INTRODUCTION
Air sparging has become a popular alternative to conventional pump-and-treat methods of remediating contaminated sites during the past 20 years. It is applied by injecting air in the vicinity of contaminants in the saturated zone. As air rises through the saturated zone contaminants partition into the vapor phase and then flow into the vadose zone. Soil vapor extraction wells are typically installed above the air sparging wells to remove contaminant-laden gas from the vadose zone (Kerfoot, 1992). Another benefit of air sparging is an enhanced rate of biodegradation because oxygen partitioning from the injected air into the aqueous phase will stimulate aerobic microbes (Johnson, 1998).
The conditions conducive to successful air sparging application are limited. Air sparging is effective when used to remediate high volatility compounds, whereas it can be ineffective for remediation of low volatility compounds (Liban, 2001). Air sparging effectiveness can also be limited in low-permeability formations where air injection rates are small. The distribution of air in the subsurface may be limited by formation heterogeneity (McCray and Falta, 1996).
Laboratory investigations have shown that air flow in porous media during air sparging typical occurs through continuous channels (Ji et al, 1993). The size and spacing of channels is an important factor in the contaminant mass transfer rate from the aqueous phase to the gaseous phase. This is because the contaminant must diffuse through water to reach the phase interface at a channel (Falta, 2000).

2
Hydraulic fracturing involves pumping fluid into a geologic formation at a rate great enough to cause pressures that will initiate a fracture. Hydraulic fracturing was originally developed in the petroleum industry, and has been used for more than 60 years to stimulate the productivity of oil and gas wells (Gidley, 1989). It is possible to create hydraulic fractures by only injecting fluid; however, granular material termed proppant is typically suspended in the fracturing fluid during injection (Murdoch et al, 1994). The proppant holds the fracture open after injection is completed. A permeable proppant increases hydraulic fracture transmissivity by increasing the thickness, or aperture , of the fracture.
The beneficial effects produced using hydraulic fracturing techniques have led to environmental remediation applications (Murdoch and Slack, 2002). The ability to introduce proppants makes it possible to design hydraulic fractures for a wide variety of applications. For example, granular graphite can be used as a proppant to create diskshaped electrodes for electro-kinetic remediation systems (Murdoch, 1997). Hydraulic fractures can also be filled with reactive solids that increase the in situ degradation rate of contaminants (Murdoch and Slack, 1992). Biodegradation can also be accelerated by filling fractures with oxygen-releasing compounds or nutrients (Vesper et al, 1994b).
The most common environmental application of hydraulic fractures involves increasing well performance by using well-sorted quartz sand to create transmissive layers in low permeability formations. Quartz-sand-filled fractures typically increase well production by 1.5 to 10 times (Murdoch, 1994, Bradner, 2003), although productivity increases of up to two orders of magnitude have been observed (Vesper et al,
1994a).

Creating hydraulic fractures in air injection wells could potentially expand the applicability of air sparging to encompass low permeability materials. Hydraulic fractures have been installed in air sparging wells in a few cases; however, field tests for characterizing air sparging are limited. The effects of hydraulic fractures on sparging well performance or subsurface air flow are unclear.
3
Objective
The objective of this investigation is to develop methods for quantifying and comparing the performance of air sparging wells. These methods will be developed to characterize the effects of sand-filled hydraulic fractures on air sparging operations. Of particular interest is comparing the performance of sparging wells that intersect hydraulic fractures to the performance of conventional air sparging wells.
Approach
In order to meet the objectives of this study, a total of eight wells with screens approximately 14 m below ground surface were installed using three different completion methods. The wells are in a granitoid gneiss saprolite at the Simpson Station field site in
Pendleton, South Carolina. Three field sparging tests were developed to characterize well performance and formation properties. The three tests are all variations of a pressure step test, involving some number of injection periods at constant pressures while monitoring mass flow.
The multi-phase flow simulator T2VOC (Falta et al, 1995) was also utilized as an investigative tool during this research. Models were calibrated to Simpson Station field

conditions with PEST-ASP by reproducing field sparging test results. The calibrated models were used to characterize gas saturation patterns and sparging radius of influence of the wells at the field site. Some model parameters were then varied to characterize well performance under different formation conditions.
4

1 LITERATURE REVIEW
The success of air sparging has caused it to be an important alternative to conventional remediation methods, such as pump-and-treat and source zone excavation.
However, air sparging effectiveness is often limited when contaminants are located in formations with moderate to low permeability. Hydraulic fracturing is a technique that has been applied in the petroleum industry, and more recently in the environmental industry, to increase well performance. Hydraulic fracturing could potentially make air sparging applicable in lower permeability formations.
1.1
Sparging Overview
Air sparging was developed in Germany in the mid-1980’s, and has gained popularity as a remediation technology in other countries over the past 20 years (Liban,
2001). The process involves injecting air into wells completed in the vicinity of contaminants in the saturated zone. Water is displaced by the injected air, creating air filled pores within the saturated zone (Bass and Brown, 1997). The air rises through the saturated zone and into the vadose zone. This process has two effects that are important for remediation: 1) contaminants partition into the vapor phase, migrate upward with the air, and are either released to the atmosphere or removed from the subsurface; and 2) oxygen in the air partitions into the aqueous phase and potentially enhances the rate of aerobic biodegradation (Johnson, 1998). Air sparging is commonly used with soil vapor extraction (SVE) systems, which aid in removal of contaminate-laden gas from the vadose zone. The SVE systems are typically designed to remove air at rates that are
5

greater than those being injected into the sparge wells to ensure capture of contaminants released from the saturated zone (Kerfoot, 1992).
6
Air sparging has been used to treat both highly contaminated source areas and dilute ground water plumes (Bass and Brown, 1997). Some of the properties that make air sparging attractive are 1) an increase in mass transfer of volatile chemicals when using air; 2) sparging well installation is typically less expensive than for groundwater recovery wells (Angell, 1991); and 3) air is easier to treat than water, and often can be discharged without treatment.
Air sparging is a successful remediation technology, but it does have limitations.
Air sparging is effective when used to remediate volatile to semi-volatile compounds, but loses effectiveness as the volatility of the target contaminant diminishes (Liban, 2001).
Low-permeability formations will decrease the rate at which air can be injected.
Heterogeneities and low-permeability layers may limit the distribution of the air in the subsurface. Both of these situations will limit the volume over which remediation is effective (McCray and Falta, 1996). Air sparging performance where contaminants are dissolved in ground water tends to be better than where contaminants are strongly sorbed
(Liban, 2001).
1.1.1
Mass Transfer
The rate at which a chemical can be remediated by sparging depends on the mass transfer rate across the water-air interface. Interface mass transfer rates during air sparging are dependent on the surface area of the interface between the two phases and

the tendency of the chemical to partition between water and air (Johnson, 1993; Mohr,
1995; Acomb et al, 1996).
7
The extent to which a chemical will partition between aqueous and gaseous phases can be described by the Henry’s constant of the chemical.
H

C
C a w
(1) where C a
is concentration of the chemical in air, and C w
is the concentration of the chemical in water (Ahlfeld et al, 1994). The effect that temperature has on volatility can be described with a scaled Henry’s constant using
H '

H
RT
(2) where R is the universal gas constant, and T is the absolute temperature (Gregory and
Blanc, 2000). Chemicals with high Henry’s constants partition into the gaseous phase more readily than chemicals with low Henry’s constants, making them more suitable for air sparging.
Air flow during sparging in natural porous media tends to create preferential pathways or channels (Ji et al, 1993), instead of being dispersed uniformly through the pore space. This is important because the surface area of the interface between air and water varies with the density of flow channels. In order for a chemical to be removed by air sparging, it must cross the interface between the air and water phases. Assuming that contaminant concentrations are homogenous, removal rates will be high initially because water at the interfaces will contain contaminants. In order for contaminants that are

8 distant from the phase interface to be removed, they must diffuse through the water towards the air (Fig. 1.1-1). Diffusion rates tend to be slow compared to interface mass transfer rates at the air-water interface, so diffusion limits the rate of contaminant removal (Falta, 2000). This makes the size and spacing of air channels within porous media important factors for air sparging system efficiency, because they determine the distances that chemicals must diffuse to reach the air-water interface (Braida, 1997; Chao et al, 1998; Elder and Benson, 1999; Rogers, 2000).
Volatilization
Diffusion Path
Grains
Water
Figure 1.1-1 Conceptualization of mass transfer during air sparging.
Contaminants must diffuse towards the air-water interface, where partitioning occurs.

1.1.2
Air Flow
The injection of air into a sparging well begins with a short period of well bore pressurization, followed by a period when the water in the well bore flows out through the well screen and into the formation. The time needed to displace the water in the well is a function of the hydrostatic pressure at the top of the well screen, formation permeability, casing radius, screen length, and applied air pressure (Bouwer and Rice,
1976).
9
The next change of the sparging process involves air entering the saturated formation or gravel pack. In order for this to occur, the pressure of the injected air must exceed the sum of the pore pressure in the saturated media (hydrostatic pressure) and the air entry pressure of the material (Johnson et al, 1993). The total pressure at which air enters the formation is
P t

P h

P e
(3) where P e
is the entry pressure, and P h
is the pore pressure.
Most natural porous media are hydrophilic, so water is the wetting phase. The air-entry pressure is the excess pressure required to overcome the surface affinity for water (Scheie, 1989), and force water out of pore spaces. Air-entry pressure is a function of grain size, sorting, packing, and structure, which control the size distribution of pores
(Dullien, 1992).
Capillary pressure is a pressure differential that exists across an interface between air and water. The capillary pressure is equal to the air-entry pressure when water saturation is approximately 1

10
P e

P c

P a

P w
,when S w

1 (4) where P a
is the air pressure, and P w
is the water pressure. The capillary pressure can also be estimated under idealized conditions using
P c

2

/ r (5) where

is the surface tension between air and water, and r is the mean radius of curvature at the interface. The entry pressure of material with pore radius of 5 μm is approximately 30 kPa, according to (5) (Table 1.1-1).
Material
Coarse sand
Fine to medium sand
Silt
Silty clay
Largest pore
radius (μm)
>500
50.0
5.0
<0.5
E n t r y P r e s s u r e ( k P a )
<0.3
3
30
>300
Table 1.1-1 Entry pressure estimates for different materials, modified from Baker,
(1997).
Once the air enters the formation, flow will be a function of injection pressure in the region of continuous air-filled pores near the air source. However, air can also travel as discontinuous bubbles through porous media (Ahlfeld et al, 1994). Bubbles will rise due to buoyancy and will be unaffected by injection pressure.
Air flow at any point within the system is governed by relationships between fluid pressures, saturations, and permeabilities. Balancing the forces that drive flow and the forces that resist flow gives


  n
 t
S n
 





 n
 k n rn k


 
P n
  n g
 z




(6)
11 where

is porosity; S n
is fluid saturation; P n
is fluid pressure; k is the intrinsic permeability tensor; k rn
is the relative permeability of the fluid;
 n is the fluid viscosity; p n
is the fluid density; g is gravitational acceleration; and z is elevation. The subscript n signifies the fluid phase.
The relative permeability, k rn
, is a function of the degree of saturation. Relative permeability with respect to a given phase will tend to increase as the saturation of that phase increases. For example, hydraulic conductivity increases as water content increases (Fig. 1.1-2).
Figure 1.1-2 Hydraulic conductivity (K) as a funcion of water content (

) for Yolo light clay, from Philip (1969).

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Clayton, (1997; 1999), showed that current simulation methods might consistently overestimate the relative permeability of a given phase in natural systems under sparging conditions. He argued that during transient flow periods some air-filled channels may be available for flow, but then become unavailable for flow when channel growth is discontinued. This means that during certain times some regions may be filled with stagnant air. Using only saturations to estimate relative permeabilities in these regions would provide inaccurate results (Clayton, 1999).
Numerical modeling (Lundegard, 1993) and field studies (Lundegard and
LaBrecque, 1995; McKay and Acomb, 2000) have shown that there can be two transient periods that sparge systems go through before reaching steady state. Period 1 begins after air enters the formation and involves an increase in the size of the air-filled region in the subsurface (McKay and Acomb, 2000). As the air saturation increases, the relative permeability of the formation with respect to air becomes greater causing an increase in flow at constant injection pressure. Changes in saturation are greatest near the well and decrease with radial distance. Pore water is displaced by air, which causes mounding of the ground water table near the well. As a result, Period 1 is characterized by increasing gas saturations in the vicinity of the well and decreasing gas saturations in the overlying vadose zone. Eventually the rate of increase in the radius of the affected volume begins to slow, and Period 2 begins. During Period 2 the majority of air flow becomes vertical, and preferentially occurs near the well (Lundegard, 1993). This period is marked by a gas saturation reduction in the periphery of the affected volume, and an increase in the gas saturation in the vadose zone due to the subsidence of ground water table mounding
(Lundegard and LaBrecque, 1995).

13
This understanding of air sparging transients has allowed a few generalizations about field data interpretation. Mounding of the water table mainly occurs during the first period. Air flow rate into the well tends to increase as the first stage of transients develops. Injection pressure and flow can stabilize prior to the development of the second phase. With these processes in mind, one should use caution when utilizing mounding of the water table to predict the radius away from the well that is influenced during sparging. This is because air saturation on the periphery may tend to diminish during the second period. However, cycled air injection may inhibit the development of the second period and therefore maintain a larger region containing air (McKay and
Acomb, 2000). Also, flow and pressure stabilization are poor indicators of when the system reaches steady state. The time that it takes for pressure and flow into the well to stabilize can be 2 to 12 times less than the time that it takes the flow in the subsurface to reach steady state (Lundegard and LaBrecque, 1995).
1.1.3
Effects of Formation Properties
The injection pressure and depth of the well screen below the water table affect the flow rate, volume of the region of increased gas saturation, and flow pattern in the subsurface. However, formation properties also have a strong influence on these factors.
Some formation properties that affect air sparging performance are mean pore size and heterogeneity.
The effect that pore size has on air flow patterns in granular material has been investigated in laboratory settings. Columnar or thin rectangular, transparent containers, are used for experiments to allow saturation patterns to be observed directly.

