United States
Environmental Protection
Agency
Geologic Sequestration of Carbon
Underground Injection Control (UIC)
Program Class VI Well Testing and
Monitoring Guidance
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Office of Water (4606M)
EPA816-R-13-001
www. epa. gov/safewater
March 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 are not within the scope of this
document.
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Executive Summary
EP'A''s Federal Requirements Under the Underground Injection Control (UIC) Program for
Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells are now 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 federal minimum technical
criteria for Class VI injection wells for the purposes of protecting underground sources of
drinking water (USDWs). This document is part of a series of technical guidance documents that
EPA is developing to support owners or operators of Class VI wells and UIC Program permitting
authorities.
The Class VI Rule requires owners or operators of Class VI wells to perform several types of
activities during the lifetime of the project in order to ensure that the injection well maintains its
mechanical integrity, that fluid migration and the extent of pressure elevation are within the
limits described in the permit application, and that USDWs are not endangered. These activities
include mechanical integrity tests (MITs), injection well testing during operation, monitoring of
ground water quality above the confining zone, tracking of the carbon dioxide plume and
associated pressure front, and, at the discretion of the UIC Program Director, surface air and/or
soil gas monitoring. This guidance provides information regarding how to perform these testing
and monitoring activities.
The introductory section reviews the Class VI regulations related to testing and monitoring and
discusses the development of the Testing and Monitoring Plan. The rest of the document
addresses technical issues as follows:
Section 2 addresses mechanical integrity testing.
Section 3 addresses operational testing and monitoring during injection.
Section 4 addresses ground water and geochemical monitoring.
Section 5 addresses plume and pressure-front tracking.
Section 6 addresses surface air and soil gas monitoring.
In addition, the Appendix presents several testing and monitoring case studies. For each section
in the body of the document, this guidance:
Explains how to perform activities necessary to comply with testing and monitoring
requirements (e.g., ground water monitoring, MITs). Illustrative examples are provided in
several cases.
Provides references to comprehensive reference documents and scientific literature for
further information.
Explains how and when to report to the UIC Program Director the results of activities
related to testing and monitoring.
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Table of Contents
Disclaimer i
Executive Summary ii
Table of Contents iii
List of Figures v
List of Tables vi
Acronyms and Abbreviations vii
Definitions ix
Unit Conversions xiii
1 Introduction 1
1.1 Overview of Class VI Testing and Monitoring Requirements 1
1.2 Testing and Monitoring Plan 4
1.2.1 Phased and/or Triggered Monitoring 5
1.3 Organization of this Guidance 6
2 Mechanical Integrity Testing 10
2.1 Mechanical Integrity Definitions and Mechanical Integrity Testing Requirements 10
2.2 Internal MITs 12
2.2.1 Annulus Pressure Test 13
2.2.2 Annulus Pressure Monitoring 14
2.2.3 Radioactive Tracer Survey 17
2.3 External MITs 19
2.3.1 Oxygen Activation Log 19
2.3.2 Temperature Log 21
2.3.3 Noise Log 24
2.3.4 Alternative Methods for External Mechanical Integrity Testing 27
2.4 Reporting the Results of MITs 27
3 Operational Testing and Monitoring During Injection 29
3.1 Analysis of the Carbon Dioxide Stream 29
3.1.1 Flue Gas Analysis Methods 31
3.1.2 Laboratory Chemical Analysis 32
3.1.3 Reporting and Evaluation of Carbon Dioxide Stream Analysis 33
3.2 Continuous Monitoring of Injection Rate and Volume 34
3.3 Continuous Monitoring of Injection Pressure 40
3.4 Corrosion Monitoring 43
3.4.1 Use of Corrosion Coupons 43
3.4.2 Use of Corrosion Loops 45
3.4.3 Casing Inspection Logs 46
3.4.4 Reporting and Evaluation of Corrosion Monitoring Data 49
3.5 Pressure Fall-Off Testing 50
4 Ground Water Quality and Geochemical Monitoring 53
4.1 Design of the Monitoring Well Network 54
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4.1.1 Perforated Interval of Monitoring Wells 55
4.1.2 Monitoring Well Placement 56
4.1.3 Use of Phased Monitoring Well Installation 57
4.2 Monitoring Well Construction 58
4.3 Collection and Analysis of Ground Water Samples 62
5 Plume and Pressure-Front Tracking 72
5.1 Class VI Rule Requirements Regarding Plume and Pressure-Front Tracking 73
5.2 Direct Pressure-Front Tracking 73
5.3 Plume and Pressure-Front Tracking Using Indirect Geophysical Techniques 78
5.3.1 Seismic Methods 80
5.3.2 Electric Geophysical Methods 85
5.3.3 Gravity Methods 88
5.3.4 Reporting and Evaluation of Geophysical Survey Results 89
5.4 Use of Geochemical Ground Water Monitoring in Plume Tracking 90
6 Surface Air and Soil Gas Monitoring 94
6.1 Soil Gas Monitoring 95
6.2 Surface Air Monitoring 100
References 102
Appendix: Testing and Monitoring Case Studies A-l
I. Cranfield Oil Field A-2
II. Paradox/Aneth Project A-3
III. Ketzin/CO2SINK Project A-5
IV. Weyburn Oil Field A-6
V. West Pearl Queen Project A-9
VI. In Salah Natural Gas Fields A-10
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List of Figures
Figure 1-1. Testing and monitoring activities during different phases of a GS project in
relation to potential project risk 3
Figure 2-1. Diagram of an improperly operated injection well showing examples of loss of
mechanical integrity and resulting fluid leakage 12
Figure 2-2. Interpretation of annulus pressure monitoring for atypical injection well 16
Figure 2-3. Radioactive tracer log showing the detection of a leak in the casing and
subsequent fluid movement in a channel behind the casing 18
Figure 2-4. Temperature log showing the detection of a leak in the casing 22
Figure 2-5. Diagram of fluid leakage through channel in cement and corresponding noise
log 26
Figure 3-1. Schematic of common flow meters 37
Figure 3-2. Example plot of measured injection rate and pressure measured at wellhead,
MRCSP Michigan Basin Validation Test 39
Figure 3-3. Example of corrosion coupons 44
Figure 3-4. Example CIL (caliper log) showing significant corrosion 48
Figure 4-1. Flow chart of modeling and monitoring at a Class VI project 55
Figure 4-2. Schematic of the U-tube fluid sampling system 64
Figure 4-3. Example Piper diagram showing proportions of major ions for formations in
Ohio and Kentucky, including potential target formations for GS 70
Figure 5-1. Example of temporal plots showing change in pressure and temperature at an
injection well (above) and monitoring well (below) during initial testing at the MRCSP
Michigan Basin Validation Test 77
Figure 5-2. Time-lapse three-dimensional seismic surveys were used to track the spread of
the carbon dioxide plume at the Sleipner project in the North Sea 83
Figure 5-3. Schematic of the VSP process 84
Figure 6-1. Schematic of a soil gas sampling system 96
Figure 6-2. Schematic of a soil flux chamber 98
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List of Tables
Table 1-1. Crosswalk of guidance document sections and relevant Class VI Rule citations 8
Table 4-1. Example analytical methods for some constituents in ground water 67
Table 5-1. Summary of Class VI Rule requirements and recommendations for identifying
the position of the carbon dioxide plume and associated pressure front 73
Table A-l. Summary of case study projects and key testing/monitoring methods used at
each project A-l
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Acronyms and Abbreviations
AGA American Gas Association
AoR Area of review
API American Petroleum Institute
CEM Continuous emission monitoring
CERCLA Comprehensive Environmental Response, Compensation, and Liability Act
CFR Code of Federal Regulations
CIL Casing inspection log
CC>2 Carbon dioxide
DAS Detailed area of study (at Cranfield)
EAGE European Association of Geoscientists & Engineers
EOR Enhanced oil recovery
EPA Environmental Protection Agency
ERT Electrical resistive tomography
FID Flame ionization detector
GMT Geomechanical test (at Cranfield)
GPS Global positioning system
GS Geologic sequestration
HiVIT High volume injection test (at Cranfield)
IE A International Energy Agency
InSAR Interferometric synthetic aperture radar
IR Infrared
ISG In Salah Gas
ITRC Interstate Technology & Regulatory Council
IIP Joint Industry Project (at In Salah)
LBNL Lawrence Berkeley National Laboratory
MIT Mechanical integrity test
MRCSP Midwest Regional Carbon Sequestration Partnership
MRV Monitoring, Verification, and Reporting (for Subpart RR)
NDIR Non-dispersive infrared
NETL National Energy Technology Laboratory
NOAA National Oceanic and Atmospheric Administration
PUD Photo ionization detector
PISC Post-injection site care
PTRC Petroleum Technology Research Center
QA/QC Quality assurance/quality control
QAPP Quality Assurance Proj ect Plan
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RCRA Resource Conservation and Recovery Act
SDWA Safe Drinking Water Act
SECARB Southeast Regional Carbon Sequestration Partnership
SWP Southwest Regional Partnership
TDS Total dissolved solids
TSD Technical Support Document
TX RRC Texas Railroad Commission
UIC Underground Injection Control
USDOE U.S. Department of Energy
USDW Underground source of drinking water
VOC Volatile organic compound
VSP Vertical seismic profile or vertical seismic profiling
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Definitions
Key to definition sources:
1: Class VI Rule Preamble.
2:40CFR144.3.
3:40CFR146.81(d).
4: This definition was drafted for the purposes of this document based on current usage and
practice.
5: EPA's UIC website (http://water.epa.gov/type/groundwater/uic/glossary.cfm).
6: 40 CFR 144.6(f) and 144.80(f).
Annulus means the space between the well casing and the wall of the borehole; the space
between concentric strings of casing; space between casing and tubing.1
Aquifer exemption refers to a special exemption that removes an aquifer or part of an aquifer
from SDWA protection when certain requirements (at 40 CFR 146.4) are met to demonstrate that
the exempted aquifer does not currently serve as source of drinking water and has no real
potential to be used as drinking water source in the future. One basis for demonstrating that an
aquifer will not be used in the future is to show that it is mineral producing or capable of mineral
production.4
Area of review (AoR) means the region surrounding the GS 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 146.84.3
Carbon dioxide plume means the extent underground, in three dimensions, of an injected
carbon dioxide stream.3
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 146] does not apply to any carbon dioxide stream
that meets the definition of a hazardous waste as defined by the Resource Conservation and
Recovery Act (RCRA) under 40 CFR part 261.3.3
Casing means pipe material placed inside a drilled hole to prevent the hole from collapsing. The
two types of casing in most injection wells are (1) surface casing, the outer-most casing that
extends from the surface to the base of the lowermost USDW and (2) long-string casing, which
extends from the surface to or through the injection zone.1
Cement means material used to support and seal the well casing to the rock formations exposed
in the borehole. Cement also protects the casing from corrosion and prevents movement of
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injectate up the borehole. The composition of the cement may vary based on the well type and
purpose; cement may contain latex, mineral blends, or epoxy.1
Class II wells means wells that inject brines and other fluids associated with oil and gas
production, or storage of hydrocarbons. Class II well types include salt water disposal wells,
enhanced oil recovery wells, enhanced gas recovery wells, and hydrocarbon storage wells.5
Class VI wells means wells that are not experimental in nature that are used for GS of carbon
dioxide beneath the lowermost formation containing a USDW; or, wells used for GS of carbon
dioxide that have been granted a waiver of the injection depth requirements pursuant to
requirements at 40 CFR 146.95; or, wells used for GS of carbon dioxide that have received an
expansion to the areal extent of an existing Class II enhanced oil recovery or enhanced gas
recovery aquifer exemption pursuant to 40 CFR 146.4 and 144.7(d).6
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
injection zone(s).3
Corrective action means the use of UIC Program Director-approved methods to ensure that
wells within the AoR do not serve as conduits for the movement of fluids into USDWs.3
Enhanced recovery wells inject substances, such as brine, steam, polymers, or carbon dioxide,
into hydrocarbon-bearing formations to improve the recovery of residual oil (enhanced oil
recovery) or natural gas (enhanced gas recovery).4
Fluid means any material or substance which flows or moves whether in a semisolid, liquid,
sludge, gas or other form or state. 2
Formation or geological formation means a layer of rock that is made up of a certain type of
rock or a combination of types.1
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.3
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 geologic
sequestration 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 geologic
sequestration of carbon dioxide that have received an expansion to the areal extent of an existing
Class II enhanced oil recovery or enhanced gas recovery 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.3
Ground water means water below the land surface in a zone of saturation.2
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Injectate means the fluids injected. For the purposes of the Class VI Rule, this is also known as
the carbon dioxide stream.1
Injection depth waivers refer to the provisions at 40 CFR 146.95 that allow owners or operators
to seek a waiver from the Class VI injection depth requirements for GS to allow injection into
non-USDW formations while ensuring that USDWs are protected from endangerment.4
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.3
Mechanical integrity means the absence of significant leakage within the injection tubing,
casing, or packer (known as internal mechanical integrity), or outside of the casing (known as
external mechanical integrity).1
Mechanical integrity test (MIT) refers to a test performed on a well to confirm that a well
maintains internal and external mechanical integrity. MITs are a means of measuring the
adequacy of the construction of an injection well and a way to detect problems within the well
system.1
Model means a representation or simulation of a phenomenon or process that is difficult to
observe directly or that occurs over long time frames. Models that support GS can predict the
flow of carbon dioxide within the subsurface, accounting for the properties and fluid content of
the subsurface formations and the effects of injection parameters.1
Owner or operator means the owner or operator of any facility or activity subject to regulation
under the UIC Program.2
Packer means a mechanical device that seals the outside of the tubing to the inside of the long-
string casing, isolating an annular space.1
Post-injection site care (PISC) means appropriate monitoring and other actions (including
corrective action) needed following cessation of injection to assure that USDWs are not
endangered, as required under 40 CFR 146.93.3
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.3
Separate-phase carbon dioxide means carbon dioxide that is present in a free, or non-aqueous,
gaseous, liquid, or supercritical phase state.4
Shut-off device refers to a valve coupled with a control device which closes the valve when a set
pressure or flow value is exceeded. Shut-off devices in injection wells can automatically shut
down injection activities when operating parameters unacceptably diverge from permitted
values.5
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Site closure means the specific point or 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
(Class VI injection well) is released from PISC responsibilities.3
Supercritical fluid means a fluid above its critical temperature (31.1°C for carbon dioxide) and
critical pressure (73.8 bar for carbon dioxide). Supercritical fluids have physical properties
intermediate to those of gases and liquids.1
Total dissolved solids (TDS) refers to the measurement, usually in mg/L, for the amount of all
inorganic and organic substances suspended in liquid as molecules, ions, or granules. For
injection operations, TDS typically refers to the saline (i.e., salt) content of water-saturated
underground formations.1
Transmissive fault or fracture means a fault or fracture that has sufficient permeability and
vertical extent to allow fluids to move between formations.3
Tubing refers to a small-diameter pipe installed inside the casing of a well. Tubing conducts
injected fluids from the wellhead at the surface to the injection zone and protects the long-string
casing of a well from corrosion or damage by the injected fluids.5
Underground Injection Control (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.5
Underground Injection Control (UIC) Program refers to the program EPA, or an approved
state, is authorized to implement under SDWA that is responsible for regulating the underground
injection of fluids by wells injection. This includes setting the federal minimum requirements for
construction, operation, permitting, and closure of underground injection wells.4
Underground source of drinking water (USDW) means an aquifer or portion of an aquifer that
supplies any public water system or that contains a sufficient quantity of ground water to supply
a public water system, and currently supplies drinking water for human consumption, or that
contains fewer than 10,000 mg/L TDS and is not an exempted aquifer.1
Well bore refers to the hole that remains throughout a geologic (rock) formation after a well is
drilled.4
Workover refers to any maintenance activity performed on a well that involves ceasing injection
or production and removing the wellhead.4
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Unit Conversions
1 foot (ft)
1 mile (mi)
1 pound per square inch (psi)
Temperature in degrees Fahrenheit (°F)
1 pound (Ib)
1 tonne or metric ton (t)
1 megatonne (Mt)
1 short ton or ton
1 cubic foot (ft3)
0.3048 meters (m)
1.609 kilometers (km)
0.006895 megapascals (MPa)
Temperature in degrees Celsius (°C)
(°F-32) xQ.56
0.4536 kilograms (kg)
1,000 kilograms
1 x 106 tonnes
0.9072 tonnes
0.0283 cubic meters (m3)
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1 Introduction
The United States Environmental Protection Agency (EPA) rulemaking Federal Requirements
Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic
Sequestration (GS) Wells [40 CFR 146.81 et seq.], hereafter referred to as the Class VI Rule,
includes testing and monitoring requirements that are tailored to the unique circumstances of GS
projects.
Testing and monitoring of GS sites is integral to the protection of underground sources of
drinking water (USDWs). Testing and monitoring:
Is required to determine whether the GS projects are operating as permitted.
Can detect risks that may lead to the endangerment of USDWs.
Is needed to inform reevaluation of the area of review (AoR) for Class VI projects, as
required at 40 CFR 146.84(e), to ensure accurate delineation of the region surrounding
the injection well(s) where the potential exists for USDWs to be endangered by the
leakage of injectate and/or formation fluids.
The purpose of this guidance document is to describe the technologies, tools, and methods
available to owners or operators of Class VI wells to fulfill the Class VI Rule requirements
related to developing and implementing site- and project-specific strategies for testing and
monitoring. The intended primary audiences of this guidance document are Class VI injection
well owners or operators, contractors performing testing and monitoring activities, and UIC
Program Directors.
1.1 Overview of Class VI Testing and Monitoring Requirements
The Class VI Rule requires various testing and monitoring activities to identify any risks to, and
endangerment of, USDWs during the various phases of a GS project (i.e., pre-injection,
injection, and post-injection) [40 CFR 146.87, 146.89, 146.90, 146.92, 146.93]. Figure 1-1
presents an example "risk diagram" for the stages of a GS project and the accompanying Class
VI Rule testing and monitoring requirements that address this risk. Note that the relative risks to
USDWs during different stages of a GS project are site- and project-specific; Figure 1-1 presents
a simplified example for explanatory purposes.
Some of the Class VI testing and monitoring-related activities support the initial characterization
of the project site and the collection of baseline data prior to the commencement of injection;
these are described in the UIC Program Class VI Well Site Characterization Guidance. The
testing and monitoring required following the cessation of injection is described in the UIC
Program Guidance on Class VI Well Plugging, Post-Injection Site Care, and Site Closure. This
document describes testing and monitoring activities that are primarily required during the
injection phase.
Injection-phase testing and monitoring activities required under the Class VI Rule
include: Analysis of the carbon dioxide stream, required at a frequency that will yield
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information on the chemical composition and physical characteristics of the injectate [40
CFR 146.90(a)].
Monitoring of operational parameters (injection pressure, rate, and volume, the pressure
on the annulus, and the annulus fluid volume) through the use of continuous recording
devices [40 CFR 146.90(b)].
Corrosion monitoring of injection well materials, required on a quarterly basis [40 CFR
146.90(c)].
Monitoring of ground water quality and geochemical changes above the confining
zone(s), at a site-specific frequency and spatial distribution [40 CFR 146.90(d)].
External mechanical integrity testing, at least once per year [40 CFR 146.90(e)].
Pressure fall-off testing, at least once every five years [40 CFR 146.90(f)].
Testing and monitoring to track the extent of the carbon dioxide plume and the presence
or absence of elevated pressure (e.g., the pressure front) [40 CFR 146.90(g)].
Surface air and/or soil gas monitoring, only if required by the UIC Program Director [40
CFR 146.90(h)].
Any additional monitoring that the UIC Program Director determines to be necessary to
support, upgrade, and improve computational modeling of the AoR and to determine
compliance with standards under 40 CFR 144.12 [40 CFR 146.90(1)].
Owners or operators must submit, as part of the permit application, a Testing and Monitoring
Plan that describes how they will meet the requirements of the Class VI Rule listed above and
establishes a detailed site- and project-specific testing and monitoring strategy [40 CFR 146.90].
Further information on the Testing and Monitoring Plan is provided in Section 1.2 of this
document and in the UIC Program Class VI Well Project Plan Development Guidance.
Additionally, the Class VI Rule includes provisions for owners or operators of Class VI wells
seeking a waiver of the requirement to inject beneath the lowermost USDW [40 CFR 146.95].
These owners or operators must apply for and receive injection depth waivers and meet
additional requirements to ensure the protection of USDWs above and below the permitted
injection zone. The additional requirements are largely based on the need to monitor additional
zones below the lower confining zone, and the Testing and Monitoring Plan that meets the
requirements under 40 CFR 146.90 must also demonstrate that additional monitoring will be
performed to ensure the protection of USDWs below the injection zone, per 40 CFR
146.95(a)(5). For more detailed information about the additional testing and monitoring
considerations for projects operating under injection depth waivers, see the UIC Program Class
VI Well Injection Depth Waivers Guidance.
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Testing and Monitoring Activities
Mechanical integrity testing
[§146.87 (a)(4), §146.89, §146.90 (e). §146.92(a)]
Analysis of carbon dioxide stream
[§146.90(a)J
Monitor injection pressure, rate and volume
[§146.90 (b)]
Corrosion monitoring
[§146.90 (c)]
Monitor ground water quality above confining zone
[§146.90 (d), §146 (b)]
Pressure fall-off testing
[§146.90 (f)]
Plume and pressure front tracking
[§146.90 (g), §146.93 (b)]
Testing and Monitoring Activities During
Phases of a Geologic Sequestration Project
Figure 1-1. Testing and monitoring activities during different phases of a GS project in relation to potential project risk
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1.2 Testing and Monitoring Plan
The Class VI Rule, at 40 CFR 146.90, requires the owner or operator of a Class VI well to
prepare, maintain, and comply with a Testing and Monitoring Plan to verify that the GS project
is operating as permitted and is not endangering USDWs. This plan must be submitted with the
initial permit application for approval by the UIC Program Director [40 CFR 146.82(a)(15)] and
revised, if necessary, based on information collected during pre-injection logging and testing [40
CFR 146.82(c)(9)]. The plan must then be periodically reviewed, at least every five years, to
incorporate monitoring data and the results of AoR reevaluations, and the owner or operator
must either make necessary amendments or demonstrate that no amendments are needed [40
CFR146.90Q)].
The Testing and Monitoring Plan serves several important purposes. First, it provides an
opportunity for the owner or operator to formulate an integrated strategy for monitoring the main
aspects of the GS project: well integrity, operational parameters, and changes within the geologic
system (plume, pressure front, and ground water quality). Importantly, Class VI permits are
issued for the lifetime of the GS project, including the post-injection site care (PISC) period [40
CFR 144.36(a)]. Periodic reevaluation of the Testing and Monitoring Plan provides a vehicle for
communication between the owner or operator and the UIC Program Director to ensure that,
over the life of the permitted project, testing and monitoring can be modified as necessary to
address changes at the GS project site. The UIC Program Class VI Well Project Plan
Development Guidance contains additional information on the Testing and Monitoring Plan
development, evaluation, and amendment process.
EPA expects that the owner or operator will work in consultation with the UIC Program Director
to develop a risk-based, flexible approach for Class VI well testing and monitoring that uses
appropriate technologies and techniques, based on site-specific information, to ensure protection
of and to minimize risk to USDWs. The Class VI Rule provides flexibility to owners or operators
to consider site-specific conditions, as described in the remainder of this document, while
complying with the testing and monitoring requirements of the Class VI Rule.
The Testing and Monitoring Plan should present an effective strategy that incorporates available,
site-specific techniques that support the overall goals of detecting trends or events that might
lead to endangerment of USDWs and demonstrates that the project is operating as permitted.
Formulating the Testing and Monitoring Plan involves an approach that includes:
1. Use of site characterization data, the site geologic conceptual model, and the results of
computational modeling to identify areas or issues of potential concern for the specific
GS project (e.g., possible leakage pathways, uncertainties in confining zone properties),
considering the boundaries of the AoR and baseline information (where necessary).
2. Selection of testing and monitoring methods and strategies, tailored to the site-specific
risk profile or identified potential concerns, to comply with the different components of
the Class VI Rule testing and monitoring requirements as listed in Section 1.1.
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3. Identification of site- or project-specific factors to consider or incorporate in evaluating
the results of testing and monitoring, which may indicate an increase in risk to or
endangerment of USDWs, and/or deviations from permitted conditions.
EPA recommends that, for each method identified in the Testing and Monitoring Plan, the owner
or operator provide the following:
A description of each method selected and its appropriateness (e.g., a geophysical method
for plume tracking considering site-specific geology).
A technical justification for the selection of the method and the associated monitoring
goal (e.g., compliance with a specific Class VI Rule requirement while addressing a site-
specific consideration).
The key parameters to be tested or monitored (e.g., chemicals to analyze during ground
water quality monitoring).
Expected performance levels, limitations (e.g., detection limits), or sensitivities (e.g.,
geologic sensitivities of a specific geophysical method).
The spatial or temporal strategy for application of the method or technique (e.g., a
description of the monitoring well network or detailed information on the frequency of
geochemical monitoring above the confining zone).
The procedure to be used to analyze and interpret results (e.g., geophysical data
processing), including levels that may indicate deviations from planned project
performance (e.g., specific threshold values of monitored parameters).
Additionally, EPA recommends that information on the qualifications of contractors or vendors
used for any monitoring be discussed in the Testing and Monitoring Plan, at the request of the
UIC Program Director. The UIC Program Class VI Well Project Plan Development Guidance
provides specific considerations, beyond those discussed in this document, for developing a site-
specific Testing and Monitoring Plan that complies with the requirements of the Class VI Rule.
Owners or operators are encouraged to refer to the UIC Program Class VI Well Project Plan
Development Guidance for further information as they develop their Testing and Monitoring
Plans.
1.2.1 Phased and/or Triggered Monitoring
Owners or operators should describe minimum monitoring techniques, locations, and/or
frequencies in the Testing and Monitoring Plan. Owners or operators may also choose to
establish potential conditions or situations that, if they arise during the course of the GS project,
will trigger additional monitoring or adjustments to ongoing monitoring activities, and/or
indicate a new phase of monitoring as planned. This type of approach would allow the site-
specific testing and monitoring strategies to be tailored to any changes in predicted performance
and in response to potential increased risks to USDWs as identified or detected during the course
of injection. This would also ensure that monitoring is streamlined based on the availability of
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new information. Because a phased or triggered strategy may not be appropriate for all sites,
EPA recommends that the owner or operator discuss this approach with the UIC Program
Director and provide a technical justification for it in the Testing and Monitoring Plan. If phased
or triggered monitoring is proposed, EPA recommends that the Testing and Monitoring Plan
detail all conditions and triggers for the phasing of the monitoring activities; any planned
changes in monitoring techniques, locations, and frequencies; and the planned schedule for each
phase.
1.3 Organization of this Guidance
This guidance document is organized around the testing and monitoring activities that will occur
during the injection phase (Figure 1-1). Following the introductory section (Section 1), the
remainder of the document is organized as follows:
Section 2, Mechanical Integrity Testing, outlines the Class VI Rule requirements related
to demonstrating the mechanical integrity of the injection well. It describes the concepts
of internal and external mechanical integrity and documents available mechanical
integrity tests (MITs).
Section 3, Operational Testing and Monitoring During Injection, describes other injection
operation-related testing and monitoring activities, including: analysis of the carbon
dioxide stream; continuous monitoring of injection rate, volume, and pressure; corrosion
monitoring; and pressure fall-off testing.
Section 4, Ground Water Quality and Geochemical Monitoring, describes the Class VI
Rule requirements for geochemical monitoring above the confining zone(s). It discusses
how owners or operators may design and construct a monitoring well network, collect
and analyze ground water samples from above the primary confining zone, and interpret
and submit the results of the ground water sample analysis.
Section 5, Plume and Pressure-Front Tracking, describes the Class VI Rule requirements
for direct and indirect monitoring of the pressure front and carbon dioxide plume. It
discusses some specific direct and indirect (i.e., geophysical) monitoring technologies.
Section 6, Surface Air and Soil Gas Monitoring, describes the Class VI Rule
requirements associated with surface air and/or soil gas monitoring, including the
discretion of the UIC Program Director to require such monitoring. It discusses available
tools and technologies for this type of monitoring.
This guidance document also includes a number of cases studies, presented in the Appendix,
which provide additional information on a range of testing and monitoring technologies used in
GS projects in various settings.
The remaining sections of this guidance document discuss a wide variety of testing and
monitoring techniques; many of these techniques are currently well established in the GS
community and may be available for adoption based on site- and operation-specific conditions as
part of the required Testing and Monitoring Plan. Additionally, this guidance document contains
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some references to emerging testing and monitoring methods that were not yet well established
at the time this document was written. In a preliminary evaluation of GS monitoring
technologies, the U.S. Department of Energy (USDOE) National Energy Technology Laboratory
(NETL) assessed several technologies based on application, function, and stage of development
(USDOE NETL, 2009a). In this evaluation, technologies were rated as primary, secondary, or
potential in their ability to provide useful information for subsurface monitoring of injection well
integrity and the fate of the injectate and mobilized fluids. Primary technologies are considered
proven. Secondary technologies are considered to be currently available and appropriate for
complementing the use of primary technologies in tracking of the injectate and understanding
carbon dioxide behavior. Potential technologies were not yet considered mature at the time this
guidance was written (they had not yet been proven in commercial-scale projects) but may have
some future utility as a monitoring tool after additional field testing. It is important to note that
the appropriateness of certain technologies may change in the future as their deployment
increases, and this should be considered when selecting the site-specific methodologies for GS
projects.
The primary technologies identified by USDOE NETL (2009a) included geophysical well
logging (see the UIC Program Class VI Well Site Characterization Guidance), annulus pressure
monitoring (Section 2), and ground water geochemistry and pressure monitoring using wells
(Section 4). Of the geophysical techniques discussed in this guidance for plume and pressure-
front tracking (Section 5), certain seismic methods were rated as secondary technologies and
other methods were considered to be potential technologies. Emerging or experimental
technologies are identified in the text, and EPA recommends that owners or operators proposing
to deploy methods considered secondary or potential remain up to date on developments in those
areas, technically justify the use of the methods, and discuss the appropriateness of their
selection with the UIC Program Director (i.e., during the development of the Testing and
Monitoring Plan).
Discussion of testing and monitoring techniques provided in this guidance is organized into four
major categories of information, within each of the document sections listed above:
General Information: How the information helps meet the requirements of the Class VI
Rule, the objective of the technique, and the fundamental principles on which the
technique is based.
Application: Basic information pertaining to collection of data using the technique and
references to more detailed manuals and guidance documents.
Interpretation: The format the collected data will take and how to interpret the data to
characterize the measured system.
Reporting and Evaluation: The recommended format and required reporting frequency of
collected data and interpretation, the information and data that should be included in all
submittals, and the factors that the UIC Program Director may evaluate.
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This document has been written to help guide owners or operators as they fulfill the testing and
monitoring requirements of the Class VI Rule. Table 1-1 lists the Class VI Rule sections
addressed by each of the section of this guidance document.
Table 1-1. Crosswalk of guidance document sections and relevant Class VI Rule citations.
Sections of the Testing and Monitoring Guidance
Relevant Regulatory Citations
2. Mechanical integrity testing
2. 1 Mechanical integrity definitions and mechanical integrity
testing requirements
2.2 Internal MITs
2. 3 External MITs
2.4 Reporting results of MITs
40 CFR 146.87(a)(4)
40 CFR 146.89
40 CFR 146.92(a)
40 CFR 146.87(a)(4)
40 CFR 146.89(a)(l)
40 CFR 146.89(b)
40 CFR 146.87(a)(4)
40 CFR 146.89(a)(2)
40 CFR 146.89(c)
40 CFR 146.92(a)
40 CFR 146.91(a)(7)
40 CFR 146.91(b)(l)
3. Operational testing and monitoring during injection
3.1 Analysis of the carbon dioxide stream
3.2 Continuous monitoring of injection rate and volume
3.3 Continuous monitoring of injection pressure
3.4 Corrosion monitoring
3.5 Pressure fall-off testing
40 CFR 146.90(a)
40 CFR 146.91(a)(l)
40 CFR 146.91(a)(7)
40 CFR 146.88(e)(l)
40 CFR 146.90(b)
40 CFR 146.91(a)(2)
40 CFR 146.88(e)(l)
40 CFR 146.90(b)
40 CFR 146.91(a)(2)
40 CFR 146.89(d)
40 CFR 146.90(c)
40 CFR 146.91(a)(7)
40 CFR 146.90(f)
40 CFR 146.91(a)(7)
4. Ground water quality and geochemical monitoring
4.1 Design of the monitoring well network
4.2 Monitoring well construction
4.3 Collection and analysis of ground water samples
40 CFR 146.90(d)
40 CFR 146.90(g)(l)
40 CFR 146.90(d)
40 CFR 146.90(d)
40 CFR 146.90(g)(l)
40 CFR 146.91(a)(7)
5. Plume and pressure-front tracking
5.1 Class VI Rule requirements regarding plume and pressure-front
tracking
40 CFR 146.90(g)
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Sections of the Testing and Monitoring Guidance
5.2 Direct pressure-front tracking
5.3 Plume and pressure-front tracking using indirect geophysical
techniques
5.4 Use of geochemical ground water monitoring in plume tracking
Relevant Regulatory Citations
40 CFR 146.90(g)(l)
40 CFR 146.91(a)(7)
40 CFR 146.90(g)(2)
40 CFR 146.91(a)(7)
40 CFR 146.90(d)
40 CFR 146.90(g)(2)
6. Surface air and soil gas monitoring
6.1 Soil gas monitoring
6.2 Surface air monitoring
40 CFR 146.90(h)(l)-(2)
40 CFR 146.91(a)(7)
40 CFR 146.90(h)(l)-(2)
40 CFR 146.91(a)(7)
The remaining sections of this guidance document also reference complementary guidance
documents that were developed concurrently with this guidance document. These additional
Class VI guidance documents provide detail on additional activities that will occur during site
characterization, well construction, AoR delineation, and PISC. Site characterization procedures
are discussed in detail in the UIC Program Class VI Well Site Characterization Guidance.
