations, 

comparison between simulated and monitored 

plume migration will be used to refine and 

calibrate the model—then update forecasts of 

plume migration. This iterative approach will be 

used to develop confidence in predictions of plume 

behavior. During the post-operational phase, a 

similar iterative approach will be used to predict 

post-injection plume behavior—with a primary 

focus on quantifying the secondary trapping 

mechanisms that will eventually immobilize the 

CO2

. TOUGH2 and TOUGHREACT have both 

been used worldwide for simulating GS of CO2

 and 

are acknowledged to be among the best models for 

simulating GS of CO2 in brine formations. 

Specific objectives of the monitoring program are to: 

•	 Obtain baseline data on reservoir pressure, water

quality, CO2

 fluxes from the land surface to the 

atmosphere and seismic activity. 

•	 Quantify the amount of CO2

 injected into the 

saline reservoir. 

•	 Monitor the pressure buildup in the saline

reservoir. 

•	 Assess the condition of the injection well.

•	 Detect induced seismicity associated with CO2 

injection. 

•	 Track migration of the injected CO2

 plume in the 

storage reservoir. 

•	 Detect potential leakage of CO2

 out of the storage 

formation to overlying strata. 

•	 Detect brine displacement associated with CO2 

injection. 

•	Measure CO2 fluxes from the land surface into the 

atmosphere. 

Information will be obtained from a comprehensive 

suite of measurements which will provide sufficient 

information to judge the safety and security of the 

saline reservoir demonstration test. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

6-20 6.0 MVA Developments for Large-Scale Tests in Various Settings 

Figure 6-3: Schematic Showing Overall Monitoring Approach for Saline Formation LVST 

An overall schematic of the monitoring approach is 

illustrated in Figure 6-4. Measurements in the storage 

reservoir will be acquired from the injection well 

and a purpose-built monitoring well. Plume tracking 

will be carried out using a combination of direct 

measurements from the injection and monitoring well 

and indirect observations using seismic imaging. In 

particular, walk-away VSP will be used annually to 

monitor the footprint of the plume as it migrates away 

from the injection well. Monitoring for leakage out of 

the primary storage reservoir will be carried out using 

direct observations from the injection and monitoring 

wells, as well as from seismic imaging. Surface flux 

monitoring data will be obtained from a combination 

of flux chamber measurements, wellhead CO2 sensors, 

and flux towers. 

The monitoring program will be generally based 

on the “enhanced monitoring package” outlined 

in the IEA Greenhouse Gas Programme (IEA 

GHG) sponsored project described in Benson et al.

(2005b). This general approach will be augmented 

with recent advances in monitoring, particularly, 

high resolution real-time seismic monitoring 

that has been developed as part of the Frio Brine

Pilot (Daley et al., 2007) and surface monitoring 

technology developed as part of the ZERT Project 

(Lewicki et al., 2007a). Advances in monitoring 

technology developed by DOE’s RCSP Program 

will also be included in the program. 

The proposed monitoring program for each 

phase of the project is summarized in Table 6-5 

and compared to the “basic” and “enhanced” 
	 	 	 	 	 

 

	 	 	 	 	 	 	 	

 

 

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-21 

monitoring packages recommended in Benson

et al. (2004). All of the elements of the “basic” 

monitoring program are included in the proposed 

monitoring plan, and most of the elements of the 

enhanced monitoring plan are also included. In 

addition, several new approaches have been added 

that are briefly described below. 

Wells Logs: A suite of well logs will be run as part 

of the characterization program that will also provide 

baseline information for the monitoring program. 

Logs of particular importance for ongoing monitoring 

include RST, formation resistivity, sonic log and CBL,

and pressure and temperature. At a minimum, the 

logs will be collected to provide baseline data for 

Table 6-5: Basic and Enhanced Monitoring Packages and 

a Comparison to the Proposed Monitoring Program 

Basic Monitoring Package Enhanced Monitoring Package San Joaquin Valley 

Sandstone Test 

Pre-Operational Monitoring 

Well logs 

Wellhead pressure 

Formation pressure 

Injection and production rate testing 

Seismic survey 

Atmospheric CO2 monitoring 

Well logs 

Wellhead pressure 

Formation pressure 

Injection and production rate testing 

Seismic survey 

Gravity survey 

Electromagnetic survey 

Atmospheric CO2 monitoring 

CO2

 flux monitoring 

Pressure and water quality above the 

storage formation 

Well logs 

Wellhead pressure 

Formation pressure 

Injection rate testing 

Seismic survey (VSP) 

Atmospheric CO2 monitoring 

CO2 flux monitoring 

Pressure and water quality above the 

storage formation 

Microseismic monitoring 

Operational Monitoring 

Wellhead pressure 

Injection and production rates 

Wellhead atmospheric CO2 

monitoring 

Microseismicity 

Seismic surveys 

Well logs 

Wellhead pressure 

Injection and production rates 

Wellhead atmospheric CO2

 monitoring 

Microseismicity 

Seismic survey 

Gravity survey 

Electromagnetic survey 

Continuous CO2

 flux monitoring 

Pressure and water quality above the 

storage formation 

Well logs 

Wellhead pressure 

Formation pressure 

Annulus pressure 

Injection rate 

Seismic survey (VSP and cross well) 

Atmospheric CO2 monitoring 

CO2 and O2 flux monitoring 

Pressure and water quality above the 

storage formation 

Microseismic monitoring 

Active source thermal logging 

Closure Monitoring 

Seismic survey Seismic survey 

Gravity survey 

Electromagnetic survey 

CO2

 flux monitoring 

Pressure and water quality above the 

storage formation 

Wellhead pressure monitoring 

Seisntic survey (VSP) 

CO2 and O2 flux monitoring 

Pressure and water quality above the 

storage formation 
 

 

 

 

 

 

 

 

 

 

 

 

	 	 	 	 	 	 	

	 	 	 	 	 	

 

 

 

 

6-22 6.0 MVA Developments for Large-Scale Tests in Various Settings 

monitoring in the assessment well. A similar suite of 

logs will also be obtained once the monitoring well is 

drilled. Periodically repeated measurements of these 

logs will provide information on CO2 saturations, 

brine displacement and movement, and condition of 

the well casing and cement. 

Formation, Wellhead and Annulus Pressure: The 

pressure in the formation, at the wellhead inside 

the injection tubing, and in the annulus between 

the injection tubing and the well casing will be 

continuously monitored to ensure they remain below 

pre-established levels. Unanticipated changes will 

provide an indication that the injection equipment or 

well installation may not be performing as expected 

or is leaking. Excessively high formation pressures 

would indicate that the injection rate is too high and 

increase the potential for induced seismicity. 

Injection Rate: Injection rates will be monitored to 

accurately account for the mass of CO2

 injected into 

the storage formation. 

Seismic Surveys: Seismic imaging has been shown 

to be a reliable method for tracking the migration 

of CO2 in subsurface environments (Benson et al.,

2005b; Daley et al., 2007; Hovorka et al., 2006). 

Various geometric configurations of sources and 

sinks can be used to acquire images of the plume, 

namely, surface seismic, surface-to-borehole 

(e.g., VSP) and borehole-to-borehole (crosswell). 

Seismic imaging can also be used to detect leakage 

of CO2 if secondary accumulations occur (Benson,

2007). In general, surface methods provide 

larger spatial coverage, but borehole methods 

provide higher spatial resolution. Additionally, 

recent developments in borehole methods provide 

the opportunity for real-time and continuous 

monitoring, which further enhances data quality 

and confidence (Daley et al., 2007). A VSP 

program is proposed that would use discrete surface 

source points (whose location would be determined 

by site access and availability along with seismic 

modeling of the volume to be monitored) and a 

permanently deployed sensor string. The sensor 

string should be deployed in the assessment 

well to allow for pre-injection monitoring. The 

potential for the use of crosswell imaging during 

the operational phase will be assessed during the 

characterization phase. 

Atmospheric CO2

 Monitoring: CO2 concentrations 

will be monitored at the wellhead for both injection 

and monitoring wells. The CO2

 sensors will be 

equipped with an automated alarm system to 

identify potentially unsafe conditions in the vicinity 

of the injection well, monitoring well and surface 

injection facilities. 

CO2 and O2 Flux Monitoring: Direct measurements 

of CO2 fluxes can be obtained using flux ACs and/ 

or EC flux towers. Two approaches will be used 

for assessing baseline fluxes, namely flux ACs and 

EC towers, to characterize anthropogenic emissions 

in the area. One potentially promising approach 

is to simultaneously measure O2 fluxes, which are 

anti-correlated with CO2

 fluxes from combustion 

sources. In this way, anthropogenic sources 

from combustion (e.g., automobiles and power 

generation) can be distinguished from releases of 

the injected CO2

. Verification Facility experiments 

beginning this summer will be incorporated into the 

flux monitoring program. Potential technologies 

include carbon isotope analysis, open-path laser 

measurements, and soil gas sampling. 

Pressure and Water Quality above the Storage 

Formation: Pressure measurements provide 

a sensitive method to detect leakage of CO2 or 

brine from the storage reservoir, particularly if 

there is a thin and permeable formation above 

the primary seal. The monitoring well will be 

equipped with a downhole pressure transducer to 

measure small changes in pressure as a means of 

detecting leakage. In addition, formation water 

samples from a monitoring zone above the storage 

reservoir will be sampled prior to injection to obtain 

baseline water quality information. Formation 

water samples will also be collected at the end of 

the injection period or periodically throughout the 

test period. If the pressure data suggest that leakage 

may be occurring, formation water samples will be 

collected to provide additional information to assess 

whether or not there is leakage. 

Microseismic Monitoring: An array of geophones 

will be installed to detect, locate, and interpret any 

microseismic activity in the area of the project in 

the pre-operational, operational, and closure phases 

of the project. An estimated 120 geophones will be 

installed in the monitoring well, extending from a 
 

 

	 	 		 	 	 	 	

	 	 	 	 	 	 	 	 	 		

	 	 	 	 	 	 	 	 	

	 		 	 	 	 	 	 	

	 		 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-23 

depth of 2,000 feet to a depth of about 8,200 feet. 

These same geophones will be used for active source 

seismic monitoring using the VSP method. 

Active Source Thermal Logging: A new boreholebased method for monitoring fluid movement and 

sensing the saturation of CO2 continuously and in 

real-time is being tested at the CO2

 Sink Project 

in Berlin, Germany. The basic concept uses fiberoptic temperature sensors to measure the rate of 

heat dissipation from a heater—which depends 

on the rate of fluid flow and the heat capacity of 

the formation. If the concept proves successful in 

the CO2 Sink Project, the monitoring well will be 

equipped with an Active Source Thermal Logging 

system. 

6.5 Williston Basin Deep Carbonate EOR Test 

This project includes injection of CO2 for sequestration 

and EOR in select oil fields in the Williston Basin.

The primary objectives of this activity are (1) to 

gather characterization data that will verify the ability 

of the target formations to store CO2, (2) to develop 

infrastructure to transport CO2 from the source to 

the injection site, (3) to advance the regulatory and 

permitting framework in North America, (4) to provide 

a test bed for developing technologies related to 

sequestration of anthropogenic CO2

, and (5) to develop 

a mechanism by which carbon credits can be monetized 

for CO2 sequestered in geologic formations. 

Several R&D issues will be addressed by the Williston

Basin test. R&D activities will be specifically focused

on predictive modeling, capture, injection, and 

monitoring operations to demonstrate that large-scale 

sequestration of CO2

 in oil fields is a viable strategy 

for sequestering significant amounts of CO2 within 

the region. The Williston Basin project will transport

a minimum of 500,000 tons of CO2

 per year from an 

anthropogenic source (PC plant) and inject it into an 

oil reservoir. The power plant will be retrofitted with 

a system that can capture CO2

 from flue gas. The CO2 

will be compressed and transported in a supercritical 

state via pipeline to the injection location. 

A specific oil field has not yet been chosen to be the 

host site for the Williston Basin large-volume CO2 

injection test. The results of regional characterization 

activities indicate that there are at least several unitized 

oil fields in the Great Plains Region that may be suitable 

for CO2

-based EOR operations. 

The primary objective of the Williston Basin test is to

verify and validate the concept of utilizing the region’s 

large number of oil fields for large-scale injection of 

anthropogenic CO2. Rigorous, robust, and cost-effective 

programs for baseline site characterization, risk 

assessment, and MVA will be conducted. The results 

of the study will be broadly applicable throughout the 

region, as there are many oil fields in the area. Oil 

fields are generally much better characterized than 

saline formations, already legally established for the 

purpose of safe large-scale manipulation of subsurface 

fluids, and offer a means to offset the considerable costs 

of CO2

 capture and transportation through the sale of 

incrementally produced oil. These attributes make oil 

fields the most cost-effective choices in the region when 

implementing large-scale CO2

 sequestration projects. 

CO2

 will be obtained from a regional PC plant and 

transported via pipeline to the sequestration site that is 

anticipated to be approximately 150 to 200 miles away. 

Pipeline transportation and subsequent EOR require 

a dry gas stream containing at least 95 wt% CO2

 and 

low levels of any other corrosive contaminants, such as 

hydrogen chloride (HCl) or sulfuric acid (H2SO4). 

This project is unique in that it will inject CO2 

recovered from the stack gas of a power plant 

into a deep (>10,000 feet) carbonate reservoir for 

simultaneous CO2 storage and EOR. This will differ 

from a normal EOR project, where the objective is to 

maximize oil production per ton of CO2 injected, in that 

the objective will be to maximize CO2

 storage. 

6.5.1 Description of Target Formations 

Hundreds of oil fields in the region have been 

thoroughly characterized since the discovery 

of oil in the Williston Basin in the early 1950s.

Thousands of wells have been drilled into a variety 

of zones throughout the basin. Depths of the wells 

range from a few thousand feet to over 14,000 feet 

in the basin’s center. Formation fluid production 

and water injection data from many of these wells 

provide insight into formation injectivity and 

permeability, as well as the integrity of overlying 

seals. At the oil field and reservoir level, a 

significant amount of historical data exists for each 

field, including well logging data for the reservoir 
	 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 		 	 	

	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 		 	 	

6-24 6.0 MVA Developments for Large-Scale Tests in Various Settings 

and seals, fluid analyses, fluid production and water 

injection data, and other key reservoir dynamics 

data. Geophysical surveys for many areas exist, but 

the availability, precise nature, and applicability of 

the survey data with respect to the project have yet 

to be determined. 

The Williston Basin is a relatively large,

roughly circular, intracratonic basin with a 

thick sedimentary cover in excess of 16,000 

feet. It covers several hundred thousand square 

miles across parts of Montana, North Dakota, 

South Dakota, and the Canadian provinces of 

Manitoba and Saskatchewan. Deposition in the 

Williston Basin occurred during all periods of

the Phanerozoic. The stratigraphy of the area is 

well studied, especially in those intervals that are 

oil-productive. Traps in the region are generally 

controlled by structure or a combination of structure 

and stratigraphically derived porosity changes. 

While general information on the structural 

geology, lithostratigraphy, hydrostratigraphy, and 

petroleum geology of the Williston Basin is readily

available, additional characterization data for 

specific candidate sinks will be necessary before 

their utilization as CO2

 storage sites. Detailed maps 

of critical elements, such as formation thickness, 

porosity, permeability, and water salinity, will need 

to be developed and the competency of regional 

traps will have to be determined based on further 

evaluations. 

6.5.2 Regional Characterization 

The target formation and its overlying sealing 

formation at any site that is considered a potential 

location for large-scale CO2

 injection operations 

must be thoroughly characterized at local, 

intermediate, and large scales in the early stages of 

the planning process. These early characterization 

activities are necessary to develop accurate 

predictions with respect to storage capacity and the 

ultimate fate of CO2 within the target formation. 

The data from early characterization, in part, 

provide the baseline information necessary to 

design and conduct cost-effective MVA strategies. 

Site characterization activities will be conducted to 

develop predictive models that address three critical 

issues to determine the ultimate effectiveness of 

the target formation: (1) the capacity of the target 

formation, in this case a unitized oil-producing 

reservoir within an established oil field; (2) the 

mobility and fate of the CO2

 at near-, intermediate-, 

and long-term time frames; and (3) the potential 

for leakage of the injected CO2

 into overlying 

formations and/or the surface. Baseline site

characterization will be accomplished using a wide 

variety of data. Previously conducted oil field 

exploration and operational activities are expected 

to provide significant baseline characterization data, 

but it is anticipated that new data will also have to 

be gathered to fill gaps not adequately covered by 

the historical oil field data. 

Data obtained and compiled as part of the baseline 

characterization will provide the basis for a variety 

of modeling activities. The primary components 

of the modeling will be the development of (1) a 

geologic model that incorporates local (oil field), 

sub-regional (i.e., Cedar Creek, Nesson, or Billings

Anticlines), and regional (Williston Basin) scale

stratigraphy and architecture; (2) a hydrogeological 

model that operates at the local and sub-regional 

scales; and (3) a reservoir dynamics model for 

the selected reservoir. These will form the basis 

for developing MVA plans and conducting risk 

assessments of intermediate- and long-term effects 

of large-scale CO2 injection. 