14
Experiments have been conducted with sorted and graded natural sediments (Adams and
Reddy, 1997; Zumwalt et al, 1997; Semer et al, 1998; Peterson et al, 1999A, 1999B,
2001; Reddy and Adams, 2001), and with glass or plastic beads (Ji et al, 1993). The investigations have shown that air flow in porous, granular materials will form either continuous channels or discontinuous bubbles. Ji et al (1993) found that flow occurred in channels in regions containing fine-grained glass beads, whereas bubbles occurred in coarse-grained beads. They found that a grain size of 2mm marked the transition between the two types of flow.
Laboratory experiments (Ji et al, 1993; Chen et al, 1996) and numerical simulations (McCray and Falta, 1996; van Dijke and van der Zee, 1998) have been conducted to determine the effects of heterogeneity on air flow patterns. Heterogeneity was represented using horizontal, low permeability lenses (Fig. 1.1-3). These studies found that the presence of slight heterogeneities will produce gas saturations with asymmetrical geometries of varying shape (Ji et al, 1993; McCray and Falta, 1997). The results of these experiments suggest that air will preferentially flow in the horizontal direction when vertical flow is impeded.
The air-entry pressure of clay lenses is higher than the air-entry pressure of enveloping higher permeability sediment. Therefore, air will flow around, rather than through, low permeability materials (Johnson et al, 1993; Tomlinson et al, 2003). If this is the case, then air injected below clay lenses may have negligible effects on contaminants within or above the low-permeability material (McCray and Falta, 1996)
(Fig. 1.1-3).

a b
Figure 1.1-3 Two-dimensional air flow through glass beads with discontinuous low permeability layers: a) drawing of laboratory experiment results, from Ji et al. (1993); b) gas saturation results from numerical simulation, from McCray and Falta (1997).
15

16
1.1.4
Radius of Influence
The radius of influence of a sparging well is the average maximum radial distance away from the well that air occurs (Ahlfeld et al, 1994). This distance marks the furthest potential boundary of air occurrence, but does not necessarily mark a distance over which contaminants are remediated. Although contaminant cleanup can take place at any point within the radius of influence, and even beyond, it has been suggested that a gas saturation of 0.1 serve as a boundary for effective remediation (McCray and Falta, 1996).
One also cannot assume that contaminant removal and/or oxygenation rates will remain constant within the affected volume due to differences in the degree of air saturation
(Ahlfeld et al, 1994). The radius of influence and air flow pattern are important to the design of an air sparging system for the remediation of a contaminated site. Knowing the radius of influence allows the number, placement, and operating conditions of air sparging wells to be determined to maximize the efficiency of the sparging system
(Lundegard and LaBrecque, 1995).
Experiments in the field and lab, and the results of numerical and analytical models, have been used to characterize affected regions during air sparging. Among the techniques that have been proposed for characterizing the radius of influence are dissolved oxygen content in ground water (Lundegard and LaBrecque, 1995), measurements of pressure distributions within the saturated zone (Morton et al, 1996;
Wardwell et al, 1997) and vadose zone (Joss, 1996), ground water mounding (Brown et al, 1993), tracer gas detection within the vadose zone (Johnson et al, 1997), changes in saturated zone moisture content (McKay and Acomb, 1995; 2000), a variety of geophysical techniques (Lundegard and LaBrecque, 1995; Schima et al, 1996; Goldflam

et al, 1997), and numerical and analytical models (Hein, 1997; Philip, 1998, van Dijke and van der Zee, 1998). Pilot tests are commonly conducted to estimate the radius of influence of representative sparging wells, typically using a combination of methods
(Bruell et al, 1997).
17
Lundegard and LaBrecque (1995) compared estimates obtained from different methods to results obtained from cross-borehole electrical resistance tomography (ERT).
They assumed that electrical resistance tomography was the method that produced the most accurate results. Water table mounding was found to be transient, and appeared to be independent of actual air distribution. Other indirect measurement methods, such as the distribution of dissolved oxygen in water, soil-gas pressure, and soil-gas composition were found to give estimates for the radius of influence that were two to eight times greater than estimates made using ERT (Lundegard and LaBrecque, 1995).
McCray and Falta (1996) proposed a method using the increase in pressure created in the affected sparge zone along with a soil capillary pressure-gas saturation curve. The positive pressures are correlated to effective air saturations of 0.1 or greater to delineate the volume of the sparge zone. This method may reduce the problem of overestimating radius of influence using methods investigated by Lundegard and
LaBrecque (1995).
1.1.5
Existing Completion Techniques
Well completion techniques for most air sparging wells are similar to those used for conventional water pumping, injection, and monitoring wells (Johnson et al, 1993).
The wells typically are constructed by placing a screened casing into a borehole,

18 surrounding the screen with a high permeability filter pack, and sealing the annulus above the filter pack with grout or bentonite. Well casings are typically 2 to 5 cm in diameter.
Utilization of wells with larger diameters has shown negligible improvements in performance (Johnson et al, 1993). Sparging wells are typically vertical because this is the most common, inexpensive, and easily constructed orientation (Johnson et al, 1993).
It has been shown through electrical resistivity tomography monitoring that air enters the formation at the top of the filter pack, rather than over the length of the well screen
(Lundegard and LaBrecque, 1995). This implies that there may be little benefit to constructing an air sparging well with more than 0.3 to 0.6 m of well screen (Johnson et al, 1993).
Laboratory experiments have been conducted to investigate the use of porous diffusers, or bubblers, in place of typical slotted screens during air sparging applications.
Diffusers may increase the development of bubbly flow as opposed to channel flow by initially introducing the air as small diameter bubbles (Burns and Zhang, 2001). Bubbly flow would be beneficial to air sparging performance due to a larger air-water interface area per volume injected. However, other researchers believe that the small bubbles produced from diffusers would coalesce within several inches of the screen in natural settings, and the effect of the diffuser would be minimal (Ahlfeld et al, 1994).
1.1.6
Methods for Improving Air Sparging Efficiency
Some methods for increasing the remediation effectiveness of conventional systems by modifying the air composition have been explored. Injection of heated air or steam has proven to enhance the recovery of heavy fuel oils by decreasing the viscosity

19 and increasing the mobility of the contaminants (Dablow et al, 1997). Increases in biodegradation rates have been observed while injecting oxygen microbubbles in the form of a surfactant/gas foam (Leigh et al, 1997). Injection of surfactant has the potential to increase the development of bubbles and suppress channel development during sparging (Zhang and Burns, 2000).
The parameters that can be controlled while operating an air sparging well are the duration of injection and the injection pressure or flow rate. The injection flow rate will increase with injection pressure. Increasing flow rates can increase contaminant removal rates, but only up to a threshold rate (Adams and Reddy, 1999). However, while increasing injection flow rate one must be careful not to exceed the pressure at which the formation will fracture. The unintentional creation of fractures, especially in lowpermeability formations, may cause preferential flow paths that can limit the distribution of air (Johnson et al, 1993). It has also been shown that air sparging wells in low permeability materials operated with pulsed injection may be more efficient than those operated with constant injection, possibly because pulsing increases mixing and contaminant redistribution within the zone of influence (Kirtland and Aelion, 2000;
Heron et al, 2002).
Others have explored options for modifying the sparge well completion to enhance overall efficiency in low permeability materials. Among these techniques are horizontal wells (Basinet and Wollenberg, 1997; Kershner and Theoret, 1997; Plummer et al. 1997), belled sand columns (Maheux and McKee, 1997), gravel-filled trenches
(Brubaker et al, 1996), and emplacement of either pneumatic or hydraulic fractures
(Murdoch, 1994).

20
1.2
Hydraulic Fracture Overview
Methods have long been sought for increasing the performance of wells. The oil industry in particular has utilized considerable resources to develop such methods. Since at least the mid-1930’s it has been recognized that the pressurization of a well to induce fracturing was a relatively easy and effective means for increasing flow to oil wells
(Yuster, 1945). By the late 1940’s hydraulic fracturing for stimulating oil well production was common practice, and the process was performed on over 1,000,000 wells by the 1980’s (Veatch, 1989). Early methods of fracturing, and some that are still used today, involved initiating and propagating a fracture by injecting only a fluid. The increase in permeability within the fractured region occurs because fractures typically do not close completely, but are held open by asperities on the fracture surfaces (Murdoch et al, 1994). The most common means for producing these fractures are pneumatic fracturing (injection of air) and hydraulic fracturing (injection of liquid). Explosives are also used to produce fractures in bedrock (Murdoch et al, 1994).
The success of hydraulic fracturing in the oil industry has caused researchers to investigate the potential of this technology to improve the performance of contaminant remediation systems. The most direct analogy between oil recovery and remediation processes is increasing the performance of injection or pumping wells installed in lowpermeability formations (Murdoch et al, 1994). Others have investigated the potential for hydraulic fractures to improve remediation technologies, such as soil vapor extraction
(Bradner, 2002), bioremediation (Vesper et al, 1994A;1994B), and electokinetics
(Murdoch, 1997; Chen, 1999; Roulier, 2000).

21
1.2.1
Hydraulic Fracturing Fluid and Proppants
Hydraulic fractures can be created by injecting water, but high viscosity guar gum gel is commonly used (Murdoch, 1995). Guar gum is a food additive that forms a shortchain polymer when added to water. The result is a fluid with a viscosity similar to that of mineral oil. The viscosity of the gel is further increased by the addition of a crosslinker, which causes the polymer chains to link. An enzyme is added to the mixture prior to injection and is designed to break the polymer chains after the gel is injected. The enzyme thins the fracturing fluid, which allows it to be removed through the well bore, or flow into the formation (Murdoch, 1994). Guar gum gel is biodegradable in aerobic conditions, which further promotes removal from pores.
Granular solids can be suspended in the gel and pumped into the fracture. The granular solids mixed into the fracturing fluid are termed “proppants”, because they prop open the fracture and prevent it from closing completely (Clark, 1949). The ability to introduce solids into fractures greatly increases the applicability of hydraulic fracturing.
The most common application for hydraulically fracturing is to increase flow in the vicinity of a well in low permeability formations during pumping or injection. A lowcost proppant that works well is well-sorted quartz sand (Vesper et al,1994a; Murdoch et al, 1994,2002; Richardson, 2003) (Fig. 1.2-1). The production of wells intersecting fractures filled with quartz sand can be 1.5 to 10 times greater than conventional wells completed in similar materials (Murdoch, 1994), although productivity increases of up to two orders of magnitude or more have been observed (Vesper et al, 1994A).

22
Figure 1.2-1 Cross-section of a quartz-sand-filled hydraulic fracture created at a depth of 1.5 m in massive silty-sand (from
Richardson, 2003).
The presence of the proppant increases the aperture, or thickness, of the fracture, but the permeability of the proppant must be considered when estimating the effectiveness of the fracture. A proppant-filled fracture can be correlated to the aperture of an ideal fracture represented as parallel plates by w p

( 12 k w p
)
1
3 (7) where k p
is the proppant permeability and w is the aperture of the proppant-filled fracture
(Murdoch et al, 1994).
The proppant of choice depends on the application. Fractures have been utilized to increase the rate of biodegradation of contaminants. In these instances the proppant may be encapsulated chemicals, such as sodium percarbonate, introduced to increase the oxygen content in the contaminated zone (Vesper et al, 1994B). Chemically active solids, such as iron fillings or potassium permanganate, can be introduced into the

23 subsurface using hydraulic fracturing to increase the degradation rates of contaminants.
Electrically conductive materials such as graphite have been used as proppants to create electrical fields for electroosmosis (Murdoch, 1997; Chen, 1999; Roulier, 2000).
1.2.2
Equipment
The equipment required to perform hydraulic fracturing with guar gum gel and solid proppant includes a container to hold the gel, a hopper to hold the proppant, containers for storing the breaker and cross-linker, and systems to deliver the components to a mixer where they are blended in the proper proportions prior to injection (Fig. 1.2-2).
Once the slurry has been mixed, a pump is used to inject slurry at the pressures and flow rates required for hydraulic fracturing. Piston pumps and progressive cavity pumps are widely used (Murdoch et al, 1994).
Sand Hopper
Screw
Conveyor
Mixer
Positive
Displacement Pump
To Injection
Well
P P
P
Gel Storage
Breaker
Storage
Linker
Storage
Figure 1.2-2 Schematic of equipment required for creating hydraulic fractures with guar gum gel and solid proppant. From
Richardson, 2003.

24
Well casings used for hydraulic fracturing operations must be able to withstand the pressures produced during fracturing. In some cases plastic pipe is cemented into a borehole, but more commonly steel pipe is used. Steel pipe can be directly pushed into the formation, which allows access to relatively undisturbed formation materials. The wells are either installed with a pointed lance that is pushed into the formation and then removed (Murdoch, 1994), or with a disposable point that can be pushed below the casing and then left in place. Creating a hydraulic fracture in a well with backfill material in the annulus between the casing and the well bore wall may cause vertical flow of the fracturing fluid.
1.2.3
Fracture Initiation
The pressure that must be achieved to initiate a hydraulic fracture is a function of formation toughness, in situ stress, borehole defects, and to a lesser extent the injection rate and fluid viscosity (Murdoch, 1994). A defect or “notch” is created in the formation exposed below the well casing to encourage the creation of horizontal fractures and to decrease the pressure required for fracture initiation. The notch is a disk-shaped cavity typically cut into the formation with a high-energy water jet (Murdoch, 2002). The nozzle that produces the water jet is lowered through the casing directs flow perpendicular to the well axis. The nozzle is then rotated to cut the circular notch, which can be 10-20 cm in radius in fine-grained sediment (Murdoch, 2002). The solid material created during the cutting process is flushed to the ground surface.
A transducer is mounted at the top of the casing to measure pressure during fracturing. The fluid pressure increases until propagation begins, and then the injection

pressure decreases as the fracture propagates into the formation (Murdoch, 1994) (Fig.
1.2-3).
25
The initial fluid pumped into the well casing consists of clean gel (no sand), termed a pad. The clean gel is used to initiate the fracture and start propagation. Sandladen gel is pumped into the well casing immediately after the pad and follows the clean gel into the fracture (Veatch, 1989). The arrival of the sand-laden gel at the bottom of the well casing is marked by an increase in injection pressure, due to the increase in viscosity
(Fig. 1.2-3).
Figure 1.2-3 Injection pressure log for constant flow rate through phases of hydraulic fracture creation with quartz sand laden gel, from
Murdoch, 1994.

26
1.2.4
Fracture Propagation and Geometry
Hydraulic fractures are produced with a mode I, or opening type of displacement
(Murdoch, 2002). Fractures with an opening type of displacement orient themselves so the fracture plane is perpendicular to the least compressive stress direction. At depths commonly associated with oil recovery, greater than 600m, the direction of maximum compression is most commonly vertical. This results in most hydraulic fractures created for oil recovery opening horizontally and being oriented in a vertical plane (Veatch,
1989). However, at shallower depths commonly associated with remediation operations, less than 30 m, the direction of maximum compression can be horizontal. Hydraulic fractures created under these conditions are commonly horizontal, which is preferred for remediation purposes (Murdoch and Slack, 2002).
The most important factor affecting fracture geometry is the state of stress in the formation (Warpinski, 1989). Variations in the state of stress in the subsurface affect the direction, radius, and thickness of hydraulic fractures. Factors that influence the state of stress at depth are the thickness of the overburden, surface loading (i.e. buildings), pore pressure, temperature, formation properties, diagenesis, tectonics, and viscoelastic relaxation (Warpinski, 1989). The direction of propagation and orientation of hydraulic fractures can be influenced by heterogeneities; for example horizontal bedding can encourage the formation of horizontal fractures as the fracturing fluid follows bedding planes (Murdoch, 1994).
Analyses of hydraulic fractures created at depths less than 30 m at 10 sites indicate that the fracture planes typically dip gently towards the parent well bore but curve slightly upward with radial distance (Murdoch and Slack, 2002). Hydraulic

27 fractures produced at shallow depths also tend to be slightly asymmetric about the parent well bore. The fractures commonly form an elongate shape with a major axis that is typically 1.2 times the length of the minor axis. The shape results from a preferential fracture propagation direction, which also causes the center of the fracture to be displaced away from the well bore (Murdoch and Slack, 2002) (Fig. 1.2-4). The major axes of these hydraulic fractures are approximately 3 times the depth of initiation (Murdoch,
2002), although major axis to depth ratios of greater than 7 have been observed. The maximum aperture of hydraulic fractures created under shallow conditions in unconsolidated materials is about 1cm (Murdoch, 2002).
Some fractures created at shallow depths quickly propagate vertically and intersect the ground surface, a situation referred to as venting (Murdoch, 1989). Venting terminates fracture propagation and results in a relatively small fracture that can be of limited use for remediation purposes (Murdoch, 2002).
Figure 1.2-4 Form of idealized hydraulic fracture created at shallow depth. Preferential propagation direction causes center of fracture to shift away from borehole, from Murdoch and Slack (2002).

28
The required injection pressure starts to decline once a fracture begins to propagate, however changes in of the sand content in the slurry can cause pressure fluctuation (Murdoch, 1994) (Fig. 1.2-3). The maximum radius that a hydraulic fracture can obtain is limited due to fracturing fluid infiltrating into the formation, termed leakoff.
Leakoff of fracturing fluid can cause propagation termination locally when a fracture intersects high permeability material (Smith et al, 1987). The fracturing fluid leakoff rate increases, which increases the proppant concentration. Once the proppant concentration reaches a critical value the slurry will not flow and propagation ceases, this is called screen-out (Gidley et al, 1987). The rate of fracture fluid leakoff increases as the fracture becomes larger due to an increase in surface area available for leakoff. The growth of the fracture ceases once the rate of leakoff becomes equal to the rate of injection (Murdoch,
1994). The relative permeability of the formation and effective viscosity of the fracturing fluid control the rate at which leakoff takes place (Veatch, 1989, Murdoch et al, 1994).
1.2.5
Monitoring Techniques
The most effective method for determining the geometry and thickness of a fracture is to excavate the fractured region and map the fracture planes and cross-sections
(Murdoch et al, 1994, 1995; Richardson, 2003). Unfortunately, this method renders the fractured well useless. Another way to directly infer the geometry of a hydraulic fracture is by taking core samples (Vesper et al, 1994A; Bradner, 2002). Measurements of uplift at the ground surface can be made during fracture propagation. The change in elevation of the ground surface is typically measured either by surveying multiple target stakes (Du
1993; Richardson, 2003), or by utilizing tilt meters (Lacy, 1987).

