Technologies Available to Address 

Induced Faults and Fractures: 

Considerations for GS Sites
Office of Water (4606M) 

EPA 816-R-10-018 

November 2010 

http://water.epa.gov/drink/
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1. Introduction 

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

Dioxide Geologic Sequestration (GS) Wells, referred to in this document as the Class VI rule, are 

designed to ensure successful confinement of injected carbon dioxide for the purpose of 

protecting underground sources of drinking water (USDWs) from endangerment by addressing 

the pathways by which injection operations can impact USDWs. Transmissive fractures and 

faults with sufficient permeability and vertical extent in the area of review (AoR) of an injection 

well for carbon dioxide may be conduits for fluid movement (§146.81(d)). The geologic site 

characterization, siting, well construction and operation, and monitoring requirements of the 

Class VI rule are tailored to ensure USDW protection by eliminating or mitigating risks, 

including potential risks related to the presence of fractures and faults in the AoR of GS projects. 

To do this, the Class VI rule requires, at a minimum, that Class VI wells be sited in areas with a 

suitable geologic system consisting of confining zone(s) that are free of transmissive faults or 

fractures and of sufficient areal extent and integrity to contain the injected carbon dioxide stream 

and displaced formation fluids and allow injection at proposed maximum pressures and volumes 

without initiating or propagating fractures in the confining zone(s) (§146.83). Owners or 

operators are required, pursuant to requirements at §§146.82 and 146.83, to perform a detailed 

site characterization that identifies potential risks and eliminates unacceptable sites, such as sites 

containing transmissive faults or fractures. To minimize risks of inducing additional fractures or 

initiating any movement along existing faults and fractures, the Class VI rule also requires 

owners or operators of Class VI wells to ensure that injection pressure does not exceed 90 

percent of the fracture pressure of the injection zone, and in no case may injection pressure 

initiate fractures in the confining zone(s) pursuant to requirements at §146.88(a). 

While the protective measures of the Class VI rule are designed to mitigate risks and minimize 

the presence of faults and fractures in GS project AoRs, it is possible—although unlikely—that 

faults and fractures could be generated or become transmissive and become conduits for fluid 

movement as a result of injection operations. Furthermore, the movement of a carbon dioxide 

plume or pressure front may differ from the predicted AoR and intercept transmissive faults and 

fractures, or owners or operators may encounter previously-unidentified fractured systems in the 

AoR of an injection operation. Thus, it is critical to identify and determine transmissive or 

entrapping characteristics of these structures and understand possible induced changes due to 

operational conditions and/or other planned engineering activities. 

An Intergovernmental Panel on Climate Change (IPCC) report published in 2005 discusses faults 

and fractures in the context of risk assessment and remediation (IPCC, 2005). They suggest 

several operational pressure-management schemes to address leakage through faults and 

fractures. Some of these include:

• Lowering injection pressure by injecting at a lower rate or through more wells; 
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• Lowering reservoir pressure by removing water or other fluids from the storage structure; 

• Intersecting the leakage with extraction wells in the vicinity of the leak;

• Creating a hydraulic barrier by increasing the reservoir pressure upstream of the leak;

• Lowering the reservoir pressure by creating a pathway to access new compartments in the 

storage reservoir; and

• Ceasing injection to stabilize the project.

Technologies are available to treat fractures and faults to prevent leakage from occurring. 

Identifying transmissive faults and fractures and reducing their transmissive characteristics may 

prevent fluid movement between formations and allow continuation of safe injection in an 

otherwise unacceptable site. Owners or operators of Class VI wells would benefit from 

considering these technologies in developing emergency and remedial response plans or planning 

response actions. 

This paper provides background on faults and fractures and their transmissive or entrapping 

characteristics. It also summarizes techniques that have been used to treat such structures in 

different industries and which have the potential to be applied to GS operations. For a more 

detailed discussion of the process of identifying and assessing faults and fractures for the purpose 

of geologic site characterization and compliance with the regulations, please see the final Class 

VI rule and supporting guidance documents. 

