## Technologies Available to Address Induced Faults and Fractures: Considerations for GS SitesOffice of Water (4606M) EPA 816-R-10-018 November 2010 http://water.epa.gov/drink/1 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. T ransmissive fractures and f

aults 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 deta iled 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 c onfining 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 be come 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 struc tures 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;2 **•** Lower ing 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;

**•** Lowerin g 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 unacceptab le 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 tha t 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 r ocks 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 project s, 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 preferent ial pathways for fluid flow. Therefore, fractures within the AoR should be characterized and identified carefully to assess the ir 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).3 2.1. Dilatant Fractures (Joints)

Dilat ant 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 me asured 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 mic rometers to several millimeters (Aydin, 2000). Joint networks are limited within brittle units b ut 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 ho rizontal. 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 State s.

**•** Tectonic joint networks : These are the m ost common joint networks in the upper crust, where a large number of subparallel jo ints 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 frac turing.4 F igure 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. C ontr action/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 press ure 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 fracture s 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 ar e similar to pressure solution structures. These bands have lower porosity and permeability, so they retard fluid migration in the directi on 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). The s e include : (1) transmitting faults; (2) sealing faults; (3) vertically transmi tting 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

Al lan diagrams ( fault surface projection maps that trace the stratigraphic units where they are truncated against a fault ), are used to visua lize juxtaposition geometry across a fault surface. These diagram s 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. Al though 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 Al lan diagram (Figu re 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).6 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 surro unding sandstone (Aydin, 2000). Such nonconductive faults are referred to as sealing faults , and their seal ing 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 zone s 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 norma l 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, cem entation 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. W hereas high fracture/fault

- normal stress may reduce aper ture and inhibit fluid flow, high frac ture/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 a ny depth and facilitate fluid migration in the vertical and lateral direction s.

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 and7 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 i n 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 fractu re 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 lea kage 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 str ess. 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, su ch 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 order8 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 theproperties of grout in the fresh and/or hardened state), such as dispersants, accelerators, gasproducing agents, and lubricants, are often added to g rout 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, an d 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. Mo st 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 epox ie s and polyester resins, in a partially polymerized state. The silicate s olutions and the monomers have initial viscosities in the range of the vis cosity of water . Epox ie s and polyester resins have substantially higher viscosities, which make them difficult to inject into fractures with small apertures unless grout pressures ar e 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. H owever , a controlled solidification is rarely possible , even under labora tory conditions, because of the many factors affecting the process.

P olymer 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 fracture s 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. T hese gels can be placed in the presence of carbon dioxide and into a wide range of pH environments (TIORCO, 2008).9 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 th e 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 fo und 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 u se d an innovative technique known as asphalt grouting, particularly in sealing flowing bodies of
wat er in subsurfa ce 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. A n impermeable zone can be created through grouting by arranging many grout holes in the form of grout curtains, grout blankets, or grouted zones. Some example s 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 T he same grouting procedures used to create an impermeable zo ne 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 procedu res 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.

F igure 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 i n 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 f ractures 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 fracture s. 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 d ecrease in applied stresseswill 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 po re pressure due to stress relief produces pore pressure gradients within the subsurface . As water flows to the areas12 of lower pressure, the pore suction may be relieved, allowing sw elling 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 occu rs in smectite (NRC, 1996).
Various ion exchange and oxidation reactions can lead to swelling behavior. Physiochemical swelling of clay minerals is dependent o n 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 p recipitation 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 (BaSO 4 )-forming solutions was conducted to immobilize contaminants in the former Koenigstein uranium mine in Wismut, Germany (Tsang and Apps, 2005).
Naturally occurring minerals ca n 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 Lod ge 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 shale s and interbedded siltstone s/sandstones. Petrological examination of the Belfast Mudstone reveals substantial carbon dioxide- seal rock interaction, with alteration of feld spar, clays, and volcanic fragments. Siderite has also precipitated within the mudstone proximal to natural fractures. The siderite δ 3 C isotopes are consistent with a magmatically derived carbon dioxide source. Seal capacity measurements combined with petr ological 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 changes13 in porosity and permeability. An example of solid- state phase changes includes the transformation of aragonite, the crystalline for m 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 fracture s and faults because reaction rates are very slow. T hese 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

eva luating planned procedures should consider the following:

**•** Characterization of faults and fractures : W hile 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 : Increase s in fluid pressure, as discussed earlier, can produce irreversible changes in fracture properties , enhancing permeability or open in g fractures/faults at any depth and facilitat ing 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 case s of leakage from a n 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 preve nt 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 technologi es 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 be14 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 sw elling of fracture fillings that may result in fluid pressure increases in the systems behind these reduced

permeability 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 monito ring 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 a nd 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
Aydin, A., Fractures, Faults, and Hydrocarbon Entrapment, Migration, and Flow, Marine and 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 CO 2 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 Chrystallizatio n Processes, Elsevier, 2005. Watson, Maxwell N. , Daniel , Richard F., Tingate , Peter R., and Gibson-Poole, Catherine M. , CO 2 -Related Seal Capacity Enhancement in Mudstones: Evidence from the Pine Lodge Natural CO2 Accumulation, Otway Basin, Australia . CRC f or 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.