29
2 FIELD CONDITIONS
2.1
Field site
The site where fieldwork was conducted for this study is located on the northern end of Simpson Agricultural Experimental Station in Pendleton, SC (Fig. 2.1-1). a
Figure 2.1-1 Simpson Station study site a) road map, b) aerial photograph, modified from Richardson, 2003. b

30
Simpson Station is owned and operated by Clemson University. The land was used as a pasture for livestock at the time of the fieldwork. The past land uses at the site that may affect soil conditions are assumed to be limited to plowing, which disturbed no deeper than 25 cm.
The area used for this research is adjacent to the west side of a corrugated steel building on a concrete pad. Hydraulic fracturing investigations have utilized the field site in the past. One project (Bradner, 2002) involved investigating the effects of hydraulic fractures on soil vapor extraction wells, whereas another project (Richardson, 2003) was designed to characterize the forms of hydraulic fractures created at shallow depths. Well casings were installed at depths of 3.0 m or less for both projects. Richardson (2003) excavated multiple hydraulic fractures within a 150 m
2
area by digging 3.7-m-deep trenches with a backhoe. The trenches were backfilled with native material. The casings for the current research were installed to a depth of 13.7 m, and placed at least 9.1 m from existing wells and the filled trench. Therefore, it is assumed that the region used for this research is undisturbed.
2.2
Regional Hydrogeological Setting
Simpson Station is located in the western portion of the Piedmont Physiographic
Province in western South Carolina. The Piedmont province is a band trending southwest to northeast along the eastern slope of the Appalachian Mountains from Alabama to New
Jersey. The Blue Ridge Province and the Atlantic Coastal Plain bound the northwestern and southeastern borders of the Piedmont, respectively (Miller, 1990).

31
Streams and reservoirs are the primary water sources in the Piedmont, because there have been difficulties obtaining viable ground water supplies for industrial and public use (Heath, 1989). However, increases in water demand and political pressure against reservoir construction have increased demand for ground water resources (Heath,
1989). Ground water withdrawals in the Piedmont averaged 3.1 billion liters per day in
1985 (Swain, 1989). Nearly all aquifers in the region are unconfined and the quality of
Piedmont ground water is considered suitable for drinking; most withdrawals are for domestic and commercial use (Heath, 1989).
The water table in the Piedmont is typically a subdued mimicry of the surface topography, with ground water divides in the vicinity of topographic highs. Precipitation occurs at an average rate of 8.0 cm per month and is the source of ground water recharge
(Miller, 1990). Most ground water discharges to streams that are spaced approximately every 1 km (Legrand, 1989). Ground water in the Piedmont occurs in three main materials; alluvium, fractured bedrock, and saprolite (Miller, 1990).
2.2.1
Alluvium
Alluvial aquifers account for only a small percentage of ground water withdrawals in the Piedmont, predominantly due to limited extent and because nearsurface aquifers are susceptible to contamination (Miller, 1990).
2.2.2
Fractured Bedrock
The bedrock in the Piedmont is composed of mafic to felsic igneous intrusive rocks (Paleozoic-Mesozoic), with igneous and sedimentary rocks (Precambrian-Paleozoic

32 and Cretaceous-Tertiary) that have been metamorphosed to varying degrees (Maher,
1991). The local and regional composition of the bedrock is highly variable due to different sizes and compositions of intrusive igneous bodies, and regional-scale thrust sheets that have been displaced many kilometers from east to west (Maher, 1991). The primary porosity and permeability of igneous and metamorphic rocks are low, typically less than 0.01 and 1.0
x 10
-20
m
2
, respectively (Fetter, 1994). Nearly all of the storage and transmission of water in bedrock results from secondary porosity. Fractures are the most important form of secondary porosity, although dissolution of marble can be important locally (Miller, 1990). The most common fracture configuration in the Piedmont consists of a set of roughly horizontal fractures hydraulically linked to one another by intersections with nearly vertical fractures (Heath, 1989) (Fig. 2.2-1). The spacing and average aperture of fractures in bedrock tend to decrease with depth (Daniel and Dahlen,
2002), although open fractures are known to occur at depths of more than 250 m (Heath,
1989).
Most ground water wells in the Piedmont are completed in bedrock (Miller,
1990). Yields of wells in the Piedmont are typically 55 to 75 lpm, although yields of greater than 380 lpm have been reported (Guthrie and DeJarnette, 1989). The yields of wells in the Piedmont depend on the size, spacing, and connectivity of water-bearing fractures (Heath, 1989). Higher yielding wells tend to be located in valleys or draws.
The locations of valleys or draws are often attributable to the presence of fractures, which make them susceptible to preferential erosion (Guthrie and DeJarnette, 1989). Bedrock overlain by thick residual soil is more likely to be heavily fractured than bedrock overlain by a thin soil layer (LeGrand, 1989).

33
Figure 2.2-1 Conceptual model of hydrologic system in the Piedmont Province, from
Heath, 1989.
2.2.3
Saprolite
Saprolite is the result of isovolumetric, in situ weathering of bedrock material
(White and Fleck, 1990). Saprolite often retains some features of the parent rock, including relict foliation, schistosity, gneissic banding, fractures, and quartz veins (Stone,
1989). Saprolite grain size ranges from clay to boulders (Daniel and Dahlen, 2002).
However, clay minerals can constitute a relatively high percentage of saprolite volume
(Taylor, 2001). Bulk density decreases as parent rock weathers to saprolite due to the alteration of biotite, k-feldspar, and plagioclase to clays. Some weathering products are

34 leached out and migrate downward. For example, weathering of plagioclase during early saprolite development causes the concentration of Ca and Na to increase with depth in the weathering profile (Gardner et al, 1978).
The thickness of saprolite can be as much as 30 m, but is typically 5 to 14 m
(LeGrand, 1989). In general, saprolite permeability increases with depth (Harned and
Daniel, 1989). This is because the degree of weathering typically decreases with depth, therefore clay content decreases with depth. The permeability generally reaches a maximum in the transition zone, which is a gradational contact between bedrock and saprolite. The relatively high permeability of the transition zone can make it a region of horizontal ground water flow, and potentially rapid contaminant migration (Harned and
Daniel, 1989).
Weathering of schist tends to produce saprolite that is highly anisotropic (Kirtland et al. 2001). This occurs because sub-parallel mica grains in schist resist weathering and persist in saprolite. Saprolite development in foliated rock involves a relatively planar, horizontal weathering front that migrates vertically downward. This results in a uniform decrease in grain size with depth and a well-defined transition zone (Harned and Daniel,
1989) (Fig. 2.2-2).
Saprolite weathered from igneous bedrock tends to be more heterogeneous than saprolite weathered from metamorphic rock (Harned and Daniel, 1989). This is because weathering of massive igneous rocks progresses inward from fracture surfaces. This weathering pattern can cause large (1 to 10 m) fragments of relatively pristine rock to be enveloped in highly weathered saprolite, and also causes the transition zones above massive igneous rocks to be poorly defined (Harned and Daniel, 1989) (Fig. 2.2-2).

35
Figure 2.2-2 Conceptual model showing differences in transition zone development based on rock type a) foliated metamorphic b) massive igneous, from Harned and Daniel
(1989).

36
Many investigators have characterized the hydrologic properties of saprolites at a variety of sites (Stewart, 1964; Vepraskas et al., 1991; Welby, 1992; Williams et al,
1994; Vepraskas and Williams, 1995; Taylor, 2001). Most have measured the properties in the lab using core samples or in the field using hydraulic well tests. Porosity of saprolite ranges from 0.30 to 0.60, and hydraulic conductivity typically ranges from 10
-4 cm/s to 10
-6
m/s (Sowers and Richardson, 1983). The permeability parallel to foliation has been shown to be as much as 10 to 100 times greater than permeability normal to foliation (White and Fleck, 1990). Characterization of saprolite at the field scale, however, has proven difficult due to the high degree of heterogeneity. It can also be difficult to intersect important vertical features using coring techniques (Corley et al.,
1999).
2.3
Site Hydrogeological Setting
Bedrock underlying the Simpson Station site is the Caesar's Head Granite, which is approximately 435 M years old according to zircon
207
Pb/
206
Pb dating (Nelson et al.
1990). The Caesar's Head Granite is a light gray, inequigranular, medium-grained, discontinuously banded to nonbanded biotite granitoid gneiss or gneissic granitoid
(Nelson et al. 1990). The mineralogy of the parent material is predominantly quartz, biotite, plagioclase, and orthoclase (Gardner et al, 1978).
There are three distinct layers within the upper 10 m of material at the site. The uppermost layer is 25- to 40-cm-thick topsoil, with the top 10 cm comprised of an organic rich A-horizon. The upper 20 cm of the topsoil lacks residual structure and soil texture, likely due to disruption by plant roots and plowing (Richardson, 2003). Below

37 the topsoil there is a massive layer composed of clay and silt sized particles with lesser amounts of sand (Bradner, 2002). This is the B-horizon, which lacks residual bedrock structures. The thickness of the B soil horizon ranges from 1.5 to 3.7 m, and the contact with the underlying saprolite is well defined. Saprolite extends from the base of the Bhorizon to bedrock at a depth of 15 to 18 m.
The foliated fabric of the parent rock is apparent in the saprolite, although the degree to which it exists varies with depth. Core samples from 13.5 m contain alternating dark (biotite) and light (quartz, k-feldspar, orthoclase) bands, assumed to be residual foliation from the parent rock. The foliation is essentially flat lying (dip less than 3°).
Angular quartz grains (2-3 mm) are common throughout the B-horizon and saprolite. Quartz fragments ranging from 1 to 10 cm also occur in these layers. These fragments were observed in excavations (Richardson, 2003) and in cores. The gneiss originally contained large fractions of mica in the form of discontinuous black, biotiterich bands (Nelson et al. 1990). Mica flakes were commonly observed in water produced from the wells and in mud produced at the ground surface during drilling for well installation. These observations suggest that mica content increases with depth.
The average depth to the water table at the site is 8.55 m. The ground water levels in wells were measured periodically and fluctuated by a few centimeters during the
1.5 years over which field testing was conducted. The average horizontal hydraulic gradient at the site is 0.015, and it suggests flow to the northeast, assuming homogeneous and isotropic conditions (Fig. 2.3-1).

236.2 m
236.0 m
237.0 m
236.8 m
236.4 m
236.6 m
Figure 2.3-1 Contours on the pieziometric surface at the depth of wells (8.5 m).
Contour interval is 0.1 m.
38

39
3 METHODS
This section describes the methods used to complete the three major phases of this research. One phase involved the installation of wells using different completion techniques. Another phase included the design, application, and analysis of data from three types of field sparging well tests. The other phase involved utilizing the multiphase flow simulator T2VOC to model air sparging. The models were calibrated using field test data, and then used to investigate effects of well completion techniques and formation permeability conditions on air sparging operations.
3.1
Well Design and Installation
A total of eight wells were installed at the Simpson Station for tests associated with this project (Fig. 3.1-1). Four of the wells intersect hydraulic fractures, whereas the other four are completed in intact saprolite. The wells were named based on completion technique; HF = hydraulic fracture, ND = naturally developed, and SP = sand pack. Of the four HF wells, two (Well HF-1-90 and Well HF-2-90) intersect fractures filled with
90 kg (0.06 m
3
) of sand, HF-4-725 intersects a fracture filled with 725 kg (0.45 m
3
)of sand, and HF-3-180 intersects a fracture created during two separate injections with a total of 180 kg (0.12 m 3 )of sand.
Two wells (ND-1 and ND-2) were created to serve as controls for the HF wells.
They were installed using techniques similar to those used for the HF wells, but without hydraulic fractures. The other two wells (SP-1 and SP-2) were completed with a 1.5meter-long slotted screen enveloped by a sand pack.

N
40
Figure 3.1-1 Layout of wells installed for research and pre-existing conditions associated with other projects.

41
3.1.1
Well Installation
The wells for this project were installed during January and February, 2003, with the exception of SP-1 and SP-2, which were installed in May, 2003. The top of the well screen in ND-1 was installed at a depth of 13.7 meters. The tops of the other well screens were installed at depths that were at the same elevation as ND-1. The boreholes in which the well casings were installed were created with either 4-inch or 8-inch O.D. augers. All drilling activities were performed with a CME 45 drill rig.
3.1.1.1
Casing Installation
The casings for all the wells, except the SP wells, were installed with techniques commonly used to create hydraulic fracture wells. The well casings were constructed from 2-inch nominal, schedule 40, black iron pipe. Wells ND-1, HF-2-90, HF-3-180, and
HF-4-725 were installed using 4-inch O.D. solid stem augers, whereas 8-inch O.D. hollow stem augers were used for Wells HF-1-90 and ND-2. Boreholes were drilled to within 1.5 m of target depth for each of the wells. The casings were lowered into the open borehole as two 6.6-meter-long sections and one 1.2-meter-long section, which were connected with threaded couplings. A disposable point was fitted in place at the bottom of the casing (Fig. 3.1-2). The drill rig was used to push the casing to target depth. At times the weight of the rig was insufficient to push the casing to depth, so a portable pneumatic hammer was used.

42
Casing
Casing
AW
Rod
Disposable Point a b
Figure 3.1-2 Disposable point used for well installation a) point inserts snuggly into well casing b) AW Rod is used to push point below casing to expose formation material.
The annulus between the casing and open borehole was sealed with grout after the casings were in place. The grout was composed of Portland cement, bentonite, water, and Tetraguard AS-20™, a water-reducing additive that limited shrinkage. A positive displacement pump was used to mix the grout to a density of 1.5 kg/L. The grout was then pumped through a ¾-inch nominal PVC tremie pipe to the bottom of the borehole, where it displaced mud or water that had accumulated there. The annuli were filled with grout to within 0.6 m of the ground surface. The top 0.6 m were then sealed with a bentonite/saprolite mixture.

AW
43
Wells SP-1 and SP-2 were created by drilling boreholes to a depth of 15.4 m with
8-inch O.D. hollow-stem augers. A wood plug was fitted into the open end of the augers to prevent formation material from entering while drilling. Once target depth was reached a 2-inch nominal PVC casing with 1.5- meter-long screen was lowered to the bottom.
The annular space between the PVC casing and the inside of the hollow-stem augers was filled with sand to 0.7 meters above the top of the wood plug. Then the annulus was filled to ground surface with water. The drill rig was used to push on AW rod that had been placed in the PVC casing in order to force the wood plug off the bottom of the augers. The augers were then lifted in increments as sand was placed into the annulus, all the while keeping the augers filled to the ground surface with water. A measuring tape was used to determine when the top elevation of the sand pack was 15 cm above the top of the screen. At this point bentonite was introduced into the well bore annulus until an elevation of 0.7 m above the top of the sand-pack was achieved. The remaining well bore annulus was filled with grout to ground surface using a tremie pipe.
3.1.1.2
Fracturing Activities
All fracturing activities were performed during February, 2003, with the exception of Well HF-4-725, which was fractured during December, 2003. The same process was used to create each of the fractures, although the volume of sand injected into individual fractures differed.
Notches were cut in the formation slightly below the bottom of the well casings in order to facilitate fracture initiation and promote horizontal propagation (Fig 3.1-3).