2. Characterization of Faults and Fractures for Carbon Dioxide Storage

Fractures (i.e., joints and faults) are mechanical breaks in rocks across surfaces or narrow zones, 

and are common geologic features in almost all rock formations (NRC, 1996). At the carbon 

dioxide injection volumes expected in full-scale GS projects, carbon dioxide plumes and 

associated pressure fronts are anticipated to extend over distances on the order of kilometers or 

more (Pruess and Garcia, 2002). While some faults provide structural traps and permeability 

barriers by juxtaposing permeable and impermeable formations, other faults and joints may act as 

preferential pathways for fluid flow. Therefore, fractures within the AoR should be characterized 

and identified carefully to assess their transmissive potential. This is required at 

§146.82(a)(3)(ii). The potential for fractures or faults to transmit fluids or carbon dioxide 

depends upon their hydraulic properties. These properties are based on their formation, 

distribution, geometry, surface features, and relationship with the surrounding system. 

The term fracture applies to a range of generic discontinuities. However, different kinds of 

fractures have different geometries, mechanical effects, and flow properties. Based on the 

configuration and whether there has been displacement, fractures can be classified into three 

basic groups: (1) dilatant fractures/joints, (2) contraction/compaction fractures; and (3) shear 

fractures/faults (NRC, 1996). 
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2.1. Dilatant Fractures (Joints)

Dilatant fractures, also known as joints, refer to two rough surfaces with a discontinuity 

between them created by a movement normal to the joint surface (Figure 1). The fracture 

permeability controlling fluid flow through a single joint is controlled by a dynamic 

parameter called the hydraulic aperture, which is related to the mechanical aperture of the 

fracture. The measured or determined values for apertures from natural fractures at outcrops, 

in boreholes, in in-situ well tests, and tracer tests range from a few hundred micrometers to 

several millimeters (Aydin, 2000). Joint networks are limited within brittle units but can be 

effective flow pathways. The most effective elements in a joint network are joint zones, 

which can increase the aperture, vertical and lateral connectivity of fractures, and produce 

longer and taller conduits for fluid migration in response to a small magnitude of shearing. 

Joints consist of three subgroups based on their generation, geometry, and contribution to 

fluid transport: 

• Hydrofractures: Natural hydrofractures are formed in an environment with high fluid 

pressure and may be vertical or horizontal. High fluid pressure and shearing would 

open dilatant fractures at all depths. These fractures are found to be the main 

contributor of hydrocarbon migration and flow in vertical and lateral directions in the 

Uinta Basin in the western United States. 

• Tectonic joint networks: These are the most common joint networks in the upper 

crust, where a large number of subparallel joints in brittle rock units form due to 

crustal and local tectonic driving forces. In stratified systems, their contribution to 

vertical flow is limited due to their strata-bound nature. However this limitation 

should be verified through a careful assessment of the formations within the AoR. 

• Thermal or desiccation joints: Thermal fractures form due to differential volume 

decrease depending on either cooling or drying caused by uplift and erosion of the 

crust. The joint spacing in this type of fracture system depends on the local rate of 

temperature change, which in most cases depends on the flow field in the system. An 

increase in temperature can lead to local reductions in fracture permeability due to 

rock and fluid expansion, whereas cooling can result in undesired transmissive 

fracturing. 
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Figure 1. (a) A fracture zone; and (b) Three modes of fracture formation resulting in various 

types of fractures classified based on the prominent displacement (Aydin, 2000). 

2.2. Contraction/Compaction Fractures 

Contraction or compaction fractures occur due to localization of contractional strain within 

tabular zones. The predominant movement is opposite that of dilating fractures such that the 

fracture walls move towards each other. These structures include pressure solution surfaces 

which usually contain clayey seams. These seams are commonly less permeable than the host 

rock in the direction normal to the solution surface, which may limit their contribution to 

fluid migration. However, if these types of fractures are subject to high fluid pressure, such as 

in the case of carbon dioxide injection, or shearing, they may contribute to in-plane migration 

of fluids (Aydin, 2000; NRC, 1996). 

Contraction or compaction bands are also commonly found in porous rocks and are similar to 

pressure solution structures. These bands have lower porosity and permeability, so they retard 

fluid migration in the direction perpendicular to the bands. The amount of retardation 

depends on the thickness and density of the bands (Aydin, 2000; NRC, 1996). 

