Geologic Sequestration of Carbon 

Dioxide 

Underground Injection Control (UIC) 

Program Class VI Well Site 

Characterization Guidance

Office of Water (4605M) EPA 816-R-13-004 May 2013 
UIC Program Class VI Well i 

Site Characterization Guidance

Disclaimer 

The Federal Requirements under the Underground Injection Control Program for Carbon 

Dioxide Geologic Sequestration Wells (75 FR 77230, December 10, 2010), known as the Class 

VI Rule, establishes a new class of injection well (Class VI). 

The Safe Drinking Water Act (SDWA) provisions and U.S. Environmental Protection Agency 

(EPA) regulations cited in this document contain legally-binding requirements. In several 

chapters this guidance document makes suggestions and offers alternatives that go beyond the 

minimum requirements indicated by the Class VI Rule. This is intended to provide information 

and suggestions that may be helpful for implementation efforts. Such suggestions are prefaced by 

“may” or “should” and are to be considered advisory. They are not required elements of the rule. 

Therefore, this document does not substitute for those provisions or regulations, nor is it a 

regulation itself, so it does not impose legally-binding requirements on EPA, states, or the 

regulated community. The recommendations herein may not be applicable to each and every 

situation. 

EPA and state decision makers retain the discretion to adopt approaches on a case-by-case basis 

that differ from this guidance where appropriate. Any decisions regarding a particular facility 

will be made based on the applicable statutes and regulations. Mention of trade names or 

commercial products does not constitute endorsement or recommendation for use. EPA is taking 

an adaptive rulemaking approach to regulating Class VI injection wells, and the agency will 

continue to evaluate ongoing research and demonstration projects and gather other relevant 

information as needed to refine the rule. Consequently, this guidance may change in the future 

without a formal notice and comment period. 

While EPA has made every effort to ensure the accuracy of the discussion in this document, the 

obligations of the regulated community are determined by statutes, regulations or other legally 

binding requirements. In the event of a conflict between the discussion in this document and any 

statute or regulation, this document would not be controlling. 

Note that this document only addresses issues covered by EPA’s authorities under the SDWA. 

Other EPA authorities, such as Clean Air Act requirements to report carbon dioxide injection 

activities under the Greenhouse Gas Mandatory Reporting Rule (GHG MRR), are not within the 

scope of this document.
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Site Characterization Guidance

Executive Summary

EPA’s Federal Requirements Under the Underground Injection Control Program for Carbon 

Dioxide Geologic Sequestration Wells are codified in the U.S. Code of Federal Regulations [40 

CFR 146.81 et seq.] and are referred to as the Class VI Rule. The Class VI Rule establishes a 

new class of injection well (Class VI) and sets minimum federal technical criteria for Class VI 

injection wells for the purpose of protecting underground sources of drinking water (USDWs). 

This document is part of a series of technical guidance documents designed to support owners or 

operators of Class VI wells and the UIC Program permitting authorities. 

Site characterization is critical to operating safe and effective geologic sequestration (GS)

projects. The proper siting of a Class VI injection well is the foundation for successful GS 

operations. Site characterization identifies potential risks and eliminates unacceptable sites (e.g., 

sites with transmissive faults or fractures that would impair containment). Key aspects of an 

appropriate GS site, per 40 CFR 146.83, include geologic formations that provide adequate 

storage capacity to store the injected carbon dioxide and a competent confining zone that will

contain the injected carbon dioxide. Class VI well owners or operators also must identify 

additional confining zones, if required by the UIC Program Director. 

The Class VI Rule also requires owners or operators of Class VI wells to perform, among other 

activities, a detailed assessment of the geologic, hydrogeologic, geochemical, and geomechanical 

properties of the proposed GS site to ensure that wells are sited in suitable locations [40 CFR 

146.82(a) and (c)]. As part of the site characterization required to be documented in a Class VI 

permit application, owners or operators of Class VI wells must submit maps and geologic cross 

sections describing subsurface geologic formations as well as the general vertical and lateral 

limits of all USDWs at the proposed GS site [40 CFR 146.82(a)]. Data and information collected 

during site characterization are used in the development of injection well construction and 

operating plans; provide inputs for the computational model that estimates the extent of the 

injected carbon dioxide plume and related pressure front; and establish baseline information to 

which geochemical, geophysical, and hydrogeologic site monitoring data collected over the life 

of the injection project can be compared. 
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Site Characterization Guidance

This UIC Program Class VI Well Site Characterization Guidance describes those data and 

information that are typically used to characterize the geology of a site, including methods for 

measuring or estimating important geologic parameters. The introductory section of this

guidance provides an overview of the Class VI Rule, specifically with regard to geologic siting 

requirements. The second section describes the site characterization data needed to obtain a 

permit for the construction of a Class VI well. The third section addresses certain aspects of site 

characterization activities that involve the synthesis of geologic, hydrogeologic, geochemical, 

and geomechanical data in order to demonstrate that the project site is suitable for injection (i.e., 

has an injection zone capable of receiving the anticipated volume of carbon dioxide and a 

confining zone(s) capable of containing the plume and pressure front). The fourth section 

addresses requirements applicable to drilling and completion of the injection well that must be 

met before operation may be authorized, pursuant to 40 CFR 146.82(c) and 146.87. In each 

section, the guidance describes options for meeting the Class VI Rule requirements and the types 

of information recommended to be submitted. 
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Site Characterization Guidance

Table of Contents

Disclaimer ........................................................................................................................................ i

Executive Summary ........................................................................................................................ ii

Table of Contents ........................................................................................................................... iv

List of Tables ................................................................................................................................. vi

List of Figures ............................................................................................................................... vii

Acronyms and Abbreviations ...................................................................................................... viii

Definitions...................................................................................................................................... xi

1. Introduction ............................................................................................................................. 1

1.1. Overview of Class VI Rule Requirements ........................................................................ 2

1.2. Overview and Purpose of this Guidance ........................................................................... 4

1.3. Relationship to Other Class VI Activities ......................................................................... 6

1.4. Organization of this Guidance ........................................................................................... 8

2. Activities Performed Prior to Construction of a Class VI Well.............................................. 9

2.1. Regional Geology, Hydrogeology, and Local Structural Geology ................................... 9

2.2. Map of Injection Well, Area of Review, Surface Water Bodies, Artificial Penetrations, 

and Faults ........................................................................................................................ 11

2.3. Detailed Geology and Hydrogeologic Site Characterization .......................................... 13

2.3.1. Maps and Cross Sections of the Area of Review ................................................ 14

2.3.2. Faults and Fractures in the Area of Review ........................................................ 15

2.3.3. Depth, Areal Extent, and Thickness of the Injection and Confining Zones ........ 17

2.3.4. Petrology and Mineralogy of the Injection and Confining Zones ....................... 18

2.3.5. Porosity, Permeability, and Capillary Pressure of the Injection and Confining 

Zones .................................................................................................................. 20

2.3.5.1. Porosity ............................................................................................................ 20

2.3.5.2. Permeability ..................................................................................................... 22

2.3.5.3. Capillary Pressure ............................................................................................ 25

2.3.6. Geomechanical Characterization ......................................................................... 26

2.3.7. Seismic History ................................................................................................... 28

2.3.8. Hydrology and Hydrogeology of the Area of Review ........................................ 29

2.3.9. Baseline Geochemical Characterization .............................................................. 31

2.3.9.1. Fluid Chemistry ............................................................................................... 32

2.3.9.2. Bulk Solid Phase Chemical Analysis .............................................................. 34

2.3.9.3. Geochemical Calculations and Modeling ........................................................ 34

2.3.10. Geophysical Characterization .............................................................................. 35

2.3.10.1. Seismic Methods.............................................................................................. 38

2.3.10.2. Gravity Methods .............................................................................................. 40

2.3.10.3. Electrical/Electromagnetic Geophysical Methods ........................................... 40

2.3.10.4. Magnetic Geophysical Methods ...................................................................... 41

2.3.11. Surface Air and Soil Gas Monitoring .................................................................. 42

3. Data Synthesis for Demonstration of Site Suitability ........................................................... 45

3.1. Facies Analysis for the Project Site ................................................................................. 46

3.2. Structure of the Injection and Confining Zones .............................................................. 47

3.3. Compatibility of the Carbon Dioxide Stream with Subsurface and Well Materials ....... 49
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Site Characterization Guidance

3.3.1. Compatibility of the Carbon Dioxide Stream with Fluids and Minerals ............. 50

3.3.2. Compatibility with Well Materials ...................................................................... 53

3.4. Demonstration of Storage Capacity ................................................................................ 55

3.4.1. Methods for Estimating Carbon Dioxide Storage Capacity ................................ 55

3.4.2. Static Models ....................................................................................................... 56

3.4.3. Dynamic Models ................................................................................................. 56

3.4.4. Application of Methods for Estimating Carbon Dioxide Storage Capacity ........ 57

3.5. Demonstration of Confining Zone Integrity .................................................................... 59

3.5.1. Movement through the Confining Zone .............................................................. 59

3.5.2. Transmission of Carbon Dioxide through Faults ................................................ 60

3.5.3. Special Considerations for Characterizing Lower Confining Zones ................... 62

3.6. Considerations for Secondary Confinement .................................................................... 63

3.7. Reporting Process ............................................................................................................ 64

4. Activities Performed Prior to Operation of a Class VI Well ................................................ 66

4.1. Well Logging ................................................................................................................... 66

4.2. Core Analyses .................................................................................................................. 68

4.3. Characterization of Injection Formation Fluid Chemical and Physical Properties and 

Downhole Conditions ...................................................................................................... 69

4.4. Fracture Pressure of the Injection and Confining Zones ................................................. 70

4.5. Hydrogeologic Testing .................................................................................................... 71

4.5.1. Pressure Fall-Off Tests ........................................................................................ 72

4.5.2. Injectivity and Pump Tests .................................................................................. 73

5. References ............................................................................................................................. 75

Appendix: Available Technologies and Methods for Conducting Required Site Characterization 

Activities 
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List of Tables

Table 1-1: Site Characterization Activities in the Class VI Rule ................................................... 4

Table 2-1: Applicability of Geophysical Techniques to Geological Features of Interest ............. 37

Table 2-2: Stages in a Geologic Sequestration Project where Geophysical Techniques May 

Be Applicable.................................................................................................................... 38
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List of Figures 

Figure 1-1: Flow Chart Showing Relationships among Site Characterization, Modeling, and 

Monitoring for a GS Project ............................................................................................... 7
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Acronyms and Abbreviations

2D Two-dimensional 

3D Three-dimensional 

AAPG American Association of Petroleum Geologists

ANN Artificial neural networks

AoR Area of review

API American Petroleum Institute

BSE Backscattered electron

CERCLIS Comprehensive Environmental Response, Compensation, and Liability 

Information System

CERI Center for Earthquake Research and Information

CFR Code of Federal Regulations

CGS Centimeter gram second system

CO2 Carbon dioxide 

CR Complex resistivity 

CSAMT Controlled source audio-frequency magnetotellurics

CT Computerized tomography 

DADN Difference analysis with data normalization

DOE United States Department of Energy

EGR Enhanced gas recovery

EM Electromagnetic

EOR Enhanced oil recovery 

EPA United States Environmental Protection Agency 

ERT Electrical resistivity tomography (electroresistive tomography)

FBP Formation breakdown pressure 

FEMA Federal Emergency Management Agency

FMI Formation microresistivity image 

FPP Fracture pumping pressure 

GEM Global Earthquake Model 

GHG MRR Greenhouse Gas Mandatory Reporting Rule 

GIS Geographic information system

GPR Ground penetrating radar 

GS Geologic sequestration

ICIS Integrated Compliance Information System

ICP/AES Inductively coupled plasma/atomic emission spectrometry
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ICP/MS Inductively coupled plasma/mass spectrometry

IFT Interfacial tension

IGIP Initial gas in place

IP Induced polarization 

LOP Leak-off point 

LOT Leak-off test

LWD Logging while drilling

M Mobility ratio

Mt Megatonne 

NERSL National Energy Research Seismic Library

NETL National Energy Technology Laboratory 

NML Nuclear magnetism logging 

NMR Nuclear magnetic resonance

NOAA National Oceanic and Atmospheric Administration

NWIS National Water Information System

OGIP Original gas in place

OOIP Original oil in place

pAVAZ P-wave amplitude variation with offset and azimuth, also referred to as pAVOA 

Pe Capillary entry pressure

PGIP Producible gas in place 

PIA Petrographic image analysis

PISC Post-injection site care

SC Specific conductivity 

SCAL Special core analysis

SDWA Safe Drinking Water Act

SEI Secondary electron imaging

SEM Scanning electron microscope (or microscopy) 

SGR Shale gouge ratio

SP Self potential (when referring to geophysical techniques) 

SP Spontaneous potential (when referring to logging) 

TDS Total dissolved solids 

TOC Total organic carbon 

UIC Underground Injection Control 

USBM United States Bureau of Mines 

USDW Underground source of drinking water 

USGS United States Department of the Interior, United States Geological Survey
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VSP Vertical seismic profile

XLOT Extended leak-off test

XRD X-ray diffraction

XRF X-ray fluorescence
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Definitions 

Key to definition sources: 

1: 40 CFR 146.81(d). 

2: EPA’s UIC website (http://water.epa.gov/type/groundwater/uic/glossary.cfm). 

3: Class VI Rule Preamble.

4: 40 CFR 144.6(f) and 144.80(f). 

5: This definition was drafted for the purposes of this document. 

6: 40 CFR 144.3. 

Area of Review (AoR) means the region surrounding the geologic sequestration project where 

USDWs may be endangered by the injection activity. The AoR is delineated using computational 

modeling that accounts for the physical and chemical properties of all phases of the injected 

carbon dioxide stream and displaced fluids, and is based on available site characterization, 

monitoring, and operational data as set forth in 40 CFR 146.84.1 

Brine means water that has a large quantity of salt, especially sodium chloride, dissolved in it. 

Large quantities of brine are often produced along with oil and gas. Water having high total 

dissolved solids (TDS) content.2 

Buoyancy refers to the upward force on one phase (e.g., a fluid) produced by the surrounding 

fluid (e.g., a liquid or a gas) in which it is fully or partially immersed, caused by differences in 

pressure or density.3 

Capillary pressure refers to the difference of pressures between two phases existing in a system 

of interconnecting pores or capillaries. The difference in pressure is due to the combination of 

surface tension and curvature in the capillaries.5 

Carbon dioxide plume means the extent underground, in three dimensions, of an injected 

carbon dioxide stream.1 

Carbon dioxide stream means carbon dioxide that has been captured from an emission source 

(e.g., a power plant), plus incidental associated substances derived from the source materials and 

the capture process, and any substances added to the stream to enable or improve the injection 

process. This subpart [Subpart H of 40 CFR part 146] does not apply to any carbon dioxide 

stream that meets the definition of a hazardous waste under 40 CFR part 261.1 

Class VI wells means wells that are not experimental in nature that are used for GS of carbon 

dioxide beneath the lowermost formation containing a USDW; or, wells used for GS of carbon 

dioxide that have been granted a waiver of the injection depth requirements pursuant to 

requirements at 40 CFR 146.95; or, wells used for GS of carbon dioxide that have received an 

expansion to the areal extent of an existing Class II EOR/EGR aquifer exemption pursuant to 40 

CFR 146.4 and 144.7(d).4
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Computational model means a mathematical representation of the injection project and relevant 

features, including injection wells, site geology, and fluids present. For a GS project, site-specific 

geologic information is used as input to a computational code, creating a computational model 

that provides predictions of subsurface conditions, fluid flow, and carbon dioxide plume and 

pressure front movement at that site. The computational model comprises all model input and 

predictions (i.e., output).5 

Confining zone means a geologic formation, group of formations, or part of a formation 

stratigraphically overlying the injection zone(s) that acts as barrier to fluid movement. For Class 

VI wells operating under an injection depth waiver, confining zone means a geologic formation, 

group of formations, or part of a formation stratigraphically overlying and underlying the 

injection zone(s).1 

Corrective action means the use of Director-approved methods to ensure that wells within the 

AoR do not serve as conduits for the movement of fluids into USDWs.1

 

Cratonic means pertaining to the old, stable lithosphere in the interiors of continents.5 

Drilling mud means a heavy suspension used in drilling an “injection well,” introduced down 

the drill pipe and through the drill bit.6 

Dynamic models refers to a method or methods for estimating carbon dioxide storage capacity 

after initiation of carbon dioxide injection, including decline curve analysis, material balance, 

and reservoir simulation.5 

Effective permeability means the permeability of one fluid when more than one fluid phase is 

present.5 

Enhanced Oil or Gas Recovery (EOR/EGR) typically means, the process of injecting a fluid 

(e.g., water, brine, or carbon dioxide) into an oil or gas bearing formation to recover residual oil 

or natural gas. The injected fluid thins (decreases the viscosity) and/or displaces extractable oil 

and gas, which is then available for recovery. This is also used for secondary or tertiary

recovery.3 

Equation of state refers to an equation that expresses the equilibrium phase relationship 

between pressure, volume and temperature for a particular chemical species.5 

Fluid means any material or substance which flows or moves whether in a semisolid, liquid, 

sludge, gas or other form or state.6 

Formation or geological formation means a layer of rock that is made up of a certain type of 

rock or a combination of types.3 

Geochemical characterization means to study the chemistry of the formation fluids and solids 

(rock) and to identify potential chemical interactions among the injectate (carbon dioxide), 

formation fluids, and solids.5 
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Geologic sequestration (GS) means the long-term containment of a gaseous, liquid or 

supercritical carbon dioxide stream in subsurface geologic formations. This term does not apply 

to carbon dioxide capture or transport.1 

Geologic sequestration project means an injection well or wells used to emplace a carbon 

dioxide stream beneath the lowermost formation containing a USDW; or, wells used for GS of 

carbon dioxide that have been granted a waiver of the injection depth requirements pursuant to 

requirements at 40 CFR 146.95; or, wells used for GS of carbon dioxide that have received an 

expansion to the areal extent of an existing Class II EOR/EGR aquifer exemption pursuant to 40 

CFR 146.4 and 144.7(d). It includes the subsurface three-dimensional extent of the carbon 

dioxide plume, associated area of elevated pressure, and displaced fluids, as well as the surface 

area above that delineated region.1 

Geomechanical characterization means to study the rock mechanical characteristics associated 

with carbon dioxide containment such as fault and reservoir rock stability and confining zone 

integrity.5

 

Geophysical surveys refers to the use of geophysical techniques (e.g., seismic, electrical, 

gravity, or electromagnetic (EM) surveys or well logging methods such as gamma ray and 

spontaneous potential) to characterize subsurface rock formations.3 

Heterogeneity refers to the spatial variability in the geologic structure and/or physical properties 

of the site.5 

Hysteresis means the phenomenon where the response of a system depends not only on the 

present stimulus, but also on the previous history of the medium. For example, in a GS project, 

relative permeability, capillary pressure, and residual trapping will depend upon the saturation 

history of the formation (i.e., injection vs. post-injection phase).5 

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

sufficient areal extent, thickness, porosity, and permeability to receive carbon dioxide through a 

well or wells associated with a GS project.1 

Injectivity is the pressure differential over existing reservoir pressure required to inject a unit 

volume of fluid in a given unit of time. It is typically expressed as psi/bbl/day (psi per barrel per 

day) but can be expressed in any combination of pressure, volume, and time units. 5

 

In situ stresses refers to the three principal stresses (vertical stress, maximum horizontal stress, 

and minimum horizontal stress) commonly used to characterize the geomechanical model.5

Intracratonic means located in an area above old, stable lithosphere, usually in the interiors of 

continents far away from plate boundaries.5

Intrinsic permeability refers to a parameter that describes properties of the subsurface that 

impact the rate of fluid flow. Larger intrinsic permeability values correspond to greater fluid 

flow rates. Intrinsic permeability has units of area (distance squared).5 
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Irreducible water saturation refers to the smallest amount of remaining water in a core sample 

after forced displacement by another fluid.5

Lithology means the description of rocks, based on color, mineral composition, and grain size.3

Mineralogy, petrology, and solid-phase chemistry refers to the composition of the solids in an 

aquifer, including the minerals, rock types and their origins, and bulk chemical composition.5 

Mud log means data collected from drilling mud as it circulates. It produces a record of the 

different types of data collected when drilling a well, such as the rate of drilling, the rock types in 

the cuttings, and the presence of hydrocarbons.5

 

Parameter means a mathematical variable used in governing equations, equations of state, and 

constitutive relationships. Parameters describe properties of the fluids present, porous media, and 

fluid sources and sinks (e.g., injection well). Examples of model parameters include intrinsic 

permeability, fluid viscosity, and fluid injection rate.5 

Pore throat radius means the radius of the opening to a pore in a rock.5 

Porosity means the percentage of rock consisting of void space.5 

Post-injection site care means appropriate monitoring and other actions (including corrective 

action) needed following cessation of injection to ensure that USDWs are not endangered, as 

required under 40 CFR 146.93.1 

Pressure front means the zone of elevated pressure that is created by the injection of carbon 

dioxide into the subsurface. For [GS projects], the pressure front of a carbon dioxide plume 

refers to the zone where there is a pressure differential sufficient to cause the movement of 

injected fluids or formation fluids into a USDW.1 

Relative permeability refers to a factor, between 0 and 1, that is multiplied by the intrinsic 

permeability of a formation to compute the effective permeability for a fluid in a particular pore 

space. When immiscible fluids (e.g., carbon dioxide, water) are present within the pore space of 

a formation, the ability for flow of those fluids is reduced, due to the blocking effect of the 

presence of the other fluid. This reduction is represented by relative permeability.5

 

Reserve means the estimated volume available for carbon dioxide storage in the injection zone, 

considering technological, economic, and regulatory constraints and limitations. Reserve 

estimates can be considered a subset of resource estimates.5 

Resource means the estimated volume available for carbon dioxide storage in the injection 

zone.5

Site closure means the point/time, as determined by the UIC Program Director following the 

requirements under 40 CFR 146.93, at which the owner or operator of a GS site is released from 

post-injection site care responsibilities.1 
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Skin factor or skin effect refers to the restrictions to flow in the near-well bore region, typically 

associated with damage during drilling and well operations.5 

Static models refers to the methods for estimating carbon dioxide storage capacity prior to 

startup of injection and includes volumetric and compressibility methods.5

Storage capacity means the pore volume within the injection zone available for carbon dioxide 

storage.5 

Stratigraphy means the sequence of rock strata, or layers. This generally refers to layers of 

sedimentary or igneous rocks.5

 

Supercritical fluid means a fluid above its critical temperature (31.1oC for carbon dioxide) and 

critical pressure (73.8 bar for carbon dioxide).5 

Tensile strength refers to the maximum force an element can take in tension before it breaks.5 

Total dissolved solids (TDS) means the total dissolved (filterable) solids as determined by use 

of the method specified in 40 CFR part 136.6 

Transmissibility means a coefficient associated with Darcy’s law that characterizes flow 

through porous media. It is equal to the coefficient of permeability (hydraulic conductivity) 

multiplied by the thickness of the formation.5

Transmissive fault or fracture means a fault or fracture that has sufficient permeability and 

vertical extent to allow fluids to move between formations.1 

Underground Injection Control Program refers to the program EPA, or an approved state, is 

authorized to implement under the Safe Drinking Water Act (SDWA) that is responsible for 

regulating the underground injection of fluids by injection wells. This includes setting the federal 

minimum requirements for construction, operation, permitting, and closure of underground 

injection wells.5 

Underground Injection Control Program (UIC Program) Director refers to the chief 

administrative officer of any state or tribal agency or EPA Region that has been delegated to 

operate an approved UIC program.2

Underground Source of Drinking Water (USDW) means an aquifer or its portion which 

supplies any public water system; or which contains a sufficient quantity of ground water to 

supply a public water system; and currently supplies drinking water for human consumption; or 

contains fewer than 10,000 mg/l total dissolved solids; and which is not an exempted aquifer.6 

Well bore refers to the hole that remains throughout a geologic (rock) formation after a well is 

drilled.5 

Wireline refers to a wire or cable that is used to deploy tools and instruments downhole and that 

transmits data to the surface.

5 
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Workover refers to any maintenance activity performed on a well that involves ceasing injection 

and removing the wellhead.5
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Site Characterization Guidance

1. Introduction 

Site characterization is a long-standing requirement of the Underground Injection Control (UIC) 

Program to ensure safe deployment of injection operations and the protection of underground 

sources of drinking water (USDWs). The U.S. Environmental Protection Agency’s (EPA’s) 

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon 

Dioxide Geologic Sequestration (GS) Wells, found at 75 FR 77230, December 10, 2010, and 

codified in the U.S. Code of Federal Regulations [40 CFR 146.81 et seq.], are referred to as the 

Class VI Rule. The Class VI Rule requires owners or operators of wells used to inject carbon 

dioxide for GS to identify the presence of suitable geologic characteristics at a proposed site to 

ensure the protection of USDWs during and following injection activities. 

Site characterization for Class VI permitting focuses on demonstrating that a proposed project 

site has a suitable injection zone to receive the carbon dioxide and a confining zone that will 

prevent fluid movement out of the injection zone as described under 40 CFR 146.83. Owners or 

operators must gather the data necessary to demonstrate site suitability and submit this with a 

Class VI permit application to be evaluated by the UIC Program Director prior to receiving 

authorization to construct the well [40 CFR 146.82(a)], and must update and gather more 

detailed site-specific information and submit this prior to receiving authorization for injection 

[40 CFR 146.82(c)]. 

The site characterization process typically includes a general characterization of regional and site 

geology, followed by detailed characterization of the injection zone and confining zones. The 

more general characterization includes data on the regional geology and hydrogeology, 

supported by maps, cross sections, and other available data. The more detailed information 

focuses on the proposed project site and involves submission of data on stratigraphy, structural 

geology, hydrogeology, geomechanical properties, and geochemistry. The initial stage includes 

compiling pre-existing and/or new information, maps, cross sections, geochemical and 

petrophysical data, and geophysical or remote sensing information as described under 40 CFR 

146.82(a). Final site characterization data will be collected as the injection well is drilled, core 

samples are taken and analyzed, and logs and tests are performed, as described under 40 CFR 

146.82(c). 

In addition to being essential to USDW protection, thorough site characterization is a necessary 

element of selecting viable GS sites. EPA expects that selecting GS sites will be analogous to the 

process by which oil and gas recovery projects are sited—from a “big picture” regional 

evaluation of prospective resources that relies primarily on existing data, to more detailed 

evaluations of prospects that appear, based on preliminary data, to be promising sites. These 

detailed evaluations involve the use of the same logging, testing, and modeling techniques 

needed to perform site characterizations that can meet the requirements of the Class VI Rule 

(NETL, 2010). 
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Site Characterization Guidance

1.1. Overview of Class VI Rule Requirements 

The Class VI Rule, at 40 CFR 146.83, establishes minimum criteria for the siting of Class VI 

wells. Specifically, Class VI wells must be located in areas with a suitable geologic system, 

including: (1) the presence of an injection zone of sufficient areal extent, thickness, porosity, and 

permeability to receive the total anticipated volume of the carbon dioxide stream; and (2) the 

presence of confining zones that are free of transmissive faults or fractures and of sufficient areal 

extent and integrity to contain the carbon dioxide stream and displaced formation fluids and 

allow injection without initiating or propagating fractures [40 CFR 146.83(a)]. Additionally, at 

the UIC Program Director’s discretion, owners or operators may be required to identify and 

characterize additional confining zones to ensure USDW protection, impede vertical fluid 

movement, allow for pressure dissipation, and provide additional opportunities for monitoring, 

mitigation, and remediation [40 CFR 146.83(b)]. 

Owners or operators must demonstrate that a proposed site is suitable for GS by performing 

detailed site characterization and submitting extensive geologic data to the UIC Program 

Director. These data, described at 40 CFR 146.82(a), are necessary to demonstrate that the well 

will be sited in an area with a suitable geologic system that will ensure USDW protection and 

meet the requirements of 40 CFR 146.83. The Class VI Rule specifies distinct requirements for 

information to be submitted with the permit application and before well construction is approved 

at 40 CFR 146.82(a), and information to be submitted before operation of the well is authorized 

at 40 CFR 146.82(c). 

Site characterization is an iterative process. Site characterization data are submitted to the UIC 

Program Director to fulfill the requirements for a Class VI permit application [40 CFR 

146.82(a)] before well construction is approved. Pursuant to the requirements at 40 CFR 

146.82(c), the data must be updated and refined before operation of the well is authorized based 

on the results of the formation testing program required at 40 CFR 146.82(a)(8) and 146.87 that 

is executed during injection well drilling and completion. 

The types of site characterization information specified by the Class VI Rule that must be 

provided with a Class VI well permit application include: 

• Maps and cross sections of the area of review (AoR) [40 CFR 146.82(a)(3)(i) and 

146.82(a)(2)]; 

• The location, orientation, and properties of known or suspected faults and fractures that 

may transect the confining zone(s) in the AoR, along with a determination that they will 

not interfere with containment [40 CFR 146.82(a)(3)(ii)]; 

• Data on the depth, areal extent, thickness, mineralogy, porosity, permeability, and 

capillary pressure of the injection and confining zone(s) and on lithology and facies 

changes [40 CFR 146.82(a)(3)(iii)]; 

• Geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid 

pressures within the confining zone(s) [40 CFR 146.82(a)(3)(iv)]; 
UIC Program Class VI Well 3 

Site Characterization Guidance

• Information on the seismic history of the area, including the presence and depths of 

seismic sources, and a determination that the seismicity will not interfere with 

containment [40 CFR 146.82(a)(3)(v)]; 

• Geologic and topographic maps and cross sections illustrating regional geology, 

hydrogeology, and the geologic structure of the local area [40 CFR 146.82(a)(3)(vi)]; 

• Maps and stratigraphic cross sections indicating the general vertical and lateral limits of 

all USDWs, water wells, and springs within the AoR, their positions relative to the 

injection zone(s), and the direction of water movement (where known) [40 CFR 

146.82(a)(5)]; and

• Baseline geochemical data on subsurface formations, including all USDWs in the AoR 

[40 CFR 146.82(a)(6)]. 

The types of site characterization information specified by the Class VI Rule that must be 

provided for the UIC Program Director to review and approve the operation of a Class VI well 

include: 

• Any relevant updates to the information on the geologic structure and hydrogeologic 

properties of the proposed storage site and overlying formations, based on data obtained 

during logging and testing of the well [40 CFR 146.82(c)(2)]; 

• Information on the compatibility of the carbon dioxide stream with fluids in the injection 

zone(s) and minerals in both the injection and the confining zone(s) [40 CFR 

146.82(c)(3)]; 

• The results of formation testing [40 CFR 146.82(c)(4)]; and

• All available logging and testing program data on the well required by 40 CFR 146.87 

[40 CFR 146.82(c)(7)]. 

Owners or operators are expected to take full advantage of existing site characterization data to 

fulfill the requirements at 40 CFR 146.82. However, a stratigraphic well may need to be drilled 

in some cases (e.g., if adequate data are not already available). If owners or operators need to 

drill a stratigraphic well, they may consider ultimately using it for injection or monitoring. 

Owners or operators should keep in mind that if the AoR delineation or any of the project plans 

require significant changes based on the final site characterization data, the Class VI permit 

would have to be modified to incorporate these changes before injection can be authorized [40 

CFR 144.39]. Depending on the extent of the modifications, the UIC Program Director may need 

to re-initiate the public notice process. To avoid any potential delays associated with the permit 

modification process, EPA encourages owners or operators to collect as much site-specific data 

as possible before submitting the initial Class VI permit application. Additional information on 

the Class VI permitting process and how UIC Program Directors may evaluate the site 

characterization submittals is presented in the UIC Program Class VI Implementation Manual 

for State Directors. 
UIC Program Class VI Well 4 

Site Characterization Guidance

1.2. Overview and Purpose of this Guidance 

The purpose of this guidance is to describe the data needs, process, and procedures for 

conducting a geologic assessment that meets the requirements of the Class VI Rule at 40 CFR 

146.82 and 146.83. This document provides guidance on the types of information to collect and 

submit with a Class VI injection well permit application as well as where and how such 

information might be obtained. Illustrative examples of some of the required information are in 

the Appendix to this document. 

This guidance document is written to assist Class VI injection well owners or operators, parties 

that may conduct the geologic siting activities on behalf of owners or operators, and the UIC 

Program permitting authorities who will evaluate Class VI permit applications. This guidance 

can also help owners or operators who hire contractors to perform some or all of the required site 

characterization activities understand, as signers of the permit application, all of the information 

that is submitted. Likewise, owners or operators are encouraged to share this guidance document 

with contractors so that they understand the permitting authority’s expectations for the data 

submitted.

It is important to note that not all sites will be suitable for GS. This guidance provides 

considerations for determining when issuing a Class VI permit is or might not be appropriate, or 

when more data may be needed to make a determination regarding the suitability of a site. EPA 

encourages owners or operators to review the considerations in this guidance and discuss the data 

being collected with the UIC Program Director throughout the site characterization process. 

Table 1-1 presents the activities owners or operators undertake as part of the site 

evaluation/characterization process (based on the requirements of 40 CFR 146.82), the 

corresponding Class VI Rule requirement, and the section of this guidance that describes how 

owners or operators can collect this information and submit it to demonstrate to the UIC Program 

Director that the site is appropriate for GS. 

Table 1-1: Site Characterization Activities in the Class VI Rule

Activity Class VI Rule Requirement Guidance 

Section

Regional evaluation

Characterize regional 

geology and 

hydrogeology and 

local structural geology

Maps and cross sections of the AoR [40 CFR 146.82(a)(3)(i)].

Geologic and topographic maps and cross sections illustrating 

regional geology, hydrogeology, and the geologic structure of the 

local area [40 CFR 146.82(a)(3)(vi)].

2.3.1

2.1

Gather information on 

all wells, etc.

Map showing the injection well, the applicable AoR, and faults, if 

known or suspected [40 CFR 146.82(a)(2)].

2.2

Study seismic history Information on the seismic history of the area, including the 

presence and depths of seismic sources [40 CFR 146.82(a)(3)(v)].

2.3.7
UIC Program Class VI Well 5 

Site Characterization Guidance

Activity Class VI Rule Requirement Guidance 

Section

Detailed analysis

Study faults and 

fractures in the AoR 

The location, orientation, and properties of known or suspected 

faults and fractures that may transect the confining zone(s) in the 

AoR and a determination that they would not interfere with 

containment [40 CFR 146.82(a)(3)(ii)].

2.3.2

Collect data on the 

depth, areal extent, 

and thickness of the 

injection and confining 

zones, and facies 

changes 

Data on the depth, areal extent, thickness, mineralogy, porosity, 

permeability, and capillary pressure of the injection and confining 

zone(s); including geology/facies changes based on field data 

which may include geologic cores, outcrop data, seismic surveys, 

well logs, and names and lithologic descriptions [40 CFR 

146.82(a)(3)(iii)].

2.3.3, 3.1

Characterize 

mineralogy of the 

injection and confining 

zones

Data on the depth, areal extent, thickness, mineralogy, porosity, 

permeability, and capillary pressure of the injection and confining 

zone(s); including geology/facies changes based on field data 

which may include geologic cores, outcrop data, seismic surveys, 

well logs, and names and lithologic descriptions [40 CFR 

146.82(a)(3)(iii)].

2.3.4

Characterize porosity, 

permeability, and 

capillary pressure of 

the injection and 

confining zones

Data on the depth, areal extent, thickness, mineralogy, porosity, 

permeability, and capillary pressure of the injection and confining 

zone(s); including geology/facies changes based on field data 

which may include geologic cores, outcrop data, seismic surveys, 

well logs, and names and lithologic descriptions [40 CFR 

146.82(a)(3)(iii)].

2.3.5

Perform 

geomechanical 

characterization 

Geomechanical information on fractures, stress, ductility, rock 

strength, and in situ fluid pressures within the confining zone(s) [40 

CFR 146.82(a)(3)(iv)].

2.3.6

Characterize 

hydrology and 

hydrogeology of the 

AoR 

Maps and stratigraphic cross sections indicating all USDWs, water 

wells and springs within the AoR, their positions relative to the 

injection zone(s), and the direction of water movement, where 

known [40 CFR 146.82(a)(5)].

2.3.8

Characterize 

geochemistry 

Baseline geochemical data on subsurface formations 

[146.82(a)(6)].

2.3.9

Perform geophysical 

characterization 

 

Data on the depth, areal extent, thickness, mineralogy, porosity, 

permeability, and capillary pressure of the injection and confining 

zone(s); including geology/facies changes based on field data 

which may include geologic cores, outcrop data, seismic surveys, 

well logs, and names and lithologic descriptions [40 CFR 

146.82(a)(3)(iii)].

2.3.10

During/after well drilling 

Update site 

characterization data 

based on pre-injection 

logs and tests

Any relevant updates, based on data obtained during logging and 

testing of the well and the formation, to the information on the 

geologic structure and hydrogeologic properties of the proposed 

storage site and overlying formations [40 CFR 146.82(c)(2)].

4

Perform formation 

testing

The results of the formation testing program [40 CFR 146.82(c)(4)]. 4.1
UIC Program Class VI Well 6 

Site Characterization Guidance

Activity Class VI Rule Requirement Guidance 

Section

Analyze cores Take whole cores or sidewall cores of the injection zone and 

confining system and formation fluid samples from the injection 

zone(s), and submit a detailed report prepared by a log analyst that 

includes: well log analyses (including well logs), core analyses, and 

formation fluid sample information [per 40 CFR 146.87(b), required 

at 146.82(c)(7)].

4.2

Characterize injection 

zone fluids

Record the fluid temperature, pH, specific conductivity, reservoir 

pressure, and static fluid level of the injection zone(s) [per 40 CFR 

146.87(c), required at 146.82(c)(7)].

4.3

Calculate fracture 

pressures

Determine or calculate fracture pressure and other physical and 

chemical characteristics of the injection and confining zone(s) and 

physical and chemical characteristics of the formation fluids in the 

injection zone(s) [per 40 CFR 146.87(d), required at 146.82(c)(7)].

4.4

Characterize injection 

zone hydrogeologic 

properties 

Prior to operation, conduct a pressure fall-off test and a pump test 

or injectivity tests to verify hydrogeologic characteristics of the 

injection zone(s) [per 40 CFR 146.87(e), required at 146.82(c)(7)].

4.5

Analyze carbon 

dioxide stream 

compatibility

Information on the compatibility of the carbon dioxide stream with 

fluids in the injection zone(s) and minerals in both the injection and 

the confining zone(s), based on the results of the formation testing 

program, and with the materials used to construct the well [40 CFR 

146.82(c)(3)].

3.3

This guidance assumes that readers are familiar with many of the available techniques used in 

geologic site characterizations and their use. Thus, descriptions of these techniques in this 

document are minimal. The Appendix provides background information on a number of these 

technical topics, along with an extensive list of references. 

1.3. Relationship to Other Class VI Activities 

This guidance document focuses on collecting the geological, physical, and chemical data 

necessary to support Class VI permit determinations during the pre-injection phase of a GS 

project. Data obtained during the site characterization process will also support other permit 

application and site operation activities. For example: 

• Data on rock and fluid properties can inform the design and calibration of AoR 

delineation models;

• Information on injection zone and/or confining zone mineralogy, fluids, and properties 

can inform proper well construction and pre-injection testing;

• Data on the confining zone fracture pressure and storage capacity can inform setting 

protective operating limits; and

• Water quality and geophysical profiling data can serve as a baseline for the testing and 

monitoring that will take place during the operational phase of the project. 

These cross-linkages between guidance documents are noted in the text where appropriate. 
UIC Program Class VI Well 7 

Site Characterization Guidance

This guidance document is part of a series of technical guidance documents developed to provide 

information and possible approaches for addressing various aspects of permitting and operating a 

Class VI injection well. A number of UIC Class VI Program companion guidance documents 

focus on other steps in the process. These documents include: 

• The UIC Program Class VI Well Area of Review Evaluation and Corrective Action 

Guidance explains how site data will inform computational modeling of the AoR; 

• The UIC Program Class VI Well Construction Guidance describes how to construct 

injection wells using materials that are compatible with the carbon dioxide and 

subsurface conditions; 

• The UIC Program Class VI Well Testing and Monitoring Guidance describes how 

baseline geochemical and other site data will inform appropriate site monitoring; 

• The UIC Program Class VI Well Project Plan Development Guidance explains how site 

data can inform development of the required project plans; and 

• The UIC Program Class VI Well Injection Depth Waivers Guidance provides special 

considerations and additional requirements for evaluating sites where injection into nonUSDWs above or between USDWs is planned. 

These guidance documents are intended to complement each other and to assist owners or 

operators in preparing permit applications that satisfy the requirements of the Class VI Rule and 

are tailored to the characteristics of individual sites. The material that these guidance documents 

encompass reflects the linkages among the different steps and stages of a GS operation as shown 

in Figure 1-1. 

Figure 1-1: Flow Chart Showing Relationships among Site Characterization, 

Modeling, and Monitoring for a GS Project
UIC Program Class VI Well 8 

Site Characterization Guidance

1.4. Organization of this Guidance 

Following the introduction (Section 1), this guidance document is organized as follows: 

• Section 2, Activities Performed Prior to the Construction of a Class VI Well, presents the 

activities that owners or operators will perform before an injection well may be drilled 

(i.e., to apply for a Class VI permit). Information generated from these activities will 

meet the requirements of 40 CFR 146.82(a)(2), (3), (5), and (6).

• Section 3, Data Synthesis for Demonstration of Site Suitability, provides considerations 

and recommendations for how owners or operators can synthesize the information 

collected to demonstrate that the site meets the requirements of 40 CFR 146.83, is 

acceptable to the UIC Program Director, and is suitable for a Class VI permit. This 

section describes some of the “big picture” questions about a proposed site that will need 

to be answered through the site characterization process. Owners or operators should 

consider these as they plan to collect the site data that will inform their permit 

application. 

• Section 4, Activities Performed Prior to the Operation of a Class VI Well, presents 

activities that owners or operators will perform before injection may be authorized. The 

information obtained from these activities will meet the site characterization-related 

requirements of 40 CFR 146.82(c)(2)–(4) and (7), and 146.87(b)–(e).
UIC Program Class VI Well 9 

Site Characterization Guidance

2. Activities Performed Prior to Construction of a Class VI Well 

The Class VI Rule, at 40 CFR 146.82(a), requires Class VI permit applicants to submit to the 

UIC Program Director extensive information on the characterization of surface and subsurface 

features of the proposed storage site, in particular on the injection zone(s), confining zone(s), and 

USDWs. Applicants will submit geologic and hydrogeologic data on the injection and confining 

zones, including their lithologic properties; the seismic history of the site; the structural geology 

of the site, including the presence of faults and fractures; and other information. Required 

submissions also include geochemical data on subsurface formations, including USDWs, and

geomechanical data on the confining zone(s). 

This section provides information to assist owners or operators in conducting the site 

characterization activities necessary to gather information, prepare, and submit a Class VI permit 

application. Each subsection below describes the activities owners or operators will need to 

perform to submit the elements of a Class VI permit application required at 40 CFR 146.82(a). 

For each required piece of information, this guidance describes potential sources of information 

and provides recommendations for how this information can be submitted to the UIC Program 

Director to support a determination that the site is suitable for GS. Note that, for completeness in 

describing a thorough geologic characterization, some of the information described in this 

section may only be available before construction if the site has been previously characterized

for another purpose, e.g., for hydrocarbon exploration. Where this is not the case, such 

information will need to be finalized after the well is constructed or based on information 

gathered via a stratigraphic test well.

Where appropriate, the subsections below also provide recommendations and special 

considerations for obtaining and interpreting data and note particular aspects of the site 

characterization process that might warrant discussions with the UIC Program Director. 

2.1. Regional Geology, Hydrogeology, and Local Structural Geology 

Owners or operators must submit geologic and topographic maps and cross sections illustrating 

the regional geology and hydrogeology and the geologic structure of the local area [40 CFR 

146.82(a)(3)(vi)]. This characterization will describe the area surrounding the proposed project 

including the subsurface formations that are targeted for injection and identified as the confining 

unit(s). This information may help in eliminating unsuitable project sites or identify the need to

characterize additional confining zone(s). If data obtained during site characterization suggest 

that a secondary confining zone is needed to protect USDWs, the owner or operator is 

encouraged to communicate with the UIC Program Director about the need to characterize 

additional zones [40 CFR 146.83(b)]. See Section 3.6 for considerations related to secondary 

confinement. 