Recommended procedures and materials for designing and constructing injection wells that
address the unique nature of carbon dioxide injection for GS are discussed in detail in the UIC
Program Class VI Well Construction Guidance. Delineation of the AoR and performance of
corrective action are covered in the UIC Program Class VI Well Area of Review Evaluation and
Corrective Action Guidance. Monitoring activities during PISC are discussed in the UIC
Program Guidance on Class VI Well Plugging, Post-Injection Site Care, and Site Closure. As
they are finalized, all of the Class VI guidance documents will be made available on EPA's
website at http://water.epa.gov/tvpe/groundwater/uic/class6/gsguidedoc.cfm.
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2 Mechanical Integrity Testing
Demonstrating and maintaining the mechanical integrity of a well is a key aspect of protecting
USDWs from possible endangerment due to injection activities. It is a specific requirement for
Class I, II, III, and VI wells in the UIC Program, and it may be a condition of some Class V
permits. Because induced formation pressures will typically be greatest at the injection well,
which penetrates USDWs, the injection zone, and intervening zones, the well is a possible
conduit for fluid movement and USDW endangerment. A variety of mechanical integrity testing
methods has been developed to provide information about leakage and fluid movement in and
around the well and enable a determination of whether there may be leaks in the tubing, casing,
or packer, or fluid flow behind the casing (through the cement sheath or in channels between the
cement and the geologic formation) (e.g., USEPA Region 5, 2008). Information in this guidance
document is based in large part on EPA experience and previous guidance for other UIC well
classes, including guidance and technical reports prepared for the UIC program on mechanical
integrity.
Mechanical integrity testing techniques may be based on a variety of principles, including
acoustic and nuclear methods and temperature and pressure measurements. These methods, when
selected appropriately for the site and used as part of a comprehensive Testing and Monitoring
Plan, can provide complementary information about the condition of the well and alert owners or
operators to well conditions that may potentially enable fluid to reach USDWs. Some mechanical
integrity testing and monitoring techniques are required by the Class VI Rule (e.g., continuous
annular pressure monitoring; see below), while other aspects of the mechanical integrity testing
requirements afford greater flexibility, such as the choice of external mechanical integrity testing
method. In all cases, owners or operators should specify in the Testing and Monitoring Plan
submitted as part of a Class VI permit application the tests and equipment they intend to use,
how those tests may provide complementary information, and the results from those tests that
would warrant further action. The sections below outline the Class VI requirements, briefly
explain internal and external mechanical integrity, and describe available MITs.
2.1 Mechanical Integrity Definitions and Mechanical Integrity Testing Requirements
MITs are required by the Class VI Rule prior to injection in a Class VI well [40 CFR
146.87(a)(4)], during the injection phase [40 CFR 146.89], and prior to well plugging after
injection has ceased [40 CFR 146.92(a)]. Additionally, the UIC Program Director may require
that casing inspection logs (CILs) be conducted periodically during injection [40 CFR
146.89(d)]. CILs complement MITs by providing additional information regarding any corrosion
within the long-string casing and are discussed in Section 3.4.3. This section discusses the well
logging and testing methods that are acceptable MITs for a Class VI well. The mechanical
integrity testing methods discussed herein are standard practices in the UIC Program and are not
unique to the Class VI Rule. Additional details regarding the execution of MITs can be found in
USEPA Region 5 (2008), USEPA (1982), and McKinley (1994). Well service companies'
technical manuals are another source of information regarding mechanical integrity testing.
As set forth in the Class VI Rule, a Class VI well has internal mechanical integrity if there is no
significant leak (i.e., fluid movement) in the injection tubing, packer, or casing [40 CFR
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146.89(a)(l)], and a Class VI well has external mechanical integrity if there is no significant
fluid movement through channels adjacent to the injection well bore [40 CFR 146.89(a)(2)].
Figure 2-1 illustrates three scenarios in which internal or external mechanical integrity has been
lost, resulting in the well being in violation of Class VI requirements:
The top example in Figure 2-1 shows a leak in the tubing. In a properly functioning Class
VI well system, the pressure will normally be higher in the annulus than in the tubing,
consistent with the Class VI requirements at 40 CFR 146.88(c), unless the UIC Program
Director determines that this might harm the integrity of the well or endanger USDWs.
Maintaining an annulus pressure that is greater than the operating injection pressure
would cause annular fluid to move into the tubing through a leak. In a situation where
either the UIC Program Director has approved a lower relative annular pressure or the
normal annular pressure has been lost, injectate may move from the tubing into the
annulus, as shown. Any tubing leak would be considered a loss of mechanical integrity.
In the middle example in Figure 2-1, mechanical integrity has been lost through a leak in
the casing, allowing annular fluid to leak outside the casing and potentially into the
formation. In cases where the formation opposite the casing leak is at a higher pressure
than the annulus pressure, formation fluid could instead enter the annulus. Annular
pressure is required to be monitored continuously [40 CFR 146.88(e)(l)], and shut-off
systems triggered by a loss of internal mechanical integrity are required [40 CFR
146.88(e)(2)] in order to halt injection quickly and limit the amount of leakage. The shut-
off system provides an additional protective barrier to USDW contamination. Failure of
the shut-off system to engage, however, would permit greater movement of annular fluid
or injectate, potentially endangering USDWs. This would also represent a mechanical
integrity failure. Additional information about shut-off systems in Class VI wells is
presented in the UIC Program Class VI Well Construction Guidance.
The bottom example in Figure 2-1 illustrates loss of external mechanical integrity
through channels in the cement that may allow injectate to migrate upwards and
potentially reach a USDW. The goal of annual external mechanical integrity testing is to
identify fluid movement through such channels. If a loss of mechanical integrity is
verified, the owner or operator must take immediate action to protect USDWs [40 CFR
146.94].
Demonstrations of internal and external mechanical integrity are described in Section 2.2 and
Section 2.3, respectively. A UIC Program Director may also allow the use of an alternative test if
approved by the EPA Administrator, pursuant to 40 CFR 146.89(e). If a well fails an MIT (or if a
loss of mechanical integrity is detected), the Class VI Rule requires that immediate action be
taken by the owner or operator to remediate the well and prevent endangerment of USDWs [40
CFR 146.88(f)].
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Annulus
Injected CO
Casing
Loss of internal
Cement mechanical integrity
Formation
Leak through hole
in casing
Cement
Surface casing
Lowermost USDW Base
Loss of external
mechanical integrity
Cement
Injection packer
|-*- Injection zone perforations
'-« Total depth
Formation
Fluid movement
through vertical
channel
Figure 2-1. Diagram of an improperly operated injection well showing examples of loss of mechanical
integrity and resulting fluid leakage (not to scale).
2.2 Internal MITs
Internal MITs are used to test for possible leaks in the casing, tubing, and packer [40 CFR
146.89(a)(l)]. The Class VI Rule requires an initial internal MIT prior to injection [40 CFR
146.87(a)(4)(i) and 146.89(b)]. Unless the UIC Program Director receives written approval from
the EPA Administrator to allow an alternative test pursuant to 40 CFR 146.89(e), an annulus
pressure test must be used as the initial internal MIT. The Class VI Rule also requires that
owners or operators continuously monitor certain parameters to demonstrate internal mechanical
integrity [40 CFR 146.89(b)]. Specifically, owners or operators must continuously monitor
injection pressure, injection rate, injected volume, pressure on the annulus between the tubing
and long-string casing, and annulus fluid volume, except during well workovers as defined in 40
CFR 146.88(d). Continuous monitoring of injection rate, pressure, and volume is discussed in
Sections 3.2 and 3.3.
Currently, the only acceptable alternative internal MIT that is available is the radioactive tracer
test, which can be used only under specific geologic conditions. EPA expects approval of the
radioactive tracer test as an alternative internal MIT to be rare for Class VI wells (see Section
2.2.3). However, the radioactive tracer test may provide supplementary information to verify or
further characterize loss of internal mechanical integrity.
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2.2.1 Annulus Pressure Test
General Information
The standard annulus pressure test is the most common and effective means to demonstrate
internal mechanical integrity within the UIC Program. It entails increasing the pressure of the
annulus to a specified level, then monitoring the annular pressure for a set period of time based
on established standards. The annulus pressure test is based on the principle that pressure applied
to fluids filling a sealed vessel, in this case the annular space, will remain approximately constant
in the absence of a fluid leak and/or significant changes in temperature. The test provides an
immediate demonstration of the internal mechanical integrity of the well. If loss of internal
mechanical integrity is detected by change of pressure during the test, action may be required to
remediate leakage pathways in the injection tubing packer or casing prior to the commencement
of injection [40 CFR 146.88(f)].
Application
The annulus pressure test is conducted after the well has been constructed and all well logs have
been conducted (see the UIC Program Class VI Well Construction Guidance). Prior to
conducting the test, the injection tubing and annulus are completely filled with liquid or gas and
the temperature in the well is allowed to stabilize. The addition of any unapproved substances to
the annulus liquid that might affect the outcome of the test may constitute falsification of the test
procedure and invalidate the test. For the test to be effective, the pressure applied to the annulus
system needs to be transmitted through the entire well bore. Therefore, no mechanical plug may
be placed above the packer in a well during the annulus pressure test.
After temperature stabilization, the annulus is pressurized to the test pressure. The appropriate
test pressure depends on several factors such as well depth, formation pressure, fluid density,
fluid column height, and anticipated injection pressure. Casing expansion, burst pressure, and
possible induced leakage or possible degradation of cement and casing should also be considered
while determining a test pressure. Experience with Class II wells offers some guidance in
determining appropriate test pressure; for example, regional requirements vary from 300 to 2,000
psi gauge (psig) (Nielsen and Aller, 1984). A common requirement is for the test pressure to be
set based on the maximum allowable injection pressure. It should be noted that injection
pressures for Class VI wells are expected to be higher than for Class II wells. For Class II wells,
EPA Region 8 (1995) sets a level of the maximum allowable injection pressure or 1,000 psig,
whichever is less. Another common requirement for Class II wells is for the annulus test pressure
to exceed the tubing pressure by 100 to 200 psi (Texas Railroad Commission, 2006; USEPA
Region 8, 1995). EPA recommends that the test pressure be determined in consultation with the
UIC Program Director and be informed by previous industry/state practices in the applicable
state and/or EPA region.
Following pressurization, the annular space is isolated from the source of pressure by a closed
valve or by disconnecting the pressure source entirely, and any pressure changes are then
measured. The appropriate test period would depend on the time that allows the pressure to
stabilize. Test times typically are between 15 minutes and one hour (Nielsen and Aller, 1984). To
be effective, the gauge used to measure the annular pressure should be sensitive enough to detect
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pressure changes that would result in a failure of the test, as determined in the Testing and
Monitoring Plan. EPA recommends that the sensitivity of this method and the equipment used be
discussed in the Testing and Monitoring Plan. Pressure gauge apparatuses are described in
Section 3.3. During isolation, measurement of pressure is best made at regular intervals (e.g.,
every 10 minutes). After the test period, the volume of the recovered liquid returned from the
annulus is expected to be proportional to the volume of the annulus and the amount of
pressurization (USEPA Region 5, 2008).
Interpretation
Pressure measurements taken during isolation of the annulus are analyzed for any change in
pressure that may indicate leakage and, therefore, failure of the test. Because the annulus
exchanges heat with its surroundings, small pressure changes that are not indicative of leakage
may occur during the test. Failure of the pressure to stabilize during the test period or a change
above a UIC Program Director-approved minimum value indicates a failure to demonstrate
mechanical integrity. A discussion of pressure changes that may indicate a failure to demonstrate
mechanical integrity for a given system should be included in the Testing and Monitoring Plan.
In addition, the amount of liquid returned after the isolation period may indicate a blockage at
shallow depth, and the entire well bore may not have been tested adequately. The amount of
liquid to be returned in a given test can be calculated based on the size of the annulus and the test
pressure (see USEPA Region 5, 2008).
2.2.2 Annulus Pressure Monitoring
General Information
The Class VI Rule requires continuous monitoring of the pressure on the annulus to verify
internal mechanical integrity during the injection phase of the project [40 CFR 146.89(b)].
Significant changes in annulus pressure measured during injection may indicate a loss of internal
mechanical integrity. Pressure monitoring also verifies that the annulus pressure is greater than
injection pressure (within the injection tubing), which is required by the Class VI Rule unless the
UIC Program Director determines that such a requirement might harm the integrity of the well or
endanger USDWs [40 CFR 146.88(c)]. If the owner or operator is concerned that maintaining the
greater annulus pressure would be detrimental to the well, EPA recommends that this be
discussed with the UIC Program Director to find an appropriate solution. Annulus pressure
monitoring to demonstrate internal mechanical integrity is performed in concert with continuous
monitoring of injection pressure, rate, and annulus fluid volume, all of which are required by 40
CFR 146.89(b) to achieve this demonstration (see Sections 3.2 and 3.3).
Application
Similar to the annulus pressure test, to be effective, continuous annulus pressure measurements
need to be made using a pressure gauge sensitive enough to detect pressure changes that would
result in a failure of the tests. It must also be considered that a pressure gauge at the surface will
require knowledge of temperature and density of the fluid in order to determine pressures down-
hole. Pressure gauge apparatuses are described in Section 3.3.
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Interpretation
Figure 2-2 presents a flow chart explaining the interpretation of the results of annulus pressure
monitoring. Continuous monitoring of the annulus is similar in methodology to the initial
pressure test, in that both methods involve monitoring annular pressure to detect unexpected
changes that may indicate fluid leakage. However, interpretation of continuous annular pressure
monitoring data is complicated by operational effects such as injection tubing expansion or
contraction, well bore temperature changes, changes in injection rate or temporary cessation of
injection, and changes in the injectate temperature. In the event of a casing leak opposite a
permeable zone, the pressure will normally fall to atmospheric pressure; if not, the range of
pressure change will be much diminished because the aquifer in communication with the leak
will buffer volumetric changes in the annulus. In the event of a tubing or packer leak, the annulus
pressure will track injection pressure. These two pressures will probably not be equal because of
a pressure loss due to friction in the injection tubing and density differences.
A leak that does not result in an unimpeded pressure change might not be apparent. Therefore, to
enhance the value of maintaining a positive pressure differential and the likelihood of detecting a
leak, the Class VI Rule requires owners or operators to monitor and report the volume of liquid
additions to the annulus system [40 CFR 146.91(a)(6)]. The results of these measurements are
accumulated, and a continuing need to add or remove fluid to maintain a set pressure may be
evidence of a leak in the well.
The standard used for evaluating continuous pressure measurement is typically similar to the
minimum value used during the annulus pressure test (USEPA Region 5, 2008). Minimum
threshold pressure changes that may indicate a loss of mechanical integrity are expected to be
identified in the Testing and Monitoring Plan by the owner or operator and approved by the UIC
Program Director. However, it may only be possible to apply the pre-determined minimum
pressure change standard when external factors that might affect the annulus pressure are stable.
Otherwise, liquid property changes occurring in response to changes in ambient conditions may
make determination of a leak-induced pressure change impossible. To provide an effective, real-
time demonstration of internal mechanical integrity, frequent review of pressure records is
necessary. This review would focus on the pressure in the annulus relative to atmospheric
pressure, injection pressure as measured at the surface, and pressure in formations adjacent to the
well bore.
Continual addition or removal of fluids to maintain annular pressure or annular pressure changes
greater than the UIC Program Director-approved minimum change that cannot be explained by
changing operational conditions (e.g., injection rate, pressure, or temperature) may indicate a
possible loss of internal mechanical integrity. Under these circumstances, EPA recommends
ceasing injection and conducting an annulus pressure test (Section 2.2.1). A radioactive tracer
survey may also be conducted to determine the depth or location of the leak (Section 2.2.3). If
the annulus pressure test indicates no loss of internal mechanical integrity, injection may resume.
If a loss of mechanical integrity is identified, the Class VI Rule requires that the owner or
operator cease injection and take appropriate action to repair the well and investigate any
potential impairment of a USDW [40 CFR 146.88(f)].
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Continuous measurement
of annular pressure and
fluid addition/removal
Is annular pressure
steady (e.g., changes less
than Director-approved
minimum threshold)
and greater than
injection pressure?
Are continual fluid
additions or losses
necessary to maintain
pressure?
Can annular
pressure changes
be explained by external
factors (e.g., injection
rate, temperature,
or pressure)?
me test indicates
no loss of internal
mechanical integrity
Continue monitoring
Annular
Pressure Increasing
Decrease is to
near zero and/or
very stable pressure
Pressure stabilizes
and resumes normal
behavior
There is a probable
deep casing leak
There is a probable
tubing leak
The test indicates
a possible loss
of internal mechanical
ntegrity. Perform
an annular pressure
test to further evaluate
Figure 2-2. Interpretation of annulus pressure monitoring for a typical injection well.
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2.2.3 Radioactive Tracer Survey
General Information
The Class VI Rule requires annulus pressure tests and monitoring to verify internal mechanical
integrity. However, if written approval is received from the EPA Administrator, the UIC
Program Director may allow alternative mechanical integrity testing methods [40 CFR
146.89(e)]. Currently, the only available alternative internal MIT is the radioactive tracer survey,
which is used under specific conditions (USEPA, 1987b). EPA expects that approval of the
radioactive tracer survey as an alternative internal MIT will be rare. The radioactive tracer
survey may require long periods of investigation and cannot feasibly be conducted continuously
during injection (and therefore cannot be used to comply with the continuous monitoring
requirements). However, the radioactive tracer survey provides supplementary information
regarding internal fluid leakage and therefore may be conducted in addition to annular pressure
monitoring. Importantly, the radioactive tracer survey may be used to locate the depth of a leak
within the well bore, unlike annulus pressure tests. As discussed in Section 2.3.4, in very specific
circumstances, radioactive tracer surveys may also be used as an external MIT.
Application
The radioactive tracer survey uses a wireline tool that consists of an injector stage, one or more
gamma radiation detector devices, and a collar locator (i.e., a logging tool used to detect the
threaded collar used to connect two joints of casing). The purpose of the collar locator is to
pinpoint the location of leaks in reference to permanent markers. This may also be done by
means of correlation to a gamma ray log that is scaled to show lithologic effects (see the UIC
Program Class VI Well Site Characterization Guidance). Using a collar locator lets the analyst
know immediately whether an identified leak is at a collar, while using a gamma ray correlation
log clarifies the strati graphic location of the leak. An anionic tracer material, such as iodine-131,
should be used to minimize molecular attraction to well and rock materials. The radioactive
tracer is usually iodine-131 because of its short (eight-day) half-life
A radioactive tracer survey may include more than one type of test (slug tracking or velocity
shot; see McKinley, 1994) and it involves releasing the radioactive tracer into the tubing above
the interval to be tested and subsequently measuring gamma radiation as it moves through the
well. In the slug test, a slug of tracer is released and the tool is lowered up and down the well
repeatedly while the position of the slug(s) is tracked. In the velocity shot method, the detectors
remain stationary and monitor the time at which the slug passes. The relative positions of the
injector and stationary detectors are variable. Three detectors are sometimes used, with two
below the injector. This allows for very accurate measurement of the speed of the injectate and
simplifies location of the upward limit of leakage by eliminating some repositioning of the tool.
Radioactive tracer surveys can be effective for locating leaks in both the tubing and the casing;
McKinley (1994) provides an example calculation showing an evaluation for both tubing and
casing leakage using data from several runs. Testing is commonly conducted during injection of
carbon dioxide and it.is best to maintain an injection rate as close to the project's maximum
injection rate as practical. See USEPA Region 5 (2008) for detailed instructions on conducting a
radioactive tracer survey as an internal MIT.
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Interpretation
After a slug of radioactive material is injected, that slug will move with the injectate into the
injection zone. If a measureable leak is present, the gamma ray detector will identify an area of
increased radioactivity after the slug has passed. Importantly, to distinguish the impact of
lithologic features, the gamma ray log needs to be compared to a baseline log that was run before
injection commenced (see the UIC Program Class VI Well Site Characterization Guidance).
Figure 2-3 presents an example radioactive tracer survey log conducted to test leakage through
casing; in this example, the tubing has been removed, further facilitating the determination of
leakage through and flow behind the casing. If, compared to the baseline gamma ray log, no
additional radiation is observed after the slug has passed, the well has demonstrated internal
mechanical integrity at the depth tested.
a.
01
O
0>
I
CO
Increasing
Gamma Radiation
Gamma ray log
taken before injection
Gamma ray log
taken after injection
, Cement
Casing
Casing
jf leak
.Fluid movement
in channel
Radioactive Tracer Log
Well Diagram
Figure 2-3. Radioactive tracer log showing the detection of a leak in the casing and subsequent fluid
movement in a channel behind the casing (USEPA, 1982; not to scale).
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2.3 External MITs
As defined in the Class VI Rule, external mechanical integrity refers to the absence of any
significant fluid movement into a USDW through channels adjacent to the well bore [40 CFR
146.89(a)(2)]. External mechanical integrity testing methods and technologies are designed to
detect fluid movement behind the casing that might result in movement of fluid into a USDW.
The Class VI Rule requires that an external MIT be conducted prior to injection [40 CFR
146.87(a)(4)], at least once per year until the injection well is plugged [40 CFR 146.89(c); 40
CFR 146.90(e)], and prior to injection well plugging after the cessation of injection [40 CFR
146.92(a)]. The UIC Program Director may also require additional tests [40 CFR 146.89(e)]. If a
loss of external mechanical integrity is detected, the Class VI Rule requires that immediate
action be taken by the owner or operator to remediate the well and prevent endangerment of
USDWs [40 CFR 146.88(f)].
Unless the UIC Program Director receives written approval from the EPA Administrator to allow
an alternative test [40 CFR 146.89(e)], the owner or operator must use at least one of the
following methods for external mechanical integrity testing: an oxygen activation log,
temperature log, or noise log [40 CFR 146.89(c)]. The choice of MIT(s) to use depends on
conditions of the site and well, and operator preference. As described below, the separate MITs
provide complementary, but not entirely duplicative, information regarding the well. In cases
where one test indicates the potential loss of mechanical integrity, follow-up tests can verify and
further characterize the potential leakage pathway. Changes in injection pressure (see Section
3.3) or annular pressure(s) (see Section 2.2) are typically the first indication of a loss of
mechanical integrity, and information from operational pressure monitoring may inform and
complement the tests listed in this section.
2.3.1 Oxygen Activation Log
General Information
The oxygen activation method is based on the ability of a wireline tool to activate oxygen into
nitrogen-16 (N16) within a short distance. This is accomplished by emitting high-energy neutrons
from a neutron source. N16 is an unstable isotope of nitrogen that is referred to as activated
oxygen. The N16 produced undergoes beta decay with a half-life of 7.1 seconds, with 69 percent
of the beta decay path accompanied by gamma radiation. The high-energy gamma ray easily
penetrates the casing, cement, tubing, and fluids in the well and can be measured by detectors in
the borehole (Bernard, 1995). The detectors are typically located at different distances from the
neutron source. The N16 generated from oxygen in the water serves as a water tracer. The
velocity of the water moving in a channel is estimated by timing the change in gamma radiation
between multiple detectors that are apart at known distances. The direction of flow can also be
assessed by positioning detectors below or above the generator (Bernard, 1995). Studies under
controlled conditions have shown that water velocities between two and 120 feet per minute can
be measured.
The results of oxygen activation logs are relatively simple to interpret. Compared to temperature
logs (Section 2.3.2), little or no shut-in (i.e., temporary cessation of injection) time is necessary.
The test also does not require a liquid-filled well bore. One disadvantage of this method is that it
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detects flow in a broad, but fixed, velocity range. The method also has a very small range of
investigation and cannot be used to demonstrate the absence of liquid movement through
confining layers (USEPA Region 5, 2008). EPA recommends that the owner or operator
demonstrate to the UIC Program Director that the tool is calibrated and used in a manner that
allows for the detection of the flow of gaseous, liquid, and/or supercritical carbon dioxide.
Application
The wireline logging tool consists of a high-energy neutron generator and multiple gamma ray
detectors. By spacing several detectors at increasing distances from the oxygen activation area,
interpretational accuracy is increased. Although the activated oxygen may be present in water
potentially moving along the well bore, activation of oxygen-bearing materials in the well may
give rise to a level of background radiation that needs to be accounted for in order to obtain a
valid measurement of the movement of fluid passing along the well bore. Therefore, the activity
due to the flowing water will need to be corrected for the stationary signal generated by
activation of oxygen-bearing well materials when there is no flow and for the normal
instrumental gamma background in the borehole (Bernard, 1995). This is normally achieved by
calibrating the instrument for the stationary signal and for the instrumental background in the
part of the well where there is no flow behind the casing. Alternatively, in applicable cases,
extending the measurement period at each station to the time beyond which the activated oxygen
in flowing water has been transported away might also allow for correction of the background
signal. The rate of decay indicated by the late measurements or in the representative section of
the well bore is used to calculate the theoretical levels of gamma radiation that would be
measured if there were no water movement. The difference between the calculated and measured
values is assumed to be the effect of the decay of activated oxygen carried to the vicinity of the
detectors as part of moving water. However, it is important to note that background
measurements made at different locations and different times may not always represent the
actual background at the time of this test, which may lead to some error in evaluating the flow
(Bernard, 1995).
To be effective, injection pressure needs to be maintained during the test to ensure identification
of fluid flow near the injection zone. The activation times used depend upon the water flow rate
and the positions of the detectors. While a long activation provides high signal strength, it might
also lead to losing part of or the entire signal, particularly at high water velocities. EPA
recommends that appropriate parameter values for the specific well conditions be discussed in
the Testing and Monitoring Plan. EPA also recommends that all measurements be taken for
periods of time sufficient for the well-specific conditions, with the well injecting at the
maximum normal rate. If anomalies are found, additional readings made above and below the
depth of the anomaly will confirm the anomalous reading and discover the extent of fluid
movement.
Interpretation
Measurements from two or more gamma-ray detectors may be used to calculate water flow
direction and velocity. If water flow outside of the casing is detected, this indicates the potential
loss of external mechanical integrity. A specific threshold velocity, below which the measured
water flow velocities would indicate false positives based on project-specific conditions, should
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be described in the Testing and Monitoring Plan. To minimize false positives, it is recommended
that all measurements be confirmed at several nearby depths and/or that measurements be taken
under a minimum of three varying injection rates: 75 percent, 50 percent, and 25 percent of the
maximum permitted injection rate. If a failure of an external MIT occurs, the Class VI Rule
requires that the owner or operator notify the UIC Program Director within 24 hours [40 CFR
146.91(c)(4)].
2.3.2 Temperature Log
General Information
Temperature logging is based on the principle that fluid leaking from the well will cause a
temperature anomaly adjacent to the well bore. Temperature logs are run after the well has been
shut-in (i.e., when injection is not occurring) to allow for temperature equilibration and after heat
radiation from well cement hydration has ended. The Class VI Rule requires that temperature
logs be conducted immediately after well cementing to evaluate the presence of cement behind
the casings [40 CFR 146.87(a)(2)(ii) and 146.87(a)(3)(ii)] (see the UIC Program Class VI Well
Construction Guidance). If temperature logs are to be used for external mechanical integrity
testing, several logs will be run prior to injection to comply with both cement evaluation and
external mechanical integrity testing requirements.
Fluid that leaks from the well bore will, in most cases, be of a different temperature compared to
native fluids at a given depth. Given sensors of sufficient sensitivity, it is possible to identify the
change in temperature resulting from heating or cooling by leaking fluid. Therefore, temperature
logs may also confirm that there is no flow of injectate through the rock surrounding the well
bore. In addition, it is possible to identify the source of the leaking fluid if flow is continuing
where small casing leaks occur.
To demonstrate mechanical integrity with a temperature log, the well needs to be shut-in long
enough for temperature effects to dissipate, leaving a relatively simple temperature profile.
Experience has shown that 36 hours is usually a sufficient shut-in period (USEPA Region 5,
2008). During the shut-in period, the temperature within the well bore will typically change
toward static geothermal conditions. If there has been a leak of fluid out of the well, the
temperature within the well bore at this location will change to a lesser degree and be measured
as an anomaly because the temperature of the surrounding formation will have been modified by
the leaking fluid (Figure 2-4). In particular, leaking fluid may introduce a cooling effect if it
decompresses.
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Increasing Temperature
Injected CO
I
f
CD
o
O)
Injecting
36-Hour shut in
Static
\
Annulus
Cement
Casing
Temperature Log
Well Diagram
Figure 2-4. Temperature log showing the detection of a leak in the casing (USEPA, 1982; not to scale).
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Application
In new wells, EPA recommends that baseline temperature logs to demonstrate external
mechanical integrity be performed as long as possible after the drilling of the well, but before
injection begins (see the UIC Program Class VI Well Site Characterization Guidance}.
Temperature effects due to circulation and infiltration of drilling fluid will persist for several
weeks or months after drilling is completed. Although these anomalies can mark permeable
zones, the existence of a temperature log that reflects the natural geothermal gradient can be of
great value in evaluating later analyses and for understanding other geophysical effects.
The wireline temperature logging tool consists of circuitry that responds to temperature change
by changing resistance to current flow. The response is linear, and temperature logs can
distinguish very small changes in temperature. To be effective, temperature logging tools should
have good thermal coupling to the borehole environment, which means that they are generally
not useful in gas-filled holes. Emerging temperature measurement technologies, such as the use
of fiber optic cables, may be more applicable to carbon dioxide-filled wells. During logging,
sampling is done at short intervals as the tool is lowered into the well, producing a record of the
entire well bore. Because the tool does not react to temperature change instantaneously and is
continuously moving, the measured temperature changes lag behind actual well bore temperature
changes by a consistent amount. The more slowly the tool moves, the closer the measured
temperatures are to actual temperatures.
If there are frequent changes in the temperature of the injectate or if process changes have caused
a significant change in the temperature of the injectate, it is important to record the average
temperatures of the injectate before existing logs were made, as well as the date of the change in
injectate temperature and the volume of liquid injected before and since that time. The scaling of
logs is very important. Features of significance are emphasized by compressing the depth scale
and expanding the temperature scale. A depth scale of one or two inches per 100 feet and a
temperature scale of one inch to two degrees Fahrenheit are appropriate in almost every case. If
multiple logs are run while the well is shut-in, it is helpful to display them on the same axes
(depth scale) for comparison. Gamma ray logs may be run simultaneously with the temperature
log. Gamma ray logs provide depth control and important information about the rock types along
the well bore. Additional detailed instructions for conducting temperature logs for external
mechanical integrity testing are available in USEPA Region 5 (2008).
Interpretation
EPA recommends that the temperature log be compared to a baseline log taken prior to injection
or to other logs taken at the same site. After the temperature effects caused by casing joints,
packers, well diameter, casing string differences, and cement have dissipated, the temperature
profiles are expected to be similar, although not identical. If the thermal effects of construction
features are evident in the temperature log, a longer shut-in period may be needed.
Identification of flow is based on relative differences between the collected temperature log and
the baseline log or the logs of nearby wells, if such logs exist. Although the gradients may be
quite different as a result of differing injection history, their profiles should be consistent.
Lithologic effects that appear on one log are expected to appear similarly in other wells at the
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same site. Anomalies are revealed by inconsistencies among logs made at the same site under
conditions that should result in thermal stability. If there are no logs suitable for comparison,
then deviations from a predictable geothermal gradient, modified by the effects of injection,
indicate anomalies.
When more than one log is run sequentially in the same well, temperature anomalies are likely to
become more prominent as the profile returns toward the natural geothermal gradient. An
example temperature log, showing an anomaly indicative of leakage, is shown in Figure 2-4.
Anomalies may indicate a failure of mechanical integrity. In such a case, an additional log may
be necessary to show whether forms apparent on the original log are evolving toward the forms
established on the log from another well. Comparison of these two new logs is expected to show
increasing similarity along the cased well bore; if not, then there may be flow along a channel
adjacent to the well bore. In the event that there are unresolved anomalies that might indicate the
absence of mechanical integrity, another approved method could be used to confirm the absence
of flow into or between USDWs. Depending on the nature of the fluid movement, radioactive
tracer, noise, oxygen activation, or other logs approved by the UIC Program Director may be
used to further define the nature of the fluid movement. For more information, see the detailed
description of temperature logging provided by McKinley (1994).