2.3. Faults (Shear Fractures)

Faults are defined as surfaces or zones of rock fractures along which there has been 

displacement (§146.3). Fault blocks predominantly move along the plane or zone of the 

discontinuity resulting either in dilation or contraction within the fault zone (Figure 1). 
5 

Faults have complex architectures that may enhance and/or impede migration and flow in the 

subsurface. They may influence flow in different ways: by modifying the flow path by 

juxtaposing stratigraphically distinct permeable or impermeable units; by acting as a 

membrane to retard the movement of fluids between permeable units on either side of the 

fault due to differences in petrophysical properties; or by providing a conduit for vertical flow 

along the fault (Manzocchi et al., 2010). A limited review of literature suggests that there are 

at least four categories of fault behavior associated with fluid transmission (Aydin, 2000). 

These include: (1) transmitting faults; (2) sealing faults; (3) vertically transmitting and 

laterally sealing faults; and (4) faults sealing or transmitting intermittently. Three 

fundamental elements of faults – juxtaposition, rock types, and the surrounding damage zone 

– would impact the fluid migration. The difference between joints and faults is the 

juxtaposition of different horizons and the occurrence of fault rock (Aydin, 2000). 

2.3.1. Juxtaposition 

Allan diagrams (fault surface projection maps that trace the stratigraphic units where they 

are truncated against a fault), are used to visualize juxtaposition geometry across a fault 

surface. These diagrams are useful in determining the possible migration pathways in a 

fault zone or identifying a permeable bed that is sealed by impermeable units across the 

fault. Although these diagrams represent the fault surface in two-dimensions, fault zones 

are composed of a finite thickness of variably deformed rock and may locally comprise 

several such zones, each of which accommodates a proportion of the displacement 

represented in an Allan diagram (Figure 2) (Aydin, 2000; Groshong, 2006). 

Figure 2. Example of an Allan diagram illustrating the juxtaposition and fault seal types 

likely on a single fault (Knipe et al., 1998). 
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2.3.2. Fault Rock and Damage zone 

The structure and composition of fault zones are invariably heterogeneous, and they 

exhibit diverse hydraulic properties. These hydraulic properties tend to vary with rock 

type and fault zone development (NRC, 1996). Deformation bands or shear bands in 

porous rock, such as sandstone, are formed by localization of shearing and volumetric 

strain along tabular zones and may have two to four orders of magnitude lower 

permeabilities than that of the surrounding sandstone (Aydin, 2000). Such nonconductive 

faults are referred to as sealing faults, and their sealing potential would depend on the 

capillary pressure characteristics. Fault rock associated with faulting in multi-layered 

brittle/ductile systems, such as shale or salt formations, may also produce a lower 

permeability fault core (Aydin, 2000). Conversely, in low porosity rocks such as granite, 

the permeability of fault zones tends to exceed the permeability of the host rock. Faults 

formed by shearing along joints or joint zones are always surrounded by a damage zone 

that may enhance the permeability normal to the fault plane. Thus, pull-apart openings, 

slip surfaces, breccia zones (zones of grinding action between two fault blocks where

subsequent cementation occurs), and the associated joint system in brittle rocks may 

become conduits for fluid migration depending on the hydraulic properties such as 

porosity within the fault zone, fault thickness, and particle size distribution.

2.3.3. Other parameters important for fluid migration

Additional factors that may affect fluid migration are slip, cementation, present stress 

state, and time. Depending upon the faulting processes, the magnitude of slip across the 

fault may have a direct effect on fault permeability because it would directly affect the 

thickness of the fault and tightness in the fault zone. Similarly, cementation by mineral 

deposits in open space within fault zones may affect the permeability of the fault. The 

hydraulic properties of a fault zone are related to the stress field surrounding the zone. 

Whereas high fracture/fault-normal stress may reduce aperture and inhibit fluid flow, high 

fracture/fault-parallel stress may increase the probability that the faults stay open and 

enhance fluid migration. As discussed in the hydrofractures section earlier, high fluid 

pressure may also open fractures/faults at any depth and facilitate fluid migration in the 

vertical and lateral directions. 

3. Mechanisms for Sealing of Fracture Systems 

Slight perturbations in temperature, pressure, and fluid chemistry can result in significant 

alterations in fracture properties (NRC, 1996). Fracture systems can be altered, based on the type 

of change and its cause, including: (1) changing stresses in the rock mass; (2) adding solid 

sealing material to fractures for grouting or propping up hydraulically-induced fractures; and (3) 

changing the distribution of solid materials in fractures though chemical reactions and 
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modifications of fracture fluids. Whereas such changes may be intentionally induced by 

engineering activities (such as the ones used in civil engineering, engineering geology, mining 

engineering, and petroleum engineering for tunnels, waste repositories, excavations, etc.), they 

also may occur in response to operations during a GS operation. The remainder of this section 

focuses on the potential use of these alteration mechanisms by Class VI well owners or operators 

and summarizes the ways in which owners or operators can induce changes to fracture systems to 

increase their confining properties or reduce their permeability. 