Providing maps and cross sections of the region and local area will enable the UIC Program 

Director to place the project site in a regional geologic context, including the types of large-scale 

structural features that may act to confine a carbon dioxide plume. This information will also 

illustrate the relationship between the injection formation and regional and local USDWs. When 
UIC Program Class VI Well 10 

Site Characterization Guidance

considered along with detailed site-specific geologic information (see Section 2.3), this 

information will help in formulating the geologic conceptual model needed for modeling of the 

AoR. 

Data Collection and Analysis 

The geologic and topographic maps and cross sections to be submitted can be obtained through a 

number of sources such as the U.S. Geological Survey (USGS), state geological surveys, and 

other state and published literature and reports on general geology and water, mineral, and/or 

energy resources. For projects proposed in reservoirs undergoing enhanced oil recovery (EOR) 

or where significant exploration has taken place, owners or operators may have access to 

regional background information previously compiled. 

Information to Submit 

Owners or operators should demonstrate that an adequate screening-level analysis has taken 

place to determine if the project site is suitable. Maps, cross sections, and stratigraphic columns 

of the region and an accompanying narrative will constitute a key part of that demonstration. 

This information can provide the context for some of the specific information submitted to fulfill 

other requirements, e.g., descriptions of faults or geologic structure. It will also help in 

identifying the preliminary boundaries of the computational model used for delineating the AoR. 

Features to describe in the narrative and in geologic and topographic maps and cross sections 

include: 

• The names, lithologies, and depths of the injection formation(s) and confining zone(s); 

• Depths, extent, and ground water flow patterns of regional USDWs; 

• A brief synopsis of the geologic history of the project site; 

• Regional faults, fault types, trends, and whether they transect the injection formation(s) 

and/or confining zone(s); and 

• Structural geology of the local area: 

o Presence and trends of folds, and 

o Whether the proposed storage site will be bounded by faults or other structural 

features.

To support the UIC Program Director’s evaluation of the submitted information, EPA 

recommends that, with the accompanying narrative, the owner or operator describe the regional 

setting and how the proposed project site fits into this regional setting. The owner or operator 

should ensure that the information submitted is complete, adequately describes the proposed 

project site and surrounding region, and is consistent with other available information about the 

region. 
UIC Program Class VI Well 11 

Site Characterization Guidance

2.2. Map of Injection Well, Area of Review, Surface Water Bodies, Artificial 

Penetrations, and Faults 

The Class VI Rule, at 40 CFR 146.82(a)(2), requires applicants for a Class VI permit to create a 

map to report the number or name and location of all wells in addition to a number of other 

surface features, water bodies, faults, and infrastructure. At 40 CFR 146.82(a)(4), the Class VI 

Rule also requires the tabulation of additional descriptive information regarding wells within the 

AoR that penetrate the injection or confining zone(s). Data compiled on wells within the AoR 

will help identify the need for corrective action. Furthermore, these data will help identify other 

activities (e.g., injection or production operations) that should be accounted for during AoR 

delineation and when developing the Testing and Monitoring Plan [40 CFR 146.90] and the 

Emergency and Remedial Response Plan [40 CFR 146.94]. 

At this stage of the site characterization process (particularly if the AoR delineation model has 

not been developed), estimates of the AoR may be preliminary, depending on the amount of preexisting quality data, and refinements to the estimated AoR will be performed prior to operation 

once the formation testing program has been executed. Maps submitted at this initial stage 

should show at least the approximate AoR and the general direction of plume and pressure front 

migration. A detailed discussion of AoR delineation is provided in the UIC Program Class VI 

Well Area of Review Evaluation and Corrective Action Guidance. 

The Class VI Rule, at 40 CFR 146.82(a)(2), requires the map to show: 

• Surface bodies of water and springs. This includes seasonal bodies of water such as 

vernal pools, fens, carrs, and playas; 

• Mines (both surface and subsurface) and quarries. For subsurface mines, the UIC 

Program Director may request additional information such as the extent of subsurface 

mining and the maximum depth at which mining has occurred or, in the case of an active 

mine, is predicted to occur; 

• Surface features, including structures intended for human occupancy. These include, 

but are not limited to homes, schools, hospitals, prisons, and other buildings. Other 

pertinent surface features include transportation infrastructure such as roads, highways, 

airports, and railways; 

• Political boundaries such as state, tribal, and territorial boundaries. This information 

is needed to ensure that permitting follows all applicable laws and regulations within 

these jurisdictions and will inform notification of other UIC Program Directors, per 40 

CFR 146.82(b); 

• The surface trace of all known and suspected faults. The faults can be presented using 

standard geologic symbols indicating the relative motion of the fault blocks. Suspected 

faults must also be presented (suspected faults should be differentiated from known faults 

on the map). At the direction of the UIC Program Director or at their own discretion, the 

owner or operator may indicate the extent of complex fault zones through shading or 

some other means; 

• The number or name, and location of all injection wells, producing wells, 

abandoned wells, plugged wells, dry holes, or deep stratigraphic holes. This 
UIC Program Class VI Well 12 

Site Characterization Guidance

information will help the UIC Program Director evaluate potential risks from artificial 

penetrations, especially any that penetrate the confining zone, to determine if risk is 

sufficient to render a site unsuitable, or to identify wells that are currently in use but 

might need to be plugged later; and

• State- or EPA-approved subsurface cleanup sites. Information should include any sites 

with the potential to impact USDWs.

The Class VI Rule, at 40 CFR 146.82(a)(4), requires tabulation of all wells within the AoR that

penetrate the injection or confining zone(s). Such information must include: 

• A description of each well’s type, construction, date drilled, location, and depth; 

• A record of plugging and/or completion; and

• Any additional information the UIC Program Director may require. 

Data Collection and Analysis 

Cartographic information for map features is available from a variety of sources: 

• State geographic information system (GIS) clearinghouses. Most states offer online 

clearinghouses for state GIS data. This may include layers for boundaries, roads, 

buildings, and other information; 

• National agencies such as the USGS, or local cartographic or planning offices. The 

USGS can also provide geologic maps containing the surface traces of faults; and

• Tax assessors, who may be able to provide boundary, building, and other map data. 

For state- or EPA-approved subsurface cleanup sites, owners or operators may indicate the 

nature of the contamination at the site and the nature and progress of remediation activities at the 

site. In addition to the sources listed above, information on cleanup sites can be obtained from: 

• National databases compiled by the EPA such as the Comprehensive Environmental 

Response, Compensation, and Liability Information System (CERCLIS) as part of the 

Comprehensive Environmental Response, Compensation, and Liability Act of 1980 

(Superfund) program; 

• Various state departments (health, environment, natural resources, etc.) may also 

maintain their own databases of subsurface cleanup sites; 

• Local universities and academic institutions; and

• Citizen watchdog groups. 

The locations of wells in the proposed AoR and descriptive information on wells that intersect 

the injection or confining zone(s) can be obtained from: 

• Federal agencies, such as EPA. The National UIC Data System and the Integrated 

Compliance Information System (ICIS) database may both provide well information; 

• State agencies, such as state oil and gas commissions. These entities often maintain 

records of the location and construction parameters for all wells within the state; 
UIC Program Class VI Well 13 

Site Characterization Guidance

• Geological surveys (both state and national). Maps may be available for either wells or 

magnetic anomalies, which may be used to infer the locations of wells; 

• State GIS clearinghouses or city planning offices. These agencies may also provide layers 

or tables with well data; 

• Water and other utilities. The UIC Program Director may request, and/or the owner or 

operator may provide, the yield of the water wells, the number of people supplied by the 

water wells, and the ownership status (public or private) of water wells; and

• Academic literature. This is especially applicable for stratigraphic boreholes.

Only existing information in the public record is required to be used when populating the map 

required at 40 CFR 146.82(a)(2). However, additional data requested at 40 CFR 146.82(a)(4) on 

well parameters for wells within the AoR may need to be generated by the owner or operator if it 

is not available or reliable. In cases where available records do not provide the necessary 

information required at 40 CFR 146.82(a)(4), or indicate that a well was plugged improperly or 

with materials inappropriate for contact with carbon dioxide, then site investigations are required 

to be performed to establish the condition of the well, as discussed at 40 CFR 146.84(c)(3). 

Information to Submit

The owner or operator must submit a map that identifies all of the required information described 

above [40 CFR 146.82(a)(2)]. When data are not sufficiently complete to locate wells with 

certainty, and if appropriate or requested by the UIC Program Director, the owner or operator 

may mark regions of the map that are known or suspected of being well fields. For these areas, a 

description of typical well construction and operation (e.g., injection, production) may be 

included with the description of known wells within the AoR. This approach may be needed in 

areas with an extensive history of hydrocarbon production or areas suspected to have a number 

of private water wells. 

Additional information that may be included or requested by the UIC Program Director includes 

gas storage fields, other injection operations, local, state, and national park or monument 

boundaries, locations of archeological or cultural heritage sites, military installations, habitat for 

threatened or endangered species, surface water impoundments, and floodplain or spillway 

boundaries. The applicant is encouraged to include on the map any additional information they 

deem appropriate.

The UIC Program Director may request additional information if full coverage of the AoR is not 

provided. The owner or operator should also provide sufficient information to support the UIC 

Program Director’s review of existing features that may affect water quality in USDWs and that 

may affect baseline environmental conditions in the AoR. 

2.3. Detailed Geology and Hydrogeologic Site Characterization 

This section provides guidance on characterizing the specific geologic, hydrogeologic, 

geochemical, geophysical, and geomechanical properties of the proposed site. The site 

characterization activities described in the subsections below outline the information and data 
UIC Program Class VI Well 14 

Site Characterization Guidance

that must be considered by the UIC Program Director in authorizing a Class VI well permit as 

identified in 40 CFR 146.82(a)(3)–(6). 

2.3.1. Maps and Cross Sections of the Area of Review

Maps and cross sections of the AoR are required by the Class VI Rule at 40 CFR 146.82(a)(3)(i). 

The maps will likely include both topographic and geologic maps. Geologic maps in particular, 

and accompanying cross sections and stratigraphic columns, summarize key information on 

lithology, sequence of geologic units (including the proposed injection formations, confining 

units, and USDWs), approximate formation thicknesses, lateral extent of units, and correlation of 

units in the vicinity of the proposed project site and across the region. This information will help 

the UIC Program Director understand the spatial relationship between the proposed injection 

formation and other aspects of the site geology, including USDWs. The information will also 

help inform the geologic conceptual model on which the modeling for the AoR delineation is 

built. This information can also help identify zones for geochemical monitoring. 

The narrative accompanying the maps and cross sections of the AoR should be similar in scope 

to the evaluation of regional geology, but provide more detail on the AoR. Among other features, 

the owner or operator should highlight the lateral extent of the proposed injection formation and 

show that it is continuous throughout the proposed site [40 CFR 146.82(a)(3)(iii) and 

146.83(a)(1)]. The required evaluation of the areal extent of the confining zones is equally 

critical [40 CFR 146.82(a)(3)(iii) and 146.83(a)(2)]. If there are additional confining units farther 

up in the stratigraphic column, this strengthens the case for suitability of a proposed site. Areas 

where formations pinch out should be identified. An estimate of the approximate dimensions of 

the injection formation in the AoR also allows the owner or operator to estimate storage capacity. 

Data Collection and Analysis 

If a project site has been well characterized for hydrocarbon exploration and/or production, 

geologic maps and cross sections and topographic maps of the area may be available. 

Topographic and geologic maps may be obtained from the USGS, state geologic surveys, or 

through a commercial provider. Geologic maps and cross sections may also be produced by the 

owner or operator based on information from cores, well logs, field mapping, or seismic surveys. 

Maps and cross sections should be of an appropriate scale to illustrate features at the project site 

that would affect the suitability of the site for GS. 

Geologic maps, cross sections, and stratigraphic columns may be improved with additional data. 

As site characterization progresses, it is recommended that the owner or operator be alert to 

potential alternative interpretations of the cross sections and other similar map information. 

Owners or operators should discuss any assumptions or uncertainties in the features illustrated in 

maps and cross sections. If an injection depth waiver is sought, the owner or operator should 

make sure that the cross sections include all relevant layers down to at least the first USDW 

below the lower confining zone. 
UIC Program Class VI Well 15 

Site Characterization Guidance

Information to Submit 

EPA recommends that owners or operators include a narrative with the maps and cross sections 

that describes, at a minimum: 

• The formation names, lithologies, and depths of the injection formation(s), confining 

zone(s), and USDWs within the proposed AoR; 

• A general description of stratigraphy, including the vertical distance and formations 

separating the injection formation from USDWs; and

• Structural geology of the project site, including whether the proposed storage site will be 

bounded or influenced by a structural trap (e.g., faults or a dome).

Identification and analysis of faults and their potential to affect containment is required at 40 

CFR 146.82(a)(3)(ii) and is discussed in Section 2.3.2. Information on facies changes is required 

at 40 CFR 146.82(a)(3)(iii) and is discussed in Section 3.1. 

2.3.2. Faults and Fractures in the Area of Review

The Class VI Rule, at 40 CFR 146.82(a)(3)(ii), requires owners or operators to submit 

information on the location, orientation, and properties of known or suspected faults and 

fractures that may transect the confining zone(s) in the AoR and a determination that they would 

not interfere with containment. This information is needed to demonstrate to the UIC Program 

Director that the site has a confining zone(s) free of transmissive faults or fractures and that will 

allow injection at proposed maximum pressures and volumes without initiating or propagating 

fractures in the confining zone(s), as required at 40 CFR 146.83(a)(2). Evaluation of fault 

stability and fault or fracture sealing capacity is needed to demonstrate that faults will not 

interfere with containment of the carbon dioxide. If an injection depth waiver is sought, the 

owner or operator must also demonstrate that the lower confining unit(s) is/are free of 

transmissive faults and fractures [40 CFR 146.95(a)(2)]. 

EPA recommends that owners or operators obtain information on faults in the injection 

formation as well. This information should also include whether a fault zone consists of one 

major plane or a series of faults that may collectively provide a conduit for fluid movement 

through the confining zone, especially if the faults intersect lenses of high permeability material. 

Faults crossing the confining zone will need to be evaluated for their stability (see below) and 

sealing capacity (see Section 3.5 and the Appendix). 

Data Collection and Analysis 

Materials available from the USGS include geologic and topographic maps (e.g., the National 

Geologic Map Database), aerial photographs, and reports. The USGS’s Earthquake Hazards 

Program provides maps of faults for many regions in the United States. The Earthquake Hazards 

Program database (available at http://geohazards.cr.usgs.gov/cfusion/qfault/index.cfm) provides 

detailed information on faults. Maps and other data may also be available from state geologic 

surveys. Such maps (i.e., from the USGS and state geological surveys) are generally at the 

quadrangle scale, but maps can also be found at the county and state scale. 
UIC Program Class VI Well 16 

Site Characterization Guidance

Geophysical survey data, including seismic, electrical, magnetic, and gravity surveys, can 

complement information from maps and other sources and can be used to delineate faults and 

fractures and to characterize their geometry. The project area and the size and location of the 

fault will determine whether two dimensional (2D) data will provide sufficient information or 

whether the higher resolution of three dimensional (3D) data is needed. See Section 2.3.10 and 

the Appendix for additional information on geophysical surveys. 

Fault Stability and Fault or Fracture Sealing Properties 

Assessment of fault stability requires knowledge of fault geometry, which can be obtained from 

the structural interpretation of seismic data, as well as in situ stresses (see Section 2.3.6). Several 

options are available to support a determination that faults will not interfere with containment 

through reactivation, including assessments of failure plots, 3D fault slip tendency, and critical 

pore fluid pressure increase (see the Appendix for additional details). EPA recommends that 

owners or operators use one of the above methods, based on information on downhole stresses 

and fault geometry, to determine fault stability and the maximum sustainable pressure that could 

be associated with injection. This information can be used to set safe injection pressure limits. 

Faults and fractures can be assessed for the likelihood that they are sealing using one of several 

approaches described in Section 3.5.2. Faults may be assessed for the units they juxtapose, the 

presence of catalysis, the shale gouge ratio, or pressure compartmentalization. Both faults and 

fractures may be assessed for whether mineralization has rendered them non-transmissive. The 

choice of method will depend upon the availability of data and samples. 

Information to Submit 

In describing faults and fractures, EPA recommends that owners or operators submit the 

following information: 

 

• Location and characteristics of the fault or fracture (e.g., geometry, depth, fault 

displacement, units juxtaposed by fault); 

• Formations intersected or transected by the fault or fracture;

• Methods and results of fault stability analyses and comparison to preliminary anticipated 

(modeled) pressures during the injection phase of the project; and

• Information on faults and fractures in the lower confining zone (in cases where an 

injection depth waiver is sought). 

To demonstrate that a fault is not transmissive, the owner or operator may submit:

• A description of the approach used to infer whether a fault or fracture is transmissive; 

• A summary table of data used to formulate the estimate;

• Supporting data and information (e.g., analyses of core samples, results of geophysical 

surveys, pore pressure data, maps, and cross sections) and any relevant calculations (e.g., 

calculation of shale gouge ratio);
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Site Characterization Guidance

• A narrative that describes and integrates the relevant information, including a discussion 

of any spatial heterogeneity in sealing properties and whether a fault or fracture is likely 

to be transmissive in the project area; and

• A discussion of uncertainties in the data. 

See Section 3.5.2 and the Appendix for examples of approaches that may be employed for this 

demonstration. 

To support the UIC Program Director’s evaluation of the data, the owner or operator should 

make sure that the data are complete and adequate for understanding the geometry of any major 

faults and the pressures that could lead to activation. All supporting data should be provided 

and/or referenced in the appropriate section of the permit application. 

2.3.3. Depth, Areal Extent, and Thickness of the Injection and Confining Zones 

The Class VI Rule requires the owner or operator to provide information to the UIC Program 

Director on the depth, areal extent, and thickness of the injection formation and confining 

zone(s) [40 CFR 146.82(a)(3)(iii)]. These features affect the ability of the injection formation to 

receive and store the injectate, as well as the ability of the confining zone(s) to contain the 

carbon dioxide and pressure front. In addition, the depth of the injection zone will govern the 

state (e.g., supercritical) of the injected carbon dioxide. 

Information on the lithologies and thicknesses of both the injection and confining zones will 

support the estimation of storage capacity and development of a site-specific geologic conceptual 

model and the computational modeling required for AoR determinations at 40 CFR 146.84. (See 

the UIC Program Class VI Well Area of Review Evaluation and Corrective Action Guidance for 

more information on multiphase fluid modeling for AoR determinations). It will also support an 

analysis of facies changes, as required at 40 CFR 146.82(a)(3); see Section 3.1 for information 

on conducting facies analyses.

Data Collection and Analysis 

Seismic techniques and other geophysical methods can provide valuable stratigraphic 

information on the injection and confining zones. Ideally, demonstration of the extent of these 

formations will be documented by adequate boreholes and grids of 2D or 3D seismic images in 

addition to maps and cross sections (Chadwick et al., 2008). More information on the details of 

geophysical techniques and a brief description of seismic stratigraphy can be found in Section 

2.3.10 and in the Appendix. Seismic techniques are also discussed in the UIC Program Class VI 

Well Testing and Monitoring Guidance. If the owner or operator is applying for an injection 

depth waiver, information on depth, extent, and thickness of the lower confining zone(s) must be 

supplied as well, as required at 40 CFR 146.95 (see the UIC Program Class VI Well Injection 

Depth Waivers Guidance for further discussion). 
UIC Program Class VI Well 18 

Site Characterization Guidance

Information to Submit

EPA recommends that owners or operators discuss the depth, areal extent, and thickness of the 

injection formation and confining zone(s) in a narrative discussion that accompanies the geologic 

maps and cross sections required at 40 CFR 146.82(a)(3)(i); see Section 2.3.1. The narrative 

should include a discussion of data quality and uncertainties in the information. If an injection 

depth waiver is sought, the owner or operator should provide similar types of information on the 

lower confining zone(s) as well. 

Formation thickness may also be illustrated using: 

• Isopach maps (contour maps showing equal values of true stratigraphic thickness); and

• Isochore maps (contour maps showing equal values of true vertical thickness) and 

supported by available well logs and cores (also see Sections 4.1 and 4.2). 

Other supporting information may include: 

• Seismic or other geophysical survey results, with relevant information highlighted (if 

geophysical data are used for this demonstration); and 

• Well log data (when it is available), with injection and confining zones highlighted (if 

well logs are used for this demonstration). 

Any variability in the thickness of the injection formation and confining zone(s) that could affect 

storage of the carbon dioxide should be discussed in the narrative report, and the owner or 

operator should demonstrate that this would not adversely affect confinement. The owner or 

operator should bear in mind that if the areal coverage of the confining zone does not cover the 

full extent of the AoR or appears to be discontinuous, the UIC Program Director may request 

information on a secondary confining zone. 

2.3.4. Petrology and Mineralogy of the Injection and Confining Zones

The Class VI Rule requires the owner or operator of a proposed Class VI injection well to submit 

data on the mineralogy of the injection and confining zone(s) [40 CFR 146.82(a)(3)(iii)]. This 

information will support the identification of any geochemical reactions that may affect the

storage and containment of injected carbon dioxide which could result from potential changes in

the properties of the injection or confining zones (e.g., porosity, permeability, injectivity). It will 

also provide information on mobilization of trace elements from the formation matrix if minerals 

known to contain trace elements are identified, which informs decisions regarding parameters to 

analyze as part of a testing and monitoring program. Evaluation of the minerals and potential 

geochemical reactions is the basis of the required demonstration of compatibility of the carbon 

dioxide stream with fluids in the injection zone and minerals in the injection and confining zones 

required prior to commencement of injection at 40 CFR 146.82(c)(3); see Section 3.3. This 

information may also support the facies analysis required at 40 CFR 146.82(a)(3)(iii) (see

Section 3.1). 
UIC Program Class VI Well 19 

Site Characterization Guidance

If an evaluation of potential geochemical processes suggests that long-term storage and 

confinement of carbon dioxide may be affected by changes in the injection formation and 

confining zone(s), the AoR delineation may need to account for geochemical reactions through 

the use of reactive transport models. Any potential effects on storage and confinement due to 

mechanisms such as precipitation and dissolution may also affect the post-injection site care

(PISC) time frame. [40 CFR 146.93(c)(1)(v)]. 

Data Collection and Analysis 

If the proposed site has undergone previous characterization (e.g., for oil and gas development), 

data on the mineralogy of the injection and confining zones may be available. Owners or 

operators should consult with the UIC Program Director regarding whether available data are of 

sufficient quality and completeness and whether they adequately represent the injection 

formation and confining zones in the AoR, or if additional information is needed. If the UIC 

Program Director determines that additional data are needed to satisfy the requirements at 40 

CFR 146.82(a)(3)(iii), this may entail analysis of existing cores or, if needed, the collection of 

new cores. 

Collection of new data will most likely be necessary in pristine saline formations under 

consideration for GS project sites; however, such new information may also be needed for 

depleted oil and gas reservoirs if the previous characterization was not sufficient to demonstrate 

that the site meets the requirements of the Class VI Rule. If the owner or operator is requesting 

an injection depth waiver, the lower confining zone must be represented in this analysis [40 CFR 

146.95(a)(2)]; see the UIC Program Class VI Well Injection Depth Waivers Guidance for further 

discussion of injection depth waivers. EPA recommends that owners or operators discuss with 

the UIC Program Director any potential needs for stratigraphic/test wells to collect the necessary 

data and samples. 

Basic lithologic information can be obtained from inspection of cuttings and cores retrieved 

during drilling of a stratigraphic well (or from existing samples from previous work at the project 

site). Such information may be reported as part of routine mud logging. Polarized light 

microscopy and scanning electron microscopy may be used on thin sections, and powdered 

samples may be subject to X-ray diffraction (XRD). Background information on these methods 

is provided in the Appendix. 

Information to Submit

EPA recommends that owners or operators submit a narrative report that includes, at a minimum,

the following information: 

• Methods used in examining samples; 

• Locations (on maps) and depths of samples and the names of the formations sampled; 

• Lithologies and descriptions (e.g., color, texture) from cores or hand samples; 

• Mineralogic and petrologic descriptions obtained via microscopy (with approximate 

percentages of minerals); 

• Cementation minerals and dissolution features; and
UIC Program Class VI Well 20 

Site Characterization Guidance

• A preliminary discussion of geochemical reactions that may affect the storage, 

confinement, and/or overall performance of the project (see Section 2.3.9 for additional 

information on baseline geochemistry). 

Although the identification of mineralogy is required at 40 CFR 146.82(a)(3)(iii), and must be 

submitted before a permit is obtained to construct the injection well, additional data will also be 

obtained during the core analyses performed pursuant to 40 CFR 146.87(b), and the owner or 

operator must provide any updates to the UIC Program Director before injection is authorized, 

per 40 CFR 146.82(c)(2). 

To support the UIC Program Director’s evaluation of the application, the owner or operator 

should demonstrate that a sufficient number of samples have been analyzed to provide an 

indication of variability in mineralogy. The owner or operator should also highlight any 

information on the mineralogy and petrology of the injection and confining zones that is relevant 

to the required analysis of compatibility of the carbon dioxide to subsurface formations (see 

Section 3.3). 

Lithologic and mineralogic information should be complete and consistent with other 

information sources such as maps and well logs. The UIC Program Director may ask for 

additional information if descriptions and analyses are incomplete. 

2.3.5. Porosity, Permeability, and Capillary Pressure of the Injection and 

Confining Zones 

Data on porosity, permeability, and capillary pressure of the injection and confining zones, 

required at 40 CFR 146.82(a)(3)(iii), are crucial for a number of aspects of site characterization 

including determination of storage capacity, injectivity, and integrity of the confining zone. They

are also needed for the multiphase modeling to predict plume and pressure front behavior and 

delineate the AoR. Data may be obtained from well logs and laboratory analyses of core 

samples. If the owner or operator is seeking an injection depth waiver, information on the lower 

injection and confining zones is needed to evaluate their suitability. 

Section 2.3.5.1 describes information sources and analyses and information to submit to the UIC 

Program Director related to porosity; Section 2.3.5.2 addresses permeability data; and Section 

2.3.5.3 discusses data on capillary pressure. 

2.3.5.1. Porosity 

Evaluation of porosity may entail collection and review of existing data, use of field methods, 

and use of laboratory methods, as described below. 
UIC Program Class VI Well 21 

Site Characterization Guidance

Data Collection and Analysis 

Existing Data

In evaluating existing data from prior activities in the project area, owners or operators should 

note the methods used, the locations where samples were taken, and the overall quality of the 

data. Sufficient representative data will be needed from within the AoR. If available data are 

inadequate to establish the suitability of the site, the owner or operator will need to collect new 

data or perform new analyses. Any questions about the suitability and representativeness of 

samples should be discussed with the UIC Program Director. 

Field and Laboratory Methods 

If existing data are not available, are inadequate, or are of insufficient quality, new data will be 

needed. To satisfy the requirement under 40 CFR 146.82(a)(3)(iii), the owner or operator may 

use laboratory or field methods (e.g., well logging, seismic) to measure and/or estimate the 

porosity of the injection and confining formations. See Section 2.3.10 for additional information 

on seismic surveys. See the Appendix for additional information on the principles of well 

logging for porosity and brief descriptions of laboratory methods. When considering field data, 

owners or operators should be aware of the limitations and appropriate applications of different 

methods. Supporting data on lithology, corrections and/or interpretations applied to well logs or 

geophysical methods, and any statistical computations performed should be described and 

referenced. 

In selecting samples for laboratory analysis, EPA recommends that owners or operators be aware 

of the quality of the sample because the method of sample collection can influence the measured 

porosity. Owners or operators should also note any possible issues with sample quality when 

reporting results. 

Comparing Laboratory and Field Data 

Laboratory and field methods may or may not agree because laboratory methods provide point 

measurements, while field methods sample a volume of the subsurface. As a result, field-based 

data can incorporate small-scale heterogeneities that result from variability in lithologic 

characteristics and larger-scale fluid migration pathways such as vugs, fractures, and dissolution 

features (Cone and Kersey, 1992). Therefore, field measurements may yield higher or lower 

values for a particular formation than measurements collected in the laboratory. EPA suggests 

that owners or operators address any discrepancies between field and laboratory data if both 

types of data are submitted.

Information to Submit

EPA recommends that owners or operators submit, at a minimum, the following information on 

porosity: 
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Site Characterization Guidance

For laboratory-based data:

• Locations (on maps) and depths of cores and the formations from which those cores were 

taken;

• Coring method used and notes on the condition of the cores; 

• Laboratory analysis method(s) used, justification for selection of method(s), associated 

assumptions, and a description of experimental conditions; 

• Approximate grain sizes and shapes; 

• Approximate pore sizes and shapes; 

• Results in tabular and graphical form shown as laboratory results and porosity 

distributions within the injection and confining formations; and

• Photomicrographs if porosity was determined using thin sections. 

For field-based data:

• Results of field measurements and estimations shown as porosity distributions within the 

injection and confining formations (also see Section 4.1), including:

o Date and time of sampling/surveying,

o Method used (e.g., logging, seismic),

o Information on the location/area and intervals tested, and

• Calculations, corrections, or other steps in processing of field data.

For both field- and laboratory-based data:

• Summary statistics on data and any statistical representations (e.g., variograms); and

• A discussion of the results, including data quality and sources of uncertainty. 

Because core samples represent point measurements, for reliable results, measurements are best 

made on a number of cores. The applicant should consider submitting a statistical representation 

of measurements such as a variogram (see the Appendix for additional information).

EPA recommends that the owner or operator demonstrate that the data are of sufficient quality. 

The owner or operator should ensure that a sufficient number of samples were analyzed and that 

they represent likely heterogeneities in the injection and confining zones. The owner or operator 

should demonstrate to the UIC Program Director that appropriate methods were used and that 

downhole conditions were simulated (or explain why they were not and whether this is expected 

to affect the usability of the measurements). Finally, EPA recommends that owners or operators 

provide a discussion comparing field and laboratory-based data, giving careful consideration to 

the reliability of the measurements and contributions to any discrepancies. 

2.3.5.2. Permeability

The permeability of the injection zone is one of the factors governing the rate at which carbon 

dioxide can be injected and is one of the parameters needed for the computational modeling 

involved in AoR determination. Permeability of the confining zone is one of the factors 
UIC Program Class VI Well 23 

Site Characterization Guidance

considered in assessing the suitability of the confining zone. The subsections below provide 

considerations for the procurement and submission of permeability data. Because a GS project is 

a multiphase fluid system, effective and relative permeability data are also needed for AoR 

determination.

Data Collection and Analysis 

EPA encourages owners or operators to use data from field testing, well logging, and laboratory 

analyses of cores to estimate intrinsic (absolute) permeability. Laboratory analyses should also 

be performed to obtain a relative permeability-saturation function. When comparing field and 

laboratory measurements for intrinsic permeability, owners or operators should bear in mind that 

permeability measurements can differ by scale. Well tests measure a much greater area than core 

samples. As such, well testing tends to provide composite representations of localized variability. 

Permeability derived from well logs represents an intermediate scale between core logs and well 

tests. 

Existing Data

Where data are available from prior activities in the project area, owners or operators should take 

note of methods used, locations from where samples were taken, and overall quality of the data. 

These are described below, along with a discussion of spatial variability in permeability data. 

Field Methods for Absolute Permeability 

 

Permeability can be estimated in situ using a variety of methods. Pressure changes during fall-off

tests can be analyzed quantitatively. If multiple wells are available, variable flow test analysis 

can be used to determine permeability provided that the reservoir pressure, flowing bottomhole 

pressure, flow rates, and the total time of the test are known (Smolen, 1992; Matthews and 

Russell, 1967). Permeability can also be determined from well log data using an estimator of 

porosity such as a density log. A summary and comparison of the various empirical methods 

available to relate porosity, resistivity, and other parameters to permeability is given by Balan et 

al. (1995). Nelson and Batzle (2006) also provide a description of methods for permeability 

estimation from well logs. Owners or operators should be aware of the limitations associated 

with any method they select and be alert for uncertainties in the data and how these uncertainties 

might affect modeling efforts. 

Laboratory Methods 

As with porosity measurements, owners or operators should be aware of any damage to cores 

that may have occurred during drilling and that might reduce permeability. Plug samples taken 

from the center of the core may be the best way to avoid such damage or infiltration of mud or 

other particles into the pore spaces. See the Appendix for additional discussion regarding coring 

and sample selection for permeability measurements. 

EPA recommends that owners or operators consider conducting laboratory measurements of 

absolute permeability in an environment that simulates reservoir conditions or discuss 
UIC Program Class VI Well 24 

Site Characterization Guidance

anticipated effects that pressure and temperature might have on results. When permeability is 

measured from a whole core, measurements should be reported in two directions: one parallel to 

the major fracture plane and the other at 90 degrees perpendicular to this direction (Almon, 

1992). 

A relative permeability-saturation function is needed for incorporation into the computational 

modeling for the AoR delineation. For GS projects, changes in relative permeability may result 

in improved or reduced injectivity into reservoir rocks and/or improved or reduced sealing 

capacity for confining formations. In measuring and reporting data on relative permeability, 

owners or operators should be aware of hysteresis effects and should consider the need for 

separate curves for drainage and imbibition. Additional discussion of permeability-saturation 

functions is provided in the UIC Program Class VI Well Area of Review Evaluation and 

Corrective Action Guidance. 

EPA recommends that data be obtained from analysis of samples collected from as many cores, 

boreholes, or wells as practical and available to provide an understanding of spatial variability in 

permeability. Along each borehole, a number of core samples should be analyzed to capture 

heterogeneity. Owners or operators should be alert to variations that might indicate lenses of 

lower or higher permeability material that may affect storage capacity or carbon dioxide 

migration. Furthermore, permeability may be an anisotropic property that varies in the x, y, and z 

directions and typically shows the greatest variation in the direction perpendicular to layering. 

For the computational modeling performed for AoR determination, a realistic representation of 

the permeability distribution is needed, and EPA suggests that owners or operators consider a 

geostatistical approach. Further discussion regarding geostatistical approaches is provided in the 

Appendix and also discussed in the UIC Program Class VI Well Area of Review Evaluation and 

Corrective Action Guidance. 

Information to Submit

EPA recommends that owners or operators submit the following data related to permeability of 

the injection and confining zones: 

For laboratory-based data:

• Locations (on maps) and depths of cores and the formations from which cores were 

taken;

• Coring method used, and notes on the condition of the cores;

• Approximate grain sizes and shapes;

• Approximate pore sizes and shapes; 

• Laboratory analysis method(s) used, justification for selection of method(s), associated 

assumptions, and a description of experimental conditions; and

• Results in tabular and graphical form shown as laboratory results and permeability 

distributions in the injection and confining formations.
UIC Program Class VI Well 25 

Site Characterization Guidance

For field-based data:

• Date, time, and method of logging/surveying; 

• Information on the locations (on maps)/areas and intervals tested;

• Calculations, corrections, or other steps used in processing of field data; 

• Methods used for permeability estimation (e.g., specific well logs, seismic) or whether 

new interpretations are being made using archived data; and

• Results of field measurements and estimations shown as permeability distributions within 

the injection and confining formations. 

For both field- and laboratory-based data:

 

• Summary statistics on data and any statistical representations (e.g., variograms); and

• A discussion of the results, including data quality and sources of uncertainty.

To support the UIC Program Director’s evaluation, the owner or operator should demonstrate 

that the data are complete and representative of the actual site. The discussion of permeability 

should also address variability in permeability and implications for the operational parameters 

for the project or for the storage capacity of the injection formation. See the Appendix regarding 

geostatistical methods.

2.3.5.3. Capillary Pressure 

Capillary pressure is one of the factors affecting the integrity of the confining zone and how 

readily carbon dioxide will penetrate into the confining zone. 

Data Collection and Analysis 

Several established methods are available for measurement of capillary pressure: mercury

injection, centrifuge, porous plate, and restored state cell. See the Appendix for brief descriptions 

of these methods. In selecting a suitable method, owners or operators should consider methods 

that allow measurement at pressures and temperatures representative of the injection zone. 

Particular attention should be paid to the capillary pressure of the confining zone because a 

sufficiently high capillary pressure is one of the mechanisms by which the confining zone acts to 

inhibit migration of carbon dioxide. Owners or operators may compare their estimated capillary 

entry pressure (Pe) to the anticipated surface tension of the supercritical carbon dioxide 

(Chadwick et al., 2008), taking into account the anticipated buoyant pressure and potential height 

of the carbon dioxide column (Lindeberg, 1997). 

Information to Submit

EPA recommends that owners or operators submit the following information on capillary 

pressures of the injection and confining zones: 

• Locations (on maps), formations, and depths of samples used for analysis; 
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Site Characterization Guidance

• Method used for analysis, fluid used, and laboratory conditions; 

• Results in functional forms for the saturation-capillary pressure functions and/or tabular 

and graphical form; 

• Summary statistics on data; 

• A discussion of any limitations of the data or methods; and 

• Any issues associated with extrapolation of results to a setting in which supercritical 

carbon dioxide is the non-wetting fluid.

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator demonstrate that the data are of sufficient quality and that the number and locations 

of samples are adequate to provide good characterization of the injection and confining zones. 

2.3.6. Geomechanical Characterization

The Class VI Rule requires that geomechanical information be submitted on fractures, stress, 

ductility, rock strength, and in situ fluid pressures within the confining zone [40 CFR 

146.82(a)(3)(iv)]. Geomechanical characterization is important for evaluating confining zone 

integrity as well as setting safe operational parameters. If an injection depth waiver is sought, the 

owner or operator must also characterize and provide information on the lower confining zone(s) 

as required at 40 CFR 146.95(a)(2); this would include geomechanical information to support a 

complete analysis. 

Data Collection and Analysis 

This section outlines options for performing and submitting the results of geomechanical studies 

of fractures, ductility, rock strength and stresses, and pore pressure measurement.

Fractures may be detected in boreholes by several methods, including fracture finder 

(microseismogram) logs, caliper logs, or acoustic logs. Also, resistivity, gamma, and neutron 

logs can detect clay or fluids contained in fractures. Video logs can also show fractures. 

Fractures may be seen in cores, although unless the core was oriented, it will not be possible to 

determine the orientation of the fractures. 

Ductility is most commonly measured by performing a triaxial load test on a core sample. EPA 

recommends that such measurements be conducted in conjunction with other tests of core 

samples, such as strength, porosity, permeability, and capillary pressure. 

Rock strength can be measured in the laboratory using a triaxial compression test. ASTM 

International (ASTM) D7012-10, Standard Test Method for Compressive Strength and Elastic 

Moduli of Intact Rock Core Specimens under Varying States of Stress and Temperatures (ASTM, 

2010), is suitable for simulating downhole stress conditions. Owners or operators should bear in 

mind that these measurements will not account for larger scale features that affect overall 

strength in situ, such as faults or joints; results should be interpreted accordingly. 

The in situ stress field is important in determining the natural stresses in the formation and, 

therefore, the reaction of the various geologic units to injection, including the potential for fault 
UIC Program Class VI Well 27 

Site Characterization Guidance

reactivation (as discussed in Section 2.3.2). The in situ stress field consists of three components: 

vertical stress, maximum horizontal stress, and minimum horizontal stress: 

• Vertical stress can be determined by integrating the density of the rock above the point 

of stress measurement (Chiaramonte et al., 2008; Herring, 1992; Streit et al., 2005). The 

density is determined using density logs (see the Appendix); and

• The magnitudes of the minimum horizontal stress (Shmin) and maximum horizontal 

stress (Shmax) can be determined with considerable accuracy through direct in situ 

formation stress tests (See Zoback et al., 2003). ASTM Method D 4645-08, Standard Test 

Method for Determination of In-Situ Stress in Rock Using Hydraulic Fracturing Method

(ASTM, 2008) may be used. Additional descriptions of the determination of in situ 

stresses at a GS site are given by Chiaramonte et al. (2008), Streit et al. (2005), and Streit 

and Hillis (2004).

Pore pressure can be measured in an open borehole by formation testers, either on wireline 

(Smolen, 1992) or during logging while drilling (LWD). If existing data are not available, this 

information will likely be acquired as part of logging and testing procedures after the well is 

constructed or by drilling a stratigraphic test well to obtain the necessary data to meet the 

requirements at 40 CFR 146.82(a). 

Information to Submit

In submitting field- or laboratory-based information on geomechanical properties, the owner or 

operator should provide: 

• The test(s) performed, dates, and locations (on maps); 

• Sample collection procedures for cores;

• Test conditions (as appropriate); 

• Results in tabular and/or graphical form; 

• A narrative of results, including any anomalies or uncertainties in the data; 

• Comparison of data from different tests if more than one type of test is used for a 

particular parameter; and

• Any issues with sample procurement, e.g., disintegration of poor quality rocks during 

transport or sample retrieval, the existence of discontinuities (fractures, fossils, etc.) in 

tested samples. 

To support the UIC Program Director’s evaluation of the geomechanical data submitted, EPA 

recommends that the owner or operator demonstrate that the data are complete, and that all data 

(e.g., from different surveys and logs) support consistent conclusions. The owner or operator 

should also demonstrate that in situ stress fields are consistent with and support the 

appropriateness of the proposed injection pressures and that fault stability analyses are consistent 

with in situ stress data (see Section 2.3.2 for additional information on fault stability analyses). 
UIC Program Class VI Well 28 

Site Characterization Guidance

2.3.7. Seismic History

The Class VI Rule, at 40 CFR 146.82(a)(3)(v), requires Class VI permit applicants to report on 

the seismic history of the project site, including the presence and depth of all seismic sources. 

Additionally, the Rule requires a determination that seismic activity will not compromise 

subsurface containment of injected carbon dioxide. Records of prior seismic activity (both 

historical and geologic) should be used to make a determination of seismic risk. Information 

submitted for this requirement will also help to establish a site-specific monitoring program and 

inform the Emergency and Remedial Response Plan required at 40 CFR 146.94. 

EPA anticipates that existing data will be sufficient for determining the presence and depths of 

all seismic sources. However, owners or operators may need to model or otherwise determine, 

using documented methods, that seismic activity from identified sources will not endanger 

USDWs. 

Data Collection and Analysis 

Seismic records and confirmed or inferred seismic sources are available from a variety of 

national and state sources, many of which are free and publicly available. State databases are 

generally more detailed, but sometimes contain partial or incomplete records. Nationally, the 

USGS Earthquake database provides source, date, time, latitude, longitude, magnitude, intensity, 

and seismic-related information for earthquakes greater than magnitude (M) 2.5. For earthquakes 

greater than M 0, the Advanced National Seismic System catalog, hosted by the Northern 

California Earthquake Data Center, is available. Other national databases include the Center for 

Earthquake Research and Information (CERI) and the National Oceanic and Atmospheric 

Administration (NOAA)’s National Geophysical Data Center. The USGS’s Earthquake Hazards 

Program database (available at http://geohazards.cr.usgs.gov/cfusion/qfault/index.cfm) also 

provides information on recorded earthquakes.

Databases cataloging active faults are also available. These databases provide information on the 

hypocenters of seismic events, which can be mapped to provide a record of seismic sources for 

an area. Other databases of seismic sources include the USGS’s Quaternary Fault and Fold 

Database of the United States, which tracks faults associated with seismic events greater than 

M6. Property insurers may also be able to provide seismic data for the region surrounding the 

proposed site. 

Information on earthquake risk is available, most notably from the USGS’s National Seismic 

Hazards Maps, which are available at numerous scales and for numerous risk thresholds. The 

data and software used to create the maps are also freely available, enabling the customization of 

maps and introduction of new data or modeling parameters. International and national 

humanitarian organizations, engineering organizations, and disaster preparedness agencies have 

also developed manuals, plans, and models of earthquake risk and, in addition, have attempted to 

quantify the potential impact of seismic events on infrastructure. For example, the Federal 

Emergency Management Agency (FEMA) has several manuals on seismic risk throughout the 

United States. The internationally-developed Global Earthquake Model (GEM) may also provide 

useful information for determining the seismic risk to infrastructure at various scales. 
UIC Program Class VI Well 29 

Site Characterization Guidance

Although a seismic event would not necessarily lead to loss of containment, using seismic hazard 

maps to demonstrate the reasonable expectation that no seismic events would occur during the 

course of a GS project may fulfill the requirements at 40 CFR 146.82(a)(3)(v). However, if such 

maps indicate a substantial likelihood of seismic activity, other required geologic information, 

such as geomechanical data, depth to confining zones, and fault stability analysis may be needed 

to demonstrate that seismic activity will not compromise subsurface containment. Any 

demonstration that seismic activity will not interfere with containment should support a 

demonstration that the confining zone(s) will not be compromised by generation of new faults or 

reactivation of existing faults and that well bores will not be damaged in order for the site to 

meet the requirements at 40 CFR 146.83. The owner or operator should also consider the effect 

that seismic activity would have on site access and the ability of the owner or operator to verify 

containment under those circumstances as discussed in the Emergency and Remedial Response 

Plan. 