2.3.3 Noise Log
General Information
Channels in cements along well bores are very rarely uniform. When flow is occurring through
these channels, irregularities in channel cross section usually result in the generation of some
turbulence, which occurs in audible ranges. Sonic energy travels for considerable distances
through solids, allowing sensitive microphones to detect the effects of turbulent fluid flow at
sizeable distances. In addition, different types of turbulence result in sounds with different
frequencies. Single-phase turbulence results in low-frequency sounds, while two-phase
turbulence usually results in high-frequency sounds. High pass filters are used to determine the
intensity of noise detected within various frequency ranges.
Application
Noise logging tools are wireline tools that are essentially very sensitive microphones. Sampling
is done in a stationary mode, and the time required at each station is approximately three to five
minutes. Detected sounds are transmitted to recorders that measure the amount (loudness) of
sonic energy received over a period of time. A cumulative measure of the sound energy that has
been received is recorded. Because sonic energy travels for considerable distances through
solids, sampling can be done in a reconnaissance mode, with additional stations run where
increases in energy are detected to identify the exact locations of conditions that cause sonic
events. Similarly to temperature logs, sonic logs are more effective in liquid-filled holes because
of improved coupling.
Noise logging may be carried out while injection is occurring in many wells because flow
restriction caused by the logging tool is often insufficient to cause turbulence and detectable
noise. It is especially desirable to log while injecting when looking for flow resulting from
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pressure increases near the top of the injection zone. EPA recommends that noise measurements
be made at intervals of 100 feet to create a log on a coarse grid. If any anomalies are evident on
the coarse log, EPA recommends constructing a finer grid by making noise measurements at
intervals of 20 feet within the coarse intervals containing high noise levels. EPA also
recommends that noise measurements be made at intervals of 10 feet through the first 50 feet
above the injection interval and at intervals of 20 feet within 100 feet above that zone, at the base
of the lowermost USDW, and, in the case of varying water quality within the zone of USDWs, at
the top and base of each interval with significantly different water quality from the next interval.
Additional measurements may be made to pinpoint the depths at which noise is produced.
Interpretation
When the level of sound is low, a linear scale is used for reporting noise logs, and, when there
are intervals with higher sound, a logarithmic scale is used. Regardless of whether data are
presented in linear or log form, a vertical scale of one or two inches per 100 feet is
recommended. Noise logging is commonly used in other classes of injection wells, and the
interpretation of noise logs is well established. Departures from baseline noise levels in the log
indicate an anomaly. Therefore, it is important to collect adequate baseline data to understand
normal fluctuations during operation and to be able to identify what constitutes a significant
departure from baseline. Figure 2-5 shows a noise log indicating leakage through a cement
channel adjacent to the well bore. Ambient noise while injecting that produces a signal greater
than 10 millivolts (mV) may indicate leakage and potential loss of external mechanical integrity.
If a lack of external mechanical integrity is identified, the Class VI Rule requires that action be
taken to remediate the well [40 CFR 146.88(f)]. If the log measurements are ambiguous, another
testing method may be used for confirmation.
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Injected C02
Noise Log Display
Cement
Surface casing
Lowermost USDW Base
Fluid departure
Permeable Formation
Annulus
Long string casing
Borehole
Channel
constriction
Permeable Formation
Injection packer
Injection zone perforations
Total depth
.V)
Figure 2-5. Diagram of fluid leakage through channel in cement and corresponding noise log (not to scale).
Note that this hypothetical schematic represents an injection well that likely is operating outside of permit
conditions, due to the large areas with no or little cement.
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2.3.4 Alternative Methods for External Mechanical Integrity Testing
The Class VI Rule requires that an oxygen-activation log or other tracer survey, a temperature
log, or a noise log be conducted to comply with external mechanical integrity testing
requirements [40 CFR 146.89(c)]. However, alternative methods beyond those listed may be
allowed by the UIC Program Director if written approval is received from the EPA
Administrator [40 CFR 146.89(e)]. A request to use methods other than those currently approved
by EPA requires this additional EPA approval process and publication of the alternative
method's approval in the Federal Register, as required at 40 CFR 146.89(e). Currently, there are
no alternative methods that may feasibly be used for external mechanical integrity testing beyond
those listed here, except under very limited circumstances. The Class VI Rule does not preclude
the use of methods that may be developed in the future, as long as use of these methods is
approved by the EPA Administrator following the procedure in 40 CFR 146.89(e).
Radioactive tracer surveys have been used for assessing external mechanical integrity and can be
very sensitive. Radioactive tracer survey instrumentation and basic methods for external MITs
are the same as those used for internal mechanical integrity testing (as described in Section
2.2.3). McKinley (1994) provides information on radioactive tracer tests and their interpretation,
including how to discern fluid movement behind the well.
By regulation, use of radioactive tracer surveys as the sole test for external mechanical integrity
testing is limited to cases where there are no permeable formations between the injection zone
and the lowermost USDW (USEPA, 1987b). Essentially, a single confining layer would need to
be present that separates the injection zone from the lowermost USDW. Given the depths of
Class VI wells and the significant siting requirements, it is unlikely that this condition will be
met for Class VI wells. However, radioactive tracer tests may be used to complement the
external MITs discussed above.
Additional external MITs include evaluation of cementing records and cement evaluation tools
(see the UIC Program Class VI Well Construction Guidance), both of which have previously
been used in isolated circumstances for external mechanical integrity testing. These methods,
however, do not directly detect fluid leakage and do not identify any potential leakage pathways
in the cement. Therefore, the use of cement evaluation tools and cementing records is not
acceptable as the sole basis for demonstrating external mechanical integrity of Class VI wells.
2.4 Reporting the Results of MITs
The Class VI Rule requires that the owner or operator submit a descriptive report of all required
MITs conducted at the site to EPA in an electronic format [40 CFR 146.91(e)]. The results of
initial MITs, performed prior to injection, must be submitted to the UIC Program Director prior
to the commencement of injection [40 CFR 146.82(c)(8)]. The results of continual monitoring to
demonstrate internal mechanical integrity must be submitted in the required semi-annual
operational reports [40 CFR 146.91(a)]. Any failure to maintain mechanical integrity must be
reported to the UIC Program Director within 24 hours [40 CFR 146.91(c)], and all results of
periodic MITs must be reported within 30 days of testing, regardless of the results [40 CFR
146.91(b)].
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When reporting the results of MITs, it is recommended that the submittal to the UIC Program
Director include:
Chart and/or tabular results of each log or test.
The interpretation of log results provided by the log analyst(s).
Description of all tests and methods used.
Records and schematics of all instrumentation used for the test(s) and the most recent
calibration of any instrumentation.
Identification of any loss of mechanical integrity, evidence of fluid leakage, and remedial
action taken.
The date and time of each test.
The name of the logging company and log analyst(s).
For any tests conducted during injection, operating conditions during measurement,
including injection rate, pressure, and temperature (for tests run during well shut-in, this
information should be provided relevant to the period prior to shut-in).
For any tests conducted during shut-in, the date and time of the cessation of injection and
records of well stabilization.
The UIC Program Director will evaluate the results and interpretations of MITs to independently
assess the integrity of the injection well.
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3 Operational Testing and Monitoring During Injection
The Class VI Rule requires owners or operators of Class VI wells to monitor injectate properties,
injection rate, pressure, and volume, and corrosion of well materials, and perform pressure fall-
off testing [40 CFR 146.90(a), (b), (c), and (f)]. Analysis of the carbon dioxide stream with
sufficient frequency to yield data representative of its chemical and physical characteristics is
required under the Class VI Rule [40 CFR 146.90(a)]. Analysis of the carbon dioxide stream is
also required prior to commencing injection [40 CFR 146.82(a)(7)(iv)]. This analysis will
identify the constituents of the carbon dioxide stream, including impurities that might alter the
corrosivity or other properties of the injectate downhole. Such information is necessary to inform
well construction and the project-specific Testing and Monitoring Plan. Information on the
composition of the injectate will also support considerations regarding the reactivity of the
injectate with the subsurface matrix and formation fluids; these considerations may be used in
the computational modeling for AoR delineation. The details of the injectate sampling process
and the frequency of sampling and analysis, along with a description of how the results may
indicate deviation from planned project operations, will be described in the UIC Program
Director-approved, site- and project-specific Testing and Monitoring Plan.
The Class VI Rule requires the installation and use of continuous recording devices to monitor
injection rate, volume, and pressure [40 CFR 146.88(e) and 146.90(b)]. This information is used
to verify compliance with Class VI permit conditions and to inform AoR reevaluations.
Additionally, anomalies in injection rate and/or pressure may be an indicator of deviation from
planned operations due to field conditions or leakage from the authorized zone. EPA
recommends that the Testing and Monitoring Plan include a discussion of expected variations in
these parameters and how the proposed strategy will detect any problematic deviations in project
performance.
Owners or operators of Class VI wells are required to conduct a pressure fall-off test at least
once every five years [40 CFR 146.90(f)]. Pressure fall-off tests can indicate whether reservoir
pressures are consistent with predictions. Results of these tests will inform and verify site
characterization information and AoR reevaluations, and confirm that the project is operating
properly and that the injection zone is responding as predicted. EPA recommends that the
frequency of pressure fall-off testing be established in the Testing and Monitoring Plan.
This section discusses how owners or operator may conduct operational monitoring activities
performed during the injection phase.
3.1 Analysis of the Carbon Dioxide Stream
The Class VI Rule requires that the injected carbon dioxide stream be analyzed with sufficient
frequency to yield data representative of its chemical and physical characteristics [40 CFR
146.90(a)]. These characteristics include fluid composition (i.e., fraction of carbon dioxide and
other constituents measured on a volumetric or mass basis at a known temperature and pressure),
temperature, and pressure, as well as additional parameters that may be used for understanding
potential interactions between the injectate and the formation.
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The primary purpose of analyzing the carbon dioxide stream is to evaluate the potential
interactions of carbon dioxide and/or other constituents of the injectate with formation solids and
fluids. This analysis can also identify (or rule out) potential interactions with well materials.
Establishing the chemical composition of the injectate also supports the determination of whether
the injectate meets the qualifications of hazardous waste under the Resource Conservation and
Recovery Act (RCRA), 42 U.S.C. 6901 et seq. (1976), and/or the Comprehensive Environmental
Response, Compensation, and Liability Act, (CERCLA) 42 U.S.C. 9601 et seq. (1980).
Additionally, monitoring the chemical and physical characteristics of the carbon dioxide (e.g.,
isotopic signature, other constituents) may help distinguish the injectate from the native fluids
and gases in case of a leak. Injectate monitoring is required at a sufficient frequency to detect
changes to any physical and chemical properties that may result in a deviation from the permitted
specifications.
This section discusses the analysis of the carbon dioxide stream, which may include constituents
other than carbon dioxide, such as sulfur dioxide, hydrogen sulfide, nitrogen oxides,
hydrocarbons, carbon monoxide, methane, water vapor, nitrogen, oxygen, mercury, or arsenic
(Apps, 2006). Owners or operators may investigate adapting methods from those available for
flue gas analysis in industrial settings as well as analytical methods for verification of the purity
of carbon dioxide used for supercritical fluid applications or the food industry.
Chemical analysis of carbon dioxide and potential trace constituents for non-GS applications
(i.e., flue gas and food-grade carbon dioxide) is typically performed in the gas phase. Because
carbon dioxide for GS will in most cases be transported and injected in the supercritical phase,
samples may need to be extracted from the pipeline or wellhead via a valve and permitted to
decompress into a gaseous phase within a sample holder or other device for analysis by one of
the methods described below. If samples are allowed to decompress to the gas phase for
chemical analysis, temperature and pressure will both drop and will no longer represent
conditions in the pipeline or as injected. Therefore, EPA recommends that, if possible, the
temperature and pressure measurements represent the in situ conditions at the injection point.
Alternatively, samples may be allowed to decompress prior to analysis and standard methods
may be used to calculate chemical and physical properties at in situ pressure and temperature
from the results of analysis of the decompressed samples.
Owners or operators are encouraged to consult with the UIC Program Director to establish a
carbon dioxide stream characterization protocol that is tailored to the specifics of the GS project.
EPA recommends that the methods used to characterize the stream be specified in the Testing
and Monitoring Plan. An owner or operator who is also subject to requirements under Subpart
RR of the Greenhouse Gas Mandatory Reporting Rule may note that the carbon dioxide
composition samples must be collected from a point immediately upstream or downstream of the
flow meter [40 CFR 98.440-98.449]. Additional information on Subpart RR may be found in the
Subpart RR General Technical Support Document (TSD) (USEPA, 2010).
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3.1.1 Flue Gas Analysis Methods
General Information
Owners or operators may consider the feasibility of adapting gas analysis methods from
industrial applications to the monitoring needs of a GS project (in which analysis methods are
used in post-capture analysis of the carbon dioxide stream). In industrial settings, flue gas
analysis is conducted both for determining the optimal operating conditions for equipment and
for compliance with federal and state emissions standards. Monitoring in such settings may be
conducted with portable analytical units or with dedicated stationary gas monitoring systems
called continuous emission monitoring (CEM) systems.
There are several types of CEMs. Extractive CEMs, which withdraw a sample from the stream
and convey it to sensors, may be the most amenable to a GS setting because they allow for a
wide range of detector types and target analytes. EPA notes that a process providing continuous
monitoring of the injection stream is not necessarily appropriate for all GS projects but might be
beneficial in certain settings where the injectate could be subject to variable composition.
Because CEMs are installed permanently, they require regular maintenance and a housing unit
for protection from environmental conditions. CEMs are not adapted specifically for GS
applications at this time, but EPA recommends that interested owners or operators consider
discussing their needs with manufacturers.
Portable flue gas analyzers may be a viable option for periodic ex situ chemical analysis of the
carbon dioxide stream. These instruments use infrared (IR) and electrochemical sensors to detect
a variety of gas constituents, such as carbon dioxide, sulfur dioxide, nitrogen oxides, methane,
oxygen, and carbon monoxide. Current manufacturer information on product specifications
suggests that some units have detection limits sufficient to detect the levels of impurities
expected in captured carbon dioxide streams (e.g., Sass et al., 2005).
Application
Extractive CEMs generally employ a sampling probe, filter, sample line, gas conditioning unit,
flow meter, calibration port, and a series of gas analyzers (Jahnke, 2000). The types of CEMs
available and their associated analytical techniques are further described in EPA's CEMs
information and guidance documents (USEPA, 2007) and by Jahnke (2000). Extractive CEMs
are capable of analyzing for key constituents expected in GS project injectate, including carbon
dioxide, oxygen, sulfur dioxide, nitrogen oxides, and carbon monoxide, hydrochloric acid,
mercury, volatile organic compounds (VOCs), and moisture. Analysis of arsenic in gases appears
to be less frequently performed than mercury analysis, but it is likely to be accomplished by
similar methods as mercury. The sensors employed in CEMs can include, among others, IR
methods, chemiluminescence, electroanalytical methods, absorption spectroscopy, mass
spectrometry, and gas chromatography. The selection of specific detectors in a unit would
depend upon anticipated constituents in the carbon dioxide stream.
Portable flue gas analyzers employ IR methods, in particular non-dispersive IR (NDIR), and
electrochemical sensors; they measure a more limited range of constituents than CEMs (e.g.,
carbon dioxide, oxygen, sulfur dioxide, nitrogen dioxide, methane, carbon monoxide) and do not
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measure metals or hydrocarbons. A sample of gas can be tested in situ using a probe or collected
and transported to the measurement device. Grab samples are often collected for analyses where
it is not practical or safe to insert a probe (Fegen, 2005).
EPA recommends that the owner or operator evaluate the detection range of the analyzer for
each constituent to ensure that any necessary dilution takes place. They may need to consult with
manufacturers to ensure that potential analytical interferences among constituents are minimized.
For example, several gases have NDIR absorption bands that are close together (Jahnke, 2000);
alternative IR bands may need to be used for some gases, or alternate analyzers chosen. It is
recommended that a discussion of selected methods and their detection sensitivities is included
in the Testing and Monitoring Plan and discussed with the UIC Program Director.
Interpretation
The data from flue gas analyzers are reported either as parts per million by volume (ppmv) or
milligrams per cubic meter (mg/m3). The conversion of mg/m3 to ppmv for each component
requires converting milligrams to moles then to cubic meters with an equation of state. CEMs
provide nearly continuous data that are usually sent to a remote computer.
3.1.2 Laboratory Chemical Analysis
General Information
Owners or operators may consider the feasibility of adapting laboratory analysis methods
employed for non-GS carbon dioxide applications. Injectate samples may be collected at the
wellhead or transmission line and transported to an in-house, temporary, or off-site laboratory
that has expertise in the analysis of gas samples and that is deemed acceptable by the UIC
Program Director. (The Testing and Monitoring Plan should identify any commercial
laboratories the owner or operator plans to use for chemical analyses of the injectate.)
Carbon dioxide is used for laboratory applications in supercritical fluid extraction and
supercritical fluid chromatography, which require the carbon dioxide to be high quality.
Accordingly, ASTM International (ASTM) has developed a standard guide for the purity of
carbon dioxide intended for such applications (ASTM, 2011). This standard includes
descriptions of analytical methods such as gas chromatography and the use of a total
hydrocarbon analyzer. These methods may be considered for adoption in analyzing the carbon
dioxide stream for certain types of impurities. For example, an adsorbent concentration method
followed by gas chromatography may be used for the analysis of hydrocarbons and halocarbons.
A method published by the South Coast Air Quality Management District (2008; Method S.C.
10.1, alternative to EPA Method 10) analyzes carbon dioxide in a gas sample by gas
chromatography with detection performed by a NDIR detector.
Some equipment manufacturers have developed similar methods suitable for the analysis of
impurities in carbon dioxide. These methods use gas chromatography for separation of the
various constituents in the sample, followed by detection with any of several available
instruments. Gas chromatographic methods have much lower detection limits than the IR and
electrochemical detectors used in portable flue gas analyzers or CEMs. The descriptions below
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are intended to provide examples of the analytical approaches available for various constituents
that may be present in a carbon dioxide stream. Owners or operators are encouraged to contact
commercial laboratories that handle gas samples to discuss their site-specific analytical needs.
Application
Gas chromatography with a pulsed flame photometric detector and flame ionization detector
(FID) can be used for measuring trace sulfur and hydrocarbon constituents in carbon dioxide
streams (e.g., Agilent, 2010). This method permits highly sensitive analyses of sulfur gases
(hydrogen sulfide, sulfur dioxide, carbonyl sulfide) and some hydrocarbons (e.g., acetaldehyde,
benzene and light hydrocarbons). In addition, gas chromatograph analyzers have been
specifically designed for detection of impurities in food-grade carbon dioxide. These units use a
sulfur chemiluminescence detector for sulfur compounds (e.g., hydrogen sulfide, carbonyl
sulfide, sulfur dioxide, mercaptans, aromatic sulfur compounds). A photo ionization detector
(PID) is used for aromatic hydrocarbons (benzene, toluene, xylenes, ethylbenzene), and an FID
is used for certain other hydrocarbons (Arnel, 1999). A nitrogen chemiluminescence detector can
be used for measurement of nitrogen oxides.
Mercury in flue gases is generally measured by one of several forms of spectroscopy. ASTM
Method D5954 (ASTM, 2006a) describes a method for measurement of both inorganic and
organic mercury in natural gas. The mercury is pre-concentrated by adsorption onto gold-coated
beads and analyzed by atomic absorption spectrophotometry. Another method, cold vapor atomic
fluorescence spectrometry, uses a sorbent trap that is inserted into a natural gas stream, with a
metered amount of gas passed through it. The mercury is detected by fluorescence spectrometry
(EPA Method 1631 Revision E; USEPA, 2002c). Arsenic may be similarly quantified by
retention onto a solid sorbent followed by analysis by X-ray fluorescence or atomic
spectroscopic techniques (e.g., Attari and Chao, 1993).
Interpretation
The detection methods that are coupled to gas chromatography generally produce outputs in the
form of concentrations in micrograms per liter (|ig/L) or, at the same analyte density, parts per
billion by volume (ppbv). Common software packages used with gas chromatographic methods
automatically calculate chemical concentrations from chromatogram curves, requiring
calibration data to be provided. Formal analytical reports take the form of chromatograms with
peak areas and resulting concentrations.
3.1.3 Reporting and Evaluation of Carbon Dioxide Stream Analysis
The Class VI Rule requires that the owner or operator submit any new data from analysis of the
carbon dioxide stream in the semi-annual reports [40 CFR 146.91(a)(7)]. The data are required to
be submitted to EPA in an electronic format [40 CFR 146.91(e)], and it is recommended that the
submission include:
A list of chemicals analyzed, including carbon dioxide and other constituents (e.g., sulfur
dioxide, hydrogen sulfide, nitrogen oxides).
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A description of the sampling methodology, noting any differences from protocols listed
in the Testing and Monitoring Plan and an explanation of why a different method was
used.
Any laboratory analytical methods used, the name of the laboratory performing the
analysis, and official laboratory analytical reports including sample chain-of-custody
forms.
All sample dates and times.
A tabulation of all available carbon dioxide stream analyses, including any quality
assurance/quality control (QA/QC) samples.
Interpretation of the results with respect to regulatory requirements and past results.
Identification and explanation of data gaps, if any.
Any identified necessary changes to the project Testing and Monitoring Plan to ensure
continued protection of USDWs.
The UIC Program Director will evaluate the submittal to ensure that the composition of the
injected stream is consistent with permit conditions and that it does not result in the injectate
being classified as a hazardous waste.
3.2 Continuous Monitoring of Injection Rate and Volume
General Information
The Class VI Rule requires the use of continuous recording devices to monitor injection rate and
volume and/or mass [40 CFR 146.88(e)]. The monthly average, maximum, and minimum values
for injection pressure, flow rate, and volume must be reported to the UIC Program Director by
the owner or operator in the semi-annual reports [40 CFR 146.91(a)(2)]. This information is used
to verify compliance with the operational conditions of the permit and to inform AoR
reevaluation.
Flow rate data are also used to determine the cumulative volume of carbon dioxide injected [40
CFR 146.91(a)(5)], which is not measured directly. If flow rate is measured on a mass basis (e.g.,
kg/sec), pressure and temperature measurements can be used to determine fluid density and
convert mass values to volumetric measurements. Use of flow rate on a mass basis is particularly
recommended because carbon dioxide is compressible; mass, in conjunction with downhole
pressure and temperature data, can constrain the volume of the injectate at depth, helping to
understand volume data as related to reservoir storage capacity. In performing this calculation,
owners or operators should be aware of how the composition of the carbon dioxide stream may
affect its density. Additional information may also be found in the Subpart RR General TSD
(USEPA, 2010).
Injection rate can be continuously monitored using a flow metering device. Flow metering is a
common practice in most industrial processes, and many types of flow meters have been
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developed for a variety of applications. The applications most similar to GS include metering of
natural gas and carbon dioxide in the petroleum industry. The types of meters used in these
practices include differential pressure meters (orifice plates, venturi meters); velocity meters
(turbine meters, ultrasonic meters), which measure the velocity of the fluid; and mass meters
(thermal meters, Coriolis meters), which measure the mass of fluid flow past the meter. These
approaches are discussed in more detail in the following sections, and schematics of common
flow meters are given in Figure 3-1. Because continuous measurement of injection rate and
volume is important for verifying that the well is operating as stipulated by the UIC permit, the
UIC Program Director may, in certain circumstances, require the owner or operator to have
backup flow meters. This may be appropriate in projects where operating conditions are variable
or if conditions are near the tolerance limits or measurement range for the flow meters.
Application
Differential pressure meters and velocity meters depend upon the properties of the fluid,
especially temperature, pressure, and density. If the fluid properties are known and constant, they
can be programmed into the meter, which can calculate flow rate. Density can either be
measured directly or it can be calculated using equations of state and pressure and temperature
readings. Otherwise, these values will need to be measured and input to a separate computational
device. Measurements from mass flow meters do not depend on the pressure and temperature of
the gas, and these meters do not require additional instrumentation. Thermal meters do require
knowledge of the heat capacitance of the fluid. If the heat capacitance is expected to change
because of variations in fluid composition, then fluid composition will need to be measured. In
all cases, signals from the flow meter will be input into a device that will calculate the flow rate.
The flow rate can then be recorded and stored electronically.
In selecting a meter type, owners or operators should weigh the advantages of the various meter
types against their monitoring goals and needs. In preparing the Testing and Monitoring Plan,
owners or operators should describe the expected accuracy and precision of their proposed
meters and explain how they compare to their anticipated pressures and the sensitivity needed to
detect deviations from permitted conditions. Owners or operators should also consider any
potential shifts in accuracy or precision that may take place in their meters due to wear, exposure
to carbon dioxide, and age. Proposed maintenance and calibration procedures should be included
in the Testing and Monitoring Plan, along with procedures for determining when replacement is
necessary. In addition, owners or operators should specify in the Testing and Monitoring Plan
how average values will be calculated for injection pressure, flow rate, and volume pursuant to
reporting requirements under the Class VI Rule, at 40 CFR 146.91(a).
Orifice plate differential meters are one of the most common meter types used to measure gas
flow. They are considered standard in natural gas pipelines and carbon dioxide pipelines
(McAllister, 2005). Orifice plates use Bernoulli's equation to determine flow by measuring the
pressure drop across a plate with a hole (Maxiflo, 2009). Orifice meters are simple to use, have
no moving parts, and are not as sensitive to density changes as some other meter types.
Disadvantages include a limited range and lower accuracy than other meters.
Venturi differential meters use the same principle as orifice plates, but the pressure differential
is measured across a constriction in a long tube. The constriction gradually widens out to the
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original pipe diameter, and this slow widening allows some recovery of pressure and results in a
lower pressure drop than in an orifice plate. The advantages of a venturi meter are similar to
those of an orifice plate; they are simple and have no moving parts. They tend to be more
accurate than orifice plates but have a higher sensitivity to fluid properties.
Turbine velocity meters operate by placing a multiple-blade rotor in the flow path
perpendicular to the flow direction. The flow moves the rotors and the flow rate is calculated by
measuring the rotational speed of the blades. Turbine movement can be measured by magnetic
pickup, photoelectric cells, gears, or tachometers. The advantages of turbine meters are high
accuracy and applicable range of flow. Disadvantages include high pressure drop, dependence on
fluid properties, and potential wear of moving parts.
Ultrasonic velocity meters operate by measuring ultrasonic waves as they travel through the
fluid. There are two types of ultrasonic meters: Doppler meters and transit time meters. Doppler
meters measure the change in frequency of ultrasonic waves reflected from entrained particles or
bubbles and are not appropriate for measuring gases. Transit time instruments measure the time
it takes for ultrasonic waves to travel between sensors both with and against the flow. The
difference between the measurements is proportional to the flow. The advantages of ultrasonic
meters are that they do not cause a pressure drop and are available in clamp-on varieties that can
be retrofitted to pipes without cutting the pipe or stopping flow. Disadvantages include the fact
that carbon dioxide strongly attenuates ultrasound waves, therefore requiring specially designed
instruments to offset the attenuation caused by carbon dioxide (van Helden et al., 2009).
Thermal mass meters use a heating element that is isolated from the flow. The amount of heat
conducted away from the element is proportional to the mass flow. Built-in calibrations allow the
unit to convert the temperature change to a flow rate. An advantage of thermal mass meters is
that they operate independently of pressure, density, and viscosity. They are intermediate in
accuracy, and their operating range is less than those of turbine and ultrasonic meters but greater
than those of orifice plates and venturi meters. They cause a lower pressure drop than most
meters with the exception of ultrasonic meters. Disadvantages include a high dependence on
accurate calibration.
Coriolis mass meters are based on the Coriolis force experienced by the fluid as it passes
through a vibrating tube. The flow passes through a bent tube that is vibrated using a magnetic
device. The flow in the tube resists the motion caused by the vibration and causes the tube to
twist. The twist is proportional to the mass flow rate. Sensors measure the speed of the vibration
and use it to calculate the mass flow rate. The advantage of Coriolis meters is that they are
independent of fluid properties such as temperature, pressure, density and viscosity. They can
measure an intermediate range of flow rates and produce an intermediate pressure drop.
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dp = pressure difference
p = pressure
v = flow velocity
A= flow area
Orifice Flowmeter
Stainless
steel body
Flow
direction
Front rotor
support
Venturi Flowmeter
Magnetic
pickup
/- Support
/ retainer
MSsss^xl
Rear
rotor support
- Thrust ball
Bearing flush hole
Shaft
bushing
Turbine Velocity Flowmeter
Fluid forces reacting to
vibration of flow tube
Twist angle
Twist angle
End view of flow
tube showing twist
Coriolis Mass Flowmeter
Figure 3-1. Schematic of common flow meters (not to scale).
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Industry standards for flow meter applications should be consulted during selection, installation,
and use. Relevant industrial standards include:
American Gas Association (AGA) Report No. 11 - Measurement of Natural Gas by
Coriolis Meters.
AGA Report No. 9 - Measurement of Gas by Multipath Ultrasonic Meters.
AGA Report No. 3 - Orifice Metering of Natural Gas.
AGA Report No. 7 - Measurement of Natural Gas by Turbine Meter.
ASME - MFC-3M-2004 - Measurement of Fluid Flow in Pipes Using Nozzle, Orifice,
Venturi Meters.
ASME - MFC-4M-1986 - Measurement of Gas Flow by Turbine Meter.
ASME - MFC-11M-2006 - Measurement of Fluid Flow by Coriolis Mass Flow Meters.
Interpretation
The various meters discussed above will provide either flow rate data in units of volume or mass
per time, or fluid velocity data in units of length per time. Injection flow rates may be calculated
from velocity data by multiplying measured values by the cross-sectional area of the pipe or
tubing at the measurement point. An example of a plot of measured injection rate over time is
provided in Figure 3-2. Injection volumes are calculated by multiplying measured flow rates by
the length of time for which the flow rate measurement is valid. Cumulative injection volume
may be continuously calculated over the life of the project and the term of the reporting period.
In addition, if volume (rather than mass) measurements are taken, it is recommended that the
total mass of the injectate be calculated based on density as determined by pressure and
temperature.
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900
800
1600
1400
C4-30 Injection Well
Wellhead Injection Pressure and Injection Rate
Temporarily drop
injection rate to 300 tpd
at compression facility
Injection Rate
Injection pressure
[Stop Injection |
2/20/08 2/22/08 2/24/08 2/26/08 2/28/08 3/1/08 3/3/08 3/5/08 3/7/08 3/9/08
Date
Figure 3-2. Example plot of measured injection rate and pressure measured at wellhead, Midwest Regional Carbon Sequestration Partnership
(MRCSP) Michigan Basin Validation Test (image provided by Battelle Memorial Institute).
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Reporting and Evaluation
Injection rate data must be submitted to EPA in the semi-annual reports [40 CFR 146.91(a)(2)].
Data will be submitted in electronic form directly to EPA, where they can then be accessed both
by the UIC Program Director and other EPA offices. Monthly average data submissions are
expected for each of the six months covered in the report. It is recommended that all of the
information below be included in the report:
Tabular data of all flow rate measurements and a description of interpretation of the data
aided with charts or graphs.
A description of the measuring methodology and technology, noting any differences from
protocols given in the Testing and Monitoring Plan and an explanation of why a different
methodology was used.
Monthly average flow rate.
Monthly maximum and minimum values.
Total volume (mass) injected each month.
Cumulative volume (mass) for the project.
If flow rate exceeded permit limits during the reporting period, an explanation of the
event(s), including the cause of the excursion, the length of the excursion, and response
to the excursion.
Identification and explanation of data gaps, if any.
Any identified necessary changes to the proj ect Testing and Monitoring Plan to ensure
continued protection of USDWs.
The UIC Program Director will evaluate the data to determine compliance with permit
conditions. The owner or operator is required to report, within 24 hours, any noncompliance with
a permit condition that may cause fluid migration into or between USDWs [40 CFR
146.91(c)(2)].
3.3 Continuous Monitoring of Injection Pressure
General Information
The Class VI Rule requires the installation and use of continuous recording devices to monitor
injection pressure [40 CFR 146.90(b)]. Injection pressure may be defined either at the wellhead
(i.e., wellhead pressure) or downhole (i.e., bottomhole pressure). Bottomhole pressure is equal to
wellhead pressure plus the hydrostatic pressure that exists due to the weight of the fluid column
between the wellhead and bottomhole, minus frictional losses. Injection pressure is monitored to
ensure that the fracture pressure of the formation and the burst pressure of the well tubing are not
exceeded and that the owner or operator is in compliance with the permit. If these pressures are
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exceeded, the formation may fracture or the tubing may burst. An example of a plot of measured
injection pressure over time is provided in Figure 3-2, on page 39.
Application
With an accurate knowledge of fluid density, bottomhole pressure can generally be estimated
from wellhead pressure measurements. However, due to temperature effects, measuring
bottomhole pressure with a dedicated downhole pressure gauge may be a more reliable approach
than a device at the wellhead. EPA recommends that owners or operators consider placement of
bottomhole pressure gauges in such a way that protects the perforations and the packer; choice of
placement should be included in the Testing and Monitoring Plan, along with plans for
calibration or other instrument checks.