6.5.3 Site Development 

The estimated injectivity of various reservoirs 

suggests that two to eight vertical injection wells 

will be sufficient for meeting the injection target of 

1 million tons of CO2

 per year. Site development 

may include conducting a small-scale pilot test. 

It is anticipated that currently existing wells in 

the oil field will be used as injectors, producers, 

and monitoring wells, but the need for drilling 

new wells has not been dismissed. Because the

operation will include an EOR component, it is 

also likely that, at some point in the operation, a 

considerable volume of CO2 will be produced with 

the oil, requiring infrastructure and equipment 

for capturing, recompressing, and re-injecting 

the produced CO2

. Thus, site design may include 

capture and compression equipment for CO2 

processing, pumps for CO2 injection, and equipment 

for monitoring (e.g., pressure, temperature and 

strain gauges, and fluid sampling equipment). It is 

expected that both borehole and surface monitoring 

tools will be used along with wireline logging 
	 	 	 		 	 	 	 	 	

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-25 

techniques. Use of tracers, fluid sampling, pressure, 

and deformation monitoring along with numerical 

modeling will be applied to definitively determine 

the area that will be affected by the injection. 

6.5.4 Risk Assessment and Mitigation Strategy 

Table 6-6 lists risks associated with the different 

stages of the CO2

 sequestration process in a 

Williston Basin oil field. No attempt was made to

list all the consequences of the events presented 

(e.g., leakage can affect potable water quality, 

reactivation of faults can entail seismic activity, 

etc.). Strategies to quantify and mitigate the risks 

are also listed in this table. 

For large-scale demonstrations, it is anticipated 

that a database of features, events, and processes 

specific to the considered environment will be 

created. A numerical model of the reservoir will be 

created and a sensitivity analysis will be performed 

with respect to the factors listed in the database. 

The analysis will allow for the quantification of the 

risks associated with the factors. The numerical 

model will be constantly updated based on the 

results of the monitoring program. As the model is 

updated, risks will be assessed to ensure safety of 

the operations and storage. 

Table 6-6: Summary of the Potential Risks Associated with Large-Scale Injection of CO2 

Project Phase Associated Risks Quantification and Mitigation Strategy 

Site Problems with licensing and permitting The program for site development will be reconsidered in the event of 

Development failure to obtain licenses and permits. The changes to the design can 

include, but are not limited to, revising the injection rates, the number 

of injection wells, and zonal isolation. 

Poor condition of the existing wellbores 

Lower-than-expected injection rates 

All wells located in the vicinity of the injection site will be tested for well 

integrity and recompleted as necessary. 

Basing on the results of the initial injection or a pilot test, reasonable 

injection rates will be determined. If actual injection rates do not meet 

the target, additional wells and/or pools will be added. 

Operations Significant rates of vertical CO2

 migration 

Activation of the preexisting faults and/ 

or fractures 

The monitoring program will allow for early warning regarding vertical 

migration, fault reactivation, and damage to the target or adjacent 

formations. If a warning is received, the injection program will be 

reconfigured. 

Substantial damage to the formation 

and/or caprock 

Failure of the wellbores 

Lower-than-expected injection rates 

Damage to the adjacent oil fields and/or 

producing horizons 

Failure of the wellbores 

Lower-than-expected injection rates 

In the event of wellbore failure, the well will be recompleted or shut off. 

Additional wells and/or pools will be included in the injection program. 

Long-Term Leakage through preexisting faults or The strategy of mitigating leakage through faults will be chosen 

Storage fractures 

Leakage through the wellbores 

depending on measured and/or anticipated rates of leakage. It can 

include, but is not limited to, decreasing formation pressure and 

treating the fractures with cement. 

All wells in the vicinity of the injection site will be periodically tested. In 

case of leakage, wells will be recompleted and/or plugged. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6-26 6.0 MVA Developments for Large-Scale Tests in Various Settings 

6.5.5 MVA Activities 

The development and execution of effective MVA 

operations are a critical element in conducting 

large-scale injection projects. Successful MVA 

activities will result in data that verify that injection 

operations do not adversely impact human health or 

the environment and validate the sequestration of 

CO2

 for the purpose of developing and ultimately 

monetizing carbon credits. A broad range of 

technologies and approaches have been applied to 

CO2 sequestration projects of various scales around 

the world. Early geological sequestration research 

and demonstration projects focused on testing a 

wide variety of MVA strategies. The absence of 

experience required early projects to gather as much 

data as possible using a wide variety of techniques. 

In particular, a desire to visually represent the plume 

of injected CO2 led to a strong emphasis on the use 

of geophysical data, especially 3-D and 4-D seismic, 

to monitor the plume. While geophysical-based 

approaches and techniques yielded valuable results 

in early projects that are essential to the development 

of geological sequestration as a CO2 mitigation 

strategy, their high costs and often limited ability to 

identify CO2 in geologic settings will likely render 

their use the exception rather than the rule when it 

comes to developing MVA plans for future projects. 

Where sequestration is associated with EOR 

operations, it is also important that MVA activities 

have minimal impact on commercial injection and 

production operations. MVA activities need to be 

coordinated and integrated as much as possible 

with ongoing and planned oil field operations. An 

emphasis on the collection of reservoir dynamics 

and monitoring well data (including the use of 

tracers) in conjunction with routine well operation 

and maintenance activities can, in some geological 

settings, be an appropriate and cost-effective 

strategy for MVA. At a minimum, the techniques 

listed below will be employed to monitor the effects 

of CO2

 injection at the site. The pre-injection state 

of each of these parameters will be determined 

by site characterization activities, either through 

the evaluation of historical data or focused field 

activities to acquire new data: 

•	 To monitor the CO2 plume: 

– Reservoir pressure monitoring 

– Wellhead and formation fluid sampling 


(oil, water, gas)
 

– Geochemical changes identified in observation 

or production wells 

•	 To provide early warning of storage reservoir 

failure: 

– Injection well and reservoir pressure monitoring 

– Pressure and geochemical monitoring of 


overlying formations
 

– Downhole geophysical monitors (microseismic 

and/or tiltmeters) 

•	 To monitor injection well condition, flow rates, 

and pressures: 

– Wellhead pressure gauges 

– Well integrity tests 

– Wellbore annulus pressure measurements 

– Surface CO2

 measured near injector points and 

high-risk areas 

•	 To monitor solubility and mineral trapping: 

– Formation fluid sampling using wellhead or 


deep well concentrations of CO2
 

– Major ion chemistry and isotopes 

•	 To monitor for leakage into overlying formations 

through faults or fractures: 

– Reservoir and overlying formation pressure 


monitoring
 

– Monitoring for tracers (e.g., PFCs) 
	 	 	 	 	 	

	 	 	 	 	

	 	 	 	 	 	 	

 

6.0 MVA Developments for Large-Scale Tests in Various Settings 6-27 

6.6 Impact of Secondary and Potential Additional 

MVA Technologies on Large-Scale Storage 

Secondary and Potential Additional Technologies are 

commonly applied in research applications to aid in 

accounting for injected CO2, providing insight into CO2 

behavior, and helping answer fundamental questions 

concerning the transport and fate of injected CO2 (see 

page A1-2 for definitions of primary, secondary, and 

potential additional technologies). While Primary 

Technologies can validate that leakage pathways 

from the injection process have not been created and 

that CO2 has remained sequestered underground, 

Secondary and Potential Additional Technologies are 

fully capable of confirming, as well as expanding upon, 

information gained from Primary Technologies by 

providing data over larger scales and generating details 

about the plume front. The case study tests described 

in Sections 6-1 through 6-5 are focused on employing 

MVA protocols consisting of Primary, Secondary, 

and Potential Additional Technologies for specific 

geological settings in order to assess CO2

 behavior 

under large-scale injection scenarios. 

Secondary and Potential Additional monitoring 

techniques can have considerable advantages over 

existing MVA technologies by providing more 

insightful data over larger scales. Determining the 

areal extent of the plume is a critical issue when 

developing any MVA package. For instance, Primary 

Technologies, including water quality and geochemical 

analysis, can pinpoint elevated CO2

 levels in water/ 

brine formations from locations in which samples 

are drawn. Multiple sampling locations (required by 

monitoring wells) would have to be generated around 

the site vicinity in order to confidently determine 

plume migration in all directions (horizontally and 

vertically). Several of the case studies (see Sections 

6.1 to 6.5), including the Nugget Sandstone Test, 

Gulf Coast Strandplain Deep Sandstone Test, and 

San Joaquin Valley Fluvial-Braided Deep Sandstone

Test, have indicated employing some form of seismic 

surveying (2-D, 3-D, VSP, microseismic) as a cost 

effective way to determine the areal extent of plume 

propagation over a large spatial range as opposed to 

drilling. In addition to determining plume migration, 

seismic surveying also has applications in assessing 

seal-formation integrity (using time-lapse images of 

the seal for all project phases) and adding detail to site 

geologic structure and stratigraphy; a task accomplished 

by a combination of extensive wireline logging and 

sample coring at several locations, as well as multiple 

physical testing applications (injection volume/rate, 

wellhead pressure, downhole pressure and temperature). 

Seismic surveying is one example of how the projects 

outlined in Sections 6.1 to 6.5 implement Secondary 

and Potential Additional Technologies to build upon and 

verify results from Primary Technologies. 

Assessing potential leakage pathways is another key 

MVA goal in any GS project. Primary technologies 

can be used to identify characteristics related to 

potential leakage pathways, including quantifying 

CO2

 concentrations in fluid/brine and soil gas before, 

during, and after injection operations, assessing 

wellbore integrity during all project phases, monitoring 

physical and chemical properties of rocks and fluids 

immediately adjacent to the wellbore (via wireline 

logs), and alarming on elevated levels of CO2

 in the 

atmosphere. Storage projects, including the Gulf Coast 

Strandplain Deep Sandstone Test, Mt. Simon Shallow 

Sandstone Test, San Joaquin Valley Fluvial-Braided

Deep Sandstone Test, and Williston Basin Deep

Carbonate EOR Test, are coupling air, soil gas, and 

groundwater/brine sampling with tracers to distinguish 

injected CO2

 found in the air, soil, or subsurface fluid 

from naturally-occurring CO2

. Tracers detected above 

the injection zone in either the atmosphere, soil gas, or 

groundwater would be a direct indication of a leakage 

pathway somewhere in the target formation and validate 

results from Primary Technologies sampling efforts. 

Secondary and Potential Additional Technologies, such 

as EC, flux ACs, and the Advanced Leak Detection 

System (or similar), can be used in conjunction with 

tracers to pinpoint the location of CO2

 fluxes from the 

surface, enabling prompt and effective remedial action. 

The level of use of Secondary and Potential Additional 

Technologies in the case studies goes well beyond what 

is anticipated for commercial GS projects. The role 

of Secondary and Potential Additional technologies 

applies mainly to research applications to gain further 

understanding for CO2 accounting and to help answer 

fundamental questions concerning transport and fate 

of injected CO2

. In current GS research applications, 

Secondary and Potential Additional Technologies 

are used to help confirm, as well as expanding upon, 

information gained from Primary Technologies. In the 

case studies, research-based MVA packages that include 
	 	 	 	 	 	

6-28 6.0 MVA Developments for Large-Scale Tests in Various Settings 

multiple tools from Primary, Secondary, and Potential 

Additional Technologies categories were selected to 

fully understand all aspects of CO2

 behavior. MVA 

packages were not based solely on site geology, which 

will be a key factor in deciding tailored MVA protocols 

for commercial injections (Benson et al., 2002b).

6.7 Future Implications from Case Study MVA 

Packages 

The research-based MVA packages of the case studies 

were developed prior to the site characterization and 

injection phases of the projects. The packages were 

arranged to include multiple tools that were fully 

capable of monitoring all aspects of CO2

 behavior 

associated with large-scale injection, obtain new 

knowledge about GS, and allow for monitoring tools 

to be compared and contrasted within a given project 

and across different geologies. Insight about the 

performance of MVA technologies under multiple 

geologic scenarios will enable future GS projects (for 

either commercial or research purposes) meet their 

monitoring needs by optimizing MVA packages that 

best suit both the site and regional characteristics. 
	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 		 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 		 	 		

	 	 	 	 	 	 	 	 	 	 	 	 		 	 	 	 	

 

	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

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Riddiford, F., Wright, I. G., Bishop, C., Espie, A. 2008 Monitoring GS, The In Salah Gas CO2

 Storage Project. 

Accessed June 12, 2008. http://uregina.ca/ghgt7/PDF/papers/nonpeer/529.pdf. 

Sakurai, S., Ramakrishnan, T.S., Boyd, A., Mueller, N., and Hovorka, S.D. 2005. Monitoring saturation changes of

CO2 sequestration: Petrophysical support of the Frio brine pilot experiment. Presented at: Society of Petrophysicists 

and Well Log Analysts 46th Annual Logging Symposium, New Orleans, Louisiana. 

Savage, D., Maul, P.R., Benbow, S., and Walke, R.C. 2004. A generic FEP database for the assessment of long-term

performance and safety of the GS of CO2

, Version 1.0. 

Shevalier, M., Durocher, K., Perez, R., Hutcheon, I., Mayer, B., Perkins, E., and Gunter, W. 2004. Geochemical

monitoring of gas-water-rock interaction at the IEA Weyburn CO2 Monitoring and Storage Project, Saskatchewan, 

Canada. In: Greenhouse Gas Control Technologies: Proceedings of the 7th International Conference on Greenhouse 

Gas Control Technologies 5-9 September 2004, Vancouver, Canada. Vol. II. Wilson, M., Morris, T., Gale, J., and 

Thambimuthu, K., (Eds.) Elsevier. pp. 2135-2139. 

Socolow, R.; Hotinski, R.; Greenblatt, J. B.; Pacala, P. 2004. Solving the climate problem – Technologies available to

curb CO2 emissions. Environment 46 (10): 8-19. 

Stevens, S.H., Pearce, J.M., and Rigg, A.J. 2001. Natural Analogs for GS of CO2

: An Integrated Global Research 

Program. Presented at: First National Conference on Carbon Sequestration, U.S. Department of Energy, National 

Energy Technology Laboratory, May 15-17, 2001, Washington, D.C. 

Strutt, M.H., Baubron, J.C., Beaubien, S.E., Cardellini, C., Granieri, D., Jones, D.G., Lombardi, S., Penner, L., and

Quattrocchi, F. 2005. Soil gas as a monitoring tool of deep geological sequestration of carbon dioxide: Results from

the three year Monitoring of the Encana EOR Project, Weyburn, Saskatchewan (Canada). In: Greenhouse Gas Control 

Technologies: Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies 5-9 September 

2004, Vancouver, Canada. Vol. II. Wilson, M., Morris, T., Gale, J., and Thambimuthu, K., (Eds.) Elsevier. pp. 2119-2123. 

Tans, P. 2008. Trends in Atmospheric Carbon Dioxide – Mauna Loa. National Oceanic and Atmospheric 

Administration, US Department of Commerce. Accessed May, 2008. http://www.esrl.noaa.gov/gmd/ccgg/trends/. 

Wells, A.W., Diehl, J.R., Bromhal, G., Strazisar, B.R., Wilson, T.H., and White, C.M. 2007. The use of tracers

to assess leakage from the sequestration of CO2 in a depleted oil reservoir, New Mexico, USA. Applied 

Geochemistry 22: 996-1016. 
R-6 References 

Zhou, W., Stenhouse, M., Sheppard, M., and Walton, F. Theme 4: Long-Term Risk Assessment of the Storage Site. 

In: Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies: Proceedings of the 

7th International Conference on Greenhouse Gas Control Technologies 5-9 September 2004, Vancouver, Canada. 

Volume III. Wilson, M., and Monea, M (eds). IEA GHG Weyburn CO2 Monitoring and Storage Project Summary 

Report 2000 – 2004. Regina, Saskatchewan, Canada: Petroleum Technology Research Centre (2004): 211–228. 
	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

Appendix I 

Comprehensive Monitoring Techniques List—Atmospheric Monitoring 

AI-1 

Appendix I 

Comprehensive Monitoring 

Techniques List—Atmospheric 

Monitoring 

Introduction 

Appendix I provides descriptions of atmospheric 

monitoring techniques available for deployment during 

geologic CO2 storage projects. The descriptions include 

applications, benefits, challenges, and experience 

relative to each technique. Monitoring tools are 

categorized into one of three categories, based on 

application, function, and stage of development: 

Primary Technology – A proven and mature 

technology or application capable of handling the 

minimum monitoring requirements that could meet 

the 95 percent and 99 percent CO2

 containment 

goals for CCS projects for 2008 and 2012, 

respectively. 

Secondary Technology – An available technology/ 

protocol that can aid in accounting for injected CO2 

and/or provide insight into CO2 behavior that will 

help refine the use of Primary Technologies. 

Potential Additional Technology – A technology/ 

protocol which is research related and might answer 

fundamental questions concerning the behavior of 

CO2

 in the subsurface and which might have some 

benefit as a monitoring tool after testing in the field. 