3.1. Changes in Effective Stress

The IPCC (2005) recommends pressure management schemes to control leakage through 

fractures and faults. These schemes are appropriate where the leakage occurs due to 

pressurized systems such as those encountered during GS operations, and they may indirectly 

affect the fracture systems. 

As previously discussed, fracture permeability is proportional to its aperture. Fracture 

propagation or increases in permeability may occur due to increased fluid pressures in the 

system. The apertures and stress-dependent properties such as frictional strength and 

permeability of natural fractures are usually considered to be highly sensitive to an increase in 

the effective stress (i.e., total stress except the pore pressure) acting normal to the fracture 

(NRC, 1996). Withdrawal of fluids from a system would reduce the fluid pressure, which 

may stop the initiation of fractures and result in an increase in effective stress. Increased 

effective stress normal to the fracture can close fractures and reduce their permeability; a 

decrease in effective stress may have the opposite effect. Therefore, closing (sealing) of 

fractures can be achieved by changes in fluid pressures. The addition or redistribution of 

loads, or changes in temperature that affect the state of stress in fractured rocks can also 

change the apertures and affect the fracture permeability (NRC, 1996).

3.2. Grouting 

Grouting has been used by numerous industries, such as civil engineering, engineering 

geology, mining engineering, and petroleum/natural gas engineering to reduce a rock mass’s 

permeability, deformability, or to increase stability. While there has not been any documented 

application of grouting associated with GS projects, the use of grouting may be applicable for 

similar purposes in a GS operation depending on the site and operational characteristics. 

The grouting process is typically accomplished by injecting a grout into fractures or pores in 

the rock mass through boreholes. The grout solidifies and prevents water or gas from moving 

out of the rock mass. Some types of grout may also reduce the deformability of the rock 

mass. The grout type, spacing of boreholes, injection pressure, reservoir pressure, subsurface 

fluid characteristics, and fracture geometry are all components of a complex system. In order 
8 

to have a successful grouting operation that produces an impermeable zone, the components 

of the system must be balanced (NRC, 1996). 

Depending on the grouting purpose, different grout types and grouting procedures can be 

used. Grouts are usually in the form of suspensions, solutions, emulsions, or melts. 

Suspensions are cement-mortar, cement, colloid-cement, cement-clay, or clay in water. Some 

admixtures (i.e., materials added in small quantities during the mixing process to modify the 

properties of grout in the fresh and/or hardened state), such as dispersants, accelerators, gasproducing agents, and lubricants, are often added to grout mixtures prior to injection 

(Buekett, 1998). Dispersants reduce flocculation of cement particles and the viscosity of thick 

grouts; thereby enhancing the penetration into fractures. Accelerators tend to shorten the set 

time for cement-based grouts, and gas-producing agents are used to offset the effect of 

shrinkage of Portland-cement based grouts. Finally, lubricants decrease the shearing 

resistance during the flow of the injected grout mixture (NRC, 1996; Henn, 1996). 

Suspension grouts used for underground applications tend to be basic. A grout comprised of 

Portland cement and water is commonly used. Mixes containing bentonite (a natural clay) are 

primarily used to reduce settling of the cement particles in the grout. When known joints, 

voids, or cavities must be filled, a sanded grout mix can be used. The addition of sand to the 

grout mix acts as a filler, reduces material costs, and helps minimize shrinkage of the 

hardened grout (Henn, 1996). 

Solutions are either of precipitation type or polymers. Most precipitation-type solutions are 

silicate solutions or lignin grouts. Polymers can be acrylamides, phenoplasts, or aminoplasts, 

which are injected in the form of monomers, or epoxies and polyester resins, in a partially 

polymerized state. The silicate solutions and the monomers have initial viscosities in the 

range of the viscosity of water. Epoxies and polyester resins have substantially higher 

viscosities, which make them difficult to inject into fractures with small apertures unless 

grout pressures are very high. In all cases, viscosity increases as the grout solidifies. Ideally, a 

grout should solidify suddenly, and the point in time at which this occurs should be 

controllable. However, a controlled solidification is rarely possible, even under laboratory 

conditions, because of the many factors affecting the process.