Pressure gauges are commonly used instruments that have been developed for a wide range of
applications. There are several types of pressure gauges (described below), which can be broadly
classified as mechanical or electronic devices. Mechanical gauges are generally considered less
accurate compared to electronic gauges, but can withstand more severe conditions. Electronic
gauges also require a power source. For additional information regarding pressure monitoring,
see Shepard and Thacker (1993), USEPA (1998), and ASTM (2009).
Amerada gauges are mechanical devices that consist of a helically wound Bourdon tube that
bends in response to the pressure differential between the inner and outer surfaces. As the tube
moves, it moves a stylus, which records the pressure on a chart. It is used mainly if the
temperature is expected to be greater than 175° C.
Strain gauges are electronic devices bonded to a pressure transducer. The transducer can consist
of wires wrapped around the inside of flexible tubing or a plate attached to a diaphragm. The
resistance of the transducer changes as it is stretched by the pressure. The transducer is
connected to a Wheatstone bridge, which can determine the resistance in the transducer. The
resistance is related back to pressure by means of a calibrated curve showing pressure versus
resistance. These gauges are rugged, have a long life span, and have a high pressure range.
Disadvantages may include a larger drift than other gauges and a higher sensitivity to
temperature changes.
Capacitance gauges are electronic gauges that consist of two plates set a very small distance
apart (0.001 to 0.002 inches) that act as the capacitor in a circuit. Deflections in one plate caused
by pressure change the capacitance of the circuit. A reference curve relates the changes in
capacitance to pressure. These gauges are among the more common types. They can exhibit
slower response times if the oil used to fill the device leaks. In addition, their use is limited to
environments where the temperature is less than 220° C.
Vibrating crystal transducers are electronic gauges consisting of a quartz crystal wired to an
electrical circuit. The crystal oscillates with a frequency that is pressure dependent. A second
crystal that is not exposed to pressure is often used to correct for temperature. These gauges are
highly accurate, but they are not as robust as other gauges and have a slow dynamic response. A
variation on the vibrating crystal transducer uses a sapphire crystal (instead of a quartz crystal),
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which is not as accurate as the quartz version but works at higher pressures (20,000 psi) and
temperatures (190° C).
Fiber optic transducers are a relatively new category of electronic gauges. They generally
measure the changes in either phase modulation or polarization rotation of light in the fiber optic
cable caused by pressure changes. Advantages include their immunity to electromagnetic
interference, small size, and good dynamic response. However, they are not as robust as other
types of gauges, are more sensitive to temperature changes, and perform poorly with static
pressure measurements.
Reporting and Evaluation
Measured pressure data must be submitted to EPA in the semi-annual reports [40 CFR
146.91(a)(2)]. Data will be submitted in electronic form directly to EPA, where they can then be
accessed both by the UIC Program Director and other EPA offices. The Class VI Rule requires
that certain information be included in these reports [40 CFR 146.91(a)], and it is recommended
that all of the information below be included:
Tabular data of all pressure measurements, a description of interpretation of the data
aided with charts or graphs, and gauge calibration records.
A description of the measuring methodology, noting differences from what is established
in the Testing and Monitoring Plan and an explanation of why a different methodology
was used.
Corrections made due to the impacts of fluctuating inj ectate temperature.
Monthly average value for injection pressure.
Monthly maximum and minimum values for injection pressure.
If pressure exceeded permit limits during the reporting period, an explanation of the
event(s), including the cause of the excursion, the length of the excursion, and response
to the excursion.
Identification and explanation of data gaps, if any.
Any identified necessary changes to the project Testing and Monitoring Plan to ensure
continued protection of USDWs, including any changes in the data measurement or
averaging methods.
The UIC Program Director will evaluate the data to determine compliance with permit
conditions. If the pressure exceeded the permit conditions, this is considered a permit violation,
and the UIC Program Director will take any necessary enforcement actions, evaluate the causes,
and determine if there is any endangerment to the well and/or any USDWs. He or she will also
determine if the permit needs to be modified or if changes are needed in any of the project plans
(e.g., the Emergency and Remedial Response Plan). The owner or operator is required to report
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any noncompliance with a permit condition that may cause fluid migration into or between
USDWs within 24 hours [40 CFR 146.9l(c)(2)].
3.4 Corrosion Monitoring
Corrosion, which is the loss of metal due to chemical or electrochemical reactions, may result in
loss of mass or thickness, cracking, or pitting of injection well components. General corrosion
refers to the uniform, or near uniform, thinning of metal. In some cases, a certain rate of general
corrosion may be acceptable, if a corrosion allowance has been included in the well materials'
design thickness. Localized corrosion consists of several forms of attack that lead to failure of
the equipment before the corrosion allowance is spent. Mechanical integrity loss may result from
the development of a leak, from mechanical failure caused by localized thinning, or from crack
propagation in the well components. Corrosion inhibitors or corrosion-resistant alloys are
additional options to provide protection from corrosion and are discussed in the UIC Program
Class VI Well Construction Guidance.
The Class VI Rule requires quarterly monitoring of well materials for corrosion [40 CFR
146.90(c)]. The objective of corrosion monitoring is early detection of deterioration of well
components (casing, tubing, or packer) that may cause loss of mechanical integrity. It is
recognized that carbonic acid corrosion of steel tubing and pipes is a concern in the oil industry
(e.g., Palacios and Shadley, 1991; Lopez et al., 2003). Carbon dioxide in the presence of water
will lead to the formation of carbonic acid; therefore, Class VI injection wells may be exposed to
a more corrosive bottomhole environment than wells that do not inject carbon dioxide.
The Class VI Rule requires that well components be monitored for corrosion using at least one of
the following methods: coupons, a flow loop, or an alternative method approved by the UIC
Program Director [40 CFR 146.90(c)]. These methods are described in the subsections below.
Additionally, the UIC Program Director may require the use of CILs on a periodic basis [40 CFR
146.89(d)] to monitor for corrosion. In addition to monitoring the injection well, EPA
recommends that owners or operators consider corrosion monitoring for any monitoring wells.
Monitoring wells remain idle, and their downhole environment may be prone to corrosion. In
particular, any monitoring wells perforated in the injection zone may be exposed to carbon
dioxide-bearing fluids, and are therefore particularly subject to potential corrosion.
3.4.1 Use of Corrosion Coupons
General Information
The most common of all corrosion rate measurement tests involves exposing pieces of metal,
similar to those in the injection system, to the conditions to which the well materials will be
exposed. Small, pre-weighed and measured coupons made of the construction materials are
exposed to well fluids for a defined period of time, then removed, cleaned, and weighed to
determine the corrosion rate (Allen and Roberts, 1978). Coupons are very simple to use and
analyze, and they give a direct measurement of material lost to corrosion. Coupons can predict
the following types of corrosion when correctly emplaced to ensure appropriate exposure:
general corrosion, crevice corrosion, pitting, stress corrosion cracking, embrittlement, galvanic
corrosion, and metallurgical structure-related corrosion (USEPA, 1987a). However, coupons
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have several limitations. An extended period of time is required to produce useful data, and
coupons can only be used to determine average corrosion rates. The inevitable differences in the
size and thermomechanical history of coupons compared with the actual well materials mean that
the corrosion rate measured on a coupon cannot exactly match the corrosion rate experienced by
the well (USEPA, 1987a); therefore, lack of serious corrosion in coupons does not conclusively
rule out corrosion of well materials.
Application
A coupon is a small, carefully manufactured piece of metal (such as a strip or ring) placed in an
appropriate location in the injection well to measure corrosion (Figure 3-3). The coupon is made
from the same material as the well's casing or tubing. It is weighed, subjected to the well
environment for a period of time, and then removed and weighed again. The average corrosion
rate in the well can be calculated from the weight loss of the coupon (Jaske et al., 1995).
Coupons are typically placed in the well using wireline equipment (USEPA, 1987a). Carriers
that hold one or more coupons have been developed in the oil and gas industry to monitor
corrosion in production wells (NACE, 2005). Coupons might also be deployed at the surface in a
valved loop through which the injection stream passes. In a Class VI well, coupons deployed
either downhole or in a loop near the wellhead will register the effects of the carbon dioxide on
the material on the inside of the tubing. Importantly, corrosion coupons can only measure
corrosion in the part of the well in which they are placed. For example, Smith and Pakalapati
(2004) described a production scenario where extensive corrosion caused joints to collapse
although coupons at the wellhead of the same well indicated minimal corrosion rates. In addition,
the coupon material needs to match the material of concern as closely as possible. When not in
use, coupons need to be stored in a non-corrosive environment. Specialized envelopes and other
containers are available for coupon storage.
NACE International (NACE) Recommended Practice RP-0775 (NACE, 2005) provides technical
information and best practices for coupon use in oil and gas applications, including more detailed
technical information on preparing, analyzing and installing corrosion coupons. ASTM
Standards Gl (ASTM, 2003) and G4 (ASTM, 2008) provide additional technical information on
preparing and evaluating corrosion coupons.
Figure 3-3. Example of corrosion coupons (image from Rohrback Cosasco Systems,
reprinted with permission).
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Interpretation
Corrosion rates are commonly reported in mils per year (mpy) of penetration or metal loss,
where a mil is equal to a thousandth of an inch. Target corrosion rates of one mpy
(approximately 25 jim/year) or less are common in wells used in the oil industry. A low
corrosion rate may not be acceptable if localized corrosion (such as pitting) is occurring, whereas
a higher rate with a general area type of metal loss may be, in certain cases, a relatively
insignificant problem (USEPA, 1987a). Inspection of the coupon's surface can yield information
about the nature of the corrosion that is taking place (e.g., localized or general attack, presence of
pitting or cracking).
The difference in the size and thermomechanical history of a coupon compared with actual items
of equipment may result in differences in the measured corrosion rates. Nevertheless, coupons
provide the simplest and most useful guide to corrosion monitoring, particularly localized
corrosion effects. When suitably fabricated and exposed, coupons predict general corrosion,
crevice corrosion, pitting, stress corrosion cracking, embrittlement, galvanic corrosion, and
metallurgical structure-related corrosion.
3.4.2 Use of Corrosion Loops
General Information
Another method of assessing corrosion is the use of a corrosion loop. A corrosion loop is a
section of tubing that is valved so that some of the injection stream is passed through a small
pipe running parallel to the injection pipe at the surface of the well. Because the composition of
this pipe is the same as the well tubing, it acts as a small-scale version of the well; the only
differences are that the loop pipe has a smaller diameter and its temperature (due to its shallower
depth) is generally lower (USEPA, 1987a). Pressure differences between the injection point and
the wellhead are also important to note. Although not as commonly used in the field as coupons,
use of flow loops is a viable corrosion monitoring option.
Application
In a field setting, the loop would consist of a section of tubing that is valved so that some of the
injection stream is passed through a small pipe running parallel to the injection pipe at the
surface of the well. The pipe can then be analyzed for corrosion. When the valves are open, some
of the injection stream passes through the loop. When the valves are closed, the corrosion loop
can be removed from the system and analyzed for corrosion. Corrosion rates can be calculated in
a similar fashion to the corrosion coupon method.
Interpretation
If corrosion is observed in the loop, corrosion is likely occurring in the well tubing. Because the
dimensions and temperature of the loop are different than that of the well, conditions in the loop
do not exactly match the conditions in the well, and the loop may be subject to more or less
corrosion than the well itself. For example, temperature usually increases with depth, and
therefore the temperature in the loop is generally less than the temperature of the well. Because
corrosion rates increase with temperature, this may lead to an artificially low estimate of
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corrosion. EPA recommends that, where practical, consideration be given to controlling the
temperature of the corrosion loops to simulate well conditions, thereby allowing for the
collection of more representative corrosion rate information. In addition, loops cannot measure
the corrosion experienced by specific features of the well (such as joints) that may have
corrosion-enhancing properties (USEPA, 1987a).
3.4.3 Casing Inspection Logs
General Information
If required by the UIC Program Director, the owner or operator of a Class VI well must run a
CIL at a frequency specified in the Testing and Monitoring Plan [40 CFR 146.89(d)]. The
purpose of the CIL is to determine the presence or absence of corrosion in the long-string casing.
CILs measure casing thickness or borehole radius. One of several available logs may be used for
a CIL, including physical measurement with a caliper, electromagnetic phase shift in the
magnetic field passing through the tubing or casing, electromagnetic flux leakage due to
variations in the tubing or casing, and ultrasonic images of reflected sound waves. Each of the
methods provides data that, along with the physical characteristics of the well, will yield the
thickness of the casing and the locations of anomalies, such as corrosion pits, scratches, and
splits. The choice of appropriate test is based on operator preferences and subject to approval by
the UIC Program Director.
Application
All CIL tools are wireline based and identify and measure variances, referred to as defects, in the
thickness of the casing wall. Examples of defects are pits or ruts (formed by corrosion,
substandard welds at casing couplings, wear from centralizers or collar locators, etc.) and splits
that open gaps in the casing.
Caliper logs measure the internal radius of the casing in several directions (see the UIC
Program Class VI Well Construction Guidance). A loss of thickness of the casing is evident
from a caliper log because the internal radius increases in the area of corrosion. Baseline caliper
surveys may be used for comparison. An example of a caliper log showing significant casing
corrosion is provided in Figure 3-4.
An electromagnetic thickness survey measures large defects on the order of one inch (USEPA,
1982; Nielsen and Aller, 1984). The tool has an emitter coil (low frequency) used to create a
magnetic field that passes through the tubing or casing and a receiver coil that measures the shift
in the returning magnetic field. The receiver coil is set at a distance where it intercepts magnetic
field lines that pass outside the coil. The phase shift is proportional to the thickness of the metal
and the casing's magnetic permeability. Properties of the casing affect the log, so properties such
as the material and density of the casing need to be known before the baseline log is run. The
results are relative and need to be compared to a baseline log. If a CIL is run when the well is
first installed to satisfy the requirements at 40 CFR 146.87(a)(4), it can serve as a baseline to
which measured casing thickness can be compared..
One commercially available electromagnetic scanner offers the advantage of not requiring the
tubing to be pulled if the inner diameter is sufficiently large to accommodate the instrument.
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Qualitative results can be obtained for tubing and casing together. If metal loss is indicated, the
tubing would then be removed to determine if the loss is in the casing or tubing.
The pipe analysis survey is a form of magnetic flux-leakage test that measures disturbances in
an artificially created magnetic field (USEPA, 1982). The logging tool consists of an
electromagnet, two arrays of pads, two cartridges of electronics, and centralizers (Nielsen and
Aller, 1984). Each pad contains upper and lower electric coils used to measure flux leakage and
eddy currents, and an eddy coil to produce eddy currents along the inner wall. The coils collect
data in the form of induced currents that are converted to casing variations on the log. The pads
are set around the tool to give circumferential coverage for the survey.
The ultrasonic imaging survey uses a very high transducer frequency to measure anomalies in
the tubing or casing (Schlumberger, 2009). The emitter/detector is on the end of the wireline
tool, with centralizers located above. The emitter sends out sound waves and the detector
measures the reflected response. The survey can measure anomalies as small as 0.3 inches and
measures anomalies both on the inner and outer surfaces of the tubing or casing. The tool rotates,
but the electronics keep track of a reference point, and it can therefore produce an accurate
circumferential image of the tubing or casing. The data are analyzed and yield the thickness and
inner and outer surface conditions. The survey response is attenuated by the fluid in the well bore
and the best results are produced with oils, brines, and light muds.
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!
Internal Radii
I
%,
.
:
}
Region of severe
casing corrosion
Figure 3-4. Example CIL (caliper log) showing significant corrosion (Brondel et al., 1994). Graphic copyright
Schlumberger. Used with permission.
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Interpretation
The data from each of the CILs are displayed as vertical logs (e.g., Figure 3-4). Defects in the
long-string casing will be displayed as anomalies on the log that cannot be attributed to casing
joints or other construction features. Loss of thickness may be determined from comparison to
baseline logs. For any of these tests, time series logs can be used to gauge the growth of defects
and predict eventual loss of mechanical integrity.
The caliper log is generally reported as internal radius, nominal wall penetration, or average
remaining thickness, depending on the logging company. Some logs can even show the variation
detected by each arm as side by side traces similar to a seismograph (see Figure 3-4). The
ultrasonic imaging survey produces images of the surfaces and a log of the thickness.
Knowledge of the casing properties is needed to properly interpret CILs. The information used in
interpreting the log consist of dimensions, weights and alloys, locations of couplings, locations
of wall scratches or other abrasions, locations of perforations, and locations of centralizers.
Couplings will show an increase in thickness and are usually spaced at regular, but always
known, intervals (e.g., Figure 3-4). Perforations will show as defects but typically yield a regular
output. Variation within the perforated sections can show corrosion in the perforations.
3.4.4 Reporting and Evaluation of Corrosion Monitoring Data
Owners or operators are required to submit the results of corrosion monitoring in the semi-annual
reports [40 CFR 146.91(a)(7)]. Data will be submitted in electronic form directly to EPA, where
they can then be accessed both by the UIC Program Director and other EPA offices. Certain
information must be included in these reports [40 CFR 146.91(a)], and EPA recommends that all
of the following information be included:
A description of the techniques used for corrosion monitoring.
Measurement of mass and thickness loss from any corrosion coupons or loops used.
Assessment of additional corrosion, including pitting, in any corrosion coupons or loops.
Measurement of thickness loss or corrosion detected in any CILs.
All measured CILs and comparison to previous logs.
Identification and explanation of data gaps, if any.
Any identified necessary changes to the proj ect Testing and Monitoring Plan to ensure
continued protection of USDWs.
The UIC Program Director will independently assess the results of corrosion monitoring to
assess the integrity of the injection well.
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3.5 Pressure Fall-Off Testing
General Information
The Class VI Rule requires pressure fall-off testing of the injection well at least once every five
years, or more frequently if required by the UIC Program Director [40 CFR 146.90(f)]. Pressure
fall-off tests are used to measure formation properties in the vicinity of the injection well (e.g.,
transmissivity). The objective of periodic testing is to monitor for any changes in the near-well
bore environment that may impact injectivity and pressure increase. Anomalous pressure drops
during the test may be indicative of fluid leakage through the well bore. However, during a
transient pressure test for a GS project, the presence of multiple fluid phases, gravity driven flow,
and dissolution of carbon dioxide in brine are likely to be important factors and should be
considered (Benson and Doughty, 2006). For instance, phase changes and multiphase flow
effects in a region near the front can cause a sharp pressure drop in that location. For additional
information regarding pressure fall-off tests, see the USEPA Region 6 UIC Pressure Falloff
Testing Guideline (USEPA, 2002a) or the course outline and notes from EPA's Nuts and Bolts
of Falloff Testing seminar (USEPA, 2003). Information is also available in publications such as
Schlumberger (2006), Kamal (2009), or Lee et al. (2003). Some portions of this section have
been adopted from USEPA (2002a).
Application
Pressure fall-off tests are conducted by ceasing injection for a period of time (i.e., shutting-in the
well) and monitoring pressure decay at the well. The results of the pressure fall-off test depend in
part on the injection conditions prior to shutting-in the well. Therefore, prior to the test, it is
recommended that injection rate and pressure be kept as constant as practicable and continuously
recorded (Sections 3.2 and 3.3).
Upon shutting-in the well, pressure measurements are taken continuously. Temperature
measurements taken during the test may assist in data interpretation. Bottomhole reservoir
pressure measurements may be less subject to data scatter, and, because of the compressible
nature of supercritical and liquid carbon dioxide, bottomhole gauges should be the least affected
by well bore effects. Wellhead (surface) pressure measurements may be sufficient if a positive
pressure is maintained at the surface throughout the test. The use of two pressure gauges is
recommended, with one serving as a backup or for verification in cases of questionable data
quality. It is recommended that the duration of the shut-in period be long enough to observe a
straight line of pressure decay on a semi-log plot (i.e., radial flow is achieved). A general rule of
thumb is to run the test for three to five times the time required to reach radial flow conditions.
For projects with multiple injection wells within the same zone, special considerations may be
made for pressure fall-off testing, as injection at one well will influence the pressure fall-off
curve at other wells. For the offset wells (i.e., those not being tested), injection should cease prior
to the test for a period of time exceeding the planned shut-in period, or injection rates may be
held constant and continuously recorded during the test. Following the fall-off test, owners or
operators are encouraged to send at least two pulses to the test well by way of rate changes in the
offset well. These pulses will demonstrate communication between the wells and, if maintained
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for sufficient duration, they can be analyzed as an interference test to obtain inter-well reservoir
parameters. For basic information on pulse tests, see Johnson et al. (1966) or Kamal (1983).
Interpretation
Pressure fall-off tests measure the change in pressure over time at the test well, and results are
plotted as a function of time. Interpretation of pressure data for a GS project may be complex due
to the presence of multiphase fluid flow. Benson and Doughty (2006) indicated that the effects of
heterogeneity and gravity may cause high residual liquid saturation estimations in evaluating
pressure transient test results in a carbon dioxide-brine system.
Typically, several graphs are used in interpretation of test results. Observed bottomhole pressure
and recorded temperature may be plotted as a function of time for the time period prior to the
shut-in and the duration of the test. This plot is used to confirm pressure stabilization prior to the
test. Any pressure changes may be evaluated relative to the sensitivity of the pressure gauges
used to confirm adequate gauge resolution. Any data collected after reaching resolution of the
gauge are suspect. Pressure gauges typically auto-correct for temperature fluctuations. However,
if temperature anomalies are not accounted for correctly, this may lead to erroneous results. Any
temperature anomalies observed during the test may be noted to determine if they correspond to
pressure anomalies. Computational models that account for the presence of multi-phase fluids
may be used to aid in interpretation of pressure fall-off tests if there are large temperature
fluctuations.
Log-log and semi-log diagnostic plots of observed pressure and time are used for further data
interpretation. Unique flow regimes can be identified on these plots, corresponding to the
region(s) governing pressure fall off during a certain phase of the test. Early data correspond to
flow within the well bore and the immediate surrounding area, and later data correlate to
distances further from the well. Later-time data, representative of reservoir conditions, are used
for quantitative data analysis. Observations of anomalous pressure decay at greater rates than
previous tests may indicate a number of scenarios such as changes in relative permeability, the
effects of well stimulation procedures, or leakage of fluid. See USEPA (2002a) for further
information on interpretation of the diagnostic plots as they relate to detection of reservoir
geologic features and leakage pathways.
Quantitative analysis of the measured data is used to estimate formation characteristics,
including transmissivity, and the well skin factor. Analytical or numerical fluid flow models are
fit to the measured data to estimate these parameters; commercial software programs are often
used. The well skin factor accounts for changes in the permeability of the formation at or near
the well bore as a result of drilling, completion, and injection practices (e.g., van Everdingen,
1953). Changes in permeability are also expected due to the presence of a multi-phase system
and possibly due to mineral precipitation near the well bore. Owners or operators should be
aware that interpretation of fall-off tests in carbon dioxide injection projects will be complicated
by two-phase flow effects and should consider this when analyzing and reporting the data. EPA
encourages the owner or operator to provide a description of any methods that may be used to
account for multi-phase effects. Parameters determined in pressure fall-off tests may be
compared to those used in site computational modeling and AoR delineation. Changes in
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formation permeability values as measured during pressure fall-off tests may also be required by
the UIC Program Director to be reflected in AoR reevaluation.
Reporting and Evaluation
The Class VI Rule requires that the results of pressure fall-off tests be submitted to EPA
electronically within 30 days of the test [40 CFR 146.91(e) and 146.91(b)(3)]. EPA recommends
that submittals include:
The location and name of the test well and the date/time of the shut-in period.
Depths of bottomhole pressure and temperature.
Records of gauges (if they are lowered and raised).
Raw data collected during the fall-off test in a tabular format, if required by the UIC
Program Director.
Measured injection rates and pressure from the test well and any off-set wells in the same
zone, including data from before shut-in.
Information on pressure gauges used (e.g., manufacturer, accuracy, depth deployed) and
demonstration of gauge calibration according to manufacturer specifications.
Diagnostic curves of test results, noting any flow regimes.
Description of quantitative analysis of pressure-test results, including use of any
commercial software, and any considerations of multi-phase effects.
Calculated parameter values from analysis, including transmissivity, permeability, and
skin factor.
Analysis and comparison of calculated parameter values to previously measured values
(using any previous methods) and to values used in computational modeling and AoR
delineation.
Identification of data gaps, if any.
Any identified necessary changes to the proj ect Testing and Monitoring Plan to ensure
continued protection of USDWs.
The UIC Program Director will evaluate the pressure fall-off test results to assess any changes in
characteristics of the near-well bore environment and any indication of fluid leakage during the
test.
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4 Ground Water Quality and Geochemical Monitoring
The Class VI Rule requires periodic monitoring of ground water quality and geochemical
changes above the confining zone(s) that may be a result of carbon dioxide or injection
formation fluid movement through the confining zone(s) or additional identified zones [40 CFR
146.90(d)]. The primary purpose of this monitoring is to identify potential injectate migration
and/or native fluid displacement from the injection zone by detecting potential geochemical
changes due to the introduction of the injectate or displaced formation fluids above the primary
confining zone(s). EPA recommends that the geochemical monitoring be conducted in the first
formation overlying the confining zone that has a sufficient permeability to support collection
and analysis of ground water samples. However, the decision regarding which formation(s) to
monitor will be based on site-specific conditions and will be determined in consultation with the
UIC Program Director. The UIC Program Director may determine that monitoring ground water
quality (or pressure) within additional zones, including USDWs, may be critical for a specific GS
project. For GS projects operating under an injection depth waiver, the requirements for ground
water quality and geochemical monitoring will necessitate measuring pressure and sampling
fluids in at least one additional formation (the first USDW below the injection zone) and
possibly other formations if specified by the UIC Program Director [40 CFR 146.95]. More
detailed information is available for such projects in the UIC Program Class VI Well Injection
Depth Waivers Guidance.
The spatial locations, depth, and number of monitoring wells required for the direct monitoring
of ground water quality and geochemical changes in the identified zone(s) will also be site-
specific and based on site characterization and operational information, including factors such as
proposed injection rate and volume, geology, and the presence of artificial penetrations [40 CFR
146.90(d)(l)]. While determining the spatial distribution and depth of monitoring wells and the
frequency of sampling, the owner or operator should also consider baseline geochemical data
collected during site characterization under 40 CFR 146.82(a)(6), as described in the UIC
Program Class VI Well Site Characterization Guidance [40 CFR 146.90(d)(2)]; the quality and
time frame of these baseline data will be important when interpreting the geochemical
monitoring results. Additionally, monitoring decisions will be based on AoR modeling results
required under 40 CFR 146.84(c). If reactive transport modeling has been conducted, modeling
results may also support the selection of parameters to be monitored.
EPA recommends that the Testing and Monitoring Plan include a detailed description of the
number and placement of monitoring wells and the site-specific factors that have been
considered, as well as a technical justification of the decision of which formations to monitor.
Similarly, a discussion of the parameters to be monitored and the frequency at which sampling
and analysis will be performed should be included in the plan. It is also important that the owner
or operator describe method sensitivities and how the monitoring strategy will detect deviations
in project performance and/or any endangerment to a USDW. If phased or triggered monitoring
is proposed, all factors considered for the development of the strategy should be included in the
plan (see Section 1.2.1).
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This section discusses how owners or operators may design and construct a monitoring well
network, collect and analyze ground water samples from above the primary confining zone, and
interpret and submit the results of ground water analyses.
In addition to the above-confining zone water quality monitoring requirements [40 CFR
146.90(d)], the Class VI Rule also requires direct monitoring of the pressure front in the injection
zone [40 CFR 146.90(g)]. Additionally, there may, in limited circumstances, be a need to
monitor the separate-phase plume geochemically via direct sampling in the injection zone. This
would occur if the UIC Program Director determines that indirect methods for tracking the
plume (e.g., geophysical methods; see Section 5) required at 40 CFR 146.90(g) are not feasible
at a particular project site and requires the use of direct monitoring for plume tracking. Because
of this, some of the recommendations described in this section relate to developing an overall
strategy for geochemical monitoring and a network of monitoring wells, both above the
confining zone(s) and within the injection zone.
4.1 Design of the Monitoring Well Network
The monitoring well network refers to wells that are used to support compliance with the testing
and monitoring requirements under the Class VI Rule. The design of the monitoring well
network is a key component of a monitoring system that serves to detect any leakage through the
confining zone that may endanger USDWs and support any direct monitoring required in the
injection zone. Therefore, the owner or operator must consider all relevant site data, including
injection rate and volume, geology, the presence of artificial penetrations, and other factors, as
required at 40 CFR 146.90(d)(l) and (2), in planning monitoring well placement (i.e., both the
depth of the wells and their geographic location with respect to the injection well(s) and
anticipated injectate plume and pressure front movement). The proposed monitoring well
placement and perforation strategies, along with a description of a monitoring well maintenance
program, are to be described and technically justified in detail in the Testing and Monitoring
Plan, based on site characteristics and computational modeling performed for AoR delineation,
subject to UIC Program Director approval. This information should demonstrate that the
proposed system can help verify that the injectate is safely confined in the target formation and
be used to detect deviations from the predicted project performance.
The general sequence of site characterization, modeling, and monitoring at a GS project is shown
in Figure 4-1. The model, based on site characterization and proposed operating data, is used to
delineate the AoR. The reader is referred to the UIC Program Class VI Well Area of Review
Evaluation and Corrective Action Guidance for discussion of generating model results and
delineation of the AoR. The AoR is then used in order to design the monitoring system. As more
data are obtained from the site, the model is revised to reflect the additional data. If revision of
the model results in a substantially different AoR, then the monitoring system may need to be
redesigned and the Testing and Monitoring Plan updated.
This section provides guidelines for the design of the monitoring well network for ground water
monitoring above the confining zone(s) and any other direct monitoring in the injection zone
required under the Class VI Rule.
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Site Characterization
Proposed Operating
Data
Computational Modeling/
AoR Delineation
Model Calibration
Monitoring System
Design
Monitoring Data
Collection and Interpretation
Figure 4-1. Flow chart of modeling and monitoring at a Class VI project.
4.1.1 Perforated Interval of Monitoring Wells
The perforated interval of a monitoring well refers to the depth at which openings or slots are
present in the casing, allowing for native ground water at that interval to flow into the casing for
sample collection. The monitoring well is designed to sample ground water only in the
perforated interval (the hydrostratigraphic section of interest).
As discussed above, the Class VI Rule requires geochemical monitoring above the primary
confining zone [40 CFR 146.90(d)]. However, the owner or operator, or the UIC Program
Director, may determine that monitoring ground water quality (or pressure) within additional
zones, including USDWs, is necessary to protect USDWs. For example, monitoring the ground
water geochemistry of the lowermost USDW may be required by the UIC Program Director to
detect potential fluid leakage into the USDW. Based on site-specific criteria, the UIC Program
Director may also determine that geochemical monitoring within the injection zone is necessary
for tracking of the carbon dioxide plume (see Section 5) if indirect methods are not appropriate
for the given site. Therefore, at a minimum, the owner or operator is required to construct
monitoring wells perforated above the confining zone in a suitable formation for collection of
ground water samples [40 CFR 146.90(d)].
EPA recommends that monitoring wells above the confining zone be perforated in the first
reasonably permeable formation above the confining zone (i.e., the first formation from which
fluids can be extracted at appreciable volumes for sampling and analysis) unless the UIC
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Program Director approves perforation in a shallower zone. Placing wells as close to the
confining zone as possible will allow for earlier detection of leakage through the confining zone.
For GS projects operating under an injection depth waiver, monitoring will be needed both above
and below the injection formation [40 CFR 146.95(f)(3)(i)]. Therefore, owners or operators may
wish to install monitoring wells with multi-level samplers. See the UIC Program Class VI Well
Injection Depth Waivers Guidance for more information.
4.1.2 Monitoring Well Placement
EPA recommends that monitoring wells be placed strategically to maximize the ability of the
monitoring well network to detect potential leakage and track the migration of the plume (if
required) and pressure front while minimizing the number of wells, which can serve as conduits
for fluid movement. The Class VI Rule requires that the placement of monitoring wells used for
geochemical monitoring above the confining zone be based on available site characterization
data and AoR delineation modeling [40 CFR 146.90(d)(2)].EPA is providing the following
recommended guidelines for determining the number and placement of monitoring wells above
the confining zone(s) at a Class VI project based on available site characterization data and the
results of computational modeling. The objective of these recommended guidelines is to inform
the development of a monitoring network with a sufficient yet minimal number of monitoring
wells that are strategically located to provide site monitoring that meets the requirements at 40
CFR 146.90(d)(l) and (2). These recommended guidelines are intended to provide a reference
for owners or operators during the design of the monitoring well network, and for UIC Program
Directors in evaluating the proposed Testing and Monitoring Plan. The guidelines are as follows:
As depicted in Figure 4-1, the monitoring well network design will ideally build upon site
characterization and computational modeling information, which will then be used to
instruct placement of monitoring wells that will enable collection of baseline site data.
The number of required monitoring wells may be greater for projects with larger
predicted areas of elevated pressure and/or plume movement, or in cases of more
complex or heterogeneous injection/confining zone hydrogeology. If the predicted area of
impact of a given project increases in size as indicated during an AoR reevaluation,
additional monitoring wells may be necessary.