Information to Submit

In reporting information on seismic risk, owners or operators should submit the following: 

• A tabulation and/or map of seismic sources and their depths; 

• A tabulation of seismic events, their hypocenters, and magnitudes for as far back as data 

are available;

• The sources of all seismic history data;

• Information on any seismic risk models used and the results; and 

• A discussion of the degree of seismic risk in the region and information to support a 

determination that the confining system and wells at the project site are not vulnerable to 

damage from seismic activity. 

The owner or operator should demonstrate to the UIC Program Director that the data provided to 

support an evaluation of seismic risk cover an appropriate time period and include sufficient 

information on the magnitudes and locations of the hypocenters of previous seismic events. If 

seismic risk models are used, the owner or operator should describe any limitations of those 

models. 

2.3.8. Hydrology and Hydrogeology of the Area of Review 

The owner or operator of a proposed Class VI injection well must submit maps and stratigraphic 

cross sections indicating the general vertical and lateral limits of all USDWs, water wells, and 

springs within the AoR, their positions relative to the injection zone(s) and confining zone(s), 

and the direction of water movement, where known [40 CFR 146.82(a)(5)]. This information can 

demonstrate the relationship between the proposed injection formation and any USDWs, and it

will support an understanding of the water resources near the proposed well. The maps and cross 

sections developed to meet this requirement may be related to or overlain on the maps and cross 

sections illustrating regional geology and hydrogeology required at 40 CFR 146.82(a)(3)(vi); see 

Section 2.1. Potentiometric maps and isopach maps may also be submitted; additionally, the 
UIC Program Class VI Well 30 

Site Characterization Guidance

cross sections submitted to satisfy the requirements at 40 CFR 146.82(a)(3)(i) should include 

information on the vertical limits of USDWs in the AoR.

This information can support development of the water quality monitoring procedures in the 

Testing and Monitoring Plan required at 40 CFR 146.90. 

Data Collection and Analysis 

In most cases, the information needed to satisfy this requirement will be available from existing 

data sources, as described below. However, the owner or operator should discuss the available 

information with the UIC Program Director to ensure that the level of detail and the areal scope 

over which the information is available will be adequate to demonstrate that all USDWs have 

been identified, accounted for, and characterized. 

Information on USDWs and springs in the AoR can be obtained from the USGS as well as 

from state and local agencies (e.g., departments of environmental protection or municipalities). 

Published academic literature and reports from existing exploration or injection projects may 

also be used. In particular, the USGS maintains a website for ground water information that 

includes ground water use, aquifers, and water quality data 

(http://water.usgs.gov/ogw/data.html). Additionally, the USGS’s Hydrologic Investigations Atlas 

Series contains maps with a large amount of water resources information including water 

availability, producing aquifers, depth to ground water, and other data. More than 700 of these 

atlases have been published and are available at http://pubs.usgs.gov/ha/ha730. 

If the project involves an injection depth waiver, the owner or operator will need to provide 

information on USDWs above and below the injection zone. Information on all USDWs—above 

and below the injection zone—should be provided in the Class VI permit application and the 

injection depth waiver application required at 40 CFR 146.95(a) to support a review of all 

USDWs in the context of each evaluation. See the UIC Program Class VI Well Injection Depth 

Waivers Guidance for additional information on the injection depth waiver application. 

Information on water wells in the AoR is available from the following sources:

• State water centers or water surveys, state departments of water resources, or state Water 

Resources Research Institutes; 

• State health departments, which may have information on local and regional water 

supplies and private wells and state engineer’s offices may have databases of well 

permits; and

• State well permitting records, which may provide locations of public and private supply 

wells. States that issue well permits typically keep permit information in a searchable 

database either online (e.g., on environmental protection websites), or in hardcopy at an 

office or agency library. 

This information will complement the information submitted to satisfy the requirement for a 

tabulation of all wells within the AoR that penetrate the injection or confining zone(s) at 40 CFR 

146.82(a)(4). Note that the requirement discussed in this section, at 40 CFR 146.82(a)(5), is to 
UIC Program Class VI Well 31 

Site Characterization Guidance

show the location of all water wells, whereas 40 CFR 146.82(a)(4) is specific to wells that 

penetrate the injection and confining zones and must include additional information about the 

wells’ construction, including the well type, date drilled, information on plugging, etc. See the 

UIC Program Class VI Well Area of Review Evaluation and Corrective Action Guidance for 

additional information on that requirement. 

Information to Submit

EPA recommends that, to satisfy this requirement, Class VI injection well permit applicants 

provide the following information to the UIC Program Director:

• The numbers, thicknesses, and lithologies of USDWs (including interbedded low 

permeability zones); 

• Information on all USDWs in the AoR and the region, and whether they are currently 

being used for drinking water; and

• The location of water wells and springs within the AoR. 

In addition to tables and other files, the owner or operator may submit maps (e.g., showing the 

location of water wells on the maps of USDWs described above) and cross sections. If any water 

quality data or data on hydraulic conductivity, hydraulic gradient, or porosity are available from 

the sources examined, the owner or operator should reference this information or discuss it in the 

required analysis of baseline water quality, required at 40 CFR 146.82(a)(c) and described in 

Section 2.3.9. The owner or operator should ensure that the information submitted is complete 

and accurate; otherwise, the UIC Program Director may need to request additional information to 

thoroughly evaluate site hydrogeology and hydrology. For example, if state well databases have 

incomplete coverage of the area of the proposed well, owners or operators may need to fill in 

information gaps using on-the-ground surveys or hand searches of health or environmental 

department records. As noted above, most of the information needed to satisfy this requirement 

will likely come from existing data. If the data come from USGS or state data sources, it is likely 

that the UIC Program Director will be satisfied with the quality and accuracy of the data.

2.3.9. Baseline Geochemical Characterization

The Class VI Rule requires baseline geochemical information on subsurface formations 

including all USDWs in the AoR [40 CFR 146.82(a)(6)]. This encompasses both fluid and solid 

phase chemical analysis. Information on water chemistry indicates which formations in the 

stratigraphic column qualify as USDWs and confirms that the proposed injection formation is 

not a USDW. Geochemical information on both solids and fluids is also needed, in combination 

with the mineralogic data required at 40 CFR 146.82(a)(3)(iii), to determine whether the 

interaction of the formation fluids with the injectate and solids will cause changes in injectivity, 

changes in the properties of the confining zone, or the release of trace elements. This will inform 

an assessment of the compatibility of the carbon dioxide stream with injection zone fluids and 

minerals in the injection zone and confining zones, required at 40 CFR 146.82(c)(3) (see Section 

3.3). Fluid chemistry also controls the amount of carbon dioxide that can dissolve in the fluid, 

affecting estimates of carbon dioxide trapping mechanisms and storage capacity. Furthermore, a 

baseline geochemical analysis will be important for comparison with future data collected via 
UIC Program Class VI Well 32 

Site Characterization Guidance

required water quality monitoring above the confining zone [40 CFR 146.90(d)]. If an injection 

depth waiver is sought, the owner or operator should also provide data on or perform analyses of 

the geochemistry of USDWs that lie below the injection zone. 

Owners or operators will need to review existing data and may need to collect samples and 

perform analyses for fluid characterization and bulk solid phase chemistry. Guidance for 

providing information about fluid chemistry and bulk chemical analysis is presented below.

2.3.9.1. Fluid Chemistry

Data Collection and Analysis 

Pre-Existing Data

Geochemical data for the site may be available if previous exploration and hydrocarbon 

production have taken place at the project site, or data may be obtained from other sources such 

as the USGS’s National Water Information System (NWIS; http://waterdata.usgs.gov/nwis/qw) 

or Produced Waters Database (http://energy.cr.usgs.gov/prov/prodwat/). State geological 

surveys, water surveys, or water resources research institutes may also have information 

available. 

Owners or operators should submit any available analyses of water or brine from all USDWs and 

other relevant formations within the AoR. If the owner or operator is requesting an injection 

depth waiver, data will be needed for the lower confining zone to serve as a baseline for 

geochemical monitoring. Where pre-existing geochemical data are available, owners or operators 

should be aware that data quality may vary among sources. Limitations or uncertainties 

regarding data quality should be noted, including the presence or absence of analyses of 

duplicate and quality assurance (QA) samples. In relatively homogeneous geological settings and 

in formations with slow flow rates, analyses taken from areas outside of the AoR may be 

generally representative of water quality within the AoR and may be used to help understand the 

geochemistry of the area. However, data will be needed from within the AoR as well. Owners or 

operators should also consider whether the existing analyses are complete and include a full suite 

of parameters (see below). Owners or operators may discuss the applicability of pre-existing 

water quality data sets with the UIC Program Director. Data with limited analyses may still be 

useful for providing some general characterization, but newer data may also be needed to 

provide full characterization of water quality within the AoR. 

Owners or operators should note the time period over which the samples were taken and whether 

this information may be sufficient to capture any naturally occurring trends in water chemistry, 

especially in formations affected by recharge or surface activities. Having sufficient background 

information will allow owners or operators to distinguish possible effects of injection from 

naturally occurring variations over the life of the project. 
UIC Program Class VI Well 33 

Site Characterization Guidance

Parameters to Analyze 

The specific parameters to be analyzed will depend on the characteristics of the site, each 

formation being analyzed, and the composition of the planned carbon dioxide stream. Parameters

tested should help inform and be consistent with the testing and monitoring planned during the 

GS project operation and PISC period. Analyses should include basic parameters, such as pH; 

total dissolved solids (TDS); alkalinity; specific conductivity (SC); and major anions and cations 

(e.g., Ca2+, Mg2+, K+

, Na+, Cl-, Br-, SO4

2-, and NO3-

). Other constituents may differ by formation 

and be determined based on the mineralogy of the injection and confining formations (as 

evaluated under 40 CFR 146.82(a)(3)(iii) and discussed in Section 2.3.4). These may include: 

Sr2+, Fe2+, Fe3+, Al, SiO2, total organic carbon (TOC), carbon dioxide (aq), and hydrogen sulfide 

(aq) (if the site is an oilfield) and trace metals (e.g., As, Hg, Cu, Zn, etc.). Additionally, baseline 

gaseous carbon dioxide should be measured in subsurface formations including all USDWs 

within the AoR. Samples from proposed injection zones that are depleted hydrocarbon reservoirs 

may need to be analyzed for hydrocarbons. 

Constituents quantified by laboratory methods (e.g., major ions, trace elements, hydrocarbons, 

and TDS) should be analyzed using approved methods, including ASTM methods, Standard 

Methods (Greenberg et al., 2005), and EPA-approved methods. The UIC Program Class VI Well 

Testing and Monitoring Guidance can be consulted for more details, including a listing of 

specific methods that are generally used. An index of EPA methods can be found at 

http://www.epa.gov/region1/info/testmethods/pdfs/testmeth.pdf. 

Sample Collection from Existing Monitoring Wells

If there are monitoring wells in the AoR and they have not been recently sampled, owners or 

operators should consider taking fresh samples for water quality analysis. For wells in deep 

formations, including the injection formation, owners or operators may use a sampling apparatus 

that maintains downhole conditions if such a device is compatible with the construction of the 

well. If samples are retrieved at the surface, it is crucial that downhole estimates of pressure and 

temperature be obtained to support modeling of water chemistry speciation under conditions in 

the injection formation. For shallow wells, EPA guidelines are provided in USEPA (1991) and 

USEPA (1992). Additional information on sample retrieval and handling is provided in the UIC 

Program Class VI Well Testing and Monitoring Guidance. Following careful sampling 

procedures during site characterization will provide a reliable baseline for any future monitoring 

using the same monitoring wells. Owners or operators should also consider obtaining baseline 

samples over an adequate period of time to capture any natural temporal trends in water 

chemistry. 

Sampling Fluids while Drilling a Stratigraphic Well

If owners or operators drill a stratigraphic well to obtain information to fulfill the requirements at 

40 CFR 146.82(a), EPA recommends that samples of formation fluids be taken at that time. 

Sampling can be conducted using wireline sampling devices. Commercial systems are available 

that can take fluid samples in addition to obtaining downhole measurements of parameters such 

as density, pH, and mud contamination. Such equipment has been developed for characterization 
UIC Program Class VI Well 34 

Site Characterization Guidance

of hydrocarbon reservoirs and would be applicable to deep formations under consideration for 

GS. Additional discussion of fluid sampling is provided in Section 4.3. If the owner or operator 

obtains analyses of pore water in the confining zone(s), owners or operators should note if 

special methods were used (e.g., squeezing of shale core samples) and whether low volumes 

precluded analyses of any parameters.

2.3.9.2. Bulk Solid Phase Chemical Analysis

In addition to mineral identification, an elemental analysis of the formation solids in the injection 

and confining zones and other relevant formations (e.g., the first permeable formation overlying 

the confining zone) may be needed to evaluate the potential for liberation of trace metals due to 

lowered pH from injection. Options include X-ray fluorescence (XRF) of whole rock samples, or 

sample digestion followed by analysis by inductively coupled plasma/mass spectrometry

(ICP/MS). 

2.3.9.3. Geochemical Calculations and Modeling

With a complete chemical analysis of formation fluids and measurements of pH and temperature, 

equilibrium geochemical speciation of the constituents in the fluids and saturation indices for 

relevant mineral phases can be calculated to help identify the major reactions that may affect 

injection and containment. EPA recommends that this baseline information be compared against 

results from any future sampling. Two examples of suitable programs are PHREEQC, the current 

version of the USGS’s PHREEQ program (Parkhurst et al., 1980) and the Geochemist’s 

Workbench® (from Rockware, Inc.). Owners or operators should verify that the program selected 

for this purpose has the capability to perform calculations for waters with the ionic strength of 

the formation fluids (i.e., brines). 

If the owner or operator plans to perform additional analyses beyond basic equilibrium 

calculations, both of the above-mentioned programs are examples of software that can model 

reactions of fluids with minerals (identified as required by 40 CFR 146.82(a)(3)(iii)) and gases 

and can incorporate reaction kinetics (rates) and transport of fluids. The advantage of such 

modeling is that it allows consideration, prior to injection, of the types of reactions (e.g., loss of 

carbonates, precipitation of carbonates, long-term dissolution of silicates) that can change 

permeability, release undesirable elements, alter injectivity, and affect ultimate storage capacity. 

The owner or operator may choose to conduct reactive transport modeling to account for any 

significant effects of geochemistry while delineating the AoR. Additionally, see Section 3.3 for 

discussion of geochemical modeling as part of a demonstration of compatibility between the 

injectate and formation fluids and formation solids. 

Data Collection and Analysis 

If pre-existing data on the geochemistry of solids or core samples from previous characterization 

work are available, the owner or operator should discuss their availability and quality with the 

UIC Program Director, along with whether new core samples are needed for the baseline 

characterization and if so, which formations should be tested. 
UIC Program Class VI Well 35 

Site Characterization Guidance

Bulk chemical analysis of a powdered, solid sample may be obtained by XRF. Alternatively, 

samples may be digested and the extracts analyzed by inductively coupled plasma/atomic 

emission spectrometry (ICP/AES) or ICP/MS. Sample digestion can be done with EPA Method 

3052 (Microwave Assisted Acid Digestion of Siliceous and Organically Based Materials). For 

the analysis stage, EPA Method 6020A (ICP/MS) or EPA Method 6010-C (ICP/AES) can be 

used. 

Information to Submit

Owners or operators should submit the following information related to the baseline 

geochemistry of the site:

• The source of the data (if using existing analyses);

• Dates, locations (on maps), formations, and depths from which samples were taken; 

• Sampling methods and sample preservation methods used; 

• Analytical methods;

• QA data or QA samples (duplicates, blanks, matrix spikes); and 

• A discussion of the results, including any anomalous data, and a discussion of the spatial 

representativeness of the data for a given formation. 

Results should be presented in tabular and graphic form and plotted on a map of the AoR, if 

possible. The report on fluid chemistry should also include, temperature, SC, and pressure values 

taken at the time of sampling. In addition to submission of baseline fluid chemistry in tabular 

form, owners or operators may present their data in graphical form (e.g., using a Piper diagram 

(Piper, 1944) or a Stiff diagram (Stiff, 1951)). 

To support the UIC Program Director’s evaluation of the data, the owner or operator should 

demonstrate that the data are representative of the injection and confining zones, appropriate 

formation(s) above the confining zone, including USDWs, and, if needed, potential secondary 

confining zones, consistent with 40 CFR 146.82(a)(6) and 146.83(b). If geochemical data (e.g., 

analysis of the bulk chemistry of the solids) indicate high concentrations of trace elements, the 

owner or operator should evaluate injection and confining zone mineralogy and whether any 

trace elements are associated with minerals that are anticipated to be dissolved under the low pH 

conditions that may occur due to injection of carbon dioxide. In some circumstances, the owner 

or operator may also choose to analyze the presence of trace elements in the first permeable 

formation overlying the confining zone. 

If vintage data are used, the owner or operator should demonstrate to the UIC Program Director 

that they are adequate to establish a reasonable baseline prior to injection. The owner or operator 

should also identify and discuss any spatial variability in water quality data. 

2.3.10. Geophysical Characterization

To support the requirement at 40 CFR 146.82(a)(3)(iii) to submit data on the injection and 

confining zone(s), owners or operators can use a variety of field data, which may include seismic 

surveys or other geophysical methods. Although they are an indirect means of measurement and 
UIC Program Class VI Well 36 

Site Characterization Guidance

subject to uncertainty and interpretation, geophysical methods provide a means of generating 

information about the subsurface in lieu of physically sampling the layers of interest. They can 

also provide information over a larger area than cores alone can reasonably provide. Depending 

upon the scale and resolution of the investigation, geophysical methods (e.g., seismic and other 

surface and cross-well geophysical techniques) can be used to estimate the stratigraphy, 

structure, extent, and thickness of subsurface units. Data collected for a baseline geophysical 

survey will also serve as the reference point for future monitoring as required at 40 CFR 

146.90(g)(2) and as described in the UIC Program Class VI Well Testing and Monitoring 

Guidance.

There are four main types of geophysical methods: seismic, gravity, magnetic, and electrical/

electromagnetic (EM). These methods can image a large area of the subsurface without 

penetrations (i.e., wells or boreholes). EPA recommends that owners or operators deploy at least 

one of these methods during site characterization as they can provide good spatial coverage of a 

project area and may be especially useful in regions where subsurface geology is heterogeneous 

and/or wells are sparse. Owners or operators should demonstrate that their selected method will 

achieve adequate resolution at the depths needed. 

In selecting the specific geophysical method(s) to use, owners or operators should consider the 

following: 

• The goals of the survey and types of information desired; 

• The desired resolution;

• Subsurface lithologies; 

• Subsurface heterogeneity;

• Known or suspected faults and whether their geometries are likely to be imaged by the 

type of survey considered; 

• Locations of existing wells to use for downhole methods; 

• Whether an injection depth waiver is sought; and 

• The availability of other information from cores, well logging, and other sources to aid in 

interpretation of the data. 

Table 2-1 summarizes the status and utility of the various geophysical methods, and Table 2-2

outlines the phases of a GS project to which various geophysical techniques may be suited. The 

types of geophysical methods are described in Sections 2.3.10.1 through 2.3.10.4, followed by a 

discussion of what information should be submitted to the UIC Program Director. Additional 

detail on all four types of methods is provided in the Appendix. 
UIC Program Class VI Well 37 

Site Characterization Guidance 

Table 2-1: Applicability of Geophysical Techniques to Geological Features of Interest

SEISMIC GRAVITY ELECTROMAGNETIC/ 

ELECTRICAL

MAGNETIC

Investigation of 2D 3D VSP* 3D-VSP Crosswell

Borehole 

Microseismic

Aerial & 

Surface 

Gravity

Borehole 

Gravity

Natural 

Source

Controlled 

Source ERT*

Aerial & 

Surface 

Magnetic

Near Borehole and Shallow 

Subsurface W W W W W W 

Field-Wide Subsurface 

Studies W W W P W W W W 

Stratigraphy W W W W W W1 W P P W P2

Thickness W W W W W W W 

Structure 0-100 m P P P P P P P 

Structure 100 m – 1 km W W W W W P P P P W P 

Structure >1 km W W W P W W3 P W W P W3

Fault/Fracture W W W W W4 P P5 W5 P5 W 

Porosity P W W6 W6 W6

Pore Pressure P W P ? P 

Abandoned Wells7 W W8

W = Well Suited (e.g., already in use for site characterization with good results); 

P = Potential (e.g., could be used, but often not used because better alternatives are available or in use but results are not as resolved as desired).

1 Valid for flows, sills, channel fills, or other discontinuous units with high density contrast

2 Chiefly for iron-mineral bearing units (e.g., mafic intrusions, red-beds, etc.) 3 Characterizes depth to basement

4 Valid only if faults/fractures are actively undergoing deformation

5 Valid only in non-porous formations 6 Qualitative estimates compared to nearby formations

7

For additional geophysical techniques on finding abandoned wells see the UIC Program Class VI Well Area of Review Evaluation and Corrective Action Guidance 8

Valid only if wells are cased in the near surface with metal

*VSP = Vertical Seismic Profile; ERT = Electrical Resistance Tomography
UIC Program Class VI Well 38 

Site Characterization Guidance

Table 2-2: Stages in a Geologic Sequestration Project where Geophysical Techniques May Be Applicable

SEISMIC GRAVITY ELECTROMAGNETIC/

ELECTRICAL

MAGNETIC

APPLICABLE 

DURING

2D3D

VSP

3D VSP

Cross-well

Borehole Microseismic

Aerial & Surface Gravity

Borehole Gravity

Natural Source

Controlled Source

ERT

Aerial & Surface Magnetic

Preliminary 

Investigation X X X X X 

Site 

Characterization X X X X X X X X X 

Injection-Phase

Monitoring X X X X X X X X X 

Post-Injection 

Site Care X X X X X X X X X X 

2.3.10.1. Seismic Methods

For site characterization, seismic methods are well suited for determining formation thickness, 

stratigraphy, structures, and the location and/or attributes of faults (Table 2-2). These methods 

work best for characterizing simple, homogenous geologic settings where supplementary sources 

of data such as well logs, outcrop data, and other geophysical surveys are available. More 

detailed information on seismic methods and processing is available from numerous sources, 

including introductory guides such as: A Handbook for Seismic Data Acquisition (Evans, 1997), 

Environmental Geology – A Handbook (Knödel et al., 2007), and An Introduction to Geophysical 

Education (Kearey et al., 2002). For additional discussion on the principles and deployment of 

seismic methods, see the Appendix. 

Data Collection and Analysis 

Pre-Existing Data

Because seismic methods are used by a variety of industries, pre-existing seismic surveys may be 

available for the area of interest, especially if the region has been the subject of hydrocarbon or 

other mineral exploration. Existing seismic data will most likely be 2D. Some seismic data may 

also be available for free from government agencies; for example, the USGS maintains the 

Seismic Data Processing and Interpretation Group, which houses the National Energy Research 

Seismic Library (NERSL) and has been acquiring seismic reflection data since the mid-1970s. 

Processing methods for seismic data have improved greatly in recent years, and reprocessing 

vintage raw data can lead to improved resolution or identification of features not identified in the 

original survey (Hyne, 2001). Owners or operators should recognize that the quality or resolution 

of publically available or free data may not be suitable for GS project site characterization. 
UIC Program Class VI Well 39 

Site Characterization Guidance

Seismic Deployments

Seismic deployment can be done on the surface (2D or 3D), in boreholes, or a combination of 

both. If owners or operators are conducting a new seismic survey for purposes of site 

characterization, EPA recommends that the decision regarding the type of deployment be based 

upon what is known about site geology and features that may need imaging. Furthermore, it 

should be kept in mind that seismic data acquired during site characterization will serve as the 

baseline for any geophysical monitoring activities conducted during the injection phase of the 

project. Because 2D surveys produce “slices” of the subsurface, they are not optimal in settings 

where significant lateral heterogeneity is expected or faults are known to be present. 3D surveys 

may be preferable to 2D surveys when characterizing sites with complex or variable subsurface 

geology, where subsurface geology is not well constrained, where improved resolution is 

necessary, or where high well costs require greater certainty in subsurface characterization. A 

vertical seismic profile (VSP) can help increase the resolution and accuracy of other seismic 

surveys, can help with pore pressure estimation, and can help to link geology derived from other 

borehole logs to seismic attributes (Kearey et al., 2002). When imaging thin beds, cross-well 

seismic methods may be useful; they offer good resolution and can fill the resolution gap 

between high-resolution well cores and 3D surface data or to help correlate structure between 

well bores. Cross-well imaging may be considered in areas with abundant subsurface 

penetrations in locations that will allow imaging of features of interest. 

Additional Seismic Data Analysis

Pore Pressure Interpretation

If seismic data are of adequate quality, owners or operators may consider using the data to 

remotely estimate subsurface pore pressure. Any seismic data that yield an accurate seismic 

velocity can be used to approximate effective stress and estimate pore pressure. However, not all 

seismic data meet this criterion because accurate velocity values are not needed to image the 

subsurface. Ensuring that seismic data can also be used for pore pressure prediction requires 

planning. Once accurate velocity data have been obtained, there are numerous methods available 

to convert velocity to pore pressure. These methods tend to work best in developed basins filled 

with shales and sands. The main disadvantage of this technique is that it requires extensive data 

processing and interpretation, which may introduce large errors and necessitate basin-specific 

correction factors during velocity processing.

Seismic Stratigraphy 

Because seismic reflections follow large-scale bedding, the geometry of the reflections allows 

the delineation of features such as unconformities, depositional sequences, and unit thicknesses 

(e.g., Vail et al., 1977). EPA recommends the integration of seismic data with lithologic data 

from cores, well logs, and other data to assist in interpretation of depositional features and 

environments. If the owner or operator undertakes a detailed analysis, lithologies and other 

characteristics identified at wells and boreholes can be correlated to seismic attributes, which can 

then be used to predict subsurface properties at other locations through various methods, 

including regression or neural networks. Stratigraphic features identified in this manner may help 
UIC Program Class VI Well 40 

Site Characterization Guidance

in identifying features (e.g., barriers, channels, fans) that might affect storage capacity and 

migration of carbon dioxide. 

2.3.10.2. Gravity Methods

Gravity methods are well established for determining stratigraphy and formation thickness and 

have possible usefulness for identifying structure, faults, and porosity (Table 2-2). Because 

detection of faults and structural features using gravity data depends upon contrasts in density, 

EPA recommends that owners or operators reserve the use of gravity methods for basins with 

varied lithologies. Salt domes and igneous intrusions are the easiest types of lithologic features to 

image because they generally have a high density contrast with surrounding formations. Faults 

may be detected with gravity data if units with contrasting density or regions with different 

sedimentary thicknesses are juxtaposed. EPA also recommends that owners or operators consider 

the types of faults that are likely to occur in the project area; small faults or faults with large 

displacement occurring in discrete steps are more difficult to detect with gravity data than large 

planar faults. Vertical faults are especially difficult to detect using surface gravity methods 

(Barbosa et al., 2007). 

Data Collection and Analysis 

Aerial and land-based gravity surveys are commonly performed by government agencies. They 

are widely available and are often free. However, data available from such sources may be 

undersampled for many site characterization purposes or may not have been targeted at shallow 

to moderate-depth sedimentary sequences. Gravity data may be more likely to exist than other 

types of geophysical data if investigations into deep saline formations have previously occurred 

at the site.

Where the owner or operator deploys a gravity survey for the purpose of site characterization, the 

choice of deployment (land-based, aerial, or subsurface (boreholes)) is usually based on factors 

such as desired resolution and site-specific geology. Broad land-based or aerial gravity surveys 

may suffice for detecting large-scale changes in the thickness of basin fill and other basin-wide 

features, while more detailed surveys will be needed to detect finer features such as the 

distribution and thickness of specific formations. Borehole surveys can be used to determine 

layer thickness and aid in determination of lithologic composition. In regions that are laterally 

variable, borehole gravity data may indicate features such as salt domes and reefs even if they do 

not intersect the borehole (LaFehr, 1992). 

2.3.10.3. Electrical/Electromagnetic Geophysical Methods

Electrical and EM methods have potential application in certain formation types for delineating 

structure, stratigraphy, faults, and porosity (see Table 2-2 for additional details). Resolution is 

low for most electrical/EM methods compared to seismic methods. However, the depth and 

breadth of electrical/EM surveys can provide valuable information on the regional geologic 

framework at low cost (Orange, 1992). Additional information on EM methods for GS site 

characterization is presented in the Appendix. 
UIC Program Class VI Well 41 

Site Characterization Guidance

Data Collection and Analysis 

Electrical survey data are not likely to be available for a proposed Class VI injection well site 

unless the region has previously been characterized for hydrocarbon or ground water resources. 

Data can be collected aerially, from the surface, or from the subsurface. For a detailed site 

characterization, EPA recommends the use of subsurface deployments when possible; this is

because subsurface techniques are generally of superior quality compared to most surface 

methods, and heterogeneous surface conditions tend to attenuate the signal (Wilt et al., 1995). 

See the Appendix for additional details on the various types of electrical and EM methods. 

2.3.10.4. Magnetic Geophysical Methods

Magnetic methods are suited for imaging faults and large-scale structures and may also be useful 

for smaller structures and stratigraphy (Table 2-2). Faults and other structural features in both 

basement rocks and overlying sedimentary formations can be imaged, but formation 

characteristics are difficult to determine using magnetic data (Ugalde, undated). Because 

magnetic data are non-unique and do not represent specific lithologies, additional data from other 

types of geophysical surveys or other sources (boreholes, outcrops, etc.) are needed to improve 

magnetic data interpretation (Jordan and Hare, 2002). The Appendix provides additional detail 

on magnetic geophysical methods.

Magnetic methods are sensitive to human infrastructure. As a result, they are not useful in 

populated or developed areas because buildings, pipes, and wires obscure the geologic signal. 

They are, however, well suited for locating abandoned, cased wells that may need corrective 

action. See the UIC Program Class VI Well Area of Review Evaluation and Corrective Action 

Guidance for additional information. 

Data Collection and Analysis 

Magnetic surveys have already been conducted over the majority of North America. However, 

the resolution of these surveys may not be high enough for site characterization purposes. Highresolution data are more likely to have been collected for hydrocarbon-producing basins and 

areas targeted for mineral exploration. 

Information to Submit

In reporting the results of geophysical surveys, EPA recommends that owners or operators 

submit to the UIC Program Director the following information:

• The source of the data and whether they are vintage or newly collected;

• The type of survey and other details of the deployment (e.g., date, location/areal extent of 

the survey, vendor who performed the survey); 

• If boreholes were used, the locations of the boreholes; 

• Type of data processing, including any reprocessing of vintage data; 
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Site Characterization Guidance

• Images, with locations of profiles indicated on a map and salient geologic features 

identified (including formations below the injection zone where an injection depth waiver 

is sought); 

• Assumptions and limitations associated with the method, data, and their interpretation;

• A narrative discussing the results in the context of the site geologic conceptual model; 

and

• If the data suggest non-unique interpretations, the owner or operator should address 

alternative interpretations.

To support the UIC Program Director’s evaluation of the data, the owner or operator should 

demonstrate that the geophysical survey results provide an image of the subsurface at a suitable 

resolution for evaluation of the injection and confining zones. The owner or operator should also 

demonstrate that the results of the survey are consistent with other data such as geologic maps 

and lithologic information from cores. If the owner or operator submits a new survey to serve as 

a baseline for future monitoring, EPA recommends that the survey be georeferenced for 

comparison against future surveys. If vintage data are submitted, the owner or operator should 

demonstrate to the UIC Program Director that the data provide adequate coverage of the AoR 

and are of sufficient quality. 

2.3.11. Surface Air and Soil Gas Monitoring

At the discretion of the UIC Program Director, the owner or operator may be required to monitor 

surface air and/or soil gas for carbon dioxide leakage that may endanger a USDW [40 CFR 

146.90(h)]. Carbon dioxide detection above background levels in soil gas or at the surface does 

not necessarily indicate USDWs have been endangered, but that a leakage pathway or conduit 

exists at some point in the operation. 

Baseline surface air and soil gas data should be collected if the UIC Program Director requires 

surface air and soil gas monitoring as part of the Testing and Monitoring Plan. Baseline data on 

carbon dioxide concentrations and fluxes collected prior to operation will provide data for 

comparison to levels during and after the operational phase of the project in order to detect any 

potential leakage. The owner or operator or the UIC Program Director may opt to perform 

surface air and soil gas monitoring during the site characterization phase to provide a baseline if 

they plan to incorporate surface air and soil gas monitoring technologies at a later date. 

The AoR should be characterized with respect to properties that may affect the baseline data, 

such as soil type, soil organic carbon content, vegetation type and density, topography, and 

surface water hydrology. Different approaches can be used to conceptualize the system, such as 

ecological modeling to identify the sources and sinks and/or flow and transport modeling to 

understand the flow paths and dispersion processes. 

Data Collection and Analysis 

Overall, the spatial distribution of soil carbon dioxide fluxes and concentrations should be 

determined on a site-specific basis. A more precise determination of baseline would require 

repeated measurements at several fixed sites to capture any seasonal or diurnal variations. In 
UIC Program Class VI Well 43 

Site Characterization Guidance

particular, EPA recommends that the location of soil gas and/or surface air sampling points be 

based on the following considerations: 

• Avoiding areas with highly fluctuating background concentrations, based on previously 

recorded data; 

• Selecting potential point-sources, including wellheads, artificial penetrations, and fault or 

fracture zones. A transect-profiling approach may be used for linear features, such as 

faults (see ASTM, 2006); and

• If intended to monitor for non-point source leakage, monitoring throughout the AoR, 

using a grid methodology in areas of potential leakage. Grid cell spacing may range over 

several orders of magnitude, depending on site-specific factors. See ASTM (2006) for 

discussion of establishing a soil sampling grid.

During measurement of concentration and fluxes, EPA also recommends monitoring soil 

temperature and moisture. Some other important data, such as atmospheric temperature, 

pressure, and wind speed and direction can be obtained from a nearby weather station. The data 

collected should be analyzed using regression analysis to develop empirical relationships 

between correlated parameters for the entire area or the chosen sub-areas, which can then be used 

to predict background carbon dioxide fluxes expected under a given set of environmental 

conditions (Oldenburg et al., 2003). 

EPA recommends that when surface air and/or soil gas monitoring is conducted in compliance 

with multiple regulatory programs, the owner or operator design a baseline determination and 

monitoring strategy that efficiently meets all objectives (e.g., to meet the requirements of the 

Class VI Rule and Subpart RR of the GHG MRR, promulgated under the authority of the Clean 

Air Act). In some cases, separate technologies (e.g., eddy covariance towers versus soil gas 

probes) may be used to meet specific objectives. However, it is likely that data collected from 

multiple techniques will be complementary and useful in data analysis and interpretation for all 

regulatory programs. Further information on technologies that can be used for soil gas and 

surface air monitoring can be found in the UIC Program Class VI Well Testing and Monitoring 

Guidance and the Subpart RR General Technical Support Document (USEPA, 2010). 

Information to Submit

If baseline surface air or soil gas analyses are needed, EPA suggests that owners or operators 

submit the following:

• Site characteristics: soil type, soil organic carbon content, vegetation type and density, 

topography, surface water hydrology; 

• Sampling locations (in map form) and dates; 

• Soil temperature and moisture data and atmospheric conditions; 

• Sampling and analytical methods, including detection limits;

• Results presented as concentrations and fluxes in tabular and graphic form, including QA 

samples and analyses;

• Methods and results of regression analyses; and
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Site Characterization Guidance

• Methods and results of any ecological modeling performed, including input data, outputs, 

and sensitivity analyses.

To support the UIC Program Director’s evaluation of surface air and soil gas data, the owner or 

operator should demonstrate that the locations sampled represent a reasonable grid size and that 

potential point sources are represented and will serve as a good baseline to which future 

monitoring data can be compared. The owner or operator should also demonstrate that seasonal 

and diurnal variations in carbon dioxide levels have been captured and describe the variability in 

the data for future reference. If an inadequate time series of analyses was performed or if there 

are concerns regarding the quality of analytical data, the owner or operator may be asked to 

submit additional data. 
UIC Program Class VI Well 45 

Site Characterization Guidance

3. Data Synthesis for Demonstration of Site Suitability

The information required at 40 CFR 146.82 and described in this guidance provide 

comprehensive data and descriptions for many properties of the proposed project site (e.g., 

porosity, geochemistry). These data do not individually provide a complete picture of the site to 

demonstrate that it can safely receive and confine the carbon dioxide. Together, however, this 

information can form a comprehensive picture of the site and demonstrate whether it is a good 

candidate for GS and meets the requirements at 40 CFR 146.83. This section describes how the 

owner or operator can synthesize the information collected during site characterization to 

demonstrate site suitability. 

• Information on facies changes, required at 40 CFR 146.82(a)(3)(iii) supports the 

development of the site conceptual model and an understanding of how the carbon 

dioxide plume will move in the subsurface; it can also inform the AoR modeling. Section 

3.1 briefly discusses how owners or operators may present geologic information (e.g., 

cores, outcrop data, seismic surveys, and well logs) to provide an illustration of facies 

changes within the subsurface; 

• Structural information on the injection and confining zones is necessary to 

demonstrate how the carbon dioxide will be confined in the injection zone and that there 

are no potential leakage pathways. Section 3.2 describes how information collected, 

including maps, cross sections, and seismic data, support a description of the site 

structural geology; 

• Carbon dioxide stream compatibility with the well and subsurface formations and 

fluids is important to the long-term viability of the injection operation. The owner or 

operator must provide information on the compatibility of the carbon dioxide stream with 

fluids in the injection zone(s) and minerals in both the injection and the confining zone(s) 

[40 CFR 146.82(c)(3)]. This information will show that the well will not be damaged by 

the injectate and that no geochemical reactions within the injection and/or confining 

formations will affect the storage and/or containment in a manner that is not accounted 

for in planning or reduce the storage capacity of the site. Section 3.3 describes how 

information on the injectate, fluids in the injection zone(s), minerals in the injection and 

confining zones, and well materials can be combined and evaluated together to 

demonstrate compatibility of the carbon dioxide stream; 

• Information on the storage capacity of the injection zone is important to demonstrate 

that the site, based on site-specific information such as thickness, porosity, geochemistry, 

etc., has sufficient capacity to receive the amount of carbon dioxide anticipated to be 

injected as required at 40 CFR 146.83(a)(1). Section 3.4 briefly discusses approaches that 

may be considered to evaluate storage capacity; 

• Information on confining zone integrity supports a demonstration that the confining 

zone will not allow migration of carbon dioxide outside the intended injection zone(s) 

and that the site meets the requirements at 40 CFR 146.83(a)(2). Section 3.5 describes 

how information collected, including lithologic and stratigraphic data, structural data, 

core analyses, and formation testing data can support a demonstration of confining zone 

integrity; and
UIC Program Class VI Well 46 

Site Characterization Guidance

• A demonstration of secondary confinement may be appropriate to ensure USDW 

protection, impede vertical fluid movement, allow for pressure dissipation, and provide 

additional opportunities for monitoring, mitigation and remediation. Section 3.6 describes 

the information that is needed to make this demonstration and how the owner or operator 

would present it to the UIC Program Director if it is required per 40 CFR 146.83(b). 

Some aspects of this data synthesis involve combining geologic, geochemical, and 

geomechanical information and explaining how they demonstrate that the site meets the Class VI 

Rule requirements. Other aspects may require additional analysis, such as modeling. The 

sections below present recommended approaches for compiling, synthesizing, and presenting the 

necessary information. 

Thinking of the proposed site in the context of this larger analysis can help guide the site 

characterization process by identifying the big questions about the site that need to be answered 

and tailoring the information collection to ensure that the data support a determination that the 

site is appropriate for GS. This synthesis also supports the AoR modeling, project plan 

development, and effective management of injection operations. It can also facilitate the UIC 

Program Director’s review of the application and may improve public acceptance of the project 

by demonstrating to the public how the geologic data support a determination of site suitability.

3.1. Facies Analysis for the Project Site 

The Class VI Rule, at 40 CFR 146.82(a)(3)(iii), requires owners or operators to provide 

information on facies changes in the injection and confining zones. Understanding facies 

changes at the injection site will help the owner or operator develop a geologic conceptual model 

that describes the depositional environments and the resulting distribution of lithologies. Because 

lithofacies exert control on porosity, permeability, and mineralogy, a good facies analysis will 

help in anticipating heterogeneity in these properties and the associated effects on the injection 

and storage capabilities of the site. Understanding of subsurface heterogeneity can also be used 

to select the placement and design of injection and monitoring wells as well as refine the 

parameterization of multiphase flow modeling for the site (see the UIC Program Class VI Well 

Area of Review Evaluation and Corrective Action Guidance). This section briefly discusses

considerations and data needed for assessing facies changes. 

Data Collection and Analysis 

An analysis of facies changes and identification of the spatial distribution of lithofacies within 

different layers/formations may require integration of several types of information gathered 

during site characterization. Lithofacies distribution for computational modeling can be 

estimated using geostatistical approaches (e.g., geometric object-based methods or cell-based 

methods). 

The data needed for facies analysis can include geologic maps, isopach maps, stratigraphic 

columns, wireline logging data, descriptions and analyses of core samples, and seismic data. For 

example:
UIC Program Class VI Well 47 

Site Characterization Guidance

• Descriptions and analyses of core samples will provide information on a number of 

relevant characteristics including mineralogy, cross-bedding, grain sizes, sorting, finegrained interbeds, and cementation;

• Seismic stratigraphic features can be used to identify stratigraphic sequences; and 

• Wireline logging data can provide information on properties such as lithology and 

porosity and can be used to confirm the depths of formations. 

Correlation of these various data sources can provide a three-dimensional representation of the 

subsurface stratigraphy. Owners or operators should bear in mind that there may be considerable 

uncertainty in facies models given the need to interpolate between what may be sparse data 

points and logistical challenges to obtaining representative data. A brief discussion of facies 

considerations for GS and some useful references are provided in the Appendix. 

Information to Submit

Owners or operators should prepare a discussion of the inferred depositional environment(s) at 

the project site in the context of the site geologic conceptual model. The discussion should 

address, at a minimum: 

• The implications for connectivity within the injection formation and the suitability of the 

confining zone; 

• Lithofacies distributions mapped in the injection and confining formations, including the 

distributions of properties such as porosity and permeability for each lithofacies; 

• The potential for preferential flow paths; 

• Diagenetic processes that may affect present-day hydrogeologic properties; and

• Uncertainties associated with the data and with the resulting facies model.

The narrative should reference appropriate data, maps, geophysical images, cross sections, and 

stratigraphic columns.

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator demonstrate that correlation among data types is reasonable and that the available 

data support facies interpretations. The owner or operator should also assess possible preferential 

flowpaths or barriers and their implications for movement of carbon dioxide and for the quality 

of the confining zone. The report should also demonstrate how the facies interpretation informed 

the development of the site geologic conceptual model for the AoR delineation modeling. 

3.2. Structure of the Injection and Confining Zones

The Class VI Rule, at 40 CFR 146.82(a)(3)(vi), requires that geologic and topographic maps and 

cross sections illustrate the geologic structure of the local area. An assessment of the structural 

geology of the project area is a crucial part of a demonstration that the well will be sited in an 

area that meets the requirements of 40 CFR 146.83(a), and owners or operators should provide a 

thorough discussion that integrates all relevant information compiled during site characterization. 

This may include use of: 
UIC Program Class VI Well 48 

Site Characterization Guidance

 

• Geologic and structural maps and cross sections (see Section 2.3.1); 

• Isopach maps (see Section 2.3.3); 

• Results of geophysical surveys (see Section 2.3.10); and 

• Data from well logs and core analyses (see Sections 4.1 and 4.2). 