Atmospheric monitoring techniques can be used 

in identifying CO2 concentrations above ambient 

background level and helping to determine locations 

of CO2

 leaks. CO2 monitoring can detect dangerous 

concentrations of CO2 that may be a threat to workers 

and others in and around the project site. 

Characterization of the atmosphere is carried out during 

site selection, especially with respect to obtaining 

permits. It is usually required to quantify the impact of 

surface activities, such as processing plants, on criterion 

pollutants. In addition, it is desirable to begin an air 

monitoring program as soon as possible to obtain a 

baseline that extends over all seasons and includes the 

range of perturbations (weather, rainfall, agricultural 

and industrial activities, etc.). Local atmospheric 

modeling can help optimize an atmospheric monitoring 

plan. Documentation of local wind speed, temperature, 

barometric pressure, and rainfall is needed to provide 

context for any atmospheric monitoring. These 

measurements are commonly included within more 

sophisticated tools. 

Benefits of atmospheric methods: Direct measurement 

of the atmosphere is important in answering the key 

questions: is sequestration working to prevent the return 

of CO2

 to the atmosphere and are conditions safe for 

humans? Compared to shallow subsurface and deep 

subsurface monitoring, atmospheric monitoring is lower 

cost, because of easy access on the surface, although for 

several tools towers above ground surface are needed 

to get a good signal. The atmosphere is the best mixed 

medium for detection and can, therefore, be used as 

an integrator to document that there is no measurable 

leakage over large areas. Measurements can be 

instantaneous, which would allow rapid response should 

a large leak be detected. Atmospheric measurements 

can provide high frequency data, as well as multiple 

parameters (e.g., wind speed and direction, moisture, 

isotopes, relative ratios of different gases, etc.) that may 

be needed to understand a complex system. 

Challenges: Because the atmosphere is well mixed,

the signal may be diluted at areas away from the point 

of interest. In addition, numerous sources of CO2 

emissions, such as soil and vegetation, combustion and 

other industrial processes, and surface handling of 

CO2, can create a highly variable, “noisy” baseline, so 

that only very large leaks may be detectable, or CO2 

detection at many points may indicate changes other 

than leakage from geologic storage. Measurement of 

leakage at the surface is retarded relative to leakage out 

of the injection zone. Retarded detection would reduce 

risk management and remediation options and, possibly, 

the success of the project. A retarded response would 

also mean that an extended monitoring period would 

be required to document integrity of the system, if 

atmospheric methods were relied on to meet this need. 

Because a well selected site should have no leakage to

the atmosphere, significant cost and effort is required to 

obtain a null result for a CO2

 storage project (i.e., many 

samples will be required). 
	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 		

	 	 	 	 	 	 		

AI-2 Appendix I 

Comprehensive Monitoring Techniques List—Atmospheric Monitoring 

The following atmospheric monitoring techniques are 

discussed in this appendix: 

1. 	CO2 Detectors 

2. 	Eddy Covariance 

3. 	Advanced Leak Detection System 

4. 	Laser Systems and Light Detection and Ranging 

(LIDAR) 

5. 	Tracers (Isotopes) 

1. 	CO2 Detectors (Secondary) 

•	 Description: CO2 detectors rely on infrared detection 

principles and are small and portable. To ensure that 

they are correctly calibrated, periodic sampling for 

laboratory analysis using gas sampling bags and gas 

chromatography for measuring CO2

 concentrations 

relative to other gasses can be employed (Benson et

al., 2005). 

•	 Applications: This type of monitoring is mostly used 

for assuring worker safety or for initial assessment. 

For abandoned or orphaned wells, infrared CO2 

detectors can be deployed in many modes. For 

example, an individual could visit a wellhead on an 

occasional basis to check for leaks. CO2

 detectors 

serve as site worker safety devices by triggering 

automated alarm systems to identify high CO2 levels. 

•	 Benefits: Simple, readily available technology. Can 

often simultaneously monitor for other relevant gases, 

such as hydrogen sulfide (H2

S) and combustibles. 

Alarms available. 

•	 Challenges: Devices used only for qualitative CO2 

detection. Does not provide quantitative information 

on the rate or volume of the leak. 

•	 Geologic Storage Experience: Air monitoring was 

used for worker safety at the Frio test and is planned 

for other projects. 

2. 	Eddy Covariance (Potential) 

•	 Description: Atmospheric flux measurement 

technique to measure atmospheric CO2

 concentrations 

at a height above the ground surface. These systems 

can detect CO2

 fluxes over large areas in real-time, 

along with micrometerological variables, such as 

wind velocity, relative humidity, and temperature 

(Anderson and Farrar, 2001; Baldocchi et al., 1996).

Integration of these measurements allows derivation 

of the net CO2

 flux over the upward footprint (either 

m2

 or km2 scale, depending on tower height). 

•	 Application: Used to detect CO2

 flux over a large 

area in real-time. 

•	 Benefits: Technology can provide accurate data under 

continuous operation, if conditions are favorable. 

•	 Challenges: Requires specialized equipment and 

data processing. Requires a significant number of 

instruments capable of measuring vertical wind 

speed and water vapor mixing heat transfer. Openpath systems tend to underestimate covariance due 

to sensor placement. Precipitation, winds from 

unfavorable directions, or extremely calm conditions 

can cause erratic, nonsensical results (Baker, 2008).

CO2

 from many sources (vegetation, soil gas, industry, 

compressors, pipelines, etc.) may mask leakage signal 

because of the magnitude and temporal variability of 

these sources. 

•	 Geologic Storage Experience: ZERT has documented 

the performance in simulated geologic storage “leak” 

settings. Otway is testing this and other atmospheric 

approaches (see http://www.cmar.csiro.au/ozflux/ 

monitoringsites/otway/purpose.html). 

3. 	Advanced Leak Detection System (Potential) 

•	 Description: An advanced leak detection system 

that can generate geo-referenced CO2 concentration 

data along a path or route. The system incorporates 

a high sensitivity three-gas detector (CH4, total 

hydrocarbons, and CO2

) with a Global Positioning 

System (GPS) with real-time mapping. 

•	 Application: This system is commonly applied to 

pipeline monitoring via a ground or airborne vehicle, 

transmission and liquid line monitoring, and landfill 

liner integrity monitoring. 

•	 Benefits: Detection of total gas composition can be 

used to separate leakage signal from processes that 

produce CO2

. CO2 leakage by itself would displace 

all other gasses equally, whereas in-situ generation 

of CO2

 by biologic action or combustion decreases 

oxygen. 

•	 Challenges: Increased time and labor to sample and 

reduce data; less immediate response. 
	 	 	 	 	

	 	

	 	 	 	 	 	

	 	 	 	 		

	 	 	 	 	 	

Appendix I 

Comprehensive Monitoring Techniques List—Atmospheric Monitoring 

AI-3 

4. Laser Systems and Light Detection and 

Ranging (LIDAR) (Potential) 

•	 Description: LIDAR is an optical remote sensing 

technology that measures properties of scattered 

light to find the range (or other information) of a 

distant target. Laser pulses are used to determine 

the distance to an object or surface. Similar to radar 

technology, which uses radio waves instead of light, 

the distance to an object is determined by measuring 

the time delay between transmission of a pulse and 

detection of the reflected signal. An open-path device 

uses a laser to shine a beam (with a wavelength that 

CO2 absorbs) over many meters. The attenuated beam 

reflects from a mirror and returns to the instrument 

for determination of the CO2

 concentration. One 

instrument can sample a large area, if the beam can 

reflect from more than one mirror. 

•	 Application: LIDAR is highly sensitive to aerosols 

and cloud particles and has many applications in 

atmospheric research and meteorology (Cracknell, 

2007). Differential Absorption LIDAR (DIAL) 

is typically applied to detecting atmospheric 

concentrations of CO2

 above storage sites and in the 

vicinity of pipelines in R&D sequestration projects.

•	 Benefits: Non-intrusive method to collect data 

in areas of limited access or containing potential 

physical or chemical hazards. LIDAR data collection 

is not limited to daylight hours. Large area data 

collection over short time. LIDAR can penetrate 

vegetative canopy. Lasers have the ability to measure 

CO2 concentrations over large areas so that any leaks 

can be quickly detected and remediation measures 

undertaken. 

•	 Challenges: Large data sets are difficult to store, 

manipulate, and utilize. LIDAR data not readily 

supported by mainstream software. Optimal weather 

conditions needed for operation. Water features 

absorb or scatter laser pulses. 

•	 Geologic Storage Experience: Lasers tested at ZERT. 

5. Tracers (Isotopes) (Potential) 

•	 Description: Tracers are unique or highly indicative 

chemical species that can be used to “fingerprint” the 

CO2 of interest and distinguish it from other sources. 

In addition, tracers can be used to understand the flow 

path of fluids, for example in a remediation situation. 

The occurrence of artificial tracers, for example 

perfluorocarbon tracers (PFTs) or SF6

 in natural 

systems is so small that detection and attribution may 

be done at parts-per-billion detection. Noble gases 

occur naturally in CO2; they can also be introduced 

to “spike” the CO2

 to make it more distinctive for 

advanced studies, and they are “conservative,” 

meaning that they are less reactive and less soluble 

than CO2

. The isotopic composition of the carbon 

and oxygen in the injected CO2 (if different from 

the ambient CO2

), as well as minor entrained 

impurities, can be used to distinguish injected CO2 

from ambient CO2. These constituents, however, are 

not conservative; as CO2 moves though rock/fluid/ 

soil/ecosystem, the ratios of isotopes and entrained 

constituents will be modified, giving a record of the 

reaction pathway. 

•	 Application: Chemical tracers, both natural and 

introduced, can be used for in situ subsurface 

characterization, model calibration, and leak 

detection. Naturally occurring chemical constituents, 

such as stable isotopes of C, H, O, or sulfur (S), can 

be used to assess fluid origin, detect CO2 migration 

or leakage into the atmosphere and assess interaction 

with host rocks along flow paths (Cole et al., 2004). 

Researchers at LBNL have recommended using

naturally stable isotopes for use in concert with 

multiple injected PFTs as a method to interpret 

subsurface CO2

 transport processes and monitor 

possible CO2 leakage pathways (GEO-SEQ, 2004).

A variety of sampling and analytical approaches 

are available, including direct extraction from flux 

chambers, simple or complex soil gas wells, and 

sorbent approaches. Analysis can be done in the 

laboratory or via various types of field instruments. 

•	 Benefits: Proven technique in other applications that 

allows for differentiation between injected CO2

 and 

naturally occurring CO2. In advanced applications 

(for assessing a potential leak), tracers can provide 

essential information about flow path and processes 

that could be used to design effective remediation. 

•	 Challenges: Many introduced tracers (PFTs, SF6

) 

are benign in water and ecosystems but are powerful 

greenhouse gasses. They, therefore, need to be used 

conservatively. Because of low detection limits,

contamination is a serious risk; it is important to use 

best practices to inject tracers (separate handling for 

injection and detection). More information is needed 
	 	 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 		 	 		

	 	 	 	 	 	 	 	 	 	 	 		 	 	 	 	

	 	 	 	 	 	 	 	 	 		 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

 

	 	

	 	 	 	 	 	 	 	 		 	 	 	 		

	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

AI-4 Appendix I 

Comprehensive Monitoring Techniques List—Atmospheric Monitoring 

about interaction of introduced tracers with water, 


rocks, soil, and organics. Natural tracers are known 


to have complex reactions with rock, water, and soil, 


requiring a fairly sophisticated approach to produce a 


correct interpretation.
 

•	 Geologic Storage Experience: PFT soil detection 

with capillary adsorbent tubes (CATs), analyzed by 

BNL, conducted by NETL at West Pearl Queen, New

Mexico, (Wells et al., 2007) and Frio. 

APPENDIX I REFERENCES 

Anderson, D.E. and Farrar, C.D., 2001. Eddy covariance measurement of CO2 flux to the atmosphere from an area of 

high volcanogenic emissions, Mammoth Mountain, California. Chem. Geology 177: 31-41. 

Baker, J., 2008. Challenges and cautions in measuring evapotranspiration. Southwest Hydrology (January/February)

24-33. 

Baldocchi, D.D., Valentini, R., Running, S., Oechel, W., and Dahlman, R., 1996. Strategies for measuring and

modeling carbon dioxide and water vapor fluxes over terrestrial ecosystems. Global Change Biology 2: 159-168.

Benson, S., Anderson, J., Bradshaw, J., et al., 2005. Underground geological storage. In: Special Report on Carbon

Dioxide Capture and Storage. Metz, B., Davidson, O., de Coninck, H.C., Loos, M., Meyer, L.A., (Eds). IPCC

Intergovernmental Panel on Climate Change, Cambridge University Press: Cambridge, UK and New York, NY, USA, 

pp. 195-276. Accessed April, 2008. http://www.ipcc.ch/pdf/special-reports/srccs/srccs_wholereport.pdf. 

Cole, D.R., Horita, J., van Soest, M.C., Kennedy, B.M., and Morea, M.F., 2004. Gas chemistry and isotopic monitoring

during the CO2 injection test at Lost Hills, CA. 

Cracknell, A.P., and Hayes, L., 2007. Introduction to Remote Sensing (2nd ed.), Taylor and Francis, London. 

ISBN 0849392551, OCLC 70765252.

GEO-SEQ, 2004. Best Practices Manual: Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation.

Earth Sciences Division, Ernest Orlando Lawrence Berkeley National Laboratory, Berkeley, CA.

http://www.netl.doe.gov/technologies/carbon_seq/refshlf/GEO_SEQ_BestPract_Rev1-1.pdf

Wells, A.W., Diehl, J.R., Bromhal, G., Strazisar, B.R., Wilson, T.H., and White, C.M., 2007. The use of tracers to assess

leakage from the sequestration of CO2

 in a depleted oil reservoir, New Mexico, USA. Applied Geochemistry 22: 996-1016. 
Appendix II 

Comprehensive Monitoring Techniques List—Near-Surface 

AII-1 

Appendix II 

Comprehensive Monitoring 

Techniques List—Near-Surface 

Introduction 

Appendix II provides descriptions of near-surface 

monitoring techniques available for deployment during 

geologic CO2

 storage projects. The descriptions include 

applications, benefits, challenges, and experience 

relative to each technique. Monitoring tools are 

categorized into one of three categories, based on 

application, function, and stage of development: 

Primary Technology – A proven and mature 

technology or application capable of handling the 

minimum monitoring requirements that could meet 

the 95 percent and 99 percent CO2

 containment 

goals for CCS projects for 2008 and 2012, 

respectively. 

Secondary Technology – An available technology/ 

protocol that can aid in accounting for injected CO2 

and/or provide insight into CO2 behavior that will 

help refine the use of Primary Technologies. 

Potential Additional Technology – A technology/ 

protocol which is research related and might answer 

fundamental questions concerning the behavior of 

CO2 in the subsurface and which might have some 

benefit as a monitoring tool after testing in the field. 

Near-surface techniques play a vital role in the 

preservation of shallow groundwater sources and supply 

critical information on any major vertical migration 

of injected CO2. Characterization of the near surface 

environment begins during site selection with assessing 

any required environmental and culture features, for 

example wetlands, floodplains, antiquities, significant 

habitat, groundwater, soil and other resources, land 

use, human populations, and infrastructure. The exact 

elements will be specific to the local requirements. For 

development of an effective near surface monitoring 

plan, detailed characterization of the static and 

changing conditions in the system is needed. This 

includes aspects, such as groundwater potentiometric 

surface and seasonal variability, moisture and 

temperature of the vadose zone, the effects of cropping, 

irrigation, and changing land use. Many tools are 

available from disciplines, such as groundwater 

management, site remediation, and agriculture. A 

few examples include cores for soil properties, soil 

moisture and soil gas wells, and surface data collection 

devices, groundwater wells with transducers for water 

level measurement, and surface surveys of soil and 

vegetation. 

Benefits of near-surface methods: The surface and 

shallow subsurface are more accessible at lower cost 

than the deep subsurface. Residence time of CO2

 is 

longer in the shallow subsurface than in the atmosphere 

above the leak, increasing the probability of detecting 

the leak. Some risk factors, for example a confined 

space (basement) risk, are probably mostly tied to a 

soil gas source of CO2. In addition, the near surface 

contains a major resource protected by regulation, 

USDW, and monitoring of this resource may increase 

public confidence and, by early detection, reduce any 

liability from leakage. 