The notches were created using a tool consisting of a nozzle oriented perpendicular to a steel pipe.
44
The disposable tip was pushed 6 cm below the bottom of the casing using the drill rig and AW rod in order to expose the formation around the bottom of the casing (Fig.
3.1-2). The notch was cut by first attaching a T-fitting onto the top of the well casing.
The top of the T-fitting was open to allow the notching tool to be inserted. A 0.3-m-long pipe was attached to the fitting in order to divert water and cuttings into a bucket.
The notching tool was lowered into the casing until it rested on the disposable point. Water was injected through the nozzle at 15 Lpm at a pressure of 20 MPa, and the nozzle was rotated by turning the steel pipe at the ground surface. The nozzle was rotated at approximately 5 rpm for 2 min to cut a circular notch in the material enveloping the borehole. The water and cuttings were collected in buckets. The volumes of the cuttings were then measured after the water had evaporated.
Bucket
Figure 3.1-3 A circular notch is cut into the formation by turning the rigid pipe at the ground surface.
Casing
Rigid
Pipe
Notch
Point

The average volume of cuttings produced from each well during notching was
4000 cm 3 . These volumes are similar to those of Richardson (2003), who directly observed notches with a 20 cm radius (Richardson, 2003).
45
The gel/sand mixture, or slurry, injected to create each of the fractures was mixed on site immediately prior to injection. The proppant used was #2 filter pack sand from
Driller’s Service, Inc. in West Columbia, SC. 96.4% of the sand grains used were between #25 (0.71 mm) and #8 (2.36 mm) sieves (Richardson, 2003).
Gel was prepared by aspirating guar gum powder into water that was circulated into a 1900 L tank. The linker and breaker were added to the gel before being pumped into a mixer where the sand was added. Sand was added until the slurry was 0.8 to 0.9 sand loading (bulk volume settled sand/ total slurry volume). The slurry then entered a progressive-cavity pump, which forced it through a hose and down the well casing.
Each fracture was created with approximately 1.5 minutes of injection. Typically
90 kg of sand, 208 L of gel, 7.5 L of linker, and 7.5 L of breaker were injected.
Additionally, a 130 L pad consisting of clean gel was injected before the slurry, and 38 L of clean gel was injected after to flush the slurry into the well casing. During the creation of the fracture in Well HF-4-725 1660 L of gel, 60 L of linker, and 60 L of breaker were injected along with the same volumes of clean gel. A pressure transducer mounted at the top of the well casing showed that the formation at 13.7 m depth consistently broke
(fracture initiated) at approximately 650 kPa, and then pressure decreased to roughly 500 kPa during injection.

46
3.1.2
Well Completion
Inserts were created to form screens in all the wells in order to maintain consistency (Fig. 3.1-4 a). Attempts to sparge into the fractured wells with open casings showed that formation material would enter the bottom of the empty casing and displace residual fracturing sand vertically upward when the well was recovering after sparging.
The formation material clogged the bottom of the open casing and severely reduced well performance. The inserts prevented formation material from entering the casing.
The inserts consist of 3-m-long pieces of 1
1
/
4
-inch nominal PVC glued together with couplings. Eighty to 100 micron, high-flow porous polyethylene screens were obtained from McMaster Carr (listed as 3/4' air mufflers, part # 4427k55) and connected a
1
4
b
place. to seal annulus and hold insert in place.

47 to the down-hole ends of the inserts. The screens are approximately 9 cm in length and
3.5 cm in diameter. K-packers from Atlantic Screen Inc. were installed above the porous polyethylene screen in order to seal the annulus and prevent formation material from migrating up the well bore during sparging. The screens were tested prior to installation in order to evaluate the pressure drop across the apparatus. At 7.0
x 10
-4
scms, the pressure drop across the porous polyethylene is 3 kPa. Flow rates during testing were typically less than 7.0
x 10
-4
scms, and the pressure drop is relatively small compared to effective injection pressure.
An assembly was created to seal the annulus between the casing and the insert at the well head (Fig. 3.1-4 b). The wellhead assembly consists of a 2-inch nominal steel pipe section threaded onto the 2-inch nominal steel well casing, and a compression fitting that the 1
1
/
4
-inch nominal PVC insert fits through. Prior to sparging, the wellhead was attached and the compression fitting secured in order to provide a seal to airflow, and to hold the well insert in place (Fig. 3.1-4 b).
Inserts were installed in the ND Wells by first filling the casing to ground surface with water. The disposable point was then pushed to 15 cm below the bottom of the casing using the drill rig and AW rod. The well insert was then pushed into the casing until the tip of the screen made contact with the top of the disposable point. A measuring tape was then lowered to the bottom of the well insert to verify that the screen was below, and that the bottom K-packer was above, the bottom of the casing.
We removed as much of the residual fracture sand as possible from casings prior to installing the inserts in the HF Wells. This was done to minimize the pressure losses that would result when air flowed through sand in the casing. The sand was removed by

48 inserting a hose into the well casing and washing the sand to the ground surface. The end of the hose was lowered to a depth of 30 cm above the bottom of the casing. We kept the end of the hose above the bottom of the casing in order to prevent flushing out sand from the fracture below the casing. Some of the larger sand grains would settle back to the bottom of the after washing the well. The result was approximately 30 cm of sand remaining in the bottoms of all HF Well casings.
The wells were then bailed to remove as much of the fracturing fluid as possible.
The decomposed fracturing fluid had a characteristic grayish color and a pungent odor.
The fluid could also be distinguished from ground water by feel, in that water laden with residual fracturing fluid had a slick consistency. The wells were bailed until these properties were no longer observed in the water being produced. On average this occurred after bailing about 75 L, or 7 well bore volumes. In each case an additional 19
L were bailed. The well inserts were then pushed into the well until the tip of the porous polyethylene screen was resting on top of the sand.
3.2
Field tests
Both conventional and specialized tests were conducted in order to characterize the performance of each well. Conventional slug tests were conducted to estimate the hydraulic properties of the wells before and after sparging. Three tests were developed in order to characterize the efficiency of the wells during air sparging. These tests involved air injection at constant pressure while monitoring flow rate during given periods of time, then incrementally changing the pressure and monitoring flow.

49
3.2.1
Slug Tests
Conventional slug tests were performed in the open 2-inch nominal well casings prior to well insert installation in the HF and SP Wells. Conventional slug tests were performed within the 1
1
/
4
-inch nominal PVC inserts for Wells ND-1 and ND-2, and HF
Wells after inserts had been installed. This was done by pouring 1 L of water into the insert. A 1.13 L slug was lowered by rope into the casings of the open well bores of the
SP Wells and HF Wells prior to insert installation. In each case the head in the well was monitored with a depth-to-water meter and recorded until the water level was within 1% of the original value. All slug test data sets were analyzed using the Bouwer and Rice method (Bouwer and Rice, 1976).
3.2.2
Sparge Testing Equipment
A portable data collection/control system was used to conduct field sparging tests
(Fig. 3.2-1). The compressed air used during sparge testing at the field site was produced from a 150-horsepower, diesel air compressor capable of creating 4.3 m
3
/min at 690 kPa.
An air-water separator was constructed out of capped 4-inch nominal PVC pipe, with inlet and outlet hose fittings located on the top cap. The separator was designed to remove liquid water (condensation) from the air before flowing through the rest of the system. Much of the testing was conducted during the winter months, so an inline heater was used to maintain the air temperature within a range of 20

to 25

C. A 1500-Watt resistance heater was placed downstream of the separator and a thermostat was installed to control the power to the heater. A Control Air Inc., Type 700, high-precision (


0.06 kPa) pressure regulator was used to control the injection pressure at the well-head. The

50 mass flow into the well was measured with a McMillan model 50, 0-500 L/min (


1.5% full scale) thermal mass flow meter during Well Capacity and Injection/Recovery Tests or an Omega FL3404G (0-2.03 cm
3
/min) variable-area mass flow meter during Entry
Pressure Tests. An Ashcroft pressure transducer was located at the top of the casing, along with a pressure gauge for visual inspection. WinDaq data acquisition software (12 bit) was used to collect pressure and flow data at a rate of one sample per second for the durations of the tests.
2
3
1
6
7 4
5
Figure 3.2-1 Flow path taken by air through portable data collection/control system 1) air compressor 2) air-water separator 3) inline heater 4) pressure regulator 5) thermal mass flow meter 6) pressure gauge and transducer 7) into well.

51
3.2.3
Sparge Tests
Three sparging field tests for characterizing the performance of air sparging wells were developed. One test is called an Entry Pressure Test , and was designed to estimate the effective air-entry pressure of the formation. A Well Capacity Test was designed to produce a measure of well performance that is analogous to the specific capacity of water production wells. An Injection/Recovery Test was designed to characterize wells based on post-sparging air flow back out of the well. Air injection pressure during all sparge tests was kept below 310 kPa, which was assumed to be the fracturing pressure of the formation.
Entry Pressure and Well Capacity Tests are variations of a stepped pressure test.
These tests were conducted by injecting air at constant pressure and measuring the flow rate as a function of time, then increasing the pressure as a step function and continuing to monitor the flow rate. The initial injection pressure was set to the hydrostatic pressure at the top of the well screen. Applying this pressure to the headspace on the well forces water from the casing and drops the water level to the top of the well screen. The pressure was increased after the water level had stabilized at the top of the well screen.
The amount of pressure increase depends on the objectives of the test; small steps of approximately 0.7 kPa were used for Entry Pressure Tests, whereas larger steps of 7.0 to
14.0 kPa were used for well performance tests.

3.2.3.1
Entry Pressure Tests
52
An increase in pressure during an Entry Pressure Test causes an abrupt increase in flow that decreases with time and goes to zero when the injection pressure is less than the sum of hydrostatic and air-entry pressure. Typically, the flows accompanying the first few steps in pressure follow this behavior. Eventually, the injection pressure becomes large enough for air to enter the formation, and the flow behavior changes. Flow increases following a step, and then stays constant or continues to increase, when the airentry pressure has been exceeded. Increasing the pressure in small steps allows the airentry pressure to be bracketed by observing the change in flow behavior.
Once the airflow rate into the well during the Entry Pressure Test was maintained, the injection pressure decreased (likely due to use of low quality pressure regulator for original tests). When this happens we assume that the air-entry pressure of the formation has been reached and flow into the saturated media has occurred. The air-entry pressure estimate is then calculated by subtracting the hydrostatic pressure at the top of the well screen from the injection pressure at which flow into the formation began.
3.2.3.2
Well Capacity Tests
Stepped-pressure tests to characterize well performance were begun by injecting air at a constant pressure equal to the hydrostatic pressure at the top of the well screen, a procedure similar to the one used to measure air-entry pressure. The injection pressure was then increased and held constant for a given period of time, causing a spike in mass flow that decreased and equilibrated to a new pseudo-steady state flow (Fig. 3.2-2). The injection pressure was then increased by 7.0 to 14.0 kPa, and the flow rate increased and

equilibrated to some greater value. This was repeated over four to eight pressure steps, with the maximum injection pressure kept less than 310 kPa.
53
Equilibration of flow required several hours to several days for each pressure.
Most of the change in flow occurred rapidly during the first few minutes, but slight changes in flow occurred for periods many times longer than this. It was infeasible to operate the air compressor for long enough periods to complete a full set of pressure steps that were completely equilibrated. Many days to a week or longer would be required for this to be accomplished. The approach that was used here was to hold the pressure constant and monitor flow rate for a particular time period, and then step up the pressure and monitor for 20 min or a time period equal to the initial injection period, whichever was less (Fig. 3.2-2). Periods of initial injection ranged from 1 to 120 min. Flow rates typically were changing slowly (less than 5.0
x 10
-5
scms/min) at the end of each injection
1.2
1.0
120
Air initially enters casing
Injection pressure steps 100
0.8
80
0.6
Mass flow spikes
60
0.4
0.2
0.0
0
Dewater casing
100 200 300
40
Injection Pressure
Mass Flow
Psuedo-steady Flows
400
20
0
500
Figure 3.2-2 Results from 1 min well performance test on Well HF-1-90.

period. The final flow rate of each step was taken as the pseudo-steady state value for that pressure (Fig. 3.2-2).
54
We wanted to characterize sparging well performance with a term that relates the flow rate into the well to the injection pressure. The term is intentionally similar to the specific capacity of a water well, and the concept is related to the productivity index of an oil well (Dariush, 1995). Both specific capacity and productivity index are ratios of discharge rate to drawdown at steady state (Driscoll, 1986). These ratios are assumed to be constant over a reasonable range of operational drawdowns based on analyses of single-phase flow of incompressible liquids through saturated porous media. Those analyses show that steady state well discharge is given by
Q

S c

P w

P
R

(8) where Q is the injection rate, P w
is the well bore pressure, P
R
is a reference pressure, and
S c
is the specific capacity, which depends on well geometry, fluid properties, and the formation permeability. The reference pressure assumed here is the absolute pressure at the well screen under ambient conditions. P w
is also measured in absolute pressure, and the difference ( P w
-P
R
) is the pressure drawdown.
The sparging process is complicated because both the flow geometry and the relative permeability distribution may be functions of injection pressure and hydrostatic pressure. Air is compressible, and air flow will only occur when an entry pressure is exceeded. Furthermore, air flow probably will be turbulent. All of these effects are expected to make characterizing the performance of a sparging well more complicated than that of a water well. It may be feasible to develop a function that characterizes these

effects using physical properties, but the use of such a function would probably be cumbersome. As an alternative, a semi-empirical function was adopted to characterize mass injection rate.
55
Q

W c


P
I

P h
P h

 n
(9) where W c
is termed the Well Capacity and has units of mass flow, P
I
is the gauge injection pressure, and P h
is gauge hydrostatic pressure. n is an empirical constant that characterizes the non-linearity. This form (9) was chosen because it is flexible enough to fit the full range of Well Capacity Test results from this research. It is also simple enough (2 variables) to yield results that can be readily interpreted. A power function form was chosen, because compressibility and turbulence are commonly represented as power functions. W c
represents a mass flow value at a particular injection pressure, in this case when P
I
=2P h
Four types of Well Capacity Tests were conducted. Tests were conducted by stepping the pressure in increments of 1 min, 10 min, or 120 min. The 1-min tests involved initial injection pressures slightly above hydrostatic pressure (70 kPa) and incremental injection pressure increases of approximately 7 kPa. The 10-min tests involved an initial injection pressure of 140 kPa and incremental injection pressure increases of approximately 14 kPa. There were two types of tests that utilized 120-min injection periods, termed 120-min-low and 120-min-high tests. The 120-min-low tests involved initial injection pressures of 70 kPa and pressure increments of approximately 7 kPa, whereas the 120-min-high tests involved initial injection pressures of 140 kPa and

56 pressure increments of approximately 14 kPa. For the ND wells each version of the test was started at the lowest pressure that would produce a measurable mass flow.
Estimated values of W c
and n were obtained for each of the tests. This was done by fitting (9) to a mass flow as a function of injection pressure plot of pseudo-steady mass flow values from field test results. Equation (9) was fitted to field data by minimizing residuals between predictions and field data using the Solver package in
Microsoft Excel.
3.2.3.3
Injection/Recovery Test
Injection/Recovery Tests were started by injecting at constant pressure while flow rate is monitored. After a given period of time a valve at the well head was closed and the hose that was supplying air to the well head was disconnected. The hose that was originally coming from the air compressor was then connected to the well head. This was done so that air produced from the well flowed forward through the data collection system. The valve on the well head was opened and data collected as the air flowed out of the well to the atmosphere. Changes to the data collection system setup from one well to the next were avoided, so results of different tests are comparable.
Injection pressure during air recovery tests was adjusted based on flow rate in order to make the total mass of injected air as similar as possible during all tests. In each case the masses of air injected, and returned, from the wells were calculated by integrating mass flow rate over time.
The volume of air recovered from a well was assumed to be an indirect estimate of the volume of formation material around the well screen affected during the injection

57 period. Assuming that temperature remains constant, a volume balance and the ideal gas law can be used to estimate the volume of aquifer in which the air is trapped using
V a

P h
V
( n r
P a
 
)
(10) where V r
is the volume of air recovered, P h
is hydrostatic pressure around the well screen,
P a
is atmospheric pressure, n is the porosity of the formation, and

is the average volumetric water content in the region affected by sparging.
The sequence of well pressurization, casing dewatering, and initiation of flow into the formation can be identified on mass flow vs. time plots of early Injection/Recovery
Test data (Fig. 3.2-3). This allows the initial portion of an Injection/Recovery Test to be used as a crude air slug test. The crudeness of the test is because there are only two points in time for which head values can be obtained: when the test is initiated and when air enters the formation. When injection is initiated, the pressure at the top of the well screen is equal to the sum of the hydrostatic and injection pressures (Fig. 3.2-3). The pressure at the top of the well screen is equal to the injection pressure at the time when air begins to enter the formation (Fig. 3.2-3).
These data were analyzed using the Bouwer and Rice method by converting the pressures within the casings for the two times to equivalent head values. Results from tests performed using the early sparge method were compared to results obtained using traditional methods to validate accuracy.