Data Collection and Analysis 

EPA encourages the use of all available data in the AoR and the surrounding region in this 

analysis. However, owners or operators should be alert to the quality of vintage data, especially 

if samples or raw data are not available. 

EPA strongly encourages the use of seismic data when evaluating structures at a GS site and 

emphasizes the usefulness of 3D seismic data or a grid of 2D seismic profiles. Lower or fair 

quality 2D data can be extremely useful for identifying larger faults, reservoir limits, and for 

general regional mapping. If geology is complex, especially around the point of injection, and 

greater detail is needed, 3D data are superior. If seismic profiling is not feasible at the project 

site, owners or operators should consider whether other geophysical methods will provide useful 

data. 

In the evaluation of regional and local structural geology, EPA recommends that the owner or 

operator illustrate and discuss major structural features that will affect the migration of carbon 

dioxide in the subsurface, such as: 

• Folds and their trend and plunge; 

• The presence of domes;

• The strike and dip of unfolded beds; 

• The locations, orientations, types of faulting (normal, reverse, strike-slip, thrust), and 

depths of faults; and 

• Units juxtaposed by faults. 

Owners or operators should discuss the role of structural traps in providing for secure storage (in 

a manner similar to the role of these structures in forming oil and gas traps). Such structures 

should limit the migration of carbon dioxide. The disadvantage of a closed structure, however, is 

that a confined column of carbon dioxide may form, putting stress on the confining zone from 

buoyant forces. In such settings, extra care may be needed in constraining the capillary pressure 

and geomechanical stability of the confining zone (Chadwick et al., 2008). 

In unfolded, gently-dipping sequences, carbon dioxide may potentially migrate long distances 

and the AoR may be larger. In such settings, careful attention should be paid to the presence of 

higher-permeability preferred flowpaths. Also, more data may be needed to accurately constrain 

structural surfaces that have minimal topography because uncertainties in the data will have a 

greater impact on predictions of carbon dioxide movement. 
UIC Program Class VI Well 49 

Site Characterization Guidance

Owners or operators should clearly indicate whether faulting is likely to enhance the project site 

by providing a trap, or potentially compromise the confining zone. Fault-bounded trapping 

through juxtaposition of the injection zone with a low-permeability layer may provide a 

favorable storage formation. Non-transmissive faults that transect the confining zone, however, 

may pose a leakage risk, and should be carefully evaluated for their stability and sealing capacity 

(see Section 2.3.2 for additional information on fault analyses and Section 3.5 for information on 

confining zone integrity). 

Information to Submit

The owner or operator should prepare a narrative for the UIC Program Director that clearly 

describes how the local and regional geologic structure are conducive to GS and that an adequate 

confining system is present. This discussion should describe how the structure of the injection 

and confining zones fit into and support the development of the site conceptual model developed 

for delineation of the AoR. Owners or operators should identify which features support the 

capacity of the site to contain carbon dioxide, including the role of structural traps. Potential 

weaknesses should also be addressed (e.g., if faults are present, whether data indicate that they 

are sealing). The owner or operator should also discuss whether there are alternative 

interpretations to the data.

Because this evaluation is based on data collected to meet other requirements, the owner or 

operator should reference the relevant data and associated uncertainties and describe how the 

data were used to support the structural analysis. Owners or operators should address the 

representativeness of these data and their consistency with other site data as well as with regionwide data (e.g., maps and geophysical images) and explain limitations when using these data to 

develop a conceptual model of the subsurface in the entire project area. The owner or operator 

should demonstrate that sufficient data were used to evaluate the structural geology, keeping in 

mind that the amount of data needed will be site-specific to some degree. For example, fewer 

data may be needed in areas with simple structures than in complex areas. 

3.3. Compatibility of the Carbon Dioxide Stream with Subsurface and Well 

Materials 

The Class VI Rule requires owners or operators to report on the compatibility of the carbon 

dioxide stream with fluids in the injection zone(s) and minerals in both the injection and the 

confining zone(s), based on the results of the formation testing program, and with the materials 

used to construct the well [40 CFR 146.82(c)(3)]. This demonstration is needed to support an 

understanding of (1) whether subsurface interactions among the injectate, fluids, and solids will 

lead to precipitation or dissolution of minerals such that permeability, porosity, and injectivity 

may change; (2) if geochemical changes due to the introduction of large amounts of carbon 

dioxide into the subsurface might cause trace elements such as lead or arsenic to be liberated 

from subsurface solids; and (3) if interactions among the fluid, carbon dioxide, and cement might 

cause deterioration of the cement such that the cement sheath would become a conduit for fluid 

migration. 
UIC Program Class VI Well 50 

Site Characterization Guidance

3.3.1. Compatibility of the Carbon Dioxide Stream with Fluids and Minerals

The compatibility demonstration will use information gathered during site characterization and 

during execution of the formation testing program, including: 

• Chemical analyses of fluids in the injection zone and, if available, the confining zone (see 

Section 2.3.9); 

• Mineralogy of the injection and confining zones (see Section 2.3.4); 

• Bulk chemical analyses of solids in the injection and confining zones (see Section 2.3.9); 

• Pressure, temperature, and pH in the injection zone and, if available, the confining zone 

(see Section 2.3.9); and 

• The chemical characteristics of the injectate (see the UIC Program Class VI Well Testing 

and Monitoring Guidance for information on this analysis).

Data Collection and Analysis 

To make a demonstration of compatibility, the owner or operator may take one or more of a few 

approaches, synthesizing information as appropriate: perform geochemical modeling, conduct 

bench-top laboratory experiments, and/or (in limited circumstances) provide an in-depth but 

qualitative discussion of potential geochemical reactions based on site data and GS literature. 

Guidance and recommendations for these approaches are presented below. 

Owners or operators are strongly encouraged to perform geochemical modeling to assess 

potential impacts of injection on the subsurface. Equilibrium speciation modeling with programs 

such as PHREEQC or the Geochemist’s Workbench® can be used to obtain saturation indices to 

predict the potential for mineral precipitation or dissolution, as described in Section 2.3.9. Such 

programs can also be used to model the reactions of fluids with minerals and gases and can 

incorporate reaction rates (kinetics). These geochemical models have also incorporated some 

capacity for 1D (PHREEQC) or 2D (Geochemists’ Workbench®) reactive transport simulations. 

Other geochemical models that may be used in GS applications include SOLMINEQ.88 

(Kharaka et al., 1989) and EQ3/EQ6 (Wolery, 1992). STOMP and TOUGHREACT are reactive 

transport models developed by Pacific Northwest National Laboratory and Lawrence Berkeley 

National Laboratory (http://esd.lbl.gov/TOUGHREACT/), respectively. They incorporate 

multiphase fluid and heat flow with geochemical reactions. TOUGHREACT has been used to 

model GS scenarios and anticipated mineral trapping (e.g., Xu et al., 2007; Xu et al., 2005). See 

the UIC Program Class VI Well Area of Review Evaluation and Corrective Action Guidance for 

additional information on multiphase reactive transport modeling. 

In performing geochemical modeling, the owner or operator should be aware of and discuss 

limitations in modeling capabilities and resulting uncertainties. In particular, this includes 

limitations in available thermodynamic and kinetic data. Gaus (2010) presents a more in-depth 

discussion of geochemical interactions in a GS context. Owners or operators are encouraged to 

take advantage of literature and research on suitable models and available thermodynamic and 

kinetic data. For example, Krupka et al. (2010) published a literature review on thermodynamic 

data for modeling of carbonate reactions associated with GS. A 2007 book by Marini covers 

thermodynamics, kinetics, and reaction path modeling as applied to GS. Gaus et al. (2008) have 
UIC Program Class VI Well 51 

Site Characterization Guidance

published a review article on geochemical and solute transport modeling for GS. Palandri and 

Kharaka (2004) have published a compilation of kinetic data. 

Owners or operators may consider bench-top laboratory experiments to simulate reactions 

among subsurface solids, fluids, and the injectate. If an owner or operator plans to use an 

experimental approach, EPA recommends using core samples of the injection and confining 

zones (see Section 4.2). If a sufficient sample is not available, rock and mineral samples 

representative of the subsurface at the project site may be used with documentation that they are 

very similar to the mineralogy of the injection and confining zones. The fluid phase should be 

formulated to mimic the formation fluids in the injection zone, and the carbon dioxide phase 

should include anticipated impurities. Pressure and temperature conditions should be 

representative of conditions at depth during operation at the project site. 

The duration of the experiment should allow for establishment of steady state conditions prior to 

introduction of carbon dioxide. After introduction of carbon dioxide, the experiment should be 

conducted for a sufficient time frame to result in measurable changes to the rock sample and for 

the fluid composition (pH, major ions) to achieve steady state; this may entail a run time of 

several weeks or a few months, depending upon the mineralogy of the sample and anticipated 

reaction rates among the fluid, minerals, and carbon dioxide. Fluid chemistry should be tracked 

during the experiment, and the solid materials should be analyzed after completion of the run. 

Rock/mineral samples should be evaluated for changes in porosity, permeability, and mineralogy 

by any of the methods described in Sections 2.3.4 and 2.3.5. 

Alternatively (and with the UIC Program Director’s agreement), the owner or operator may 

provide a detailed discussion of the geochemical characteristics of the injection and confining 

zone(s) and the injectate composition in the context of what is known in the literature about the 

reactivity of the minerals and anticipated reactions with the carbon dioxide and carbon dioxiderich brine. 

To make a convincing demonstration, this discussion should draw extensively on the geologic, 

mineralogic, geochemical, and GS literature and should tie this information closely to the known 

properties of the subsurface geochemistry and mineralogy at the project site, based on data 

collected during site characterization. Information from the literature such as mineral dissolution 

and precipitation rates should be considered in this evaluation, and the owner or operator should 

take note of limitations in available data (e.g., variations among studies, differences between 

field- and laboratory- derived data). Geochemical studies from GS pilot projects may be 

referenced if they have properties similar to the project site. Such a discussion will be qualitative 

in nature and is likely to be appropriate only in limited situations, such as where the geology is 

uncomplicated and homogeneous, the mineralogy is simple and relatively unreactive, and the 

injectate is known to be relatively free of impurities such as sulfur dioxide, which may give rise 

to very low pH values in the injection formation (Xu et al., 2007). If an owner or operator plans 

to use this approach, he or she should consult with the UIC Program Director. If this approach is 

supported by the UIC Program Director, the owner or operator should submit a thorough 

discussion that cites relevant literature and references mineralogic and geochemical data 

collected during site characterization. 
UIC Program Class VI Well 52

Site Characterization Guidance

Information to Submit

If geochemical modeling is performed, owners or operators should submit:

• The model used;

• Input data in tabular form;

• Modeling parameters and data used (e.g., activity coefficient model, identification of 

thermodynamic database, solid phases selected, reactions modeled, kinetic data, etc.);

• Results in tabular and graphical form;

• A thorough narrative interpreting the results and their applicability to the project; and

• A discussion of limitations and uncertainties associated with the modeling.

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator demonstrate that the information on which the model is based is complete and that 

the model is appropriate for the GS scenario. If significant mineral precipitation or dissolution is 

predicted, the owner or operator should discuss its impact on injectivity and whether 

precipitation or dissolution of minerals at the interface with the confining zone might either 

diminish or improve the sealing capabilities of the confining zone. 

In reporting the results of experimental work, owners or operators should submit:

• A thorough description of the experimental method;

• A description of the composition and origin of solids used;

• The chemistry of the input solution and the carbon dioxide phase (i.e., impurities);

• Porosity and permeability of the rock sample prior to experimentation;

• Plots of solution chemistry with time during the experiment;

• Geochemical reactions (e.g., dissolution and precipitation of minerals) that have taken 

place;

• Methods of evaluating permeability and porosity at the end of the experiment and the 

resulting values; and

• A narrative discussing the results and their implication for long-term behavior of the site, 

including changes in injectivity, the degree of mineral trapping, and how this information 

relates to the AoR delineation. 

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator demonstrate that the test conditions and input materials are representative of the 

injection formation and the downhole conditions, that the test was run for an adequate period of 

time, and that the fluid chemistry achieved steady state. 

If data are available from more than one location within the AoR, the owner or operator should 

provide an analysis that encompasses any variability in fluid chemistry and discuss any impacts 

on the resultant modeling or experiments. Similarly, if core analyses indicate lithologic and 

mineralogic heterogeneity, this too should be discussed.
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3.3.2. Compatibility with Well Materials

Owners or operators must provide information on the compatibility of the carbon dioxide stream 

with fluids in the injection zone(s) and minerals in both the injection and the confining zone(s) 

[40 CFR 146.82(c)(3)]. This will support a demonstration that reactions between the cement, 

formation fluids, and carbon dioxide will not lead to deterioration in the strength of the cement 

sheath or increases in the porosity and permeability that could result in the cement sheath 

becoming a conduit for carbon dioxide or carbon dioxide-rich fluids. 

The chemical and mechanical properties of hydrated cement in contact with a carbon dioxiderich environment should be considered. This is particularly relevant for Portland based cements. 

Owners or operators should demonstrate that the proposed cement sheath for their injection well 

will maintain integrity during the course of the project, including after injection ceases. This 

demonstration should take into account the following information gathered during site 

characterization and during well construction: 

 

• Chemical analyses of fluids in the injection zone and, if available, the confining zone; 

• Cement type and additives; 

• Pressure, temperature, and pH in the injection zone and, if available, the confining zone; 

• Chemical characteristics of the injectate, including impurities that may result in an 

especially low pH (e.g., sulfur dioxide); and

• Mineralogy of the injection and confining zones. 

Data Collection and Analysis 

To make a demonstration of compatibility, the owner or operator may conduct bench-top 

laboratory experiments and/or perform modeling or provide a detailed discussion of 

geochemistry based on available literature. Guidance and recommendations for these approaches 

are presented below. 

Modeling may be performed to support the compatibility demonstration. Owners or operators 

should state assumptions used in modeling such as governing mechanisms (diffusion of carbon 

dioxide into cement, transport through microannuli), and assumption of local equilibrium vs. 

modeling of kinetics. Owners or operators should identify the aqueous and mineral components 

(e.g., carbonate minerals, jennite or tobermorite for calcium silicate hydrate) included in the 

modeling and identify the thermodynamic data set used. Modeling should also account for 

changing subsurface conditions as a result of injection over time. If the owner or operator 

chooses to pursue modeling as part of the demonstration, he or she may consider the approaches 

used in recent studies (e.g., Wigand et al., 2009; Huet et al., 2010). 

Owners or operators may use benchtop laboratory experiments in a hydrothermal or flowthrough apparatus to support their compatibility demonstration. Any such experiments should be 

conducted at downhole pressure and temperature conditions. Samples of cement used in 

experiments should be cured under conditions representative of downhole pressure and 

temperature conditions in order to replicate the mechanical properties of the cement sheath in the 

injection zone. Experimental fluids should be formulated to mimic formation fluid composition. 
UIC Program Class VI Well 54 

Site Characterization Guidance

Experiments should be conducted over a sufficient time frame to permit measurement of the 

resulting mineralogical and mechanical properties. At the end of the experimental run, cement 

samples should be analyzed for mineralogy, texture, porosity, permeability, and strength; results 

should be compared with initial values. Examples of laboratory experiments performed for 

research purposes include Wigand et al. (2009) and Carroll et al. (2011). 

Owners or operators may discuss with the UIC Program Director the acceptability of using a 

literature-based discussion for their demonstration. This approach may be viable for settings 

where the injectate will be free of impurities, such as sulfur dioxide that might cause extremely 

low pH, and if the proposed cement has additives known to reduce susceptibility to carbonic acid 

attack. Such a discussion should take into account both field and laboratory-based information 

and should also explain how the proposed cementing procedures will result in a high-quality 

sheath that will resist incursion of carbon dioxide-rich fluid along the well bore (i.e., no 

microannuli or channels in the cement). 

Information to Submit

In submitting the cement compatibility demonstration, the owner or operator should describe the 

method selected for the demonstration and why it was chosen. For a literature-based discussion, 

all relevant literature and relevant data from site characterization (e.g., formation fluid 

chemistry) should be referenced. 

If owners or operators use an experimental approach, EPA recommends that they provide: 

• A thorough description of the experimental methods; 

• Why the particular experimental technique was chosen;

• Conditions under which the cement sample was cured; 

• The chemistry of the input solution and the carbon dioxide phase (i.e., impurities);

• Porosity, permeability, and density of the cement sample prior to experimentation;

• Plots of solution chemistry with time during the experiment; 

• Properties of the cement sample at the end of the experiment and at any intermediate 

stages at which samples are taken; and

• A discussion of the results and implications for the long-term integrity of the cement.

If owners or operators select a modeling approach, they should provide the following: 

• The model used; 

• Input data in tabular form; 

• Modeling parameters and data used (activity coefficient model, thermodynamic database, 

solid phases selected, reactions modeled, kinetics data, etc.);

• Results in tabular and graphical form; 

• A thorough narrative interpreting the results and their applicability to the project; and

• A discussion of limitations and uncertainties associated with the modeling.
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Site Characterization Guidance

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator demonstrate that the experimental conditions or modeling parameters are 

representative of the project, and that any reactions between the carbon dioxide and the cement 

or other well materials would not compromise the integrity of the well. See the UIC Program 

Class VI Well Construction Guidance for additional information on the compatibility of well 

materials and cements with carbon dioxide. 

3.4. Demonstration of Storage Capacity 

A demonstration of storage capacity can support predictions of the ability of the injection zone to 

receive and contain the anticipated total volume of carbon dioxide to be injected throughout the 

life of the GS project without endangering USDWs. It will support a demonstration that the site 

meets the requirements of 40 CFR 146.83(a)(1) that the injection zone or zones be of sufficient 

areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the 

carbon dioxide stream. This information should be consistent with the proposed operating 

parameters, site-specific information, and AoR delineation under 40 CFR 146.84. 

3.4.1. Methods for Estimating Carbon Dioxide Storage Capacity 

Carbon dioxide storage capacity depends on a combination of factors including multiphase flow 

processes, formation geometry and types of boundaries (e.g., open or closed boundaries, fault 

sealing), geologic parameters (e.g., porosity, permeability, compressibility) and their 

heterogeneity, and subsurface geochemistry (Doughty et al., 2001). Therefore, each type of 

geologic system chosen for storage (e.g., oil and gas reservoirs, saline formations, unmineable 

coal seams, and shale and basalt formations) may have different characteristics to consider while 

estimating storage capacity. In addition, project-specific factors also affect the storage capacity 

estimations, such as total volume, and chemical and physical characteristics of carbon dioxide to 

be injected; injection well configuration (e.g., number of wells and locations) and well bore 

integrity; operational parameters (e.g., pressure, injection rate); and other injection and 

production activities. EPA recommends that estimates of storage capacity, therefore, be 

accompanied by a clear statement regarding factors considered and the limitations of the 

assessment method used. 

Methods for estimating carbon dioxide storage capacity can be divided into static and dynamic 

models (USDOE, 2008; NETL, 2010). The application of static and dynamic models for 

estimating carbon dioxide storage capacity is based on methods routinely used in the UIC 

Program and by industry and others for estimating petroleum reserves, ground water resources, 

and underground natural gas storage. The selection of suitable methods for estimating storage 

capacity needs to consider various combinations of physical and chemical trapping mechanisms 

and their effectiveness over geological time frames and scales (Bachu et al., 2007; IPCC, 2005). 

Brief discussions regarding static and dynamic modeling methods for estimating carbon dioxide 

storage are provided in Sections 3.4.2 and 3.4.3, respectively. Section 3.4.4 describes 

considerations for the application of storage capacity estimation methods. 
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3.4.2. Static Models

Static models are simplified mathematical expressions that can be used to estimate the quantity 

of carbon dioxide stored in a reservoir and are typically used prior to injection, although they can 

also be used for estimating storage capacity after injection commences. Static models include 

volumetric and compressibility models (USDOE, 2008). Volumetric models are applied to open 

reservoirs when it is assumed that formation fluids are freely displaced from the reservoir. These 

models use porosity, area, and thickness in a Monte Carlo simulation approach with various 

efficiency terms included to account for the fraction of accessible pore volume that will be 

occupied by the injected fluid (USDOE, 2008). Compressibility-based models are used to 

estimate carbon dioxide storage in closed reservoirs, which are separated laterally by lowpermeability zones where the injected carbon dioxide is constrained by the compressibility of the 

formation’s native fluid and rock matrix. The compressibility approach is generally used for 

fluids with nearly constant total compressibility and assumes a single-phase system; typical 

applications include single-phase oil reservoirs and confined saline formations. 

Static models, typically applied to basin- or regional-scale assessments, can be used to quantify 

carbon dioxide storage estimates for oil and gas reservoirs, saline formations, and unmineable 

coal seams (Bachu et al., 2007; NETL, 2010). Standardized methodologies for estimating carbon 

dioxide storage capacity using static models have been adopted by the Carbon Sequestration 

Leadership Forum, and use of static methods has been proposed by DOE’s Regional Carbon 

Sequestration Partnership Program. A comparison of methods proposed by the two groups can be 

found in Bachu (2008). Owners or operators should be aware of the limitations of any static 

model selected, including the model’s limited ability to address factors that affect carbon dioxide 

storage capacity such as geologic heterogeneity, fault-sealing, well bore integrity, injectivity, 

formation geochemistry, the various trapping mechanisms, and the injection well configuration. 

While these models are employed more generally for basin- or regional-scale assessments, they 

also do not address issues related to far-field pressure buildup or native formation fluid (e.g., 

brine) displacement (Birkholzer and Zhou, 2009). Additional information on storage capacity 

estimation using static models is available in the Appendix. 

3.4.3. Dynamic Models

Dynamic methods include decline curve analysis, material balance, and reservoir simulation 

(USDOE, 2008). Of these, reservoir simulation is the most advanced and the most resourceintensive option and may not be easily applicable to basin- or regional-scale assessments where 

the necessary data are limited. However, this approach is suitable for local- or site-scale 

assessments, such as a Class VI project, where site characterization data are available and 

numerical modeling is already employed for AoR delineation. Using this approach will allow the 

development of more realistic, site-specific storage estimates that account for site-specific factors 

(e.g., boundaries, formation heterogeneity, near- and far-field pressure buildup, formation fluid 

displacement, etc.) as well as project-specific factors (e.g., operational parameters, injection well 

configurations, well bore integrity, etc.). This approach can also be used to reduce uncertainty 

and refine estimates of storage capacity by integrating new field data and well testing 

information during operation. 
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Decline curve analysis, for which a specific injection rate-time relationship (e.g., exponential 

function) is assumed, can be used for estimating storage capacity; however, it can only be used 

for active injection operations (USDOE, 2008). This method is generally applicable to individual 

wells or entire fields as long as the injection rate and time data exhibit a trend that fits the 

assumed function. Similarly, the material balance approach is also more suitable for injection 

operations already taking place since it includes the cumulative carbon dioxide injection and the 

corresponding pore pressure at various times. 

3.4.4. Application of Methods for Estimating Carbon Dioxide Storage Capacity 

Storage capacity estimates needed to support a demonstration that the site meets the 

requirements of 40 CFR 146.83(a)(1) will initially be submitted along with the permit 

application, which also includes the required AoR delineation information under 40 CFR 146.84. 

The numerical modeling employed for delineating the AoR must be based on site 

characterization data and account for chemical and physical properties of all phases of the carbon 

dioxide injected [40 CFR 146.84(a)]. Therefore, EPA recommends performing dynamic storage 

capacity estimates, complemented by static methods as described below, in concert with 

development of the numerical modeling used for the AoR delineation. If another method is 

chosen by the owner or operator, the application used should account for the planned and 

proposed operational parameters and the site characterization data collected, and be consistent 

with the AoR delineation process. 

In formulating an initial storage capacity estimate for site selection or screening activities, 

owners or operators may use static models in conjunction with available data on the project site. 

Additionally, static models can provide alternative assessments of storage capacity to confirm 

numerical modeling results if a reservoir simulation is chosen to determine and/or demonstrate 

the suitability of a site for a proposed project. 

In depleted reservoirs that have been used for EOR, reservoir simulations may have been 

previously performed to predict reservoir behavior based on the amounts of carbon dioxide 

injected. In these cases, estimating storage capacity can be facilitated by continued use of 

reservoir modeling. In coalbed methane settings, the storage mechanism is relatively 

straightforward and may be done in a manner similar to reserves estimation (Bachu et al., 2007). 

A static model may be suitable for such settings, keeping in mind limitations in calculation of the 

storage efficiency factor; owners or operators are encouraged to discuss the suitability of such 

estimates with the UIC Program Director. 

Estimation of storage capacity in deep saline formations will be more challenging than for 

depleted reservoirs or coalbed methane enhanced recovery settings because saline formations 

will involve several trapping mechanisms; in addition, fewer data may be available and existing 

data may be at a lower spatial resolution. Bachu et al. (2007) note that the storage capacity 

estimate needs to include the contributions from the various trapping mechanisms 

(structural/stratigraphic, solubility, residual, and mineral), and provide examples of using static 

model calculations for different trapping mechanisms. Numerical simulations can be used to 

explore this level of complexity at the site scale and are the most rigorous approach. However, 

the usefulness of reservoir simulation will be limited by the amount and quality of data available 
UIC Program Class VI Well 58 

Site Characterization Guidance

at the time the estimate is made. In some cases, static models may provide an adequate initial

estimate; however, EPA recommends that they be refined using dynamic modeling when 

adequate data become available. Any uncertainties about which approach is suitable should be 

discussed with the UIC Program Director. 

See the Appendix for additional discussion of data needs for storage capacity estimates. EPA 

also strongly encourages owners or operators to perform sensitivity analyses to estimate the 

effects of uncertainty in the input data for all storage capacity estimates. 

After injection commences, the owner or operator should periodically update and refine the 

estimate of carbon dioxide storage capacity based on new field data and well testing information. 

EPA recommends the use of dynamic modeling for updating carbon dioxide storage capacity 

estimates. Periodic reevaluations of the storage capacity should be done in conjunction with 

reevaluations of the AoR. For example, estimates of carbon dioxide trapping mechanisms from 

reactive transport modeling will affect storage capacity estimates. Likewise, alterations in 

storage capacity estimates may lead to changes in operational parameters. Evaluations of storage 

capacity and operational parameters may especially need to be revisited in case of unexpectedly 

high pressure buildup within the injection formation or evidence of fluid displacement that may 

cause significant risk of endangerment to USDWs. 

Information to Submit 

In reporting storage capacity estimates, the owner or operator should submit: 

• A description of the selected estimation method, including a discussion of its suitability 

for the type of formation; 

• Tabulation of any input data used, along with estimates of uncertainty in those data; 

• Results in tabular or graphic format; 

• A discussion of the results, relating them to proposed operational parameters and the 

anticipated total volume of carbon dioxide to be injected and the duration of the project 

and any identified site-specific vulnerabilities (e.g., faults, fractures, etc.); 

• A discussion of assumptions and limitations of the method used; 

• A discussion of uncertainty based on the results of a sensitivity analysis; and

• A discussion of how the results are consistent with and/or supported by the AoR 

delineation modeling. 

 

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator demonstrate that the storage capacity estimates support the anticipated injection rate 

and operational period, and that the anticipated total amount of injected carbon dioxide will not 

exceed storage capacity. The owner or operator should also demonstrate through sensitivity 

analyses that conservative estimates have been used for setting the proposed injection rate and 

volumes. An example evaluation of carbon dioxide storage capacity has been described by 

Asghari et al. (2006). 
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3.5. Demonstration of Confining Zone Integrity 

The owner or operator must demonstrate the ability of the confining zone to contain the carbon 

dioxide [40 CFR 146.83(a)(2)] and not allow migration of carbon dioxide, either through 

interconnected pore spaces across the thickness of the seal or through the confining zone along 

faults or fractures. In particular, analyses may be needed to ensure that existing non-transmissive 

faults will not become transmissive under anticipated injection and storage pressures. 

A number of approaches may be used to demonstrate competence of the confining zone. The 

Class VI Rule does not specify which methods should be used; rather, the choices of analyses 

and the data needed will depend on site geology. The methods described here are applicable to 

sites with single confining zones or multiple confining zones, if characterization of such 

additional zones is required by the UIC Program Director, per 40 CFR 146.83(b). 

Data Collection and Analysis 

An assessment of confining zone integrity will involve a synthesis of several types of 

information gathered through the site characterization process. In general, the following types of 

data may be used when demonstrating confining zone integrity: 

• Lithologic and stratigraphic data, e.g., on the depth, thickness, and mineralogy of the 

confining zone (see Sections 2.3.3 and 2.3.4); 

• Structural data, e.g., on faults and fractures, including fault geometry, depth of origin 

and termination, and the amount of displacement along the fault, including 

determinations of whether slip is consistent or variable along the fault and where such 

variations occur (see Sections 2.3.2 and 4.2); 

• Data from core analysis, e.g., the capillary pressure, rock strength, permeability, and 

porosity (see Section 4.2); 

• Field formation testing data, e.g., in situ fluid pressures, the magnitudes of principal 

stresses, and temperature (see Section 4); and

• Geophysical survey data, e.g., seismic, gravity, magnetic, or other geophysical methods 

(see Section 2.3.10).

Furthermore, while not a direct measure of integrity, the ability of the confining zone to contain 

natural oil and gas accumulations may serve as an additional line of evidence. Considerations for 

demonstration of confining zone integrity are presented in Section 3.5. Section 3.5.3 provides 

additional considerations for projects that will operate under injection depth waivers. 

3.5.1. Movement through the Confining Zone 

Continuous confining zones lacking faults or fractures may still allow the transmission of carbon 

dioxide through interconnected pore spaces throughout the thickness of the seal. Movement 

across intact seals in a GS setting will likely be controlled primarily by capillary pressure and 

permeability: 
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• Capillary pressure. As a general rule, good seals will have capillary entry pressures 

between approximately 6 and 40 MPa (Duncan, 2009). EPA recommends that owners or 

operators verify that the capillary entry pressure is in excess of pressure increases 

expected from the buoyancy-driven accumulation of carbon dioxide. Computational 

modeling developed for AoR delineation can assist in evaluating whether predicted 

pressures will remain below the capillary entry pressure, but owners or operators should 

bear in mind that such a demonstration is constrained by the fact that capillary pressure 

measurements will only be available from limited point locations. Capillary pressure and 

related measurement techniques are discussed in Section 2.3.5.3; and

• Permeability. Once the fluid pressure exceeds the capillary pressure, fluid may flow 

through the layer at a rate controlled by the permeability and the fluid pressure (Duncan, 

2009). A layer can make an effective seal even if the capillary entry pressure is low or if 

capillary entry pressure is exceeded, as long as the permeability is also low. Owners or 

operators should provide relative permeability-saturation-capillary pressure relationships 

derived from core analyses. They should discuss permeability of the confining zone in the 

context of other characteristics such as capillary pressure and thickness, and they may 

consider the performance of similar lithologies in other GS projects. Owners or operators 

may also consider numerical modeling to assess the potential effectiveness of the seal in 

inhibiting migration of carbon dioxide. See the Appendix for additional information on 

measurement of intrinsic permeability and relative permeability. 

3.5.2. Transmission of Carbon Dioxide through Faults 

A confining zone may be compromised if faults or fractures allow carbon dioxide movement 

across it. Faults can provide leakage pathways and fractures can be generated when capillary 

entry pressure and pore pressure exceed the rock strength. At that point, the layer will fracture 

before carbon dioxide enters into the pore spaces. 

Characterizing the Sealing Potential of Existing Faults or Fractures

Faulted or fractured formations may seal carbon dioxide (Meckel, 2007), but EPA recommends 

that applicants verify confining zone integrity by characterizing the sealing potential of the 

formation. Any faults or fractures that intersect, originate, or terminate in the confining zone 

should be thoroughly characterized (i.e., dimensions, geometry, sealing properties) regardless of 

their size (Knipe et al., 2001; Meckel, 2007). Thorough characterization of these features is 

important because properties can be heterogeneous across the fault or fracture plane, 

complicating interpretation (Freeman et al., 1998). A fault or fracture may be sealing (nontransmissive) in some regions while remaining transmissive in others. 

Owners or operators should also keep in mind that leakage can occur in complex seals composed 

of numerous variably permeable layers. For example, small faults and fractures that do not 

extend completely through the unit can connect permeable regions of the unit to form pathways 

for carbon dioxide migration (Ingram et al., 1997). These types of leakage pathways are likely to 

be more difficult to characterize because of their smaller scale. 
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EPA suggests several possible approaches to evaluate the likelihood of leakage occurring across 

existing faults or fractures, as follows: 

• Juxtaposition of units. Faults are likely to be sealed against lateral movement of carbon 

dioxide across the fault if the fault juxtaposes conductive and non-conductive units on 

either side. An Allan chart can be used to determine which units contact each other along 

a fault surface (Knipe et al., 1998); 

• Leakage along faults. The risk of leakage along a fault will be lower if sediments with a 

high capillary pressure and low permeability are found along or incorporated into the 

fault zone. These sediments will prevent migration of carbon dioxide along the fault for 

the same reasons they can prevent migration upward when present as a seal. Such 

materials can occur along the faults as a result of catalysis, diagenetic sealing, or by 

entrainment during fault movement. Owners or operators may use information from 

outcrops or cores that intersect the fault to evaluate whether such sediments occur in the 

fault zone; 

• Catalysis. Breakdown of materials along the fault due to physical abrasion during fault 

slip can produce fine material that tends to have smaller pore throats and, 

correspondingly, high capillary pressure. Catalysis can reduce the permeability of highporosity sandstones up to four orders of magnitude with only a few centimeters of slip 

and lead to sealing behavior along the fault (Yielding et al., 1997). Owners or operators 

may evaluate the degree of catalysis by examining hand samples, cores, or thin sections 

of samples taken from the fault zone. After evaluation, hand samples may be subjected to 

capillary pressure tests or other laboratory tests to quantify the effect of catalysis on pore 

size; 

• Diagenetic sealing. Determining the amount of diagenetic sealing of a fault or fracture 

due to authigenic calcite or silicates requires the direct examination of core samples from 

the fault or fracture zone in the laboratory. In some cases, samples taken from nearby 

faults or outcrops may be used to infer the amount of diagenetic sealing on buried faults 

or fractures, provided that the faults or fractures examined originated in the same time 

period and that evidence at various scales (e.g., thin section, hand sample, outcrop) 

indicate that diagenetic behavior is similar throughout the unit; 

• Calculation of shale gouge ratio (SGR). Materials from hanging- and footwalls in shale 

and other clay-rich formations can be incorporated along a fault, producing shale gouge. 

This fine-grained material helps to retard the flow of fluids along the fault. The amount of 

shale entrained by the fault from the shale/siltstone units the fault intersects can be 

estimated using the SGR (Freeman et al., 1998). This method works best for 

shale/sandstone/siltstone sequences. See the Appendix for additional information on 

calculation and interpretation of the SGR. Calculation of the SGR and other shaleentrainment methods requires accurate knowledge of lithology (specifically 

clay/phyllosilicate content) and thickness in the area of the fault. This level of 

information may require new boreholes, seismic surveys, other geophysical surveys, 

and/or a refined analysis of fault geometry and extent. EPA encourages owners or 

operators to determine the SGR where it is feasible and appropriate; and

• Pressure compartmentalization. If a fault compartmentalizes regions of different 

subsurface pressure, it may be sealing (Huffman, 2002). This method requires both 

subsurface mapping of all faults within the area of interest and pore pressure 
UIC Program Class VI Well 62 

Site Characterization Guidance

measurements. Pressure measurements can be taken directly from wells on both sides of

the fault (Doughty and Karasaki, 2004), or indirect pore pressure data may be generated 

by transforming seismic velocity data into pore pressure (see Section 2.3.10 and the 

Appendix). An example figure is provided in the Appendix. 

The owner or operator should be aware that use of seismic pore pressure estimates is still under 

development and can introduce errors, especially in subsurface environments that have not 

undergone significant subsurface exploration. Gathering sufficient subsurface pressure data by 

wells to use the pressure compartmentalization method may be labor intensive, and, although a 

pressure difference across a fault indicates sealing behavior, the lack of a pressure difference 

does not definitively indicate a transmissive fault.

3.5.3. Special Considerations for Characterizing Lower Confining Zones

An owner or operator applying for an injection depth waiver must demonstrate the integrity of

both the upper and the lower confining zones [40 CFR 146.95(a)(2)]. The basic methods for 

evaluating seal integrity remain the same whether the confining zone is above or below the 

injection zone. Estimates of thickness, permeability, fracture pressure, capillary pressure, and 

other parameters are recommended, as well as an understanding of whether the zone contains 

interbedded units of higher permeability. The owner or operator will also need to demonstrate 

that the confining zones are free of transmissive faults and fractures [40 CFR 146.95(a)(2)]. 

One important difference to consider between confining zones above and below the injection 

zone is that the upper confining zone will likely contact free-phase carbon dioxide prior to its 

dissolution while the lower confining zone may or may not contact free-phase carbon dioxide. 

However, both the upper and lower confining zones will be in contact with brine and may 

eventually be in contact with carbon dioxide-saturated brine. While capillary entry pressure is 

not relevant in the case of brine contacting a confining zone already saturated with brine, the 

capillary entry pressure of free-phase carbon dioxide in the lower confining zone should be 

determined and considered. See the UIC Program Class VI Well Injection Depth Waivers 

Guidance for additional information on applying for injection depth waivers.

Information to Submit

EPA encourages owners or operators to submit a discussion of confining zone integrity. The 

owner or operator should reference all relevant information from the site characterization and 

should provide a narrative discussing all lines of evidence used to support the demonstration. 

Details should be shown for any calculations performed (e.g., SGR), and images that support the 

demonstration should be annotated to illustrate relevant features. Not all types of analyses 

presented above may be needed, but the information presented should collectively indicate that 

the confining unit meets the requirements at 40 CFR 146.83. Any limitations in the data or 

analysis should be noted. 

Because the parameters used to assess confining zone integrity are calculated from existing data, 

the reliability of the final measurement depends upon the quality of the input data, and errors will 

be propagated through any calculations done in support of this analysis. The owner or operator 
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Site Characterization Guidance

should discuss any potential errors and how they may affect the evaluation of confining zone 

integrity. 

Because fault properties may vary spatially along the fault, resulting in variability of sealing 

capacity, the owner or operator should communicate any uncertainties in the data and be 

cognizant of the need for additional analyses to represent any spatial heterogeneity. 

3.6. Considerations for Secondary Confinement 

The Class VI Rule, at 40 CFR 146.83(b), provides the UIC Program Director with discretion to 

require the owner or operator to identify and characterize additional zones that will impede 

vertical fluid movement, are free of faults and fractures that may interfere with containment, 

allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation, 

and remediation. This demonstration is needed to facilitate consideration of GS sites where the 

owner or operator or the UIC Program Director determines that an additional barrier to fluid 

movement is appropriate based on site-specific data. 

These additional confining zones will not be needed in all circumstances, and the UIC Program 

Director would exercise their discretion to require characterization of secondary confinement if, 

for example, the first impermeable zone immediately above the injection zone can provide some 

confinement but may not demonstrate all of the properties needed to ensure that the carbon 

dioxide will not migrate. Characterization of a secondary confining zone may be needed if: 

• The primary confining zone does not exhibit sufficient strength to allow injection at the 

proposed pressures; 

• Known or suspected faults or fractures transect the primary confining zone and would 

interfere with containment of carbon dioxide; 

• The primary confining zone is not sufficiently extensive to cover the entire maximum 

extent of the carbon dioxide plume and pressure front or it is not sufficiently thick and 

homogeneous over the entire area; or 

• There is insufficient information or conflicting data about the primary confining zone. 

Data Collection and Analysis 

If the UIC Program Director requires information about a secondary confining zone, the owner 

or operator will need to demonstrate how the two layers would contain and prevent upward 

movement of the carbon dioxide. This demonstration should address how the two confining 

zones together meet all the requirements for confinement at 40 CFR 146.83(a)(2). Specifically, 

they should be free of faults that are transmissive throughout both confining zones, be of 

sufficient areal extent and integrity to contain the injected carbon dioxide stream and displaced 

formation fluids, and allow injection at proposed maximum pressures and volumes without 

initiating or propagating fractures. The owner or operator may also need to characterize the 

intervening zones between the primary and secondary confining zones to demonstrate that they 

allow for pressure dissipation and provide additional opportunities for monitoring or 

remediation. 
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Characterizing the secondary confining zone and any intermediate zones will involve the same 

methods that are used to characterize the primary confining zone. Some types of data, such as 

well logs or cross sections, will probably contain information about all subsurface formations, 

and the owner or operator would need to highlight information relevant to the additional 

confining zone and intervening layers.

If existing data or cores are used, the owner or operator should verify that they include coverage 

of the secondary confining layer and, ideally, any intervening units. If adequate data and/or 

samples are not available, additional sampling or analysis may be needed. If core samples are 

taken during drilling of a stratigraphic well, the owner or operator should ensure that the cores 

include representative samples from the primary and secondary confining zone, as well as any 

intervening layers. Owners or operators may need to obtain core analyses for samples from the 

secondary confining unit (e.g., porosity, permeability, capillary pressure, mineralogy, strength). 

Any relevant features on seismic or other geophysical images that help define the thickness and 

areal extent of the confining zone and characterize faults should be highlighted. In some cases, 

the owner or operator may need to establish the fracture pressure or fault sealing capabilities in 

the secondary confining unit. 

Information on the potential for pressure dissipation within the intervening layers may come 

from AoR modeling that includes information about both confining zones and the intervening 

formations. If additional ground water quality monitoring or direct monitoring for carbon dioxide 

or pressure measurements in these zones is warranted, the owner or operator should demonstrate 

how such monitoring enhances the Testing and Monitoring Plan. 

Information to Submit

The owner or operator is encouraged to discuss with the UIC Program Director specific needs 

related to characterizing additional confining zones, including how the primary confining zone is 

deficient. This will establish the level of data collection and analysis that may be needed to 

demonstrate that the system of subsurface formations is sufficient to confine the carbon dioxide 

and protect USDWs from endangerment. 

Based on the discussions, additional data collected, and additional analysis of the secondary 

confining zone, the owner or operator should submit to the UIC Program Director a description 

of the primary and secondary confining zones and the intervening layers, and how they will 

impede vertical fluid movement, allow for pressure dissipation, and provide additional sites for 

monitoring, mitigation, and remediation.

3.7. Reporting Process 

The Class VI Rule requires owners or operators to submit site characterization data collected 

pursuant to 40 CFR 146.82(a) and (c) with the permit application or prior to receiving

authorization to begin injection, respectively (see the preceding sections of this document for 

specific recommendations on the types of information to submit). These data must be retained 

throughout the life of the GS project and for 10 years following site closure [40 CFR 

146.91(f)(1)].
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Under the Class VI Rule, regardless of whether a state has primary enforcement responsibility, 

owners or operators are required to submit site characterization data to EPA in an electronic 

format approved by EPA [40 CFR 146.91(e)]. The data and supporting documents may be 

submitted as PDF files, including charts, graphs, and tabular data. EPA also recommends that 

raw data be submitted, in separate files (e.g., LAS, Excel). Additionally, EPA recommends that 

maps be submitted in a GIS-compatible format, to further assist a more detailed and flexible

review process by the UIC Program Director. For additional information on complying with the 

reporting requirements related to submitting site characterization data, please see the UIC 

Program Class VI Well Recordkeeping, Reporting, and Data Management Guidance for Owners 

and Operators. 
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4. Activities Performed Prior to Operation of a Class VI Well

Prior to commencing injection, owners or operators must provide extensive geologic and 

hydrogeologic data collected during the construction of a Class VI well to demonstrate to the 

UIC Program Director that the injection and confining zones are suitable for receiving and 

containing injected fluids [40 CFR 146.82(c)]. This section provides guidance on the formation 

and well testing and logging activities that the owner or operator must conduct to generate the 

information and data required to receive authorization to inject at a Class VI well. 

The testing and logging activities described here provide the information and data that will be 

considered by the UIC Program Director in authorizing Class VI operation as identified in 40 

CFR 146.82(c) and the formation testing requirements at 40 CFR 146.87. (The UIC Program 

Class VI Well Construction Guidance provides information on how owners or operators can 

meet the injection well testing requirements of 40 CFR 146.87.) 