Challenges of near-surface methods: As with the 

atmosphere, there are numerous sources of near surface 

CO2 emissions, such as soil microbes and vegetation; 

in-situ remediation of oil spills produces large amounts 

of CO2. The soil gas system is complicated by 

factors, such as moisture, temperature, nutrients, and 

barometric pressure that vary daily, seasonally, and 

complexly. Measurements of leakage from soil gas 

may be very close to the leakage point (e.g., results 

of ZERT), although it is possible that buildup in the 

vadose zone would result in leakage at a topographic 

low point distant from the leakage point. Ground water 

systems may be dynamic, responding to recharge and 

discharge. Like the atmosphere, with groundwater a 

leakage signal may be diluted or attenuated by rockfluid interaction (buffering) away from the point of 

leakage. Like the atmosphere, measurement of leakage 

at the near surface is retarded relative to leakage out 

of the injection zone. Retarded detection reduces risk 

management and remediation options and possibly the 

success of the project. A retarded response would also 

mean that an extended monitoring period would be 

required to document integrity of the system if near 

surface methods were relied on to meet this need. A 

well selected site should have no leakage to surface; 

therefore, a significant cost and effort is required to 

obtain a null result for a CO2

 storage project (many 

observations will be required). 
	 	 	 	 	 	 	 	 	 	

	 	 	 			 	 	 	 	

	 		 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	

AII-2 Appendix II 

Comprehensive Monitoring Techniques List—Near-Surface 

The following near-surface monitoring techniques are 

discussed in this appendix: 

1. Ecosystem Stress Monitoring 

2. Tracers 

3. Groundwater Monitoring 

4. Thermal Hyperspectral Imaging 

5. Synthetic Aperature Radar (SAR and InSAR) 

6. CIR Transparency Films 

7. Tiltmeter 

8. Flux Accumulation Chamber 

9. Induced Polarization (IP) 

10. Spontaneous (Self) Potential 

11. Soil and Vadose Zone Gas Monitoring 

12. Shallow 2-D Seismic 

1. Ecosystem Stress Monitoring (Potential) 

•	 Description: Color infrared orthoimagery, satellite 

imagery, and aerial photography can be used to assess 

ecosystem stress as an indicator of CO2 or brine 

leakage. 

•	 Application: CO2

 or brine leaks from underground 

storage sites may have significant impacts on local 

ecosystems in the shallow subsurface, the sea floor, 

and within the water column that could provide 

useful indicators. Detection techniques require initial 

surveys to establish baseline conditions above storage 

sites. Confidence in leakage detection will require 

improved understanding of how plant populations 

change in composition, quantity, and health as 

conditions change. 

•	 Benefits: Direct monitoring of ecosystem health 

can provide confidence that the storage system is not 

causing damage, reduce risk in case of leakage, and 

guard against challenges in cases where observed 

changes are not the result of CO2

 injection. 

•	 Challenges: Ecosystem sensitively to leakage is 

variable with species and setting, which may cause 

methods to be insensitive (false negatives). Many 

other factors leading to ecosystem stress lead to 

abundant changes that must be followed up using 

other techniques (false positives). Absence of data 

on the quantitative effects on marine and terrestrial 

ecosystems of excess CO2

 from leaking storage sites 

(West et al., 2005). 

•	 Geologic Storage Experience: ZERT has nice results. 

British Geological Survey (BGS) did a test in an area

of natural leakage in Italy (see CO2GeoNet for results 

[http://www.co2geonet.com]). Volcanogenic sources 

with high fluxes of CO2

 at Mammoth Mountain, CA, 

studied by USGS, provide a case study of impact of 

leakage on tree kills. 

2. Tracers (Potential) 

•	 Description: Tracers are unique or highly indicative 

chemical species that can be used to delineate 

the flow-path of fluids in the subsurface. For CO2 

sequestration projects (Nimz and Hudson, 2005), 

tracers have included noble gases and PFTs. The 

occurrence of these chemicals in natural systems is 

so low that detection and attribution may be done 

at parts-per-billion detection. In some cases, the 

isotopic composition of the CO2

 is readily identifiable, 

and has been used as a tracer. 

•	 Application: Chemical tracers, both natural and 

introduced, can be used for in situ subsurface 

characterization, model calibration, and leak 

detection. Naturally occurring chemical constituents, 

such as stable isotopes of O, C, H, N, and S; noble 

gases Kr, Ne, argon (Ar), He, xenon (Xe) and their 

isotopes; and radioactive isotopes (e.g., 3

H, 14C, 36Cl, 125I, 129I, 131I) can be used to assess fluid origin, detect 

CO2 migration or leakage into the atmosphere and 

assess interaction with host rocks along flow paths 

(Cole et al., 2004). Researchers at LBNL have

recommended using naturally stable isotopes for use 

in concert with multiple injected PFTs as a method 

to interpret subsurface CO2 transport processes 

and monitor possible CO2 leakage pathways (GEOSEQ, 2004). Research funded by DOE’s Core

R&D program has led to the development of an in

situ stable isotope analysis system as part of a focus 

at developing novel monitoring tools for geologic 

sequestration. Phase-partitioning tracers could be 

used to determine the amount of immobile phases 

(such as the residual oil in a petroleum reservoir). 

Preliminary tests have been carried out at the Frio 

project in Texas to test the applicability of phasepartitioning tracers to estimate the amount of residual 

gas trapping that has taken place. Residual gas 

trapping is an important parameter for estimating 

long-term storage integrity. 

•	 Benefits: Proven technique in other applications that 

allows for differentiation between injected CO2

 and 

naturally occurring CO2

. 

•	 Challenges: While it is comparatively 

straightforward to measure the parameters listed 
		

		 	 	 	 	 	 	

	 	 	 		 	 	 	 	

Appendix II 

Comprehensive Monitoring Techniques List—Near-Surface 

AII-3 

above, interpreting these measurements to infer 

information about geochemical reactions is much 

more challenging. Utilization of tracers requires the 

availability of a number of boreholes in and around 

the injection plume. The use of tracers for CO2 

geologic storage has yet to be demonstrated. 

•	 Geologic Storage Experience: NETL participated 

in the ZERT field experiments, which injected small 

amounts of tracer-spiked CO2

 just below the soil 

from vertical and horizontal wells. Surface flux and 

tracer mappings were in agreement and provided 

complementary information for modeling CO2 

movement near the surface. Otway employed noble 

gas tracers. 

3. Groundwater Monitoring (Primary) 

• Description: Impacts on groundwater can 

result from migration of CO2

 or brine into 

USDWs. Groundwater monitoring can be 

used to assess changes though time and across 

an area with indicators, such as pH, specific 

conductance, alkalinity, major and trace chemical 

constituents, dissolved gases, stable isotopes, 

radio-isotopes (14C), and redox potential, to 

understand the location and consequences of CO2 

migration. Changes in the chemical composition 

of groundwater could be used to detect leakage 

or the risk of changes in water quality. Changes 

in pH, alkalinity, redox potential, specific 

conductance, stable isotopes, and gases are used 

to elucidate the impact on drinking water of 

saline water or CO2 migration. 

•	Application:	 A successful monitoring program 

should include both pre- and post-injection sampling 

and assessment of baseline water chemistry and 

mineralogy. Well spacing needs to consider 

sensitivity and attenuation, risk factors, groundwater 

flow direction and rate, and account for non-geologic 

storage changes. 

•	 Benefits: Groundwater is an integrating horizon 

that covers all, or much of, many sites; it flows and, 

therefore, an up-gradient/down-gradient sample point 

array could be effective in determining that there is 

no change resulting from geologic storage of CO2

. 

Direct monitoring of a protected resource provides 

public confidence. 

•	 Challenges: Need wells and natural sample points, 

as there may be water resources at different depths. 

Some parameters could be collected automatically 

using probes on data loggers or with uplinks to 

monitoring stations. However, some of the most 

useful require sample collection and laboratory 

analysis. Many factors besides geologic storage could 

cause change and, therefore, enough sample points 

are needed to assess the reasons for the observed 

change, such as land use changes. Groundwater 

systems may be relatively insensitive to perturbation 

by introduction of CO2

 because of buffering. 

•	 Geologic Storage Experience: Small test at Frio, 

Otway, and SWP Phase II at SACROC. Each of 

these tests has found a fairly complex and dynamic 

environment. Testing planned at SECARB Phase III

test at Cranfield, Illinois. 

4. Thermal Hyperspectral Imaging (Potential) 

•	 Description: Hyperspectral imaging collects 

and processes information from across the 

electromagnetic spectrum. Hyperspectral sensors 

collect information as a set of images. Each image 

represents a range of the electromagnetic spectrum, 

also known as a spectral band. These images are then 

combined and form a three dimensional hyperspectral 

cube for processing and analysis. Sensors may be 

airborne, satellite mounted, or hand held. 

•	 Application: Like CIR, hyperspectral imaging is 

an excellent tool in assessing vegetative integrity 

around an injection site. DOE’s Core R&D program

investigated a ground-surface controlled leak 

experiment releasing CO2

 and CH4 that was conducted 

at the Naval Petroleum Reserve Site #3 in Wyoming 

in 2006. Aerial hyperspectral imagery based on 

MASTER technology was acquired, and analyses of 

these data demonstrated that MASTER could identify 

CO2 and CH4 surface seeps at high concentrations. 

•	 Benefits: Since an entire spectrum is acquired at 

each point, the operator needs no prior knowledge of 

the sample, and post-processing allows all available 

information from the dataset to be mined. Data can 

be acquired over a relatively large area quickly and 

efficiently. Airborne or satellite deployment can 

image the whole area, including areas that are poorly 

accessible on the ground. 
AII-4 Appendix II 

Comprehensive Monitoring Techniques List—Near-Surface 

•	 Challenges: Fast computers, sensitive detectors, and 

large data storage capacities are needed. 

•	 Geologic Storage Experience: Teapot test. 

5. Synthetic Aperture Radar (SAR and InSAR) 

(Potential) 

•	 Description: SAR (InSAR—Interferometric 

Synthetic Aperture Radar) is a satellite-based 

technology in which radar waves are sent to the 

ground. The measured reflection of those waves 

provides high-precision information on the position 

of the ground surface (Gabriel et al., 1989). Several 

commercial SAR satellites are currently available and 

applicable to monitoring large sequestration projects, 

and new, more capable systems are in the pipeline. 

Most commercial systems provide 100 kilometer by 

100 kilometer scenes, a sufficiently broad area for 

even the largest sequestration project. Provided the 

repeat orbit of one scene is close enough to that of a 

later pass over the same specific scene, the two scenes 

can be interferometrically processed to produce an 

image of the vertical surface deformation of the earth 

that has occurred between the time the first scene was 

collected and the time the second scene was collected. 

•	 Application: This technique measures the 

surface effect of subsurface phenomena. The 

surface deformation maps can be used to monitor 

groundwater and oil reservoir drawdown over time, 

understand earthquakes, and explore for geothermal 

resources. InSAR, if applicable at the site of interest, 

will be one of the essential methods for monitoring 

a large CO2

 injection effort by providing large 

scale snapshots of changes that the injection and 

movement of the subsurface CO2

 may reveal via 

surface deformation. InSAR methods work best in 

environments with minimal topography, minimal 

vegetation, and minimal land use. Adaptive methods, 

such as reflectors, can be deployed where these 

conditions are not met. A related technique is direct 

measurement of changes in elevation though mapping 

with LIDAR. 

•	 Benefits: Measurement of the surface response to 

elevated pressure though time lapse. Satellite based, 

covers very large areas, including inaccessible areas. 

•	 Challenges: The area of elevated pressure is 

mapped, not the plume of injected CO2

. Numerous 

assumptions required to translate surface response to 

subsurface. Steep terrain is difficult to correct for in 

the processing step and gives rise to soil slippage and 

rock fall that can de-correlate the image. Vegetation 

can upset the radar reflection point for many 

commercial systems and produce a de-correlated 

image. 

6. Color Infrared Transparency Film (Potential) 

•	 Description: This technology utilizes three 

sensitized film layers that reproduce infrared as red, 

red as green, and green as blue, due to the way the 

dyes are coupled to these layers. All three layers 

are sensitive to blue so the film must be used with 

a minus blue (i.e., yellow) filter. Vegetative health 

can be determined from the relative strengths of 

green and infrared light reflected; this shows in color 

infrared as a shift from red (healthy) towards magenta 

(unhealthy). 

•	 Application: CIR aerial photos of specific project 

sites can be taken from an aircraft or by satellite to 

determine vegetative health in the vicinity of the 

project site as an indicator of a possible CO2

 leakage 

pathway (Crum, 2006). 

•	 Benefits: A combination of wavelengths provides a 

better understanding of happenings on the Earth’s 

surface. Good indicator of vegetative health. 

•	 Challenges: The presence of water interferes with 

the quality of the image due to absorption of nearinfrared wavelengths (appears black on the image). 

Must have a means to obtain aerial CIR images 

(aircraft, satellite, etc.). 

7. Tiltmeter (Potential) 

•	 Description: A tiltmeter is an instrument designed 

to measure very small changes from the horizontal, 

either on the surface or at depth. In essence, it works 

like a carpenter’s level, except that it can detect and 

quantify extremely small deviations from horizontal. 

•	 Application: These tools are regularly used to 

monitor oil field operations, including water and CO2 

flooding and hydrofracturing. Several commercial 

companies offer this technology, and tiltmeter arrays 

can be installed either at the earth’s surface or 

within subsurface wells. Measurements are typically 

collected remotely and sent for interpretation via 

radio or satellite telemetry. This approach is useful 

in places where long-time series can be collected to 
	 	 	 	 	 	 	 	

Appendix II 

Comprehensive Monitoring Techniques List—Near-Surface 

AII-5 

remove noise. Ideally, a combination of surface and 

subsurface tools is deployed, but that is a function 

of well and surface availability. Tiltmeters can be 

strategically placed around the site to determine 

surface deformation caused by interaction of the CO2, 

brine, and rock. Typically, deformation is less than a 

few centimeters, which can be measured with existing 

tiltmeters (NETL, 2008). CONSOL Energy Inc. is 

employing surface tiltmeters to measure reservoir 

deflection and to track plume movement in a DOE 

funded project that demonstrates a novel drilling and 

production process that reduces potential methane 

emissions from coal mining, produces usable methane 

(natural gas), and creates a sequestration sink for CO2 

in unmineable coal seams. 

•	 Benefits: A technique which is sensitive to the 

pressure in the injection zone is useful, as elevated 

pressure is itself a risk factor. 

•	 Challenges: An array of many tiltmeters is required 

(often far from the injection site) to measured the area 

of deformation. Does not identify the CO2

 plume. 

•	 Geologic Storage Experience: CONSOL Energy, Inc. 

is employing surface tiltmeters to measure reservoir 

deflection and track plume movement in a DOE 

funded project that demonstrates a novel drilling and 

production process that reduces potential methane 

emissions from coal mining, produces usable methane 

(natural gas), and creates a sequestration sink for CO2 

in unmineable coal seams. 

8. Flux Accumulation Chambers (Secondary) 

•	 Description: An accumulation chamber with an open 

bottom (cm2

 scale) is placed either directly on the soil 

surface or on a collar installed on the ground surface. 

Air contained in the chamber is circulated through an 

IRGA, and the rate of change in CO2 concentration in 

the chamber is used to derive the flux of CO2 across 

the ground surface at the point of measurement 

(Norman et al., 1992). Advanced techniques include 

using other trace gases, such as radon, as proxies for 

determining and differentiating gas fluxes from depth 

(Baubron, 2005).

•	 Application: These chambers quantify the CO2

 flux 

from the soil at a small, predetermined area. 

•	 Benefits: Technology can quickly and effectively 

determine CO2

 fluxes from the soil at a predetermined 

spot. Allows collection of high quality gas sample, 

from which naturally occurring tracers, such as 

isotopes or noble gasses, or introduced tracers can be 

detected. Flux is assumed to be more closely related 

to leakage rate than is concentration. 

•	 Challenges: Monitoring a large area requires many 

installations. Soil gas flux has strong seasonal and 

other temporal variability that has to be controlled for 

by the method to provide leakage estimates. Soil flux 

is not effective if water table is high or soil is wet or 

frozen. 

•	 Geologic Storage Experience: Flux accumulation 

chambers have been used at ZERT, Rangeley, 

Weyburn, and Frio (not successful) and are planned 

for several RCSP projects – SECARB Black Warrior

coal, others. 

9. Induced Polarization (IP) (Potential) 

•	 Description: IP is comparable to electrical resistivity 

tomography techniques due to electrical currents 

being induced in the subsurface via two electrodes, 

with voltage being observed through two other 

electrodes. IP is observed when a steady current 

through two electrodes in the Earth is terminated; 

the voltage does not instantly return to zero, but 

rather decays slowly, indicating that charge has 

been stored in the rocks. This charge mainly 

accumulates at interfaces between clay minerals 

and is responsible for the IP effect. In particular, 

time domain IP methods measure the voltage decay 

or chargeability over a given time interval once the 

induced voltage is removed. The integrated voltage is 

used as the measurement. Frequency domain-based 

IP approaches use alternating currents to generate 

electric charges in the subsurface, and the apparent 

resistivity is measured at different alternating current 

frequencies (Keary et al., 2001). 

•	 Application: Geophysical imaging technology is 

used to detect metallic materials in subsurface strata, 

particularly ores. 

•	 Benefits: Detecting metallic materials in the 

subsurface with fair ability to distinguish between 

different types of mineralization. 

•	 Challenges: Difficult to accurately depict nonmetallic based materials in the subsurface. 

•	 Geologic Storage Experience: For planned use of IP 

by the RCSPs, see Table 5-1. 
 