25
20
Pressurization of casing
15
10
Water flows out of casing
5
Air enters formation
0
0 10 20 30 40 50 60 70 80
Figure 3.2-3 Initial portion of injection period from Injection/Recovery test showing delineation of water flow out of well casing based on air flow rate verses time.
58
3.3
Modeling
A model of the sparging process was calibrated by adjusting selected parameters so the results of the analysis match the results of representative field tests. The calibrated models were then used to make predictions about well performance, radius of influence, and effect of fracture geometry under differing field conditions.
3.3.1
Model description
The code used for this research is T2VOC (Falta et al, 1995), which is an updated version of the multiphase contaminant transport code STMVOC (Falta et al, 1992).
T2VOC and predecessors use the integral finite difference method for spatial discretization (Falta et al, 1995).

3.3.1.1
T2VOC
59
T2VOC is capable of simulating flow in a multiphase system with three mass components; water, air, and chemical. There can also be up to three mobile phases; gas, aqueous, and NAPL. Each phase can be multi-component (Falta et al, 1995). The gas in simulations for this study is represented by a single component, with properties representing air.
Each grid cell in the model is assigned a particular material type. The materials available are distinguished from one another by physical properties represented by input parameters. Material properties of interest that require input values in T2VOC include permeability in the three principal directions, and porosity.
Multiple sets of equations are available for calculating relative permeability and capillary functions in T2VOC. All simulations conducted for this research used option
IRP=9 (Falta et al, 1995), which are the 3-phase relative permeability functions proposed by Parker et al, (1987), derived using a variation of work by van Genuchten, (1980). The capillary pressure function option used for the simulations was ICP=8 (Falta et al, 1995), from Parker et al, (1987).
3.3.1.2
Code Modifications
The T2VOC code was modified in order to allow separate n values to be used for water and air relative permeability functions, and to include irreducible gas saturation.
The shapes of the curves can be fit individually when separate n values are used for air and water relative permeability functions. The functions are idealized and may differ

significantly from nature when one n is used for both phases. The equations used in place of some of the default IRP=9 equations are
60 m w

1

1 / n w
and m g

1

1 / n g
(11)
S g

( S g

S mg
) /( 1

S m
) (12) k rg

S g

1

  l
1 m g
2
 m g
(13) k rw

S



1


  1 m w

 m w



2
(14) where k rg
and k rw
are the relative permeabilities of gas and water respectively, S and g
S w are the effective saturations of gas and water respectively, S g
is the saturation of gas, S m
is the apparent irreducible wetting fluid saturation, S mg is irreducible gas saturation, and m and n are curve shape parameters where subscripts g and w denote gas and water respectively. The order of phase wettability is assumed to be water > air. Irreducible water and gas saturation ( S m
, S mg
) and curve shape parameters ( n w
, n g
) are the required input parameters used to calculate relative permeabilities using these functions.
While conducting air sparging simulations there was numerical instability that appeared to be due to gas saturations within individual cells oscillating around 0.0. To address this problem, grid cells located below the water table were assigned small (0.005) initial gas saturations for all simulations. The irreducible gas saturation, S mg
, is assigned the same value, and is included to prevent gas saturations from decreasing below this value.

61
The capillary functions were also changed in the T2VOC code to include airwater-entry pressure, which is not included in the Van Genuchten functions. The function used to calculate water-air capillary pressure is
P cgw
 
2

 w g

S w

1 / m 
1
1

/ n v

P e
(15) where S w
is the effective water saturation,
 w
is the density of water, g is the acceleration of gravity, P cgw
is the gas-water capillary pressure, P e is air-entry pressure, and n v
, m , and
α are curve shape parameters. Irreducible water saturation ( S m
), air-entry pressure ( P e
) , and curve shape parameters ( n v
,

) are required input parameters to define the capillary pressure functions. Air-entry pressure was included so there would be a capillary pressure associated with a water saturation of 1.0, as is observed in the field.
3.3.1.3
Grid Design
Grids used for this research were two-dimensional and radially symmetric with a total height of 18 m discretized into 32 rows. Some simulations used a small grid with a
30 m radius and 51 columns (Fig. 3.3-1), whereas others used a larger grid with a 160 m radius and 63 columns.
The outer radius of the small grid was represented by a no flow boundary (16), whereas the outer boundary of the large grid was represented by a constant head boundary (17). The top of the grid in each case was represented by a constant pressure boundary equal to atmospheric pressure (18). The well casing radius in each grid was 2.5 cm, depth to the top of the screen was 5.5 m, and depth to ground water surface was 8.2 m in all simulations. Air was injected or recovered at the same point along the left

62
Figure 3.3-1 Typical grid used for T2VOC simulations. = point of injection. boundary of the grids. The pressure losses along the well casing were assumed negligible at the flow rates obtained during field tests. Therefore, the well casing was not included, with the exception of air recovery simulations.
dP/dr=0; (r= 30m , 0 >z> 18m ) (16)
P=P z
; (r= 160m , 0 >z> 18m ) (17)
P=P atm
( 101kPa ); ( 0 >r> 30m or 160 m , 0 >z> 1m ) (18)
The three types of well completion techniques were represented with different grid block properties. The major difference between the three completions is the length of the screened portion of the casing, or fracture size for wells with fractures installed.
The injection layer for HF Well simulations was 1 cm thick, because this is what we assume is the average fracture aperture. The screened interval of the SP Wells was

63 represented by eleven layers totaling 1.5 m. Sand packs in the SP Wells were represented by the second column of the grid. The outer radius of the second column was set to 10 cm, which corresponds to the radius of the 8-inch O.D. hollow-stem augers used to construct the wells. An additional 15-cm-wide layer was included above and below the well screen to represent the sand pack portions that extend above and below the screen.
Simulated air was produced from a constant pressure grid cell (19) that was connected to the active cell representing the top of the well screen.
P=P inj
; (r= 0m , 14.75m
>z> 14.76m
) (19)
The three types of sparging tests that were performed in the field also required different approaches to modeling. For simulations of air recovery tests the well casing was represented by removing the connections between cells in the 1 st
and 2 nd
columns down to the cell representing the top of the well screen (20). In this case the constant pressure cell was connected to the active cell representing the top of the well casing at the ground surface. The constant pressure cell approach allowed air to be produced at constant pressure, as opposed to constant flow that is produced by the default generation cell option in T2VOC (Falta et al, 1995).
dP/dr=0; (r= 2.5cm
, 0 >z> 14.75m
) (20)
3.3.2
Model Calibration
The T2VOC models were calibrated by fitting low-pressure Well Capacity Test results for SP-2 and HF-3-180 using the parameter estimation software PEST. Well
Capacity Test data were used for model calibration because the large range of injection pressures allows for better estimation of capillary pressure function parameters. The low-

64 pressure tests were chosen because the data sets from the two representative wells were relatively large. The models used for calibration reproduced injection pressure increases at 1 min intervals applied during field tests. However, the mass flow rates at the end of each injection period were the only values compared to modeling results during calibration.
The formations were assumed to be homogeneous and isotropic, with hydraulic fractures and sand packs represented as high permeability zones. The parameters used to characterize the formation and sand materials in T2VOC include intrinsic permeability, k , relative permeability function parameters n a
, n w
, S m
, and S ma
, (Equations 11-14), and capillary pressure function parameters S m
, n v
,

, and P e
(Equation 15). Some parameters were fixed using available data and the others were fitted using PEST. The S m
values for the capillary and relative permeability functions were set equal to each other.
The average hydraulic conductivity of saprolite from pre-sparge slug tests is
9.6
x 10
-4
cm/s. This value corresponds to an intrinsic permeability of 8.3
x 10
-13
m
2
,
which was used to represent saprolite k in all simulations. The air-entry pressure for the fracture and filter pack sand was fixed at 0.0 kPa, assuming that the air-entry pressure of the sand is negligible. The minimum gas saturations were fixed at 0.005 for both saprolite and sand. This was done because the minimum gas saturation is only used to stabilize the model, and is not meant to represent an actual physical property.
A representative saturation vs. capillary pressure function (Van Genuchten) based on laboratory experiments was obtained from Taylor (2001) for a saprolite weathered from granitic gneiss similar to the Caesar's Head Granite .
The capillary function parameters from Taylor (2001) could not be used directly because the Van Genuchten

65
30
20
10
50
40
Laboratory Test Results
Fitted Capillary Function
0
0.5
0.6
0.7
0.8
Water Saturation
0.9
1.0
Figure 3.3-2 Capillary pressure vs. saturation data from Taylor (2001) and fitted capillary function used for saprolite in all simulations. function does not include entry pressure. However, the shape of the curve produced by plotting the Taylor (2001) function was fixed for all simulations. Equation (15) was fitted to this curve to estimate n v
and

(Fig. 3.3-2). The curve was fitted to the Taylor
(2001) results for water saturations less than 0.9, because the inclusion of air-entry pressure makes fitting data for water saturations near 1.0 difficult. The capillary function parameters P e
and S m
were fitted during calibration. n v and

had to be refit to the representative data set after each model calibration run, because changing P e
and S m changes the shape of the saturation vs. capillary pressure curve.
The remaining parameters were obtained by fitting predicted values to observations using PEST. A small grid was used with initial conditions calculated prior

66 to calibration. Calibration required an iterative 3-step process where one set of parameters was varied, while another set was fixed. The varied and fixed parameters were then reversed and the process repeated. The first step involved estimating saprolite parameters using data from SP-2 Well tests. Values for the saprolite were then fixed and data from HF-3-180 tests were used to estimate parameters for sand filling the fracture.
New n v
,
 gn
, and
 nw
, values were then obtained by refitting the capillary function to the fixed capillary curve using the new P e
and S m
values. The entire process was then repeated using new parameter values for each step. The calibration process was finished when changes in parameter values became acceptably small (~2.0%).

67
4 RESULTS
4.1
Slug Tests
Conventional slug tests were performed on most wells both prior to and after the first air sparging test. Slug tests on wells HF-2-90 and HF-4-725, however, were conducted only after sparging. Data obtained from initial portions of Injection/Recovery
Tests were analyzed as air-slug tests to obtain additional estimates of hydraulic conductivity. All slug test data were analyzed using the Bouwer and Rice Method
(Bouwer and Rice, 1976).
4.1.1
Conventional Slug Tests
Slug tests conducted prior to sparging on the ND and SP wells provided estimates of formation hydraulic conductivity ranging from 2.4
x 10
-4
cm/s to 8.2
x 10
-4
cm/s (Table
4.1-1). The estimates obtained from the ND wells (2.4
x 10
-4
and 4.6
x 10
-4
cm/s) are less than those obtained from the SP wells (6.6
x 10
-4
and 8.2
x 10
-4
cm/s).
The post-sparge hydraulic conductivity estimates from the ND and SP wells are more diverse, ranging from 0.4
x 10
-4
cm/s to 6.7
x 10
-4
cm/s (Table 4.1-1). Post-sparge hydraulic conductivity estimates from ND wells (0.4
x 10 -4 and 0.7
x 10 -4 cm/s) are less than estimates from SP wells (4.7
x 10
-4
and 6.7
x 10
-4
cm/s). Hydraulic conductivity estimates after sparging are less than the pre-sparge estimates from all four wells. Postsparge hydraulic conductivity estimates from ND wells are 0.1 to 0.2 of pre-sparge values, whereas post-sparge estimates from SP wells are 0.7 to 0.8 of pre-sparge values.

68
Analyses of slug tests conducted on Well HF-1-90 and Well HF-3-180 prior to sparging give hydraulic conductivity estimates of 18.0
x 10
-4
cm/s, which is twice the presparge value from SP wells, and 10 times greater than the pre-sparge value from ND wells. The range of post-sparging results from the HF wells is 20 x 10 -4 cm/s to 81 x 10 -4 cm/s. This range is broader than the pre-sparge range due to the inclusion of estimates from Well HF-2-90 and Well HF-4-725, which were not slug-tested prior to air injection.
In contrast to the SP wells, hydraulic conductivity determined by slug testing in
HF wells slightly increased after sparging from 18 x 10
-4
to 21 x 10
-4
and 23 x 10
-4
cm/s. The post-sparge hydraulic conductivity estimates from the HF wells are about twice the values from SP wells, and 100 times greater than values from ND wells (Table 4.1-1).
SP-1
SP-2
Avg.
Before Sparging After Sparging Air Slug
8.2
6.7
6.5
6.6
7.4
4.7
5.7
4.9
5.7
ND-1
ND-2
Avg.
HF-1-90
HF-2-90
HF-3-180
Avg.
4.6
2.4
3.5
18.0
18.0
18.0
0.68
0.41
0.55
21.0
23.0
20.0
21.3
4.0
3.3
3.7
25.0
45.0
28.0
32.7
HF-4-725
4
81.0
61.0
Table 4.1-1 Hydraulic conductivity estimates from slug test analyses.

69
4.1.2
Early-Sparge Slug Tests
Data for early-sparge slug test analyses were obtained from the initial portions of
Injection/Recovery Tests (Table 4.1-1). Well SP-2 and Well HF-4-725 are exceptions, however; early-sparge slug test data for these wells were collected from the initial portions of low pressure Well Capacity Tests, where small flows into the formation were obtained at the well bore evacuation pressure. In general, the early-sparge slug test results are similar to the other methods. The correlation coefficients are r 2 =0.81 for presparge and r
2
=0.88 for post-sparge data (Table 4.1-1) (Figure 4.1-1). For the ND and SP wells, the early-sparge slug test hydraulic conductivity values are between the pre-sparge and post-sparge conventional slug test values. However, the early-sparge slug test values for the HF wells are about 1.5 times greater than the post-sparge conventional values. An exception is Well HF-4-725, where the early-sparge-slug test value is 0.75 times the conventional value. The largest difference in hydraulic conductivity estimates from different methods is between the HF-2-90 pre-sparge conventional and early-sparge slug test. These values differ by 2.5 times, appearing as an outlier on Figure 4.1-1a.

70
30
20
50
40
SP Wells
ND Wells
HF Wells
HF-2-90
10
2
90
80
70
60
50
40
30
0
0 10 20 30 40
50
SP Wells
ND Wells
HF Wells
20
10
2
r2=0.816
0
0 10 20 30 40 50 60 70 80 90
Figure 4.1-1 Correlations between early sparge slug tests and a) pre-sparge tests b) postsparge tests.

71
4.2
Entry Pressure Tests
Entry Pressure Tests were conducted on a representative well from each of the well completion methods: Well ND-1, Well HF-3-180, and Well SP-1. Well ND-1 was the only one of the three wells with a screen in direct contact with the saturated formation. The screens of the other two wells were in contact with fracture or filter pack sand.
The beginning of the Well ND-1 Entry Pressure Test involved increasing injection pressure to the hydrostatic pressure at the top of the screen (62.7 kPa) in order to dewater the well casing (Fig. 4.2-1). The injection pressure was increased in ~0.7 kPa increments, starting after flow into the well at hydrostatic injection pressure decreased to zero. With each pressure increase, the flow into the well would increase, and then decrease as pressure within the casing equilibrated. When flow decreased to zero, it was assumed that air-entry pressure had not been reached, so injection pressure was increased.
Flow into the well was sustained when injection pressure reached 93 kPa (Fig. 4.2-1).
Subtracting hydrostatic pressure from total injection pressure at which flow began provides an air-entry pressure estimate of 30.3 kPa.
The Entry Pressure Tests on Well HF-3-180 and Well SP-1 were conducted similarly to the Well ND-1 test. After de-watering the casings of Wells HF-3-180 and
SP-1, injection pressure was increased as a series of steps. In each case, a constant flow was maintained after hydrostatic pressure had been exceeded. Flow never decreased to 0 at any of the subsequent injection pressures, therefore air-entry pressure is less than the first pressure increment above hydrostatic, approximately 3.5 kPa.

120
100
80
60
40
72
20
0 10 20 30 40
Figure 4.2-1 Results of initial Entry Pressure Test conducted on Well ND-1.
50
Well Capacity Tests were also used to estimate air-entry pressure. This was done by plotting mass flow data as a function of injection pressure, then extrapolating back to zero flow. The pressure at which zero flow would occur minus hydrostatic pressure was assumed to be a rough estimate of air-entry pressure. The resulting estimates are further substantiated by comparing them to the minimum pressure that was required to initiate flow into the wells for each test. The flow meter used to collect the Well Capacity Test data is less accurate than the flow meter used during Entry Pressure Tests, especially at low flow rates. However, the errors in estimates from the Well Capacity Test method are expected to be less than

7.0 kPa.