Polymer gels have been developed by industry for use in enhanced oil recovery (EOR)

applications that are designed to isolate producing wells from water influx due to channels 

and fractures behind the pipe and fractures in the water zone. The gels penetrate the rock 

matrix pores and the smallest fractures to completely shut off fluid flow by reducing 

permeability. The gels have been demonstrated to be strong enough to resist differential 

pressures exceeding 2,000 PSI or 13,790 kPa. These gels can be placed in the presence of 

carbon dioxide and into a wide range of pH environments (TIORCO, 2008). 
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An emulsion is a suspension of two liquids that do not mix together. An example of an 

emulsion grout is asphalt. In the emulsion, the asphalt grout is dispersed in water in colloidal 

form. After injection, the emulsion must be broken so that the asphalt can coagulate to form 

an effective grout with special chemicals injected with the emulsion for this purpose 

(Nicholson Construction Company, 2010). 

Melt refers to grouting material at its forming temperature. Asphalt grout is a good example 

of a melt. Asphalt grout is generally heated to 400° or 450° F before injection. One 

construction company has found at times that large sub-surface flows of water are difficult to 

stop by grouting with cement, soil, or chemical grouts. In these conditions, they have used an 

innovative technique known as asphalt grouting, particularly in sealing flowing bodies of 

water in subsurface rock channels (Nicholson Construction Company, 2010). 

Grouts are injected into the subsurface through boreholes, also known as grout holes, which 

are placed in specific formations (e.g., multiple parallel rows; a radial pattern) based on the 

desired outcome. An impermeable zone can be created through grouting by arranging many 

grout holes in the form of grout curtains, grout blankets, or grouted zones. Some examples of 

such applications include curtains constructed between a dam foundation and an 

impermeable or less permeable layer, or a grout curtain or grout blanket used to lengthen 

flow paths (Figure 3). Foundation excavations are rendered impermeable by similar 

arrangements, such as grout curtains, to lengthen flow paths or by implementation of a 

combination curtain-blanket to form a watertight box around an excavation. 

Figure 3. Grouting to reduce permeability in dams and reservoirs using curtains and blankets 

(NRC, 1996). 
10 

The same grouting procedures used to create an impermeable zone for dams and excavations 

can also be used to strengthen and stiffen weak or deformable fractured rock masses by filling

the openings (Figure 4). Most clay-based suspensions and precipitation solutions can only be 

used for impermeabilization. Depending on temperature, some polymers do not have 

satisfactory resistances and stiffness. On the other hand, most other chemical grouts will 

actually increase the stiffness and strength of rock masses or any ground for that matter. The 

typical procedure for rock grouting includes: injecting the grout; observing its behavior 

during injection (flow/pressure behavior) and after injection (reach, effect on rock mass 

properties); and injecting more grout through the same bore holes or new ones if necessary. 

These procedures for fracture sealing through grout holes can be employed as downward 

staging (stage grouting) or upward staging (stop grouting), as shown in Figure 5. 

Figure 4. Injecting grout through a borehole into fractures (Warner, 2004). 
11 

a.

b.

Figure 5. Procedures for fracture sealing through grout holes: (a) downward staging; and (b) 

upward staging (NRC, 1996). 

3.3. Fracture Alteration by Chemical Processes

Geometry of fracture void spaces can be altered by physicochemical processes that result 

from changes in the system due to GS operations. Also, some chemical processes are 

engineered to achieve desired fracture alteration. 

3.3.1. Swelling of Clays

Many fractured rocks contain clay in the rock matrix, argillaceous rock (i.e., clay rich 

rock) or as fillers in the fractures and pores. Exposure of the rock mass to water may lead 

to swelling of the clay minerals that, over time, results in a decrease in the void volume of 

the fractures. A number of different swelling mechanisms exist in argillaceous rocks. 

Two swelling mechanisms are mechanical swelling and physicochemical swelling. Other 

rocks such as anhydrites also swell due to exposure of fractures to water and stress relief, 

but the mechanisms differ. 

Mechanical swelling is the inverse of consolidation in that a decrease in applied stresses 

will lead to a reduction in pore pressures. Consequently, pore water will flow into the destressed, depressurized zone and cause swelling (NRC, 1996). 