For new Class VI wells, these testing and logging activities are undertaken during and after 

drilling and construction of the new injection well. For Class VI wells to be transitioned from 

other classes of injection wells (or pre-existing monitoring, stratigraphic test, or production 

wells), the testing and logging information can be provided from previous and ongoing testing 

and monitoring of the formation and from well tests and logs conducted during the previous use 

of the well. 

The activities described in this section include formation testing/logging, core sampling and 

analysis, and hydrogeologic testing to determine the physical and chemical characteristics of the 

injection and confining zones. Importantly, these post-well construction/pre-operational testing 

and logging data will provide updates to and can be synthesized with related injection and 

confining formation data obtained during the GS site characterization and submitted earlier as 

part of the Class VI permit application. Where appropriate, this section references related topics 

in Section 2 of this guidance. 

Each section below describes the Class VI Rule requirements that relate to specific 

testing/logging activities and identifies the use or relevance of the information to be provided. 

Brief technical descriptions are provided in the Appendix for testing and logging methods and 

how required information and data can be generated or obtained. Where appropriate, subsections 

below also provide recommendations and special considerations for obtaining and interpreting 

data and note particular aspects of the formation and well characterization process that might 

warrant discussions with the UIC Program Director. 

4.1. Well Logging 

During the drilling and construction of a Class VI injection well, the owner or operator must run 

logs, conduct surveys, and perform tests when appropriate to determine or verify the depth, 

thickness, porosity, permeability, lithology, and salinity of any formation fluids in all relevant 

geologic formations [40 CFR 146.87]. 
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These well logging activities supplement data on geologic and hydrogeologic properties of 

relevant subsurface formations collected during initial site characterization and are used to 

support building a conceptual understanding of the site, conducting the AoR determination, and 

designing the GS project. Performing a variety of logs provides complementary information on 

subsurface properties as well as taking advantage of the different levels of vertical resolution of 

the log types. 

Data Collection and Analysis 

At a minimum, well logs must include resistivity, spontaneous potential, gamma ray, porosity, 

fracture finder logs, and any other logs the UIC Program Director requires based on the geology 

of the site [40 CFR 146.87(a)(2) and (3)]. These logs must be conducted before installation of the 

surface casing [40 CFR 146.87(a)(2)(i)] and before installation of the long-string casing [40 CFR 

146.87(a)(3)(i)]. Any alternative methods that provide equivalent or better information must be 

approved by the UIC Program Director prior to implementation [40 CFR 146.87(a)(5)]. These 

types of logs are described in the Appendix; for further information on geophysical logging and 

analysis, see Asquith and Krygowski (2004), Telford et al. (1990), and NETL (2009). 

Information to Submit

 

The owner or operator must submit to the UIC Program Director a descriptive report prepared by 

a knowledgeable log analyst that includes an interpretation of the results of these logs [40 CFR 

146.87(a)]. This report must be provided in an electronic format and should include: 

• The date and time of each test, the date of well bore completion, and the date of 

installation of all casings and cements; 

• Chart results of each log and any supplemental data;

• The name of the logging company and log analyst and information on their 

qualifications; 

• Interpretation of the well logs by the log analyst, including any assumptions, 

determination of porosity, permeability, lithology, thickness, depth, and formation fluid 

salinity of relevant geologic formations; and

• Any changes in interpretation of site stratigraphy based on formation testing logs.

To support the UIC Program Director’s evaluation of the logging results, EPA recommends that 

the owner or operator demonstrate that the collected information is consistent with other 

available site characterization data in the permit application and that the data support other 

assessments of stratigraphy and formation properties. The owner or operator should demonstrate 

that the logs were adequately performed and properly characterize all formations, and that 

logging tests were conducted by a knowledgeable log analyst. The UIC Program Director may 

compare the results of formation testing logs from different wells in the vicinity to interpret local 

stratigraphy and verify the depths and properties of the proposed injection and confining zones. 

Where information gathered via the logs diverges from other data or supports different 

conclusions about the subsurface, the owner or operator should discuss in the report, and with the 
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Site Characterization Guidance

UIC Program Director, the implications for any of the planned operational procedures, the AoR 

determination, or the GS project plans. 

4.2. Core Analyses 

The Class VI Rule [40 CFR 146.87(b)] requires the owner or operator to take whole cores or 

sidewall cores of the injection and confining zones and formation fluid samples from the 

injection zone(s) and to submit to the UIC Program Director a detailed report prepared by a log 

analyst. 

Core samples provide information to support stratigraphic correlation, interpretation of 

depositional environments, and wireline log calibration. Information from cores will be used to 

refine site characterization data submitted pursuant to 40 CFR 146.82(a). Core samples may also 

have been taken prior to well construction if a stratigraphic well was drilled during initial site 

characterization. 

Data Collection and Analysis 

Core Sampling 

Decisions about the type of coring to perform will ultimately depend upon logistics and the type 

of lithology to be cored. Detailed information on the various coring methods is available in 

Whitebay (1992). Proper drilling methods should be practiced to maintain zonal isolation when 

penetrating the confining zone or any over- or under-pressured zones. 

Core samples must be taken from the injection and confining zones [40 CFR 146.87(b)]. Owners 

or operators may also consider analyzing samples from the first permeable formation overlying 

the confining zone or from other permeable formations and confining zones farther up in the 

stratigraphic column. The lower confining zone should be included if the owner or operator has 

been granted an injection depth waiver (see the UIC Program Class VI Well Injection Depth 

Waivers Guidance for additional information on the injection depth waiver application process). 

The optimal number of samples to analyze will vary by site, but representative samples should be 

chosen from cores and core sections with different lithologies and characteristics (e.g., texture, 

grain size). Heterogeneous formations would warrant more closely spaced core samples than 

uniform formations. For heterogeneous formations with many fractures or solution features, it 

may be preferable to examine the complete length of full-diameter core in the interval being 

tested. Owners or operators may have also used a geostatistical approach to model the 

distribution of permeability and porosity in the injection and confining zone(s); selection of core 

samples during drilling and construction of the Class VI well should be planned to further refine 

such estimates. 

Core Logging and Analysis 

Core logs should include descriptions or indications of: lithology, thickness, grain size, 

sedimentary structures, diagenetic features, contacts, textural maturity, oil staining, fracturing, 
UIC Program Class VI Well 69 

Site Characterization Guidance

and porosity. Laboratory analysis of cores should include petrology and mineralogy; 

petrophysical properties; and geomechanical properties (see Sections 2.3.4 through 2.3.6). 

Owners or operators may consider special core analysis (SCAL) to obtain an in-depth suite of 

tests for parameters relevant to GS, such as relative permeability, capillary pressure, fluid 

compatibility, wettability, and pore volume compressibility. 

Information to Submit

Owners or operators must submit to the UIC Program Director a report prepared by a log analyst

[40 CFR 146.87(b)]. Owners or operators should review the report prior to submission to ensure 

that it is complete and includes information on methods, notes on QA samples and calibration of 

instrumentation as appropriate, results in tabular and/or graphic form, and photographs as 

appropriate. Where information from the core analysis diverges from other data or supports 

different conclusions about the subsurface, the owner or operator should discuss in the report, 

and with the UIC Program Director, the implications for any of the planned operational 

procedures, the AoR determination, or the GS project plans. 

4.3. Characterization of Injection Formation Fluid Chemical and Physical 

Properties and Downhole Conditions 

The Class VI Rule requires the sampling and characterization of the chemical and physical 

properties of the formation fluids in the injection zone [40 CFR 146.82(a)(8) and 146.87(b)] as 

well as recording of the fluid temperature, pH, SC, reservoir pressure, and static fluid level [40 

CFR 146.87(c)]. Fluid sampling and recording of downhole pressure, temperature, SC, and pH 

provides information to support a determination of the compatibility of the injectate with the 

formation fluids [40 CFR 146.82(c)(3)]. 

Data Collection and Analysis 

Information on downhole pressure, temperature, pH, and SC can be obtained before completion 

using formation testing tools. Such tools may also record other parameters such as fluid density 

and fluid carbon dioxide. Alternatively, downhole conditions may be recorded after completion 

using wireline tools. 

Fluid sampling can be done before well completion using wireline sampling devices, or after 

well completion. If sampling is performed before completion, the well bore should be cleaned of 

drilling mud as much as possible before the sample is taken (Nagarajan et al., 2007). After well 

completion, samples can be collected downhole using devices such as a flow-through device (see 

the UIC Program Class VI Well Testing and Monitoring Guidance), or at the surface by pumping 

the fluids for collection. Analyses generally include major anions and cations, pH, temperature, 

pressure, alkalinity, TOC, and total inorganic carbon (see Section 2.3.9). 
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Information to Submit

To meet the requirements of 40 CFR 146.82(a)(8) and 146.87(b), the owner or operator should 

submit the following information to the UIC Program Director:

• Type of sampling equipment used and field procedures (e.g., sample preservation); 

• If the sample was pumped, flow rate, type of pump, and location of the pump, and 

geochemical modeling results indicating the likely geochemical makeup of the fluids at 

downhole conditions; 

• Data for field measurements (pH, SC, temperature, pressure); 

• Laboratory results, including QA samples (e.g., blanks, duplicates, matrix spikes); and

• Notes on any anomalous data. 

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator demonstrate that they used proper field techniques to obtain samples. Where 

information gathered via formation testing diverges from other data or supports different 

conclusions about the injection and confining zones, the owner or operator should discuss with 

the UIC Program Director, and in the report, the implications for any of the planned operational 

procedures, the AoR determination, or the GS project plans. 

4.4. Fracture Pressure of the Injection and Confining Zones 

Owners or operators must determine or calculate the fracture pressure of the injection and 

confining zones [40 CFR 146.87(d)(1)]. This information, in conjunction with predictions of 

pore pressures within the injection zone, is used to support the determination of an appropriate 

injection pressure to ensure that injection will not initiate or propagate fractures in the confining 

zone [40 CFR 146.83(a)(2)]. In addition, this information can be used to confirm or refine the 

preliminary site characterization information described in Section 2. Where the owner or 

operator has received an injection depth waiver, they should provide information on the fracture 

pressure of the lower confining zone(s) to support the determination of injection pressures that 

do not compromise confinement below the injection zone. 

In addition, owners or operators may be asked by the UIC Program Director to determine or 

calculate other physical and chemical characteristics of the injection and confining zone(s) [40 

CFR 146.87(d)(2)]. Any such request will be site-specific and would likely involve gathering 

data to augment other information gathered during the site characterization process, address any 

data anomalies or inconsistencies, support the development of the AoR delineation model, or 

support setting of permit conditions (e.g., operational limits). 

Data Collection and Analysis 

The step rate test is a common method for determining the fracture pressure of a formation (see 

the Appendix and USEPA, 1999 for additional detail). EPA recommends the use of downhole 

pressure gauges during the test. If a surface gauge is used, the reading needs to be corrected to 

obtain the downhole pressure and the correction factor will need to account for friction. For wells 

with depths greater than 3,000 feet, the uncertainty in the friction correction may introduce too 
UIC Program Class VI Well 71 

Site Characterization Guidance

much error to allow for an accurate reading (McAleese, 2000). EPA recommends using two 

pressure gauges to ensure that there is a backup if one gauge fails. Additionally, the flow meter 

should be calibrated prior to the test (USEPA, 1999). 

Information to Submit

For the UIC Program Director to appropriately evaluate the fracture pressure calculation, as 

required at 40 CFR 146.87(d)(1), EPA recommends that the owner or operator submit the 

following information: 

• Type and location of the pressure gauge; 

• Type of flow meter and calibration records; 

• Raw pressure and flow data; 

• Plot of flow rate versus pressure data; and

• Discussion of any anomalous data. 

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator demonstrate that proper test conditions were obtained and that the proposed operating 

pressure is appropriate based on the information gathered and the predicted (modeled) pore 

pressures throughout the injection zone. The owner or operator should also demonstrate that 

proper correction factors were used if the gauges were not deployed at the bottom of the well 

bore and that a constant injection rate was used at each step period. 

The owner or operator should also discuss how the calculated fracture pressure compares with 

data from core tests or other wells in the area. Where this information is not consistent with 

existing data or supports different conclusions about the subsurface formations, the owner or 

operator should discuss in the report, and with the UIC Program Director, the implications for 

any of the planned operational procedures (e.g., injection pressure). 

Data from the step rate test may also be helpful in designing well stimulation programs. Step rate 

tests can be carried out in conjunction with hydrogeologic testing described in Section 4.5 in 

order to determine other reservoir properties such as transmissibility.

4.5. Hydrogeologic Testing 

The Class VI Rule requires hydrogeologic testing of the injection well before injection 

operations begin. A pressure fall-off test and either a pump test or injectivity test [40 CFR 

146.87(e)(1)–(3)] must be performed. These tests are designed to verify information on the 

injectivity of the injection zone to support the setting of permit limits for carbon dioxide 

injection rates and volumes. Injectivity depends on parameters such as porosity, permeability, 

and connectivity. Many of these parameters will have been measured during the initial site 

characterization. Hydrogeologic testing can verify these parameters and can also help determine 

any local reduction in permeability near the well bore caused by the well construction process, 

often referred to as the skin factor. Hydrogeologic testing can also be used to determine if a 

stimulation program is necessary and aid in the design of such a program. Data from 
UIC Program Class VI Well 72 

Site Characterization Guidance

hydrogeologic testing may also be useful in verifying the computational model for AoR 

determination. 

4.5.1. Pressure Fall-Off Tests

Pressure fall-off tests are conducted on a well to verify several hydrogeologic parameters: the 

transmissibility of the injection zone, the static injection zone pressure, and the skin factor. 

Pressure fall-off tests can also indicate if there are faults and fractures near the well bore. 

Data Collection and Analysis 

EPA recommends the use of downhole gauges with surface displays for fall-off tests. The 

surface readout allows real time reading of the pressure and allows any anomalies to be noted 

and potentially corrected while the test is being conducted rather than during data analysis. Using 

two pressure gauges will provide a backup in case one fails and will provide two data sets which 

can be used to verify the accuracy of the test. 

The appropriate injection and shut-in periods are determined based on site-specific parameters 

and the desired area for which data will be gathered. It is important that the flow rate during 

injection is constant and that the test is conducted over a sufficient period of time so that the 

pressure effects seen are not caused by the well bore but reflect the reservoir conditions. If the 

pressure fall-off test is to be used to examine reservoir features such as faults, non-homogenous 

areas, or other wells, the time should be long enough to allow the pressure effects from those 

areas to be seen. EPA Region 6 has published a guidance entitled “The Nuts and Bolts of Falloff 

Testing” (USEPA, 2003) that provides guidance on determining the appropriate injection and 

fall-off times, along with many other technical details. 

Information to Submit

For the UIC Program Director to appropriately evaluate the fall-off test, EPA recommends that 

the owner or operator submit the following information: 

• Raw pressure data; 

• Flow data from the injection portion of the test; 

• Test parameters (injection time, shut-in time, fluid viscosity, temperature, well bore 

diameter, pressure gauge type and location); 

• Semi-log plots used for data analysis; 

• Parameters calculated from the analysis; and

• Discussion of the results, including data quality and any anomalous values. 

If the fall-off test data were used to verify computational model results, the owner or operator 

may also want to reference those results. 

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator provide sufficient information to demonstrate the validity and results of the test. For 
UIC Program Class VI Well 73 

Site Characterization Guidance

example, the owner or operator should demonstrate that pressure gauge data accurately capture 

the full range of test data and that the gauge was either properly placed to measure downhole 

pressure or appropriate corrections were made to calculate downhole pressure. The owner or 

operator should also demonstrate that a steady rate was held before the shut-in portion of the test 

was begun and that the time frame of the test was sufficiently long. The owner or operator should 

demonstrate that the semi-log plots were linear and explain any non-linearities against other data 

submitted for the site characterization. 

EPA recommends that any interpretation of anomalies be corroborated with other data. For 

example, if an anomaly is proposed to have been caused by a fault, then the owner or operator 

should review and provide information from geologic maps and seismic data to determine if 

faults are documented in the area indicated by the pressure transient analysis. 

Finally, the owner or operator should demonstrate that the results of the analysis are consistent 

with other site data. For example, transmissivity values calculated from the fall-off test may be 

compared to permeability values determined from cores. Where the information diverges from 

other data or supports different conclusions about the subsurface, the owner or operator should 

discuss the implications for any of the planned operational procedures, the AoR determination, 

or the GS project plans. 

4.5.2. Injectivity and Pump Tests

Injectivity and pump tests are used in a manner similar to pressure fall-off tests to determine the 

transmissibility of the reservoir, the skin factor, and to identify nearby faults or fractures. The 

tests are subject to less interference from the well bore than pressure fall-off tests, but they are 

subject to more noise in the pressure data from the flowing fluid. Obtaining data from both a falloff test and an injectivity or pump test allows verification of data, because, in some cases, more 

than one factor can yield similar pressure response curves. 

Data Collection and Analysis 

Injectivity testing involves pumping carbon dioxide into the well at a constant rate and recording 

the pressure response in the well. A pump test is similar to an injectivity test, but fluid is pumped 

from the well instead of injected. Either test can be used to fulfill the requirement at 40 CFR 

146.87(e), and they should yield the same results. Injectivity tests are more commonly used in 

injection well applications. As with fall-off tests, placing the pressure gauge downhole reduces 

inaccuracies that are caused by friction loss in the well bore. Generally, with wells over 3,000 

feet deep, downhole pressure gauges should be used (McAleese, 2000). Dual pressure gauges are 

also recommended to ensure that a backup gauge is available. 

The rate of injection on an injectivity test should be low enough that the fracture pressure of the 

formation is not exceeded. The injection rate should be held constant long enough that radial 

flow is established and there are no near-well bore pressure effects. Variable flow rates or too 

short of an injection period may lead to poor test results. 
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Several variations on injectivity testing may be performed. A multi-rate injection test uses two or 

more injection rates to produce more data for a more complete analysis. Each injection rate is 

held long enough to obtain radial flow. In interference tests, fluid is injected into one well and 

the pressure is measured at another well. The interference test can yield information on the 

porosity and compressibility of the formation between the two wells. If planned properly, a 

pressure fall-off test can also be conducted following an injectivity test. 

Pressure data from each of these tests are analyzed in the same way, using the same types of 

plots as those used for pressure fall-off tests. If the semi-log plots are not linear, this is likely due 

to errors in the assumptions underlying plot construction. Such errors could include non-constant 

injection rates, non-homogenous reservoir properties, interfering wells, or faults. 

Information to Submit

Data submitted for injectivity or pump tests would be similar to data for a pressure fall-off test 

and should include: 

• Raw pressure data; 

• Flow data including rates and times; 

• Test parameters (injection time, fluid viscosity, temperature, well bore diameter, pressure 

gauge type and location); 

• Semi-log plots used for data analysis; 

• Parameters calculated from the analysis; and

• A discussion of the results, including data quality and any anomalous values. 

To support the UIC Program Director’s evaluation of the data, EPA recommends that the owner 

or operator demonstrate that the test results are valid and verified, and that the data are consistent 

with other collected data. For example, the owner or operator should demonstrate that pressure 

gauge data accurately capture the entire range of injection pressures used. The owner or operator 

should also demonstrate that gauges were properly located to provide accurate bottomhole 

readings and/or that surface pressure readings were properly corrected to obtain bottomhole 

pressure. 

The owner or operator should demonstrate that flow data and flow meters were calibrated and 

that a constant flow rate was maintained. The owner or operator should show that semi-log plots 

are linear and explain any anomalies, comparing data as necessary to other information collected 

during site characterization to aid in interpretation. Any deviations from linear behavior should 

be analyzed and a cause determined and documented. Because an anomaly may be caused by 

more than one type of phenomenon, any interpretations of anomalies should be verified using 

independent data. Where information from injectivity or pump tests diverges from other data or 

supports different conclusions about the subsurface, the owner or operator should discuss the 

implications for any of the planned operational procedures, the AoR determination, or the GS 

project plans. If the injectivity or pump test data were used to verify computational model 

results, the owner or operator may also want to reference those results. 
UIC Program Class VI Well 75 

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5. References 

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Woods (Eds.), AAPG Methods in Exploration Series, No. 10, Development Geology 

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Asghari, K., A. Al-Dliwe, and N. Mihinpey. 2006. Effect of operational parameters on carbon 

dioxide storage capacity in a heterogeneous oil reservoir: A case study. Industrial & 

Engineering Chemistry Research 45: 2452-2456. 

Asquith, G.B., and D. Krygowski. 2004. Basic Well Logging Analysis (2nd ed.). AAPG: Tulsa, 

OK.

ASTM International (ASTM). 2006. Standard Guide for Soil Gas Monitoring in the Vadose 

Zone. ASTM D5314 - 92(2006). DOI: 10.1520/D5314-92R06. http://www.astm.org. 

ASTM. 2008. Standard Test Method for Determination of In-Situ Stress in Rock Using 

Hydraulic Fracturing Method. ASTM D4645 - 08. DOI: 10.1520/D4645-08. 

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Journal of Greenhouse Gas Control 1: 430-443. 

Bachu, S. 2008. Comparison between Methodologies Recommended for Estimation of CO2

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Balan, B., S. Mahaghegh, and S. Ameri. 1995. State-of-the-art in permeability determination 

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Gaus, I. 2010. Role and impact of CO2-rock interactions during CO2 storage in sedimentary 

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Appendix: Available Technologies and Methods for Conducting 

Required Site Characterization Activities
UIC Program Class VI Well A-i 

Site Characterization Guidance 

Table of Contents

Appendix: Table of Contents ....................................................................................................... A-i

Appendix: List of Figures ........................................................................................................... A-ii

Appendix: List of Tables ........................................................................................................... A-iv

Introduction to the Appendix ...................................................................................................... A-v

A1. Information to Support Development of Maps and Cross Sections of the Area of 

Review, Determination of Formation Thickness, Illustration of Structural Geology, and 

Facies Analysis ........................................................................................................................... A-1

A2. Information to Support Petrologic and Mineralogic Analyses ............................................ A-6

A3. Information to Support Submittal of Data on Porosity, Permeability, and Capillary 

Pressure of the Injection and Confining Zones ......................................................................... A-10

A4. Information to Support Geomechanical Characterization of the Confining Zone ............. A-21

A5. Information to Support Fault Stability Analysis and Analysis of Confining Zone 

Integrity ..................................................................................................................................... A-28

A6. Information to Support Geophysical Characterization ...................................................... A-35

A7. Information to Support Demonstration of Storage Capacity ............................................. A-50

A8. Information to Support Pre-Injection Logging and Testing ............................................... A-68
UIC Program Class VI Well A-ii 

Site Characterization Guidance 

List of Figures

Figure A-1: Interpreted Cross Section ........................................................................................ A-2

Figure A-2: Structural Cross Section of the Soan Syncline, Kohat-Potwar Geologic 

Province, Upper Indus Basin, Pakistan ........................................................................... A-3

Figure A-3: Dip Model of a Tilted Plunging Anticline as it would Appear on an Arrow Plot 

of Dipmeter ..................................................................................................................... A-4

Figure A-4: Sandstone Cemented with Calcium Carbonate, Viewed under Crossed 

Polarizers......................................................................................................................... A-7

Figure A-5: Limestone With Fossil Fragments, Viewed under Crossed Polarizers ................... A-7

Figure A-6: Grains of Sand in a Shale Matrix, Viewed under Crossed Polarizers ..................... A-7

Figure A-7: Schematic Illustration of an Extended Leak-off Test and Associated Terms ....... A-23

Figure A-8: Schematic Cross Section through Borehole .......................................................... A-24

Figure A-9: Image Logs of a Well with Well Bore Breakouts ................................................. A-25

Figure A-10: Example Plot of Data Used for Estimating Frictional Limits (Petrel SubBasin, Australia) ........................................................................................................... A-26

Figure A-11: Example of a Regional Stress Map based on the Orientation of Well Bore 

Breakouts in Paleozoic Rocks the Western Canada Sedimentary Basin near 

Calgary .......................................................................................................................... A-27

Figure A-12: Example Failure Plot Indicating Scenarios where Fault Reactivation is 

Possible ......................................................................................................................... A-28

Figure A-13: Example Fault Slip Tendency Image .................................................................. A-29

Figure A-14: Example Mohr Diagram ...................................................................................... A-30

Figure A-15: An Isometric View of a Fault Plane .................................................................... A-31

Figure A-16: Simplified Shale Smearing Along a Fault ........................................................... A-32

Figure A-17: Sealing Capacity from Seismic Pore Pressure Images ........................................ A-33

Figure A-18: A Gravity Map of an Area Ore Deposit and Mine .............................................. A-42

Figure A-19: A Subsurface Cross Section of Electromagnetic Resistivity Data ...................... A-44

Figure A-20: Permanently Installed ERT Array at the CO2SINK Pilot Site at Ketzin ............ A-46

Figure A-21: An Aerial Gravity Map ....................................................................................... A-48

Figure A-22: Variation in Size and Resolution of Various Storage Capacities ........................ A-51

Figure A-23: Vertical Interference or Pulse Test ...................................................................... A-54

Figure A-24: A Diagram Demonstrating Wetting Angle ......................................................... A-56

Figure A-25: Capillary Pressure (Drainage and Imbibitions) as a Function of Wetting Phase 

Saturation ...................................................................................................................... A-56
UIC Program Class VI Well A-iii 

Site Characterization Guidance 

Figure A-26: Density of Carbon Dioxide as a Function of Depth ............................................ A-58

Figure A-27: A Schematic of the Skin Effect ........................................................................... A-61

Figure A-28: Example of Geophysical Well Logs ................................................................... A-69

Figure A-29: Example Porosity Log, Including Density (Red) and Neutron (Blue) Logs, for 

the Cincinnati Arch Validation Test Well .................................................................... A-72

Figure A-30: Example of Borehole Video Imaging Log Showing Formation Fractures ......... A-74
UIC Program Class VI Well A-iv 

Site Characterization Guidance 

List of Tables

Table A-1: Typical Permeability for Various Lithologies ........................................................ A-13

Table A-2: Parameters and Data Needed to Define the Stress Tensor and the Geomechanical 

Model ............................................................................................................................ A-21

Table A-3: Parameters and Methods for Quantifying Storage Capacity .................................. A-52

Table A-4: Interpreting Borehole Condition from Caliper Readings ....................................... A-70
UIC Program Class VI Well A-v 

Site Characterization Guidance 

Introduction 

This Appendix provides background information on some of the activities that will be performed 

as part of site characterization for a GS project that meets the requirements of 40 CFR 146.82 

and 40 CFR 146.87. The UIC Program Class VI Well Site Characterization Guidance assumes 

that owners or operators are familiar with many of the available techniques used in assessing 

proposed GS sites, and it focuses on how these techniques should be applied to meeting the Class 

VI Rule requirements. This Appendix presents additional information, including examples of the 

application of various techniques in GS or other scenarios, on certain activities that reviewers of 

the draft guidance suggested was too detailed for the guidance document. It also refers the reader 

to additional sources of published information that are publically available. 

This Appendix includes the following sections: 

• A1, Information to Support Development of Maps and Cross Sections of the Area of 

Review, Determination of Formation Thickness, Illustration of Structural Geology, 

and Facies Analysis, which augments Sections 2.3.1 and 2.3.3 of the guidance; 

• A2, Information to Support Petrologic and Mineralogic Analysis, which supports 

Section 2.3.4 of the guidance; 

• A3, Information to Support Submittal of Data on Porosity, Permeability, and 

Capillary Pressure of the Injection and Confining Zones, which supplements the 

information in Section 2.3.5 of the guidance; 

• A4, Information to Support Geomechanical Characterization of the Confining Zone, 

which supports Section 2.3.6 of the guidance; 

• A5, Information to Support Fault Stability Analysis and Analysis of Confining Zone 

Integrity, which provides additional information related to Sections 2.3.2 and 3.5 of 

the guidance;

• A6, Information to Support Geophysical Characterization, which provides additional 

information related to Section 2.3.10 of the guidance; 

• A7, Information to Support Demonstration of Storage Capacity, which supplements 

Section 3.4 of the guidance; and 

• A8, Information to Support Pre-Injection Logging and Testing, which relates to the 

information in Section 4.1 of the guidance. 
UIC Program Class VI Well A-1 

Site Characterization Guidance

A1. Information to Support Development of Maps and Cross Sections of the 

Area of Review, Determination of Formation Thickness, Illustration of 

Structural Geology, and Facies Analysis

To support owners or operators as they compile and/or prepare maps and cross sections of the 

AoR, as required by the Class VI Rule at 40 CFR 146.82(a)(3)(i), the sections below provide 

background information on stratigraphic cross sections, structural cross sections, and dipmeter 

logs. This information also supports determination of formation thickness [40 CFR 

146.82(a)(3)(iii)] and local structural geology [40 CFR 146.82(a)(3)(vi)]. Information is also 

provided on facies analysis; a description of facies changes is required at 40 CFR 

146.82(a)(3)(iii), and owners or operators may elect to do a more thorough facies analysis to help 

in developing the site conceptual model. For additional information and recommendations 

regarding this information, please see Sections 2.3.1 and 3.1 of the guidance. 

Stratigraphic Cross Sections 

Stratigraphic cross sections show characteristics of correlatable stratigraphic units relative to a 

chosen geologic layer, or datum. Cross sections can rely on and incorporate data from a variety 

of sources, including logs, seismic data, cores, and cuttings. Figure A-1 shows an example of a 

schematic stratigraphic cross section that also displays log data.

The choice of a datum (the level or reference horizon) is a key part of developing a stratigraphic 

cross section. By displaying geologic units relative to the datum, the stratigraphic cross section 

may illustrate geologic relationships as they existed at a previous time (i.e., prior to 

deformation). In many cases, an unconformity (such as a buried erosion surface) is used as a 

datum because unconformities often represent relatively uniform time horizons (Boak, 1992). 

Stratigraphic cross sections may be produced with various orientations relative to structural 

features. Sections oriented perpendicular to the depositional strike show facies changes toward or 

away from the basin margin, while sections oriented parallel to the depositional strike show 

lateral variations of particular units or sequences (Boak, 1992; Evenick, 2008). Another common 

orientation is perpendicular to a fold axis or major fault (Groshong, 2006). Furthermore, while 

cross sections are normally presented perpendicular to the ground surface, only cross sections 

oriented perpendicular to the dip of the units will show the true bedding thickness (Groshong, 

2006). 

Cross sections can be checked for accuracy by restoring deformed strata to an original, 

undeformed state, where there are no gaps or overlaps between sedimentary layers. This 

technique may not be possible for complexly deformed areas and requires simplifying 

assumptions (such as consistent thickness) about the original depositional characteristics of the 

layers. In addition, this technique is not applicable to non-homogenous strata such as salt domes 

and reefs (Evenick, 2008). 

Cross sections can be anchored or projected (Evenick, 2008). Anchored cross sections have 

direct well control; they are either pinned (have at least one well directly on the surface trace of 
UIC Program Class VI Well A-2 

Site Characterization Guidance

the cross section) or tied (the trace follows a line from well to well). While tied cross sections 

have the advantage of direct data, they often enhance out-of-plane features and distort the 

thickness and other properties of subsurface layers (Evenick, 2008). 

Projected cross sections have no direct well control. Projected cross sections may be bounded or 

synthetic. Bounded cross sections have data projected from nearby wells, and synthetic sections 

are not based on direct data. Projection of data onto the trace should be done carefully to avoid 

introducing error. Common methods include along dip, with structural contours, and within dip 

domains (groups of dips). See Groshong (2006) for more information on projected cross 

sections.

Figure A-1: Interpreted Cross Section.

Constructed from well log data. Distance scale is irregular to make the cross section more compact. Gamma ray logs 

are displayed to the left of the well, and conductivity is displayed to the right. From: Kirschbaum and Hettinger 

(2004).
UIC Program Class VI Well A-3 

Site Characterization Guidance

Structural Cross Sections 

Structural cross sections illustrate the subsurface relationships and structural features of rock 

units. Cross sections are generally most useful when oriented perpendicular to major structural 

trends, although bends in the section can be used to show variable structural trends or other 

features (Boak, 1992). Additional smaller cross sections can be included to illustrate specific 

features such as faults. Structural cross sections may reference attached stratigraphic cross 

sections if correlations are difficult. Figure A-2 shows an example of a structural cross section.

Stratigraphic and structural cross sections are developed using similar methods. For a structural 

cross section, the datum is generally sea level, and units are drawn above or below that elevation 

according to their present positions (Boak, 1992). Unlike stratigraphic cross sections, structural 

cross sections are generally drawn with little or no vertical exaggeration; this allows the cross 

section to accurately represent the relative positions of the layers. 

Figure A-2: Structural Cross Section of the Soan Syncline, Kohat-Potwar Geologic Province, Upper 

Indus Basin, Pakistan.

From: Wandrey et al. (2004).

Dipmeter Logs

 

Dipmeters are designed to measure the dip of the stratum and the dip direction of layered rock 

surfaces that intersect the well. To generate a dipmeter reading, microresistivity sensors are 

mounted on a caliper logging tool. A minimum of three calipers is needed, but most modern 

dipmeters have six or more sensors to provide redundancy in case of failure, as well as to 

improve results (Johnson and Pile, 2006). The dip is calculated based on depth, the positions of 

the sensors, and the diameter of the well. If two or more sensors are present on the same caliper, 

small-scale features such as cross-bedding and directional sand transport can sometimes be 

identified (Johnson and Pile, 2006). Dipmeter logs can also be used to identify structural features 

such as faults and folds when compared to standard dip models such as the one shown in Figure 

A-3. 
UIC Program Class VI Well A-4 

Site Characterization Guidance

Figure A-3: Dip Model of a Tilted Plunging Anticline as it would Appear on an Arrow Plot of Dipmeter. 

From: Goetz, 1992; © American Association of Petroleum Geologists (AAPG) 1992, reprinted by permission of 

AAPG whose permission is required for further use.

Facies Analysis 

Facies analysis can inform conclusions about whether to expect good lateral connectivity within 

the formation and whether there are barriers to vertical connectivity. Ambrose et al. (2008) have 

discussed the importance of facies changes to GS projects. Beach and barrier island deposits, for 

example, tend to be homogeneous and continuous. Fluvial facies produce heterogeneity in the 

reservoir because the fluvial channels are associated with fine-grained floodplain deposits; this 

heterogeneity may produce more limited, poorly connected areas for carbon dioxide storage. In 

some settings (e.g., the GS project at Sleipner), mudstone layers serve as permeability barriers, 

forming baffles that limit the buildup of buoyant pressure in the injection formation (Chadwick 

et al., 2008). 

Variable porosity/permeability distributions are related to grain sizes, facies changes, and 

variability in cementation (Norden et al., 2010), and a good facies model will be valuable for 

understanding these variations. However, some fine-grained deposits may also have high 

porosity and permeability. These grain size and facies variations cannot be used exclusively as 

an indicator of permeability. Furthermore, diagenetic (post-deposition) processes also govern the 

characteristics of formations, especially carbonates. Like descriptions of clastic systems, 

descriptions of carbonate facies are based on observations of rock fabrics and pore spaces from 

core and cutting samples. These descriptions are correlated with wireline log responses and other 

information to map porosity, saturation, and permeability (Lucia, 1992). Because the 
UIC Program Class VI Well A-5

Site Characterization Guidance

characteristics of carbonates are often strongly (and sometimes completely) determined by the 

sediments’ interactions with formation fluids, understanding current and past hydrogeology is 

also important in the analysis of carbonate facies. 

A sequence stratigraphic approach focuses on surfaces (unconformities) that divide the 

sediments into chronostratigraphic units and allows strata to be correlated and then extrapolated 

to areas where data are lacking. Sequence stratigraphy is well established and is widely used in 

the oil and gas industry to characterize reservoirs and may be a useful approach for a GS project; 

it has already been used in the characterization of facies in some GS projects (e.g., Gibson-Poole 

et al., 2005). Additional information is available in the following sources: Lang et al. (2001); 

Van Wagoner et al. (1990); Posamentier and Allen (1999). 
UIC Program Class VI Well A-6

Site Characterization Guidance

A2. Information to Support Petrologic and Mineralogic Analyses

The Class VI Rule requires the owner or operator of a proposed Class VI injection well to submit

data on the mineralogy of the injection and confining zone(s) [40 CFR 146.82(a)(3)(iii)]. This 

section provides background information on conducting petrologic and mineralogic analyses to 

support meeting this requirement, including analysis by polarized light microscopy, scanning 

electron microscopy, and XRD. For additional information and recommendations, see Section 

2.3.4 of the guidance (Petrology and Mineralogy of the Injection and Confining Zones).

Examples of Mineralogic and Petrologic Features Relevant to GS

The most common lithologic types in oil and gas reservoirs and deep saline formations are 

sandstone, limestone, and dolomite. The major minerals in sandstones include quartz and 

feldspar, with calcite (often as cement) and clay fines common as lesser components. Limestones 

and dolomites consist primarily of carbonate minerals (calcite, aragonite, dolomite). “Impure” 

limestones may have minor quartz grains, pyritic limestone contains pyrite, and argillaceous 

limestones contain clay components (Williams et al., 1982). Figures A-4 and A-5 show examples 

of thin sections of a sandstone and a fossiliferous limestone. 

Shales and mudstones (clay-silt mixtures) will be common in the confining zones of GS projects. 

These lithologies consist of clay minerals and small particles of quartz, feldspar, and mica. 

Individual particles may be difficult to see by optical microscopy (Figure A-6), and, aside from 

general confirmation of the lithology and texture, limited information can be gained. If detailed 

information is desired, a scanning electron microscope (SEM) may be considered. 

Some of the textural features that might be observed in thin sections and under SEM include 

cementation (secondary minerals providing cohesion to the rock), dissolution features (indicative 

of removal of minerals), pore size and shape, and the presence of fine clay minerals. For 

example, in Figure A-5, the carbonate cement can be seen infilling voids within the fossils and in 

between the fossil fragments. The extent of these features is integral to understanding porosity 

and permeability and for anticipating changes that may take place as a result of interactions 

between the injectate, native fluids, and formation solids. 

The composition, grain size, grain shape, and sorting seen under a microscope can all be used to 

infer the depositional environment. This facies analysis can help in locating changes in physical 

parameters. For example, if grain size is seen to decrease upwards, a corresponding decrease in 

permeability may be seen. Such observations are considered a routine part of the determination 

of reservoir quality in the oil and gas field (e.g., Grier and Marschall, 1992) and would be 

valuable as part of storage formation characterization. A detailed discussion of the genesis, 

composition, and textures of rocks is also provided in Williams et al. (1982).
UIC Program Class VI Well A-7 

Site Characterization Guidance

Figure A-4: Sandstone Cemented with Calcium Carbonate, Viewed under Crossed Polarizers. 

Field of view is 3.5mm. The white and gray shapes are individual grains of sand, the tan in-between the sand grains 

is pore space filled with calcite cement. From: Univ. of Oxford (2010); © David Waters and the Department of 

Earth Sciences, University of Oxford, reproduced with permission.

Figure A-5: Limestone With Fossil Fragments, Viewed under Crossed Polarizers.

Field of view is 3.5mm. The angular tan and blue shapes are calcite crystals filling in pore space. From: Univ. of 

Oxford (2010); © David Waters and the Department of Earth Sciences, University of Oxford, reproduced with 

permission.

Figure A-6: Grains of Sand in a Shale Matrix, Viewed under Crossed Polarizers.

Field of view is 2mm tall. Quartz sand grains are gray and white. From: Schieber (2006); © Juergen Schieber, 

reproduced with permission.
UIC Program Class VI Well A-8 

Site Characterization Guidance

Analysis by Polarized Light Microscopy 

The petrographic microscope is a fundamental tool for identifying and characterizing rock and 

mineral samples. Samples are prepared by mounting chips of the rock onto glass slides, cutting 

and grinding down to a thickness of 30 microns, and polishing. Poorly consolidated samples are 

often impregnated with epoxy prior to cutting them into chips. 

A petrographic microscope is a transmitted light microscope designed for the examination of 

rock thin sections. It includes a rotating stage and polarizers both above and below the stage; the 

specimen is examined both with the upper polarizer in place (“crossed polarizers” or “crossed 

nicols”) and with it removed (“plane polarized light”). When the upper polarizer is inserted, the 

vibration directions of the two polarizers are perpendicular. This arrangement takes advantage of 

the optical properties of minerals; those that are not isotropic have more than one index of 

refraction, and light passing through is split into separate rays with different velocities. Under 

crossed polarizers, the difference in the velocities produces interference colors, which helps with 

mineral identification when taken together with cleavage, shape, and other characteristics. 

Petrographic microscopes have remained relatively unchanged in principle since their 

development in the late 1800s. Edwards (1916) and Kerr (1959) are examples of classic texts that 

are still available on the optical properties of minerals, descriptions of the petrographic 

microscope, and mineral identification using the microscope. Basic descriptions of petrographic 

microscopes are commonly available on the Internet. 

Careful petrographic analysis can provide information about the minerals present, the 

relationships among them (e.g., overgrowths), textures, grain size, and weathering (e.g., rounded 

grains in a clastic sediment). Williams et al. (1982) provide details on the mineralogy and 

textures to be expected in different rock types and how they relate to rock formation. 

Scanning Electron Microscopy 

SEM uses a beam of electrons instead of visible light, permitting much higher resolution and 

magnification than a petrographic microscope. The term “scanning” refers to the raster pattern 

used in moving the electron beam over the sample surface (similar to a television). The same thin 

sections prepared for light microscopy can be used in a scanning electron microscope. Also, 

unconsolidated samples can be prepared for analysis by mounting them onto a glass slide using 

adhesive.

The most common use of an SEM is for secondary electron imaging (SEI). In this mode, it 

produces a high resolution image of the sample surface with good depth of field. This function 

can image grain morphology and other features in loose samples affixed to a slide, but it is not 

appropriate for thin sections because they are polished flat. The oil and gas industry uses SEM in 

this capacity for assessment of reservoir quality (Grier and Marschall, 1992). 

With thin sections, an SEM can be used in backscattered electron (BSE) mode. The signal from 

backscattered electrons depends on the atomic weight of the material being examined. Minerals 

are seen with different levels of brightness, with higher density minerals appearing brighter. This 
UIC Program Class VI Well A-9

Site Characterization Guidance

can be helpful for distinguishing minerals that appear similar under light microscopy. The same 

types of textural relationships would be seen as with a petrographic microscope, but very fine 

grains such as clay minerals and other clay-sized particles can be identified, as can mineral 

coatings and cements. Also, an elemental analysis of the minerals can be obtained if the SEM is 

equipped for energy-dispersive X-ray spectroscopy or wavelength-dispersive X-ray 

spectroscopy. Such analyses are point measurements, allowing analysis of specific sections of a 

mineral grain or of cements and grain coatings. Energy-dispersive spectra can be quickly viewed 

during examination as a qualitative aid in mineral identification in addition to being used for 

quantitative analysis. 

Images taken in BSE mode can be used in petrographic image analysis to calculate estimates of 

porosity, permeability, and capillary pressure based on 2D measurements (Welton, 2004). 

X-ray Diffraction

XRD may be useful for verification of mineralogy or identification of clay minerals. XRD helps 

to identify minerals based on structure rather than chemistry. The most common method for 

geologic samples is powder XRD, in which a slurry of the ground specimen is allowed to dry on 

a glass slide, which is then placed in the diffractometer. The sample is exposed to a beam of Xrays, which are diffracted by the various planes within the structure of the mineral. The angle of 

refraction for each plane is determined by Bragg’s Law. During the analysis, a detector is moved 

through a range of angles relative to the sample and registers the angles at which X-rays are 

detected. The resulting pattern of X-ray peaks is used to identify the mineral. If multiple minerals 

are present, the patterns will be superimposed upon each other, and a qualitative estimate of the 

relative quantities of the minerals may be possible. XRD may be especially useful for identifying 

clay minerals, which are too fine to fully characterize by polarized light microscopy. Moore and 

Reynolds (1989) provide a thorough coverage of the theory and practice of XRD, with a focus on 

its application to clay minerals.