73
Flow was initiated at any injection pressure a few kPa above hydrostatic during all testing of HF and SP wells. However, pressure at least 30 kPa in excess of hydrostatic was required to initiate flow for tests on ND wells. Interestingly, the pressure required to initiate flow into ND Wells increased with each test. Initial air-entry pressures are 30 to
40 kPa, but air-entry pressure increases by 20 to 40 kPa for each subsequent test (Table
4.2-1).
Date
3/10/2003
9/11/2003
12/5/2003
6/15/2004
Entry Pressure (kPa)
ND-1 ND-2
30.3
EPT
NA
59.3
39.5
68.3
82.1
69.5
119.5
Table 4.2-1 Entry pressure estimates for ND wells in four consecutive tests,
EPT=Entry Pressure Test result.
4.3
Well Capacity Tests
Pseudo-steady flow rate as a function of pressure from Well Capacity Tests produces plots with slopes that are constant or increase with pressure (positive curvature)
(Fig. 4.3-1 through 4.3-8). Plots that are most linear are 1- and 10-minute test results from HF wells, whereas 1- and 10-minute test results from SP wells are the most nonlinear. Most of the plots intercept the x -axis (0 flow) at approximately 60 kPa, roughly hydrostatic pressure. Exceptions are the ND well plots, which intercept the x -axis at pressures of 90 to 180 kPa (Fig. 4.3-1 and 4.3-2), because of the air-entry pressure effect outlined above (Table 4.2-1).

3.0
2.5
2.0
1.5
1.0
1 Minute
10 Minute
120 Minute-High
0.5
0.0
140 160 180 200
Pressure (kPa)
Figure 4.3-1 Pseudo-steady mass flow as a function of injection pressure for Well Capacity Tests on Well ND-1.
2.0
74
1.5
1 Minute
10 Minute
120 Minute-High
1.0
0.5
0.0
140 160 180
Pressure (kPa)
200
Figure 4.3-2 Pseudo-steady mass flow as a function of injection pressure for Well Capacity Tests on Well ND-2.

6
5
4
3
2
1
1 Minute
10 Minute
120 Minute-Low
1.5
1.0
0.5
0
80 100 120 140 160
Pressure (kPa)
Figure 4.3-3 Pseudo-steady mass flow as a function of injection pressure for Well Capacity Tests on Well SP-1.
3.0
2.5
1 Minute
120 Minute-Low
2.0
0.0
80 100 120 140 160
Figure 4.3-4 Pseudo-steady mass flow as a function of injection pressure for Well Capacity Tests on Well SP-2.
75

4
3
1 Minute
10 Minute
120 Minute-High
2
1
0
80 100 120 140 160 180 200
Figure 4.3-5 Pseudo-steady mass flow as a function of injection pressure for Well Capacity Tests on Well HF-1-90.
4
1 Minute
120 Minute-High
3
2
1
0
80 100 120 140 160 180
Pressure (kPa)
Figure 4.3-6 Pseudo-steady mass flow as a function of injection pressure for Well Capacity Tests on Well HF-2-90.
76

6
5
4
3
2
1
1 Minute
10 Minute
120 Minute-High
120 Minute-Low
0
60 80 100 120 140 160 180 200
Figure 4.3-7 Pseudo-steady mass flow as a function of injection pressure for Well Capacity Tests on Well HF-3-180.
77
3
1 Minute
2
1
0
60 70 80 90
Pressure (kPa)
100 110
Figure 4.3-8 Pseudo-steady mass flow as a function of injection pressure for Well Capacity Tests on Well HF-4-725.

78
The mass flow rates from 120-minute tests are greater than mass flow rates from shorter term tests performed with similar injection pressures for all the wells (Fig. 4.3-1 through 4.3-8). Moreover, plots from 120-minute data tend to be steeper than plots from shorter tests. Plots of 120-minute data from HF wells tends to be more non-linear than plots from shorter term tests, but for the other wells (SP and ND) plots of 120-minute data are more linear than those from shorter term tests.
1-minute and 10-minute test data from the same wells are similar to each other and generally plot along the same trend (Fig. 4.3-1,3,5,8). The pseudo-steady flow rates at initial injection pressures during tests on HF wells are similar; however, flow rates at subsequent pressures increase at a greater rate for the longer term tests (Fig. 4.3-5 and
4.3-7). Pseudo-steady flow rates from longer term tests on SP wells are greater than flow rates from shorter-term tests for all injection pressures.
W c and n values were obtained by fitting equation (9) to Well Capacity Test results (Table 4.3-1). This was done to provide scalar measures of the well performance that could be compared. HF and SP wells tended to perform similarly, whereas ND wells consistently under performed compared to the other completion methods.
W c represents the mass flow rate into a well when injection pressure is held constant at twice hydrostatic. W c values obtained from field test analyses range from
2.2
x 10 -5 to 330 x 10 -5 scms. W c
values obtained from tests on HF and SP wells are all greater than those from tests conducted on ND wells. One-minute and 10-minute W c values from tests on HF and SP wells are similar, although values from Wells HF-3-180 and HF-4-725 are slightly greater. However, 120-minute-low W c
values from tests on SP wells are slightly greater than the one value from an HF well (HF-3-180).

ND-1
ND-2
SP-1
SP-2
1 Minute n W c
x 10
5
3.4
4.6
3.0
2.3
(scms)
4.7
2.2
130.0
84.0
HF-1-90
HF-2-90
HF-3-180
HF-4-725
HF-1-90
HF-2-90
HF-3-180
HF-4-725
1.3
1.2
1.4
1.7
ND-1
ND-2
SP-1
SP-2
120 minute-Low n W c
x 10
5
(scms)
2.0
1.7
328.0
250.0
1.5
82.0
92.0
130.0
280.0
170.0
10 Minute n
2.8
2.9
3.2
W c
x 10
5
(scms)
7.3
10.0
110.0
Hydrostatic
(kPa)
59.4
61.2
58.6
59.0
1.5
1.0
77.0
160.0
59.0
57.1
59.4
54.9
120 minute-High n W c
x 10
5
2.5
2.1
(scms)
27.0
35.0
Non-equilibration
2.1
1.6
1.9
75.0
130.0
140.0
Not conducted
79
Table 4.3-1 W c
and n estimate values obtained from Well Capacity Test analyses.
W c
typically increases or is roughly constant as test duration increases. W c increases with test duration for the ND and SP wells, (the 1-minute and 10-minute tests on Well SP-1 are exceptions). W c
seems to be relatively insensitive to test duration for
HF wells. n values in Eq. (9) range from 1.0 to 4.6, and tend to be greater for tests conducted on the ND and SP wells than from tests on HF wells. 1-minute tests on ND wells produce the greatest n values (3.4 and 4.6) and smallest W c
values (2.2
x 10
-5
and
4.7
x 10 -5 scms). Increasing the duration of tests on ND wells reduces n (2.1 and 2.5) and increases W c
(27 x 10
-5
and 35 x 10
-5
scms). n values from 1-minute tests on SP wells are less (3.0 and 2.3), and W c
values are greater (130 x 10
-5
and 84 x 10
-5
scms) than those from ND well tests. Increasing the duration of the test on the SP wells decreases n (1.7

80 and 2.0) and increases W c
(250 x 10
-5
and 328 x 10
-5
scms). The flow rate oscillated severely during the 120-minute-high tests on the SP wells, preventing data collection for
W c
and n analysis. n values approach 2 as test duration increases, although different well completion methods converge on this value differently. SP and ND well results produce large n values that decrease with test duration. However, HF wells produce relatively small n values that increase with test duration (Table 4.3-1).
Analysis of data collected during 1-minute tests on HF wells, excluding Well HF-
4, produced the lowest overall values of n (1.2 to 1.7) and relatively large W c
values (82 x 10
-5
to 130 x 10
-5
scms). When compared to 1-minute values, the 120-minute estimates for n increase (1.6 to 2.1) and W c
estimates mostly increase (75 x 10 -5 to 140 x 10 -5 scms).
1-minute test data from Well HF-4-725 produce the greatest 1-minute HF well n value
(1.7), and greatest overall 1-minute W c
value (280 x 10
-5
scms). However, Well HF-4-725 trends are obscured by severe oscillations in flow rate during longer-term tests, which resulted in data that could not be analyzed for W c
and n .
4.4
Injection/Recovery Tests
Injection/Recovery Tests were performed on all wells except Well SP-2. Air was injected into each well for approximately 2 hours at a pressure of 138 or 207 kPa, whichever would produce a mass flow closest to 2.0
x 10
-3
scms. All flow data for the
Injection/Recovery Tests are plotted as positive flow (Fig. 4.4-1 to 4.4-7). The injection portion of the test is separated from the recovery portion by a dashed line at t = 120 min.
Some zero flow periods have been removed from each of the data sets between the end of

81 the injection periods and beginning of the recovery periods. These data were removed to facilitate comparison of injection and recovery. The removed data represent the time that was required to remove air-hoses and reverse the system, which took approximately 2 minutes.
Sharp changes in flow rate observed in Injection/Recovery Test data accompany changes in injection pressure, cycling of the inline heater, or oscillatory flow (Fig. 4.1-1 through 4.1-7). Injection pressure changes were made during testing when early flow rate into the well was significantly less than 2.0
x 10
-3
scms (Fig. 4.1-1,2,3,6). Changes in flow rate occur in the recovery portions of the tests, and correspond to cycling of the inline heater. Flow rate increases when the heater turns on, and decreases when it turns off. The amplitude and frequency are greater for tests conducted in cold weather (Fig.
4.1-1) than for tests conducted in warmer weather (Fig. 4.1-4). Those sharp flow changes are caused by fluctuations in the injection equipment, however, oscillations in flow also occurred that were unrelated to equipment effects (discussed in 4.5.2).
The recovery period in each of the tests is marked by a sharp spike followed by a steady decrease in flow (Fig. 4.4-1 through Fig. 4.4-7). The way that flow decreases for fractured wells differs from that of non-fractured wells. Flow from the HF Wells decreases quickly to roughly the final rate of injection (Fig. 4.4-1,2,6). Then the curve flattens for 20 to 40 min, but it then steepens again and decreases at a faster rate over the rest of the recovery period. In contrast, flow from the non-fractured wells quickly drops to a value that is less than the final injection rate (Fig. 4.4-3,4,5). Flow rate then decreases at a rate that is slower than that from the fractured wells. Although initial recovery flow rates from non-fractured wells are less for the non-fractured wells, the flow

82
3.0
2.5
2.0
1.5
I
H
1.0
Flow In
0.5
Flow Out
0.0
0 50 100 150 200 250
3.0
Time (min)
Figure 4.4-1 Well ND-1 Injection/Recovery Test results. H=heater and
I= injection pressure increase.
2.5
2.0
1.5
I
1.0
Flow In
H
0.5
Flow Out
0.0
0 50 100 150
Time (min)
200 250
Figure 4.4-2 Well ND-2 Injection/Recovery Test results. H=heater and
I= injection pressure increase.

3.0
2.5
H
I
2.0
1.5
1.0
Flow Out
Flow In
0.5
0.0
0 50 100 150 200 250
Time (min)
Figure 4.4-3 Well HF-1-90 Injection/Recovery Test results. H=heater and I= injection pressure increase.
3.0
83
2.5
H
2.0
1.5
Flow In
1.0
0.5
Flow Out
0.0
0 50 100 150 200 250
Figure 4.4-4 Well HF-2-90 Injection/Recovery Test results. H=heater.

3
H
2
Flow In
2
1
4
3
I
1
O
O
Flow Out
0
0 50 100 150 200
5
Figure 4.4-5 Well HF-3-180 Injection/Recovery Test results. H=heater and
O= oscillatory flow.
Flow In
O
O
Flow Out
H
0
0 50 100
150 200
Figure 4.4-6 Well SP-1 Injection/Recovery Test results. H=heater, O= oscillatory flow, and I= injection pressure increase.
84

85
) ) ) ) )
3 3 3 3 3 ( ( 3 3 3 sx 10 sx 10 sx 10 sx 10 sx 10 scm scm scm scm scm Flow ( Flow ( Flow ( Flow ( Flow ( Mass Mass Mass Mass Mass

rates at the end of the recovery period typically are greater because flow rate decreases more slowly.
86
The total mass injected into the wells ranges from 8.4 scm to 21.3 scm, and the total mass recovered from the wells ranges from 1.8 scm to 8 scm (Table 4.4-1). Well
HF-3-180 was an exception, with a much larger mass injected (72.73 scm), and a much smaller mass recovered (0.04 scm). The ratio of the mass of air recovered to mass of air injected ranges from 0.22 to 0.40, but the ratio from Well HF-4-725 is only 0.0005. The average ratio of air recovered from the ND and SP wells is 0.32, and the average ratio recovered from the HF wells, excluding Well HF-4-725, is 0.33.
ND-1
ND-2
SP-1
Ratio Rec.
12.5
8.4
21.3
4.5
1.9
8.0
0.36
0.23
0.38
Avg.
0.32
HF-1-90
HF-2-90
HF-3-180
HF-4-725
12.6
15.3
18.2
72.7
5.1
4.3
5.3
0.0
0.40
0.28
0.29
0.0000
Avg.
0.33
Table 4.4-1 Total masses of air injected and recovered during air recovery tests.

87
The mass of air recovered from the wells is assumed indicative of the volume of the gas-bearing formation around the well screen. Gas-bearing volume estimates were made using Equation 10; assuming 50% porosity, 15% residual water, and that the trapped air is at hydrostatic pressure. The gas-bearing volume estimates ranged from 3.4 to 14.4 m
3
(Table 4.4-2). This range correlates to a gas-bearing sphere centered about the well screen with a 0.9 to 1.5 m radius.
ND-1
ND-2
SP-1
3
4.5
1.9
8.0
8.1
3.4
14.3
HF-1-90
HF-2-90
HF-3-180
5.1
4.3
5.3
9.1
7.7
9.5
HF-4-725 0.0
0.0
Table 4.4-2 Mass of air recovered from wells during Injection/Recovery Tests and estimates of minimum volume of aquifer affected within the vicinity of the well screen.
4.5
Mass Flow Transients
Histories of mass flow into SP and ND wells differ from histories of mass flow into HF wells. In some cases the general forms of the transient mass flows were systematic and different, whereas in other cases the histories were chaotic and characterized by rapid oscillations in mass flow rate. Rapid oscillation occurred during tests on SP and HF wells, but was absent in data sets from ND wells.

88
4.5.1
Transient Mass Flow Features
Transient mass flow features occur during two injection phases. Phase 1 involves mass flow during the initial injection pressure, and is represented by data from each of the three types of sparging tests that were conducted. Phase 2 involves mass flow during subsequent injection pressures, and is represented by data from Well Capacity tests (Fig.
4.5-1).
The initiations of injection are marked by sharp spikes in mass flow (Fig. 4.5-1).
The spike is followed by a period of relatively low mass flow, and then the mass flow begins to increase. The mass flow rate typically approaches the steady-state value within the pre-determined injection period. However, because mass flow typically may be changing at a slow rate, this value is referred to as pseudo-steady state. Another sharp spike in mass flow occurs when injection pressure is increased (Fig. 4.5-1).
500
1.5
1.0
Pressurization of casing
Flow spikes and re-equilibrations after pressure increases
Flow increase to pseudo-steady state
400
0.5
Stage 1
Stage 2
Pressure
300
200
0.0
Dewatering of casing
-0.5
100
0 50 100 150 200
Figure 4.5-1 Mass flow (thin line) and pressure (thick line) as functions of time, with interpretations, during 2 hour-low Well Capacity Test in Well ND-1.