When the applied stresses on soil or rock are reduced, the compressed framework of solid 

minerals will tend to expand in a pseudo-elastic manner. As the solid matter is effectively 

incompressible, the expansion will involve an increase in the pore volume. This will 

create a reduction in the pore fluid pressure. The reduction in pore pressure due to stress 

relief produces pore pressure gradients within the subsurface. As water flows to the areas 
12 

of lower pressure, the pore suction may be relieved, allowing swelling to occur (Harris, 

1996). 

Physicochemical swelling can be osmotic interparticle swelling—that is, water is 

attracted into the double-layer zone surrounding clay particles—or it can be swelling in 

which water is incorporated into the clay layers, such as occurs in smectite (NRC, 1996). 

Various ion exchange and oxidation reactions can lead to swelling behavior. 

Physiochemical swelling of clay minerals is dependent on the clay mineral type, the 

electrolyte concentration, and the nature of the cations. In general, higher electrolyte 

concentrations inhibit swelling (Harris, 1996). 

3.3.2. Precipitation 

Fractures and faults can be sealed by the precipitation of minerals. Injecting 

supersaturated, mineral-forming solutions into soil or rock formations can result in 

sealing by the in-situ growth of minerals such as gypsum, anhydrite, calcite, or barite. The 

first large-scale application of barite (BaSO4)-forming solutions was conducted to 

immobilize contaminants in the former Koenigstein uranium mine in Wismut, Germany

(Tsang and Apps, 2005). 

Naturally occurring minerals can react with solutions to dissolve, while supersaturated 

solutions can precipitate minerals. Permeability is increased when minerals are dissolved, 

and it is decreased when minerals are precipitated. 

A study of a low-permeability mudstone in the Pine Lodge Field of the Otway Basin, 

Australia was conducted to determine seal effectiveness in carbon dioxide GS (Watson et 

al., 2005). The Pine Lodge Field contains natural carbon dioxide within the Belfast 

Mudstone, a seal for many gas accumulations throughout the Otway Basin. The Pine 

Lodge carbon dioxide accumulation occurs in fractured shales and interbedded 

siltstones/sandstones. Petrological examination of the Belfast Mudstone reveals 

substantial carbon dioxide-seal rock interaction, with alteration of feldspar, clays, and 

volcanic fragments. Siderite has also precipitated within the mudstone proximal to natural 

fractures. The siderite δ3C isotopes are consistent with a magmatically derived carbon 

dioxide source. Seal capacity measurements combined with petrological evaluation show 

a correlation between seal capacity enhancement, siderite precipitation and the original 

porosity/permeability of the rock. 

3.3.3. Other Alterations Caused by Operational Conditions 

Fracture void space may be altered by changes in solid-state phase of solid grains if there 

is a significant effect on the grain density (and the volume), with accompanying changes 
13 

in porosity and permeability. An example of solid-state phase changes includes the 

transformation of aragonite, the crystalline form of calcium carbonate generally produced 

by biological processes, to calcite, the form generally found in limestones (NRC, 1996). 

For engineering projects such as GS operations, solid-state phase transitions are not 

typically utilized for sealing fractures and faults because reaction rates are very slow. 

These effects may be more significant at high temperatures resulting from in situ 

combustion methods used for enhanced oil recovery because the rate of solid-state 

transitions increases with an increase in temperature. 

4. Considerations for use of Sealing Techniques at GS Sites 

Owners or operators of Class VI wells who are planning for remedial response actions to 

address potential initiation or activation of transmissive faults and fractures and Directors 

evaluating planned procedures should consider the following: 

• Characterization of faults and fractures: While characterizing faults and fractures, 

it is important to recognize the dynamic nature of the system. Changes in the 

system should be evaluated within the time scales of interest. Slower rate changes 

may become significant in long-term time period. 

• Fluid pressure: Increases in fluid pressure, as discussed earlier, can produce 

irreversible changes in fracture properties, enhancing permeability or opening 

fractures/faults at any depth and facilitating vertical or lateral fluid migration. 

Reduction in fluid pressure induced by fluid withdrawal from a geologic system 

usually results in strengthening of the rock mass and is suggested by the IPCC 

report (2005) as a mitigating strategy in cases of leakage from an injection zone. 

However, it is also possible, but rare, that a reduction in water pressure can 

increase the effective stress sufficiently to cause failure or collapse within the rock 

structure, or may lead to borehole instability. 