For projects with a separate-phase plume and/or pressure front predicted to move in a
specific direction (e.g., due to formation dip), wells should be primarily placed in the
predicted down-gradient direction. However, at least one up-gradient well is
recommended.
Well placement should be based on the predicted rate of migration of the separate-phase
plume and/or pressure front.
Wells sited above the confining zone(s) should be preferentially placed in regions of
concern for potential risk of fluid leakage and USDW endangerment. These regions may
include identified faults, fractures, or abandoned well bores (see the Cranfield and In
Salah case studies in the Appendix) that may represent a potential pathway for fluid
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leakage into a USDW and are predicted to overlie the maximum thickness and saturation
of the separate-phase plume and/or elevated pressures. Such regions may be located in
the vicinity of the injection well(s), as this will be the region of greatest pressure increase
and greatest risk of fluid leakage.
For projects with multiple Class VI injection wells, EPA recommends that the monitoring
well system design address all injection wells together in a unified plan, even though the
injection wells are permitted separately.
The number of monitoring wells placed above the confining zone should be determined
such that any leakage through the confining zone that may endanger a USDW will be
detected in sufficient time to implement remedial measures. The number of monitoring
wells above the confining zone may be determined based on a modeling and/or statistical
analysis, which may be documented in the Testing and Monitoring Plan. Considerations
that may be included in this analysis are the regional hydraulic gradient, flow paths,
transmissivity, and baseline geochemistry.
If approved by the UIC Program Director, previously existing wells perforated in the
appropriate zone may be converted to use as monitoring wells for the GS project. These
wells should be constructed to appropriate specifications, as discussed in Section 4.2.
Revision of the site computational model and delineated AoR associated with AoR
reevaluation may trigger a revision of the Testing and Monitoring Plan [40 CFR
146.90(j)]. Design of the monitoring well network, including steps taken to determine the
placement of monitoring wells, should be reviewed during revision of the Testing and
Monitoring Plan. If revision of the site computational model has resulted in changes to
the size and shape of the AoR, monitoring well placement may require revision. See the
UIC Program Class VI Well Area of Review Evaluation and Corrective Action Guidance
for discussion of AoR reevaluation; also see the UIC Program Class VI Well Project
Plan Development Guidance for additional information on updating the Testing and
Monitoring Plan.
4.1.3 Use of Phased Monitoring Well Installation
If approved by the UIC Program Director, monitoring wells may be installed on a phased basis
during the lifetime of the project. Allowing for phased monitoring well installation will allow for
monitoring well placement design to be changed based on monitoring results, new information
about the project, and revision of the site computational model. It may also allow the use of
newer and more protective monitoring well construction or materials. If phased monitoring well
installation is allowed by the UIC Program Director, the phasing plan should be described and
technically justified (e.g., the timing of monitoring well construction for each well) in detail in
the Testing and Monitoring Plan. EPA recommends that planned monitoring wells that meet
either of the following conditions be constructed prior to the commencement of injection:
The wells are predicted to come into contact with the carbon dioxide plume (when direct
monitoring for plume tracking is required) and/or with significantly elevated pressure
within five years of commencement of injection operations.
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The wells are located in regions above the confining zone(s) overlying the portions of the
injection zone where the separate-phase plume and/or pressure front is predicted to move
within five years of commencement of injection operations.
The recommendation of five years is based upon the minimum required frequency for AoR
reevaluations. However, another time frame, based on site-specific considerations, may be
proposed and technically justified in the Testing and Monitoring Plan. EPA recommends that
decisions regarding phased monitoring well installation and this duration be made in consultation
with the UIC Program Director.
4.2 Monitoring Well Construction
The construction of monitoring wells is similar to the construction of injection or production
wells in that all necessitate maintaining zonal isolation, employing good cementing practices,
and selecting suitable well materials for the conditions with which they will come into contact.
As with all wells, improperly constructed monitoring wells can serve as conduits for fluid
movement, potentially endangering USDWs. This guidance document may be used to inform
monitoring well construction if and where needed but does not address topics common to all
types of well construction, instead focusing on topics that may be of particular interest or
concern for constructing monitoring wells for GS. There are many documents and resources that
provide more detailed descriptions of and recommendations for well construction, including the
Class VI Rule injection well construction requirements at 40 CFR 146.86 and the UIC Program
Class VI Well Construction Guidance, which discusses aspects of construction for Class VI
injection wells. Other well construction resources include, but are not limited to,
recommendations and guidelines published by the American Petroleum Institute (API) and
ASTM. Furthermore, the UIC Program Class VI Well Injection Depth Waivers Guidance
includes information on construction of wells in areas where the injection zone is located above
the lowermost USDW. Topics that may be of particular concern for construction of monitoring
wells at GS projects include materials, drilling techniques, well completion, zonal isolation, and
recompletion of existing wells for use as monitoring wells. These are described below.
Materials
As with injection wells, monitoring well materials should be selected to withstand downhole
conditions, including the fluids with which the materials may be expected to come into contact.
Some factors that may be important to consider for the selection of monitoring well materials in
GS projects include elevated pressures, temperatures, and stress from the rock column,
depending on the depth of the wells. Wells for monitoring in the injection zone (if required by
the UIC Program Director) may also encounter separate-phase carbon dioxide and carbon
dioxide-rich fluids. These conditions can accelerate the degradation of well materials, including
metals, cements, and plastics. Any monitoring equipment installed in the monitoring well will
also need to be compatible with subsurface fluids with which they will come into contact. The
UIC Program Class VI Well Construction Guidance contains specific information and references
to other resources about materials that are compatible with carbon dioxide streams as well as
native brines. It also discusses designing materials for the stresses likely to be encountered in the
downhole environment. Wells completed in the injection zone will eventually be exposed to the
pressure front as the plume enters the vicinity of the well. Although the pressure will be
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somewhat lower than the injection pressure, the well should be designed for pressures greater
than the initial reservoir pressure.
Monitoring wells completed above the injection zone will likely face lower pressures than
injection wells or monitoring wells in the injection zone, but they may still be exposed to similar
conditions, e.g. contact with corrosive brines. Wells completed below the injection zone in the
case of an injection depth waiver will likely be subjected to even higher temperatures and
pressures than in the injection zone.
Well Drilling
Wells should be drilled in a manner that prevents movement of fluids between formations. In
addition to allowing fluid movement, improper drilling can weaken or damage formations in the
immediate vicinity of the well bore and lead to poor cement bonding, which can compromise the
well after construction. Under- and over-pressurized zones present particular challenges in
drilling and completing the well. An under-pressurized zone might be encountered when drilling
through a depleted reservoir. Elevated pressure in an over-pressurized zone may be encountered
if drilling is conducted to place a new monitoring well in the injection formation. For example, if
an AoR reevaluation indicates that the plume has moved into an unanticipated area, it might be
desirable to place a new monitoring well within the pressure front to better track the plume. In
drilling such a well, care would be needed to prevent migration of fluids and/or carbon dioxide
out of the injection zone.
The choice of appropriate drilling fluid (mud) is important for maintaining zonal isolation and
for constructing a good well bore. It is important that the mud be appropriate for the subsurface
conditions and allow fluid pressures to be properly maintained with respect to the formation.
Depleted reservoirs may have formations or zones with poor integrity; an inappropriate mud may
further degrade the rock, plug the pore space, and/or widen the well bore. High-pressure zones,
on the other hand, necessitate the use of high-density mud to help maintain well control (i.e.,
control of high downhole pressure during drilling; Wray et al., 2009). Muds come in several
classes or types, including water-based and oil-based fluids, those with and without solids, and
high performance muds, which can include synthetics. It is possible to test the compatibility of
the mud with the rock in the lab using core samples, although field experience is often also used
(Brufatto et al., 2003).
During drilling, the pressure or weight of the mud needs to be correctly controlled. If the
pressure/weight is too high, the mud will infiltrate the formation. It may potentially fracture the
formation and can be difficult to remove, causing pore spaces to clog. If the pressure/weight is
too low, native fluids from higher pressure zones can flow into the well bore, potentially causing
the driller to lose control of the well. Infiltration of fluids from the formation into the well bore
can cause delays in drilling and, with infiltration during well cementing, a poor cement job (poor
bonding and/or development of channels in the cement) can result. If a well is being drilled
through an injection zone, loss of control could result in movement of carbon dioxide out of the
injection zone. The total pressure exerted against the formation is determined by a combination
of mud density, height of the mud column, mud flow rate, friction losses, and pressure at the
wellhead (Medley and Reynolds, 2006). Mud density is the easiest and most common way to
alter mud weight and can be changed by altering the type of mud and through additives. Changes
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in drilling procedures or in drilling equipment may allow for controlling flow rate, pressure, and
friction losses as well.
After drilling, the mud should be properly removed to clean and prepare the well bore so that a
good bond and seal can be achieved between the cement and the casing and between the cement
and the formation. The decision to not remove the mud may give rise to concerns regarding the
quality of cementing achieved. If there is mud on the casing or formation, channels or
microannuli could form in the cement and/or along the cement/casing contact or the
cement/formation contact. These microannuli or channels could result in formation fluid or
injectate movement outside the casing in the well bore. The UIC Program Director should be
consulted for any decision regarding not removing the mud. The optimal strategy for mud
removal depends upon borehole characteristics and the rheology of the drilling fluid (Brufatto et
al., 2003). Options include displacing the mud using another fluid called a spacer, using metal
attachments called scratchers attached to the casing and either rotating or reciprocating the
casing, or using special chemicals such as acid washes (Shryock and Smith, 1981).
Well Completions
Well completion involves installing well tubular materials and other equipment to prepare the
well for operation. Some equipment may be "dedicated" (permanently deployed), such as
temperature gauges, pressure sensors, or geochemical sampling devices. Other monitoring
equipment, such as crosswell sonar devices, mechanical integrity testing instruments, and
logging equipment may be deployed periodically and will need adequate access to allow
lowering into the well. The well diameter, any deviations of the well from vertical, and any
significant curvature or bends in the well should be taken into consideration in combination with
the size (e.g., diameter) and access needs of any monitoring equipment to be used. Other factors
to consider in designing the monitoring well and planning for completion include the number and
locations of perforated zones.
Most permanent downhole equipment requires cables or tubing that allow the transmission of
collected data or samples to the surface. These can, however, interfere with other monitoring
equipment lowered into the well. The cables and sample tubing can be coated and placed in
metal or other hard conduits to protect against damage during installation. Another way to
protect cables and sample tubing is to run them along the exterior of the tubing and hold them in
place using clamps to prevent them from interfering with other equipment. In some rare cases,
devices have been run along the outside of the casing and cemented in place. In this case, the
sensors will need to be rugged and reliable because there is no way to replace them once they are
installed. The typical lifespan of such devices, their anticipated durability under the conditions to
which they will be exposed, and any potentially increased risk to well integrity should be
considered when permanently deploying equipment, particularly along the exterior of the casing.
Dual sensors (i.e., two sensors performing the same function, a primary and a backup) are also
often used for this reason. EPA recommends that the use of external gauges be determined in
consultation with the UIC Program Director, considering whether external gauges are a viable
option for the given project and whether they pose an undue risk compared to downhole
equipment. In some cases, aggressive downhole environments can interfere with sensor
functioning. For example, fiber optic sensors have been known to drift in high temperature and
pressure environments. Carbon- or metal-based coatings can sometimes prevent these problems
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(Omotosho, 2004). Coatings can also protect cables from aggressive chemical environments as
well as elevated temperature and pressure.
Because there is cement between the casing and the well bore to prevent fluid migration along
the well bore, both the casing and cement will need to be perforated in areas where direct
monitoring will occur so that the monitoring equipment can access the formation fluids to be
sampled. Perforations are not required where equipment is installed on the exterior of the casing.
However, geochemical sampling will always require perforations. The perforated intervals
should be designed to monitor the appropriate zones and to be wholly located within the desired
zones. Perforated zones should not cross injection zone/confining zone boundaries or confining
layers, and the depths of perforated layers should be verified using logs to ensure they have been
emplaced properly.
Zonal Isolation
In some cases, it may be desirable to monitor in multiple zones (e.g., the injection zone, the first
permeable zone above the injection zone, and underlying formations if the project operates under
an injection depth waiver). Using multiple completions in one well can minimize the number of
penetrations through the confining layer. In this case, care is necessary to ensure proper zonal
isolation during the entire life of the well.
Monitoring wells perforated in multiple zones should be equipped with packers to isolate the
zones. The packers should be placed above and below each perforated zone to prevent flow of
fluids between formations. The lowermost perforated zone, however, only needs a packer above
the perforations. If there are abandoned perforations below the lowermost perforations in use, a
bridge plug and cement plug should be set between the two sets of perforations to isolate the
abandoned perforations. Packers should be made of materials capable of withstanding any
corrosive effects from fluids with which they may come into contact, such as brine, wet carbon
dioxide, supercritical carbon dioxide, or brine saturated with carbon dioxide. Packers will also
need to be constructed to allow cables and tubing to pass through, and they should be pressure
tested at the anticipated downhole pressures to ensure that they are sealed and will not allow
fluid to pass through them.
One option to help preserve zonal isolation is to install equipment on the exterior of the casing
and cement it in place. Running the required cables and tubes down the outside of the casing
provides fewer openings in the packer and, therefore, fewer opportunities for leakage. However,
the typical lifespan of such devices, their anticipated durability under the conditions they will
experience, and any potentially increased risk to well integrity should be considered when
permanently deploying equipment, particularly along the exterior of the casing. External
deployment of fiber optic distributed temperature sensors and electric tomography equipment
was done in a monitoring well in the CC^SINK test project at Ketzin, Germany (Giese et al.,
2009).
Recompletion of Existing Wells as Monitoring Wells
The cost of drilling new wells can make the use of existing wells as monitoring wells an
attractive option. GS projects may involve the use of old production or injection wells for
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monitoring purposes. If such wells are recompleted for monitoring, there are special
considerations necessary to ensure the integrity of the well and to prevent fluid migration along
the borehole. These considerations include logging of the well (see the UIC Program Class VI
Well Construction Guidance), determining the integrity of the cement and casing, conducting
any necessary action to repair defects, and determining whether the existing well materials are
adequate for the new function of the well.
The diameter of the hole, any deviations from vertical, and any significant curvature or bends in
the well should be compared with the size of the proposed monitoring equipment. Existing well
materials should be checked to ensure that they are compatible with fluids with which they will
come into contact, such as carbon dioxide and carbon dioxide-rich brines if they are completed in
the injection zone. Any flaws in the casing or cement will need to be repaired. Procedures for
repairing defects in wells can be found in the UIC Program Class VI Well Area of Review
Evaluation and Corrective Action Guidance. Also, if monitoring is not necessary below the
injection formation (i.e., in projects that do not involve an injection depth waiver), plugging the
well below the injection formation is recommended.
4.3 Collection and Analysis of Ground Water Samples
General Information
The Class VI Rule requires ground water geochemical monitoring above the confining zone to
detect changes in aqueous geochemistry that may result from fluid leakage out of the injection
zone [40 CFR 146.90(d)]. The results of ground water monitoring will be compared to baseline
geochemical data collected during site characterization [40 CFR 146.82(a)(6)] to obtain evidence
of fluid movement that may impact USDWs. In addition, the owner or operator, if required by
the UIC Program Director, may periodically collect fluid samples within the injection zone as a
component of carbon dioxide plume tracking, as discussed in Section 5.
The proposed list of constituents, sampling methodology, sampling frequency, and the methods
used for analyses for all constituents should be described and technically justified in the site-
specific Testing and Monitoring Plan. EPA also recommends that a discussion of method
sensitivities, as well as how deviations from planned project performance that may indicate an
endangerment to a USDW will be identified, be included in the Testing and Monitoring Plan, as
approved by the UIC Program Director.
At a minimum, EPA recommends that all wells initially be sampled on a quarterly basis for all
relevant constituents during the injection phase. Alternatively, a project-specific frequency may
be determined (e.g., based on variability in ground water chemistry) and approved by the UIC
Program Director. Sampling frequency may be reduced based on project-specific benchmarks,
such as generally stable conditions observed in several successive sampling rounds. Likewise,
sample frequency may need to be increased if the results of monitoring indicate possible fluid
leakage or endangerment of USDWs at a particular location. Certain constituents may be
monitored near-continuously using dedicated downhole sensors, such as pH and specific
conductivity.
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Application
Sample Collection
Appropriate protocols consistent with existing EPA guidance (e.g., USEPA, 1991 and 1992)
should be followed for collection of ground water samples to maintain sample integrity. Some
aspects of commonly used ground water sampling protocols typical for shallow ground water
investigations are also applicable to deep-well sampling at GS sites, while other protocols will
need to be adapted to high-pressure, high-temperature conditions. This section briefly describes
appropriate protocols for collection of ground water samples for GS projects. For further
guidance, refer to existing EPA guidance (USEPA, 1991 and 1992; some portions of this section
have been adopted from these existing documents).
Fluid collection from monitoring wells at depths typical of GS projects is complicated by
elevated pressure and temperature of the sampled zone and the presence of multiphase fluids.
Partitioning of gases (e.g., carbon dioxide dissolution into the aqueous phase) is temperature and
pressure dependent. If not controlled, dissolved gases and supercritical fluids that exist at high
pressures and temperatures found in the deep formations quickly exsolve or flash to gas as they
are brought to the surface for analysis. Sampling systems have been developed that are lowered
into the well bore using a wireline or slickline. These samplers maintain sample integrity by
collecting samples at formation pressure and temperature, and allow collection and analysis of
brine, dissolved gases, and supercritical fluids (Freifield et al., 2009; Boreham et al., 2011).
Parameters such as temperature, density, pH, and conductivity can also be measured at near in
situ conditions. If samples are not collected at the original, in situ conditions, additional
measurements and reconstruction of the in situ conditions may be necessary during analysis and
should be reported along with the results.
The U-tube sampling system is one example of a sampling system that has been developed
specifically for deep well sampling, such as at GS sites. EPA notes that the U-tube sampling
system may not be appropriate or feasible for all GS sites; however it has been used successfully
in some test projects and is provided here as one example of a pertinent deep well sampling
system (Boreham et al., 2011). A U-tube sampling system has been used to collect samples of
reservoir fluids near in situ conditions for research-oriented GS projects at Cranfield,
Mississippi, and Otway, Australia, as well as other sites. The U-tube sampler can collect large
volumes of multiphase samples into high pressure cylinders for real-time field analysis and/or
off-site laboratory analysis (Figure 4-2).
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Sample vessels
13 liters each
N,Tank
Sampling
port
1.5km
Load cell
to measure
weight
Quadrupole
Mass
Spectrometer
Sample leg
Drive leg
Ball check valve
Sliding end packer
Inlet niter:
40 urn sintered
stainless steel
Figure 4-2. Schematic of the U-tube fluid sampling system (adapted from Freifeld et al., 2009; not to scale)
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The general recommended protocol for deep well sampling at GS sites consists of the following
steps:
1. Fluid level or pressure measurement. Prior to well purging and sample collection, it is
important to measure and record the static fluid level and/or pressure in the well, along
with bottomhole temperature. These measurements may be needed to estimate the
amount of water to be purged prior to sample collection, and they may also be used for
calculation of in situ pressure (Section 5.2). Pressure measurements may be obtained by
application of a downhole pressure transducer (Section 5.2).
2. Decontaminating sample equipment. When dedicated equipment is not used for sampling
(or well purging) or when dedicated equipment is stored outside of the well, the sampling
equipment needs to be cleaned between each sampling event. See USEPA (1992) for
recommended cleaning procedures, as well as manufacturer guidelines for the particular
system used.
3. Well purging. Fluid that has been stored within the well bore is removed prior to sample
collection to ensure that the sample is representative of the formation. See USEPA (1991)
for guidance on how to determine the volume of fluid to be removed from the well bore
prior to sample collection. During purging, EPA recommends that pH, specific
conductance, and temperature be field measured periodically. EPA recommends that
samples not be collected until the values of these parameters have stabilized. Use of
passive (non-purge) sampling techniques (see, e.g., ITRC, 2006) should be described and
technically justified in the Testing and Monitoring Plan and decided in consultation with
the UIC Program Director.
4. In situ or field analyses. It is recommended that physically or chemically unstable
analytes be measured in the field rather than in the laboratory. Examples include pH,
redox potential, dissolved oxygen, temperature, and specific conductivity. An in-line flow
cell, field kit, or downhole probes may be used for this analysis. All field and downhole
equipment should be properly calibrated according to manufacturer specifications.
5. Sample collection and handling. The following recommended guidelines pertain to
collection of ground water samples (for additional guidance, see USEPA, 1991 and
1992):
a. Samples should be collected at tubing outlets as close as possible to the wellhead
and placed into containers.
b. Separate containers are typically used for different types of target analytes.
Sample collection and containerization should be prioritized according to the
volatility of the target analytes. The preferred order is: (1) volatile organics, (2)
dissolved gases, including carbon dioxide, (3) semivolatile organics, (4) metals
and cyanide, (5) major anions and cations, and (6) radionuclides.
c. Samples should be transferred to sample containers in a controlled manner that
minimizes sample agitation and aeration.
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d. Ground water samples should be collected within a time period after the well is
purged that ensures the quality of samples.
e. The rate at which the well is sampled should not exceed the rate at which the well
was purged.
f Generally, the only samples that should be filtered in the field include major
anions and cations and total dissolved solids (IDS).
g. QA/QC procedures should be followed, as discussed below.
6. Sample containers and preservation. Refer to certified environmental laboratory protocols
or USEPA (1991) for the appropriate sample container and preservation method
depending on the analyte. Exposure of the samples to ambient air should be minimized.
7. Chain of custody and records management. A chain-of-custody procedure should be
designed to allow the owner or operator to reconstruct how and under what circumstances
the sample was collected, stored, and transported, including any problems encountered.
The chain-of-custody procedure is intended to prevent misidentification of samples, to
prevent tampering, and to allow easy tracking of possession.
8. Sample storage and transport. Transport should be planned so as not to exceed sample
holding time before laboratory analysis and to maintain samples at necessary
temperatures. Every effort should be made to inform the laboratory staff of the
approximate time of arrival so that the most critical analytical determinations can be
made within recommended holding periods.
Quality Assurance/Quality Control
The owner or operator is encouraged to follow accepted QA/QC procedures for collection and
analysis of ground water samples (USEPA 1991 and 1992). The purpose of QA/QC samples is to
ensure that the sampling protocol supports accurate laboratory analyses by eliminating cross
contamination of samples and evaluating the repeatability of the laboratory analyses. It is
recommended that the following QA/QC samples be analyzed, as a minimum, with each batch of
collected samples (a batch should not exceed 20 samples):
One field duplicate.
One equipment rinsate, blank.
One matrix spike (when appropriate for the analytical method).
One trip blank (when analyzed constituents include volatile organics or dissolved gases).
All field QA/QC samples should be prepared exactly as other field samples with regard to
sample volume, containers, and preservation. EPA recommends that the results of QA/QC
samples be evaluated to ensure that data quality is within acceptable limits. The owner or
operator may define acceptable data evaluation criteria in the Testing and Monitoring Plan. In
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addition, pursuant to 40 CFR 146.90(k), a Class VI permit application must contain a quality
assurance and surveillance plan for all testing and monitoring requirements. For further
information on EPA QA/QC procedures, including recommendations for preparing a Quality
Assurance Project Plan (QAPP), readers are directed to guidance provided for projects funded or
conducted by EPA (e.g., USEPA, 2002b).
Sample Analysis
Once the sample has been collected, it should be analyzed using an approved method for the
constituents of interest. EPA recommends that fluid samples be monitored for, at a minimum,
TDS, specific conductivity, temperature, pH, carbon dioxide, and density. In addition, the UIC
Program Director may require regular monitoring of major anions and cations, select trace
metals, tracers, hydrocarbons, and any other constituents identified by the owner or operator
and/or the UIC Program Director. If impurities are present in the injectate (e.g., mercury,
hydrogen sulfide), it is recommended that these be included in ground water monitoring (to
detect concentrations beyond baseline) if there are indications of carbon dioxide or formation
fluid displacement. Owners or operators of GS projects located in former or current oil and gas
reservoirs may also monitor for hydrocarbons. EPA recommends that owners or operators of
projects located in formations containing appreciable levels of arsenic or other metals that may
be mobilized by the injection activity routinely monitor for those metals. However, the final list
of constituents will be determined on a project-specific basis in consultation between the owner
or operator and the UIC Program Director, using site-specific data obtained during site
characterization (e.g., geology, geochemistry) and the composition of the injectate. As noted
above, the constituents of interest should be described in the Testing and Monitoring Plan.
Examples of acceptable analytical methods for relevant parameters are provided in Table 4-1. It
is recommended that an EPA-certified laboratory be used for all sample analysis. EPA's Office
of Water implements the Drinking Water Laboratory Certification Program in partnership with
EPA regional offices and states. Laboratories are certified by EPA or the state to analyze
drinking water samples for compliance monitoring. In order to be certified by EPA, laboratories
are required to successfully analyze proficiency testing samples annually, use approved methods,
and successfully pass periodic on-site audits. Lists of certified laboratories are available through
state lab certification programs. A listing of state lab certification programs can be found on
EPA's website at http://water.epa.gov/scitech/drinkingwater/labcert/statecertification.cfm.
Table 4-1. Example analytical methods for some constituents in ground water. Note that additional or
alternative methods may be available.
Monitoring Parameter
Carbon dioxide
Dissolved metals
Arsenic
Mercury
Lead
Hydrogen sulfide
EPA Method(s)
200.8, 200.9, 7010
245.1,245.2
ASTM Method(s)
D513
D3919-08
D2972
D3223
D3559
D4658
Standard Method(s)
4500
3112,3113
3114,3500
3500
4500
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Monitoring Parameter
Petroleum hydrocarbons
TDS
Major anions
Major cations
Fluid density
Methane
EPA Method(s)
8015C
300.1
6020A, 6020C, 700B
ASTM Method(s)
D7678-11
D5907
D4327-03
D5673-05, D4691-
02(2007), D 1976-07
D 1429-08
Standard Method(s)
2540C
4110,4140
3125,3111
6211
Interpretation
The analytical laboratory will provide the owner or operator with electronic and/or physical
reports that provide all sample results in appropriate units (e.g., mg/L), method detection limits,
the results of all QA/QC samples, and an evaluation of the resulting data quality. The results of
field-measurement analysis (e.g., pH, temperature) are typically then compiled with the
laboratory-supplied data. EPA recommends that the owner or operator maintain an electronic
database of all monitoring well sample results that lists the resulting sample concentration and
supplementary information, including sample data/time, analysis date/time, analytical detection
limit, and data quality flags.
Prior to use for interpretation, collected data from monitoring wells are to be evaluated for
quality and correctness. EPA recommends standard methods be used to ensure that sample
results are consistent with the project data quality objectives. Interpretation of measured results
also relies on comparison to baseline samples collected from the formation prior to injection, the
results of the compatibility demonstration required at 40 CFR 146.82(c)(3), or samples collected
upon construction of the monitoring well. See the UIC Program Class VI Well Site
Characterization Guidance for discussion of baseline samples.
The primary objective of ground water monitoring is to detect geochemical changes that may be
indicative of fluid leakage and migration. EPA recommends that the owner or operator evaluate
the collected data relative to previously collected data and baseline data. Additionally, if the
owner or operator conducts batch rock-water-carbon dioxide experiments or geochemical
modeling, the collected data should be compared to those results as well (see the UIC Program
Class VI Well Site Characterization Guidance for more information on these methods). Trends
that may be indicative of fluid leakage include:
Changing TDS: An increasing TDS trend may indicate that native brines have migrated
from the injection zone, or an intervening zone, into the monitored zone. A change in the
overall TDS trend may indicate fluid exchange between adjacent formations.
Changing signature of major cations and anions: A change in the signature of dissolved
ground water constituents in the monitored zone as compared to that of the injection zone
or confining zone may indicate leakage. The anion/cation signature may be evaluated
through the construction and use of ion diagrams, including Piper and Stiff diagrams
(Figure 4-3).
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Increasing carbon dioxide concentration: An increase in the concentration of dissolved
carbon dioxide may indicate leakage of the dissolved-phase plume into the monitoring
zone. Increasing carbon dioxide concentrations may also be observed due to other factors,
including increasing ground water recharge. These other factors may be evaluated to
ascertain if the observed increasing carbon dioxide concentrations are due to migration
from the injection zone.
Decreasing pH: A decreasing pH trend may indicate migration of carbonic acid and other
fluids into the monitoring zone. Similar to increasing carbon dioxide concentrations,
other factors may be evaluated that would cause an observed decrease in pH.
Increasing concentration of injectate impurities: An increase in the concentration of any
impurities in the injectate (e.g., hydrogen sulfide) may be indicative of injectate
migration into the monitoring zone.
Increasing concentration of leached constituents: The presence of carbon dioxide may
leach certain inorganics (e.g., lead, arsenic, iron, manganese) from the formation matrix
due to lowered pH. Additionally, if petroleum hydrocarbons are present, carbon dioxide
may increase the concentration of these constituents in the fluid phase. Increasing trends
may be indicative of fluid migration.
Increased reservoir pressure and/or static water levels (see Section 5.2).
Reduced sample fluid density, combined with the presence of separate-phase carbon dioxide in
the sampled fluid, may also indicate the presence of the separate-phase plume at the monitoring
location.
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80
. ,. ,,,.
Sulfate(Sty) + Chloride (Cl)
/ V
yso/ v
7 / /\
6Q\ Calcium (Ca) + Magnesium (Mg)
Magnesium (Mg)/6y
Sulfate (S04)
20 40 60
HC03 Chloride (Cl)
Cl
* Rose Run
A Rome
# Mt. Simon
* Newburg
A Sea water
Figure 4-3. Example Piper diagram showing proportions of major ions for formations in Ohio and Kentucky,
including potential target formations for GS (Battelle Memorial Institute, 2003).
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Reporting and Evaluation
The owner or operator is required to submit the results of ground water monitoring in the semi-
annual reports [40 CFR 146.91(a)(7)]. Data will be submitted in an electronic form directly to
EPA, where they can then be accessed both by the UIC Program Director and other EPA offices.
EPA recommends that the following information be submitted with all reports:
The most recent database of all ground water monitoring results and QA/QC monitoring
results.
Original complete laboratory reports, including chain-of-custody records.
Interpretation of any changing trends and evaluation of fluid leakage and migration. This
may include graphs of relevant trends and interpretive diagrams (e.g., Piper diagrams).
A map showing all monitoring wells, indicating those wells that are believed to be within
the boundaries of the separate-phase or dissolved-phase carbon dioxide plumes.
The date, time, location, and depth of all ground water sample collection and laboratory
analysis of each sample.
An evaluation of data quality for each sampling event.
A description of all sampling equipment and laboratory analytical procedures used,
noting any differences from protocols specified in the Testing and Monitoring Plan.
Records of calibration of all field sampling instruments.
Identification of data gaps, if any.
Any identified necessary changes to the project Testing and Monitoring Plan to ensure
continued protection of USDWs.
The UIC Program Director will evaluate the ground water monitoring data to independently
assess data quality, constituent concentrations (including potential contaminants), and the
resulting interpretation to determine if there are any indications of fluid leakage and/or plume
migration and whether any action is necessary to protect USDWs.
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5 Plume and Pressure-Front Tracking
Identification of the position of the injected carbon dioxide plume and the presence or absence of
elevated pressure (i.e., the pressure front) is integral to protection of USDWs for GS projects.
Regions overlying the separate-phase (i.e., liquid, gaseous, or supercritical) carbon dioxide
plume and area of elevated pressure are at increased risk for potential fluid movement that may
endanger a USDW. Because of this, monitoring the movement of the carbon dioxide plume and
pressure front is necessary to identify potential risks to USDWs posed by carbon dioxide
injection activities. Plume and pressure-front monitoring results also provide necessary data for
comparison to and verification of model predictions, and they inform the reevaluation of the
AoR (Figure 4-1). The owner or operator will use a site-specific, complementary suite of
methods to track the position of the carbon dioxide plume and area of elevated pressure.
Available methods for plume and pressure-front tracking include: (1) in situ fluid pressure
monitoring; (2) indirect geophysical monitoring; (3) ground water geochemical monitoring; and
(4) computational modeling. These methods must be described by the owner or operator in the
Testing and Monitoring Plan that is approved by the UIC Program Director [40 CFR 146.90].
EPA recognizes that these four methods include a range of specific technologies that may be
used to monitor and track a carbon dioxide plume and pressure front. Therefore, in the Class VI
Rule, EPA does not prescribe specific technologies (e.g., geophysical techniques, water sampling
apparatuses) that must be used to achieve these goals. The suite of methodologies used will be
site specific and vary based on project details, but it must include at least one direct method [40
CFR 146.90(g)(l)] and an indirect method, unless the UIC Program Director determines indirect
methods are not applicable [40 CFR 146.90(g)(2)]. Additionally, the flexibility of these
requirements allows for deployment of new technologies as they are developed. This section
discusses available methods that can be used for tracking the carbon dioxide plume and pressure
front. Computational modeling is discussed in detail in the UIC Program Class VI Well Area of
Review Evaluation and Corrective Action Guidance.