89
The initial mass flow spike probably represents the period required to fill the well casing to the applied pressure (Fig. 4.5-1). The low-flow period that follows is interpreted as dewatering of the well casing. Mass flow rate then increases when air enters the formation. This would happen when the air pressure pushed the water in the well down to the well screen and the air-entry pressure was exceeded.
Mass flow approaches pseudo-steady state during Phase 1 in all of the wells.
However, a distinct difference is observed between non-fractured wells and wells intersecting fractures (Fig. 4.5-2). In the non-fractured wells (SD and ND), the flow increases gradually after air initially enters the formation, and the rate continues to increase until a pseudo-steady rate is reached (Fig. 4.5-2). In contrast, the mass flow rate increases sharply, and then decreases to a pseudo-steady rate in the HF wells (Fig. 4.5-2).
The time required to reach the pseudo-steady flow rate in the fractured wells was usually shorter (30 sec to 2 min) than in the non-fractured wells (5 min to 2 hours).
Similar flow features are present during Phase 2 (Fig. 4.5-3). An increase in injection pressure is marked by a mass flow spike in all wells. Flow decreases to pseudo-steady state after the flow spike in fractured wells (Fig. 4.5-3 solid line). Mass flow histories during Phase 2 in SP and ND wells vary depending on the mass of air that has been injected prior to an increase in injection pressure. When a relatively small air mass has been injected early in a test, flow decreases sharply after the spike and then increases to pseudo-steady state (Fig. 4.5-3 dotted). However, flow steadily decreases to pseudo-steady state after the spike when pressure is increased after a relatively large mass of air has been injected (Fig. 4.5-3 dashed). Phase 2 pseudo-steady flow is consistently reached in a shorter time in non-fractured wells than in fractured wells.

8
6
4
2
SP-2
HF-3
Air initially enters formation
0
0 10 20 30 40 50 60 70 80 90 100 110
Time (min)
Figure 4.5-2 Mass flow histories during Stage 1 of 2 hour-low Well Capacity Tests on
Wells SP-2 and HF-3-180.
2.0
1.5
1.0
0.5
SP-1, Early
SP-1, Late
HF-1
Injection pressure increase
0.0
0 5 10
Time (min)
Figure 4.5-3 Mass flow patterns during stage 2 in low-pressure 120-min Well
Capacity Tests on Wells SP-1 and HF-3. Initial and pseudo-steady flow scaled from 0 to 1 for comparison.
90

91
4.5.2
Oscillatory Flow
Unexpected flow histories marked by significant oscillations were commonly observed in field sparging data. A characteristic repeating pattern was present in many of the oscillatory records (Fig. 4.5-4). The pattern begins with a sharp increase in flow rate.
The flow rate then decreases gradually, roughly resembling a negative exponential function. The cycle ends with a sharp decrease in flow, followed by an increase marking the beginning of the next cycle (Fig. 4.5-4). This repeating pattern was evident in most records showing oscillatory flow. The feature is poorly defined in some records, however, and the flow oscillations appear chaotic in a few tests (Fig. 4.4-7). In general, the amplitude of the oscillations was greatest initially, and then decreased with time. The period of the oscillation cycles was regular in some cases (typically 1-2 minutes) (Fig.
4.5-4), whereas in other cases the periods were irregular. This behavior occurred more
140
5
Injection pressure
4
120
100
3
80
60
2
1
Characteristic repeating feature
40
20
0
0 200 400 600
0
800
Figure 4.5-4 Oscillatory flow with characteristic repeating feature from 120-min-high
Well Capacity Test on Well HF-3-180.

commonly when air was injected into wells with high W c
values. The oscillations also tended to occur at earlier times, or at lower pressures, as W c
values increased. The oscillations typically began following an increase in injection pressure, although instances where oscillations began after a constant injection pressure had been maintained for several minutes or longer also occurred.
92
The oscillations often dampened with time and the flow equilibrated to a pseudosteady flow rate after 1 to 20 min. However, in some tests the oscillations were more persistent, and continued for several hours or more. The equilibrium flow following oscillations differed from the mean flow during oscillation. In one test, for example, the flow oscillated about a mean of 2.2
x 10
-3
scms, but then the oscillations stopped and the rate equilibrated to a value of 2.0
x 10
-3
scms (Fig. 4.5-5).
2.6
2.4
2.2
140
120
100
80
2.0
60
40
1.8
20
1.6
0 50 100 150 200 250
0
Time (sec)
Figure 4.5-5 Mass flow rate with time from Injection/Recovery Test on Well
HF-4-180 showing oscillatory flow followed by equilibrium.

93
Oscillating flow was absent from Entry Pressure Tests, where the flow rates and total injected volumes were relatively small. Oscillating flow was observed in both of the other types of tests; however, it was only a factor in data collection for the Well Capacity
Tests. This is because steady flow rate at a given pressure was required for calculation of
W c
, whereas total volume injected was the primary value of interest for Injection
/Recovery Tests. Flow rate data were used for the W c
analysis when the oscillatory flow was absent, or when the flow rates at a given pressure reached pseudo-steady state within a predetermined period. However, flow data were not used when pseudo-steady state was not reached, or was reached at a time that was greater than the pre-determined injection period. Problems determining mass flow rate values during oscillating flow limited some Well Capacity Test data sets.
4.6
Modeling
T2VOC simulations were conducted to investigate effects of well completion method and formation properties. Parameters from the calibrated models were used as baseline for all simulations. Aspects of the sparging system, such as fracture geometry, injection period, and formation permeability, were investigated by manipulating one or more variables in the fitted models.
4.6.1
Model Calibration
Twelve parameters were estimated during the model calibration process, and six parameters were fixed during calibration (Table 4.6-1). The parameters that were fixed include saprolite permeability and residual air saturation for both materials. The capillary

Intrinsic Permeability
Saprolite
(F) 8.3e-13 m
2
Sand
1.5e-11 m
2
Relative Permeability n, Water
Function Parameters n, Air
Res. Water Sat.
Res. Air Sat.
6.0
2.0
0.317
(F) 0.005
7.0
2.0
0.05
(F) 0.005
Capillary Function n
Parameters α, for both v
Entry Pressure
Res. Water Sat.
(F) 2.0
(F) 1.9
8000 Pa
0.317
2.0
9.0
(F) 0.0 Pa
0.05
Table 4.6-1 Values of parameters that were fitted during calibration. (F)= Fixed
94 function parameters n v
and α for saprolite were selected to fit experimental data from
Taylor (2001). The air-entry pressure for sand was assumed to be negligible, and was assigned a value of 0 kPa.
The permeability of the sand used in the fractures and filter packs is 1.5
x 10
-11
m
2
, according to results of parameter estimation. The calibrated n w
and n a
values in the relative permeability functions for saprolite and sand are within ranges recognized for similar materials (Parker et al., 1987) (Table 4.6-1). The S m
value for saprolite is within the range of values obtained by Taylor (2001) for granitic gneiss saprolite. The air-entry pressure for the saprolite was estimated to be 8 kPa during model calibration.
The values obtained for capillary function parameters n v
and α for saprolite cannot be directly compared to typical values for these materials. This is because the capillary function used during model calibration was modified to include air-entry pressure.
The simulated transient mass flow that occurs during each injection pressure generally resembles the field data (Fig. 4.6-1). The model predicts that flow rate increases sharply following increases in injection pressure, and then decreases with time.

The predicted magnitude of the increase in flow is variable, generally increasing with time and with the magnitude of the pressure increase (Fig. 4.6-1).
95
Mass flow spikes are present during each injection pressure increase in field data from both wells. However, the simulated spikes are subtle at early times for each of the wells. The difference between observed and predicted values can be attributed to flow into the well casing. The relatively large flow rate following an injection pressure increase in the field data probably results from air flowing through the system as the pressure in the casing rises to the new pressure. The casing volume was omitted from the numerical model. The small spikes in flow rate that do occur in the simulations are a result of rapid flow that occurs as pressure in the air-filled region increases (Fig. 4.6-1).
The results predicted using representative parameters are similar to observed results from field tests, with correlation coefficients of 0.98 and 0.968 for Well SP-2 and
Well HF-1-90, respectively (Fig. 4.6-2). The estimated flows from Well SP-2 simulations fit the field data values closely from 70-90 kPa, they slightly overestimate field data from 90-135 kPa, and slightly underestimate field data at higher pressures (Fig.
4.6-2 a). The simulated results from HF-1-90 underestimate field test values at pressures less than 120 kPa, and slightly overestimate flows at higher pressures (Fig. 4.6-2 b).

2.0
1.5
1.0
T2VOC
Field Test
0.5
a.
0.0
0 50 100 150 200 250 300 350 400
1.4
1.2
1.0
0.8
T2VOC
Field Test
0.6
0.4
0.2
b.
0.0
0 50 100 150 200 250 300 350 400
Figure 4.6-1 Comparison of mass flow transients over range of injection pressures from field tests and modeling; a =SP-2, b =HF-1-90.
96

3.0
2.5
2.0
1.5
Field Test
T2VOC
1.0
0.5
a.
0.0
60 160 80 100 120 140
1.4
1.2
1.0
0.8
0.6
0.4
Field Test
T2VOC
0.2
b.
0.0
60 80 100 120
Figure 4.6-2 Comparison of pseudo-steady mass flows at different injection pressures from field tests and modeling; a =SP-2, b =HF-1-90.
140
97

98
4.6.2
Well Capacity Modeling
T2VOC simulations were used to investigate how W c
changes under various conditions. One set of simulations characterized how W c
varies with changes in formation permeability for SP and HF wells. Another set of simulations focused on HF wells, characterizing how variations in fracture radius or aperture affected W c
in two different formation permeability conditions. Small grids were used for all Well Capacity simulations.
The models for both sets of simulations reproduced 1-minute Well Capacity
Tests, which were the test data used for model calibration. W c
estimates were obtained by fitting equation (9) to modeling results plotted as mass flow rate verses injection pressure.
4.6.2.1
Well Capacity/Permeability Relationships
Simulations were used to investigate how the presence of a hydraulic fracture influenced W c
under different formation permeability conditions. This investigation was of interest because the saprolite permeability at the field site is only about 20 times less than the fracture sand permeability, and a larger contrast will occur at many locations.
The investigation utilized field-calibrated models for a well with a 1.5-m-long screen and sand pack (SP Well) and for a well intersecting a 1.5-m-radius sand-filled fracture (HF Well). Other simulations were created to represent hypothetical situations.
Parameters from the field-calibrated models were held constant for these simulations, with the exception of formation permeability. The formation permeabilities were changed so the ratio of sand permeability to formation permeability, (k s
/k f
), varied by

99 whole orders of magnitude (Table 4.6-2).
These k s
/k f
values are used to reference individual simulation results, but the actual k s
/k f k s
(m
2
)
10 1.5x10
-11
18 1.5x10
-11
100 1.5x10
-11
1000 1.5x10
-11
10000 1.5x10
-11 k f
(m
2
)
1.5x10
-12
8.3x10
-13
1.5x10
-13
1.5x10
-14
1.5x10
-15 value only refers to permeability ratios where sand permeability is 1.5
x 10
-11
m
2
.
Table 4.6-2 Simulation k values.
Simulated W c
values range over three orders of magnitude for the SP well, and over two orders of magnitude for the HF well (Table 4.6-3). For higher formation permeabilities the W c
estimates from the SP well simulations are greater than those from the HF well simulations (Fig. 4.6-3).
However, as formation permeability decreases the relationship is reversed. W c
values consistently decrease as saprolite permeability decreases, but the rate at which SP well
W c
values decrease is greater than that for the HF wells. The formation permeability that produces equal W c
values for the wells is approximately 5.0
x 10
-13
m
2
. At 1.5
x 10
-12
m
2 the SP well W c
is 1.4 times greater, whereas at 1.5
x 10
-15
m
2
the HF well W c
is 14 times greater (Table 4.6-3, Fig. 4.6-3). n values also vary as a function of fracture/formation permeability ratio (Table
4.6-3). In both cases n is approximately 2 for k s
/k f
= 10, 18, and 100, however, the maximum n values are from k s
/k f
= 18 simulations. n values decrease as permeability ratio increases to values greater than k s
/k f
= 18 in both cases. n values from HF well simulations decrease from 2.0 to 1.0, whereas n values for SP wells decrease from 2.1 to
1.3 (Table 4.6-3).

k s k s
/k f
10
18
10
18 f
W c n n
1.4E-03 2.0
6.7E-04 2.1
8.5E-05 2.0
8.3E-06 1.6
1.3E-06 1.3
W c c
(scms) n n
1.0E-03 1.9
5.9E-04 2.0
1.5E-04 1.9
5.5E-05 1.3
1.8E-05 1.0
Table 4.6-3 Simulated W c
and n values as a function of permeability ratio.
100
1e-3
1e-4
1e-5
SP Well
HF Well
1e-6
1e-15 1e-14 1e-13 1e-12
2
Figure 4.6-3 Simulated W c
values as a function of formation permeability for SP and HF wells. s
=1.5
x 10
-11
m
2
for all simulations.

4.6.2.2
Well Capacity/Fracture Geometry Relationships
101
Simulations of HF wells were conducted to investigate the effect of fracture geometry on W c
values. One set of simulations characterizes the effect of fracture radius on W c
, whereas another set characterizes the effect of fracture aperture. The fracture radius and aperture were varied by changing the number of columns and/or rows assigned fracture sand properties within the model mesh. Each set of simulations was conducted using two different formation permeabilities to investigate how formation permeability affects the relationship between fracture geometry and W c
. These formation permeabilities correspond to the k s
/k f
=18 and k s
/k f
=1000 values used to compare HF and SP well performance previously (Table 4.6-2). These simulations are referred to as
Fit-k (k s
/k f
=18) and Low-k (k s
/k f
=1000).
4.6.2.2.1
Fracture Radius
Effects of fracture radius were investigated by conducting simulations with 15 different radii, ranging from no fracture (0.0 m) to 5.0 m, while holding aperture constant at 1.0 cm. The W c
values from the Fit-k simulations range from 1.7
x 10
-4
to 6.0
x 10
-4
scms
(Fig. 4.6-4). However, W c
values from the Low-k simulations range over more than two orders of magnitude, from 6.0
x 10
-7
to 9.6
x 10
-5
scms (Fig. 4.6-5).
The W c
values for the Fit-k simulations increase sharply from 1.5
x 10
-4
to 5.5
x 10
-4 scms with increase in fracture radius from 0.0 to 0.5 m (Fig. 4.6-4). An increase in fracture radius from 0.5 to 3.0 m produced smaller increases in W c
, from 5.5
x 10
-4
to
6.0
x 10 -4 scms, and changes in W c
for radii between 3.0 to 5.0 m were negligible. W c values from Low-k simulations also increase with fracture radii, but do so differently than

2.2
6e-4
5e-4
4e-4
3e-4
2e-4
1e-4
0
0
Wc n
2.1
2.0
1.9
1.8
1 2 3
4 5
1.7
Figure 4.6-4 W c
estimates from modeling as a function of fracture radius for
Fit-k simulations.
1e-4
8e-5
6e-5
4e-5
2e-5
0
0
Wc n
2.4
2.2
2.0
1.8
1.6
1.4
1.2
5
1.0
1 2 3
4
Figure 4.6-5 W c
estimates from modeling as a function of fracture radius for
Low-k simulations.
102

103
W c
values from Fit-k simulations. W c
increases from 6.0
x 10
-7
to 1.2
x 10
-5
scms with increase in fracture radius from 0 to 0.5 m (Fig. 4.6-5). W c
then increases at a greater rate for fracture radii from 0.5 to 2.0 m, and then the rate of increase slows as radius increases from 2.0 to 4.0 m. Changes in W c
with fracture radius greater than 4.0 are negligible.
The maximum value of W c
is 9.6
x 10
-5
scms. n values also vary with fracture radius. For Fit-k simulations n is 1.7 for the baseline case (0 radius) (Fig. 4.6-4). n then increases to 1.9 as fracture radius increases.
For the Low-k simulations n is 2.3 for the baseline, and decreases to 1.4 for a fracture radius of 1.0 m (Fig. 4.6-5). However, n then increases and approaches a value of 2.0 at a fracture radius of 5.0 m.
4.6.2.2.2
Fracture Aperture
Fracture aperture simulations considered air sparging into a well intersecting a
1.55-m-radius sand-filled fracture with four different apertures: no fracture (0.0), 1.0, 2.0, and 4.0 cm. W c
consistently increased with fracture aperture for Fit-k and Low-k simulations (Fig. 4.6-6,7). The W c
values from the Fit-k simulations range from 1.7
x 10
-4 to 7.4
x 10 -4 scms (Fig. 4.6-6). W c
values from the Low-k simulations occur over a greater range, spanning nearly two orders of magnitude from 6.0
x 10
-7
to 6.6
x 10
-5
scms
(Fig. 4.6-7).
The greatest rate of increase for W c
values from the Fit-k simulations occurs between fracture apertures 0.0 and 1.0 cm; W c
increases from 1.7
x 10
-4
to 5.0
x 10
-4
scms over this range (Fig. 4.6-6). Fracture aperture increase from 1.0 to 2.0 cm produced a slight increase in W c
, from 5.0
x 10
-4
to 6.1
x 10
-4
scms. A change in aperture from 2.0 to

104
4.0 cm produced an even smaller change in W c
, from 6.1
x 10
-4
to 7.4
x 10
-4
scms. The Fitk fracture aperture results are unique among the fracture geometry simulations in that W c continues to increase at a relatively high rate over the entire range of geometries that were simulated.
The effect of fracture aperture on W c in the Low-k simulations differs from the effect observed in the Fit-k simulations. In the Low-k simulations W c
increases from
6.0
x 10
-7
to 5.5
x 10
-5
scms between fracture apertures of 0 and 1.0 cm; this represents nearly all (0.8) of the total increase in W c
. W c
continued to increase from 5.5
x 10
-5
to
6.4
x 10
-5
scms for fracture apertures between 1.0 and 2.0 cm, but increases negligibly for fracture apertures between 2.0 and 4.0 cm. n values from simulations also vary with fracture aperture (Fig. 4.6-6,7). n increases from 1.7 to 1.9 as aperture increases from 0 to 4.0 cm in Fit-k simulations.
However, in Low-k simulations n decreases from 2.3 to 1.3 as fracture aperture increases from 0 to 4.0 cm.
The baseline (0.0 m radius and 0.0 m aperture) simulations were identical for each formation permeability case, and thus produced the same values of W c
(Fig. 4.6-4,6 and
4.6-5,7). The highest W c
value produced from Fit-k simulations occurred in the (aperture
= 4.0 cm, radius = 1.55 m) simulation (Fig. 4.6-6), whereas the largest Low-k value occurred in the (aperture = 1.0 cm, radius = 5.0 m) simulation (Fig. 4.6-5).