 

 

 

 

 

 

 

		 	 	 	 	 	

 

 

 

 

 

 

 

 

 

	 	 	 		 	

AII-6 Appendix II 

Comprehensive Monitoring Techniques List—Near-Surface 

10. Spontaneous (Self) Potential (Potential) 

•	 Description: Method based on the surface 

measurement of natural potential differences resulting 

from electrochemical reactions in the subsurface. 

SP anomalies normally have an amplitude of several 

hundred millivolts with respect to barren ground. 

Field equipment consists of a pair of electrodes 

connected by a high-impedance millivoltmeter. The 

electrodes must be non-polarizing (normally by 

immersion in a saturated solution of its own salt, 

e.g. copper in copper sulfate), as simple metal spikes 

would generate their own SP effects. The salt is 

contained in a porous pot which allows slow leakage 

of the solution into the ground. 

•	 Application: Interpretation of SP anomalies is similar 

to magnetic interpretation, because dipole fields are 

involved in both cases. All interpretation is assumed 

to be qualitative at best. The anomaly minimum is 

assumed to occur directly over the anomalous body. 

The anomaly half-width provides a rough estimate 

of depth, and the symmetry or asymmetry provides 

information about the attitude of the body, the steep 

slope, and positive tail of the anomaly lying on the 

downdip side (Kearey et al., 1991). 

•	 Benefits: Rapid and cheap method requiring only 

simple field equipment. Useful in rapid ground 

reconnaissance for base metal deposits when used in 

tandem with EM and geochemical techniques. 

•	 Challenges: Provides little information in subsurface 

exploration efforts. Data should be considered only 

for qualitative purposes. Penetration is limited 

to about 30 meters. Clay covering may mask SP 

anomaly of formations below. 

11. Soil and Vadose Zone Gas Monitoring 

(Secondary) 

•	 Description: Bulk chemical composition of gases

collected at soil and subsoil depth can be used to 

quantify CO2 concentration profiles (by depth) 

and asses whether CO2 originates from natural or 

nonbiologic-respiration sources (e.g., fossil fuel 

combustion). Numerical simulation studies of leakage 

and seepage demonstrate that CO2

 concentrations can 

attain high levels in the shallow subsurface even for 

relatively moderate CO2

 leakage fluxes (Oldenburg 

and Unger, 2003). Soil pore gas concentrations and 

isotropic composition can be measured using a variety 

of techniques, including drive points (geoprobes), 

IRGAs, gas chromatography, and mass spectrometry. 

American Standard Test Method (ASTM) D5314-92 

provides the standard protocol for monitoring soil gas 

in the vadose zone. 

•	 Application: The soil gas technique provides accurate 

measurements of CO2 concentration at a particular 

location, but depends on the sampling grid. The spatial 

resolution must be considered. Although a higher 

sampling density is achievable, it will increase the 

expense and decrease the speed of ground coverage. 

•	 Benefits: Can collect diverse information needed to 

interpret signal (e.g., gas ratios, isotopes, moisture). 

•	 Challenges: To be valid, soil gas sample points need 

to be spaced so as to detect leak points, which natural 

analogs suggest could be small and localized. Well 

construction must complete wells in zone of interest, 

avoiding atmospheric leakage. 

•	 Geologic Storage Experience: See Atmospheric 

Monitoring (Appendix I). 

12. Shallow 2-D Seismic (Secondary) 

•	 Description: Method of exploration geophysics 

that implements the principles of seismology that 

has been applied to shallow surface imaging from 

reflected seismic waves. The technique is based on 

determination of the time interval elapsed between 

the initiation of the seismic wave and the arrival of 

reflected or refracted impulses at one or more seismic 

detectors. The method requires a controlled and 

repeatable seismic energy source. By documenting

the time it takes for a reflection to arrive at a receiver, 

it is possible to estimate the depth of the feature 

that generated the reflection. In this way, reflection 

seismology is similar to sonar and echolocation. The 

source–receiver array can be along a line (2-D survey) 

or in a pattern across the land surface (3-D survey). 

•	 Application: Seismic reflection technology has 

been applied to characterizing the shallow geology 

at locations that are environmentally contaminated; 

in detecting shallow subsurface voids that might 

be related to sinkholes, tunnels, or construction; in 

mapping faults or bedrock surfaces; and in other 

situations. Shallow seismic might be deployed 

in time-lapse mode to look for changes from the 

baseline, or post-injection when a leak is suspected to 

try to image a concentration of trapped gas phase CO2 

by mapping a bright spot. 
Appendix II 

Comprehensive Monitoring Techniques List—Near-Surface 

AII-7 

•	 Benefits: Technology that can provide high-resolution 

images of the subsurface for monitoring design. 

Should CO2

 leak and accumulate at shallow depth, 

the low density of the gas phase would be expected 

to produce a strong area of slow velocity, readily 

mapped as change from baseline, or even in a single 

survey, as a bright spot. 

•	 Challenges: Seismic techniques respond to a 

significant change in velocity of sound through the 

rock/fluid system so that CO2

 dissolved in ground 

water would not be likely to produce a measurable 

signal. Thin or low-saturation gas phase CO2

 (near 

wells or faults) may also be below the resolution and, 

therefore, undetectable. Resolution of sound waves 

and depth of penetration are inversely related; cost 

of surveys and processing and source and receiver 

spacing are also related, requiring careful design. 

Static errors caused by changes in shot points or in 

near surface conditions can reduce detection; they 

may also add noise. Resulting errors in processing 

may create a signal where no change in fluids 

occurred (false positive). It is not possible to quantify 

CO2 volume using seismic, as thickness and saturation 

are both difficult to quantify. Mass-balance and 

dissolution/mineral trapping are difficult to monitor. 

Out of plane migration is not quantified. 

•	 Geologic Storage Experience: Most seismic surveys 

conducted for geologic storage have been designed 

for deep injection zone targets; however, success 

with detection at Weyburn, Sleipner, and Frio 

(borehole) add confidence that, if seismic surveys 

were undertaken for leak detection, they could 

be successful, given favorable concentration and 

thickness. 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	

	 	 	 	 	 	 	 		 	 	 	 		 	

	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 		 	 	

 

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

AII-8 Appendix II 

Comprehensive Monitoring Techniques List—Near-Surface 

APPENDIX II REFERENCES 

Baubron, J-C., 2005. Soil gas velocity and flux modeling using long-term Rn monitoring: A new tool for deep CO2 

gas escape detection. In: Wilson, M., Morris, T., Gale, J., and Thambimuthu, K. (Eds). Greenhouse Gas Control 

Technologies, Volume 2. Elsevier Science Limited., Oxford, UK. pp. 2115-2117. 

Cole, D.R., Horita, J., van Soest, M.C., Kennedy, B.M., and Morea, M.F. 2004. Gas chemistry and isotopic monitoring

during the CO2

 injection test at Lost Hills, CA. 

Crum, S., 2006. Aerial photography and remote sensing. University of Texas at Austin, Department of Geography. 

http://www.colorado.edu/geography/gcraft/notes/remote/remote_f.html. 

Gabriel, A.K., Goldstein, R.M., and Zebker, H.A., 1989. Mapping small elevation changes over large areas: differential 

radar interferometry, J. Geophys. Res, 94 (B7): 9183-9191.

GEO-SEQ, 2004. Best Practices Manual: Carbon Dioxide Sequestration: Site Evaluation to Implementation. Earth

Sciences Division, Ernest Orlando Lawrence Berkeley National Laboratory, Berkeley, CA.

http://www.netl.doe.gov/technologies/carbon_seq/refshlf/GEO_SEQ_BestPract_Rev1-1.pdf. 

Kearey, P., Brooks, M., and Hill, I., 1991. In: An Introduction to Geophysical Exploration, Second edition, Blackwell

Science, pp. 199-205. 

National Energy Technology Laboratory (NETL), 2008. Carbon Storage for Facilitating 21st Century Energy Systems. 

Regional Carbon Sequestration Partnership Program. 

Nimz G.J., and Hudson, G.B., 2005. The use of noble gas isotopes for monitoring leakage of geologically stored

CO2, In: D. Thomas and S. Benson (eds.), Carbon Dioxide Capture for Storage in Deep Geologic Formations, Vol. 2:

Elsevier Press, Amsterdam, pp. 1113-1130. 

Norman, J.M., Garcia, R., and Verma, S.B., 1992. Soil surface CO2

 fluxes and the carbon budget of grassland. 

J. Geophys. Res. 97: 18,845-18,853. 

Oldenburg, C.M., and Unger, A.J.A., 2003. On leakage and seepage from geologic carbon sequestration sites: Unsaturated 

zone attenuation. Vadose Zone Journal 2(3): 287-296. 

West, J.M., Pearce, J.P., Bentham, M., and Maul, P., 2005. Issue profile: Environmental issues and the geological

storage of CO2

. European Environment 15: 250-259. 
 

	 	 	 	 	 	 	 		 	 	

	 	 	 	 	 	 	

Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

AIII-1 

Appendix III 

Comprehensive Monitoring Techniques 

List—Subsurface Monitoring 

Introduction 

Appendix III provides descriptions of subsurface 

monitoring techniques available for deployment during 

geologic CO2

 storage projects. The descriptions include 

applications, benefits, challenges, and experience 

relative to each technique. Monitoring tools are 

categorized into one of three categories, based on 

application, function, and stage of development: 

Primary Technology – A proven and mature 

technology or application capable of handling the 

minimum monitoring requirements that could meet 

the 95 percent and 99 percent CO2

 containment 

goals for CCS projects for 2008 and 2012, 

respectively. 

Secondary Technology – An available technology/ 

protocol that can aid in accounting for injected CO2 

and/or provide insight into CO2 behavior that will 

help refine the use of Primary Technologies. 

Potential Additional Technology – A technology/ 

protocol which is research related and might answer 

fundamental questions concerning the behavior of 

CO2 in the subsurface and which might have some 

benefit as a monitoring tool after testing in the field. 

Subsurface monitoring techniques play a vital role in 

identifying CO2 plume location, pressure propagation, 

and reservoir and seal integrity. MVA techniques 

can detect CO2 and compare observations with the 

predicted fate and transport results from modeling 

efforts. Characterization and modeling are the first 

lines of defense to assure that the injection zone is 

behaving as predicted; this involves tools, such as 

surface and well-bore seismic methods, coring and 

core analysis, open hole wireline logging, single and 

multiple well hydrologic testing, step-rate pressure 

testing (to reveal the maximum allowable pressure 

prior to caprock fracturing), and rock-fluid-engineered 

system geochemical and geomechanical compatibility 

assessments. Many techniques can be imported from 

oil and gas exploration and reservoir management 

disciplines, as well as from Class I and Class II UIC 

experience. Laboratory analyses are important to 

constrain data collected in the field; these data can 

range from mineralogical descriptions of cores via thick 

section, scanning electron microscope, x-ray diffraction 

end-point or a whole range of hysteretic curves for 

fluids of interest, batch or flow-though rock-water-fluid 

interactions, tracer behavior, and laboratory assessment 

of relevant acoustic or EM energy into the rock-fluid 

system. A central goal of characterization is to develop 

accurate input data to represent the earth system in a set 

of numerical models that will predict the performance 

of the injection zone as fluids are introduced. 

A variety of techniques are also available to assess 

the condition of the well and ensure that the well 

itself does not provide a leakage pathway for CO2 

migration. Several logs are routinely used for this 

purpose, including temperature, noise, casing integrity, 

and radioactive tracer logs (Benson et al., 2002). It is

worth noting that the resolution of cement bond and 

well integrity logs may not be sufficient to detect very 

small rates of seepage through microcracks (Benson

and Meyer, 2002). 

Benefits of subsurface methods: The location of the 

CO2 and the region of elevated pressure can be more 

easily predicted than any potential leakage. The volume, 

thickness, and saturation will also be high relative 

to any leak scenario. Substitution of supercritical 

CO2

 (nonconductive, density of 0.6 g/cm3) for brine 

(conductive, density >1 g/cm3

) results in a relatively 

strong geochemical, geophysical, and compositional 

contrast, and many techniques can be used to image it. 

Tracking the plume and area of elevated pressure (AOR) 

can be done with many techniques to provide public 

confidence. 

Challenges of subsurface methods: The depth of the 

injection zone (desirable for isolation and separation 

from USDW) makes direct access to the injection 

zone through deep wells costly and limits the types 

and resolution of geophysics. No techniques are 

available to measure the CO2 in situ with precision; it 

is, therefore, not possible to directly quantify CO2

 in 

the injection zone and determine that none has leaked. 

It is necessary to use indirect or inferential methods to 

document that the injection is performing as expected 

and that CO2 and brine are not escaping the injection 

zone in unacceptable directions and at unacceptable rates. 
	 	 	

	 	 	 	 	

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

		

AIII-2 Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

The following subsurface monitoring techniques are 

discussed in this appendix: 

1. Multi-component 3-D Surface Seismic 


Time-lapse Survey
 

2. VSP 

3. Magnetotelluric Sounding 

4. EM Resistivity 

5. EMIT 

6. Injection Well Logging (Wireline Logging) 

7. Annulus Pressure Monitoring 

8. Pulsed Neutron Capture 

9. ERT 

10. Sonic (Acoustic) Logging 

11. 2-D Seismic Survey 

12. Time-lapse Gravity 

13.	 Density Log (RHOB Log)

14. Optical Log 

15.	 Cement Bond Log (Ultrasonic Well Logging)

16. Gamma Ray Logging 

17. Microseismic (Passive) Survey 

18. Crosswell Seismic Survey 

19. Aqueous Geochemistry 

20. Resistivity Log 

1. Multi-component 3-D Surface Seismic 

Time-lapse Survey (Secondary) 

• Description:	 Three-dimensional surface seismic 

surveys are a widely deployed technology in oil 

and gas exploration that utilizes surface sources 

(e.g., dynamite or vibrating machines) to generate 

downward propagating elastic waves that are reflected 

from subsurface features and return to the surface 

where they are recorded by ground motion sensors 

(geophones), resulting in a three-dimensional view of 

the subsurface. In the case of a 3-D survey, a regular 

2-D grid of surface sources and sensors is deployed. 

The recorded data are combined to produce a 3-D 

image of the subsurface. Conventional surface seismic 

surveys record only compressional, or P-waves. 

Multicomponent seismic surveys can be used to record 

both P-waves and shear, or S-waves; this is achieved by 

recording all components of the returning wavefield. 

Each sensor within a multicomponent recording cable 

comprises three orthogonally oriented geophones 

for land acquisition, plus a hydrophone for marine 

acquisition (hence four-component or 4C). P-waves are 

detected primarily by the Z-component geophone and 

the hydrophone, while S-waves are detected primarily 

by the X- and Y-component geophones. 

•	 Application: In a monitoring program, an 

initial seismic survey contributes to geologic site 

characterization. In addition, the survey provides 

an initial baseline that can be compared to changes 

in subsequent seismic surveys to create a time 

lapse image of CO2

 plume migration and to detect 

significant leakage or migration of CO2

 from the 

storage site. Surface seismic techniques provide 

detailed spatial resolution of CO2

 distribution, but are 

less sensitive than well-based methods and, therefore, 

require the presence of large volumes for detection of 

CO2

 (Monea et al., 2008). Tracking CO2 flood fronts 

and sweep efficiency over time following the injection 

period (4-D seismic) is another application of 3-D 

seismic and is an important tool for determining 

plume location relative to predictive modeling results. 

•	 Benefits: 3-D seismic is the available technique that 

assesses the entire earth volume with the highest 

resolution; other techniques sample either a fraction 

of the volume (near wells, along 2-D lines, etc.). 

Time lapse images (4-D can be used to measure 

change and confirm prediction’s) derived from good 

quality 3-D seismic are good communication tools 

•	 Challenges: Semi-quantitative estimate of the 

distribution of CO2

: not sensitive to dissolved or 

thin CO2 plumes; seismic response not linear with 

concentration; therefore, cannot be used to quantify 

volume stored. There are environmental impacts 

associated with using underground explosions 

or vibroseis trucks, clearing vegetation to install 

geophones, or building new roads to transport 

equipment and personnel. 3-D quality and sensitivity 

varies depending on rock and fluid properties, 

geometries, etc. Seismic will not work well in some 

settings. Noise from static errors can cause anomalies 

on repeat surveys and may decrease confidence unless 

follow-up assessment is budgeted 

2. Vertical Seismic Profile (Potential) 

•	 Description:	 VSP provides valuable information 

about the geologic structure of the subsurface and 

is one of the best ways to study seismic anisotropy. 

In VSP exploration, seismic energy is periodically 

imparted into the Earth’s subterranean formations 

with a surface source at or near a well borehole. The 

seismic waves thus generated can be detected along 

the length of the well bore with a receiver, which 

utilizes signals characteristic of the Earth’s response 
 

	 	 	 	 	 	 	

	 	 	 	 	 	 	

 

Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

AIII-3 

to the imparted seismic energy. The response signals 

are used to produce a vertical seismic profile of the 

Earth’s subterranean formations surrounding the 

well bore. 

