Geologic Sequestration of Carbon
United States
Environmental Protection
Agency
Underground Injection Control (UIC)
Program Class VI Well Site
Characterization Guidance
Office of Water (4605M) EPA 816-R-13-004 May 2013
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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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Executive Summary
EP'A''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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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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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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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 Inj ection 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
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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
CC>2 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:
l:40CFR146.81(d).
2: EPA's UIC website (http://water.epa.gov/tvpe/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.l
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 IIEOR/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
strati graphically 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 strati graphically overlying and underlying the
injectionzone(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 IIEOR/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 (31.1°C 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/1 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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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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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
at40CFR146.82(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)];
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• 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 VIImplementation Manual
for State Directors.
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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
Gather information on
all wells, etc.
Study seismic history
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)].
Map showing the injection well, the applicable AoR, and faults, if
known or suspected [40 CFR 146.82(a)(2)].
Information on the seismic history of the area, including the
presence and depths of seismic sources [40 CFR 146.82(a)(3)(v)].
2.3.1
2.1
2.2
2.3.7
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Activity
Class VI Rule Requirement
Guidance
Section
Detailed analysis
Study faults and
fractures in the AoR
Collect data on the
depth, areal extent,
and thickness of the
injection and confining
zones, and fades
changes
Characterize
mineralogy of the
injection and confining
zones
Characterize porosity,
permeability, and
capillary pressure of
the injection and
confining zones
Perform
geomechanical
characterization
Characterize
hydrology and
hydrogeology of the
AoR
Characterize
geochemistry
Perform geophysical
characterization
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)].
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)].
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)].
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)].
Geomechanical information on fractures, stress, ductility, rock
strength, and in situ fluid pressures within the confining zone(s) [40
CFR146.82(a)(3)(iv)].
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)].
Baseline geochemical data on subsurface formations
[146.82(a)(6)].
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)].
2.3.2
2.3.3,3.1
2.3.4
2.3.5
2.3.6
2.3.8
2.3.9
2.3.10
During/after well drilling
Update site
characterization data
based on pre-injection
logs and tests
Perform formation
testing
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)].
The results of the formation testing program [40 CFR 146.82(c)(4)].
4
4.1
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Activity
Class VI Rule Requirement
Guidance
Section
Analyze cores
Take whole cores orsidewall 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
at146.82(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.
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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 non-
USDWs 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.
Site Characterization
Proposed Operating
Data
Computational Modeling/
AoR Delineation
Model Calibration
Monitoring System
Design
Monitoring Data
Collection and Interpretation
Figure 1-1: Flow Chart Showing Relationships among Site Characterization,
Modeling, and Monitoring for a GS Project
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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).
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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 strati graphic 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
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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.
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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 pre-
existing 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
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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;
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• 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
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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)(l)]. 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.
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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.
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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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• 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).
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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 strati graphic 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).
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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)(l)(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
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• 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,
per40CFR146.82(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.
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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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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
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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
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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.
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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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• 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
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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 ofln-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).
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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 (NO A A) '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.
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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
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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
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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
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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.
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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 (IDS); alkalinity; specific conductivity (SC); and major anions and cations
(e.g., Ca2+, Mg2+, K+, Na+, Cl", Br", SC>42~, and MV). 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, SiC>2, 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 IDS) 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/regionl/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 33
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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.
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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 35
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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.