• Sealing mechanism/technologies: The identification of transmissive faults and 

fractures and the reduction of their transmissive characteristics through the 

implementation of available technologies, such as grouting, may prevent fluid 

movement between formations and allow continuation of safe injection in an 

otherwise unacceptable site. However, when contemplating using these 

technologies, owners or operators of Class VI wells should consider the 

possibility of these technologies not being permanently effective. Specifically, for 

grouting, the injection pressure for grout may hydraulically fracture the rock mass 

and inadvertently worsens the condition. Furthermore, depending on the material 

used, if the grouting material does not solidify, is eroded, or leaches out after 

injection, it may create a risk of contaminating USDWs. Similar risks may be 
14 

encountered when fluids are injected to achieve chemically-induced changes in 

fracture systems. Additionally, special consideration should be given to the 

creation of an impermeable zone by grouting, or by swelling of fracture fillings 

that may result in fluid pressure increases in the systems behind these reducedpermeability zones. 

5. Conclusions 

The primary goal of the Class VI rule is to avoid siting of Class VI wells in regions with fractures 

and faults. For this reason, the Class VI rule is designed to minimize any risks associated with 

fractures and faults through tailored site characterization, operating, and monitoring 

requirements. Suitable and adequately characterized sites will help ensure the protection of 

USDWs from endangerment. However, in rare circumstances, if faults and fractures are 

generated or become transmissive, technologies exist to seal these faults and fractures. 

Although comprehensive, the list of techniques available to treat transmissive fractures and faults 

or reduce their transmissivity presented in this document is not conclusive or exhaustive, due to 

continuous technological advances in GS and related technologies. Because GS is a new 

technology, its deployment necessitates careful investigation of the applicability of these 

techniques as well as new and evolving technologies, based on site- and operation-specific 

conditions. Available technologies should be considered during project development, described 

in emergency and remedial response plans, and considered in preparing financial responsibility 

demonstrations. Owners and operators of Class VI wells should consult with the Director before 

using of any remediation technology. 
15 

6. References

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Petroleum Geology, 17:797-814, 2000. 

Buekett, J. International Admixture Standards. Cement and Concrete Composites. 20:137-140, 

1998. 

Groshong, R.H., 3-D Structural Geology, Springer Berlin Heidelberg, 2006. 

Harris, Colin S., Engineering Geology of the Channel Tunnel, Thomas Telford Publishing, 1996. 

Henn, Raymond W., Practical Guide to Grouting Underground Structures, Published by ASCE, 

1996. 

IPCC (Intergovernmental Panel on Climate Change), Chapter 5: Underground Geological 

Storage, 2005. 

Knipe, R.J., G. Jones, Q.J. Fisher, Faulting, Fault Sealing, and Fluid Flow in Hydrocarbon 

Reservoirs: An Introduction, Geological Society, London, Special Publications, 147: vii-xxi, 

1998. 

Manzocchi, T., C. Childs, and J.J. Walsh, Faults and Fault Properties in Hydrocarbon Flow 

Models, Geofluids, 10:94-113, 2010. 

National Research Council (NRC), Rock Fractures and Fluid Flow: Contemporary 

Understanding and Applications, Washington D.C., 1996. 

Nicholson Construction Company Web site: 

http://www.nicholsonconstruction.com/groundTreatment/asphaltGrouting.aspx. 2010.

Pruess, K. and J. Garcia, Multiphase Flow Dynamics during CO2 Disposal into Saline Aquifers, 

Environmental Geology, 42:282-295, 2002. 

TIORCO Web site: http://www.tiorco.com/matrixshutoff.php. 2008. 

Tsang, C.F. and J.A. Apps, Underground Injection Science and Technology 52, Chapter 25. 

Grouting with Mineral-Forming Solutions-A New Technique for Sealing Porous and Fractured 

Rock by Directed Chrystallization Processes, Elsevier, 2005. 

Watson, Maxwell N., Daniel, Richard F., Tingate, Peter R., and Gibson-Poole, Catherine M., 

CO2-Related Seal Capacity Enhancement in Mudstones: Evidence from the Pine Lodge Natural 

CO2 Accumulation, Otway Basin, Australia. CRC for Greenhouse Gas Technologies, Australian 

School of Petroleum, Adelaide University, SA 5005, Australia, 2005. 

Warner, J. Practical Handbook of Grouting: Soil, Rock, and Structures. John Wiley & Sons, Inc. 

p.320, 2004.