•	 Application: Classic use is to depth correct a 

seismic survey (to tie horizons measured in time to 

those observed with wireline logs or cores in wells). 

Added value is to increase resolution relative to 

surface seismic, so that thin zones can be detected, 

for example if the CO2

 plume is thin. VSP provides 

high-resolution seismic image of the immediate 

vicinity of the borehole. VSP can be implemented 

in a “walk-away” fashion to monitor the footprint of 

the plume as it migrates away from the injection well. 

Walk-away VSP is employed by placing the source 

progressively further and further down-gradient 

from the injection well in order create an offset at the 

surface as the receivers are held in a fixed location. 

This technique yields a mini 2-D seismic line that 

can be of higher resolution than surface seismic data 

and provides more continuous coverage than an offset 

VSP. Furthermore, walk-away VSPs with receivers 

placed above the reservoir can be an effective method 

to quantify seismic attributes and calibrate surface 

seismic data. 

•	 Benefits: Technology can provide robust information 

on CO2

 concentration and migration in the vicinity of 

a single well bore and delineate potential migration 

pathways (e.g., fractures). 

•	 Challenges: Application limited to monitoring in a 

limited area surrounding a wellbore. 

•	 Geologic Storage Experience: VSP will be used 

by the RCSPs (MRCSP, SECARB, SWP, and

WESTCARB) during their Phase II projects to

evaluate cap rock integrity in the vicinity of the CO2 

injection well. 

3. Magnetotelluric Sounding (Potential) 

•	 Description: Natural-source, electromagnetic 

geophysical method for imaging structures below the 

Earth’s surface by mapping the spatial variation of the 

Earth’s resistivity using electrical currents (or telluric 

currents) created by natural variations in the Earth’s 

magnetic field. The Earth’s naturally varying electric 

and magnetic fields are measured over a wide range 

of frequencies (0.0001 to 10,000 Hz). Concurrent 

measurements of orthogonal components of the 

electric and magnetic fields permit the calculation 

of the impedance tensor, which is complex and 

frequency-dependent. Using this tensor, it is possible 

to gain insight into the resistivity structure of the 

surrounding material (Cantwell, 1960). 

•	 Application: The magnetotelluric sounding 

method was originally used for academic research. 

It was used successfully for the mapping of 

geothermal reservoirs starting in the early 1980s 

and became a standard application. In recent years, 

magnetotellurics has also become increasingly 

popular in oil and mineral exploration. DOE and the 

National Nuclear Security Administration (NNSA) 

at their Nevada Site Office addressed ground-water 

contamination resulting from historic underground 

nuclear testing and used magnetotelluric sounding 

to define the character, thickness, and lateral extent 

of the pre-Tertiary confining units (Williams et al., 

2007). 

•	 Benefits: Can probe the Earth to depths of several 

tens of kilometers. 

•	 Challenges: Requires further development for 

monitoring of CO2

 movement. The resolution of 

magnetotelluric surveys is limited by the diffusive 

nature of electromagnetic propagation in the earth; 

it is usually on the order of hundreds of meters to 

kilometers. 

•	 Geologic Storage Experience: For planned use 

of magnetotelluric sounding by the RCSPs, see 

Table 5-1. 

4. Electromagnetic Resistivity (Potential) 

•	 Description: EM is a technique used to measure 

the electrical conductivity of the subsurface, 

including soil, groundwater, rock, and buried objects. 

Electromagnetic techniques are sensitive to rock 

pore fluids within the subsurface, and they have been 

proposed for imaging CO2 in EOR. Electromagnetic 

data are commonly presented as contour plots. 

•	 Application: An important consideration in any EOR 

application is to distinguish between injection stream 

and gases, injected fluids, and formation fluids. The 

sensitivity of electromagnetic response to pore fluids, 

coupled with advances in computational capability, 

inversion code resolution, and field instrumentation, 

make borehole EM techniques a potential tool for 

such subsurface imaging applications (Kirkendall 

and Roberts, 2001). EM meters respond strongly to 
	 	 	

	 	 	 	 	 	 	

	 	 	 	 	 		

AIII-4 Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

metal, which can be an advantage when the target is 

metallic, but surveys can be affected by extraneous 

metallic objects, for example well casings. 

•	 Benefits: Soil-to-instrument contact is not required, 

allowing much more rapid data acquisition over 

other resistivity techniques (which utilize metal pins 

inserted into the ground) and overcomes coupling 

problems that can be associated with Ground 

Penetrating Radar (GPR) methods. 

•	 Challenges: EM meters respond strongly to metal. 

This can be an advantage when the target is metallic, 

but surveys can be affected by extraneous metallic 

objects, such as wells. Resolution is often a challenge. 

•	 Geologic Storage Experience: Frio pilot tested cased 

hole–cross-well EM, but well spacing was too close 

for successful use with steel casings. 

5. Electromagnetic Induction Tomography 

(Potential) 

•	 Description: EMIT is a promising new tool for 

imaging electrical conductivity variations in the 

Earth. Crosswell EM imaging takes advantage of 

the differences in the way electromagnetic fields are 

induced within various materials (Kirkendall and 

Roberts, 2002). For example, rocks containing a lot 

of water, typically in the form of droplets bound to 

tiny rock pores, usually conduct electricity better than 

rocks containing CO2. The technique uses magnetic 

fields to image the subsurface; it was developed for 

use by the oil and gas industry to determine where 

reserves are located. The electromagnetic source 

field is produced by induction coil (magnetic dipole) 

transmitters deployed at the surface or in boreholes. 

Vertical and horizontal component magnetic field 

detectors are deployed in other boreholes or on the 

surface. Sources and receivers are typically deployed 

in a configuration surrounding the region of interest. 

Although such electromagnetic field techniques 

have been developed and applied, the algorithms 

for inverting the magnetic field data to produce the 

desired images of electrical conductivity have not 

kept pace. EMIT is capable of mapping the changes 

in resistance of subsurface formations using magnetic 

fields. 

•	 Application: EMIT is used to generate 3-D images of 

passive electromagnetic properties in the subsurface 

for applications such as site characterization 

and plume tracking. EMIT has shown success 

being deployed in petroleum applications for 


field characterization and steam flood monitoring 


(Berryman et al., 2000).

•	 Benefits: Electrical techniques show promise of 

quantifying saturation through a broader range than 

acoustic techniques, and joint inversion might be 

productive. EMIT provides greater resolution and 

petrophysical information that ERT. 

•	 Challenges: Relatively new technology that needs 

further development to accurately and systematically 

invert magnetic field data to produce images of 

electrical conductivity. Technology requires a robust 

computational and equipment package. It is more 

difficult to execute and requires non-conductive 

casing downhole to obtain high-frequency data. 

6. Injection Well Logging (Wireline Logging) 

(Primary) 

•	 Description: One of the commonest methods for 

evaluating geologic formations is the use of well logs. 

Logs are conducted by lowering an instrument into 

the well and taking a profile of one or more physical 

properties along the length of the well. A variety 

of well logs is available that can measure several 

parameters from the condition of the well to the 

composition of pore fluids and the mineralogy of the 

formation. 

•	 Application: Well logs for CCS projects will be 

most useful for detecting the condition of the well 

and ensuring that the well itself does not provide a 

leakage pathway for CO2

. Several logs are routinely 

used for this purpose, including temperature, noise, 

casing integrity, and radioactive tracer logs (Benson

et al., 2002). However, the resolution of well logs may 

not be sufficient to detect very small rates of seepage 

through microcracks (Benson and Meyer, 2002).

Several wireline logging technologies are described in 

this appendix. 

•	 Benefits: Very useful for wellbore leakage. 

•	 Challenges: Area of investigation limited to 

immediate wellbore. 

7. Annulus Pressure Monitoring (Primary) 

•	 Description: The most common internal MIT done 

pursuant to the UIC program is the standard annular 

pressure test (SAPT). The SAPT is a simple test, 
	 	 	 	 	 	 	 	

Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

AIII-5 

wherein the annular space between the tubing and 

casing is subjected to pressure above hydrostatic, 

and if the pressure can be maintained for a specified 

period of time within a specified percentage of loss 

or gain, the well is deemed to have passed. Most 

commonly, the SAPT is complimented by the 

cementing records external, or prong two, MIT. Test 

pressures ranging from 200 psi up to 2,500 psi are 

used (U.S. EPA, 1998). The testing interval is most 

commonly 30 minutes, but the allowable percentage 

of pressure gain or loss varies widely. The SAPT 

is most often performed with water in the annulus 

and water as the pressurizing agent. However, most 

jurisdictions allow the use of nitrogen or compressed 

air as the pressure source, if the annulus is liquid 

filled. Complete testing requirements as outlined by 

EPA can be found at: http://www.epa.gov/region5/ 

water/uic/r5guid/r5_05.htm. Positive annular 

pressure can be maintained as a leakage-prevention 

measure and to assure that the packer is seated; high 

frequency readouts (seconds to daily) can be recorded 

or transmitted to monitoring site with alarm to 

provide high assurance of correct well performance. 

•	 Application: Used to test the integrity of the annular 

space between the tubing and the well casing. 

•	 Benefits: Testing procedure to ensure the integrity, 

longevity, and function of injection wells under 

the UIC program. Suite of required equipment is 

minimal. 

•	 Challenges: Short duration test cannot assure 

absence of slow leakage if elevated pressure over 

long periods of time. Constant positive pressure 

maintenance requires maintenance of readout. 

•	 Geologic Storage Experience: Positive annular 

pressure with real-time readout to assure current well 

performance was used at Frio test and SECARB’s

Phase II test at Cranfield. 

8. Pulsed Neutron Capture (PNC) (Secondary) 

•	 Description: Changes in fluid composition from 

brine to CO2 respond strongly to pulsed neutron 

methods, for example thermal decay logging and 

carbon/oxygen (C/O) ratio. Various pulsed neutron 

techniques can be combined in one tool for greater 

analytical capabilities, one tool that can be lowered 

into the cased well and is capable of assessing oil 

saturation, lithology, porosity, oil, gas, and water 

as a function of well depth using pulsed neutron 

techniques. Most rigorous quantification of CO2 

change in saturation is obtained by measuring the 

change in pulsed neutron response (sigma) in time 

lapse that is by comparing logs run after CO2

 plume 

development to a baseline collected prior to injection. 

Wellbore correction logs provide fluid properties and 

temperature. 

•	 Application: In addition to the measurements 

discussed above, PNC is used to identify leakage 

through the cemented annular space of the well in 

geologic CO2

 sequestration applications. 

•	 Benefits: A wireline technique that can be used to 

quantify CO2

 saturation near the well bore. Log can 

be run through steel casing and tubing. 

•	 Challenges: Sensitive to wellbore conditions and 

requires correction. Workover by low or high salinity 

water modifies fluid and especially degrades pulsed 

neutron response. Fluid characteristics identified only 

in the vicinity of the wellbore. 

9. Electrical Resistivity Tomography (Potential) 

•	 Description: ERT is a geophysical technique 

for imaging subsurface structures from electrical 

measurements made at the surface or by electrodes 

in one or more boreholes. It is a subsurface imaging 

technology that measures electrical resistivity in soil 

and rock. This technology can be used to obtain 

“snapshot” images of relatively static subsurface 

conditions for site screening or characterization. 

It can also be used to obtain a series of images 

showing the relatively rapid changes caused during 

environmental remediation. An ERT, for near-surface 

and subsurface imaging, data acquisition system 

acquires a series of voltage and current measurements 

from surface electrode arrays or electrode arrays 

emplaced underground. The electrode arrays consist 

of electrode dipoles that communicate with other 

dipoles. The electrode dipoles are fastened at regular 

intervals (typically five feet apart) to a supporting 

shaft or string. The electrode arrays can be spaced 

close to each other or hundreds of feet apart, 

depending upon the resolution needed. 

•	 Application: ERT works well in both the vadose 

(unsaturated) and saturated subsurface zones. The 

extensive data resulting from measurements taken 

between the electrode arrays are processed to produce 

electrical resistivity tomographs using state-of-the-art 

inversion algorithms. These calculated tomographs 
	 	 	 	 	 	

	 	

	 	

 

 

 

 

		 	 	 	 	

		 	 	 	 	 	 	

AIII-6 Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

show spatial variations in electrical resistivity. The 

tomographs show the location and shape of electrical 

resistivity zones, and these images can be used as a 

guide for focusing more detailed characterization and 

monitoring evaluations (Newmark et al., 2001). ERT 

for subsurface imaging was developed for DOE’s 

Office of Science and Technology (OST) by LLNL. 

ERT commonly operates in one of two modes. For 

in-situ applications, ERT uses electrodes on the 

ground surface or in boreholes. In some cases, these 

are spaced electrode arrays as strings or mounted on 

casing (Daily et al., 2004). Alternatively, previously 

installed casing may also serve as single long 

electrodes; this second mode is called long electrode 

electrical resistance tomography (LEERT) (Binley et

al., 1999). 

•	 Benefits: Can detect change in fluids (gas substitution 

for water). Depth of penetration of a surface array 

depends on the rock and fluid properties. 

•	 Challenges: Requires installation of large electrode 

array around site. Data quality decreases as 

electrodes are placed further apart. Technology needs 

further development for monitoring CO2

 movement. 

Likely poor to no sensitivity to leaks occurring as 

dissolved fluids. 

•	 Geologic Storage Experience: ERT is being tested 

in both surface and crosswell arrays at a shallow 

injection zone at the CO2

 Sink project at Ketzin, near 

Berlin, Germany.

10. Sonic (Acoustic) Logging (Primary) 

•	 Description: A sonic log is a porosity log that 

measures interval transit time (∆t) of a compression 

sound wave travelling through one foot of formation. 

Sonic logging is essential to calibration of surface 

seismic methods. The sonic log device consists of 

one or more sound transmitters and two or more 

receivers. Sonic logs are compensated for borehole 

size variations, as well as for errors due to tilt of the 

sonic tool. Interval transit time (∆t) in microseconds 

per foot is the reciprocal of the velocity of a 

compression sound wave in feet per second. A sonic 

derived porosity curve is usually recorded along with 

the ∆t curve. Sonic logs generally have additional 

information recorded with them, which may include a 

caliper log, gamma ray log, or an SP log. The interval 

transit time (∆t) is dependent on both the lithology 

and porosity, so a formation’s matrix velocity must be 

known to derive the sonic porosity. This can be done 

by using a chart or by following the Wyllie formula 

below. 

φsonic = 

∆t

log – ∆t ma 

∆t

f – ∆t ma 

where φsonic = Sonic derived porosity 

∆t

log = Interval transit time of the formation 

∆t = Interval transit time of the matrix ma

∆t

f = Interval transit time of the fluid in the 

well bore 

The Wylie formula for calculating sonic porosity 

can be used to determine porosity in consolidated 

sandstones and carbonates with intergranular porosity 

or intercrystalline porosities. However, when sonic 

porosities of carbonates with secondary vuggy or 

fracture porosity are calculated by the Wylie formula, 

porosity values will be too low. This is because 

the sonic log only records matrix porosity. Total 

porosity can be obtained by using one of the nuclear 

logs (density or neutron). In full waveform sonic 

logging, the complete acoustic wave at each receiver 

is recorded digitally. The character of the acoustic 

signal detected by the receivers is affected by, among 

other things, the mechanical properties of the rock 

around the borehole. In addition, sonic logs represent 

one of the best ways to tie seismic data to the actual 

subsurface conditions. The well to seismic ties are 

usually done after final seismic processing, assuming 

that the seismic data are of high quality with no 

significant problems. 

•	 Application: Sonic log uses include determination

of porosity in porous rocks, measurement of 

permeability in porous rock, detection of fractures, 

and even lithology characterization (Paillet and 

White, 1982). 

•	 Benefits: Sonic velocity contrast between water and

CO2

 is strong, so that this log type can be used to 

assess changes in fluid as the CO2 plume moves past 

the wellbore. Some sonic logs can be collected in 

cased wells. Sonic logs can be converted to synthetic 

seismograms to effectively tie site specific well bore 

information to seismic lines, thereby converting the 

data to a more spatial applications. 
Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

AIII-7 

•	 Challenges: The technique only measures sound 

travel time and requires additional data manipulation 

to arrive at porosity. No standard protocol for 

conversion from travel time to porosity; there 

are many variations of the travel time/porosity 

relationship. 

•	 Geologic Storage Experience: Acoustic logs were 

successfully used to detect CO2

 at the Nagaoka 

project, Japan. Acoustic logs were tested at the Frio 

project and showed change in the interval where CO2 

was present, but signal could not be quantified 

11. 2-D Seismic Survey (Secondary) 

•	 Description: Reflection seismic is a method that 

allows imaging of changes in the subsurface geology 

by inducing an acoustic wave from near the surface 

of the Earth and listening for the echoes from deeper 

stratigraphic boundaries. 2-D seismic is recorded 

using straight lines of receivers crossing the surface 

of the Earth. Acoustic energy is usually provided 

by the detonation of explosive charges or by large 

vibroseis trucks. The sound spreads out through 

the subsurface as a spherical wave front. Interfaces 

between different types of rocks will both reflect and 

transmit this wave front. The reflected signals return 

to the surface where they are observed by sensitive 

microphones known as geophones. The signals 

detected by these devices are recorded and sent to 

data processors where they are adjusted and corrected 

for known distortions. The final processed data is 

displayed in a form known as “stacked” data. The 

resulting profile is visualized as a 2-D slice through 

the Earth. 