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Table 2-1: Applicability of Geophysical Techniques to Geological Features of Interest
Investigation of
Near Borehole and Shallow
Subsurface
Field-Wide Subsurface
Studies
Stratigraphy
Thickness
Structure 0-100 m
Structure 100 m- 1 km
Structure >1 km
Fault/Fracture
Porosity
Pore Pressure
Abandoned Wells
SEISMIC
2D
W
W
W
W
W
W
p
3D
W
W
W
W
W
W
W
VSP*
W
W
W
p
3D-VSP
W
W
W
W
p
W
W
W
7
Cross-
well
W
W
W
W
P
W
p
Borehole
Microseismic
W
P
P
W
W
W4
GRAVITY
Aerial &
Surface
Gravity
W
W1
P
P
W3
p
p
Borehole
Gravity
W
W
W
P
P
W
ELECTROMAGNETIC/
ELECTRICAL
Natural
Source
W
P
P
P
W
P5
W6
Controlled
Source
W
W
P
P
P
W
W5
W6
ERT*
W
W
P
W
p
p5
W6
W
MAGNETIC
Aerial &
Surface
Magnetic
W
P2
P
P
W3
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
7For 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
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Table 2-2: Stages in a Geologic Sequestration Project where Geophysical Techniques May Be Applicable
APPLICABLE
DURING
Preliminary
Investigation
Site
Characterization
Injection-Phase
Monitoring
Post-Injection
Site Care
SEISMIC
Q
X
X
X
X
Q
on
X
X
X
§3
^
X
X
X
1
§
X
X
X
"3
o
^
X
X
X
1
3
1
«2
~0
•s:
0
X
X
GRAVITY
1
O
4
t?i
5
1
X
X
2
1
~o
-s:
0
03
X
X
X
ELECTROMAGNETIC/
ELECTRICAL
O
1
1
5j
X
^
^
^
1
§
c3
X
X
X
X
^
^
X
X
MAGNETIC
1
S-^
1
°a
1
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 (Knodel 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
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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, deposit!onal 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 deposit!onal 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
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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.
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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. High-
resolution 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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• 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
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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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• 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.
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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)(l). 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
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• 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. Fades 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 deposit!onal 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:
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• Descriptions and analyses of core samples will provide information on a number of
relevant characteristics including mineralogy, cross-bedding, grain sizes, sorting, fine-
grained 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 deposit!onal 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:
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• 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.
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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 region-
wide 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.
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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 Workbench15 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 ID (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/X 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
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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 dioxide-
rich 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.
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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 dioxide-
rich 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 flow-
through 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.
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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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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)(l) 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 low-
permeability 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 resource-
intensive 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)(l) 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
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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 (non-
transmissive) 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 high-
porosity 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 shale-
entrainment 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
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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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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
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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, strati graphic 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)] andbefore 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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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,
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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)(l)]. 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
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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)(l), 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)(l)-(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
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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
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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 fall-
off 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.
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5. References
Almon, W.R. 1992. Overview of Routine Core Analysis. In Morton-Thompson, D., and A.M.
Woods (Eds.), AAPG Methods in Exploration Series, No. 10, Development Geology
Reference Manual (pp. 201-203). American Association of Petroleum Geologists
(AAPG): Tulsa, OK.
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. ASTMD5314 - 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.
http://www.astm.org.
ASTM. 2010. Standard Test Method for Compressive Strength and Elastic Moduli of Intact
Rock Core Specimens under Varying States of Stress and Temperatures. ASTM D7012 -
10. DOI: 10.1520/D7012-10. http://www.astm.org.
Bachu, S., D. Bonijoly, J. Bradshaw, R. Burruss, S. Holloway, N.P. Christensen, and O.M.
Mathiassen. 2007. CO2 storage capacity estimation: Methodology and gaps. International
Journal of Greenhouse Gas Control 1: 430-443.
Bachu, S. 2008. Comparison between Methodologies Recommended for Estimation of CO2
Storage Capacity in Geological Media - Phase II Report. The CSLF Task Force on CO2
Storage Capacity Estimation and the USDOE Capacity and Fairways Subgroup of the
Regional Carbon Sequestration Partnerships Program.
Balan, B., S. Mahaghegh, and S. Ameri. 1995. State-of-the-art in permeability determination
from well log data: Part 1 - A comparative study, model development. SPE 30978.
Barbosa, V.C.F., P.T.L. Menezes, and J.B.C. Silva. 2007. Gravity as a tool for detecting faults:
In depth enhancement of subtle Almada's basement faults, Brazil. Geophysics 73: B59-
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Birkholzer, J.T., and Q. Zhou. 2009. Basin-scale hydrogeologic impacts of CO2 storage:
Capacity and regulatory implications. International Journal of Greenhouse Gas Control
3(6): 745-756.
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Carroll, S., W. McNab, S. Torres, J. Singleton, and P. Zhao. 2011. Wellbore integrity in carbon
sequestration environments: 1. Experimental study of cement - sandstone/shale - brine -
CO2. Energy Procedia 4: 5186-5194.
Chadwick, A., R. Arts, C. Bernstone, F. May, S. Thibeau, and P. Zweigel, P. 2008. Best practice
for the Storage of CO2 in Saline Aquifers. Keyworth, Nottingham: British Geological
Survey Occasional Publication No. 14.