Use of Mineralogic and Petrologic Information 

Data on the characteristics of the solids in the injection and confining zone(s) can also support an 

evaluation of the potential for geochemical reactions between the carbon dioxide, brine, and 

minerals that may cause changes in geomechanical and operational parameters or result in 

mobilization of contaminants. Lowered pH in the near-well bore region would promote 

dissolution of any carbonate minerals and cements in the injection formation, and precipitation of 

carbonates may occur in the more distal regions where pH is higher. Such reactions may affect 

porosity, permeability, and injectivity (Cailly et al., 2005). The kinetics of the dissolution and 

precipitation of silicates in clastics are slower (Palandri and Kharaka, 2004); certain lithologies 

such as clean sandstones will be less reactive in a carbon dioxide-rich system. Certain reactive 

clays and mafic silicates, however, may provide cations for precipitation of authigenic 

carbonates. Relatively rapid formation of carbonates would be expected in basalts (McGrail et 

al., 2006). Sulfide minerals and iron oxides may be dissolved and can liberate metals. Thus, an 

accurate assessment of mineralogy is important for predictions of long-term effects of injection 

on the properties of the injection formation. 
UIC Program Class VI Well A-10

Site Characterization Guidance

A3. Information to Support Submittal of Data on Porosity, Permeability, and 

Capillary Pressure of the Injection and Confining Zones

Owners or operators must submit data on porosity, permeability, and capillary pressure of the 

injection and confining zones, per 40 CFR 146.82(a)(3)(iii). This section provides background 

information to support meeting this requirement. For recommendations on meeting this 

requirement, see Section 2.3.5 of the guidance on Porosity, Permeability, and Capillary Pressure 

of the Injection and Confining Zones. Additional information on capillary pressure is also 

provided in Section A8 of this Appendix. 

Porosity

Factors Affecting Measured Porosity

Porosity is controlled by many variables. In sedimentary rocks, porosity is a function of the 

packing, sorting, grain size, and grain shape of the individual particles as well as in situ stress 

(Cone and Kersey, 1992). Pore space can occur as space between grains, as micro-scale pores 

along grain surfaces or other boundaries (when spaces are less than 2 μm), or along fractures. It 

can also be controlled by dissolution features (typically in carbonates). In clastic rocks, 

intergranular pore space is generally the most significant, especially in loosely packed, medium 

to large grain well-sorted lithologies such as clean sandstones. Fractures are usually the most 

important contributors to porosity in non-sedimentary rocks although there are exceptions, e.g., 

vuggy basalts can have porosities up to 12% (Fetter, 1988). Clastic rocks on average have the 

highest porosity of any rock type, with sandstones having up to 40% pore space (Cone and 

Kersey, 1992). The porosity of carbonates varies widely but is usually between 5 and 25% (Cone 

and Kersey, 1992).

Shales, which generally are potential sealing formations, usually have higher porosity than 

sandstones upon deposition (up to 80%) but experience rapid decreases in porosity with burial 

compaction and additional diagenesis (Avseth et al., 2010). The mean porosity for over 100 

samples of Devonian-age shale was 3.6–4.1%, with extremes of 1.2–7.6% when measured using 

helium gas resaturation (Davies et al., 1990). However, the study also noted difficulties in 

measuring shale porosity because low values may be near the resolving limit of some techniques 

and small pore size (averaging 0.05 μm in some shales (Soeder, 1988)) can complicate some 

techniques.

The method of sample collection can influence the measured porosity. For lithologies with 

greater than 30% porosity, samples collected with sidewall cores tend to yield porosity 

measurements that are below actual values by a few percentage points because of compaction 

during coring (Almon, 1992). Damage to samples collected with percussion methods can further 

distort results. For low porosity units, measured porosities can be over-represented because 

porosity is enhanced by damage that occurs during coring, while for high porosity formations, 

compaction and grain shattering can reduce measured porosity (Almon, 1992).
UIC Program Class VI Well A-11 

Site Characterization Guidance

Igneous and metamorphic rocks usually have low porosities. However, some volcanic tuffs are 

very porous and pumice can have up to 87% absolute porosity (Fetter, 1988). Weathering can 

also greatly increase porosity of these lithologies; weathered ultramafic and plutonic rocks can 

have porosities up to 60% due to the breakdown of minerals such as mica (Fetter, 1988). 

Porosity Measurement

Field Methods 

In the field, neutron logs, density logs, and sonic logs are well-suited to help estimate porosity 

(Aguilera, 1992). Neutron logs can be used in cased or uncased wells. With this method, a 

neutron-emitting probe is lowered into a well, and neutrons are captured by the hydrogen atoms 

in trapped pore water, gas, and hydrocarbons and are re-emitted as gamma rays. The probe logs 

the total amount of gamma radiation and estimates the pore fluid volume. One downside to this 

method is that water bound to clays can over-represent porosity in shales, siltstones, and other 

clay-rich units. As a result, a neutron log is collected and processed with other logs such as 

density logs or gamma ray logs to ensure accuracy. Porosity values collected from neutron logs 

are also absolute porosity; space in isolated, disconnected vugs that is not available for fluid 

storage is captured in the measurement. Another potential problem is that the neutron log cannot 

be used to determine the type of pore fluid present, which may be an important consideration 

when determining total storage capacity and injectivity.

 

Density log data are collected using a sonde equipped with a source of gamma radiation and at 

least one gamma ray detector deployed in a well. As it enters the formation, the radiation is 

scattered according to bulk density. Porosity can be calculated from density log data if the 

lithology of the subsurface and the saturating fluid are known: 

where ρmatrix is estimated based on the lithology (e.g. sandstone = 2.65 g/cm3

, limestone = 2.71 

g/cm3

, and dolomite = 2.87 g/cm3, etc.), ρbulk is from the density log, and ρfluid is estimated based 

on the salinity and hydrocarbon makeup of the saturating fluid (e.g. water = 1 g/cm3

, etc.) 

(Alberty, 1992a; Dewan, 1983). 

 

Sonic logs measure the speed of sound in a formation. As a sonic probe is pulled up a well, it 

emits a sound wave and logs the time any reflected sonic waves arrive back at the receiver. If the 

lithology of the layer is known, the porosity can be deduced from deviation from the theoretical 

sonic travel time for a layer of the same lithology with zero porosity. The Wyllie time average 

method or the Raymer-Hunt-Gardner methods are two common methods used with sonic logs. 

Sonic logs work best when the pore fluid is water or brine. Additional descriptions of these logs 

are provided in Section A7. 
UIC Program Class VI Well A-12

Site Characterization Guidance

Laboratory Methods

Several laboratory methods are available to determine porosity. These methods provide values 

for effective porosity. However, there is no good laboratory method for determining absolute 

porosity. Because porosity is stress dependent, laboratory measurements should be taken at stress 

conditions similar to in situ conditions (Cone and Kersey, 1992). Furthermore, core samples 

represent point measurements. For reliable results, measurements are best made on a number of 

cores, and the applicant might consider submitting a statistical representation of measurements 

such as a variogram.

If an unaltered, fresh sample of the formation of interest is available, the summation method can 

be used. Gas, oil, water, and any other fluids are extracted from the rock using a vacuum or other 

method. The sum of extracted fluids is assumed to equal the sum of the pore space. This method 

is potentially problematic, however, because the sample is not cleaned and because core samples 

are often subject to damage (e.g., mud intrusion, etc.) during retrieval, which can displace pore 

fluids.

With a less pristine sample, a resaturation method can be used. First, the sample is cleaned and 

dried, which allows for the remediation of some damage incurred during drilling. Hydrocarbons 

are generally removed from samples using toluene. The sample is then heated until it maintains a

constant weight. One potential problem with this method is that if brines are present, 

precipitation of salts can reduce the porosity (Cone and Kersey, 1992). If smectite, gypsum, or 

clay minerals are present, samples should be dried at 63 ̊ C and 45% humidity to prevent 

removal of structural water and damage to clay minerals (Cone and Kersey, 1992). 

Once the sample remains at a constant weight, indicating that all fluids have been driven off, the 

sample is then saturated with either a liquid (usually water) or a gas. Helium is usually the gas of 

choice because it does not adhere to mineral surfaces and its small molecule size allows it to 

diffuse into micropores. If liquid resaturation is chosen, the sample is saturated with liquid and 

re-weighed. For rock samples with very small pore sizes, the choice of displacing and saturating 

fluid used during the porosity measurement may introduce variability into the final results 

because of the attraction between pore surfaces and displacing fluids. The amount of pore space 

is deduced from the density of the saturating liquid. In gas resaturation, the sample is placed in a 

confined volume and resaturated with gas from a referenced cell. The volume of pore space is 

determined from the change in the pressure in the reference cell through the ideal gas law (pV =

nRT). Gas resaturation should not be used with vuggy or fractured samples.

Dry methods are also available. Thin sections of rocks made from core samples can be analyzed 

under a polarized light microscope or scanned and analyzed with specialized software 

(petrographic image analysis). Less commonly used laboratory methods to determine porosity 

include X-ray computerized tomography (CT scanning) and nuclear magnetic resonance 

imaging. 
UIC Program Class VI Well A-13 

Site Characterization Guidance

Permeability 

Permeability refers to the property of a porous medium to transmit fluids under a hydraulic 

gradient (USGS, 1989). Several physical factors can influence permeability. These include 

median pore size and connectivity of the pore space within the material (e.g., Bachu and 

Bennion, 2008). Grain size is also a significant factor; because all wetted grains have a boundary 

layer of fluid with a velocity of zero, more energy is expended in overcoming shear forces 

between the boundary layer and through fluids when the grain size is small (Schlumberger, 

2006). 

Absolute (Intrinsic) Permeability

 

Absolute permeability, also known as intrinsic permeability, is the permeability of a material 

when only one fluid is present. It is dependent only on the properties of the material and not the 

fluid. Absolute permeability can be calculated from laboratory analyses of a core sample as:

 

Absolute Permeability = f

QμL

A ×(p2−p1)

 Equation 2 

where Q is the flow rate through the core, μ is the fluid viscosity, L is the length of the core, Af is 

the cross sectional area of the core, and (p2-p1) is the pressure difference on either side of the 

core. Permeability values of different lithologies can vary by orders of magnitude (Table A-1), 

with salts and shales typically exhibiting lower permeability values and sandstones having the 

highest values. 

Table A-1: Typical Permeability for Various Lithologies.

From: Davis (1988). 

Lithology Permeability (mD)

Shale (unfractured) 4.7 x 10-5

Sandstone 3.8-4,740

Coal 334

Salt 9.61 x 10-5

 

Because geologic materials are inherently heterogeneous, absolute permeability will vary 

spatially. Furthermore, permeability is an anisotropic property that varies in the x, y, and z 

directions and typically shows the greatest variation in the direction perpendicular to layering. 

For the computational modeling performed for AoR delineation, a realistic representation of the 

permeability distribution is needed. Approaches for handling the distribution of permeability, 

including geostatistical approaches are discussed below and in Section 2 of the UIC Program 

Class VI Well Area of Review Evaluation and Corrective Action Guidance. 
UIC Program Class VI Well A-14 

Site Characterization Guidance

Effective Permeability

 

Effective permeability measures the permeability of a material to one fluid when more than one 

fluid phase is present (such as carbon dioxide in brine or oil). In addition to pore size 

distribution, effective permeability is affected by the relative saturation of fluids within a 

material and the interfacial tension (IFT) between the fluids (Bachu and Bennion, 2008). 

Because IFT is influenced by in situ conditions such as pressure and temperature, these variables 

can also influence effective permeability. Due to its dependence on the IFT and the relative 

saturation of fluids, effective permeability in a GS project is expected to vary spatially and 

temporally as the pressure and distribution of brine and carbon dioxide change. 

Relative Permeability

 

Relative permeability is the dimensionless ratio of the effective permeability to absolute 

permeability. It varies from 0 to 1. Relative permeability is relevant to site characterization for 

GS because one phase or fluid can inhibit or facilitate the preferential flow of another phase or 

fluid. Because relative permeability varies with the relative saturations of the fluids, it may be 

expressed as a relative permeability-saturation function for incorporation into computational 

modeling. See the UIC Program Class VI Well Area of Review Evaluation and Corrective Action 

Guidance for more information. Relative permeability has been studied extensively due to its 

importance in hydrocarbon extraction (Schlumberger, 2006). For GS, changes in the relative 

permeability may result in improved or reduced injectivity into reservoir rocks and/or improved 

or reduced sealing capacity for confining formations. 

Many mathematical methods for obtaining relative permeability are available. One of the 

simplest is the Pirson model, which uses the saturation of the wetting phase before and after 

drainage of a core sample to determine the relative permeability of the wetting phase:

where Si and Sir are the initial saturation and residual saturation of the fluid.

 

Relative permeability measured in the laboratory is often found to depend on many factors, 

including pore size and IFT, which in turn depends on in situ pressure, temperature, overburden 

pressure, wettability, and salinity conditions (Bachu and Bennion, 2008; Hawkins, 1992). A 

lower IFT encourages the transport of the non-wetting phase through the pore space, leading to 

an increase in the relative permeability. Hysteresis effects may also influence relative 

permeability (Hawkins, 1992). This may be important for fields with previous water and carbon 

dioxide flooding histories or if injection of carbon dioxide is not done at a constant rate. 

 

Permeability data for several different fluids/mixtures within the reservoir may be needed to 

fully characterize behavior of the injectate at carbon dioxide storage sites as injection progresses. 

These fluids/mixtures are:

 

• Brine, hydrocarbon, or other initial reservoir fluid; 
UIC Program Class VI Well A-15 

Site Characterization Guidance

• Carbon dioxide/reservoir fluid mixture; and 

• Pure carbon dioxide. 

Initially, the permeability depends only on the behavior of the reservoir fluid. Next, permeability 

becomes dependent on a mixture of two or more liquids as injectate is introduced into the 

reservoir. Bachu and Bennion (2008) found that the permeability of sandstone, carbonate, and 

shale core samples taken from a typical intracratonic sedimentary basin to carbon dioxide at 

irreducible water conditions was one-fifth that of brine at 100% brine conditions for lithologies 

with permeabilities greater than 1 mD.

As large volumes of carbon dioxide are injected, a new zone may form near the injection well as 

the carbon dioxide saturation increases and the reservoir fluid is completely displaced. Once 

again, the permeability is dependent on a single fluid: this time the injected carbon dioxide as 

opposed to the native reservoir fluid. This zone is called the “dry-out” zone. Salts will precipitate 

out of the migrating brines, potentially decreasing permeability (Burton et al., 2009). However, 

the presence of a dry-out zone may increase injectivity because the effective permeability (the 

product of intrinsic and relative permeability) of carbon dioxide in the dry-out zone exceeds the 

effective permeability of carbon dioxide in the two-phase region (Burton et al., 2009). 

Measuring Permeability

Permeability can be quantified using in situ field measurement techniques (e.g., well tests, well 

logging) or laboratory methods (using cores). Unlike other parameters (e.g., viscosity, 

temperature, pressure), permeability is calculated indirectly from values derived from other 

measurements (e.g., capillary pressure, IFT). As a consequence, permeability can vary depending 

on the method used. Additional discussion is provided below. 

It should be noted that permeability measurements can differ by scale. Well tests are 

representative of a much greater area (scale) than core samples, which represent a much smaller 

scale (sampling point) (Ellis and Singer, 2007). As such, well testing tends to provide composite 

representations of localized variability. Permeability derived from well logs represents an 

intermediate scale between core logs and well tests.

Field Methods 

Permeability can be estimated in situ using a variety of methods. Pressure changes during 

drawdown tests can be analyzed quantitatively or, if multiple wells are available, variable flow 

test analysis can be used to determine permeability provided that the reservoir pressure, flowing 

bottomhole pressure, flow rates, and the total time of the test are known (Smolen, 1992; 

Matthews and Russell, 1967). 

 

The absolute permeability can also be determined from the hydraulic conductivity (Lewis et al., 

2006) using the relationship: 

Absolute Permeability = Kμ

ρg Equation 4 
UIC Program Class VI Well A-16 

Site Characterization Guidance

where K is the hydraulic conductivity, μ is the dynamic viscosity of the liquid, ρ is the density of 

the liquid, and g is the acceleration due to gravity.

 

An important consideration in field measurements pertains to the effective permeability of the 

existing well bores. Gasda et al. (2008) present a method to determine the permeability of the 

near-well bore region, which may differ due to damage during drilling (skin effect), using the 

pressure in units above and below confining formations. The method can identify permeability 

along the well bore even when it is greater than reservoir permeability. Additional discussion of 

skin effects is provided later in this Appendix (Section A8). 

Permeability can also be estimated from well log data. This is accomplished with an estimator of 

porosity such as a density log. Several empirical approaches have been developed to relate 

porosity, resistivity, and other parameters (e.g., irreducible water saturation) to permeability, 

with early work starting in the 1920s. Some empirical relationships are more suitable for certain 

rock types or textures; a summary and comparison of the various empirical methods are given by 

Balan et al. (1995). Nelson and Batzle (2006) also provide a description of methods for 

permeability estimation from well logs. These include multiple linear regression approaches 

using porosity and other variables and involve dividing the formation into zones with different 

lithologies, compositions, and flow histories. 

Laboratory Methods 

Absolute Permeability

Permeability measurements in the laboratory can be conducted with water, brines, gases, or other 

fluids when core samples are available. However, determining permeability from downhole 

cores may be difficult if damage has occurred during drilling. Permeability in core material can 

be reduced by as much as 80% due to the infiltration of mud, fine material, or other particles into 

the pore spaces of the core. Plug samples taken from the center of the core may be the best way 

to avoid such damage and generate a representative measure of permeability. Sandblasting the 

outside of whole-core samples may remove some built-up fines and improve results, but it 

cannot remediate mud that may have worked into the pores (Almon, 1992). Permeability can also 

be measured from sidewall cores. However, sidewall permeability measurements are often 

erroneously high for hard, dense formations because of grain shattering and other damage during 

the coring and extraction of the side wall core. Conversely, permeability measurements taken 

from sidewall cores for loose, friable (crumbly) formations are often erroneously low due to 

grain shattering introducing fines into pore spaces (Almon, 1992). 

Once an appropriate lithologic sample has been isolated, it can be analyzed. The most common 

laboratory methods involve isolating a sample of core in a non-permeable sleeve while injecting 

a fluid material into the core. Measurements taken using a single fluid yield information on 

absolute permeability. Lead sleeves are often used because traditional sleeve materials allow the 

diffusion of carbon dioxide across the sleeve. Also, lead sleeves transfer pressure radially 

throughout the core if experiments are conducted at in situ pressure conditions. 
UIC Program Class VI Well A-17 

Site Characterization Guidance

Gas (air) and brine are the most common fluids used for injection in conducting permeability 

tests. Gas permeability is the industry standard for hydrocarbon exploration because it is the 

easiest to produce. While gas and brine tests produce similar permeability results when 

permeability is high, gas permeability tends to be higher when the permeability is low because 

frequent collisions of gas molecules with the pore walls help propel the gas molecules forward. 

Gas methods are also corrected for gas slippage effects at low pressures and inertial effects at 

high pressures (Ohen and Kersey, 1992). 

The pressure difference across the core after the flow has stabilized can be transformed into a 

permeability measurement using a modified version of Darcy’s Law. A non-steady-state variant 

of this method measures the gas pressure decay across the core. Non-steady-state methods 

usually produce more accurate results. Experiments can be conducted in a temperature controlled 

environment to simulate reservoir conditions when measuring effective permeability.

 

When permeability is measured from a whole core, measurements are usually reported in two 

directions: one parallel to the major fracture planes and other at 90 degrees perpendicular to this 

direction (Almon, 1992). Measurements may also be needed along the core in order to gain a 

representative understanding of permeability within the unit. 

 

Relative Permeability

Although both effective and relative permeability can be measured in the laboratory, relative 

permeability is more commonly measured and reported (Abaci et al., 1992; Ahmed, 2006). 

Several methods are available. One common method uses a setup similar to absolute 

permeability methods except that after initial saturation and pressure equilibration, a second fluid 

is introduced and driven though the sample until the saturation and pressure differential across 

the sample returns to a constant value. A faster alternative is the unsteady-state method, in which 

a stream of gas is injected into a sample to displace a liquid. However, mathematical calculations 

are more complex when using the unsteady-state method.

Several types of corrections have been applied to core data. The Klinkenberg correction, which is 

important for low-permeability rocks, relates permeability for liquids to gas permeability. The 

pore fluid chemistry, especially salinity, may also affect permeability. Another type of 

adjustment is a correction for the dependence of permeability on pressure. For example, 

unconsolidated rocks can collapse, reducing permeability. These corrections are described by 

Nelson and Batzle (2006). 

Petrographic Image Analysis 

Petrographic image analysis (PIA) is an established method employed in the oil and gas industry 

to derive 3D petrophysical properties (porosity, capillary pressure, permeability, relative 

permeability) from 2D measurements of pore size and geometry. It can be used for 

characterization of sandstones, carbonates, and conglomerates, and it is inexpensive and rapid 

(Gies, 1993). 
UIC Program Class VI Well A-18 

Site Characterization Guidance

To collect PIA data, standard petrographic thin sections are viewed under a petrographic 

microscope or SEM in backscatter mode (BSE), and the images are stored and analyzed using 

image analysis software. The sample will need to have been impregnated with epoxy to fill the 

pore spaces prior to making the thin section. If light microscopy is to be used, adding dye to the 

epoxy will make pore spaces easily visible and will facilitate the image analysis. In BSE images, 

the pore spaces will be darker grey than the mineral grains. During image measurement, a 

number of fields of view on the thin section will be examined to obtain a representative sampling 

of pore spaces. The number of images needed may vary according to the rock type and 

magnification (Solymar and Fabricius, 1999). The images allow quantification of the number, 

size, and structures of pores. Macroporosity can be determined, and, with the high magnification 

and excellent resolution achievable with SEM, microporosity can also be determined. Pore size 

distribution can be measured, as well as pore circumference and area. These properties can be 

used to estimate capillary pressure and permeability. Capillary pressure can be expressed as a 

function of porosity, pore perimeter, and pore surface (Cerepi et al., 2001). Permeability can be 

derived using the Carman-Kozeny model (Cerepi et al., 2001; Solymar and Fabricius, 1999), 

which relates permeability to the porosity, the pore area, and pore perimeter. Cerepi et al. (2001) 

have also evaluated an alternate model for permeability (“bundle of capillary tubes”), but 

achieved better results using the Carman-Kozeny model. 

PIA has been found to produce porosity values that agree closely with data from other methods 

(core analysis, wireline logs data, petrographic methods) (Layman, 2004). With respect to 

permeability, Solymar and Fabricius (1999) found that PIA tends to yield higher values than 

measurements of liquid permeability. This method has become well established, and additional 

literature is available that further explores the basis of PIA methods and the relationship between 

PIA-derived parameters and those measured in the laboratory. 

Other Permeability Estimation Methods Based on Petrophysical Data 

In addition to the Carman-Kozeny model noted above, there are several equations that make use 

of the results of petrophysical analysis, including information that can be gained from PIA. 

Krumbein and Monk’s equation uses mean grain diameter and the standard deviation of grain 

diameter (an indication of sorting). Berg’s model links grain size, shape, and sorting to 

permeability. Van Baaren’s model is an empirical variation on the Carmen-Kozeny model and is 

similar to Berg’s (Nelson and Batzle, 2006). 

Some models are based on pore dimension and use capillary pressure and pore size. For 

example, Winland’s equation relates permeability to porosity and capillary pressure. Katz and 

Thompson’s equation addresses the influence of pore structure on flow properties. Details are 

provided by Nelson and Batzle (2006). 

Geostatistical Methods

Analyses of formation properties such as porosity and permeability from logs or core samples 

provide point measurements that cannot fully capture subsurface variability. However, 

representation of the distribution of porosity and permeability is valuable for the multiphase 

modeling required for AoR delineation under 40 CFR 146.84. Subsurface heterogeneity is 
UIC Program Class VI Well A-19 

Site Characterization Guidance

difficult to represent using conventional models, and if adequate data are available, owners or 

operators may consider use of geostatistical approaches such as semivariograms, kriging, and 

stochastic simulations to estimate porosity and permeability distributions at the project site: 

• Semivariograms characterize spatial correlations and are developed from field 

measurements. A semivariogram model can then be fit to an empirical semivariogram. A 

number of semivariogram models exist including nugget, spherical, exponential, 

Gaussian, and power models. Individual models or combinations of models may be fit to 

the data; 

• Kriging and stochastic (see next bullet point) methods may be used to estimate parameter 

values at unsampled locations once a semivariogram model has been developed. Kriging 

is an interpolation method that calculates a statistically unbiased, best-fit estimate at each 

point, accounting for the hard data values and the correlations between the data. Kriging 

results are artificially smooth because the variability between estimated locations is not 

considered (Khan, 2003); and

• Stochastic simulation is a probabilistic approach that generates multiple, equally probable 

realizations of a variable. The result from this method is not a single best answer, but a 

range of possible outcomes. Examples of stochastic simulations include Monte Carlo and 

Sequential Gaussian Simulation. Stochastic simulations can also be employed after 

kriging to correct for the artificially smooth output from kriging (Khan, 2003). 

Though geostatistical methods may be helpful for approximating parameter values at unsampled 

locations, the results may not always accurately capture the complexities of the subsurface 

geologic heterogeneities such as faults, lenses, and varying lithologies. Geostatistical methods 

are optimal when the data are normally distributed and stationary (i.e., mean and variance do not 

vary significantly in space). To improve the results, a number of alternative methods have been 

proposed for use in combination with geostatistics, including the coupled Markov chain (Park et 

al., 2003) and the use of artificial neural networks (ANN) (Wang and Wong, 1999). Owners or 

operators may also consider using cross-validation to validate the modeling results (Malvic, 

2005). 

Capillary Pressure

Several established methods are available for measurement of capillary pressure:

• Mercury injection - a dried core sample is injected with mercury in increasing pressure 

steps up to 60,000 psi. The pressure versus the mercury saturation is measured. This 

method is quicker than some of the other methods and can achieve much higher 

pressures. The disadvantages are that it uses mercury, and results need to be extrapolated 

to reservoir fluids. This method is effective for measuring pore throat size distributions, 

although not as effective for measuring capillary pressure in some formations such as 

tight sands; 

• Centrifuge - core samples are centrifuged and the fluid forced out is measured. This test 

is relatively rapid, taking hours instead of days or longer. It can be performed at reservoir 

temperatures and pressures. The disadvantage is that this test has a maximum pressure 
UIC Program Class VI Well A-20 

Site Characterization Guidance

limit that is lower than mercury injection. Additionally, there may be cavitation if the 

capillary pressure is greater than atmospheric pressure. However, this test is well suited 

for poorly consolidated samples;. 

• Porous plate - a porous membrane is used, and pressure is increased with a fluid. The 

pressure required to displace the pore fluid is measured. This method offers the advantage 

of using native fluids and does not require cleaning or drying of the cores. It can test a 

lower maximum pressure than mercury injection, and it is well suited for shales and 

clays. However, samples need to reach equilibrium, which can result in test lengths of 

days to weeks; and 

• Restored state cell - the sample is initially saturated with brine. A non-wetting fluid is 

then introduced in small pressure steps. The pressure is increased until no more water is 

released. This method has the advantage that the electrical properties of the fluid can be 

measured as well. Furthermore, native fluids can be used. However, the disadvantage is 

that it takes longer than the centrifuge or mercury tests.

 

Newer techniques such as nuclear magnetic resonance and a vapor deposition technique may 

also be considered. 
UIC Program Class VI Well A-21 

Site Characterization Guidance

A4. Information to Support Geomechanical Characterization of the Confining 

Zone

The Class VI Rule requires geomechanical information to be submitted on fractures, stress, 

ductility, rock strength, and in situ fluid pressures within the confining zone [40 CFR 

146.82(a)(iv)]. This section provides background information for understanding in situ fluid 

pressure and downhole stresses; this information supplements Section 2.3.6 of the guidance on 

Geomechanical Characterization. Data on pore pressure and stress data may also be used for 

analysis of fault stability (see Section A5 below and Section 2.3.2 of the guidance). References 

and methods are summarized in Table A-2. 

Table A-2: Parameters and Data Needed to Define the Stress Tensor and the Geomechanical Model.

After Chiaramonte et al. (2008).

Parameter Data Collection Methods Additional Information

Pore pressure Measurement of downhole pressure by drill 

stem testing and production testing 

Smolen (1992); Borah (1992); 

Lancaster (1992); Harrison & 

Chauvel (2007)

Vertical stress 

(Sv) 

Integration of density logs over the desired 

depth 

Zoback et al. (2003); 

Chiaramonte et al. (2008); 

Streit et al. (2005); Herring 

(1992)

Minimum 

horizontal stress 

(Shmin)

Leak-off tests (LOT), Extended LOT 

(XLOT)

Chiaramonte et al. (2008); 

Zoback et al. (2003); Streit et 

al. (2005)

Maximum 

horizontal stress 

(SHmax) 

Modeling well bore failure features such as 

drilling-induced tensile fractures (if Sv, Shmin

and pore pressure values are known) or 

stress-induced well bore breakouts (if Sv, 

Shmin, pore pressure, and the rock strength are 

known)

Moos & Zoback (1990); 

Goetz (1992); Streit & Hillis 

(2004); Zoback et al. (2003); 

Streit et al. (2005) 

 

Pore Pressure 

Pore pressure can be measured by formation testers or by performing drill stem tests. Formation 

testers are specialty wireline tools used for measuring the pressure of the formation in an open 

hole (Smolen, 1992). In drill stem testing, the formation pressure is measured by sealing the zone 

of interest with well bore packers (Borah, 1992). After completing the well, additional pressure 

testing can be conducted by production testing such as single-point, multi-point, and swab testing 

(Lancaster, 1992). Bottomhole pressure may also be measured by pressure transducers. 

Transducers convert a pressure change into a mechanical displacement or deformation, which is 

then converted into an electrical signal (Harrison and Chauvel, 2007). Additional information 

regarding types of pressure transducers is available in Harrison and Chauvel (2007) and from 

commercial manufacturers as well as in the UIC Program Class VI Well Testing and Monitoring 

Guidance. 
UIC Program Class VI Well A-22 

Site Characterization Guidance

In Situ Stress Determination 

The three principal stresses commonly assumed to characterize the geomechanical model of a 

site at depth are the vertical stress, Sv, the maximum horizontal stress, SHmax, and the minimum 

horizontal stress, Shmin (Zoback et al., 2003; Streit et al., 2005). Fault slip occurs in normal 

faulting regions (gravity-driven faulting) when the minimum stress reaches a low value relative 

to the vertical stress (Sv ≥ SHmax ≥ Shmin); folding and reverse faulting can occur in compressive 

stress fields when both of the horizontal stresses exceed the vertical stress and the maximum 

horizontal stress is sufficiently large relative to the vertical stress (SHmax ≥ Shmin ≥ Sv); and strikeslip faulting occurs when the difference between SHmax and Shmin is sufficiently large (SHmax ≥ Sv 

≥ Shmin) (Zoback et al., 2003). 

The magnitude and orientation of the vertical stress, the minimum horizontal stress, and the 

maximum horizontal stress can be determined from drilling data and well logs. Methods for 

quantifying the magnitude and orientation of these principal stresses are summarized below.

Vertical Stress 

Vertical (orientation) stress (Sv) can be obtained from density logs (Zoback et al., 2003). The 

magnitude of Sv can be obtained by integrating data collected from density logs over depth. 

Density logs measure the bulk density of the rocks in the well bore walls through gamma ray 

emissions (Chiaramonte et al., 2008; Herring, 1992; Streit et al., 2005). Vertical stress at the 

depth of interest can be calculated by the following equation (Chiaramonte et al., 2008; Streit et 

al., 2005; Zoback et al., 2003): 

Sv(z0) = ∫

z

0

0 ρgdz Equation 5 

where z0 is the depth of interest. In some cases (e.g., offshore wells), the analyst needs to account 

for the lower density of the water column and the transition to higher density with depth when 

evaluating the magnitude of vertical stress (Zoback et al., 2003). Additional editing and 

extrapolation of data may be necessary; for example, when borehole conditions are unfavorable 

and density data exhibit high levels of variability (Zoback et al., 2003). 

Minimum Horizontal Stress 

The magnitude of the minimum horizontal stress (Shmin) in normal and strike-slip faulting regions 

can be determined with considerable accuracy through direct in situ formation stress tests (see 

Zoback et al., 2003). For deep wells where conventional in situ formation stress tests are not 

available, information about Shmin can be collected by leak-off tests. A leak-off test is conducted 

by pumping into a well at a constant rate and recording the well bore pressure as a function of 

cumulative volume (or time if pumped at a constant rate). As described by Zoback et al. (2003), 

the pressure will increase linearly with volume (or time) until a distinct departure from a linear 

increase occurs (leak-off point or LOP) (Figure A-7). As pumping continues at constant rate, the 

maximum pressure reached is termed the formation breakdown pressure (FBP) and the pressure 
UIC Program Class VI Well A-23 

Site Characterization Guidance

then falls below the FBP to a relatively constant value called the fracture pumping pressure 

(FPP). The FPP value should be similar to the LOP. 

Figure A-7: Schematic Illustration of an Extended Leak-off Test and Associated Terms. 

Where: LT= Limit Test; LOP= Leak-Off Point; FIT= Formation Integrity Test; FBP= Formation Break-down 

Pressure; FPP= Fracture Pumping Pressure; ISIP= Instantaneous Shut-in Pressure; FCP= Fracture Closure Pressure. 

From: Zoback et al. (2003); © Elsevier, reproduced with permission.

The extent that leak-off tests can be used to estimate Shmin can be assessed by evaluating the data 

collected. Zoback et al. (2003) noted that test data that show that the leak-off point was reached 

can be considered “an approximate measure” of Shmin. Further, Zoback et al. (2003) noted that, if 

the test data shows that a stable FPP was achieved, the test can be considered “a good measure” 

of Shmin. Chiaramonte et al. (2008) described the use of information from leak-off tests to 

determine the fracture pressure limit of the confining zone at the Teapot Dome oil field in 

Wyoming.

Another technique, which uses annular pressure measurements during drilling operations, is 

described by Zoback et al. (2003) as a potential method for estimating the magnitude of Shmin. 

Maximum Horizontal Stress 

In addition to the use of in situ stress testing, the magnitude of the maximum horizontal stress 

(SHmax) can be estimated based on knowledge of the vertical stress, Sv, and the minimum 

horizontal stress, Shmin. The stress polygon method, as described by Zoback et al. (2003), can be 

used to estimate possible SHmax values associated with normal-gravity, reverse faulting, and 
UIC Program Class VI Well A-24 

Site Characterization Guidance

strike-slip faulting environments, given the pore pressure at depth and available results of in situ 

formation stress tests or leak-off tests. Chiaramonte et al. (2008) applied the polygon method at 

the Teapot Dome oil field in Wyoming.

The orientation of SHmax can be determined from the orientation of borehole breakouts and 

drilling-induced tensile fractures. Borehole breakouts and drilling-induced tensile fractures can 

form in the well bore during drilling operations. Zoback et al. (2003) provide a theoretical 

discussion of effective stresses acting in a vertical well bore. Streit et al. (2005) provide an 

illustration of the occurrence of well bore breakouts (formation loss in the area of minimum 

horizontal stress) and drilling-induced tensile fractures (along the axis of maximum horizontal 

stress) in a borehole relative to the orientation of maximum and minimum horizontal stresses.

 

Figure A-8: Schematic Cross Section through Borehole. 

(a) borehole breakout due to spalling of borehole wall indicating the Shmin direction. (b) drilling-induced tensile 

fractures indicating the SHmax direction. From: Streit et al. (2005); © Elsevier, reproduced with permission.

Well bore breakouts and drilling-induced tensile fractures can be detected through the use of 

image logs (Zoback et al., 2003). Figure A-9(a) is a standard “unwrapped” well bore image from 

an ultrasonic borehole televiewer. Borehole breakouts can be seen as dark bands on opposite 

sides of the well in Figure A-8(a), and as out-of-focus zones on opposite sides of the well in the 

formation microresistivity image (FMI) in Figure A-9(b). The orientation and opening angles of 

the breakouts are shown in Figure A-9(c). Figure A-9(a) also shows fractures oriented 90° from 

the well bore breakouts, which indicates the occurrence of failures associated with both well bore 

breakouts and drilling-induced tensile fractures (Zoback et al., 2003). 
UIC Program Class VI Well A-25 

Site Characterization Guidance

Figure A-9: Image Logs of a Well with Well Bore Breakouts.

(a) ultrasonic televiewer image logs (b) FMI log (c) cross sections of the well in (a). Breakouts are dark bands in 

part (a) and out-of-focus areas in part (b). From: Zoback et al. (2003); © Elsevier, reproduced with permission.

Another method that can be used to estimate SHmax is referred to as a frictional limit calculation 

(Zoback et al., 2003; Streit et al. 2005; Streit and Hillis, 2004). The relation equates the ratio of 

the maximum-to-minimum principal stresses to frictional sliding on cohesionless, optimally 

oriented faults (Streit et al., 2005; Streit and Hillis, 2004):

where σ1 and σ3 are the maximum and minimum principal stresses, respectively, Pp is the pore 

fluid pressure, and μ is the coefficient of static friction. The coefficient of static friction is 

generally considered between 0.6 and 1.0 for a range of rocks and faulting environments (Zoback 

et al., 2003). 

The specific parameters used in Equation 6 for σ1 and σ3 are defined by the faulting environment 

(Zobak et al., 2003), as described previously. For example, a strike-slip faulting environment 

would be characterized σ1 = SHmax and σ3 = Shmin, while a normal faulting environment would be 

characterized by σ1 = Sv and σ3 = Shmin. An example plot of data used for estimating frictional 

limits is given in Figure A-10 (Streit et al., 2005). Example plots of stress magnitudes as a 

function of depth for various faulting environments are provided by Zoback et al. (2003). 

Techniques for stress determination in deviated wells (e.g., horizontal or wells drilled with 

complex trajectories) are described by Zoback et al. (2003). 
UIC Program Class VI Well A-26 

Site Characterization Guidance

Figure A-10: Example Plot of Data Used for Estimating Frictional Limits (Petrel Sub-Basin, Australia).

Shmin estimates are derived from pressure leak-off tests, and Sv estimates were obtained by examining density logs. 

R values are Pearson correlation coefficients. Vertical axis is meters. From: Streit et al. (2005); © Elsevier, 

reproduced with permission.

The orientation of borehole breakouts and tensile fractures (Figure A-11) can be determined 

from image logs and four-arm caliper logs. Six-arm caliper logs are also available, which may be 

able to provide more accurate and detailed data on borehole breakouts if four-arm caliper logs 

are not sufficient. FMI logs generate an electrical image of the borehole from microresistivity 

measurements, which penetrate about 30 inches from the well bore. FMI data are used to identify 

drilling-induced features and breakouts (Schlumberger, 2002). An application using FMI logs for 

the analysis of tensile fractures was described by Chiaramonte et al. (2008). Caliper logs (two-, 

three-, four-, or six-arm) can measure the enlargement of boreholes in the presence of natural 

fractures (Aguilera, 1992). Choosing a caliper log with a greater number of arms can increase the 

accuracy and level of detail in the resulting data. Breakout and tensile fracture data collected at 

depth from various wells can be used to develop stress maps such as those shown in Figure A-11. 
UIC Program Class VI Well A-27 

Site Characterization Guidance

Figure A-11: Example of a Regional Stress Map based on the Orientation of Well Bore Breakouts in 

Paleozoic Rocks the Western Canada Sedimentary Basin near Calgary. 

Modified after: Bell et al. (1994); © Alberta Geological Survey, reproduced with permission.
UIC Program Class VI Well A-28 

Site Characterization Guidance

A5. Information to Support Fault Stability Analysis and Analysis of Confining 

Zone Integrity

The Class VI Rule, at 40 CFR 146.82(a)(3)(ii), requires owners or operators to determine that 

any faults or fractures that may transect the confining zone(s) in the area of review will not 

interfere with containment. The Class VI Rule also, at 40 CFR 146.83(a)(2), requires the owner 

or operator to demonstrate the presence of a confining zone(s) free of transmissive faults or 

fractures and that has sufficient integrity to contain the injected carbon dioxide stream and 

formation fluids. These topics are addressed in Sections 2.3.2 and 3.5 of the guidance. Additional 

background information is presented here describing various methods that may prove useful to 

owners or operators. Examples of case studies are also presented. 

Fault Stability Analysis 

Below are three examples of methods for analyzing fault stability and evaluating the pore 

pressure that should be maintained to minimize the chances of fault activation. 

Failure Plots 

Failure plots (Figure A-12) can be used to identify faults within a carbon dioxide storage 

reservoir that are relatively stable as a function of fault angle. Failure plots are developed by 

plotting differential stress (i.e., the difference between the maximum and minimum principal 

stresses, σ1 - σ3) versus fault angle, thus identifying conditions that permit fault reactivation 

(failure) versus formation of new fractures (or relatively stable fault conditions) (Streit et al., 

2005). Streit (1999) described the method for constructing failure plots for various rock types 

and fault strengths. Although the failure plot method has been applied to study sites for carbon 

dioxide storage, 3D methods should also be used to estimate fault slip tendency (Streit et al., 

2005). 

Figure A-12: Example Failure Plot Indicating Scenarios where Fault Reactivation is Possible.

Adapted from: Streit et al. (2005); © Elsevier, reproduced with permission.
UIC Program Class VI Well A-29 

Site Characterization Guidance

3D Fault Slip Tendency

The parameter referred to as slip tendency (Ts) can be used to assess the potential for reactivating 

a fault associated with carbon dioxide injection (Streit and Hillis, 2004). The fault slip tendency 

depends upon the effective normal stress, shear stress, and pore fluid pressure. This method can 

also be used to calculate fault slip tendency along the grid orientation of a fault when 3D seismic 

surveys are available, and the fault slip tendency can be displayed in 3D graphical form using 

commercially available software (e.g., TrapTester, Badley Geoscience Ltd, UK, 

http://www.badleys.co.uk). Figure A-13 is an example fault slip tendency image in 3D form. 

The fault slip tendency equation provided by Streit and Hillis (2004) can be used to predict the 

maximum sustainable pore pressure to avoid fault reactivation. This estimation may be compared 

to anticipated (simulated) pore pressure at the fault under the proposed operating conditions. The 

predicted pore pressure at the location of the fault should be less than the maximum sustainable 

pore pressure, with a margin of safety to account for uncertainties in both the fault slip tendency 

calculation and modeling results. The margin of safety will depend upon the precision of the data 

available and should be discussed in the submission materials. 

Figure A-13: Example Fault Slip Tendency Image.

From Streit et al. (2005); © Elsevier, reproduced with permission.

Critical Pore Fluid Pressure Increase 

The Mohr diagram (Figure A-14) can be used to evaluate the effects of increasing fluid pressure 

on fault stability (Streit et al., 2005; Streit and Hillis, 2004). The diameter of a semicircle 

represents the differential stress (σ1-σ3), and the curve to the left represents the rock failure 

envelope. A change in fluid pressure (as indicated by the arrow) can shift the Mohr envelope 

toward the failure envelope, which indicates a condition of fault failure. In the figure, the 

decrease in the effective normal stress (from increasing pore pressure or other causes) needed to 

reactivate an existing fault is indicated by a. The additional decrease in effective normal stress 

needed to create a new rupture is indicated by b. 
UIC Program Class VI Well A-30 

Site Characterization Guidance

Figure A-14: Example Mohr Diagram.

The maximum injection pressure that can be considered safe and sustainable is site-specific and 

depends on the seismic history and current state (or pressure-depleted condition) of the site 

(Benson and Cook, 2005). 

Sealing Potential of Faults 

Section 3.5.2 of the guidance presents several factors that may be evaluated in order to 

understand the sealing potential of existing faults; juxtaposition of units, capillary pressure of 

sediments in the fault zone, catalysis and diagenesis in the fault zone, the SGR, and pore pressure 

compartmentalization. Below is additional detail on use of Allan charts, calculation of the SGR, 

and pore pressure compartmentalization.

Allan chart

An Allan chart can be developed from detailed fault geometry (available from maps, cross 

sections, and other interpretive aids) and a detailed stratigraphic column (developed from well 

bores, outcrops, and other data). The quality of an Allan chart is highly dependent on data 

quality, especially if layers are thin or when uncertainties in the amount of displacement along 

the fault may make it difficult to obtain a good understanding of juxtaposition. Leakage may still 

occur along the fault even when juxtaposition of permeable/impermeable units across the faults 

successfully limits the lateral migration of carbon dioxide.