The various methods for identification of the location of carbon dioxide, mobilized fluids, and
elevated pressure provide complementary types of data. Direct pressure monitoring (see Section
5.2) and ground water geochemical monitoring (see Section 5.4) do not rely on theoretical
assumptions or data processing to the extent of other methods (e.g., indirect geophysical
methods). However, these two types of monitoring only provide point measurements (i.e.,
measurements at discrete locations). Indirect geophysical monitoring, discussed in Section 5.3,
provides broad, non-point measurements, but data collection requires extensive pre-processing
and in some cases results may be ambiguous compared to direct monitoring. Computational
modeling (discussed in the UIC Program Class VI Well Area of Review Evaluation and
Corrective Action Guidance} provides a prediction of future conditions, but these predictions
rely on simplifying assumptions and are prone to uncertainty. The most comprehensive
understanding of plume and pressure-front behavior will follow from an integrated interpretation
of information collected from a combination of these methods. For example, interpretation of
geophysical monitoring results is improved by consideration of available monitoring well data
during data processing. The predictive capability of computational models is improved by model
calibration to ground water geochemistry, pressure, and geophysical monitoring data. For Class
VI projects, this process is conducted during AoR reevaluation.
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5.1 Class VI Rule Requirements Regarding Plume and Pressure-Front Tracking
The Class VI Rule requires the use of "direct" methods for tracking the presence or absence of
elevated pressure (e.g., the pressure front) within the injection zone [40 CFR 146.90(g)(l)]. The
Class VI Rule also requires the use of indirect geophysical techniques for the purpose of tracking
the extent of the carbon dioxide plume, unless the UIC Program Director determines, based on
site specific geology, that such methods are not appropriate [40 CFR 146.90(g)(2)]. As discussed
below, on a site-specific basis, where the UIC Program Director determines that indirect methods
are not appropriate, he or she may require the use of direct methods for the purpose of tracking
the carbon dioxide plume by using monitoring wells that are perforated within the injection zone.
Table 5-1 provides a summary of the Class VI Rule monitoring requirements related to tracking
the position of the carbon dioxide plume and pressure front.
Table 5-1. Summary of Class VI Rule requirements and recommendations for identifying the position of the
carbon dioxide plume and associated pressure front.
Technology
Description
Class VI Rule
Requirement
Citation
Direct pressure
monitoring
Measurement of in situ fluid
pressure that may be achieved
using transducers placed within
monitoring wells in the injection
zone, behind casing gauges, or
through direct measurement of
fluid depth through a perforation
(see Section 5.2)
Required to track the presence
or absence of elevated pressure
within the injection zone
40 CFR 146.90(g)(l)
Indirect
geophysical
monitoring
Seismic, electrical, gravity, or
electromagnetic techniques
(see Section 5.3)
Required to track the presence
or absence of elevated pressure
within the injection zone and
the extent of the carbon dioxide
plume, unless the UIC Program
Director determines that such
methods are not appropriate
40 CFR 146.90(g)(2)
Direct carbon
dioxide plume
monitoring
Use of monitoring wells in the
injection zone to substantiate the
presence or absence of carbon
dioxide by geochemical methods
(see Section 5.4)
Required to track the extent of
the carbon dioxide plume if the
UIC Program Director
determines that indirect
methods are not appropriate
40 CFR 146.90(g)(l)
Computational
modeling
Informing the development of
field monitoring strategies and
incorporation of measured data
into a comprehensive
mathematical model of the site
Computational modeling is
required as a component of
AoR delineation and
reevaluation
40 CFR 146.84
5.2 Direct Pressure-Front Tracking
The Class VI Rule requires that fluid pressure be directly monitored within the injection zone [40
CFR 146.90(g)(l)]. Owners or operators are also required to supplement the direct monitoring
with indirect, geophysical techniques unless the UIC Program Director determines, based on site-
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specific geology, that such methods are not appropriate [40 CFR 146.90(g)(2)]. Pressure
monitoring in the injection zone is an integral part of overall GS monitoring because increased
pressure within the injection zone is the primary driver for fluid movement that may endanger
USDWs. Furthermore, pressure measurements will also inform AoR reevaluation.
Direct pressure monitoring provides measurements of formation pressure and supports tracking
the migration of the pressure front [40 CFR 146.90(g)(l)]. In this context, the term "direct
methods" pertains to the in situ measurement of fluid pressure, which may be achieved using
transducers placed in the injection zone behind casing gauges, or by direct measurement of fluid
depth in the well. Direct measurements of pressure also include measurements made at the
wellhead. These measurements do not rely on theoretical assumptions or data processing;
however, they only provide point measurements (i.e., measurements at discrete locations).
Therefore, where applicable, the Class VI Rule also requires indirect geophysical monitoring
(discussed in Section 5.3), which provides non-point measurements that can provide a broad
view of the movement and extent of the carbon dioxide plume and pressure front. EPA requires
that the strategy and methodologies selected for pressure-front monitoring be described in the
site-specific Testing and Monitoring Plan, which is approved by the UIC Program Director [40
CFR 146.90].
EPA recommends that owners or operators also monitor pressure above the confining zone(s);
these data may also be used to detect potential leakage through the confining zone(s). The
pressure front is defined as the zone where the pressure differential is sufficient to cause the
movement of injected fluids or formation fluids from the injection zone into a USDW. This
determination of the pressure front is based on existing standard practices for other well classes
in the UIC Program and involves calculation of a threshold reservoir pressure as described in the
UIC Program Class VI Well Area of Review Evaluation and Corrective Action Guidance. The
value of threshold reservoir pressure that defines the pressure front may be calculated based on
static pressure within the injection zone and the lowermost USDW, as well as the elevations of
both zones by determining the pressure within the injection zone that is great enough to force
fluids from the injection zone through a hypothetical open conduit into any overlying USDW.
The UIC Program Class VI Well Area of Review Evaluation and Corrective Action Guidance
includes an illustrative example of this calculation.
The proposed pressure monitoring frequency for all wells must be described and technically
justified to meet the requirements for the Testing and Monitoring Plan at 40 CFR 146.90. At a
minimum, EPA recommends that all wells be monitored for pressure changes on a monthly basis
during the injection phase. Monitoring frequency may need to be increased if the results of
monitoring indicate pressure increases greater than modeling predictions or indicate fluid
leakage. For many GS projects, pressure may be monitored nearly continuously by the use of
dedicated downhole devices. EPA notes that it is important to use and calibrate these devices
according to the manufacturer's specifications and standard (e.g., ASTM) guidance.
Application
At GS sites, direct pressure monitoring may be achieved using downhole transducers. Direct
pressure monitoring may also include measurements made at the wellhead. In some cases, fluid
pressure may be inferred from measurements of the depth to fluid. Measurement of the depth to
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fluid in the well from the surface can be used to determine bottomhole pressure based on
knowledge of the density of the fluid and the vertical distance between the perforated interval
and wellhead measurement. Fluid-level measurements may be obtained by use of an electric
depth gauge lowered on a wireline.
Considerations related to monitoring well placement and the design of the monitoring well
network for tracking the pressure front are similar to those for ground water geochemical
monitoring above the confining zone, as discussed in Section 4. Geochemical monitoring above
the confining zone and direct monitoring of pressure serve to achieve complementary goals for
ensuring USDW protection, by identifying potential leakage through the confining zone and
identifying elevated pressure zones in the injection zone, respectively. Therefore, EPA
recommends that, to minimize the number of monitoring wells deployed, owners or operators
consider an overall strategy to incorporate both types of monitoring when designing the
monitoring well network. Similar to the conditions recommended in Section 4 for geochemical
monitoring above the confining zone, EPA recommends the following considerations for the
design of the monitoring well network for pressure-front tracking:
Wells used to track the migration of the pressure front should be designed to allow in situ
measurements within the injection zone. EPA recommends that pressure measurements
be conducted in wells perforated at stratigraphically equivalent depth intervals to the
depth of the injection zone.
For projects with a separate-phase plume and/or pressure front predicted to move in a
specific direction (e.g., due to formation dip), wells should be primarily placed in the
predicted down-gradient direction. However, at least one up-gradient well is
recommended.
Well placement should be based on the predicted rate of migration of the separate-phase
plume and/or pressure front, according to the results of computational modeling and
taking into consideration associated uncertainties.
The number of monitoring wells placed within the injection zone should be determined
such that changes in the area of elevated pressure may be tracked sufficiently to detect
any pressure increase that differs from modeled predictions. The determination of the
number of injection zone wells may be based on a modeling and/or statistical analysis,
which should be documented in the Testing and Monitoring Plan.
Interpretation
Fluid-level data obtained from electric gauges lowered into the well on a wireline will consist of
depth to fluid measurements, in units of feet or meters. These measurements will be converted to
values of the elevation of the fluid column relative to a common datum, most commonly mean
sea level. This is achieved from the following equation:
FL=MPE-DTF [1]
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where FL is the elevation of the top of the fluid column within the well, MPE refers to the
surveyed measurement point elevation at the wellhead, and DTP refers to the measured depth to
fluid. Data collected from downhole pressure transducers will consist of pressure readings (in
units of psi or Pa). With knowledge of the elevation of the pressure transducer measurement
device, FL may be obtained using the following equation:
FL = PTE + ^- [2]
Pg
where PTE refers to the known elevation of the pressure transducer (measured when the pressure
transducer was emplaced), Pt refers to the measured pressure at the transducer, p refers to the
density of fluid within the well, and g refers to the acceleration due to gravity. Lastly, the FL
within the well is used to calculate the pressure (P) at the depth of the perforated interval of the
well using the following equation:
P = (FL-Z)-pg [3]
where Z is the elevation of the center of the perforated interval of the well. Note that temperature
corrections may be necessary for the fluid density term used in these calculations. If using data
from a pressure transducer set at the center of the perforated interval of the well, the above
calculations are unnecessary, and the measured pressure is representative of the in situ pressure.
Once the in situ pressure at all wells has been determined, temporal changes should be analyzed
by comparing the new data to previously collected data. EPA recommends that the owner or
operator produce and interpret time-series graphs for each well, taking into consideration the
injection rate and well location. An example plot of the temporal trend of measured pressure for
an injection and monitoring well are presented in Figure 5-1. It is recommended that spatial
patterns be analyzed by constructing maps that present contours of pressure and/or hydraulic
head. Increases in pressure in wells above the confining zone (if such monitoring is performed)
may be indicative of fluid leakage, and measurements should be used to complement fluid
monitoring data in assessing leakage. It is recommended that increases in pressure within the
injection zone be compared to modeling predictions to determine if the AoR is consistent with
monitoring results. Pressure increases at a monitoring well location greater than predicted by the
current site AoR model, or increases at a greater rate, may indicate that the model needs to be
revised. In this case, the UIC Program Director should be consulted to determine whether an
AoR reevaluation is necessary.
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C4-30 Injection Well
Bottomhole Pressure and Temperature
2300
22CQ
0
2/19/08 2/21/OB 2'23/OB 2.'25/08 2'27/OB 2/29/08 3/2/08 3'4,'OB 3/6.'08 3/8/03
ET(mln)
15SO
1540
1S30 --
1
^ 1520 -
I
a: 1510
I
| 1500
1
1490 -
1480 -
1470
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, . J..J,...
V
] Start I niec lion
90
88
.
84 1
oo
i
ill
74
72
70
2.'19'08
2/23/08
3/e,'08
ET{dayi)
3/10/08
3/14/08
3.1 aw
Figure 5-1. Example of temporal plots showing change in pressure and temperature at an injection well
(above) and monitoring well (below) during initial testing at the MRCSP Michigan Basin Validation Test
(images provided by Battelle Memorial Institute). Images are intended for example purposes only; note that
axis scales on the two graphs are not identical.
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Reporting and Evaluation
The Class VI Rule requires that the owner or operator submit the results of pressure monitoring
as part of the semi-annual reports [40 CFR 146.91(a)(7)]. Data will be submitted in an electronic
form directly to EPA, where they can then be accessed both by the UIC Program Director and
EPA offices. EPA recommends that the following information regarding direct pressure-front
monitoring be submitted with all reports:
Raw pressure data, interpreted data where pressure is calculated at the depth of the
injection zone, location and depth of all readings (e.g., depth to the perforated intervals),
and fluid temperature and density measurements.
If using pressure transducers, records of the most recent calibration or verification of the
measurement instrument.
Records of the surveying of wellhead and measurement point elevations.
Interpretation of data using supplemental maps and graphs, such as time-series graphs,
pressure contour maps, and correlations between injection rate and pressure response.
Comparison of measured pressures and model predictions for the same time period after
commencement of injection.
Geomechanical data and/or quantification of any fluid withdrawal or injection that would
impact measured pressure monitoring data.
Identification of data gaps, if any.
Any identified necessary changes to the proj ect Testing and Monitoring Plan to ensure
continued protection of USDWs.
Presentation, synthesis, and interpretation of the entire historical data set, including an
assessment of whether pressure data are indicative of fluid leakage.
The UIC Program Director will also evaluate the submitted data to independently assess if
pressure increases within the injection zone are consistent with predictive modeling, as well as
whether pressure measurements from wells above the confining zone are indicative of fluid
leakage. EPA notes that the owner or operator is required to report any permit noncompliance
which may cause fluid migration into or between USDWs within 24 hours [40 CFR
146.91(c)(2)].
5.3 Plume and Pressure-Front Tracking Using Indirect Geophysical Techniques
The Class VI Rule requires the use of indirect (i.e., geophysical) methods to supplement the
direct monitoring of the pressure front and to monitor the carbon dioxide plume unless the UIC
Program Director determines, based on site-specific considerations, that indirect methods are not
suitable [40 CFR146.90(g)(2)]. This section will discuss the use of geophysical methods, which
can be used to image the carbon dioxide plume and, in the case of seismic profiling, may also be
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used to derive fluid pressure. Geophysical methods include several technologies used to
indirectly monitor subsurface conditions over a relatively large area using surface and/or several
well bore measurements. These techniques typically work by initiating the propagation of a
signal (e.g., seismic, electromagnetic) and measuring the reflection or transmission of that signal.
Resulting data can be processed and interpolated to provide estimates of fluid phase-state (e.g.,
aqueous versus supercritical) and fluid pressure (if seismic profiling is used). Geophysical
techniques provide advantages over use of monitoring wells in that results are interpreted to
provide an understanding of the position of the carbon dioxide plume over a broad area, whereas
monitoring wells only provide discrete point measurements. Geophysical techniques have been
widely deployed in petroleum exploration and monitoring and in early GS projects (e.g., USDOE
NETL, 2009a). Using geophysical techniques also does not necessitate the drilling of a
monitoring well, which would be an artificial penetration and a potential conduit for fluid
movement.
There are three main types of geophysical methods that can be used for monitoring at GS
projects: seismic, gravity, and electrical. In addition to plume and pressure-front tracking,
geophysical methods are also used for site characterization (see the UIC Program Class VI Well
Site Characterization Guidance}. Baseline geophysical surveys conducted during site
characterization are necessary for comparison, to assess changes in the subsurface induced by the
injection operation. For detailed information regarding conducting baseline geophysical surveys,
see the UIC Program Class VI Well Site Characterization Guidance. This section focuses on
those methods applicable to surveys collected during the injection phase.
As described in Section 1.3, in a preliminary evaluation of GS monitoring technologies, USDOE
NETL (2009a) assessed several technologies based on application, function, and stage of
development. In this evaluation, technologies were rated as primary, secondary, or potential in
their ability to provide useful information for subsurface monitoring of injection well integrity
and the fate of the injectate and mobilized fluids.
The primary technologies identified by USDOE NETL (2009a) included some geophysical
techniques discussed in this document for plume and pressure-front tracking. Among these,
certain seismic methods were rated as secondary technologies, and the remaining methods, as
discussed below, were considered to be potential technologies that have not yet been proven in
commercial-scale projects. Before using any technology considered "potential" in the USDOE
NETL evaluation system, EPA recommends that the owner or operator consult with the UIC
Program Director (i.e., during the development of the Testing and Monitoring Plan). In addition
to geophysical techniques, the USDOE NETL evaluation also discusses certain potential
technologies, such as tiltmeters, synthetic aperture radar, and interferometric synthetic aperture
radar (InSAR), which can indicate crustal deformation associated with elevated pressure due to
carbon dioxide injection. These methods are at an earlier stage of development in their
applicability to GS and are not discussed in detail in this guidance document. The reader is
referred to USDOE NETL (2009a) and references therein for more information, and owners or
operators may consider use of these techniques in consultation with the UIC Program Director. If
taken in proper time lapse, some geophysical well logging methods (e.g., pulsed neutron) can
also be used for tracking of the plume. A well-logging program may be used to detect changes in
fluid saturation near the well bore and identify plume thickness. For further information on these
logs, see the UIC Program Class VI Well Site Characterization Guidance.
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In addition to the advantages and disadvantages common to most geophysical surveys (see the
UIC Program Class VI Well Site Characterization Guidance)., an additional challenge facing
deployment of these technologies for plume and pressure-front monitoring is ensuring proper
time-lapse (also called four-dimensional) deployment. To facilitate comparison between
sequential surveys, it is essential that each survey is carefully georeferenced. Changes in
subsurface conditions between surveys can be linked to changes in the location of the plume or
pressure front only if the exact location of every survey is known. Otherwise, anomalies between
surveys may be the result of comparing two different subsurface locations. Installing
infrastructure such as survey markers or measurement stations is one method to ensure
repeatability. A permanent deployment array is another method that can limit positioning error
between repeat surveys.
Changes in near-surface conditions may also need to be taken into consideration. For example,
research suggests that near-surface conditions such as soil water saturation may have a large
effect on comparability between seismic surveys (Urosevic et al., 2007). If possible, near-surface
variables should be limited by taking repeat surveys during periods of similar soil water
saturation and other near-surface variables.
Because the information gathered from geophysical surveys is indirect and subject to processing
that can introduce error, it is recommended that the results of any survey also be compared to
other site data (e.g., monitoring well data) where available. EPA recommends that the Testing
and Monitoring Plan describe any information that may be used to improve or support the
repeatability of the geophysical methods and associated data processing (e.g., selection of
sources, spacing, depth, optimization techniques, removal of background signal). Importantly,
quantification of the limits and uncertainties in the detection capabilities of the chosen methods
should be described in the Testing and Monitoring Plan.
5.3.1 Seismic Methods
General Information
Seismic profiling methods measure the arrival of seismic waves that travel through the earth.
Seismic surveys can be used to track the separate-phase plume and the migration of formation
fluids. These methods are generally recognized to have the highest resolution of all geophysical
remote imaging techniques in a variety of geologic settings (Benson and Myer, 2002). A large
variety of seismic techniques are available with different capabilities that can be targeted to
deliver greater detail near the borehole, between wells, or in another targeted location. Because
seismic monitoring is an established method, data collection and processing methods are well
known, numerous, and can be easily tailored to site-specific conditions.
However, seismic imaging may be difficult in certain types of geologic formations including
salts, basalts, coal seams, carbonates, and non-sedimentary units (Cooper, 2009; Hyne, 2001). If
such lithologies are present, seismic data may need to be supplemented with additional data to
ensure accuracy (e.g., geochemical monitoring in the injection zone for plume tracking). Seismic
methods also: perform poorly for detecting carbon dioxide in depleted gas reservoirs and do not
work well for imaging through shallow, dry natural gas reservoirs; can be affected by
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anthropogenic noise; are hard to deploy in populated areas; and can result in widely varying data
quality.
Of the seismic methods, two- and three-dimensional surface surveys, including time-lapse
surveys, and microseismic surveys are considered secondary technologies according to the
USDOE NETL evaluation system. Vertical seismic profiling (VSP) and crosswell seismic
methods are considered to be potential monitoring technologies (USDOE NETL, 2009a).
Application
All seismic methods rely on different subsurface materials having different seismic velocities
and varying likelihoods of reflecting seismic waves based on characteristics such as fluid
saturation and compaction. For example, seismic waves travel much more slowly through carbon
dioxide-saturated rock because supercritical carbon dioxide is less dense and more compressible
than aqueous fluids. Therefore, depending on the material, both the transmission time and the
number of reflections vary. In some methods, the recorded time is the two-way travel time (from
the source to the subsurface reflector and back to the receiver).
Data collection procedures for specific seismic methods vary widely, but there are several
common fundamentals. All methods require a natural or anthropogenic source of seismic waves,
which are detected by receivers (geophones or hydrophones) that log information about the
wave. Sources and receivers can either be on the surface (surface methods) or in the subsurface
(borehole methods). Seismic sources include natural earthquakes (including microseismic events
as small as -3 magnitude), explosives, vibroseis trucks, air guns, and piezoelectric sources.
Surface seismic methods (including two- and three-dimensional seismic) are suitable for plume
and pressure-front monitoring because they can image a large area and will likely be able to
capture the entire extent of the plume or pressure front. Borehole methods are only able to verify
if the plume has reached a certain point. Additionally, if the carbon dioxide plume develops
narrow protrusions (i.e., fingers) or migrates along faults or other narrow linear features,
borehole methods may fail to detect the movement of the carbon dioxide.
Borehole methods (e.g., crosswell, VSP, borehole microseismic) produce higher-resolution
images than surface methods because seismic waves only pass through weathered surface
horizons once, minimizing distortion. The higher resolution provided by these techniques may be
useful where the carbon dioxide plume is predicted to be thin or complex in shape. Additionally,
because wells are stationary, repeatability and georeferencing between surveys in a time-lapse
sequence is not a problem. However, borehole methods are less than ideal for plume and
pressure-front monitoring because they can only image a small region close to the well bore.
Borehole seismic methods may use monitoring wells installed for ground water monitoring.
Two-dimensional seismic surveys are used to collect an image that represents a vertical cross
section though the earth. Data are collected by a linear arrangement of geophones and seismic
sources positioned along the surface trace of the slice. Two-dimensional seismic surveys were
considered state of the art through the 1980s and are still commonly used today. Because of their
linear nature, two-dimensional surveys do not image features that are out-of-plane. For this
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reason, two-dimensional surveys are less applicable for plume and pressure-front tracking
compared to three-dimensional surveys.
Three-dimensional seismic surveys use a grid of multiple sources and receivers to generate a
mix of source-receiver combinations. The most basic arrangement is a linear array of geophones
and a linear array of seismic sources intersecting at a right angle (McFarland, 2009). The
resulting data set represents signal data received from a variety of sources, angles, and distances
at each geophone, eliminating problems caused by out-of-plane features. Advanced computer
processing is able to account for these geometries and create a three-dimensional model of the
subsurface. Three-dimensional seismic methods replaced two-dimensional seismic methods as
the state-of-the-art standard in the 1990s. Resolution and spatial coverage can be high, and,
under the right conditions, this method is ideal for imaging carbon dioxide in the subsurface.
Time-lapse seismic surveys (also referred to as four-dimensional surveys) generally consist of
the periodic repetition of three-dimensional surveys to image changes to the subsurface over
time. The exact same methodology needs to be used in the same locations during the repeated
surveys in order for data to be comparable. Performing a time-series survey allows subsurface
features such as fluid saturation to be tracked over time. The ability to accurately determine the
exact position of individual seismic surveys has been assumed to exert the strongest influence on
the overall quality of the time-lapse composite. However, research at the Otway project in
Australia (Urosevic et al., 2007) suggests that near-surface conditions such as soil saturation may
also have a significant effect on seismic repeatability and comparability between surveys. An
example of tracking the evolution of a carbon-dioxide plume in the subsurface using time-lapse
seismic surveys is provided in Figure 5-2.
Vertical seismic profiles or VSPs are the most common borehole seismic method. They obtain
an image of the plane between the well bore and the surface. A VSP is conducted with one
component located on the surface (usually the source) and the remaining component placed
downhole (Figure 5-3). The surface component may be stationary or moved during the survey.
1994
1999
2001
-
2002
I 2004
2006
3 km
- N
Figure 5-2. Time-lapse three-dimensional seismic surveys were used to track the spread of the carbon dioxide
plume at the Sleipner project in the North Sea (Arts et al., 2008). Figure shows a surface view of the plume
(right) and slices through the plume (left). Images from European Association of Geoscientists & Engineers
(EAGE)TFirst Break; reprinted with permission.
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Survey
Well
Recording
Truck
Source
Shallow
J-Component
Reference
Geophone
Moveable
J-Component
Wall Lock
Geophone
TD
Explanation:
I | Downgoing multiple
, ; Direct arrival
Upgoing refection
(*) Upcjoingmultiple
Figure 5-3. Schematic of the VSP process (adapted from Sah, 2003).
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VSPs can be conducted on land or at sea in vertical or deviated wells to a depth of at least 3,000
m (Balch et al., 1982). The source may be directly adjacent to the borehole or located at a fixed
distance away (an "offset" VSP). A "walkaway" VSP results when the source is moved away
from the well over the course of the survey. VSPs provide valuable information about the
subsurface geologic structure and seismic anisotropy; in addition, increased resolution compared
to surface seismic methods allows VSPs to detect thin plumes.
Crosswell seismic methods deploy sources and receivers in several different wells, producing a
survey that images the plane between the wells. Equipment is generally deployed in dedicated
monitoring wells not more than 500 m apart (Hoversten et al., 2002), although deployment down
active injection wells is also possible (Daley et al., 2007). A seismic source is deployed down
one well and seismic recorders are deployed down additional wells. A typical problem with
crosswell surveys is difficulty in matching profiles taken at a common well. These failures often
result from processing techniques that assume simple geology and vertical wells and that fail to
allow for out-of-plane structure. However, newer data processing techniques have made progress
at remedying these problems. Crosswell surveys using several wells are now able to generate
three-dimensional crosswell surveys (Washbourne and Bube, 1998). Multiple wells are needed
for crosswell seismic surveys, potentially limiting deployment in regions with few subsurface
penetrations. This may also limit the usefulness of crosswell seismic for purposes of plume
tracking as a project matures, if the plume has expanded beyond the area between the
observation wells.
Borehole microseismic profiling uses a string of geophones deployed down a monitoring well
for weeks to months, or permanently (to avoid placement errors). Microseismic events that occur
naturally during that time (typically on the order of magnitude -3 to -1) are detected by these
geophones. Because this method does not use an actively controlled source of seismic energy, it
is considered to be a passive-source method. On average, microseismic events can be detected up
to 1 km from the well (Downie et al., 2009). After collection, the hypocenters of the
microseismic events are plotted onto a three-dimensional subsurface projection to image
subsurface areas undergoing deformation. Borehole seismicity profiling may not be appropriate
for imaging fluids, and therefore it may not be useful for plume tracking at present. However, the
method may be useful for tracking the pressure front because changes in seismicity are often
related to changes in subsurface pressure.
Interpretation
Seismic surveys produce a two-dimensional cross-section or a three-dimensional image of the
subsurface. However, after collection, seismic data require extensive post-collection processing
to convert the data into interpretable images. For example, due to source/receiver geometry and
physics, uncorrected seismic reflections from dipping layers appear in the wrong location and at
an incorrect dip. Layers that terminate against a fault may appear to cross the fault. Depending
upon the method, more than 30 different filtering and processing steps can be applied. These data
processing steps inherently introduce error and uncertainty, and direct data collected from
monitoring wells may be used to constrain data processing and improve data confidence.
Resolution varies greatly depending on the seismic technique used. Generally, crosswell seismic
has the best resolution, followed by VSP, then surface seismic methods. Three-dimensional
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methods usually have higher resolution than two-dimensional methods. However, there is a
tradeoff between resolution and depth: high-frequency waves yield a greater resolution because
the wavelength is smaller, but they cannot penetrate as deeply. Traditional rules of thumb limit
the resolution to between one-quarter and one-eighth of the wavelength (Rubin and Hubbard,
2005; Wilson and Monea, 2004). It is generally recognized that seismic methods have the best
resolution of all geophysical methods (Benson and Myer, 2002).
Although seismic waves are sensitive to low saturations of carbon dioxide, the relationship
between saturation and sensitivity is not linear (TEA, 2006). Therefore, while it is relatively easy
to determine if separate-phase carbon dioxide is present using seismic methods, it is much harder
to constrain the volume present on a seismic survey. Additionally, temperature uncertainties in
the reservoir can introduce large errors into carbon dioxide volume calculations because
temperature has a strong effect on carbon dioxide phase and volume. The range of carbon
dioxide saturation that can be imaged will depend upon several site-specific conditions. Lumley
et al. (2008) have discussed this issue and draw some general conclusions: (1) seismic techniques
are an excellent monitoring tool for detecting areas with and without carbon dioxide (i.e., with a
bird's eye view); (2) in typical situations, seismic techniques may or may not be able to
reasonably image the three-dimensional distribution of carbon dioxide; and (3) it will be
extremely challenging to quantitatively invert seismic data to accurately estimate carbon dioxide
saturations and injected volumes of carbon dioxide due to fundamental physical limitations.
Seismic surveys can be processed to yield subsurface pressure data and used to track the pressure
front. Any seismic survey that yields an accurate acoustic seismic velocity can be used, but
multi-component data are especially useful in improving the resolution of seismic pore pressure
determinations. Seismic velocity data are coupled with an estimate of the overburden pressure
(usually from gravity data or borehole logs) and further processed to produce pressure estimates.
This step may introduce error because subjective correction factors may be needed. Pore pressure
estimation, in a well-known basin, tends to work best in basins filled with shales and sands
where significant investigations have already occurred and local correction factors have already
been developed (see Sayers et al., 2005; Young and Lepley, 2005; and Sayers et al., 2000).
Under optimal conditions, pore pressure analysis can resolve pressure data for strata 30 to 60 m
thick at medium depth in clastic basins with relatively simple stratigraphy (Huffman, 2002).
5.3.2 Electric Geophysical Methods
General Information
Electromagnetic and electric geophysical methods measure changes in the resistivity of the
formation due to changes in the electrical conductivity and saturation of formation fluids.
Electric methods transmit current into the subsurface, while electromagnetic methods measure
the induction effect (generation of current and electric fields) in the subsurface caused by another
electromagnetic field or electric current. Because carbon dioxide is relatively less conductive to
electric current and brines are highly conductive, displacement of brine by carbon dioxide will
result in a change in the resistivity of the formation to current flow.
One advantage of electric techniques is that they are not dependent on rock strength or formation
depth but are influenced almost solely by fluid composition and saturation, which may depend
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on rock type and porosity, making them good candidates for tracking the progress of carbon
dioxide plumes in a wide range of environments (Wynn, 2003). Electrical conductivity is also
more directly influenced by carbon dioxide saturation and other changes in reservoir fluid
properties than seismic variables, which are more influenced by changes in density (Wilt et al.,
1995). Additionally, hardware will likely be permanently installed so that georeferencing of
equipment is not an issue for subsequent tests. This advantage makes four-dimensional
comparisons easier than with other methods. Resistivity methods are not recommended for dry
gas reservoirs (Benson and Myer, 2002).
Time-lapse surveys can be complicated by changes in soil saturation, fluid pH, and temperature.
Also, most electrical/electromagnetic deployments are better for measuring bulk changes in
resistivity than for identifying thin fingers or small regions of anomalously resistive material,
similar to what may occur along leakage paths. Potential imaging planes for borehole methods
are also limited to planes between wells or other subsurface protrusions. Electric geophysical
methods for plume and pressure tracking are characterized as potential monitoring technologies
in the USDOE NETL evaluation system (USDOE NETL, 2009a). Therefore, their feasibility for
plume and pressure-front tracking should be considered based on site-specific conditions and be
discussed and technically justified in the Testing and Monitoring Plan.
Application
Although many different methods are available, two electric methods are common and likely to
be useful for monitoring at GS projects: long electrodes and electrical resistance tomography
(ERT). These methods are described more fully in the appendix to the UIC Program Class VI
Well Site Characterization Guidance. There are additional emerging methods that are not
described in this guidance, such as the joint use of crosswell seismic and electromagnetic
technology for monitoring of the plume (Hoversten et al., 2002).
The long electrode method shows promise for GS; owners or operators may wish to consider
this method as its utility becomes better established. The method consists of a controlled-source
electric method that uses electrodes inserted into the subsurface to emit and receive electric
pulses. Long electrodes are a conducting material that is in contact with both the region of
interest and the surface. Specially deployed metal probes can be installed or, in some cases, the
well casings themselves can be used as long electrodes. Even when wells are used, additional
probes may be needed to improve resolution (Newmark et al., 2002). If metal probes are used,
they will represent penetrations into the confining zone, because the probe needs to be in contact
with pore fluids in the region of interest (i.e., the injection zone). Such probes, however, are
generally permanently deployed, so the risk of leakage may be minimal as long as the probes
themselves do not degrade.
During the survey, some long electrodes are used as receivers and measure the electric signal
from charging of other electrodes with an electric current. The resistivity of the formation is
calculated from the difference between the strength of the emitted and received signal and
contoured on a surface map. A variety of source/receiver combinations is usually used to
maximize the amount of data gathered and the number of different views of the targeted area
(Daily and Ramirez, 2000). Both vertical and horizontal wells can be used as long electrodes. If
only vertical wells are used, the resulting survey will have no vertical resolution. Additionally,
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when using long electrodes, the signal is the average over the entire length of the electrode.