•	 Application: In a monitoring program, an 

initial seismic survey contributes to geologic site 

characterization. In addition, the survey provides 

an initial baseline that can be compared to changes 

in subsequent seismic monitoring surveys to create 

a time lapse image of CO2

 plume migration and to 

detect significant leakage and migration of CO2

 from 

the storage site (Monea et al., 2008). 

•	 Benefits: No wellbores or drilling needed to 

characterize subsurface. 

•	 Challenges: Very energy intensive technique. 

Environmental impacts associated with using 

underground explosions or vibroseis trucks, clearing 

vegetation to install geophones, or building new roads 

to transport equipment and personnel. 

12. Time-lapse Gravity (Potential) 

•	 Description: A gravity survey is based on the 

premise that a target is restricted in space and has 

a different density from the surrounding geology, 

e.g. that a ‘pool’ of gas has collected at shallow 

depth. This technique employs measurements of the 

gravitational field at a series of different locations 

over an area of interest in order to monitor changes 

in the density of fluid resulting from leaked CO2

. For 

CO2 monitoring, time-lapse gravity measurements 

would be expected to show a decrease as CO2 

accumulation proceeds, since CO2

 is less dense than 

the groundwater it replaces. The method can detect 

mass changes, and possibly surface deformations, 

induced by the storage process or by possible CO2 

leakage into the overburden. 

•	 Benefits: Non-invasive surface measurement 

indicative of fluid change at depth. 

•	 Challenges: Limited detection and resolution unless 

gravimeters are located just above reservoir (wellbore gravimetry). Detection threshold for CO2

 is 

highly site specific, depending on the reservoir’s 

depth (deeper reservoirs are less suitable), physical 

properties, and the survey conditions. Then, leaked 

CO2

 would only be detected by gravity change 

if it accumulated in a shallow reservoir; leakage 

scenarios where it leaks along a thin (fault, well, 

or thin zone) flow path would not be detected. An 

additional problem is the difficulty of eliminating all 

other sources of gravity variations and noise (tides, 

instrument drift, regional gravity contributions, etc.) 

to permit interpretation of the anomaly in terms of the 

geologic and geophysical parameters of the localized 

target. 

•	 Geologic Storage Experience: As proof of concept, 

gravity surveys were conducted at Sleipner West 

where CO2

 injected into the Utsira injection zone, 

which lies at relatively shallow (800 m) depths 

beneath the North Sea floor, to obtain a gravity 

baseline. A second test was conducted three years 

later to detect changes due to continued CO2 injection. 

Results were favorable with better-than-expected 

repeatability (Hoversten and Gasperikova, 2005; 

Nooner et al., 2006). Gravity should be even more 

sensitive for a gas phase CO2 leak. 
	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 		 	

	 	 	 	 		 	 	 	 	 	

		 	 	 	 	 	

		 	 	

		 	 	 	 	 	 	

	 	 	 	 	 	 	

	 	 	 		 	 	 	 	 	 	 	

		 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	

AIII-8 Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

13. Density Logging (RHOB Log) (Secondary) 

•	 Description: RHOB is derived from RHO, the Greek

letter used to represent density, plus B for bulk. Bulk

density is the density of the formation including any 

fluids in the pore space. A RHOB log provides a

continuous record of a formation’s bulk density as a 

function of depth by accounting for both the density 

of the matrix and the density of the liquid in the pore 

space. RHOB measurements are typically linear,

often in the interval 1.95-2.95 g/cm3 

. RHOB is

often measured as a combination of density-neutron 

together with gamma and calliper (calliper logs 

record borehole diameter) because gamma provides 

repeatability and calliper is good for quality control. 

•	 Application: Used to provide a continuous record of 

a formation’s bulk density as a function of depth. 

•	 Benefits: Technology can estimate formation density 

and porosity at varying depths. 

•	 Challenges: Lower resolution log compared to other 

wireline methods. High 
-radiation zones (uranium 

ore) can yield erroneous low density log values (Hill, 

1993). 

14. Optical Log (Secondary) 

•	 Description: Camera system is lowered into a cased 

well for visual casing inspection. A cable feed to 

the surface provides the operator a screen (Cathode 

Ray Tube or Liquid Crystal Display). The angle of 

view can be rotated from looking directly down the 

center of the casing, to observing a portion of the side 

wall. Corrosion, cracks, holes, and loose joints can 

be detected visually. If required, ultraviolet light can 

be used to detect micro-fractures in the casing. The 

camera is equipped with a video recording device and 

a depth counter to pinpoint any compromised areas. 

•	 Application: Lowered into a cased well for visual 

casing inspection. 

•	 Benefits: Readily available technology. 

•	 Challenges: Can be time consuming. Image quality 

may be poor. Stray radio frequencies can deteriorate 

image. 

15. Cement Bond Log (Ultrasonic Well Logging) 

(Primary) 

•	 Description: CBLs use sonic attenuation and travel

time to determine whether casing is cemented or free. 

Cement bond logs use waveforms having frequencies 

that range from 200 kilohertz (kHz) to 700 kHz that 

are in the transmitter portion of the logging tool. 

A rotating acoustic sensor is employed to measure 

acoustic energy through a 360 degree rotation. The 

rate of decay of the waveforms received indicates 

the quality of the cement bond at the cement/casing 

interface, and the resonant frequency of the casing 

provides the casing wall thickness required for 

pipe inspection. Because the transducer is mounted

on the rotating receiver, the entire circumference 

of the casing is scanned. This 360° data coverage 

enables the evaluation of the quality of the cement 

bond, as well as the determination of the internal 

and external casing condition. If available, a shop 

calibration record should be attached. The surface 

pressure under which the log was run should be noted 

on the log form. If an initial CBL does not indicate

the presence of cement, often a second log will be 

run with pressure on the casing. This may show 

cement while the earlier log does not. In this case, a 

microannulus has developed due to past expansion of 

the casing while it was pressurized during operations 

or testing. It is sometimes necessary to pressurize the 

casing above the highest pressure to which it has been 

subjected. 

•	 Application: The CBL is effective for evaluating

conventional cement slurries and foam cement 

slurries. It performs the functions of cement 

evaluation, casing inspection, corrosion detection and 

monitoring, detection of internal and external damage 

or deformation, and casing thickness analysis for 

collapse and burst pressure calculations. 

•	 Benefits: The CBL clearly indicates top of cement,

free pipe, and gives an indication of well cemented 

pipe. Assessment of the rock-annulus not accessible 

by other techniques. 

•	 Challenges: Good centralization is important for 

meaningful and repeatable CBLs; CBLs should not

be relied on for a quantitative evaluation of zonal 

isolation or hydraulic integrity. Cement should be 

allowed to cure for at least 72 hours before logging. 

May not detect micro-annulus or channeling. Cannot 

assess permeability of the cement or geochemical 

modification, such as by interaction with CO2

. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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AIII-9 

16. Gamma Ray Logging (Secondary) 

•	 Description: Technique using natural gamma 

radiation to characterize the rock or sediments in 

a borehole. Various rocks emit different amounts 

of natural gamma radiation. Shales, in particular, 

typically emit more gamma rays than other 

sedimentary rocks, such as sandstone, gypsum, 

salt, coal, dolomite, and limestone. Shales emit 

more gamma radiation due to elevated radioactive 

potassium in their clay content and because the 

cation exchange capacity of clays causes them to 

adsorb uranium and thorium. The gamma ray log is 

conducted by lowering an instrument down the well 

and recording gamma radiation as a function of depth. 

In the U.S., readings are most commonly taken at 

half-foot intervals. 

•	 Application: Gamma logging is most commonly used 

for formation evaluation in oil- and gas-well drilling 

and sometimes in mineral exploration and water-well 

drilling. 

•	 Benefits: Common measurement of the natural 

emission of gamma rays by a formation. Can 

operate through the steel and cement walls of cased 

boreholes because sufficient gamma radiation travels 

through the steel and cement to allow qualitative 

determinations of the formation despite some gamma 

absorption. 

•	 Challenges: Subject to error when a large proportion 

of the gamma ray radioactivity originates from the 

sand-sized detrital fraction of the rock (Heslop, 1974; 

Rider, 1990). 

17. Microseismic (Passive) Survey (Secondary) 

•	 Description: Microseismic monitoring has been 

employed for about 40 years to measure down-hole 

processes. It is rooted in earthquake seismology; and, 

thus, the basic theoretical underpinnings are clearly 

known. The approach provides an image of fractures by 

detecting microseisms (micro-earthquakes) triggered 

by shear slippage. The location of the microseismic 

events is obtained using a down-hole receiver array 

that is positioned at depth in a second well near the 

injection well. Microseismic mapping can be performed 

in the injection well in cases where suitable offset 

monitoring wellbores are not available. It is common 

to pair microseismic and tiltmeter surveys (Figure 

AIII-1). Microseismic fracture mapping measures very 

small seismic events, commonly between M -4 and 0. 

However, the seismic waves attenuate in the crust, and 

it is often difficult to detect events that are more than 

800 m away. The rate at which the waves attenuate 

is a function of the rock petrophysics, which can be 

readily measured using conventional logging tools or in 

petrophysical laboratories. 

Figure AIII-1: Crustal deformation survey interpretations. (Left) Tiltmeter array interpretation from an oil field operation, 

revealing the location of a small change in surface elevation. Image courtesy of Pinnacle Technologies, Inc. (Right) InSAR 

difference map showing complex subsidence (red) and uplift (blue) associated with oil field production near Bakersfield, 

California, from August 1979 to September 1999. Color bands show roughly 60 millimeters of change from red to blue; 

resolution is one millimeter deformation. The image shows large oil fields and illustrates how faults can affect the 

distribution of deformation. Image courtesy of the U.S. Geological Survey (USGS). 
	 	

	 	 	 	 	 	 	 	 	

AIII-10 Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

•	Application: Microseismic surveys are regularly used 

to monitor hydrofracturing in commercial oil fields, 

as well as to track flow fronts and pressure waves 

during water injection. Passive seismic can be used 

to monitor the formations above the reservoir for 

evidence of CO2 migration through the seal rock and 

assess fracture propagation. 

•	 Benefits: Since passive seismic uses natural wave 

generators instead of a vibroseis truck or explosives, 

it has advantages for remote areas where it is difficult 

to locate vibroseis trucks and for environmentally 

sensitive areas. Provides a unique dataset that can be 

used to map the important feature of pressure through 

a 3-D volume. May indentify areas of weakness 

(fractures and faults). 

•	 Challenges: Some fluid-rock systems may produce 

no acoustic signal. Inversions can yield some location 

uncertainty; incorrectly located events can add 

uncertainty. 

•	 Geologic Storage Experience: Anneth. 

18. Crosswell Seismic (Potential) 

•	 Description: Crosswell seismic is conducted between 

wells with the source and receivers placed inside sets 

of wellbores. The receiver arrays are held fixed in 

one or more wells, while the source is slowly drawn 

upwards (source run) in the other well and is “fired” 

at preset intervals. The receivers are relocated and 

the source run is repeated. Typical spacing between 

adjacent source points ranges from 2.5 feet (0.8 

meters) to 20 feet (6 meters). Receiver separation 

is usually similar. It is possible for these systems 

to acquire 20,000 or more traces in a single, 24­

hour day. A complete survey can be as small as a 

few thousand traces or as large as several hundred 

thousand traces. Such factors as the well separation, 

the thickness and structure of the imaging target, 

and the frequency content of the received signal 

dictate the necessary size of a survey. Crosswell 

surveys typically utilize a frequency band ranging 

from 20 to 2,000 Hz, depending on the type of 

source used, the distance between wells, and 

the attenuation characteristics of the zone under 

investigation. Resolution on the order of 10 feet (3 

meters) is possible. Crosswell processing is similar to 

surface seismic processing in that it includes velocity 

estimation (travel time tomography) and reflection 

imaging. Reflection imaging provides more resolution 

than the velocity image (tomogram) and depends 

significantly on the accuracy of the velocity model for 

good results. 

•	 Application: Crosswell profiling is a technology for 

reservoir delineation, development, characterization, 

and monitoring, but not exploration. Monitoring 

changes in reservoir conditions (e.g. saturation or 

pressure) is quite effective, but monitoring requires 

multiple visits to the same site in order to obtain 

time-lapse images. Imaging of reservoir properties 

(e.g., porosity), can be successful and contribute 

to characterization (Harris and Langan, 2001). A 

special case of crosswell surveillance—Continuous 

Active Seismic Source Monitoring (CASSM)— 

was developed by LBNL (Daley, et al., 2007) for

deployment at Frio. In this method, the source array 

and receiver string were run in the wells on tubing 

and left in place as the injection proceeded, providing 

real time data on plume migration . 

•	 Benefits: Crosswell seismic profiling provides higher 

resolution than surface methods but samples a smaller 

volume. 

•	 Challenges: Mass of CO2

 and dissolution/mineral 

trapping are not measured by seismic techniques. 

Wells must be controlled (run in imperforated 

boreholes or CO2 pushed back from the sand face 

by “kill” fluids) prior to running surveys; this 

limits opportunities for geochemical or well-based 

monitoring. 

•	 Geologic Storage Experience: Frio, Lost Hills. 

Several of DOE’s RCSPs are implementing crosswell 

seismic surveys to assess seal performance and 

measure plume geometry for their Phase II and Phase 

III injection projects. 

19. Aqueous Geochemistry (Primary) 

•	 Description: Measuring geochemical evolution of 

subsurface formation waters including dissolved 

CO2

, dense phase CO2, and other fluids requires fluid 

sampling on a regular basis. Monitoring could be 

undertaken in boreholes that penetrate the reservoir 

or in monitoring wells that penetrate overlying 

formations. Measurements could include parameters, 

such as: pH, HCO3

-2, alkalinity, dissolved gases, 

hydrocarbons, major and minor elements, TIC, TOC, 

stable isotopes, redox potential, specific conductance, 

TDS, density, natural and introduced tracers. It is 
Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

AIII-11 

important to design the sample retrieval system that 

will conserve the properties that are required for 

analysis. Fluid mixtures (CO2

-brine plus any other 

relevant gases or hydrocarbons) will density-separate 

in the wellbore, and this fractionation will increase as 

fluids move upward through tubing and gases expand 

and become less dense. Temperature and solubility 

relationships will also change, for example gas in 

solution will evolve. If needed, several techniques 

can be used to reduce these complications. 

•	Application: Commercial downhole sampler systems 

can be deployed on wireline or slickline to collect 

samples at reservoir pressure and temperature and 

then conserve this volume during transport to the 

surface. A U-tube sampler was designed for the Frio 

Project that allows samples to be returned to surface 

at near reservoir pressures (Freifeld and Trautz, 

2006). The U-Tube is composed of a double length of 

high pressure stainless steel tubing with a check valve 

open to the reservoir. Formation fluid is collected 

in the U-Tube, driven at reservoir pressure into 

evacuated sample cylinders at the surface by highpressure, ultra-pure nitrogen. Free gas in the sample 

and gases coming out of solution are pumped from 

the top of the gas separator through a quadrapole 

mass spectrometer analyzer and a landfill gas 

analyzer to measure changes in gas composition in 

the field (Figure AIII-2). Geochemical analysis must 

also be matched to the analysis requirements, which 

may require measurement of gas and liquid fractions 

at known pressure and temperature, collection of field 

parameters, filtration, stabilization, labeling, storing, 

and shipping samples. 

•	 Benefits: Geochemistry provides detailed 

information needed to confirm model predictions. In 

particular, it is the only technique available that has 

promise to document dissolution and mineral trapping 

or, conversely, any geochemical interactions that may 

lead to increased risk (e.g., damage to formation, 

confining zone, or engineered system). 

•	 Challenges: Requires well penetration, well 

perforation, and sampling apparatus and personnel. 

Well drilling and completion causes contamination of 

the near well-bore environment with allochthonous 

fluids; that must be reduced and corrected for. 

Extraction of fluids is labor-intensive, requiring a gas 

lift or pumping system except where pressure or gas 

saturation are high enough to lift fluids to the surface. 

Figure AIII-2: Schematic Drawing of the U-Tube Sampling Technology 
	 	

AIII-12 Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

•	 Geologic Storage Experience: Weyburn had an 

extensive fluid sampling effort that documented rockwater-CO2

 interaction. Frio also had high quality 

frequency sampling to document breakthrough, 

transport properties, and geochemical reaction. Otway 

had geochemical sampling to document breakthrough 

and tracer movement. 