Figure A-15 shows an example of heterogeneity across a fault plane. The area has layer-cake 

stratigraphy on either side of the fault. In the figure, the footwall and hanging wall boundaries 

are indicated by solid lines; the vertical exaggeration is a factor of five. The area that juxtaposes 

potentially conductive units is shaded, with the colored region showing the SGR (see below), 

which is one indication of sealing potential. Note that the SGR changes dramatically over the 
UIC Program Class VI Well A-31 

Site Characterization Guidance

surface of the fault. It is often more important to determine if the fault is sealing or non-sealing 

in the area or areas that have a critical impact on the integrity of the seal (e.g., above or below 

structural spill points) than for the entire surface of the fault. 

Figure A-15: An Isometric View of a Fault Plane.

GOC=Gas-Oil Contact, OWC=Oil Water Contact. From: Freeman et al. (1998); reproduced with permission from 

the Geological Society: London.

Shale Gouge Ratio 

In Figure A-16, the fault crosses shale (gray) and sandstone (white) layers. As displacement 

occurs along the fault (a and b), portions of the shale layers are incorporated into the fault zone. 

As the displacement increases (c), the amount of shale along the fault thins. The direction of fault 

slip is indicated by arrows, and the fault plane is idealized as a dotted line. 
UIC Program Class VI Well A-32 

Site Characterization Guidance

Figure A-16: Simplified Shale Smearing Along a Fault.

Modeled after Koledoye et al. (2003).

Pore Pressure Compartmentalization

Using this method, it is also possible to evaluate if sealing behavior changes along the fault 

(Figure A-17). In the figure, faults are interpreted in the seismic image in (A), then mapped as 

lines onto the pore pressure determination (B). The color ramp is from low pressure (green) to 

high pressure (red). While the major fault (labeled with arrow Y and Z) at right 

compartmentalizes pressure, indicating that it may be sealing, the fault at left (labeled with arrow

X), does not separate regions of different pressure, suggesting that it may not be sealing. The 

apparent non-compartmentalization of high pressure near the tip of the Z arrow may be due to 

poor resolution of the pressure data. Vertical red lines above X and Z are assumed to be wells. 
UIC Program Class VI Well A-33 

Site Characterization Guidance

Figure A-17: Sealing Capacity from Seismic Pore Pressure Images.

From: Huffman (2002); © AAPG, 2002. Reprinted by permission of the AAPG, whose permission is required for 

further use.

Case Studies and Applications 

This section provides example applications of geomechanical characterization studies for helping 

to predict any potential impacts of carbon dioxide injection on fault stability and confining zone 

integrity as required by the Class VI Rule at 40 CFR 146.83(a)(2). 

Fault Stability Case Studies

Chiaramonte et al. (2008) evaluated the fault slip potential of the injection zone for the Teapot 

Dome oil field to determine the risk of leakage through the fault. The authors also conducted a 

critical pressure perturbation sensitivity analysis to understand possible impacts of horizontal 

stress estimates (SHmax and Shmin) and faulting environments on the probability of fault slip 

potential. Their study illustrates the potential for using geomechanical modeling to estimate the 

pore pressure required for a fault to slip during a GS project. 

Gibson-Poole et al. (2008) summarized a geomechanical assessment of a basin-scale carbon 

dioxide geological storage system in southeast Australia. Using data and information regarding 

the site’s rock strength, in situ stresses and fault orientation, Gibson-Poole et al. (2008) estimated 

the maximum sustainable pore pressure and risk of fault reactivation. Results showed large 

variability due to data uncertainties. The authors recommended additional work (e.g., laboratory 

testing of tensile and compressive core strength) to reduce uncertainties and constrain the 

geomechanical model.
UIC Program Class VI Well A-34 

Site Characterization Guidance

Rutqvist et al. (2007) demonstrated the use of two numerical modeling approaches for analyzing 

geomechanical fault slip (i.e., continuum stress-strain analysis and discrete fault analysis) 

coupled with fluid flow to estimate the maximum sustainable injection pressure during 

geological sequestration of carbon dioxide. The results of these two numerical approaches were 

compared to conventional analytical fault-slip analysis. The authors concluded that the numerical 

methods provided a more accurate estimation of the maximum sustainable carbon dioxide 

injection pressure than the conventional analytical method because the numerical models can 

better account for the spatial evolution of both in situ stresses and fluid pressure. 

Confining Zone Integrity Case Studies

Haug et al. (2007) described a geomechanical characterization of a potential carbon dioxide 

injection site at an existing oil and gas field in Alberta, Canada, which included determination of 

the principal stresses (Sv, SHmax, Shmin) and discussion of laboratory testing determinations of 

rock strength and deformation behavior. The study also included a sensitivity analysis regarding 

potential success for carbon dioxide containment based on data variability. The authors 

concluded that laboratory triaxial tests should be conducted to confirm the accuracy of the 

correlations.

Smith et al. (2009) described the program components of geomechanical testing and modeling of 

reservoir and confining zone integrity for a carbon dioxide sequestration project at an existing oil 

and gas field in Alberta, Canada. This work described the overall geomechanical workflow 

process and provided specific examples of log-derived rock strength and elastic properties, cores 

used for geomechanical testing, stress versus strain data measured on cores, linear MohrCoulomb failure envelopes, rock strength measurements, and uniaxial pore volume 

compressibility tests. In situ stresses, formation pressures and mechanical properties were input 

into a finite-differences-based geomechanical simulator to predict conditions leading to 

deformation of reservoir and confining zone, induced stresses, and to assess the propensity for 

fault reactivation and movements. 

Orlic (2009) discussed the impacts of geomechanical changes in a reservoir associated with 

pressure depletion and rock compression during hydrocarbon production. Computational 

modeling examples were used to illustrate the mechanical impact of carbon dioxide injection on 

confining zone integrity, fault stability, and well integrity. This study illustrates the use of 

computational modeling for predicting effects of carbon dioxide injection on containment 

capacity of the reservoir, taking into account previous stresses from depletion. 

Rutqvist and Tsang (2002) demonstrated the use of computational modeling to study the 

geomechanical effects of injecting carbon dioxide into a hypothetical sandstone formation. The 

authors provided discussion of the rock and fluid input parameters and simulation results 

assuming a homogeneous confining zone without intersecting fracture zone, and the effects of a 

vertical fracture zone in the confining zone. The analysis provided a better understanding of 

possible mechanisms affecting geomechanical changes associated with carbon dioxide injection 

processes.
UIC Program Class VI Well A-35 

Site Characterization Guidance

A6. Information to Support Geophysical Characterization

To support the requirement at 40 CFR 146.82(a)(3)(iii) to submit data on the injection and 

confining zone(s), this section provides background information on available geophysical 

methods that owner or operator may use, including seismic, gravity, magnetic, and electrical/EM 

methods. This section supplements the information provided in Section 2.3.10 of the guidance, 

which discusses geophysical characterization.

Geophysical methods gather information about subsurface features in lieu of physically sampling 

the region of interest. Depending on the scale and resolution of the investigation, geophysical 

methods may help to provide the required information on the stratigraphy, structure, extent, 

thickness, porosity, and permeability of subsurface units to be submitted to the UIC Program 

Director with a Class VI injection well permit application [40 CFR 146.82(a)(1)–(21)]. There are 

four main types of geophysical methods: seismic, gravity, magnetic, and electrical/EM. These 

methods can image a large volume of the subsurface without penetrations (i.e., wells or 

boreholes). These methods can provide good spatial coverage of a project area and may be 

especially useful in regions where subsurface geology is heterogeneous and/or wells are sparse. 

Geophysical methods are widely used for subsurface exploration and characterization in the 

hydrocarbon industry, archeology, engineering, and other fields. 

Methods used to characterize sites for carbon dioxide storage will not differ substantially from 

methods used to characterize subsurface geology for other purposes. The choice of storage 

formation (e.g., depleted reservoir, coal seam, saline formation, etc.) will not likely strongly 

influence the suitability of geophysical techniques. Site-specific considerations such as depth, 

geologic complexity, and overlying lithologies are more likely to influence the choice of 

methodology. Two notable exceptions to this generalization are seismic methods, for which this 

technology may be hampered in depleted gas reservoirs, and gravity methods, which work 

especially well in most brine-filled formations. 

The need to characterize features at depth is likely to be the most uniformly limiting factor in 

selecting an appropriate geophysical method for site characterization. Most carbon dioxide is 

likely to be stored at a depth of at least 800–1000 m, depending on site-specific conditions, and 

resolution at depth varies greatly among techniques and among different deployment techniques 

within the same method. Geophysical methods used primarily to image the shallow subsurface 

(e.g., ground penetrating radar (GPR), shallow seismic refraction, etc.) are not discussed in this 

section.

Overview of Geophysical Techniques 

Data gathered with geophysical techniques may aid in the creation of geologic maps and cross 

sections that illustrate the regional geology, hydrogeology, and geologic structure. Table 2-1 of 

the guidance summarizes the types of data produced by the various methods. 

The different geophysical methods vary in quality, the surface and subsurface environments in 

which they can be used, and the types of data they produce. For example, unlike other 
UIC Program Class VI Well A-36 

Site Characterization Guidance

geophysical methods, seismic data may allow estimates of pore pressure in the injection 

formation, confining zone(s), and other zones. 

Lithology and rock properties cannot be determined solely using geophysical data. Data gathered 

from geophysical surveys can indicate certain lithologies but are not conclusive. Information 

from stratigraphic wells, stratigraphic columns, or other sources is required to be submitted to the 

UIC Program Director with a Class VI injection well permit application. Such information can 

help to confidently assign rock types and properties to formations imaged using geophysical 

methods. Some of the required materials (e.g., maps and cross sections, available field data such 

as well logs) may help in interpreting geophysical data [40 CFR 146.82(a)]. 

Regardless of the geophysical method type, aerial, surface, and borehole deployments of each 

method are typically available. There are common advantages and disadvantages to each. Aerial 

surveys can cover large areas at low cost, they require no site preparation, but they often produce 

surveys of lower resolution than those produced by surface or borehole methods. Surface 

methods offer higher resolution in most situations and still offer coverage over a large areal 

extent. However, cost may be high, especially in areas with topographic relief, infrastructure, 

and/or environmentally sensitive cultural areas. Borehole methods often offer the highest 

resolution and can also often be acquired at a low cost. However, they do not image a large 

volume of the subsurface and they depend upon subsurface penetrations that cross the formations 

of interest. For all survey types, increasing the density of measurements, sources, or receivers 

will generally increase the quality of the survey but will also increase cost. 

Seismic Methods 

A seismic survey uses seismic waves to produce 2D sections or 3D images of the subsurface. 

Both seismic reflection and seismic refraction techniques are available. Refraction techniques are 

generally used for imaging shallow features (less than 100 m) and are less useful than reflection 

techniques for interpreting complex geologic structures. The remainder of this section focuses on 

reflection techniques. More information on refraction techniques is available in An Introduction 

to Geophysical Exploration (Kearey et al., 2002). 

Seismic reflection techniques measure the time it takes for seismic waves emitted from a source 

to bounce off a subsurface reflector and be detected at a geophone. This method is by far the 

most established, commonly deployed, varied, and advanced of the geophysical methods. More 

detailed information on seismic methods and processing is available from numerous sources, 

including introductory guides such as: A Handbook for Seismic Data Acquisition (Evans, 1997), 

Environmental Geology – A Handbook (Knödel et al., 2007), and An Introduction to Geophysical 

Education (Kearey et al., 2002). 

Different source/receiver deployment configurations can be used to maximize data quality 

depending on terrain and other factors (see Short, 1992 for more details). Newer, fully portable 

(cableless) data acquisition systems are also available (Criss, 2007) and may be used in regions 

with surface infrastructure and/or rough terrain. 
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Site Characterization Guidance

Seismic reflection systems are recognized as having the highest resolution of all geophysical 

imaging techniques in most situations (Benson and Myer, 2002). Seismic methods work best 

when characterizing simple, homogenous geologic settings where supplementary sources of data 

such as well logs, outcrop data, and other geophysical surveys are available. Increasing 

subsurface complexity may increase survey cost or decrease the resolution of survey results. 

Areas with accumulations of loose sediments such as thick sands or unconsolidated sandstones, 

conglomerates, well sorted gravels, or weathered horizons are challenging to image and may 

require more detailed consideration of seismic source and detector (see Short, 1992 or Knödel et 

al., 2007 for further information on selecting a proper seismic source). Seismic surveys are also 

complicated by noise contamination from roads, airports, railroads, mines, and other human 

activities that cause mechanical vibration.

Difficulty also increases when imaging through salts, basalts, coal seams, carbonates, and nonsedimentary units (Cooper, 2009; Hyne, 2001). Non-clastic rocks (i.e., metamorphic or igneous 

rocks) and coal seams cannot be imaged well. If such lithologies are present in the area of 

interest, seismic data may need to be supplemented with additional data. For example, if salt 

bodies are present, gravity data can be co-analyzed with seismic data to accurately determine 

their size and location (Nester and Padgett, 1992). Basalts pose a problem for seismic methods 

because traditional seismic approaches have resulted in severe energy scattering and wave 

interference. Some success has been reported in imaging basalts using multicomponent systems 

and wave component analysis (Sullivan et al., 2008). Carbonates often have minimal changes in 

seismic properties even when there are changes in texture, permeability, and porosity. High 

quality surveys, multicomponent methods, or other additional data collection steps may be 

needed to obtain sufficient accuracy and resolution in difficult environments. 

Both surface and subsurface seismic methods can use additional wave types to improve data 

quality. Most seismic data acquisition systems collect only p-wave (compressional wave) data 

unless otherwise specified, usually in two vibrational directions (called components). Other 

seismic wave types and components may also be collected to improve survey results. Special 

sources, receivers, and recording capacity are usually the only changes required to modify a 

seismic survey for additional wave types. Geophones that measure additional seismic 

components (such as direction of vibration) may also be added. The main disadvantage of these 

methods is that they increase processing time and are not as well-developed as standard 

approaches.

Wave choice depends largely on subsurface geology. P-waves remain the best option for imaging 

bulk changes such as porosity. However, p-waves are distorted by gases in rock. In such cases, 

shear waves (s-waves), which are not distorted by subsurface gases, can be used (Thompson, 

2005). This may be advantageous when characterizing some depleted gas reservoirs for carbon 

dioxide storage. S-waves are also appropriate for heavily faulted or fractured sites due to their 

greater sensitivity to continuous features such as fractures. Stoneley waves can help to identify 

fractures and changes in permeability (Cheng, 1992). Because s-waves provide information in 

the waveform as well as in the arrival time of the wave, a smaller number of geophones may be 

needed to gather the same amount of information. 
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S-waves can also help improve seismic pore-pressure prediction. S-wave data can aid in 

determining which seismic velocity variations are due to variations in fluid content and which 

are due to variations in fluid pressure (Sayers et al., 2000). In complex areas such as shallow, 

grossly undercompacted sediments, zones of severe unloading with minimal effective stress, and 

areas near gas chimneys and clouds, s-wave data may also help improve results (Huffman, 2002; 

Thompson, 2005). 

Seismic Deployments

Seismic data can be collected with many different source/receiver configurations. Deployment 

can be done on the surface, in boreholes, or in a combination of both. 2D and 3D seismic 

profiling are the leading options available for surface-based seismic imaging. 2D surveys 

produce “slices” of the subsurface while 3D surveys produce subsurface models that can be 

rotated and viewed from different perspectives. 2D seismic surveys are less expensive than 3D 

surveys because they require less site preparation, shooting time, and post-collection data 

processing. The chief disadvantage of 2D imaging is that, because it is collected in a line on the 

surface, it is difficult to determine the location of out-of-plane features. Therefore, 2D surveys 

are not optimal in settings where significant lateral heterogeneity is expected (e.g., areas with salt 

domes, intrusions, or where sedimentary layers are expected to thin or thicken). Application of 

2D seismic profiling may also be problematic in faulted regions, where the choice of line 

orientation is more critical to capture faults. 3D surveys are preferable to 2D surveys when 

characterizing sites with complex or variable subsurface geology, where subsurface geology is 

not well constrained, where improved resolution or greater certainty in subsurface 

characterization is needed. 

Both 2D and 3D seismic methods have been used at GS sites. 2D seismic surveys were used for 

site characterization and baseline data at the Sleipner project in the North Sea (Hellevang et al., 

2005). The Weyburn project in Saskatchewan, Canada also used 2D seismic lines for site 

characterization and as baseline measurements (Wilson and Monea, 2004). 3D seismic surveys 

were used for both site characterization and as baseline data at the carbon dioxide storage by 

injection into a natural saline aquifer project at Ketzin, Germany (CO2SINK) and for site 

characterization at the Kallirachi oil field in Greece, which is being considered for EOR/carbon 

dioxide storage (Koukouzas et al., 2009). 

A larger number of downhole seismic techniques are available. VSPs are the most common 

borehole seismic method. A VSP is conducted with one component located on the surface 

(usually the source) and the remaining component placed downhole. A VSP can be conducted in 

a vertical or deviated well to a depth of at least 3,000 m (Balch et al., 1982). The source may be 

directly adjacent to the borehole or, for an offset VSP, located at a fixed distance away. A VSP 

can resolve features 3–4.5 m in size or smaller. 

A VSP can also help increase the resolution and accuracy of other seismic surveys. First, a VSP 

can provide an accurate determination of the seismic velocity within the area of interest (seismic 

refraction techniques can also provide this information in simple geologic settings). This 

determination can help with seismic migration and pore pressure estimation. A VSP can also 
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Site Characterization Guidance

help confirm the depth at which upgoing reflections are generated, which can be used to link 

geology derived from other bore logs to seismic attributes (Kearey et al., 2002). 

Crosswell seismic methods deploy sources and receivers in different wells, producing a survey 

that images the plane between the wells. The Ketzin project used crosswell surveys and VSP 

surveys for site characterization and baseline monitoring data. Crosswell surveys between 

multiple wells can be used to produce a fence diagram. Equipment is generally deployed in 

monitoring wells located within 500 m of each other (Hoversten et al., 2002), although 

deployment down active injection wells is also possible (Daley et al., 2007). 

Crosswell seismic surveys combine most of the advantages of VSP with additional lateral extent. 

Crosswell seismic profiling can achieve a maximum resolution of 3 m (Harris and Langan, 

1997), which may provide data 10–100 times more detailed than surface seismic data (Martin et 

al., 2002). Crosswell seismic profiling may also be the best option available for imaging thin 

beds. The data can be used to fill the resolution gap between high-resolution well cores and 3D 

surface data (Washbourne and Bube, 1998) or to help correlate structures between well bores. 

However, because of the need for multiple wells, crosswell seismic profiling will not be suitable 

in areas that do not already have abundant subsurface penetrations. Furthermore, the distribution 

of wells will determine the potential planes for crosswell imaging. These orientations may not be 

optimal for imaging the relevant features. Crosswell imaging was used successfully for both site 

characterization and baseline monitoring at the Nagaoka pilot project in Japan, which injected 

and monitored 0.01 megatonne (Mt) of carbon dioxide. 

The borehole microseismic method relies completely on subsurface deployment and uses passive 

seismic energy. A string of geophones is deployed down a monitoring well and used to sense 

seismic events, typically on the order of M -3 to -1. Microseismic events can be detected up to 1 

km from the well on average (Downie et al., 2009). The period of data collection is variable and 

depends upon the frequency of seismic events, but typically lasts from several weeks to several 

months. This is disadvantageous compared to other seismic methods that collect data over a 

period of hours. Generally, the greater number of microseismic events, the more accurate the 

result. 

After collection, the hypocenters of the seismic events are projected onto a subsurface map to 

image fracture networks, faults, and other regions actively undergoing strain or deformation. The 

quality of the geologic model used to transform the time data and locate each hypocenter largely 

controls the accuracy of the result (Warpinski et al., 2009). 

Processing of Seismic Data

Post-collection processing techniques provide control over the final quality of the survey and its 

applicability to the project site characterization. In some cases, old data may even be reprocessed with newer techniques to uncover additional information. Choice of processing 

techniques will largely depend on site-specific factors other than the type of carbon dioxide 

storage reservoir being investigated. For example, certain types of processing (such as pre-stack 

migration) are more appropriate in regions where steep faults or other features are anticipated 

(such as near salt domes). Seismic processing techniques are immensely varied; the following is 
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an overview. For more detailed information, a number of handbooks on seismic processing are 

available (e.g., Upadhyay, 2004). 

If information about faults or other discontinuities in the subsurface is desired, special processing 

techniques can be used to mine the data for this information. Seismic crustal anisotropy 

processing can be used in areas where aligned fractures, joints, or fluid inclusions recur in the 

subsurface at a distance smaller than the wavelength of the seismic wave. As the wave passes 

through such a region, it is split into two waves with different polarization and velocities 

(Crampin and Lovell, 1991), in a manner similar to the effects of diffraction gratings on light 

waves. Studying the split waves can reveal information about the magnitude, consistency, and 

orientation of recurring subsurface features. Alternatively, p-wave data can be processed with a 

technique called p-wave amplitude variation with offset and azimuth (abbreviated pAVAZ or 

pAVOA) (Gray et al., 2002) to reveal information about fracture and pore orientations. However, 

these techniques are not fully developed. These techniques may have the potential to be adapted 

to image cleats and other discontinuities common in coal seams or columnar joint in basaltic 

flows if either type of formation is used as a potential carbon dioxide reservoir. 

Coherence processing can be used to detect faults. This method suppresses continuous features 

and highlights discontinuities, such as faults, within seismic sections. Although discontinuities in 

high-quality seismic data are often indicative of faults and lithologic breaks, discontinuities in 

low-quality seismic data may be due to a range of data collection and processing errors. As a 

result, coherence is very sensitive to the quality of input seismic data and is not suitable for lowquality surveys. 

Other advanced processing techniques, such as difference analysis with data normalization 

(DADN) (Onishi et al., 2009) are also available. 

Pore Pressure Interpretation

Seismic data can be processed to remotely determine subsurface pore pressures. This is 

accomplished using the relationship between pore pressure and effective stress: 

pore pressure = total stress (i.e., overburden stress) – effective stress

Any seismic data that yield an accurate velocity for the seismic wave in the subsurface can be 

used to approximate effective stress. However, not all seismic data meet this criterion because 

accurate velocity values are not needed to image the subsurface. Ensuring that seismic data can 

also be used for pore pressure prediction may not greatly increase the survey cost, but it does 

require planning. 

Once accurate velocity data have been obtained, numerous methods are available to convert 

velocity to pore pressure. These methods tend to work best in developed basins filled with shales 

and sands. In regions with high sedimentation rates like the Gulf of Mexico, tectonically 

complex regions, or regions with abundant carbonates, the transforms to convert velocity to 

pressure may introduce significant error. (See Sayers et al., 2005; Young and Lepley, 2005; and 

Sayers et al., 2000 for more information.) 
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Site Characterization Guidance

The overburden pressure in the area of interest is needed for accurate pore-pressure 

determination. The overburden pressure is closely related to the density of the overlying material 

and can be determined from well density logs. Gravity measurements can also be used to 

estimate the overburden pressure (Huffman, 2002). This is especially advantageous in areas with 

complex geology (e.g., regions with salt domes or other intrusive structures) where individual 

boreholes are likely to miss significant features. 

Under optimal conditions, pore pressure analysis can resolve pressure data for strata 30–60 m 

thick at medium depth in clastic basins with relatively simple stratigraphy (Huffman, 2002). 

Pressure information can also be used to help determine the integrity of sealing layers and the 

sealing behavior of faults (Huffman, 2002; Sayers et al., 2002). Additionally, if pore pressure 

appears compartmentalized by a fault in a 3D subsurface pressure map, this may support the 

interpretation that the fault is sealing. Subsurface pressure data may also help to inform estimates 

of risks associated with induced seismicity and estimates of total storage capacity, both of which 

require estimates of subsurface pressure. 

The main disadvantages to this technique are the extensive data processing and interpretation, 

which may introduce large errors, and the need for basin-specific correction factors during 

velocity processing. Saline formations and depleted reservoirs are the storage formations of 

interest where a potential Class VI injection well applicant would be most likely to utilize this 

technique. 

Additional Seismic Data Analysis - Seismic Stratigraphy

Seismic stratigraphy identifies stratigraphic units based on their seismic characteristics. Because 

seismic reflections follow large-scale bedding, the geometry of the reflections allows the 

delineation of features such as unconformities, depositional sequences, and unit thicknesses. 

Seismic reflections will not indicate facies shifts, but can show fluid changes or diagenetic 

changes (Emery and Myers, 1996). The principles of seismic stratigraphy are presented in a 

classic paper by Vail et al. (1977). 

Stratigraphic features identified in seismic surveys can be integrated with lithologic data from 

cores, well logs, and other data to allow interpretation of depositional environments. Lithologies 

and other characteristics identified at wells and boreholes can be correlated to seismic attributes, 

which can then be used to predict subsurface properties at other locations through the use of 

neural networks, regression, or other methods. Stratigraphic features identified in this manner 

may help in identifying features (e.g., barriers, channels, fans) that might affect storage capacity 

and migration of carbon dioxide. 

There are different processing and display options that can be employed for stratigraphic 

interpretation, and the choice of method will depend upon acquisition parameters, seismic 

sources, and site geology (Emery and Myers, 1996). 
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Gravity Methods 

Gravity-based methods image differences in density among subsurface materials. Because 

density is related to gravity, changes in the distribution of fluids, cementation, and porosity of 

subsurface materials can be measured as changes in gravity. Gravity data can be collected from 

land-based stations, aerially, or directly from the subsurface using boreholes. Choice of 

deployment is usually controlled by factors such as desired resolution and site-specific geology 

and is not limited by choice of carbon dioxide storage formation type. 

Gravity is measured with a gravimeter; information on how measurements are obtained can be 

found in Paterson and Reeves (1985). Figure A-18 is an example of a typical surface deployment 

pattern.

Figure A-18: A Gravity Map of an Area Ore Deposit and Mine. 

From: Yarger and Jarjur (1972); Reproduced with permission from the Kansas Geological Survey. 

Because detection of faults and structural features using gravity data depends upon contrasts in 

density, gravity methods work best in basins with varied lithologies. Salt domes and igneous 

intrusions are the easiest types of lithologic features to image because they usually have a highdensity contrast with surrounding formations. Figure A-18 illustrates the gravity anomaly 

associated with an ore deposit and mine. Faults may be detected with gravity data if units with 

contrasting density or regions with different sedimentary thicknesses are juxtaposed. Small faults 

or faults with large displacement occurring in discrete steps are more difficult to detect with 
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Site Characterization Guidance

gravity data than large planar faults. Vertical faults are especially difficult to detect using surface 

gravity methods (Barbosa et al., 2007). 

Because gravity measurements are not unique to specific lithologies, additional data from other 

types of geophysical surveys or other sources (e.g., boreholes, outcrops) can greatly improve the 

interpretation of gravity data (Jordan and Hare, 2002). One advantage relative to seismic data is 

that, because processing of gravity data is much more straightforward, it generally introduces 

much less interpretive error. 

Aerial and Surface Gravity Methods 

For aerial methods, data are typically collected along parallel lines in the area of interest. Closer 

spacing will generally increase resolution. For surface deployments, measurements are typically 

taken at discrete stations across the area of investigation. Broad gravity surveys may suffice for 

detecting large-scale changes in the thickness of basin fill and other basin-wide features, while 

more detailed surveys will be needed to detect finer features such as the distribution and 

thickness of specific formations. 

Borehole Gravity Methods 

Borehole surveys can be used to determine layer thickness and aid in determination of lithologic 

composition. Borehole gravity methods collect information from a larger subsurface volume than 

other types of borehole logs. This is useful for characterizing porosity and other formation 

parameters in carbonate and fractured reservoirs (LaFehr, 1992; Chapin and Ander, 1999) or 

other situations where poor borehole conditions, problematic casings, cementing problems, and 

well bore washouts are likely to affect the quality of other borehole formation-testing tools 

(LaFehr, 1992). 

Borehole gravity surveys are conducted in a manner similar to borehole seismic surveys. A 

gravimeter is lowered down the borehole and measurements are taken as the device is raised, 

usually at set intervals between 3 m and 15 m (Herring, 1990). Borehole surveys have been 

conducted in wells 2,000 m deep (Seigel et al., 2009) and inclined up to 60 degrees (Seigel et al., 

2009). Resolution is usually high. Special techniques (i.e., gravity gradiometry) are needed to 

characterize non-horizontal strata. 

In regions that are laterally variable geologically, borehole gravity data may indicate features 

such as salt domes and reefs even if they do not intersect the borehole (LaFehr, 1992). As a rule 

of thumb, borehole gravity surveys can detect anomalies as far away as one to two times the 

height of the body in question. For example, a sandstone lens 50 m high could be detected 100 m 

from the well bore under good conditions (Herring, 1992). When using a single well, however, it 

is only possible to know the radial distance from the well of a feature and not the direction. 

Electrical/Electromagnetic Geophysical Methods 

Electrical and EM methods use the conductive properties of subsurface materials to infer fluid 

distribution, stratigraphy, and/or structural information. Data can be collected aerially, 
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Site Characterization Guidance

surficially, or from the subsurface. Electrical/EM methods can use either natural electric fields or 

a controlled source (man-made). Deployment of survey equipment may either be temporary (for 

one survey) or permanent (e.g., installed during well construction). 

Electrical methods transmit a pulse of electrical energy into the subsurface using electrodes or 

other means; changes in properties such as galvanic potential that are registered when the signal 

arrives at a receiver are used to infer subsurface resistivity, which is then mapped and 

interpreted. EM methods measure the induction effect (generation of current and electric fields) 

in the subsurface by another EM field or electric current (Jordan and Hare, 2002). Depending 

upon the method, results can be presented either as a surface map or cross section. Figure A-19 

provides an example of the end result from an EM survey. 

Figure A-19: A Subsurface Cross Section of Electromagnetic Resistivity Data.

From: Lucius and Bisdorf (1997).

Fluid saturation and composition are the two most important factors controlling the 

conductivity/resistivity in the subsurface and, accordingly, the response to electric and EM 

fields. Therefore, electrical and EM methods are most sensitive to fluid composition, 

distribution, and saturation and less responsive to lithologic or structural changes (Wynn, 2003). 

Detailed determination of subsurface lithologies or structural features is usually only possible 

when the flow and distribution of formation fluids are controlled by lithology and structure. For 

example, fractures and faults are generally considered significant for electric/EM studies in low 

permeability and low porosity formations, where they can act as the primary pathways for 

conductive fluids (Orange, 1992). Accordingly, electrical/EM data are more likely to be used to 

characterize saline formations and depleted reservoirs than other types of potential carbon 

dioxide storage formations. Interpretation of electrical data is primarily qualitative and generally 

attempts to explain the shape of an anomaly in terms of fluid flow direction and magnitude 

(Orange, 1992). Values such as flow volume and composition cannot typically be quantified. 

Deployment method is more strongly influenced by the desired resolution than the type of carbon 

dioxide storage formation. Most surface methods for electrical data collection yield poor results 

compared to subsurface methods because surface conditions are highly heterogeneous and tend 

to attenuate the signal (Wilt et al., 1995). Near-surface changes in saturation (e.g., from 
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Site Characterization Guidance

rainstorms) can also greatly affect survey results, although this is more problematic for timelapse monitoring than site characterization. 

For subsurface deployments, the survey depth is typically two to three times the length of the 

dipole used to generate the current (Jordan and Hare, 2002). Resolution is usually 5–20% of the 

electrode depth (Jordan and Hare, 2002). Resolution is low for most electrical/EM methods 

compared to seismic methods. However, the depth and breadth of electrical/EM surveys can 

provide valuable information on the regional geologic framework at low cost (Orange, 1992). 

Highly conductive and magnetic rocks may introduce error into electric/EM methods (Jordan and 

Hare, 2002). Additional care should be taken if magnetite, iron-rich sands, graphite, or other 

conductive and/or magnetic constituents are present (at levels as low as 1%) within the area of 

interest. For further information, Jordan and Hare (2002) and the U.S. Army Corps of Engineers 

(1995) provide a detailed discussion of electrical and EM methods. 

Natural Source Electrical/Electromagnetic Methods

The self-potential (SP) method is an electrical technique that detects the current (in millivolts) 

generated by electrochemical reactions (i.e., oxidation/reduction reactions) in the subsurface 

(Orange, 1992). Measurements should not be taken within 500 m of power plants, substations, 

pipelines, telephone lines, or power lines (Jordan and Hare, 2002). The result is a surface map of 

electric potential. (see U.S. Army Corps of Engineers, 1995, for further details on SP surveys.) 

Magnetotellurics is an EM method that measures resistivity in the subsurface based on the 

strength and wave impedance of naturally propagating low-frequency EM fields in the Earth 

(Orange, 1992). Data are usually displayed as a cross section. Magnetotelluric surveys can image 

10 km or more into the subsurface (Orange, 1992), allowing deep structures to be identified. 

Rock types can also be inferred when resolution is high and an existing knowledge of regional 

stratigraphy is available.

Methods that use naturally occurring electric fields avoid the expense and logistics of choosing 

and operating a source. However, naturally occurring fields are unpredictable, and the total 

energy level of the field cannot be controlled (Orange, 1992). 

Controlled Source Electrical/Electromagnetic Methods

Controlled source methods use external sources to generate electrical energy and direct it into the 

subsurface or to induce EM fields in the subsurface. These methods can image the subsurface up 

to 1–2 km deep (Orange, 1992) with low resolution. Electrical controlled-source methods use a 

variety of sources channeled into the subsurface using source and receiver electrodes (U.S. Army 

Corps of Engineers, 1995). Induced polarization (IP) and complex resistivity (CR) are subtypes 

of this method and are most often used in known hydrocarbon reservoirs (Orange, 1992). 

Electrical methods can also be used in a crosswell configuration. One such technique is electrical 

resistance tomography (ERT). Deployment is similar to crosswell seismic imaging with a source 

of electric current in one well and a receiver in another. Resistivity changes on the order of 30% 
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can generally be detected, although under optimal conditions resistivity changes as little as 10% 

can be measured (Newmark et al., 2001). Figure A-20 presents an example permanent downhole 

ERT array used to characterize and monitor carbon dioxide injection into a depleted reservoir. 

Figure A-20: Permanently Installed ERT Array at the CO2SINK Pilot Site at Ketzin.

The diagram uses blue boxes to represent geophones, while the red star is the source. VSP = Vertical Seismic 

Profile, DTS = Distributed Thermal Sensor, VERA = Vertical Electrical Resistance Array, MSP = Moving Source 

Profile. From: Forster et al. (2006); © AAPG 1992, reprinted by permission of the AAPG whose permission is 

required for further use.

Surface EM controlled-source methods use coils and/or grounded wires to generate an EM field 

on or above the surface. This field induces currents in the subsurface, which, in turn, generate 

their own EM fields. The induced subsurface EM fields are then quantified by the disturbance 

they create in other fields (frequency domain methods) or as they decay (time domain methods). 

Resistivity can be calculated through inversion and modeling of these measurements (Orange, 

1992). EM methods can be used to detect changes down to 1 km or more (Orange, 1992; Jordan 

and Hare, 2002). Data can be collected aerially, although the maximum depth decreases to 100–

200 m when using aerial data collection. Aerial data collection usually cannot resolve anomalies 

smaller than 50–100 m2

 (Jordan and Hare, 2002). 

Controlled source audio-frequency magnetotellurics (CSAMT) is similar to the magnetotellurics 

method mentioned above, but the EM wave is generated and introduced into the ground by a 

dipole or pair of dipoles, usually 10-200 m in length (Jordan and Hare, 2002). A linear array of 

receivers located several kilometers away collects the signal from the subsurface. Data are 
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displayed as a cross section. CSAMT is less affected by infrastructure-related noise than other 

electrical/EM depth-profiling methods. 

Using a controlled source allows the operator to control the source strength and, to some degree, 

the signal-to-noise ratio. However, because the field is induced, the field geometry is determined 

and accounted for during processing. This increases the difficulty of the survey and may 

introduce processing errors. Also, determining the geometry of the field becomes increasingly 

difficult in geologically complex regions. 

Processing of Electrical/Electromagnetic Data

Depending upon the exact deployment, electrical methods require various amounts of postcollection data processing. Advanced processing techniques are also available if high resolution 

in single or time-lapse studies is needed (Onishi et al., 2009). Processing methods are not 

affected by the type of carbon dioxide storage formation being investigated. 

Magnetic Geophysical Methods 

Magnetic methods use natural variations in the Earth’s magnetic field to map features at the 

shallow, sedimentary, and basement levels. The magnetic field is affected by the distribution of 

iron-bearing minerals in subsurface formations. The distribution of iron-bearing minerals is 

usually controlled by the occurrence of igneous rocks, the prevalence of mineralization along 

faults, and the separation of detrital minerals during fluvial and other sedimentary processes.

The type of storage formation is not likely to influence the suitability of magnetic methods for 

site characterization purposes, although basalts may have a slight affinity for magnetic methods 

since igneous rocks can have a high content of potentially magnetic minerals. 

Magnetic intensity surveys are usually collected aerially using a magnetometer, although groundbased surveys can also be collected using a portable magnetometer. Figure A-21 presents an 

example of the type of data an aerial survey can provide. Paterson and Reeves (1985) provide a 

detailed discussion of magnetic methods. 
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Figure A-21: An Aerial Gravity Map. 

The data can then be interpreted for faults (the dashed and solid lines) and other structures. From: Goussev et al. 

(2004). 

Faults and other structural features in both basement rocks and overlying sedimentary cover can 

be imaged, but formation characteristics are difficult to determine using magnetic data (Ugalde, 

undated). Faults can be identified either because displacement along the fault juxtaposes units 

with different magnetic signatures or, more commonly, because secondary mineralization of 

magnetite or demineralization along the fault plane alters the magnetic signal in the region of the 

fault. Information on the dip of faults can also be gathered in some cases. One common 

interpretive error in magnetic surveys is wrongly identifying paleochannels filled with detrital 

magnetite as faults. Therefore, extra care should be taken in interpreting regions with sandstones 

and other fluvial lithologies. 

Because magnetic data are non-unique and do not represent specific lithologies, additional data 

from other types of geophysical surveys or other sources (boreholes, outcrops etc.) can improve 

magnetic data interpretation (Jordan and Hare, 2002). This approach was taken at the Weyburn 

Project in Saskatchewan. At the site, co-processing of low quality gravity and seismic data 

allowed positive identification of faults that were ambiguous using either data set alone (Goussev 

et al., 2004) during site characterization. This data interpretation approach may be a good 

solution for characterizing areas with vintage data sets such as oil and gas reservoirs. 

Magnetic methods are sensitive to human infrastructure. As a result, they are not useful in 

populated or developed areas because buildings, pipes, and wires obscure the geologic signal. 

The one advantage to this sensitivity is that magnetic surveys may be used to find abandoned, 

cased wells. This can help in identifying abandoned wells that may need corrective action, as 
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Site Characterization Guidance

required at 40 CFR 146.84(c). See the UIC Program Class VI Well Area of Review Evaluation 

and Corrective Action Guidance for further details on locating abandoned wells and performing 

the required corrective action activities.

Processing of Magnetic Data

After collection, magnetic intensity data undergo processing. Processing methods are not 

influenced by the type of carbon dioxide reservoir under investigation. High frequency 

anomalies can be attributed to near-surface and shallow subsurface effects, intermediate 

frequency anomalies can be attributed to the composition of the sedimentary basins, and lowfrequency anomalies can be ascribed to changes in the basement rocks. Most surveys collected 

today are of sufficient resolution to detect anomalies in all three ranges. 
UIC Program Class VI Well A-50 

Site Characterization Guidance

A7. Information to Support Demonstration of Storage Capacity

To support a demonstration that the site meets the requirement that the injection zone or zones 

are of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated 

volume of the carbon dioxide stream per 40 CFR 146.83(a)(1), this section provides background 

on the concept of storage capacity and some of the methods that have been used to estimate 

storage capacity for different formation types. This section includes definitions of terms, 

references for information on various parameters, methods for estimating carbon dioxide storage 

capacity, and case studies. For additional information and recommendations, see Section 3.4 of 

the guidance, Demonstration of Storage Capacity.

Resources and Reserves

The concepts of resources and reserves are used to estimate the availability of mineral resources 

(e.g., in the oil and gas and mining fields). Similarly, the concepts of resources and reserves can 

be applied to carbon dioxide storage capacity. USDOE (2008a) makes a distinction between 

carbon dioxide resource estimates and carbon dioxide capacity estimates. A carbon dioxide 

resource estimate is defined as the volume of porous and permeable sedimentary rocks available 

for carbon dioxide storage and accessible to injected carbon dioxide via drilled and completed 

well bores. This assessment includes physical constraints, but it does not include economic or 

regulatory constraints. A carbon dioxide storage capacity estimate is an attempt to realistically 

include both the physical and economic constraints that determine the volume of rock available 

for storing carbon dioxide. The level of detail in storage capacity estimates depends on the scale 

and resolution of the assessment as illustrated in Figure A-22 (Bachu et al., 2007). Storage 

capacity estimates can be classified by degrees of certainty (Bachu et al., 2007; Bradshaw et al., 

2007) as described below and illustrated in Figure A-22. 

Theoretical Storage Capacity – This storage capacity estimate results in the least certainty. 

Bachu et al. (2007) describe it as representing the physical limit of what the geologic system can 

accept (e.g., entire pore space) or only the space from which the original fluids can be displaced 

(i.e., pore space minus the irreducible residual saturation of the initial fluid). The theoretical 

storage capacity typically represents a maximum upper limit to the capacity estimate; however, it 

is an unrealistic number as in practice there will always be physical, technical, and practical 

limitations that prevent full utilization of the theoretical storage capacity.
UIC Program Class VI Well A-51 

Site Characterization Guidance

Figure A-22: Variation in Size and Resolution of Various Storage Capacities. 

(a) resource pyramid and (b) data and assessment scales. From: Bachu et al. (2007); © Elsevier, reproduced with 

permission.

Effective Storage Capacity – This estimate is also known as “realistic capacity.” Bachu et al. 

(2007) note that it is obtained by applying a range of technical (geological and engineering) cutoff limits to a storage capacity assessment, which usually changes with the acquisition of new 

data and/or knowledge. 

Practical Storage Capacity – This estimate is also known as “viable capacity.” Bachu et al. 

(2007) describe it as obtained by considering both technical and practical challenges to safe 

carbon dioxide geological storage. This estimate is prone to changes over the life of a GS project 

as technology, policy, regulations and/or economics change. 

Matched Storage Capacity – This estimate yields the greatest certainty regarding carbon dioxide 

storage capacity. Bachu et al. (2007) describe it as a detailed matching of large stationary carbon 

dioxide sources with geological storage sites that are adequate in terms of capacity, injectivity 

and supply rate. 

Additionally, USGS has released a report on risk-based capacity estimates, which differs from 

the above estimates in that it uses fully probabilistic methods to incorporate geologic uncertainty 

in calculations of storage potential (Brennan et al., 2010). 

This section focuses on some methods that may be used to develop estimates of storage capacity 

for a GS project with the greatest certainty and highest level of detail.

Parameters and Data Interpretation

This section provides brief information on parameters that may be needed to estimate the volume 

(or mass) of carbon dioxide storage capacity, depending upon the method selected. Table A-3 

provides a summary of the types of methods available for quantifying parameters, such as 

laboratory methods and field testing, and estimating or predictive tools. Porosity, permeability, 

and injectivity (flow rate) are discussed in the guidance (Sections 2.3.5 and 4.5.2) and in Section 
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Site Characterization Guidance

A3 of this Appendix. Some recommended data sources for determining injection zone thickness, 

area, and background hydraulic gradient are discussed in Sections 2.3.1 and 2.3.3 of the guidance 

and Section A1 of this Appendix. Several of these parameters, such as capillary pressure, 

temperature, compressibility, water saturation, intrinsic and relative permeability, and porosity 

are also needed for the multiphase fluid modeling required for proposed Class VI injection well 

AoR delineations [40 CFR 146.84]. For more information on the required AoR modeling for a 

proposed Class VI injection well, see the UIC Program Class VI Well Area of Review Evaluation 

and Corrective Action Guidance. 

Table A-3: Parameters and Methods for Quantifying Storage Capacity. 