Therefore, small changes that only contact a small part of the electrode may be difficult to detect.
Crosswell ERT surveys have a similar deployment to crosswell seismic surveys and image a
plane between the two wells. Point electrodes are deployed at set distances along a non-
conductive well casing such as plastic or fiberglass (Newmark et al., 1999). Deployment can be
either temporary or permanent, in which the electrodes are part of the casing. As an electric
source is raised in one well, the resistivity of the formation between the wells is recorded.
Ideally, the distance between wells is not more than a few hundred meters (Christensen et al.,
2005), although successful ERT studies have occurred with wells spaced up to 850 m apart
(Marsala et al., 2008). Because resistivity measurements are taken at different depths, this type of
survey can determine both the horizontal and vertical extent of electric anomalies. This
deployment produces results with greater detail than other electrical methods. However, it may
require specialized hardware (e.g., specialized casing and the cabling connecting the electrodes
to the surface) and dedicated monitoring wells and/or stoppages in production/injection.
Interpretation
Resistivity measurements are highly sensitive to the brine saturation within a reservoir.
Measured resistivity values will increase when gas or supercritical fluid enters the pore space in
the monitored location. In reservoirs without the presence of other gases, increased resistivity
measurements are interpreted as the arrival of the separate-phase carbon dioxide plume (e.g.,
Schilling et al., 2009). Resistivity changes on the order of 30 percent can generally be detected,
although under optimal conditions resistivity changes as little as 10 percent can be measured.
The resolution of the survey is highly dependent upon the arrangement of the electrodes. When
low electromagnetic frequencies are used, resolution is fairly low and the measurements are
strongly affected by the conductivities of structures near the source and receiver (Wynn, 2003).
Resolution is low for most methods when compared to seismic methods, although some methods
may provide higher resolution for small areas.
Depending upon the exact deployment, electrical methods require various amounts of post-
collection processing. Raw data are corrected for the effect of steel casings and obvious outliers
are excluded. The data are then inverted and color-coded to produce either two- or three-
dimensional resistivity maps (Schuett et al., 2008). Depending upon the method, results can be
presented either as surface maps or depth sections. Like seismic methods, the results of electrical
methods are interpreted visually. Electrical changes in the subsurface are also caused by changes
in soil saturation, the pH of the fluids, and temperature. Such changes can complicate time-lapse
surveys. In addition, several non-unique reconstructions of electrical survey data are possible,
complicating data interpretation. Interpretation can be improved by considering other types of
data (e.g., monitoring well data, other geophysical surveys). Furthermore, instrument calibration
in a laboratory using in situ conditions can improve data quality and interpretability (e.g.,
Schilling et al., 2009).
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5.3.3 Gravity Methods
General Information
Gravity-based methods use a gravimeter to detect the force due to gravity at a given point.
Measurements may be used to track the carbon dioxide plume because carbon dioxide has a
different density than the formation fluids it displaces and will have a different gravity signal
strength. The contact between carbon dioxide and formation fluids might be determined both
laterally with surface measurements and vertically with borehole measurements (Alshakhs et al.,
2008). Gravity methods cannot be used to measure the pressure front, and they are considered to
be potential monitoring technologies according to the USDOE NETL (2009a) evaluation system.
Further discussion of geophysical gravity methods can be found in the UIC Program Class VI
Well Site Characterization Guidance.
Gravity measurements for plume tracking will work best in horizontal, thick formations with
high porosity and permeability where brine is being replaced by carbon dioxide and a thick
enough plume is produced to create large density contrasts with stronger signals between original
and post-injection conditions. Gravity monitoring may be especially useful for monitoring
upward movement of gaseous carbon dioxide plumes, which can occur at relatively shallow
depths (i.e., less than approximately 800 m).
Carbon dioxide is difficult to detect with gravity measurements when it occurs in thin layers.
Therefore, gravity methods are likely to work better in thick saline formations than in
hydrocarbon reservoirs, which are often thinner (Hoversten and Gasperikova, 2003). Depleted
gas reservoirs pose a challenge for gravity monitoring because residual gas trapped within pores
in the reservoir can decrease the density contrast with injected carbon dioxide (Sherlock et al.,
2005). One advantage of gravity methods, particularly compared with seismic methods, is that
the data are collected from a robust signal and transformed with simple equations that introduce
a minimum of interpretive error. However, like electromagnetic data, the measurements are not
unique to certain lithologies or features, and complementary data are helpful in interpreting the
results.
Time-lapse gravity surveys should show a decrease in gravity values as carbon dioxide migrates
into a location (USDOE NETL, 2009a). The method can detect mass changes and, possibly,
surface deformations induced by the injection activity. The detection threshold is site specific,
and it depends on reservoir depth and physical properties and the distance between the target
location and the survey. A common problem in interpretation of gravity surveys is the need to
account for other sources of gravity variations and instrument drift.
Application
Data are collected using a gravimeter, which measures the elongation of a wire suspending or
attached to a mass. As gravity increases, the mass is pulled downward and the wire lengthens.
The deformation is measured and transformed into a gravity reading. Relative gravimeters
compare the gravity measurement at one point to measurements at another point. They should be
calibrated at a location where the gravity is known accurately and subsequently transported to
another location where the gravity is to be measured. The gravimeters then measure the ratio of
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the gravity at the two points; the deformation is measured and transformed into a gravity reading.
Absolute gravimeters, which measure gravity by dropping a mass a short distance (several
centimeters) and using a laser to measure the acceleration, are also available. Absolute
gravimeters are thought to produce higher quality data than other types of gravimeters (Cooper,
2009).
Land-based and aerial gravity methods are both used to collect gravity surveys on a large
scale. Land-based surveys will generally have a higher resolution than aerial data, and aerial data
may not be sufficiently resolved for plume detection. For surface deployments, measurements
are typically taken at discrete stations across the area of interest.
Borehole gravity surveys are similar to borehole seismic surveys. A gravimeter is lowered
down the borehole and measurements are taken as the device is raised. Borehole surveys have
been conducted in wells 2,000 m deep and inclined up to 60 degrees (Seigel et al., 2009). Gravity
gradiometry, a slightly different data collection technique, needs to be used in regions with non-
horizontal strata. Borehole gravity data can be used to monitor the carbon dioxide plume by
detecting the interface between formation fluids, even if well bores do not intersect it. The
gas/brine interface can be detected for hundreds of meters. With a permanently installed
gravimeter, the detection distance for these interfaces could be detected at over 1 km away
(Alshakhs et al., 2008). However, when using a single well it is only possible to know the radial
distance of a feature from the well, not the direction.
Interpretation
After collection, gravity data are corrected for instrument drift, elevation differences, and other
site-specific conditions of the deployment. For monitoring purposes, gravity data will most likely
be contoured and displayed on a surface map. Like other geophysical monitoring techniques,
data are usually interpreted and cross-referenced with cross-sections, stratigraphy, and regional
geologic information to help constrain the most logical interpretation of the data.
5.3.4 Reporting and Evaluation of Geophysical Survey Results
The Class VI Rule requires that the owner or operator submit the results of any indirect
geophysical monitoring in the semi-annual reports, pursuant to 40 CFR 146.91(a)(7). Data will
be submitted in an electronic form directly to EPA, where they can then be accessed both by the
UIC Program Director and other EPA offices. EPA recommends that the following information
be submitted with all reports:
A description and technical justification of all survey techniques and methodologies used.
A map showing the location of all survey equipment positions during the test.
A description of the use of survey markers and/or measurement stations in the
geophysical surveys.
The date and time of collection of all geophysical data.
A description of near-surface conditions, such as soil water-saturation conditions.
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If required by the UIC Program Director, raw data collected by the survey equipment.
A description of all data processing steps taken and the major assumptions used during
data processing that may affect the interpretation of the data, if different than specified in
the Testing and Monitoring Plan.
An interpretation of all geophysical survey results relating to the position of the plume
and/or pressure front and fluid leakage (if detected), including available information on
injection (e.g., rate, pressure), method sensitivity, and any anomalies that require follow-
up.
Maps showing the interpreted location of separate-phase carbon dioxide in the injection
zone and its location in any additional zones in which it was detected.
A comparison of the measured position of the carbon dioxide plume with modeled
predictions corresponding to the time of the survey.
Identification and explanation of data gaps, if any.
Any identified necessary changes to the proj ect Testing and Monitoring Plan to ensure
continued protection of USDWs.
Presentation, synthesis, and interpretation of the entire historical data set.
The UIC Program Director will evaluate the submitted data to independently assess if the
position of the carbon dioxide plume and/or pressure front are consistent with predictive
modeling and to confirm USDW protection within the AoR.
5.4 Use of Geochemical Ground Water Monitoring in Plume Tracking
Ground water geochemical monitoring from wells perforated within the injection zone may be
used to infer the presence or absence of carbon dioxide at a location, and therefore they may be
used to augment the required activities at 40 CFR 146.90(g) for tracking the extent of the carbon
dioxide plume. The Class VI Rule does not require the use of monitoring wells for the purposes
of tracking the extent of the carbon dioxide plume in all cases. In certain cases, the owner or
operator, collaboratively with the UIC Program Director, may determine that the use of
geochemical ground water monitoring may be necessary to track the carbon dioxide plume
sufficiently. The decision whether to use geochemical ground water monitoring for plume
tracking will be based on site-specific conditions and predicted system behavior (e.g., rate and
direction of migration of the separate-phase plume and/or pressure front). The owner or operator
is encouraged to consult the UIC Program Director while making this decision during
development of the Testing and Monitoring Plan.
EPA recommends that the Testing and Monitoring Plan include a detailed description of the
number and placement of monitoring wells and the site-specific factors that have been
considered, as well as a description of why geochemical monitoring is needed. Similarly, a
discussion of the parameters to be monitored and the frequency at which sampling and analysis
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will be performed should be included in the plan. It is important that the owner or operator
describe method sensitivity and how the monitoring plan will detect plume extent and/or any
endangerment to a USDW. If phased or triggered monitoring is proposed, all factors considered
for the development of the strategy should also be included in the plan. More information on the
development of the Testing and Monitoring Plan can be found in the UIC Program Class VI Well
Project Plan Development Guidance and Section 1.2 of this guidance document.
Evaluation of Plume Tracking Using Ground Water Geochemical Monitoring
EPA recommends that the following be considered in determining whether to use ground water
geochemical monitoring as a component of plume tracking:
In cases when the UIC Program Director has determined that geophysical techniques are
not appropriate for a given site for plume tracking, direct methods must be used [40 CFR
146.90(g)], and EPA recommends the use of geochemical ground water monitoring for
plume tracking. Section 5.3 discusses the types of geologic formations for which indirect
geophysical methods may not be suitable. For example:
o Seismic imaging may not be appropriate in salts, basalts, coal seams, carbonates,
non-sedimentary units, depleted gas reservoirs, and shallow natural gas reservoirs.
Seismic methods can also be affected by anthropogenic noise and are hard to
deploy in populated areas.
o Time-lapse electrical/electromagnetic methods can be complicated by changes in
soil saturation, fluid pH, and temperature, and they are not favorable for imaging
thin fingers of carbon dioxide fluid that may occur along preferential pathways.
o Carbon dioxide is difficult to detect with gravity measurements when it occurs in
thin layers. Therefore, gravity methods are likely to work better in thick saline
formations than in hydrocarbon reservoirs, which are often thinner. Depleted gas
reservoirs also pose a challenge for gravity monitoring because residual gas
trapped within pores in the reservoir can decrease the density contrast with
injected carbon dioxide.
Geophysical techniques are capable of imaging the separate-phase carbon dioxide plume,
but not the larger dissolved-phase carbon dioxide plume that is created by dissolution of
carbon dioxide into native fluids. In cases where there may be risks associated with the
dissolved-phase plume, geochemical ground water monitoring is encouraged.
If geophysical methods will be deployed, but are prone to a significant amount of
uncertainty, ground water geochemical monitoring may be used to complement
geophysical surveys (e.g., the site-specific factors discussed above). For example,
geochemical data may be used to reduce uncertainty with interpretation of geophysical
results during data processing.
In some cases, it may be appropriate to conduct relatively frequent ground water
geochemical monitoring for plume tracking (e.g., every six months), with less frequent
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repeat geophysical surveys to complement the geochemical monitoring (e.g., every five
years). A complementary program of geochemical monitoring and geophysical surveys
may be designed to provide sufficient tracking of the carbon dioxide plume.
Application
Considerations related to collection and analysis of ground water samples within the injection
zone will be similar to those for wells perforated above the confining zone, described in more
detail in Section 4 of this guidance document. EPA recommends similar sampling protocols,
QA/QC, and analytical procedures as those discussed for ground water geochemical monitoring
above the confining zone. For the purposes of plume tracking, EPA recommends that fluids
collected from the injection zone be monitored for carbon dioxide, at a minimum. If available,
downhole probes may be used to estimate carbon dioxide concentrations in lieu of sample
collection and laboratory analysis. Additionally, an analysis of headspace gas (gas that
accumulates at the top of the well) at monitoring wells may be used as an indicator of the
proximity of the plume.
Wells constructed to directly monitor pressure within the injection zone may also be used for
geochemical monitoring. In rare cases, particularly when indirect geophysical techniques are not
used, additional monitoring wells may be necessary within the injection zone to track the carbon
dioxide plume. Specifically, EPA recommends the following considerations for design of the
monitoring well network for plume tracking:
EPA recommends that monitoring wells sited near injection wells be perforated at a
similar interval to the injection well(s). For those wells sited further from injection wells,
the owner or operator may consider perforating wells at shallower depths (closer to the
injection zone/confining zone interface) to account for vertical buoyant flow as carbon
dioxide migrates laterally.
For projects predicted to have a separate-phase plume and/or pressure front that moves
preferentially in one direction, EPA recommends that monitoring efforts be concentrated
in that direction.
Well placement should be based on the predicted rate and direction of migration of the
separate-phase plume and/or pressure front.
The number of monitoring wells placed within the injection zone should be determined
such that the migration of the carbon dioxide plume may be tracked sufficiently. The
determination of the number of injection zone wells may be based on a modeling and/or
statistical analysis, as well as the overall testing and monitoring strategy to detect any
deviation from the modeled predictions or planned operation. EPA recommends that this
determination be documented in the Testing and Monitoring Plan.
Interpretation
The objective of ground water monitoring within the injection zone is to track the extent of the
carbon dioxide plume by determining the presence or absence of carbon dioxide at a location.
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Determination of plume thickness and its three-dimensional extent may require additional
assessments. EPA recommends that the owner or operator evaluate the collected data in
comparison to baseline data and other previously collected data. Trends that are indicative of the
presence of the carbon dioxide plume at a particular location may include an increase in the
concentration of dissolved carbon dioxide at in situ conditions. The concentration of carbon
dioxide at specific in situ conditions (e.g., temperature, pressure) may be used to ascertain if
separate-phase carbon dioxide may be present, based on accepted mass-transfer relations and
equilibrium constants. Results that may be indicative of the presence of the separate-phase plume
at the monitoring location also include reduced sample fluid density and the presence of
separate-phase carbon dioxide in the sampled fluid, as measured at in situ conditions.
EPA recommends that, where possible, data collected from monitoring wells within the injection
zone be compared to indirect geophysical data regarding the extent of the separate-phase plume.
Comparison and interpretation of the two data sets may be used to elucidate uncertainties related
to either monitoring technology.
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6 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 USDWs [40 CFR
146.90(h)]. Under the Class VI Rule, all surface air and/or soil gas monitoring required for
compliance with UIC regulations must be based on potential risks to USDWs [40 CFR
146.90(h)(l)]. The objective of surface air and/or soil gas monitoring under the Class VI
Program is to provide an additional line of evidence of whether carbon dioxide has leaked from
the injection zone and potentially endangered USDWs.
If the UIC Program Director requires surface air and/or soil gas monitoring pursuant to
requirements at 40 CFR 146.90(h), and an owner or operator demonstrates that monitoring
employed under Subpart RR of the Greenhouse Gas Mandatory Reporting Rule [40 CFR 98.440
to 98.449] accomplishes the goals of 40 CFR 146.90(h)(l) and (2) and meets the requirements at
40 CFR 146.91(c)(5), the UIC Program Director must approve the use of monitoring employed
under Subpart RR [40 CFR 146.90(h)(3)]. Subpart RR, promulgated under the authority of the
Clean Air Act, complements UIC requirements with the added monitoring objectives of
verifying the amount of carbon dioxide sequestered, as well as collecting data on any carbon
dioxide surface emissions. Section 4 of the Subpart RR General TSD (USEPA, 2010) describes a
suite of monitoring technologies available for surface air and soil gas monitoring. Section 5 of
the TSD provides considerations for reporters in developing their Monitoring, Verification, and
Reporting (MRV) plans for Subpart RR.
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 monitoring strategy that
efficiently meets all monitoring objectives. In some cases, separate technologies (e.g., eddy
covariance towers versus soil gas probes) may be used to meet specific monitoring objectives.
However, it is likely that data collected from multiple techniques will be complementary and
useful in data analysis and interpretations for all applicable regulatory programs.
Carbon dioxide detection above background levels in soil gas or at the surface does not
necessarily demonstrate that USDWs have been endangered, but it may indicate that a leakage
pathway or conduit exists at some point in the operation. For example, the carbon dioxide
delivery system or ancillary wellhead equipment may be a leakage source. Carbon dioxide
migration into the unsaturated zone or surface air from the injection zone may occur from a non-
point or point source or a combination of both. Non-point sources include migration of injectate
through the confining zone and overlying zones through a diffuse network of high-permeability
pathways, including micro-fractures. Point sources include leakage through artificial penetrations
(wells), individual fractures, fault zones, and surface equipment. In either case, leaking carbon
dioxide at these depths will be in the gaseous phase, and it will mix with resident gases (e.g., air,
soil gas). Carbon dioxide migration may be detected by observation of concentrations elevated
above background levels. Detection of migration is more likely for point sources, because the
resulting carbon dioxide concentrations will likely be greater. Common to surface air and soil
gas monitoring is the need to account for natural background carbon dioxide concentrations,
which fluctuate seasonally. In addition to monitoring for carbon dioxide concentration, surface
air and/or soil gas may also be monitored for tracer gases or carbon dioxide isotopic signatures,
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which may aid in evaluating carbon dioxide sources. A detailed discussion of monitoring for
tracer gases and carbon dioxide isotopes is included in the Subpart RR General TSD (USEPA,
2010). There are also some emerging methods, such as the process-based method for near-
surface leakage detection used at the Weyburn-Midale enhanced oil recovery (EOR) project site
(see the Appendix for more information). This method relies on gas concentration relationships
to identify the dominant near-surface processes (Romanak et al., 2012).
The Class VI Rule, at 40 CFR 146.90(h)(2), requires that monitoring frequency and spatial
distribution of surface air and/or soil gas monitoring be determined using baseline data, and the
Testing and Monitoring Plan must describe how the proposed monitoring will yield useful
information on the area of review delineation and/or compliance with standards under 40 CFR
144.12. Information regarding determination of baseline is given in the UIC Program Class VI
Well Site Characterization Guidance. In addition, EPA recommends that the location of surface
air and/or soil gas sampling points be based on the following considerations:
Avoiding areas of highly fluctuating background concentrations, based on previously
recorded data.
Sampling near obvious point sources, including wellheads, artificial penetrations, natural
discharge points, and fault or fracture zones. A transect-profiling approach may be used
for linear features, such as faults (see ASTM, 2006b).
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 (2006b) for
discussion of establishing a soil sampling grid.
6.1 Soil Gas Monitoring
General Information
Soil gas monitoring at a GS project refers to sampling of vapors within the unsaturated zone (i.e.,
the zone from the ground surface to the capillary fringe above the water table), or across the
ground surface, and analysis for the vapor-phase concentration of carbon dioxide. Soil gas
monitoring is a relatively common technology, used in characterization of contaminated sites and
for exploration of natural resources, including petroleum, natural gas, and precious metals.
Unsaturated-zone samples may be collected from soil gas probes. Soil flux chambers are used to
collect vapors across the ground surface. As described below, collected gas samples may be
analyzed using portable gas analyzers.
Application
Soil gas is traditionally sampled using whole air or sorbent methods. Whole air methods collect a
sample of soil gas for vapor-phase analysis. Sorbent methods collect non-polar chemicals on a
sorbent material that is put in place at the site for an extended period of time. For GS projects,
EPA recommends use of whole air sampling methods because data collection and interpretation
are comparatively straightforward.
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Soil gas probes are borehole sampling devices that are driven into the unsaturated zone. The tip
of the sampling probe contains a sampling tube that runs to the surface (Figure 6-1). During
sample collection, a vacuum is applied to the sampling tube on the surface, and soil gas from the
sampled depth is collected. For GS projects, EPA recommends that soil gas probes be driven to a
depth as close to the potential leakage point as possible. In most cases, it is recommended that
soil gas probes be driven as deep as possible while remaining above the water table capillary
fringe, accounting for seasonal and long-term fluctuation. In any case, it is recommended that
soil vapor samples be collected at depths great enough to be out of the zone of influence of
atmospheric chemical concentration and temperature fluctuations; in addition, the probe should
not be terminated in a low-permeability (e.g., clay) zone. During installation, it is recommended
that the probe tip be emplaced midway within a sand pack (minimum of one foot; e.g., CalEPA,
2003). The borehole may then be grouted to the surface with hydrated bentonite or a
cement/bentonite mixture.
Flow meter
Vacuum -
gauge
Flow valve Exhaust
Gas
sample
syringe
Stainless steel "T" fitting
with chromatographic septum
Bonnet
IPA
Ground surface
Soil
Cement and
bentonite plug
Sample tubing
Filter sand
Soil gas sampling
probe point (dedicated)
Figure 6-1. Schematic of a soil gas sampling system (adapted from Wilson et al., 1995; not to scale).
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Prior to sample collection from a soil gas probe, the probe is purged, similar to ground water
monitoring wells (see Section 4.3). Purge tests are conducted on each typical lithologic unit into
which soil vapor probes are installed to determine the appropriate purge volume (CalEPA, 2003).
In general, it is recommended that purging and sampling rates not be greater than 100 to 200 mL
per minute. Leakage of surface air through the borehole during sampling, and concomitant
sample dilution, is of potential concern during sample collection. During sampling, a leakage test
may be conducted by placing a tracer compound, such as isopropyl alcohol, at the surface. A
leakage test sample would then be analyzed using appropriate analytical methods for detection of
the tracer. Samples may be collected in reusable containers, such as glass syringes, as long as
appropriate decontamination procedures are adhered to between sample collections. Samples
may be analyzed in the field for carbon dioxide using a standard handheld gas analyzer, such as a
portable infrared detector. The portable analyzer should be calibrated regularly to a gas standard
according to manufacturer specifications.
Soil flux chambers, also referred to as accumulation chambers, are installed at the ground
surface and are used to measure the flow and composition of gases at the soil surface (Figure
6-2). The chamber is swept by injection of a carrier gas, and the resulting mixture is collected for
analysis (ASTM, 2006b). The flux of carbon dioxide out of the soil surface into surface air may
be calculated if flow rates of the injected gas are known. Compared to soil gas probes, soil flux
chambers are more limited in their ability to detect carbon dioxide leakage. Samples are diluted
by use of the carrier gas, decreasing method sensitivity. Vapor flux from deeper zones near the
USDW to the soil surface may be reduced due to soil characteristics such as high water
saturation and the presence of low permeability lenses. However, the use of soil flux chambers
may be preferred because borehole installation is not necessary, and equipment may be reused at
several sites. The use of soil flux chambers may also be complementary to soil gas probes;
whereas probes identify a zone of leakage, chambers may be used to estimate the flow and
composition at the surface. Additional information regarding soil flux chambers that pertains to
quantification of leakage rates is available in the Subpart RR General TSD (USEPA, 2010).
Interpretation
Subsurface gases are relatively less affected by surface environmental forces (e.g., atmospheric
dispersion) and associated dilution. Therefore, monitoring soil gas concentrations of carbon
dioxide may be preferable over surface air monitoring for early detection of leakage. It is
recommended that carbon dioxide concentrations observed in soil gas measurements be
compared to background levels to identify potential anomalies that may be indicative of leakage
of carbon dioxide from the intended storage formations and possible USDW contamination.
Background soil carbon dioxide fluxes, concentrations, and isotopic compositions show large
variations and are dependent on exchange with the atmosphere, organic matter decay, uptake by
plants, root respiration, deep degassing, release from ground water due to depressurization, and
microbial activities (Oldenburg and Lewicki, 2004). Therefore, EPA recommends that baseline
studies be carried out prior to injection of carbon dioxide to characterize the background spatial
trends and variability.
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Sample collection-
and analysis
Carrier gas
On/off flow
control
Grab sample
port
Plexiglass
Figure 6-2. Schematic of a soil flux chamber (adapted from ASTM, 2006b; not to scale).
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Such studies would include repetitive measurements over time taken at several fixed
representative sites to capture diurnal to seasonal variations (Oldenburg et al., 2003). EPA
particularly recommends that such monitoring include areas with geologic and artificial
structures (e.g., faults, artificial penetrations) that may potentially create conduits for migration
to occur. During these measurements, soil temperature and moisture are recommended to be
monitored along with the collection of records of atmospheric temperature, pressure, and wind
speed and direction measured at a weather station. Modeling of soil fluxes may be used to
support a determination of background levels. Ideally, robust (e.g., multi-year) pre-injection
background carbon dioxide data will be available from the locations monitored during the life of
the GS project. Importantly, collected gas composition data using different methods (e.g.,
different types of soil gas probes, different depths) are not directly comparable. If pre-injection
data are not available, local soil gas data collected outside of the region of influence of the
project may be used for comparison. Identification and quantification of leakage is also an
integral part of the Subpart RR requirements and more information can be found in the Subpart
RR General TSD (USEPA, 2010). See also the UIC Program Class VI Well Site
Characterization Guidance for additional information on collecting baseline data.
It is recommended that seasonal fluctuations in background levels be considered during this
comparison. If a sampling grid has been established, data collected during a sampling event may
be plotted on a site map and contoured. Sampling locations with the greatest carbon dioxide
concentrations may be in the vicinity of a migration pathway. However, migration pathways may
be circuitous within the subsurface, in which case it may not be straightforward to determine the
migration source strictly from soil gas data. Furthermore, non-point sources may result in large
carbon dioxide plumes in soil gas without a discernible central location. If soil gas data indicate
potential migration, USDWs in the vicinity may be monitored for any geochemical changes and
impairment.
Multi-level soil vapor data collection points are typically necessary to provide the basis for
making three-dimensional interpretations (i.e., lateral and vertical extent) of carbon dioxide
concentrations in soil gas. Like other monitoring techniques, data are usually interpreted and
cross-referenced with cross-sections, stratigraphy, and regional geologic information to help
constrain the most logical interpretation of the data.
Reporting and Evaluation
If soil gas monitoring is required by the UIC Program Director, results must be submitted in the
semi-annual reports [40 CFR 146.91(a)(7)]. Additionally, any release of carbon dioxide to the
atmosphere or biosphere detected through soil gas monitoring must be reported within 24 hours,
pursuant to the Class VI Rule requirements at 40 CFR 146.91(c)(5). EPA recommends that
submittals in the semi-annual reports include the following:
Records, schematics, and technical justification for all soil gas probe or soil flux chamber
equipment installation.
Date and time of measurements.
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Description of existing areas of geologic and artificial structures that are potential
conduits for carbon dioxide migration.
A database of all available soil gas data from each sampling location and depth, including
any background data and QA/QC samples.
Soil and air temperatures and pressure, if required.
Interpretive maps and/or graphs of carbon dioxide trends.
Records of the calibration of any analytical equipment, including handheld portable gas
analyzers.
Records of all field activities, including vacuum-volume purge tests, sample probe
purging and sampling rates.
6.2 Surface Air Monitoring
General Information
Surface air above the GS project may be analyzed for elevated levels of carbon dioxide.
Collection and analysis of surface air samples is relatively straightforward. Similar to soil gas
sampling, EPA recommends that collected data be compared to background levels in order to
assess leakage [40 CFR 146.90(h)(2)]. Surface air monitoring is complicated by other carbon
dioxide sources, including soil and vegetation, industrial processes, and surface carbon dioxide
delivery and processing equipment. Additionally, the atmosphere is well mixed, and the leakage
signals may be diluted such that they cannot be detected (USDOE NETL, 2009a). As with soil
flux chambers, carbon dioxide leaking through USDWs may not emanate at appreciable rates to
the surface due to retardation in the unsaturated zone. For these reasons, surface air monitoring
will likely only be useful for detecting large point-source leaks. Surface air monitoring, however,
may be required by other state or federal regulations, including Subpart RR. The Subpart RR
General TSD (USEPA, 2010) discusses surface air monitoring techniques as they pertain to
quantification of leakage from a GS project.
Application
The simplest application of surface air monitoring is the use of portable or stationary carbon
dioxide detectors. Infrared detectors, also used for soil gas sampling (Section 6.1), may be used
for field-analysis of surface air. Stationary monitors may be used to continuously collect and
record ambient carbon dioxide concentrations. Handheld portable analyzers may be used to spot
check carbon dioxide concentrations at given times. Alternatively, sampling devices may be left
at the surface to collect air samples over a given time, such as a 24-hour interval (e.g., Summa
canisters).
Advanced leak detection systems, often used along pipelines, consist of a portable gas analyzer
mounted to a global positioning system (GPS)-referenced ground or airborne vehicle. The
Subpart RR General TSD (USEPA, 2010) further discusses carbon dioxide detectors, including
detection of tracers and carbon dioxide measurements.
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Eddy covariance towers may be used to monitor carbon dioxide concentrations at a height
above the ground surface. These towers use an infrared gas analyzer to continuously monitor
carbon dioxide concentrations. They also use additional equipment to measure wind velocity,
relative humidity, and temperature. Primarily, these towers would be used to detect carbon
dioxide flux of large areas in real time (USDOE NETL, 2009a). Interpretation of atmospheric
data from eddy covariance towers requires significant data processing and may be complicated
by local weather patterns and precipitation.
Interpretation
EPA recommends that measured carbon dioxide concentrations in surface air be compared to
locally collected background data. The average carbon dioxide concentration in surface air is
currently 0.038 percent (NOAA, 2011), though local background concentrations do vary. Carbon
dioxide levels that are significantly higher than background levels may be indicative of leakage.
However, for reasons discussed above, surface air data is not ideal for detecting the source or
location of leakage that may impact a USDW. If carbon dioxide leakage is suspected based on
surface air data, additional monitoring may need to be conducted in order to elucidate the source
of the leak and assess any impairment of USDWs. This may involve further sampling using soil
gas probes and ground water monitoring within surficial USDWs.
Reporting and Evaluation
If surface air monitoring is required by the UIC Program Director, results must be submitted
electronically in the semi-annual reports [40 CFR 146.91(a)(7)]. Additionally, any release of
carbon dioxide to the atmosphere or biosphere detected through surface air monitoring must be
reported within 24 hours, pursuant to the Class VI Rule requirements at 40 CFR 146.91(c)(5).
EPA recommends that submittals in the semi-annual reports include the following:
Records and technical justification of the location and time intervals of all surface air
sampling.
A database of all available surface air data from each sampling location, including any
background data and QA/QC samples.
Interpretive maps and/or graphs of carbon dioxide trends.
Records of the calibration of any analytical equipment, including gas analyzers.
Records of all field activities.
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Appendix: Testing and Monitoring Case Studies
GS is an emerging technology and, as of the writing of this document, few commercial-scale
projects have begun operation. However, numerous field-scale pilot projects have been initiated
in the United States and internationally. One objective of these projects has been testing and
evaluation of different monitoring techniques. EPA believes that learning from early projects
will be integral to developing effective testing and monitoring programs and protecting USDWs.
The case studies presented here provide examples of the application of several of the
technologies discussed in this guidance. The reader is referred to references cited within the case
studies for further information regarding use of these techniques at the specific projects.
Importantly, the majority of the projects discussed here are not mature commercial-scale
projects, but rather research-oriented or pilot projects. The testing and monitoring techniques
described in these case studies are provided as examples of field applications of these techniques;
Testing and Monitoring Plans for individual Class VI projects will be determined based on site-
specific considerations in communication with the UIC Program Director. As additional data are
collected from larger-scale GS projects, EPA is committed to collecting and evaluating new data
and information as a component of the Class VI Rule adaptive approach.
Case studies were selected to represent a range of project types, geographic locations, geologic
settings, and monitoring techniques, as summarized in Table A-l. Other GS projects in the
United States and other countries provide additional examples of GS monitoring techniques
applied in commercial and research settings. For example, operators of the Salt Creek EOR
project in Wyoming have used various methods to track and contain carbon dioxide leaks, and
the Mountaineer project in West Virginia (though not put into commercial-scale operation)
provides an example of a planned monitoring program for GS in the Mount Simon saline aquifer.
Interested parties are encouraged to review the available literature on these and other projects.
Table A-l. Summary of case study projects and key testing/monitoring methods used at each project.