20. Resistivity Logs (Secondary) 

•	 Description: A log of the resistivity of the formation, 

expressed in ohm-meters, to characterize the rock 

or sediment in a borehole. The resistivity may 

cover a wide range of values and, for convenience, 

is usually presented on a logarithmic scale from 

(for example) 0.2 to 2,000 ohm-m. Resistivity is 

measured using four electrical probes to eliminate 

the resistance of the contact leads. The log must be 

run in wells containing electrically conductive fluid 

(mud or water). The resistivity log is fundamental 

in formation evaluation, since hydrocarbons do 

not conduct electricity, while all formation waters 

do. Therefore, a large difference exists between the 

resistivity of rocks filled with hydrocarbons and those 

filled with water. 

•	 Benefits: High-resolution technique used to 

characterize the subsurface. 

•	 Challenges: Resistivity logs are affected by bed 

thickness, borehole diameter, and borehole fluid and 

can only be collected in water- or mud-filled open 

wells. 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 		 	 	 	 	 	 	 	 	 	 	 		

	 	 	 		 	 	 	 	 	 	 	 	 	 		

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 		 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

 

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	

 

	 	 	 	 	 	 	 	

Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

AIII-13 

APPENDIX III REFERENCES 

Benson, S.M., Hepple, R., Apps, J., Tsang, C.F., and Lippmann, M., 2002. Lessons learned from natural and industrial

analogues for storage of carbon dioxide in deep geologic formations. Lawrence Berkeley National Laboratory

Report LBNL-51170.

Benson, S., and Myer, L., 2002. Monitoring to ensure safe and effective geologic sequestration of carbon dioxide.

Lawrence Berkeley National Laboratory. IPCC Workshop on Carbon Dioxide Capture and Storage – 2002.

Berryman, J., Buettner, H., Champagne II, N., Grant, B., Sharp, R., Dorn, O., and Papanicolaou, G., 2000. Surface

and borehole electromagnetic imaging of conducting contaminant plumes. Report on EMSP Project #55011. 

http://www.athena.uc3m.es/~dorn/elmag/report1/firstyear.html#Directions. 

Binley, A., Daily, W., and Ramirez, A., 1999. Detecting leaks from waste storage ponds using electrical tomographic

methods. In: Proc. 1st World Congress on Process Tomography, pp 6-13. 

Cantwell, W.H., 1960. Detection and analysis of low frequency magnetoretelluric signals. In: Ph.D. thesis, M.I.T, 

Cambridge, MA (unpubl.). 

Daily, W., Ramirez, A., Binley, A., and LeBrecque, D., 2004. Electrical resistance tomography—Theory and practice.

Near Surface Geophysics, vol. 2. Society of Exploration Geophysicists. 

Daley, T.M., Solbau, R.D., Ajo-Franklin, J.B., and Benson, S.M., 2007. Continuous active-source seismic monitoring

of CO2 injection in a brine aquifer. Geophysics 72:A57-A61. 

Freifeld, B.M., and Trautz, R.C., 2006. Real-time quadrupole mass spectrometer analysis of gas in borehole fluid

samples acquired using the U-tube sampling methodology. Geofluids. 6(3): 217-224. 

Harris, J., and Langan, R., 2001. Crosswell seismic profiling: Principle to applications. Search and Discovery 

Article #40030. 

Heslop, A., 1974. Gamma-ray log response of shaly sandstones. Trans. SPWLA, McAllen, Texas. 

Hill, D., 1993. Density log errors due to high grade uranium ores. ROYAUME-UNI (1987-1992) (Revue). 7(4): 497-500. 

Pergamon Press, Oxford. 

Hoversten, G.M., and Gasperikova, E., 2005. Non-seismic geophysical approaches to monitoring. In: Carbon Dioxide 

Capture for Storage in Deep Geologic Formations – Results from the CO2 Capture Project. Volume 2: Geological 

Storage of Carbon Dioxide with Monitoring and Verification. Thomas, D.C., and Benson, S.M. (Eds.). Elsevier,

Oxford, UK. pp. 1071-1112. 

Kirkendall, B., and Robert, J., 2001. Electromagnetic imaging of CO2

 sequestration at an enhanced oil recovery site. 

Lawrence Livermore National Laboratory. Presented at: The 1st National Conference on Carbon Sequestration. 

http://www.netl.doe.gov/publications/proceedings/01/carbon_seq/6a3.pdf. 

Monea, M., Knudsen, R., Worth, K., Chalaturnyk, R., White, D., Wilson, M., Plasynski, S. McIlvried, H. G., 

and Srivastava, R. D. 2008. Considerations for monitoring, mitigation, and verification for geologic storage 

of CO2. American Geophysical Union (AGU) Monograph, Science and Technology of Carbon Sequestration, 

Sundquist, E.T. and McPherson, B., Eds, in press, 2008.
 

 

	 	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	 	

AIII-14 Appendix III 

Comprehensive Monitoring Techniques List—Subsurface Monitoring 

Newmark, R., Ramirez, A., and Daily, W., 2001. Monitoring carbon dioxide sequestration using electrical 

resistance tomography (ERT): Sensitivity studies. Developed for the 2001 U.S. Department of Energy’s First 

National Conference on Carbon Sequestration. 

http://www.netl.doe.gov/publications/proceedings/01/carbon_seq/carbon_seq01.html#Session7A. 

Nooner, S., Zumberge, M, Eiken, O., Stenvold, T., and Thibeau, S., 2006. Constraining the density of CO2 within 

the Utsira Formation using time-lapse gravity measurements. Proceedings of the 8th International Conference on 

Greenhouse Gas Control Technologies, Trondheim, Norway, 19–22 June 2006. 

Paillet, F., and White, J., 1982. Acoustic modes of propagation in the borehole and their relationship to rock 

properties. Geophysics, 47(8): 1215-1228. 

Rider, M., 1990. Gamma-ray log shape used as a facies indicator: Critical analysis of an oversimplified 

method. In: Geological application of wireline logs. Hurst, A., Lovell, M.A., and Morton, A.C. (eds.), Geological 

Society of London Special Publication No. 48. pp. 27-37. 

U.S. Environmental Protection Agency, 1998. Determination of the mechanical integrity of injection wells. 

United States Environmental Protection Agency Region 5 – Underground Injection Control (UIC) Branch Regional

Guidance # 5. http://www.epa.gov/region5/water/uic/r5guid/r5_05.htm. 

Williams, J.M., Wallin, E.L., Rodriguez, B.D., Lindsey, C.R., and Sampson, J.A., 2007. Magnetotelluric data,

Mid Valley, Nevada, Test Site, Nevada: U.S. Geological Survey Open-File Report 2007-1123, 137 p. 
AIV-1 Appendix IV 

Summary of the Purpose for Monitoring During the Phases of a Geologic Storage Project 

Appendix IV 

Summary of the Purpose for Monitoring During the 

Phases of a Geologic Storage Project 

Monitoring Activity 

Monitoring Phase 

Pre-Operational Operational Closure Post Closure 

Establishing baseline conditions from 

which the impacts of CO2 storage can 

be assessed 

Yes 

Ensure effective injection controls Yes 

Detect the location of the CO2

 plume Yes Yes 

Assessing the integrity of shut-in, 

plugged, or abandoned wells Yes If leakage 

detected 

If leakage 

not stopped 

If leakage 

not stopped 

Identify and confirm storage 

efficiency and processes Yes Yes 

Model calibration and performance 

confirmation – comparing model 

predictions to monitoring 

Yes Yes 

Detect and quantify surface seepage If leakage 

detected 

If leakage 

not stopped 

If leakage 

not stopped 

Assess health, safety, and 

environmental impacts of leakage 

If leakage 

detected 

If leakage 

not stopped 

If leakage 

not stopped 

Monitoring micro-seismicity 

associated with CO2

 injection Yes If micro-seismicity detected 

Monitoring to design and evaluate 

remediation efforts 

If leakage 

detected 

If leakage 

detected 

Provide assurance and accounting 

where monetary transactions 

are involved, such as with carbon 

trading and emission tax or emission 

reduction incentives. 

Yes Yes 

Evaluating interactions with or 

impacts on other geological resources 

(e.g., nearby water, coal, oil & gas, 

mineral reserves or other geological 

waste disposal operations. 

If interactions 

are possible 

If interactions 

are possible 

If interactions 

are possible 

Settling of legal disputes due to leaks, 

seismic events, or ground movement 

If leakage, 

seismicity or 

ground movement 

detected 

If leakage, 

seismicity or 

ground movement 

detected 

If leakage, 

seismicity or 

ground movement 

detected 

Assuring the public when visibility 

and transparency is of prime 

importance 

Yes Yes 
AIV-2 
Appendix V AV-1 

Overview of RCSP Projects Related to UIC Program 

Appendix V 

Overview of RCSP Projects Related to UIC Program 

Geologic 

Province 

Target 

Formation 

Geology 

Formation Type 

Total 

Injection 

(tons CO2) 

Approximate 

Depth (ft) Permit Class Permitting Agency 

Appalachian Basin 

Oriskany 

and Clinton 

Sandstone 

Saline formation 1,000–3 ,000 5,900–8,300 Class V Ohio EPA 

Cedar Creek, 

Billings, or Nesson 

Anticline 

Carbonate 

Formation Oil-bearing 3–6 million 9,800–11,250 Class II 

Cincinnati Arch Mt. Simon 

Sandstone Saline formation 1,000–3,000 3,200–3,500 Class V EPA Region IV 

Colorado Plateau 

Sandstone 

and 

Limestone 

Saline formation 2,000 3,500 

(1) Class V 

(2) Exploratory 

Stratigraphy 

Permit 

(3) Temporary 

Individual 

Permit 

(1) EPA Region 9 

(2) Arizona Oil and 

Gas Conservation 

Commission 

(3) Arizona 

Department of 

Environmental 

Quality 

Columbia Basin Basalt 

Formation Saline formation 3,000 3,255–3,335 & 

3,600–3,755 Class V Washington Dept. of 

Ecology 

Desert Creek and 

Ismay Zones 

Carbonate 

Formation Oil-bearing 450,000– 

750,000 5,600–5,800 Class II Navajo EPA and 

Federal EPA 

Devonian-aged 

rock 

Carbonate 

Formation Saline formation 11 million 6,500–7.500 NA NA 

Duperow 

Formation 

Carbonate 

Formation Oil-bearing 3,000–5,000 2,500–4,000 Class II North Dakota 

Industrial Commission 

Entrada Sandstone 

Formation Saline formation 4 million 8,000 Class V EPA Region 8 

Harmon Coal 

Seam 

Lignite Coal 

Seam 

Coal seam <1,000 1,600–1,800 Class II North Dakota 

Industrial Commission 

Horseshoe 

Atoll Play and 

Pennsylvanian 

Reef/Bank Play 

Carbonate 

Formation Oil-bearing 900,000 5,800 Class II Texas Railroad 

Commission 

Illinois Basin 

Mississippi 

Weiler 

Sandstone 

Oil-bearing Heavy 300 1,550 Class II Illinois DNR Oil & Gas 

Division 

TBD Oil-bearing Well 

Conversion 300 1,549 Class II Illinois DNR Oil & Gas 

Division 

TBD Oil-bearing Pattern 

Flood I 300 1,548 Class II Illinois DNR Oil & Gas 

Division 

TBD Oil-bearing Pattern 

Flood II 300 1,551 Class II Illinois DNR Oil & Gas 

Division 

Mt. Simon 

Sandstone Saline formation 10,000 7,000-8,600 Class I Illinois EPA 
AV-2 Appendix V 

Overview of RCSP Projects Related to UIC Program 

Geologic 

Province 

Target 

Formation 

Geology 

Formation Type 

Total 

Injection 

(tons CO2) 

Approximate 

Depth (ft) Permit Class Permitting Agency 

Lower Tuscaloosa Sandstone 

Formation Saline formation 3 million 10,000–10,500 Class V Mississippi Oil and Gas 

Board 

Lower Tuscaloosa Sandstone 

Formation Saline formation 400,000– 

1 million 8,500–9,000 Class V Primacy State 

(MS, AL, FL) 

Lower Tuscaloosa 

Massive Sand Unit 

Sandstone 

Formation Saline formation 3,000 8,600 

Class V 

(Permitted 

to Class I 

Requirements) 

Mississippi 

Department 

Environmental Quality 

McCormick Sand Sandstone 

Formation Saline formation 1,000 3,400–3,500 Class V EPA Region 9 

Michigan Basin Bass Island 

Dolomite Saline formation 3,000–20,000 3,200–3,500 Class V EPA Region V 

Middle Capay 

Shale 

Shale 

Formations Gas-bearing 500 3,050 Test Well 

(Class II) 

California Division 

of Oil, Gas, and 

Geothermal Resources 

(DOGGR) 

Middle Devonian 

Keg River 

Carbonate 

Formation Oil-bearing 250,000 (CO2

) 

90,000 (H2

S) 5,000 Class II Alberta Energy and 

Utilities Board 

Moxa Arch 

LaBarge Platform 

Nugget 

Sandstone Saline formation 3 million 11,000 Class V 

Wyoming Department 

of Environmental 

Quality (WDEQ) 

Pocahontas and 

Lee Formations 

Coal 

Formation Coal seam 1,000 1,600–2,300 Class II 

EPA Region III and 

Virginia Department 

of Mines & Minerals 

Pottsville 

Formation 

Black Creek, 

Mary Lee, 

and Pratt 

Coal Zones 

Coal seam 1,000 1,500–2,500 Class II Alabama Oil & Gas 

Board 

Stevens, Olcese, 

or Vedder 

Sandstones 

Sandstone 

Formation Saline formation 1 million 7,000–9,000 Class V Uncertain – likely EPA 

Tuscaloosa 

Formation 

Sandstone 

Formation 

Oil-bearing 

Saline formation >800,000/yr 10,066 Class II Mississippi Oil and Gas 

Board 

Upper Cretaceous 

Fruitland 

Formation 

Coal 

Formation Coal seam 75,000 3,000 Class II 

Mew Mexico Oil Cons. 

Division and Federal 

BLM 
Appendix VI 

Site Characterization and Mechanical Integrity Testing Detailed Decision Trees 

AVI-1 

Appendix VI 

Site Characterization and Mechanical Integrity Testing Detailed Decision Trees 

Site Characterization 

Typical site characterization procedure for a given GS project that includes 

mandatory siting requirements pursuant to 40 CFR § 146.14 & 146.24 
AVI-2 Appendix VI 

Site Characterization and Mechanical Integrity Testing Detailed Decision Trees 

Mechanical Integrity Testing
 

MIT Pathway Based on Regulations Set Forth in 40 CFR § 146.8 

and the Proposed Regulations for UIC Class VI Injection Wells 
	 	 	 		 	 	 	

	 	 	

	 	

	 	

	 	 	 	 	 	 	

List of Reviewers LoR-1 

List of Reviewers 

The following individuals/organizations provided 

technical insight that was critical to the development of 

this document. 

Susan Hovorka 

Gulf Coast Carbon Center. Bureau of Economic

Geology. The University of Texas at Austin 

Lee Spangler 

Montana State University 

Bruce Kobelski 

Underground Injection Control Program – U.S. EPA 

Julianna Fessenden 

Los Alamos National Laboratory 

Tom Daley 

Lawrence Berkeley National Laboratory

Lydia Cumming 

Battelle Memorial Institute

Neeraj Gupta 

Battelle Memorial Institute

Stephanie Wolfe 

University of North Dakota – Energy & Environmental

Research Center 

Richard Hammack 

National Energy Technology Laboratory – Geosciences 

Division 

Nick Woodward 

U.S. Department of Energy – Office of Science 

Comments from the U.S. Environmental 

Protection Agency 

Contacts
 

If you have any questions, comments, or would like 

more information about DOE’s Carbon Sequestration 

Program, please contact the following persons: 

Sean Plasynski 

Carbon Sequestration Program Technology Manager 

Strategic Center for Coal 

412-386-4867 

sean.plasynski@netl.doe.gov 

Dawn Deel 

Monitoring, Verification, and Accounting Focal Lead 

Strategic Center for Coal 

304-285-4133 

dawn.deel@netl.doe.gov 

John Litynski 

Sequestration Division Director 

Strategic Center for Coal 

304-285-1339 

john.litynski@netl.doe.gov 

Document Prepared by: 

Coordinating Lead Author: 

Rameshwar D. Srivastava, Ph.D - SAIC/NETL 

Lead Authors: 

Bruce Brown - SAIC/NETL 

Timothy R. Carr, Ph. D - WVU/SAIC 

Derek Vikara - SAIC/NETL 

Contributing Author: 

Howard McIlvried, Ph.D - SAIC/NETL 

Quality Assurance/Control: 

Joseph Giardina - SAIC/NETL 

Gregory Washington - SAIC/NETL 

Contract Information 41817.311.01.10.003 
1450 Queen Avenue SW 3610 Collins Ferry Road 626 Cochrans Mill Road 

Albany, OR 97321-2198 P.O. Box 880 P.O. Box 10940 

541-967-5892 Morgantown, WV 26507-0880 Pittsburgh, PA 15236-0940 

304-285-4764 412-386-4687 

WEBSITE: www.netl.doe.gov 

CUSTOMER SERVICE: 1-800-553-7681 

January 2009