Parameter

Methods for Quantifying 

Parameters

Parameters for Estimating 

Storage Capacity

Laboratory Field Estimation or 

Prediction

Static 

Method

Material 

Balance

Reservoir 

Simulation

Pressure X X X X X

Fracture Pressure X X X

Temperature X X X

Compressibility X X X

Porosity* X X X X

Permeability* X X X X

Relative 

Permeability* X X X X 

Transmissibility X X X X

Interfacial Tension X X X

Water Saturation X X X X

Wettability X X

Capillary Pressure X X X X

Viscosity X X X X 

Density and Specific 

Gravity X X X X 

Mobility and 

Mobility Ratio X X 

Capillary and 

Gravitational 

Numbers

X X 

Injection Zone 

Thickness, Area and 

Background 

Hydraulic Gradient†

X X X X X 

Number of Wells X X X

Skin Factor X X X

Diffusion Coefficient 

and Dispersivity X X 

Sweep Efficiency X X

* Covered in Section A3 of the Appendix and in Section 2.3.5 of the guidance.

† Covered in Sections 2.3.3 and 2.3.8 of the guidance.
UIC Program Class VI Well A-53 

Site Characterization Guidance

Pressure

Formation pressure measurements are required by the Class VI Rule as part of the logging, 

sampling and testing required prior to injection well operation [40 CFR 146.87(c)]. Information 

on obtaining pore pressure measurements is provided in Section A4 of this Appendix. Additional 

information regarding types of pressure transducers is available in Harrison and Chauvel (2007) 

and from commercial manufacturers as well as in the UIC Program Class VI Well Testing and 

Monitoring Guidance. 

Fracture Pressure

Field methods such as step rate tests (see Section 4.4 of the guidance) can provide the required 

calculated information about the fracture pressure of both the injection and the confining zone(s) 

[40 CFR 146.87(d)(1)] that will support injection pressure limits in the Class VI permit. As noted 

by USDOE (2008a), all geological formations will begin propagating fractures upon reaching a 

threshold pressure; this site-specific threshold-pressure constraint is an important consideration 

in estimating carbon dioxide storage capacity.

A step rate test is performed by first shutting-in the well long enough for the bottom hole 

pressure to reach equilibrium with the formation pressure. This can be done by using a downhole 

pressure gauge with a surface readout and watching the gauge until the pressure stabilizes. 

Theoretical calculations of the time required to reach equilibrium are also available. A fluid is 

then injected at a constant rate while the downhole pressure is measured. The injection rate is 

held constant for a period of time that depends on the formation permeability. A typical injection 

step would be 1 hour for low permeability formations (less than 5 mD) and 1⁄2 hour for permeable 

formations (greater than 10 mD) (USEPA, 1999). After one injection step is completed, the 

injection rate is raised and another step is conducted. The pressure increments should be great 

enough to yield measurable pressure differences in the well and should cover the entire planned 

injection range. Injection rate is plotted versus pressure. The plot should initially be linear. 

Injection steps are continued until at least two data points are gathered past the point where the 

plot shows deviations from the linear trend; the intersection point of the two curves is the 

fracture pressure. After the last injection step, the well is shut-in again and the instantaneous 

pressure is recorded.

Temperature

Temperature sensors include mechanical (obsolete), thermistors (semiconductor material and 

highly sensitive), and resistance temperature detectors (wide temperature range and excellent 

accuracy). Prensky (1992) has described the determination of formation temperature and 

temperature gradients by the two-point or multiple-point average temperature gradient, whereby 

a linear relationship is assumed between the ambient surface temperature and the bottomhole 

temperature. Regression techniques can be used to calculate geothermal gradients for large data 

sets (Speece et al., 1985). Information regarding local and regional thermal gradients can also be 

obtained from reports generated by academic institutions and government agencies such as 

Nuccio and Condon (1996). The reader is referred to Bachu and Haug (2005) and Harrison and 

Chauvel (2007) for additional discussion and examples. 
UIC Program Class VI Well A-54 

Site Characterization Guidance

Compressibility

Rock compressibility data for a given reservoir can be obtained from laboratory measurements 

on core samples. In situations where laboratory analysis is not practical, rock compressibility 

values can be estimated from porosity overburden pressure as described by Craft and Hawkins 

(1959). Harrell and Cronquist (2007) provide a substitute correlation for estimating rock 

compressibility that depends on rock properties. Other values of rock compressibility have been 

reported as case studies in the literature (e.g., Law and Bachu, 1996; Ross et al., 2009). 

For carbon dioxide, equation-of-state models have been developed to predict carbon dioxide 

compressibility in multi-component two-phase systems (Firoozabadi et al., 1988). The 

compressibility of carbon dioxide can also be affected by SOx and NOx impurities, potentially 

affecting the estimated volume of carbon dioxide for storage; the reader is referred to Benson 

and Cook (2005) and Sass et al. (2005). 

Transmissibility 

In the field, vertical permeability (or transmissibility) can be estimated by transient tests 

generally classified as vertical interference testing or vertical pulse testing (Earlougher, 1977). 

For these types of tests, part of the well may be used for injection and part of the well may be 

used for pressure observation as illustrated in Figure A-23. Earlougher (1977) described several 

applications of vertical testing using type-curve matching methods. Additional discussion of 

pressure testing and analysis in gas injection wells is provided by Matthews and Russell (1967). 

Figure A-23: Vertical Interference or Pulse Test.

From: Earlougher (1977); © SPE, 1977, reproduced with permission; further reproduction prohibited without 

permission.

Interfacial Tension

Knowledge regarding the IFT between carbon dioxide and brine at in situ conditions is needed 

for precise measurements of capillary pressure, which in turn impacts relative permeability 
UIC Program Class VI Well A-55 

Site Characterization Guidance

(Bachu and Bennion, 2008). IFT is the surface tension at the interface of two immiscible fluids. 

Surface tension can be measured by a variety of laboratory methods such as the Du Noüy Ring 

method, the Wilhelmy Plate method, the spinning drop method, the pendant drop method, and 

other techniques. For additional information, see Bachu and Bennion (2008), del Rio and 

Neumann (1997), and Nobakht et al. (2007). 

IFT can also be estimated mathematically by an empirical power function of pressure, whereby 

the values of the coefficient and exponent depend on temperature and water salinity (Bachu and 

Bennion, 2009). Bachu and Bennion (2009) provide parameters for a range of temperature and 

salinity conditions representative of in situ carbon dioxide-brine systems. 

Water Saturation 

Water saturation (Sw) describes the fraction of water in a given pore space. It depends on particle 

size and interparticle porosity (Lucia, 1992). Water saturation is most often determined from 

resistivity log measurements combined with knowledge of porosity, water resistivity, and shale 

volume (Alberty, 1992b). Water saturation values range from 0 (completely dry) to 1 

(completely saturated). For additional information, see Alberty (1992b). Water saturation can 

also be determined from cores, for example from capillary pressure testing and other laboratory 

methods that involve expelling and measuring the formation water or other fluids (Ringen et al., 

2001). 

Wettability

In a solid, porous medium in contact with two or more fluid phases, wettability is the ability of 

one of the fluid phases (the wetting phase) to contact the solid preferentially over other phase(s) 

(Donaldson and Tiab, 2003) (Figure A-24). Wettability has important consequences for the 

relative permeability and Pe (see below) of pore fluids. These two parameters, in turn, affect the 

sealing and storage capacities of subsurface units (Chiquet et al., 2007; Li et al., 2005). 

Wettability can be observed directly in the laboratory by measuring the contact angle between 

the solid portions of the formation and formation fluids (Chiquet et al., 2007) or can be inferred 

using either the Amott method or the USBM (United States Bureau of Mines) test (Donaldson 

and Tiab, 2003). There are no established techniques for downhole field measurement of 

wettability.

Salinity, temperature, and pressure can all affect wettability (Donaldson and Tiab, 2003), and 

wettability measurements will be most applicable if they are taken under conditions that 

approximate those found within the formation of interest. Additionally, micromodels are 

currently being developed that will be able to predict changes in wetting phase behavior as 

reservoir conditions change (PNNL, 2010). These may be useful if the reproduction of reservoir 

conditions is not possible in the laboratory. 
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Site Characterization Guidance

Figure A-24: A Diagram Demonstrating Wetting Angle.

The wetting angle is (180-θ).A fluid with a low wetting angle (at right) and a fluid with a moderate wetting angle (at 

left) on the same substrate. The fluid with the lower wetting angle would be the wetting phase if both fluids were

present in the interconnected pore space of a solid made of the material upon which the wetting angle is being 

measured. 

Capillary Pressure

Capillary pressure is the minimum pressure required for an immiscible non-wetting fluid to 

overcome capillary and interfacial forces and enter pore space containing the wetting fluid. For 

carbon dioxide injection into a saline formation, the non-wetting fluid is carbon dioxide and the 

wetting fluid is the native brine. Capillary pressure has been shown to be affected by IFT and 

pore-size characteristics, as well as in situ pressure, temperature, and water salinity (Bachu and 

Bennion, 2008; Wollenweber et al, 2010). Capillary pressure relationships for porous media are 

typically reported as a function of the wetting phase saturation, and the capillary pressure curves 

generated by laboratory testing can be used to estimate the irreducible wetting phase saturation 

of the carbon dioxide/brine/rock system. Mathematical models have also been developed to 

predict capillary pressure relationships (e.g., Van Genuchten, 1980). Figure A-25 shows capillary 

pressure curves used in a simulation of carbon dioxide storage in saline formations (Ide et al., 

2007). 

Figure A-25: Capillary Pressure (Drainage and Imbibitions) as a Function of Wetting Phase Saturation.

Generated using the Van Ganuchten Formulation. From: Ide et al. (2007); © Elsevier, reproduced with permission.
UIC Program Class VI Well A-57 

Site Characterization Guidance

Reservoir capillary pressure relationships can be evaluated in the laboratory using the porous 

plate or centrifuge method (which uses actual or simulated fluids), or the mercury injection 

method (which simulates the wetting characteristics of the reservoir) (Vavra et al., 1992); 

descriptions are provided in Section A3. 

Several techniques have been developed to measure capillary pressure in situ. Kuchuk et al. 

(2008) used a permanent downhole electrode array using time lapse resistivity in combination 

with pressure and flow readings to determine the capillary pressure and other properties of the 

formation downhole. Vinegar and Waxman (1984) mention the use of polarization logging 

measurements to determine pore size distribution. The capillary pressure is estimated from the 

pore size distribution. Others have used nuclear magnetism logging (NML) to estimate capillary 

pressure. NML has a very short effective range and returns a volume average of the capillary 

pressure. Freeman (1984) used wireline data consisting of pressure readings with water 

saturation and porosity data to estimate capillary pressure. Proett et al. (2003) proposed the use 

of data from a pump-out of drilling mud after drilling to determine capillary pressure. They 

measured pressure, flow, and fluid properties during the pump-out and used an algorithm to 

determine the capillary pressure.

Most of the available in situ methods determine the capillary pressure indirectly using data from 

downhole logs and algorithms based on certain assumptions. The accuracy of the methods likely 

depends on how closely the formation being tested resembles the assumptions made in 

developing the algorithm. These methods may not be as accurate as laboratory data, but 

generally can be done more quickly under in situ conditions.

Viscosity

Viscosity is a property of a fluid that measures resistance to shear stress. In the centimeter gram 

second (CGS) system, the unit of viscosity is the poise, which is 1 g·cm-1

·s

-1. The ratio of 

viscosity to density is called the kinematic viscosity, which has the units of stoke or cm2

s

-1. 

Viscosity can be measured in the laboratory with various types of viscometers (e.g., u-tube, 

falling piston, oscillating, vibrational, rotational, bubble, and other types of viscometers). Close 

temperature control is essential for accurate measurements. ASTM International maintains 

standard methods for viscosity measurements (www.astm.org). 

In situ, real-time direct measurements of viscosity can be collected at reservoir conditions using 

a wireline formation tester such as a tool described by O’Keefe et al. (2007). The tool measures 

the thermophysical properties of the fluid by the vibration of a mechanical resonator submersed 

in the flowline fluid, and the instrument measures viscosity in the range of 0.25 to 50 cP with a 

reported accuracy of ±10%.

Density and Specific Gravity

In the field, the in situ density of the formation fluid can be measured during open-hole sampling 

of reservoir fluids using a wireline formation tester (O’Keefe et al., 2007). The density of 

subsurface formations can be determined by formation density and combined neutron and 

density logs (Hancock, 1992; Section A7) and the borehole gravity meter (Herring, 1992). 
UIC Program Class VI Well A-58 

Site Characterization Guidance

Carbon dioxide density can be estimated by the Peng-Robison equation of state (Peng and 

Robinson, 1976) using available software such as the CMG Winprop module (Computer 

Modeling Group, Ltd., Canada) as described by Nobakht et al. (2007). Carbon dioxide density 

increases with depth (local pressure gradient) (Figure A-26) and decreases with increasing 

geothermal gradient (Kovscek, 2002). Brine density can be predicted at in situ temperature, 

salinity, and pressure conditions by several algorithms as discussed by Adams and Bachu (2002). 

Other algorithms for predicting density of carbon dioxide-brine mixtures are described by 

Hassanzadeh et al. (2008). 

Figure A-26: Density of Carbon Dioxide as a Function of Depth.

© CO2CRC, 2010, reproduced with Permission.

Mobility and Mobility Ratio 

The mobility of a phase is defined as its relative permeability divided by its viscosity (Warner, 

2007; Kopp et al., 2009a; 2009b; Craig, 1980). Mobility combines a rock property, relative 

permeability (dependent only on the saturation of the two fluid phases and the capillary pressure) 
UIC Program Class VI Well A-59 

Site Characterization Guidance

(Bachu and Bennion, 2008), with a fluid property, viscosity. Mathematically, mobility is 

expressed as: 

λi = k

μ

i

i

 Equation 7 

where λi is the mobility of fluid phase i, ki is the effective permeability of fluid phase i, and μi is 

the viscosity of fluid phase i. (Relative permeability is discussed in Section 2.3.5 of the guidance 

and in Section A3 of this Appendix.) Low-viscosity fluids generally have high mobility and 

high-viscosity fluids generally have low mobility. The mobility ratio (M) generally is defined as 

the mobility of the displacing phase (carbon dioxide for sequestration) divided by the mobility of 

the displaced phase (e.g., fluid in a saline formation). 

M is considered to be either “favorable” or “unfavorable.” A favorable mobility ratio is a low 

value (M ≤ 1), which means that the displaced fluid (water) has a higher mobility than the 

displacing phase (carbon dioxide). An unfavorable mobility ratio (M > 1) means that the 

displacing fluid has a higher mobility than the displaced fluid. In practical terms, a favorable 

mobility ratio means that the displaced water phase can move more quickly through the reservoir 

rock than the displacing carbon dioxide phase. More importantly, an unfavorable or large M

value tends to give rise to rapid migration of carbon dioxide along paths of least resistance. 

Typical values for M for reservoir conditions of interest in sequestration are 2–10. 

Viscous fingering can cause carbon dioxide to bypass much of the pore space, depending on the 

heterogeneity and anisotropy of rock permeability, because supercritical carbon dioxide is much 

less viscous than water and oil. Benson and Cook (2005) noted that only some of the resident oil 

or water will be displaced during carbon dioxide injection because of the comparatively high 

mobility of carbon dioxide, thus leading to an average saturation of carbon dioxide in the range 

of 30–60% during storage in the reservoir. 

Capillary and Gravitational Numbers 

In addition to mobility, the displacement process will be driven by capillary and buoyancy 

forces. The capillary number (Ca) is defined as the ratio of capillary forces to viscous forces 

(Kopp et al., 2009a). As carbon dioxide migrates through a formation, some of it is retained in 

the pore space by capillary forces, known as residual carbon dioxide trapping. 

The Ca is defined as the ratio of capillary forces to viscous forces and can be used to characterize 

the extent of carbon dioxide trapping in an injection zone. As carbon dioxide migrates through a 

formation, some of it is retained in the pore space by capillary forces, known as residual carbon 

dioxide trapping. Kopp et al. (2009a) examined the effect of Ca on storage capacity and 

concluded that a higher Ca is expected to be associated with a lower average carbon dioxide 

saturation. This expectation is based on the occurrence of stronger capillary forces associated 

with higher Ca values, thus leading to a smoother displacement front during the imbibition 

process, and resulting in a lower, non-wetting phase (carbon dioxide) saturation in the swept area 

behind the brine displacement front. 
UIC Program Class VI Well A-60 

Site Characterization Guidance

The Gravitational number (Gr) is defined as the ratio of the gravitational (buoyancy) forces to 

the viscous forces (Kopp et al., 2009a; Bryant and Lake, 2005, Chp 18). The type of fluid in the 

reservoir will influence the magnitude of the buoyancy forces that drive vertical flow of carbon 

dioxide in an injection zone (Benson and Cook, 2005). For example, the comparatively large 

density difference between carbon dioxide and formation water creates strong buoyancy forces 

that drive carbon dioxide upwards. In oil reservoirs, the density difference and buoyancy forces 

are less, particularly if oil and carbon dioxide are miscible. In gas reservoirs, carbon dioxide 

migrates downward because carbon dioxide is more dense than natural gas. Gr can therefore be 

used to predict the tendency of flow direction during the injection phase. 

Number of Wells

 

Projects that employ multiple injection wells at a site can accelerate the volume of carbon 

dioxide injected into storage reservoirs. According to Michael et al. (2010), comparable carbon 

dioxide injection rates can be achieved in a low-permeability storage reservoir as in a highpermeability reservoir by increasing the number of injection wells. Bachu et al. (2007) and 

Gibson-Poole et al. (2005) also discussed the benefits of increasing the number of injection wells 

to improve injectivity in low-permeability rocks. However, if a storage reservoir already has a 

number of wells that penetrate the reservoir, then there may be a risk of leakage during carbon 

dioxide injection. For example, Gasda et al. (2004) studied clusters of wells that were previously 

drilled for hydrocarbon extraction in the Viking Formation, and they concluded that the number 

of wells that could potentially serve as leakage pathways during injection depends upon whether 

the injection well is located in an area with a high or low density of pre-existing wells. 

Skin Factor

 

The skin effect or skin factor represents restricted entry into the formation associated with 

damaged formation near the well bore. In well bores where skin effects are a concern, injectivity 

can be enhanced by stimulating (e.g., by acid treatment) or by performing a workover (e.g., 

added perforations) of the injection well (Gidley, 1992; Osborne, 1992). 

The concept of skin effect is illustrated in Figure A-27, which shows the pressure distribution 

from the well bore (bottomhole) flowing pressure, pwf, to the reservoir pressure, pR for ideal and 

actual conditions (Golan, 1992). The difference between actual and ideal conditions in the 

damaged near-well bore region corresponds with the pressure drop associated with the skin 

effect. For additional information, including estimation of the skin factor, see Golan (1992), 

Lancaster (1992), Lee (1992), and Lee (2007). 
UIC Program Class VI Well A-61 

Site Characterization Guidance

Figure A-27: A Schematic of the Skin Effect.

PR = Reservoir Pressure, Pwf = well bore (bottomhole) flowing pressure, P’wf = ideal well bore flowing pressure, 

ΔPskin = P’wf – Pwf, rw = well bore radius, ra = radius of skin zone, re = radius of drainage. q represents pressure 

profile under steady state conditions with no skin effect. From: Golan (1992); © AAPG 1992, by permission of the 

AAPG whose permission is required for further use.

Diffusion Coefficient and Dispersivity

Molecular diffusion is defined as the net transport of a molecule in a liquid or gas medium as a 

result of intermolecular collisions and driven by a gradient through the medium such as 

temperature, pressure, or concentration (Tucker and Nelken, 1990). The diffusion coefficient or 

diffusivity is defined as the ratio of the net mass flux per unit gradient, and the rate of diffusion is 

a function of the properties of the compound as well as the medium through which the compound 

moves (Tucker and Nelken, 1990). Dispersion is controlled by the intensity of turbulent mixing 

rather than molecular diffusion. Methods for estimating values of diffusion coefficient and 

dispersivity are summarized by Tucker and Nelken (1990). 

Sweep Efficiency

Volumetric sweep efficiency EV is a term commonly used in the petroleum industry to represent 

the ratio of the volume of fluid contacted by a displacing agent to the volume of fluid originally 

in place. Values of EV range from 0 to 1 (or 0 to 100%) and are typically in the range of 40% to 

60% for water flooding processes for hydrocarbon extraction from reservoirs (Lake, 1989). 

Volumetric sweep efficiency can be further defined as the product of areal sweep efficiency EA

and vertical sweep efficiency E whereby (Lake, 1989; Craig, 1980; Warner, 2007): 

E

I

V = EAEI Equation 8 

Areal sweep efficiency EA is generally used in the petroleum industry to represent the ratio of the 

area contacted by the displacing agent to the total area, and vertical sweep efficiency EI is used to 

characterize the ratio of the cross-sectional area contacted by the displacing agent to the total 

cross-sectional area (Lake, 1989; Craig, 1980; Warner 2007). Several correlations have been 
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Site Characterization Guidance

developed and reported in the petroleum literature for estimating sweep efficiency through 

porous media for various well field injection patterns and simplifying assumptions (Craig, 1980). 

Methods for Storage Capacity Estimation 

Methods for estimating carbon dioxide storage capacity can be divided into static and dynamic 

models (USDOE, 2008a). Static models are typically used for estimating carbon dioxide storage 

capacity prior to injection, although static models can also be used for estimating storage after 

injection commences. Dynamic models are typically employed after injection commences. The 

application of static and dynamic models for estimating carbon dioxide storage capacity is based 

on methods routinely used for estimating petroleum reserves, ground water resources, 

underground natural gas storage, and in the UIC Program. Parameters typically used to calculate 

storage capacity are listed in Table A-3. Additional discussion regarding static and dynamic 

modeling methods for estimating carbon dioxide storage is provided below. 

Static Models

Static models are typically used for estimating carbon dioxide storage capacity prior to the 

startup of injection. Static models, which include volumetric and compressibility methods, rely 

on parameters that are directly related to the geologic description of the area for injection such as 

porosity, area, thickness and compressibility (USDOE, 2008a and 2008b). Standardized 

methodologies for estimating carbon dioxide storage capacity in geological media (coal beds, oil 

and gas reservoirs, and deep saline formations) using static models have been adopted the 

Carbon Sequestration Leadership Forum (http://www.cslforum.org). These methodologies, as 

described by Bachu et al. (2007), are summarized below. 

Coal Beds 

The carbon dioxide storage capacity of a suitable coal bed can be estimated based on analogy 

with estimating the total gas in place (capacity) and reservoir deliverability (White et al., 2005). 

For a coal bed with gas already adsorbed by the coal, the initial gas in place (IGIP) can be 

calculated by the relation (Bachu et al., 2007; White et al., 2005): 

IGIP = A × h × nC × GC × (1 − fa − fm) Equation 9 

where A is the area and h is the effective thickness of the coal zone, nC is the bulk coal density 

(generally assumed to be 1.4 t/m3), GC is the coal gas content, and fa and fm are the ash and 

moisture weight content fractions of the coal, respectively. The coal gas adsorption capacity can 

be assumed to follow a pressure-dependent Langmuir isotherm in the form:

GCS = VL

P

P+PL

Equation 10 

where GCS is the gas content at saturation, P is the pressure, and VL and PL are Langmuir volume 

and pressure, respectively. These relations are based on the assumptions that coal has a high 

affinity for carbon dioxide, 100% saturation is achieved, and all of the coal is accessed by the 
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injected carbon dioxide. To estimate the effective carbon dioxide storage capacity in coal beds, 

the analogy is drawn to the estimation of the producible gas in place (PGIP) from the IGIP with 

the relation:

PGIP = Rf × C × IGIP Equation 11 

where Rf is the recovery factor and C is the completion factor (or effective contact area). The 

completion factor is an estimate of the coal thickness that will contribute to gas production or 

storage. It should be noted that there are limited field data for quantification of the recovery 

factor (Bachu et al., 2007). 

Oil and Gas Reservoirs 

Calculation of carbon dioxide storage capacity for depleted oil and gas reservoirs is based on the 

assumption that the same storage volume is available for injected carbon dioxide as was 

previously occupied by the extracted hydrocarbons (Bachu et al., 2007). This condition may be 

altered, for example, in the case of formation water invading a pressure-depleted reservoir. 

Another assumption is that carbon dioxide injection will continue until the pressure is restored to 

its original reservoir condition. As discussed previously, the re-pressurization of a depleted 

reservoir may be problematic with regard to the integrity of the reservoir and/or cap rock; thus, 

the maximum sustainable pore pressure may need to be lower than the original reservoir 

pressure.

An equation for calculating the carbon dioxide storage capacity in oil and gas reservoirs is based 

on the geometry of the reservoir (Bachu et al., 2007): 

where: 

MCO2t = theoretical mass storage capacity for carbon dioxide in a reservoir at in situ

conditions [M] 

ρCO2r = carbon dioxide density at reservoir conditions [ML-3] 

Rf = recovery factor [dimensionless]

A = reservoir area [L2

] 

h = thickness [L]

ø = porosity [dimensionless] 

Sw = water saturation [dimensionless]

Viw = volume of injected water [L3

] 

Vpw = volume of produced water [L3] 

Bachu et al. (2007) provide alternative relations that account for fluid compressibility in gas 

reservoirs: 
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Site Characterization Guidance

and for fluid compressibility in oil reservoirs: 

where OGIP and OOIP represent the original gas and oil in place at surface conditions, FIG is the 

fraction of injected gas, Bf is the formation volume factor that converts oil volume from standard 

conditions to in situ conditions, Viw and Vpw are the volumes of injected and produced gas, P, T, 

and Z are pressure, temperature, and gas compressibility, respectively, and the subscripts r and s

represent reservoir and surface conditions. 

The effective storage capacity can be influenced by the historical operation of the oil and gas 

reservoir (i.e., pressure depletion and formation water influx), thus reducing the total available 

capacity for carbon dioxide storage. The effective carbon dioxide storage capacity can also be 

influenced by carbon dioxide mobility, fluid density differences, reservoir heterogeneity, and 

residual water saturation. These influences can be combined to represent an efficiency factor for 

estimating an effective storage capacity (Bachu et al., 2007; Doughty and Pruess, 2004): 

MCO2e = CmCbChCwCaMCO2t ≡ CeMCO2t Equation 15 

where MCO2e is the effective reservoir carbon dioxide storage capacity, MCO2t is the theoretical 

mass storage capacity of carbon dioxide in a reservoir at in situ conditions, and the coefficient Ce

is a single effective capacity coefficient that incorporates the cumulative effects of the other 

coefficients represented by subscripts m for mobility, b for buoyancy, h for heterogeneity, w for 

water saturation, and a for formation strength. Currently, limited data are available for estimating 

values for Ce. 

Deep Saline Formations 

For deep saline formations, carbon dioxide storage capacity estimates can be developed for 

structural and stratigraphic traps, residual gas traps, solubility traps, mineral traps, and 

hydrodynamic traps (Bachu et al., 2007) as described below. 

For structural and stratigraphic traps, the formation is initially saturated with water (instead of 

hydrocarbons), and the theoretical volume available for carbon dioxide storage, VCO2t, can be 

calculated by the relation (Bachu et al., 2007): 

VCO2t = Ah∅(1 − Swirr) Equation 16 

where A is the reservoir area, h is thickness, φ is porosity, and Swirr is the irreducible water 

saturation. Similar to oil and gas reservoirs, the effective carbon dioxide storage volume, VCO2e, 

can be estimated by:

VCO2e = CcVCO2t Equation 17 
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Site Characterization Guidance

where Cc is a capacity coefficient that represents the effects of heterogeneity, buoyancy, and 

sweep efficiency, and it can be determined through numerical simulation and/or field study. 

Okwen et al. (2010) developed a method for estimating carbon dioxide storage efficiency 

applicable to structural and stratigraphic trapping that can be characterized by carbon dioxide 

mobility, buoyancy forces, and residual saturation. The mass of carbon dioxide that corresponds 

to the effective storage volume can be estimated by multiplying VCO2e by carbon dioxide density 

at storage temperature and pressure conditions. 

Residual gas traps form within a saline formation when injected carbon dioxide migrates 

through the porous media and water moves back into the pore space. For example, during 

injection, carbon dioxide can migrate laterally and upward due to buoyancy forces. Once 

injection stops, carbon dioxide can continue to migrate, water enters the pore space, and residual, 

immobile carbon dioxide is left behind the plume (Juanes et al., 2006). Qi et al. (2009) proposed 

an injection strategy whereby carbon dioxide and brine are injected together and thus maximize 

storage efficiency in formations. The theoretical carbon dioxide storage volume of the residual 

gas traps can then be estimated by the relation (Bachu et al., 2007):

VCO2t = ∆Vtrap∅SCO2t Equation 18 

where ∆Vtrap represents the carbon dioxide-invaded rock volume and SCO2t is the trapped carbon 

dioxide saturation. ∆Vtrap and SCO2t can be estimated through numerical simulations (e.g., Juanes 

et al., 2006). The mass of stored carbon dioxide can be estimated by multiplying the storage 

volume by carbon dioxide density at in situ conditions. 

Solubility trapping of carbon dioxide is a relatively slow process and is assumed to become 

significant after cessation of injection (Bachu et al., 2007). Although dissolution of free-phase 

carbon dioxide occurs rapidly, and water in direct contact with injected carbon rapidly becomes 

saturated with carbon dioxide, the available contact area between free-phase carbon dioxide and 

unsaturated water is small, greatly limiting solubility trapping. When migration of carbon 

dioxide has stopped (thus reducing the influence of dispersion), then diffusion, which is very 

small, becomes the only mechanism enabling unsaturated water to contact carbon dioxide unless 

the water itself is moving. If a hydraulic gradient within the formation replaces the carbon 

dioxide-saturated water with unsaturated water, or the rock permeability and thickness are 

conducive to the development of convection within the pore system, then carbon dioxide will 

continue to dissolve into the unsaturated water that passes the contact area. The theoretical mass 

carbon dioxide storage capacity can be estimated using a simplified relation and average values 

for formation thickness, porosity, and carbon dioxide content in formation fluid as (Bachu et al., 

2007): 

where ρ is the density of the formation water, XCO2 is the mass fraction carbon dioxide content in 

formation water, and the subscripts 0 and S represent initial and saturated carbon dioxide content, 

respectively. Similar to the relations for coal beds and oil and gas reservoirs, the mass carbon 
UIC Program Class VI Well A-66 

Site Characterization Guidance

dioxide storage capacity can be estimated by multiplying the theoretical value by a coefficient 

that includes the effects of spreading and dissolution of carbon dioxide in the whole formation. 

However, for a site-specific application, the theoretical carbon dioxide storage capacity 

associated with solubility trapping should be assessed by numerical modeling (Bachu et al., 

2007). 

Mineral trapping of carbon dioxide depends on the chemical composition of the rock matrix and 

formation waters, in situ temperature and pressure conditions, the interface between the mineral 

grains and the formation water containing dissolved carbon dioxide, and the flow of fluids past 

the interface (Bachu et al., 2007). For site-specific applications, the amount and time frame of 

carbon dioxide storage associated with mineral trapping should be estimated by numerical 

modeling and supported, where possible, with laboratory testing and field data.

Hydrodynamic trapping of carbon dioxide is a combination of mechanisms (structural and 

stratigraphic trapping, dissolution, mineral precipitation, residual gas trapping) operating 

simultaneously, but at different rates, while an injected plume of carbon dioxide expands and 

migrates in a storage reservoir (Bachu et al., 2007). Carbon dioxide storage capacity associated 

with hydrodynamic trapping therefore needs to be evaluated at a specific point in time as the sum 

of the component mechanisms by numerical simulations. 

Dynamic Models

Dynamic models are generally considered applicable for estimating carbon dioxide storage 

capacity after initiation of carbon dioxide injection (USDOE, 2008a). They would therefore be 

useful after receiving a permit to operate a Class VI injection well, as a way to monitor storage 

capacity over time. Dynamic models include decline curve analysis, material balance, and 

reservoir simulation. 

Decline Curve Analysis

The decline curve analysis is a dynamic method for estimating subsurface storage volumes based 

on a simple exponential relation of injection rate and time (USDOE, 2008a): 

qCO2 = qCO2ie−Dt Equation 20 

 

where qCO2 is the carbon dioxide injection rate and the subscript i denotes the initial injection 

rate, D is a decline coefficient that represents flow characteristics of the formation, and t

represents time. Carbon dioxide storage capacity, GCO2, can be estimated by the relation:

GCO2 = (qCO2i−qCO2)

D Equation 21 

where the decline coefficient D is determined from the exponential decline equation for a given 

injection rate history. This decline curve analysis is generally considered applicable to individual 

wells or entire fields, provided the exponential trend exists. Additional information regarding 

theory and application of decline curve analysis techniques is provided in Arps (1962), Campbell 
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Site Characterization Guidance

and Campbell (1978), and Li and Horne (2003). This relation can be used to estimate carbon 

dioxide storage capacity likely to be attained with continued injection. 

Material Balance 

The material balance method for estimating carbon dioxide storage capacity is based on the 

relationship between cumulative carbon dioxide injection and the corresponding pore pressure as 

a function of time (USDOE, 2008a). The relation is analogous to the p/z plots used in gas 

reservoirs and underground gas storage reservoirs (e.g., Harrell and Cronquist, 2007), where z is 

the gas compressibility factor of carbon dioxide evaluated at pressure p. A straight line is 

expected on a plot of p/z versus cumulative carbon dioxide gas injection. The carbon dioxide 

storage capacity can be estimated from this plot by extrapolating the curve and determining the 

value of cumulative carbon dioxide gas injection that corresponds to the maximum p/z value at 

capacity pressure. 

Reservoir Simulation

Reservoir simulation is considered the most advanced method for estimating carbon dioxide 

storage capacity, provided the input data adequately represent the injection formation and 

operating conditions (USDOE, 2008a). The purpose of simulation is to estimate field 

performance under one or more operational schemes (Batycky et al., 2007). For example, the 

simulation can be used to study actual field or pilot performance and thus improve estimates for 

carbon dioxide storage capacity. As discussed previously, reservoir simulation can be also used 

to develop estimates of specific carbon dioxide storage trapping mechanisms (e.g., 

hydrodynamic trapping). Reservoir simulation is the most resource-intensive method of 

estimating carbon dioxide storage. However, it requires the input of data at a scale and resolution 

appropriate for obtaining results at formation scale. Additional discussion regarding reservoir 

simulation is provided in the UIC Program Class VI Well Area of Review Evaluation and 

Corrective Action Guidance. 
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Site Characterization Guidance

A8. Information to Support Pre-Injection Logging and Testing 

To support submittal of the well logs required at 40 CFR 146.87, this section describes various 

types of logs that can be used during formation testing. This information supplements Section 4.1 

of the guidance.

Gamma ray logs measure the natural radioactivity emitted by radioactive isotopes (e.g., 

potassium, thorium, and uranium) in minerals. Gamma ray logs are the most common log run for 

stratigraphic correlation because they are relatively unambiguous and easy to interpret by a 

qualified analyst (Evenick, 2008) (Figure A-28). The intensity of radioactivity is measured by a 

scintillation counter in American Petroleum Institute (API) units (Evenick, 2008). Because clays 

tend to have higher concentrations of potassium and thorium than other minerals, gamma ray 

logs can provide information on the clay and mica content (or “shaliness”) of the formation 

(Johnson and Pile, 2006). The log curve can also be compared to a section with 100% or 0% 

shale saturation to determine a “shale baseline” and calculate the percent of shale present in other 

regions of the log (Johnson and Pile, 2006). 

The spectral gamma ray tool, an advanced version of the gamma ray tool, allows for the 

identification of gamma ray counts caused by specific elements. This allows for the removal of 

gamma ray counts caused by uranium, which is often deposited by formation fluids, although it 

is also found in some sandstones and carbonates (Johnson and Pile, 2006). Gamma ray logs are 

virtually unaffected by changes in porosity (Johnson and Pile, 2006). 

Spontaneous potential (SP) logs show naturally occurring differences in electric potential 

(usually measured in millivolts, mV) due to salinity differences between the drilling mud and 

formation fluids, and between formation fluids in different units (Johnson and Pile, 2006). The 

SP response can be used to correlate formations between wells, determine permeability, and 

estimate formation fluid resistivity (Evenick, 2008; Alberty, 1992b; Hancock, 1992). Because SP 

logs reflect differences in electric potential, contrasts in permeability and salinity between 

formations are critical (see Figure A-28). Although not good for identifying general lithology, SP 

logs can help in differentiating shales from carbonates or sandstones, and they work best when 

shale layers separate more permeable formations (Evenick, 2008; Johnson and Pile, 2006). 

Hancock (1992) describes other conditions where SP logs are not applicable or difficult to 

interpret.

The SP response typically varies by lithology and can be used to correlate formations between 

wells, determine permeability, and estimate formation fluid resistivity (Alberty, 1992b; Hancock, 

1992). Because SP logs reflect differences in electric potential, contrasts in permeability and 

salinity between formations are critical (see Figure A-28). SP logs are influenced by the presence 

of impermeable limestones and work best when shale layers separate more permeable formations 

(Johnson and Pile, 2006). Hancock (1992) describes other conditions where SP logs are not 

applicable or difficult to interpret. 

SP logs can be challenging to correlate because they are not good indicators of lithologic 

boundaries (Evenick, 2008). With the advent of other more specialized and better resolved 

techniques, the role of SP logs has been gradually diminished (Blackbourn, 1990). 
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Site Characterization Guidance

Figure A-28: Example of Geophysical Well Logs. 

Caliper logs show the measured diameter of the borehole. A caliper log can be used as a crude 

lithologic indicator by comparing the caliper reading to the size of the drill bit, as shown in Table 

A-4. Different rock and sediment types show different responses on the caliper log, depending on 

properties such as permeability and level of consolidation. Hancock (1992) describes the various 

responses that indicate specific lithologies. In general, shales, coals, and bentonites tend to wash 

out with drilling (Evenick, 2008). 
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Site Characterization Guidance

Table A-4: Interpreting Borehole Condition from Caliper Readings.

Well Bore Larger than 

Expected

Well Bore as 

Expected

Well Bore Smaller than 

Expected

Indicated by Caliper > Bit size Caliper = Bit size Caliper < Bit size

Possible Rock 

Characteristics Soft or Fractured Hard / Unfractured Permeable

Possible Cause Wash Out Mud-cake Accumulation

Porosity Logs 

Porosity logs are a class of geophysical logs that indirectly measure formation porosity, and 

include density, neutron, sonic, and magnetic resonance logs, which are individually described 

below. Typically, multiple logs are run simultaneously, and the results from the multiple logs can 

be interpreted to estimate porosity and formation lithology (AAPG, 2004). All of these logs 

would not necessarily need to be run to comply with the Class VI Rule porosity logging 

requirements. Rather, a suite of porosity logs may be run based on site conditions, owner or 

operator preferences, and as approved by the UIC Program Director. 

• Sonic logs record the sound wave transit time between a source and receiver(s) through 

the rock formation. The transit time depends on the lithology and porosity of the 

formation, so it is necessary to determine or estimate lithology to measure porosity from 

a sonic log. Lithology may be known through core analysis, interpretation of other logs, 

or interpretation of sonic logs simultaneously with other porosity logs. For shale-free 

lithologies, the transit time is frequently related to porosity and mineral fractions. 

Estimates of porosity provided by sonic logs are categorized as primary porosities which 

excludes vugs and fractures that can be important in many carbonate sequences. 

Additionally, the presence of hydrocarbons in a formation will increase the interval 

transit time, and this effect is corrected for prior to estimating porosity (AAPG, 2004); 

owners or operators of GS projects in depleted reservoirs should bear this in mind when 

selecting porosity logs; 

• Density logs measure the bulk density of the formation, including the densities of the 

rock and the pore fluid. The logs reflect changes in the rock composition, the porosity, 

and the contained fluids. The logging device consists of a gamma ray source and two 

detectors; this arrangement allows the results to be compensated for variable rugosity 

(roughness) and mud-cake thickness (Johnson and Pile, 2006). Porosity determination 

requires an average value for matrix density which may vary both between and within 

formations. Bulk densities from logs and laboratory-measured core porosities can be used 

to establish correlations between density and porosity for a particular interval. An 

example with density log included as a component of a porosity log is presented in Figure 

A-29;

• Neutron logs measure the hydrogen concentration in both pore fluids and in chemically 

bound water. In shale-free formations, hydrogen atoms are present primarily in the water 

phase, and neutron logs therefore measure aqueous fluid-filled porosity. Low 

measurement results from the neutron logger correspond to larger porosity values. 
UIC Program Class VI Well A-71 

Site Characterization Guidance

Similar to density logs and sonic logs, neutron log responses are dependent on formation 

lithology. Additionally, the presence of gas within the pores affects the neutron log 

response and also needs to be considered in selecting appropriate logs. The neutron log 

measure of porosity is overestimated in shales because hydrogen atoms are present within 

the clay structure in addition to pore water. An example neutron porosity log included as 

a component of a porosity log is presented in Figure A-29; and

• Nuclear magnetic resonance (NMR) logs measure the free precession of proton nuclear 

magnetic moments in the earth’s magnetic field. Hydrogen protons in solids or bound to 

surfaces show differences in responses compared to bulk fluids in pore space. Therefore, 

these logs can be used to determine residual water saturation, the effective porosity, 

permeability, pore size distribution, and residual oil saturation. Compared to the other 

porosity logging techniques discussed below, NMR logging porosity estimates are 

insensitive to formation lithology type, and therefore the NMR log may be run alone as a 

porosity log. 

 

As noted above, the response of sonic logs, density logs, and neutron logs depend not only on the 

porosity of the formation, but also the lithology. Common lithologies that may be encountered 

include sandstone, limestone, dolomite, anhydrite, and salt. Accurately calculating porosity from 

the measurement response requires that the lithology at each depth be known or estimated based 

on core analyses or other available information (see Sections 2.3.4 and 4.2). However, both 

lithology and porosity can be inferred if at least two of the above-mentioned logs are run and 

interpreted concurrently. This is possible using established relationships for the response from 

several logging tools. See AAPG (2004) for detailed information regarding porosity log 

measurement combinations and interpretation. 
UIC Program Class VI Well A-72 

Site Characterization Guidance

Figure A-29: Example Porosity Log, Including Density (Red) and Neutron (Blue) Logs, for the 

Cincinnati Arch Validation Test Well.

From: Battelle Memorial Institute.

Fracture Finder Logs

Several types of logs may be used for fracture detection, including sonic logs and a number of 

borehole imaging logs (Telford et al., 1990; AAPG, 1994). Not all logs discussed below must be 

run to comply with the Class VI Rule fracture finder logging requirements. Rather, a single type 

of fracture finder log may be run based on site conditions and operator preferences, and as 

approved by the UIC Program Director. 

• Sonic logs, described above, can also be used for fracture detection. The logging tool 

provides a sonic signal, and the resulting log is a vertical graph of the amplitude and 

travel time of the reflected signal. A decrease in amplitude where sonic travel time is 

constant may indicate open fractures (Telford et al., 1990). As described above, sonic 

logs measure primary porosity, which excludes fractures. However, used with either 

neutron or density logs, both of which provide an estimate of the total porosity, sonic logs 

would yield an estimate of the proportion of vugs and fractures as secondary porosity; 

• Borehole televiewers, also termed acoustic borehole images, make use of reflected sonic 

waves. The recorded sonic amplitude and travel time are assigned colors to create an 

image. The resulting logs are color-relief images of the borehole wall, based on acoustic 
UIC Program Class VI Well A-73 

Site Characterization Guidance

travel time and amplitude. Low-amplitude, high travel-time features, including fractures, 

are typically assigned dark colors. As with sonic fracture finder logs, shales and other 

features that result in a low sonic amplitude are considered during log interpretation; 

• Electrical borehole imaging logs operate under a similar principle as acoustic imaging 

logs. Because this is an electrical log, the test is conducted in boreholes filled with a 

conductive drilling fluid. Measured resistivity values are assigned colors to develop an 

image. The resulting log is a color-relief image of the resistivity of the borehole wall. 

Low-resistivity features, including shales and fluid-filled fractures, are typically 

displayed as dark colors; and

• Borehole video imaging logs have become more common in recent years and may be 

used to detect fractures. A video log is conducted by lowering a video camera into the 

well. The video is seen in real time and recorded at the surface, allowing for detailed 

focus on features of interest. Video logs can be conducted in liquid-filled or open 

boreholes, as long as the borehole fluids are relatively clear. Fractures are evident on 

borehole video logs (Figure A-30). 
UIC Program Class VI Well A-74 

Site Characterization Guidance

Figure A-30: Example of Borehole Video Imaging Log Showing Formation Fractures. 
UIC Program Class VI Well A-75

Site Characterization Guidance

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