Project
Cranfield (Mississippi)
Paradox/Aneth (Utah)
Ketzin (Germany)
Weyburn (Canada)
West Pearl Queen (New Mexico)
In Salah (Algeria)
Project Type
EOR/GS
EOR/GS
Saline aquifer
EOR/GS
Depleted oil field
Gas production
Key Technologies Employed
Seismic and electric geophysical methods,
geochemical analysis, pressure monitoring, surface
air/soil gas monitoring, tracers
Seismic and microseismic methods, soil gas
monitoring, pressure monitoring, tracers
Seismic and electric geophysical methods, pressure
monitoring, geochemical analysis, soil gas
monitoring, tracers
Seismic and microseismic methods, pressure
monitoring, geochemical analysis, process-based soil
gas monitoring
Seismic methods, pressure monitoring, tracers
Remote satellite imaging, seismic and microseismic
methods, surface air/soil gas monitoring
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I. Cranfield Oil Field
The Southeast Regional Carbon Sequestration Partnership (SECARE) is conducting a research-
oriented EOR/GS pilot project at the Cranfield oil field, located approximately 20 km east of
Natchez, Mississippi. Injection activities at the site target an 18 m thick sandstone layer in the
Upper Cretaceous Lower Tuscaloosa Formation, at a depth of 3,300 m (Hovorka et al., 2011).
The reservoir is highly heterogeneous and consists of stacked and incised channel fills. A thick
marine mudstone portion of the Middle Tuscaloosa Formation is the lowest element of a regional
confining system and is overlain by several additional confining beds. The uppermost confining
unit consists of thick mudrocks of the Paleocene Midway Formation (Hovorka, 2011). SECARB
conducted a stacked injection and monitoring test using existing wells dating from the 1960s.
Injection of carbon dioxide for the USDOE NETL Phase II stacked test began in July 2008, and,
as of early 2011, 2.5 million tons of carbon dioxide had been injected through 24 wells (Hovorka
etal., 2011; Luetal., 2012).
Monitoring activities at Cranfield have been conducted in several study areas, including a high
volume injection test (HiVIT); a "detailed area of study" (DAS) well-based monitoring test; a
geomechanical test (GMT) area near a non-transmissive fault; and a surface monitoring program
at the so-called "P-site," which includes monitoring a plugged and abandoned well, a well pad,
an open pit, and plants (Hovorka, 2011). The reservoir was characterized extensively prior to the
start of injection, and initial site characterization has been augmented by wireline logs, core
analyses of reservoir and confining intervals, hydrologic testing, and fluid sampling (Hovorka,
2011). Baseline temperature and pressure measurements were gathered in spring 2008, and
monitoring began in July 2008, after the start of injection. Pressure has been monitored
continuously in both the injection zone and a sandstone unit in the Upper Tuscaloosa Formation
that serves as a monitoring horizon above the confining zone (SECARB, 2012).
Field-wide injection began in July 2008, with a higher injection rate obtained in the HiVIT by
December 2009. Injection into the DAS occurred simultaneously. Bottomhole pressure has
remained stable since the maximum injection rate at field pressure was reached in 2011 (USDOE
NETL, 2012b). U-tube samplers were used for liquid and gas sampling from the perforated zone
of injection wells (Lu et al., 2012). During a temporary blockage of the U-tube sampler, an
alternative downhole sampler was used to collect fluid samples (Lu et al., 2012). Liquid sample
analyses included measurements of: pH, electrical conductivity, alkalinity, hydrogen sulfide,
major cations and anions, trace metals, carbon isotopes, benzene, toluene, ethylbenzene, xylenes,
VOCs, phenols, and polyaromatic hydrocarbons. Gas samples, analyzed for carbon dioxide,
methane, and carbon isotopes, were analyzed using a chromatograph equipped with FIDs and
thermal-conductivity detectors. Core samples were collected and analyzed using X-ray
diffraction to determine the mineral composition.
The carbon dioxide plume was tracked using a variety of seismic and electric geophysical
methods. Technologies used include casing-deployed crosswell ERT, continuous active source
seismic monitoring, crosswell seismic, VSP, and repeat three-dimensional surface seismic in the
HiVIT (Hovorka, 2011; Daley, 2012). Surface seismometers were also installed but, due to noise
levels, were not useful (Hovorka, 2011). Results from ERT indicated significant changes in
conductivity, likely related to replacement of brine by carbon dioxide (Hovorka et al., 2011;
USDOE NETL, 2012b). However, overall seismic monitoring varied with scale (surface versus
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VSP), which is potentially related to naturally high methane levels masking the carbon dioxide
(Daley etal., 2012).
Results from geochemical and geophysical monitoring indicated that the formation water was
methane-saturated prior to carbon dioxide injections, and carbon dioxide-water-rock reaction
appears to be minimal. The carbon isotopic ratio from gas samples suggests possible mixing
between injected and original formation gas, indicating minor carbonate dissolution during
injection. These results were further supported by the brine sampling, which indicated that brine
chemistry was largely unaltered after the start of injection (Lu et al., 2012).
A soil gas laboratory was installed at the P-site and quarterly monitoring was initiated. The
purpose of the soil-gas program was to monitor a methane anomaly (detected using a soil gas
probe) at a plugged and abandoned well that had been re-entered. A risk assessment had
previously concluded that older, abandoned wells at the site posed a significant leakage risk
(Hovorka, 2011). Spatial gas profiling from the study indicated high levels of carbon dioxide and
methane in near-surface soils; however, the study team determined that the elevated levels of
carbon dioxide were likely the result of oxidation of thermogenic methane from the deep oil and
gas reservoir and were not related to injection activity. Monitoring for carbon, hydrogen, and
noble gas tracers, as well as induced tracers (e.g., perfluorocarbons), was also used to assess any
potential carbon dioxide leakage in the near-surface (Lu, 2011).
Field tests in the HiVIT, DAS, and P-site test areas have been completed and, as of 2012, Phase
III of the Cranfield project was selected by USDOE NETL to move forward (USDOE NETL,
2012a and 2012b). The GMT efforts were initiated in fall 2009, to assess sub-fracture stress near
a non-transmissive fault; however, because of high temperatures and corrosion of the well bore
environment, the wireline failed and the test was not successful. The Phase III work will involve
refining the existing activities to determine the validity of the various technologies used, and it
incorporates a proposed 10-year monitoring program. Proposed monitoring activities include soil
gas sampling; monitoring shallow ground water; measuring carbon dioxide surface flux;
monitoring carbon dioxide plume movement using tracers; downhole well logging; and
incorporating seismic and electromagnetic techniques to detect potential leakage and monitor the
plume (USDOE NETL, 2012a). Overall, monitoring, data analysis, and outreach activities at
Cranfield are expected to continue through 2017 (USDOE NETL, 2012a).
II. Paradox/Aneth Project
Aneth Field is an active hydrocarbon production field in the Paradox Basin near Bluff, Utah. The
Southwest Regional Partnership (SWP) operates the pilot-scale Paradox/Aneth EOR/GS project
in conjunction with field operators. The targets of the carbon dioxide flood are the Desert Creek
and Ismay members of the hydrocarbon-bearing Paradox Formation, a Paleozoic carbonate
formation. The injection zone is located at a depth of approximately 1,930 m and has an average
thickness of 17 m, although the thickness is highly variable (USDOE NETL, 2009b). The Gothic
Shale and an organic-rich mud deposit (the Chimney Rock Shale) serve as upper and lower
confining zones, respectively (SWP 2008; Cheng et al., 2010). The reservoir is not strongly
faulted and the gross structure is depositional (USDOE NETL, 2009b). Aneth Field is typical of
many Western hydrocarbon fields; the site was selected to develop factors that can be used to
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identify other storage sites in the western United States as well as to develop a risk assessment
framework for such sites (SWP, 2008).
SWP began injection in August 2007, at a rate of approximately 15,000 tons per year of carbon
dioxide (Rutledge et al., 2008a). Carbon dioxide flooding for EOR has occurred in other parts of
Aneth Field since 1985, though the fate of the injected carbon dioxide was poorly understood
(Chidsey et al., 2006). Baseline studies were completed prior to the beginning of carbon dioxide
flooding in 2007 (SWP, 2008). Although the flood will last for five to eight years to maximize
potential oil recovery, monitoring by SWP only lasted for the first two years of the commercial
flood. Seismic methods were used to track the injected carbon dioxide plume. A permanent 60-
level, 96-channel geophone array was installed in a monitoring well to allow for high quality,
repeatable VSPs at low cost (Huang et al., 2008). From 2007 to 2009, one baseline and two
repeat VSP surveys were completed. Between the baseline and first repeat survey, approximately
10,500 tons of carbon dioxide had been injected (Rutledge et al., 2008a). For each survey, data
were obtained from one zero-offset and seven offset source locations. Double difference seismic
tomography, which has greater resolution capabilities, was also applied (Zhou et al., 2010;
Slaker, 2011). Results from the geophones indicated that time-lapse VSPs coupled with high
resolution migration and scattering analysis can provide reliable imaging of carbon dioxide
migration within the target formation (Huang et al., 2008).
Microseismic monitoring has also been used continuously since injection began in 2007 (Huang
et al., 2008; SWP, 2008). The 60-level geophone string used in the VSP surveys was repurposed
for microseismic monitoring. Following injection, the number of microseismic events increased,
and episodic events (magnitude -1 to 0) were detected within 22 kilometers of the geophone
string at an occurrence rate of approximately zero to 10 events per day starting in March 2008.
According to poroelastic stress models, the likely cause for the increase in seismicity was an
increase in fluid pressure within the target formation. The locations of the microseismic activity
indicate northwest/southeast fractures within the reservoir (Rutledge et al., 2008b; Plasynski et
al., 2011). In addition to the carbon dioxide plume, subsurface pressure, including annulus and
aquifer pressure, was also tracked at the site (SWP, 2008).
A tracer study using 1,3,5-naphthalene trisulfonate and 2,6-naphthalene disulfonate was
conducted at Aneth to better characterize flow patterns during waterflooding. During subsequent
carbon dioxide flooding, perfluorocarbons and propanol were also used as tracers to characterize
carbon dioxide flow. Results indicated that these tracers were effective and that various
combinations of these tracers could be used in GS applications in similar settings (Rutledge,
2010).
Soil carbon dioxide flux measurements were used to monitor for potential carbon dioxide
leakage. Instruments included an automated soil carbon dioxide flux system, a survey chamber,
and soil temperature probes. These methods were useful in determining natural background and
seasonal variation in carbon dioxide flux. Monitoring prior to and during carbon dioxide
injection did not identify any leaks (Rutledge, 2010).
For over two years, continuous self-potential measurements were applied as a supplemental
technique to measure pressure changes around the wellhead related to carbon dioxide injection.
The method involves using a non-polarizing electrode to measure naturally occurring voltages
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formed by fluid flow. The project involved installing 16 silver/silver chloride non-polarizing
electrodes at eight locations of differing distances from the wellhead. Anomalies were observed
at several injection wells, which were initially attributed to a geobattery mechanism (the
production of an electrical source current in an electrically conducive ground). While the method
detected anomalies around some production wells, for others the method was not useful and
produced poor quality data due to noise levels (Rutledge, 2010).
Field hydrothermal experiments were conducted at Aneth to understand mobilization of trace
metals related to carbon dioxide injection at the caprock-reservoir boundary. Preliminary results
from the study, which involved collecting reservoir brine samples, indicate that the pH decreased
following carbon dioxide injection, and mobilization of iron, lead, barium, zinc, and copper led
to elevated levels of these metals in reservoir fluids. Further data analysis is planned, as well as
additional experiments to evaluate barium, arsenic, and iron mobilization (Marcon et al., 2012).
III. Ketzin/CO2SINK Project
The Ketzin project, a pilot-scale project located in the German state of Brandenburg, is the first
onshore European GS project. Injection activities at the site target a 650 m deep, 80 m thick
sandstone saline aquifer in the Triassic Stuttgart Formation (Schilling et al., 2009; MIT,
2010). The first phase of the project, called CO2SINK (for "CO2 Storage by Injection into a
Natural Saline Aquifer at Ketzin"), ran from 2004 to 2010 and was supported by the European
Union. Since the end of the CC^SINK project in 2010, ongoing monitoring efforts at the site
have been supported by the German Federal Ministry for Education and Research. Carbon
dioxide injection began in June 2008, and, as of December 2011, approximately 57,000 tons of
carbon dioxide had been injected. The majority of injected carbon dioxide is 99.9 percent pure,
with the exception of 1,500 tons of a 99.7 percent carbon dioxide steam from the Schwarze
Pumpe plant, injected in spring 2011 as a sub-project (GFZ German Research Centre for
Geosciences, 2012). The monitoring program at Ketzin involves continuous temperature and
pressure monitoring in injection and monitoring wells; geophysical and geochemical monitoring;
plume tracking using surface seismic and geoelectric methods; measurements of natural carbon
dioxide flux at the surface; subsurface analyses of geology, gases, and fluids; and
microbiological monitoring.
At Ketzin, researchers have used both seismic and electrical methods to track the carbon dioxide
plume. The monitoring focus area was defined as a 1 km deep block covering a 14 km2 area
around the injection well (CC^SINK, 2010). Several types of seismic imaging were tested at the
site to determine the most appropriate method for longer-term monitoring. Baseline three-
dimensional seismic, VSP, and crosswell seismic surveys were taken prior to injection (Giese et
al., 2009). In addition, existing two-dimensional seismic data were verified with repeat surveys
(Schilling et al., 2009). Crosswell surveys made use of two new monitoring wells. All of the
preliminary seismic methods successfully imaged the target formation, though three-dimensional
seismic has proved to be more challenging in part because of the relatively small amount of
carbon dioxide injected and the heterogeneity of the reservoir (Martens et al., 2012). Seismic
monitoring results indicate that after approximately 24,250 tons had been injected (15 months
after the injection start date), the carbon dioxide plume remained concentrated around the
injection well with a lateral extent of about 300 to 400 m and an approximate thickness of 5 to 20
m (Martens et al., 2012).
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Researchers at Ketzin also used ERT to track the carbon dioxide plume. To increase repeatability
and minimize disruption to injection activities, all three boreholes at the site were equipped with
a permanent vertical electrical resistance array when they were cased. Each array has 15
electrodes spaced 10 m apart (CC^SINK, 2010). As of 2011, one baseline survey and four
follow-up surveys had been conducted. Results indicate that the ERT is sensitive to resistivity
changes caused by carbon dioxide migration within the brine-filled reservoir (Schmidt-
Hattenberger et al., 2011). The follow-up surveys yielded good lateral and vertical definition of
the plume in the regions near the borehole (CC^SINK, 2010; Schmidt-Hattenberger et al., 2011).
One of the downhole arrays is also equipped with a permanent fiber-optic downhole sensor to
provide continuous pressure measurements (Giese et al., 2009; CC^SINK, 2010).
Migration of the two sources of carbon dioxide (i.e., primary source vs. Schwarze Pumpe plant
source) were tracked via gas tracer tests using krypton and sulfur hexafluoride, as well as carbon
isotopic tracers. These methods were shown to be effective in identifying the source of carbon
dioxide and trace the velocity, behavior, and fate of the carbon dioxide in the reservoir (Martens
etal.,2012).
Long-term soil gas flux, soil moisture, and temperature measurements have been collected
monthly at 20 stations since 2005 (Zimmer et al., 2011). These measurements allow for the
detection of potential upward migration of carbon dioxide and leakage to the surface. A
comparison of baseline measurements to measurements collected since the start of injection
indicate that there has been no change in carbon dioxide soil gas flux. Available data have
allowed for an estimation of natural variability in background flux to distinguish biological
activity from leakage. The surface monitoring network was expanded in spring 2011 to include
eight permanent stations with automated soil gas samplers collecting measurements on an hourly
basis. Results from the additional monitoring stations have yet to be released (Martens et al.,
2012).
The Ketzin team has also taken measures to monitor both deep and shallow ground water at the
site. Existing studies provided background information on deep ground water properties (Forster
et al., 2006). Baseline water samples were taken from the injection formation, and three shallow
wells (35 to 55 m deep) were drilled to monitor the near-surface hydrology and to deploy
electrochemical carbon dioxide detection methods. To monitor the fluids in the injection zone,
permanent downhole gas membrane sensors have been deployed in two wells. These sensors use
a gas-permeable silicone membrane to separate dissolved gases from formation fluids. A
continuous loop of injected argon gas acts as a carrier to transport the separated gases to the
surface where they are analyzed by a portable mass spectrometer or collected for further study
(Giese et al., 2009; Zimmer et al., 2011). Researchers also monitored the microbiological
community in the injection zone to assess any impacts related to changes in the pH of the
formation fluids (Morozova et al., 2011).
IV. Weyburn Oil Field
The Weyburn project in Saskatchewan, Canada injects more than 1.8 megatonnes (Mt) of carbon
dioxide annually into the Weyburn oil field and, since 2005, in the adjacent Midale oil field, for
EOR. The target layers are the 24 m thick, 1,400 m deep hydrocarbon-bearing carbonate beds of
the Midale Formation, which are sealed by numerous thick shales (Wilson and Monea, 2004;
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Riding and Rochelle, 2005). Regional investigations were conducted over a 200 km by 200 km
by 4 km deep block centered on Weyburn Field, while more detailed studies were focused on an
area extending 10 km beyond the limits of the planned carbon dioxide flood. Baseline
monitoring began in 2000 prior to injection. Since 2000, over 16 Mt of carbon dioxide have been
injected at the site (Romanak et al., 2012). While injection is ongoing, the research phase of the
project is nearing completion. A report on the first phase (2000-2004) of research activities at the
site was issued in 2004 and a report on the research activities of the second and final phase
(2005-2011) is scheduled for publication in 2012. The final report is expected to contain
recommendations for monitoring technologies and deployments in EOR fields.
Researchers at Weyburn have successfully used time-lapse three-dimensional surface seismic
profiling to image the injected carbon dioxide plume (Wilson and Monea, 2004) even though the
thickness of the reservoir is at the limit for seismic resolution and the total injection volume was
initially small (approximately 2,500 tonnes). Although plume extent could be accurately detected
at relatively low saturations, results also suggested that quantitative estimation of plume volume
will be considerably more difficult (IEA, 2006). The time-lapse seismic surveys using shear
wave splitting showed the potential for imaging mineral dissolution and precipitation along
fracture networks, which influenced carbon dioxide distribution within the reservoir (Wilson and
Monea, 2004). Along with other monitoring efforts, seismic results indicated that the plume
distribution was most strongly influenced by the geologic features (e.g., faults, fractures,
porosity) of the reservoir (Wilson and Monea, 2004).
The carbon dioxide plume was also tracked using isotopic and geochemical methods. Produced
fluid with the greatest isotopic anomalies corresponded to regions with the highest injection
volume (Wilson and Monea, 2004). A geochemical baseline survey was conducted in 2000, and
sampling of reservoir fluid every four months from the same 40 wells continued for the next four
years. Fluids were analyzed for total alkalinity, pH, calcium, magnesium, resistivity, chlorine,
sulfate, aluminum, barium, beryllium, chromium, iron, arsenic, copper, nickel, and zinc (Wilson
and Monea, 2004). Samples were also analyzed for the following dissolved gases: carbon
monoxide, carbon dioxide, helium, hydrogen, hydrogen sulfide, methane, neon, nitrogen, and
oxygen. Results from the geochemical sampling program indicated dissolution trapping of the
carbon dioxide within reservoir brines and the dissolution of reservoir carbonates. Due to the
lengthy reaction time, geochemical sampling could not confirm mineral trapping
(Czernichowski-Lauriol, 2006). Metal concentrations were difficult to interpret. Concentrations
of aluminum, barium, beryllium, chromium, and iron increased over the sampling period, but
arsenic, copper, nickel, and zinc concentrations fell. These trends have not yet been explained.
Good correlation was observed between seismic anomalies, geochemical changes, and areas of
the field undergoing the most intense injection (Wilson and Monea, 2004).
Monitoring at Weyburn also includes a passive microseismic monitoring array. Seismic events
detected during the monitoring period ranged from -4 to -1 in magnitude (Wilson and Monea,
2004). Such events are similar to or smaller in magnitude than events detected during periods of
pure waterflooding. Monitoring also indicated that seismic events within the field area were
more closely related to production activities than injection (Wilson and Monea, 2004). In
addition to passive seismic monitoring, downhole pressure measurements collected regularly as
part of production activities from a sparse subset of production wells were also used to track
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subsurface pressure. Data were plotted and contoured to create a map of the reservoir pressure
field (Wilson and Monea, 2004).
In addition, targeted monitoring and testing were deployed in response to allegations of a carbon
dioxide leak at a nearby farm. The farm owners were concerned that there had been a carbon
dioxide leak to the surface, based on soil carbon dioxide concentrations and carbon isotope
testing (see Petro-Find GeoChem Ltd., 2010). Project operators responded that the injected
carbon dioxide isotopic signature was not unique from other, natural sources and that levels of
carbon dioxide in the soil were consistent with widely accepted levels for natural settings
(PTRC, 2011). The operators and environmental research group ZPAC-CO2 Research, Inc.
agreed to conduct a full investigation on the site consisting of soil gas analysis, noble gas
analysis, and hydrogeologic mapping.
Since baseline data had not been collected at the farm site, the methodology for the study relied
on the relationships and relative abundances of selected component soil gases (carbon dioxide,
oxygen, nitrogen, argon, nitrogen, argon, C2-Cs alkenes, and methane), using a process-based
method that does not rely on baseline data. Samples were collected from purpose-built semi-
permanent monitoring wells. The results were compared to measurements in soils in similar
ecosystems and to soils above an active volcanic complex (Mt. Etna) where carbon dioxide was
known to be leaking naturally from a deep source to the surface. Additionally, carbon isotopes
were measured. All ratios suggested biogenic processes were controlling soil gas composition.
Comparison of carbon isotope composition versus carbon dioxide concentration was used since
the isotopic signature of the carbon dioxide alone was not a unique indicator. This test indicated
that the isotopic composition was on a mixing line between air and biogenic processes,
suggesting leaked carbon dioxide was not needed to explain the carbon isotope abundance in
soils at the site (Sherk et al., 2011). Analysis of the alkenes was not undertaken because of the
low abundance of methane in the collected samples.
Noble gas levels were also analyzed to indicate the potential for carbon dioxide leakage from
injected reservoirs. This method was selected because tracers had not been injected with the
carbon dioxide, and carbon isotope signatures were not unambiguous. Using samples collected
from existing water, injection, and production wells, researchers were able to demonstrate that
the noble gas composition of soil gases closely approximated the noble gas concentration of the
ambient air and did not show signs of mixing with crustal-derived noble gases (Sherk et al.,
2011).
Finally, a hydrogeologic analysis of the alleged leakage site was conducted. The investigation
used soil samples gathered during the drilling of the soil gas monitoring wells as well as other
sources. This portion of the study reached three findings: the shallow ground water at the site
met Saskatchewan's Drinking Water Quality Standards during the period of sample collection,
no anomalous features were found during the investigation that could act as previously unknown
conduits for carbon dioxide movement, and films on ponds at the site were of biologic origin and
not evidence of hydrocarbon seepage (Sherk et al., 2011).
Relying on the fixed gas relationship results, the noble gas results, and the hydrogeologic
analysis, the study concluded that carbon dioxide had not leaked from the injection zone or
injection wells to the surface at the farmstead.
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V. West Pearl Queen Project
The West Pearl Queen project is a completed pilot-scale project that injected 22,090 tons of
carbon dioxide into the West Pearl Queen oil field in Hobbs, New Mexico during 2002 and 2003
(Cooper et al., 2008). Carbon dioxide was injected via a single well into a 12 m thick depleted
sandstone target formation, the Shattuck Sandstone Member of the Permian Queen Formation.
The unit, which is at a depth of 1,372 m, is overlain by dolomite and shale confining formations.
Beneath the formation is a nearly continuous blanket of caliche with varying thickness of 0 to 5
ft (Westrich et al., 2001; Wells et al., 2007).
At the site, four existing wells were repurposed for the project: one for use as an injection well
and three for monitoring. The injection well had been shut-in since 1998, and the monitoring
wells had previously been used as two produced water injection wells and one production well.
The carbon dioxide was vented from the injection well 6 months after injection was completed.
Monitoring studies were limited to a 1 square mile region surrounding the injection well.
Laboratory analyses and numerical modeling were also completed to support the field testing
program. Samples of injection zone fluids were taken 6 months post injection as well as during
the carbon dioxide venting process. In addition to sample collection, the volume of produced
fluid during venting was also recorded (Pawar et al., 2006).
Researchers used tracer additions and seismic methods to track the carbon dioxide plume. Three
unique perfluorocarbon tracers were co-injected sequentially with the carbon dioxide as 12 hour
slugs at one-week intervals (Wilson et al., 2005; Myers et al., in press). Following injection, 40
capillary adsorption tube samplers were deployed in a radial pattern surrounding the injection
well to monitor soil gas. The capillary adsorption tube samplers were collected and redeployed
several times. To avoid sample contamination (which could inadvertently lead to a false positive
identification of a tracer), the injection team and the sampling team were based 130 km apart,
and the teams avoided visiting the site on the same day (Myers et al., in press).
Within a few days of injection, tracers were detected at sampling locations at a depth of
approximately 2 m, 50 m away from the injection well. The tracers were detected for several
years after venting, indicating that injected carbon dioxide continuously escaped from the
injection zone. The volume of leakage was estimated to be 0.0085 percent of the total amount of
carbon dioxide sequestered per year (Wilson et al., 2005; Wells et al., 2007). Although many
leakage pathways are possible, investigation targeted leakage along the injection well casing as
the most likely leakage path given the timing, amount, and distribution of the detected carbon
dioxide (Wells et al., 2007; Wilson et al., 2010). P-wave images from seismic surveying
identified a pool of carbon dioxide near the base of the injection well, but detection capabilities
were not strong enough to detect the carbon dioxide leak discovered through tracer methods
(Pawar et al., 2006). Importantly, only the P-wave data were analyzed; further analysis of the
seismic images may help elucidate changes in seismic data related to injection (Cooper et al.,
2008). Remote sensing and ground-penetrating radar were also used in conjunction with tracers
to determine possible leakage pathways. These methods found fractures and faults in the caliche
beneath the injection area and northwest of the injection well, which may have facilitated
leakage. Thin (less than 1 ft) areas of caliche may have also contributed to leakage southwest of
the injection well. Another potential tracer transport mechanism is atmospheric transport, though
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the locations of tracer leakage could not be explained by this route of transport (Wilson et al.,
2005).
Researchers also monitored injection zone pressure at the site. Following the injection phase, a
downhole pressure sampler was deployed at the bottom of the injection well. Pressure
measurements were taken intermittently over a six-month period (Pawar et al., 2006). For the
first month after shut-in, pressure readings decreased, suggesting that the formation was
accommodating the injected carbon dioxide (Wells et al., 2007). After 30 days, equilibrium
pressure was reached. The equilibrium pressure was much higher than modeled predictions
(Pawar et al., 2006). A post-test assessment of the geology of West Pearl Queen was undertaken
to better understand what factors contributed to higher-than-expected injection pressures leading
to lower carbon dioxide injection rates. Research from this study indicated that the poor
interconnectivity between individual component beds of the Shattuck reservoir sandstones, as
well as heterogeneities in the formation (e.g., channels, thrust fault, facies changes, and local bed
thickenings), were contributors (Cooper et al., 2008).
Carbon dioxide plume monitoring was also conducted via geophysical methods. A baseline
three-dimensional seismic survey was followed with a repeat survey six months after injection
(just prior to venting) to image the carbon dioxide plume (Pawar et al., 2006). Microseismic
monitoring was also deployed at the site; no significant microseismic events were detected. The
migration of injected fluids between wells through the heterogeneous injection zone was found
to be incorrectly predicted by preliminary modeling. The localization of injected carbon dioxide
at the base of the injection well and a delay between injection and arrival at the nearby injection
well were also observed; injectate took three years to arrive at a monitoring well only 0.25 miles
away from the injection well (Cooper et al., 2008).
VI. In Salah Natural Gas Fields
The In Salah project is a commercial-scale GS project centered on a group of active natural gas
production fields at Krechba, in central Algeria. Carbon dioxide is separated from produced gas
to meet market requirements for natural gas purity. The carbon dioxide stream (which is
approximately 98 percent pure carbon dioxide) is being re-injected to meet the operator's
environmental sustainability standards (BP, 2008; Wright, 2007). The target formation is a
heterogeneous, low-permeability sandstone that is approximately 20 m thick and 1,800 m deep
(Wright, 2007). The sandstone is part of a gas-containing anticline, and the carbon dioxide is
injected through three horizontal injection wells (BP, 2008).The purpose of the project is to
inject up to 1 Mt of carbon dioxide per year, beginning in 2004, while testing and developing
techniques to demonstrate verifiable carbon dioxide sequestration in conjunction with
commercial natural gas production (BP, 2008; Michael et al., 2009; Riddiford et al., 2004).
Monitoring activities at the site are overseen by a Joint Industry Project (IIP), an international
effort supported by joint venture partners BP, Sonatrach, and Statoil, as well as USDOE and the
European Union Directorate General for Research and Innovation. A monitoring plan for the
project was developed based on a cost-benefit assessment of monitoring options; this assessment
was refined after initial testing and a quantitative risk assessment was completed after four years
of injection and monitoring to further update the project's development plan (Wright et al.,
2010). Leakage from legacy wells in the production field was identified as the highest risk for
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leakage out of the target formation. IIP monitoring activities are organized into phases, with
Phase I completed in 2010. During Phase II, monitoring techniques that were proven to be
effective during Phase I will be implemented on a routine basis by the operators, while IIP
efforts will focus on emerging technologies and improved modeling techniques (ISG, 2010).
Remote satellite imaging of surface deformation is one of the technologies used to track the
plume at In Salah. Investigations focus on a 25 km by 8 km area defined by both the gas leg and
the immediately underlying aquifer section of the reservoir anticline. During the initial planning
phase, researchers expected that satellite tracking would be of little use at In Salah because of the
depth and thinness of the target formation. However, modeling conducted by Lawrence Berkeley
National Laboratory (LBNL) using the TOUGH-FLAC simulator for multi-phase fluid flow and
geomechanics, indicated that injection at the site could potentially result in several centimeters of
surface elevation change (Vasco et al., 2008; Rutqvist et al., 2010). Results of this magnitude are
sufficient for satellite monitoring. The site is also ideally suited for satellite monitoring because
site is remote and the land surface is hard and has little vegetation. Between 2004 and 2007, 17
passes were made to collect satellite data. As of 2008, data collection was ongoing at a rate of
one image every 26 days, with a pixel size of 3 square meters (Mathieson et al., 2008).
Satellite images show an excellent correlation between areas of injection and uplift. Elevation
increases of up to approximately 20-25 mm were observed near the injectors, enough for
successful imaging. There is also good correlation between areas of extraction and subsidence.
The images indicate a northwest/southeast elongating plume, which mirrors the orientation of
fracturing in the injection zone (Mathieson et al., 2008). Satellite imaging also alerted site
operators to rapid migration of the carbon dioxide plume toward a suspended appraisal well at
the site. Later monitoring at the suspended well revealed that some carbon dioxide was reaching
the surface, and more detailed investigations led to the detection of a previously uncharacterized
fracture near the well (Ringrose et al., 2009; Statoil, 2009). Tracers co-injected with the carbon
dioxide were used to verify that the leaking carbon dioxide at the abandoned well originated
from a nearby injector (Ringrose et al., 2009). Subsequently, the leaking well was permanently
sealed and abandoned, closing the communication pathway that remained following suspension
of the well.
Three-dimensional seismic surveys are also considered an important technology in the In Salah
monitoring plan and are used to help track the spread of the carbon dioxide plume (Wright,
2006). A baseline seismic survey was conducted in 1997, and a repeat survey was conducted in
2009 in the northern part of the field (BP, 2008). Data from the repeat survey were not yet
available when this document was developed. An array of downhole three-component geophones
has also been deployed at one well for microseismic monitoring. This monitoring began in
August 2009 and very low levels of microseismic events (zero to one events per day) were
recorded until mid-2010, when the frequency of events increased. Daley et al. (2012) concluded
that these preliminary results were sufficient to warrant further investment in microseismic
monitoring at the site. In addition, to track subsurface pressure, the active injection and
production wells are continually monitored for pressure at the wellhead (ISG, 2009). Ground
water is monitored by pumping and sampling of six dedicated shallow aquifer monitoring wells.
Near-surface soil/air monitoring has also been conducted at In Salah. Initial baseline soil gas
measurements were taken in 2004, and a second round of measurements was taken in 2009
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(Jones et al., 2011). During this second study, surface gas measurements were taken in March
2009 using a vehicle-mounted open-path laser system. Researchers also collected soil gas
samples for laboratory analysis and made in situ soil gas measurements with instruments that
used IR analyzers for carbon dioxide. Carbon dioxide flux measurements were also made at this
time, and buried probes were deployed to collect data on radon, which may act as a natural
tracer. Additional measurements were made in November 2009, in support of a baseline study of
biological activity. The surface air and soil gas results were affected by poorly constrained
natural (diurnal and seasonal) variations and interference from dust, vehicle exhaust, and other
factors. The only clearly anomalous values were found around the abandoned well described
above, due to the previous leak at the site (Jones et al., 2011).
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