Chiaramonte, L., M.D. Zoback, J. Friedmann, and V. Stamp. 2008. Seal integrity and feasibility
of CO2 sequestration in the Teapot Dome EOR pilot: geomechanical site characterization.
Environmental Geology 54: 1667-1675.
Cone, M.P., and D.G. Kersey. 1992. Porosity. In Morton-Thompson, D., and A.M. Woods
(Eds.), AAPG Methods in Exploration Series, No. 10, Development Geology Reference
Manual (pp. 204-209). AAPG: Tulsa, OK.
Doughty, C., K. Pruess, S.M. Benson, S.D. Hovorka, P.R. Knox, and C.T. Green. 2001. Capacity
Investigation of Brine-Bearing Sands of the Frio Formation for Geologic Sequestration of
CO2. http://www.netl.doe.gov/publications/proceedings/01/carbon_seq/p32.pdf.
Doughty, C., and K. Karasaki. 2004. Modeling flow and transport in saturated fractured rock to
evaluate site characterization needs. Journal of Hydraulic Engineering and Research 42
(extra issue): 33-44.
Duncan, I. 2009. CO2 Seals: Why are they relevant to EOR Projects? Presented at the 2009
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Appendix: Available Technologies and Methods for Conducting
Required Site Characterization Activities
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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
Al. 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-l
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
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List of Figures
Figure A-l: 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 Sub-
Basin, Australia) A-26
Figure A-l 1: 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-l 5: 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
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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
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List of Tables
Table A-l: 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
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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:
• Al, 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.
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Al. 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-l 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
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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.
Depositional Environments
coastal plain Relative Salinity
estuarine complex B freshwater influence
shoreface/delta front brackish water influence
lower shoreface/offshore marine I normal marine
Well Log Information
GR C
gamma
ray log
conductivity
log
Figure A-l: 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).
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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.
KalachitUi Range
Dhulian
SOAN SYNCLINE
Kot Saratig Balkassar
Karsal
Sail Range
Punjab Platform
Kallar Kahar
Sea Level _
Skin -
30 MILES
25
50 KILOMETERS
EXPLANATION
L~' -J NCogene
I Paleogene
Cenozoic
undivided
I I Permian
I
Cambrian
Eocambrian
Prccambrian
Fault
Field location
with subsurface
well data
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.
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TILTED ANTICLINE
Plunging 10° N
w
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.
Fades 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
etal.,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
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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 strati graphic 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).
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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).
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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.
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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
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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 X-
rays, 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 elastics 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.
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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 um), 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 um 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).
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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:
Porosity = /(pf"atr'^p&"'fc). Equation 1
(Pmatrix-pfluitl)
where/Wrais estimated based on the lithology (e.g. sandstone = 2.65 g/cm3, limestone = 2.71
g/cm3, and dolomite = 2.87 g/cm3, etc.), pbuik is from the density log, and pfluid 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.
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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.
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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 = — - - - Equation 2
4/X(p2-pi)
where Q is the flow rate through the core, // is the fluid viscosity, L is the length of the core, ^4/
the cross sectional area of the core, and (p2~Pi) is the pressure difference on either side of the
core. Permeability values of different lithologies can vary by orders of magnitude (Table A-l),
with salts and shales typically exhibiting lower permeability values and sandstones having the
highest values.
Table A-l: Typical Permeability for Various Lithologies.
From: Davis (1988).
Lithology
Shale (unfractured)
Sandstone
Coal
Salt
Permeability (mD)
4.7 xlO'5
3.8-4,740
334
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.
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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:
S Equations
where S, 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;
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• 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:
K ii
Absolute Permeability = — Equation 4
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where K is the hydraulic conductivity, ju is the dynamic viscosity of the liquid, p 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.
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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).
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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
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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
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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.
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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
Vertical stress
Minimum
horizontal stress
\^>hmin)
Maximum
horizontal stress
Measurement of downhole pressure by drill
stem testing and production testing
Integration of density logs over the desired
depth
Leak-off tests (LOT), Extended LOT
(XLOT)
Modeling well bore failure features such as
drilling-induced tensile fractures (ifSv, Shmin
and pore pressure values are known) or
stress-induced well bore breakouts (if Sv,
Shmin, pore pressure, and the rock strength are
known)
Smolen (1992); Borah (1992);
Lancaster (1992); Harrison &
Chauvel (2007)
Zoback et al. (2003);
Chiaramonte et al. (2008);
Streit et al. (2005); Herring
(1992)
Chiaramonte et al. (2008);
Zoback et al. (2003); Streit et
al. (2005)
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.
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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, Snmax, 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 strike-
slip faulting occurs when the difference between Snmax and Shmin is sufficiently large (SHmax> Sv
(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~) = J0Z° pgdz Equation 5
where ZQ 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
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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.
FPP
Volume (or Time If constant flow rate)
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
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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 Snmax 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.
(•)
drilling
breakout : induced
shear failure zone U zone shape tensile
fracture
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).
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NESWNNESWN
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 Snmax 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):
Equation 6
where GI and o3 are the maximum and minimum principal stresses, respectively, Pp is the pore
fluid pressure, and ju 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 GI and 03 are defined by the faulting environment
(Zobak et al., 2003), as described previously. For example, a strike-slip faulting environment
would be characterized GI = Snmax and 03 = Shmin, while a normal faulting environment would be
characterized by GI = Sv and 03 = 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).
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Petrel Sub-basin Pressure [MPa)
,0 10 20 30 40 50 60 70 80 90 100 110 120
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-l 1) 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-l 1.
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ite
112'
SHmin ORIENTATIONS IN
PALEOZOIC ROCKS
Mean breakout
azimuths
• Major population
^ Minor population
Orientations obtained from
other measurements
A - Anelastic strain recovery
H - Hydraulic fracture
U - Updip bed slip
100
I
scale 1:5 000 000
200
300 miles
I
Figure A-ll: 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.
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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, 01 - 03) 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).
80
-$> 60
b
I
b" 40
20
formation of
new fracture
fault failure \ in Berea
possible \ sandstone
40 50 60 70 80 90
fault angle, 6
Figure A-12: Example Failure Plot Indicating Scenarios where Fault Reactivation is Possible.
Adapted from: Streit et al. (2005); © Elsevier, reproduced with permission.
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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.
0 m depth
3500 m depth
>hlgh
p tendency
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 (01-03), 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.
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in
in
ED
L_
—•
[/i
L_
re
/ /
X
X
Effective Normal Stress
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
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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.
Upthrown reservoir zones
outlined in blue
Top Lwr
op Lwr
hoom
f
Downthrown reservoir
zones outlined in black
"\_x Shale Gouge Ratio (%)
-0
-20
increasing
seal
I capacity
50
'
/
Base
Brent
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 6), 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.
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a
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.
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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 (Snmax 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.
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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, Snmax, 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 Mohr-
Coulomb 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.
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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)(l)-(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
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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 (Knodel 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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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 Knodel 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 non-
sedimentary 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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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 re-
processed 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 low-
quality 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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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, deposit!onal 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 deposit!onal 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.
Contour Interval - 0.1 milligok
* Meoiuremenr stofion Scale in feet
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 high-
density 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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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 15m (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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surflcially, 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.
340
2 320-
5
300-
a 280
260 -1
Vertical Exaggeration x4
0 100 200 300 meters
I , ... I , ... I , ... I
.a
I
1)
h
ft
300
200
150
100
70
45
30
20
15
10
7
4.5
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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rainstorms) can also greatly affect survey results, although this is more problematic for time-
lapse 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.
711 TF
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 post-
collection 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 ground-
based 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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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 low-
frequency 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.
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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)(l), 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.
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(a) Increased
certainty
of storage
potential
Increasing
cost of
storage
(b) Level of Detail
and Resolution
High
Medium
Low
Site Local
Regional Basin Country
Satm
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) cut-
off 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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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 Al 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
Pressure
Fracture Pressure
Temperature
Compressibility
Porosity*
Permeability*
Relative
Permeability*
Transmissibility
Interfacial Tension
Water Saturation
Wettability
Capillary Pressure
Viscosity
Density and Specific
Gravity
Mobility and
Mobility Ratio
Capillary and
Gravitational
Numbers
Injection Zone
Thickness, Area and
Background
Hydraulic Gradientf
Number of Wells
Skin Factor
Diffusion Coefficient
and Dispersivity
Sweep Efficiency
Methods for Quantifying
Parameters
Labora-
tory
X
X
X
X
X
X
X
X
X
X
X
x
X
Field
X
X
X
X
X
X
X
X
X
X
x
X
X
X
Estimation or
Prediction
X
X
X
X
X
x
X
X
X
X
x
X
X
X
X
X
X
Parameters for Estimating
Storage Capacity
Static
Method
X
X
X
X
X
Material
Balance
X
Reservoir
Simulation
X
X
X
X
X
X
x
X
X
X
X
X
X
x
X
X
X
X
* Covered in Section A3 of the Appendix and in Section 2.3.5 of the guidance.
f Covered in Sections 2.3.3 and 2.3.8 of the guidance.
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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)(l)] 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 /^ 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.
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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).
TUBING
»«^»
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
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(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 Noiiy 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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Figure A-24: A Diagram Demonstrating Wetting Angle.
The wetting angle is (180-9). 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).
PC drainage
— PC imbibition
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.
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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'^s"1. The ratio of
viscosity to density is called the kinematic viscosity, which has the units of stoke or cmV1.
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).
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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).
•<— Ground level
4-Critical depth
(approx)
2.5
© CO2CRC
200
400 600
Density of CO2 (kg/m3)
800
1000
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)
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(Bachu and Bennion, 2008), with a fluid property, viscosity. Mathematically, mobility is
expressed as:
AI = — Equation 7
where hi is the mobility of fluid phase /', kt is the effective permeability of fluid phase /', and pt is
the viscosity of fluid phase /'. (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).
Mis 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 (Co) 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.
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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 high-
permeability 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).
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Damaged Undamaged reservoir
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,
APskin = 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 Eyis 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 Ey 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 £/whereby (Lake, 1989; Craig, 1980; Warner, 2007):
Ev = EAEj 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 £/ 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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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 x h x nc x Gc x (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/a and/m 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:
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 X C X IGIP Equation 1 1
where Rfis 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):
MCo2t = Pco2r [RfAh0(l - Sw) - Vlw + Fplv] Equation 12
where:
= theoretical mass storage capacity for carbon dioxide in a reservoir at in situ
conditions [M]
Pco2r = carbon dioxide density at reservoir conditions [ML"3]
Rf = recovery factor [dimensionless]
A = reservoir area [L2]
h = thickness [L]
0 = porosity [dimensionless]
Sw = water saturation [dimensionless]
Vi-w = 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:
MCo2t = Pco2r*/(l - FIG) x OGIP x Equation 13
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and for fluid compressibility in oil reservoirs:
r«fOOIP T, _
MCo2t = Pco2r X -^ -- Viw + Vpw Equation 14
where OGIP and OOIP represent the original gas and oil in place at surface conditions, FIG is the
fraction of injected gas, 5/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 = CmCbChCwCaMc02t = 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 = Ah0(l - Swirr) Equation 16
where A is the reservoir area, h is thickness, ^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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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 = hVtrap$Sc02t Equation 18
where AVtrap represents the carbon dioxide-invaded rock volume and Sco2t is the trapped carbon
dioxide saturation. AVtmP 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):
Mc02f = Ah0(psXcs° 2 - po*o°2) Equation 19
./~y~)9
where p is the density of the formation water, JL 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
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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):
Qcoz = qco2ie~Dt Equation 20
where qco2 is the carbon dioxide injection rate and the subscript /' 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:
r _ cozt-coz T7™,o+;™ 01
"CO2 ~ - iiquationzl
where the decline coefficient/) 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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and Campbell (1978), and Li and Home (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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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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Descriptive
Log
Spontaneous
Potential (SP)
Resistivity
Gamma-Ray
Sand (dry)
Sand (fresh water)
Clay
Sand (fresh water)
Clay
Sandstone
(brackish water)
Sandstone (brine)
Shale
Sandstone (brine)
Shale
Sandstone (brine)
Laminated
shalely sand
(brine)
Sandstone (brine)
Shale
Sandstone
(brine)
Shale
normal
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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Table A-4: Interpreting Borehole Condition from Caliper Readings.
Indicated by
Possible Rock
Characteristics
Possible Cause
Porosity Logs
Well Bore Larger than
Expected
Caliper > Bit size
Soft or Fractured
Wash Out
Well Bore as
Expected
Caliper = Bit size
Hard / Unfractured
Well Bore Smaller than
Expected
Caliper < Bit size
Permeable
Mud-cake Accumulation
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.
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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.
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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
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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).
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Company: Geotogic Sequestration, Inc.
Well: Prooosed Injection Well #1
Location:
Zero Datum: Ground Level Tool Zero:
Reason for Survey: Open Hole
Date: 01-May-lO
Run No. One
Total Depth: 1,000 meters
Water Level: 32 meters
Oil on Water: Mone
Operator: Smith
Side-Scan
Amount: 0 Ft
Depth
Remarks
o.o m
105,0 m
600,0m
6Q8.Qm
617.0 m
628.0 H\
630,0 m
704.0m
713,5 m
714.0 m
y is 9000, Casing pins ail aopear r> good shape.
Starr at ground fevtf
SWL: water Is dear, vis-Wii
End of easng: open hole
608 m co 61 1 m; arge beak-cut zone
6re#-out5 and rubble
e fracture, water is observed moving up Hole
Lar 95 break-out lone wttrt mutiple fracture
ures (sub vertical and su&- ixjriwntai; water fe observed sw*ilng
with upward movement
Perforation:
GpftH Hok-
Notes; All depths are referenced to side-scan lens.
Figure A-30: Example of Borehole Video Imaging Log Showing Formation Fractures.
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References
Abaci, S., J.S. Edwards, and B.N. Whittaker. 1992. Relative permeability measurements for two
phase flow in unconsolidated sands. Mine Water and the Environment 11(2): 11-26.
Adams, J.J., and S. Bachu. 2002. Equations of state for basin geofluids: Algorithm review and
intercomparison for brines. Geofluids 2: 257-271.
Aguilera, R. 1992. Formation Evaluation of Naturally Fractured Reservoirs. In Morton-
Thompson, D., and A.M. Woods (Eds.), AAPG Methods in Exploration Series, No. 10,
Development Geology Reference Manual (pp. 192-193). AAPG: Tulsa, OK.
Ahmed, T.H. 2006. Reservoir Engineering Handbook. 3r edition. Gulf Professional Publishing
(Elsevier): Burlington, MA.
Alberty, M. 1992a. Standard Interpretation. In Morton-Thompson, D., and A.M. Woods (Eds.),
AAPG Methods in Exploration Series, No. 10, Development Geology Reference Manual
(pp. 180-185). AAPG: Tulsa, OK.
Alberty, M. 1992b. Basic Open Hole Tools. In Morton-Thompson, D., and A.M. Woods (Eds.),
AAPG Methods in Exploration Series, No. 10, Development Geology Reference Manual
(pp. 144-149). AAPG: Tulsa, OK.
Almon, W.R. 1992. Overview of Routine Core Analysis. In Morton-Thompson, D., and A.M.
Woods (Eds.), AAPG Methods in Exploration Series, No. 10, Development Geology
Reference Manual (pp. 201-203). AAPG: Tulsa, OK.
Ambrose, W.A, S. Lakshminarasimhan, M.H. Holtz, V. Nunez-Lopez, S.D. Hovorka, and I.
Duncan. 2008. Geologic factors controlling CO2 storage capacity and permanence: Case
studies based on experience with heterogeneity in oil and gas reservoirs applied to CO2
storage. Environmental Geology 54(8): 1619-1633.
American Association of Petroleum Geologists (AAPG), 2004. Basic Well Logging Analysis, 2nd
Edition.
Arps, JJ. 1962. Estimation of primary oil and gas reserves. In Frick, T.C. (Ed.), Petroleum
Production Handbook, Volume II Reservoir Engineering. Chapter 37. Society of
Petroleum Engineers: Dallas, TX.
Avseth, P., T. Mukerji, and G. Mavko. 2010. Quantitative Seismic Interpretation: Applying Rock
Physics Tools to Reduce Interpretation Risk. Cambridge University Press: Cambridge,
United Kingdom.
Bachu, S., and B. Bennion. 2008. Effects of in-situ conditions on relative permeability
characteristics of CO2 brine systems. Environmental Geology 54: 1707-1722.
Bachu, S., and B. Bennion. 2009. Interfacial tension between CO2, freshwater, and brine in the
range of pressure from (2 to 27) MPa, temperature from (20 to 125) °C, and water
salinity from (0 to 334 000) mgL"1. Journal of Chemical and Engineering Data 54: 765-
775.
Bachu, S. and K. Haug. 2005. In situ characteristics of acid-gas injection operations in the
Alberta Basin, Western Canada: Demonstration of CO2 geological storage. In Thomas,
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