8e-4 2.2
2.1
6e-4
2.0
4e-4
1.9
2e-4
Wc n
1.8
0 1 2 3
4
1.7
Figure 4.6-6 W c
estimates from modeling as a function of fracture aperture for
Fit-k simulations.
2.2
6e-5
2.0
4e-5
1.8
2e-5
0
0 1 2 3
Wc n
1.6
1.4
4
1.2
Figure 4.6-7 W c
estimates from modeling as a function of fracture aperture for
Low-k simulations.
105

106
4.6.3
Gas Saturation Patterns
The transient development of air saturation patterns within the vicinity of sparging wells was investigated by simulating several cases using T2VOC. One set of simulations evaluated patterns of gas saturation after 3 days of injection into a well with a
1.5-m-long screen and sand pack (SP well) (Fig. 4.6-8 and Fig. 4.6-10). Another set involved evaluating gas saturation patterns after 3 days of injection into a well intersecting a 5-m-radius horizontal fracture (HF well) (Fig. 4.6-9 and Fig. 4.6-11). The fractures, or tops of the well screens, were located 12.5 m below the ground surface in the models. Small grids were used for gas saturation pattern simulations.
Two variations of each type of simulation were performed to investigate effects of formation permeability on gas saturation patterns. One variation used sand and formation parameters determined from model calibration with field data (Fit-k) (Fig. 4.6-8 and Fig.
4.6-9). The other was identical, except the formation permeability was 0.1 of the field case (Low-k) (Fig. 4.6-10 and Fig. 4.6-11). This was done because the permeability of the saprolite at the field site is an intermediate value (typical of silty sand to fine sand, according to Freeze and Cherry, 1979). The beneficial effect of a hydraulic fracture increases with the contrast between the permeability of the formation and that of the sand filling the fracture (Murdoch et al., 1994, Bradner, 2002). As a result, the Low-k simulations were run to evaluate effects of hydraulic fractures on sparging wells in formations whose permeability is an order of magnitude less than the field conditions.
The permeability used for the Low-k simulations is typical of silt to clayey-sand, according to Freeze and Cherry (1979).

107
An injection pressure of 109 kPa was used for the Fit-k SP well simulation, whereas the injection pressures used for all other simulations were greater. The other injection pressures were adjusted to higher values so that roughly the same total mass of gas entered the formation during each of the simulations. This was done so that gas saturation patterns from different wells would represent similar masses of air at similar times.
4.6.3.1
Fit-k SP Well Simulation
Early injection into the Fit-k SP well is characterized by a roughly spherical zone of increased gas saturation, S g
, centered about the well screen (Fig. 4.6-8). After 2 hours of injection the zone is roughly 4 m in diameter and the maximum S g
= 0.33, excluding
S g
values within the sand pack. As injection continues the size of the zone increases while the center moves upward (Fig. 4.6-8).
The upper edge of the gas-bearing zone reaches the water table after approximately 3 hours of injection (Fig. 4.6-8). At this time, the affected zone contains a roughly spherical region 4.5 to 5 m in diameter centered on the well screen where S g
is relatively high (0.4 to 0.45, shown as green in Fig. 4.6-8). The roughly spherical region is enveloped, and overlain, by a region where gas saturation is less (0.1 to 0.2, shown as light blue in Fig. 4.6-8). The region of low gas saturation forms a column over the well screen, and the diameter of the gas-bearing zone increases as the water table is approached (Fig. 4.6-8). The shape of the gas-bearing zone after 1 day of injection resembles an upwardly flared bowl (Fig. 4.6-8). The maximum radius of the gas-bearing zone is approximately 7 m at the depth of the initial water table, and narrows to 3 to 4 m at the depth of the well screen. The gas-bearing zone extends approximately 1.5 m below

108
Figure 4.6-8 Gas saturation plots at different sparging times and mass flow with time from Fit-k SP simulation.

109
Figure 4.6-9 Gas saturation plots at different sparging times and mass flow with time from Fit-k HF simulation.

110
Figure 4.6-10 Gas saturation plots at different sparging times and mass flow with time from Low-k SP simulation.

111
Figure 4.6-11 Gas saturation plots at different sparging times and mass flow with time from
Low-k HF simulation.

112 the well screen. The rate at which the gas-bearing zone increases in size slows after 1 day of injection. Even though the size remains roughly constant, S g
continues to increase within the gas-bearing zone as injection continues.
The mass flow rate in the Fit-k SP well simulation increases continuously throughout the 3-day-long injection period (Fig. 4.6-8). Mass flow increases rapidly at the initiation of injection, and then the rate of increase diminishes with time. The mass flow rate after 3 days of injection is approximately 1.0
x 10
-2
scms. The flow rate is 0.70 of this value at 8 hours of injection time, and is 0.90 of this value at 1 day injection time
(Fig. 4.6-8).
4.6.3.2
Fit-k HF Well Simulation
The effects of a flat-lying hydraulic fracture on gas saturation patterns in the Fit-k
HF well simulation are relatively subtle (Fig. 4.6-9). The significant differences resulting from the fracture occur during the early periods of injection. Most notably, S g
values within the fracture reach 0.3 as far as 1 m away from the well screen within 30 minutes.
The gas-bearing zone grows during early injection periods similarly to the SP well case; however, instead of being spherical it is elongate in the horizontal direction (Fig. 4.6-9).
The maximum diameter of the gas-bearing zone is 6 m after 2 hours of injection, whereas it is 4 m when the fracture is absent. The time taken for the upper edge of the gas-bearing zone to intersect the water table is approximately 1.5 hours, or 0.6 the time taken in the non-fractured case. However, after 3 days of injection the gas saturation patterns in the two cases are virtually identical (Fig. 4.6-8 and 4.6-9).
The mass flow rate in the Fit-k HF well simulation increases more quickly than it does in the Fit-k SP well simulation. The mass flow after 8 hours of injection is 0.90 of

113 the maximum flow, 9.0
x 10
-3
scms, reached after 3 days of injection. The mass flow rate in the Fit-k HF well simulation reaches a pseudo-steady value after approximately 2 days of injection, whereas the mass flow rate in the Fit-k SP well simulation was still increasing after 3 days of injection.
4.6.3.3
Low-k SP Well Simulation
The geometry of the gas-bearing zone in the Low-k SP well simulation (Fig. 4.6-
10) is similar to the Fit-k SP well simulation (Fig. 4.6-8). However, a longer period is required for the upper edge of the gas-bearing zone to intersect the water table. In the
Low-k SP well simulation the water table is reached after 8 hours of injection, which is
3.2 times longer than in the Fit-k simulation. The radius of the gas-bearing zone during early injection times is smaller in the Low-k simulation than it is in the Fit-k simulation.
However, as injection continues the radius of the zone in the Low-k simulation exceeds that of the simulations using Fit-k. After an injection period of 1 day the radius in the
Low-k simulation is 1.5 times larger, and after 3 days it is 2.25 times larger than the radius from the Fit-k simulation. The maximum radius of the gas-bearing zone from
Low-k simulation is 12 m at the elevation of the water table and 8 m at the elevation of the well screen. The increase in affected volume is due to a relatively broad region of low S g
( < 0.2, shown as light blue in Fig. 4.6-10) around the periphery of the gas-bearing zone.
The mass flow increases more slowly in the Low-k simulation (Fig. 4.6-10) than it does in the Fit-k simulation (Fig. 4.6-8). The rate at which mass flow increases after 3 days of injection is faster in the Low-k simulation than it is in the Fit-k simulation. Initial

114 mass flow rate is less in the Low-k simulation, but at later injection times (t >1.5 days) mass flow rate surpasses that of the Fit-k simulation (Fig. 4.6-8 and 4.6-9).
4.6.3.4
Low-k HF Well Simulation
The development of the gas-bearing zone observed in the Low-k HF well simulation is strikingly different from the other three cases (Fig. 4.6-11). In the Low-k
HF well simulation, S g
exceeds 0.2 along the entire length of the fracture before air enters the formation, whereas air enters the formation before gas reaches the tip of the fracture in the Fit-k HF well simulation. The gas-bearing zone then begins to develop over the entire length of the fracture (Fig. 4.6-11), as compared to the zone that develops in the vicinity of well screen in the other simulations (Fig. 4.6-8). A region of increasing S g preferentially grows around the tip of the fracture during early injection times. This region continues to grow and gas first reaches the water table over the tip of the fracture approximately 5 m from the well, which differs from the other 3 cases where the water table is initially breached adjacent to the well. This produces a region of relatively low
S g
(0.1 to 0.2) that is enveloped by a region with higher gas saturation (Fig. 4.6-11). This pattern of flow rates that decrease initially differs from the other 3 examples, but it is consistent with field observations and other simulations involving hydraulic fractures
(Fig. 4.5-2, Fig. 4.6-15). Air reaches the water table after approximately 20 hours of injection, which is far longer than the other simulations. The radius of the gas-bearing zone is 14 m at the water table and 5.5 m at the well screen, which is the largest gasbearing zone of the four simulations (Fig. 4.6-11).
In the Low-k HF well simulation mass flow decreases during the first hour of injection, then increases with time as injection continues (Fig. 4.6-11). The early time

115 flow rates from the Low-k HF simulation are less than early time flow rates from any of the other simulations. Whereas, late time flow rates from the Low-k HF simulation are greater than those from other simulations.
4.6.4
Radius of Influence
T2VOC simulations were used to investigate the effect that fracture radius has on a sparging well radius of influence. Two sets of simulations were performed. In one set field calibrated formation permeability was used (Fit-k), whereas in the other formation permeability was decreased (Low-k). The permeabilities used in simulations correlate to the k s
/k f
=18 and k s
/k f
=10000 values used to characterize formation permeability effects on W c
(Table 4.6-2). Each set of simulations was conducted with 15 different fracture radii, ranging from no fracture (0.0 m) to 5.0 m. The fracture aperture in each simulation was 1.0 cm. The simulated sparging time for each run was 3 days. Small grids were used for radius of influence simulations.
The injection pressure used for the Fit-k simulations is 138 kPa. The injection pressure for the Low-k simulations was adjusted to 270 kPa so that the estimated radii of influence for both 0.0 m fracture radii simulations were similar, about 2.3 m. This similarity provided a baseline for comparison.
The radius of influence in each simulation was determined by analyzing plots of gas saturation (Fig. 4.6-12). The radius of influence was assumed to be the linear distance from the well casing to the point at which the S g
= 0.1 contour intersected the original position of the water table. The S g
= 0.1 contour was used based on work by
McCray and Falta, (1996).

116
Radius of Influence
S g
= 0.1 contour
Figure 4.6-12 Radius of influence as distance from the well casing where S g
= 0.1 contour intersects original position of the water table.
Radius of influence estimates for the Fit-k case range from 2.3 to 5.4 m (Fig. 4.6-
13). More than 95% of the total change in radius of influence occurs as the fracture radius increases to 0.35 m. The radius of influence increases little with fracture radii between 0.35 and 1.0 m (Fig. 4.6-13). The increase in radius of influence is negligible for fracture radii larger than 1.0 m.
The radius of influence for the Low-k case ranged from 2.4 to 12.2 m, which is more than 3 times larger than the range from the Fit-k case (Fig. 4.6-13). The rate of radius of influence change is greatest at small fracture radius, similar to the Fit-k example. However, the radius of influence increases throughout the entire range of fracture radii for Low-k simulations, whereas radius of influence reaches a maximum for
Fit-k simulations (Fig. 4.6-13). At fracture radii larger than 0.95 m, the radius of influence increases linearly with a slope of 1.3.

117
12
10
8
6
4
2 kf = 1.5 x 10
-15 kf = 8.3 x 10
-13
0
0 1 2 3
Fracture Radius (m)
4 5
Figure 4.6-13 Radius of influence as a function of fracture radius from modeling results for two formation permeability cases.
4.6.5
Anisotropy
Simulations were conducted to characterize the sensitivity of the Injection
/Recovery Tests to differences in formation permeability anisotropy. It was hypothesized that formation properties promoting horizontal flow and inhibiting vertical flow may affect volumes of air recovered during testing. A high horizontal permeability component may increase the volume of air near the screen, and could therefore affect the volume that flows back during recovery. Simulations of the Injection/Recovery Tests were conducted to evaluate this hypothesis.
All Injection/Recovery Test simulations used the large grid SP well model, with a
1.5-m-long screen and sand pack. The simulations were conducted by injecting at 207

118 kPa for 2 hours, then decreasing injection pressure to 0 kPa for 2 hours, allowing air to flow back through the simulated well casing to the ground surface.
Simulations were conducted representing horizontal to vertical permeability ratios (k h
/k v
) of 1, 10, 100, and 1000. A permeability of 7.5
x 10 -13 m 2 was selected to represent the isotropic case. The directional permeabilities were then changed, making horizontal permeability whole orders of magnitude greater than vertical permeability.
Each of the three anisotropic cases were simulated, then permeabilities were adjusted while maintaining the appropriate k h
/k v
until the total air mass that entered during the injection period was approximately 100 m
3
(Table 4.6-4). This was done assuming that if similar volumes entered during the injection periods, then the differences in total volume returned and pattern of return would be solely functions of formation properties.
The permeability ratio values are used to refer to individual simulation results; however, the ratio value is specific only to permeability values that allow approximately 100 m 3 of air to be k h
/k v
1
10
100
1000 k h
(m
2
) k v
(m
2
)
7.5x10
-13
7.5x10
-13
1.45x10
-12
1.45x10
-13
2.4x10
-12
3.7x10
-12
2.4x10
-14
3.7x10
-15
Table 4.6-4 Directional permeabilities used for each k h
/k v
case. injected in a 2-hour period.
Anisotropy affects the pattern of mass flow with time during the injection period.
In the isotropic case mass flow increases over the entire injection period, however, the rate of mass flow increase slows with time (Fig. 4.6-14). The mass flow histories during injection change as k h
/k v
increases. The change is characterized by an increase in the slope (dQ/dt) at early injection times, and a decrease in dQ/dt at later injection times.

20
15
10
Isotropic
10 X
100 X
1000 X
5
0
0 50 100
Time (min)
150 200
Figure 4.6-14 Mass flow verses time plot of results from Injection/Recovery Test modeling with different states of anisotropy. k h
/k v
1
10
100
1000
Mass In (scm) Mass Out (scm) Ratio Rec.
99.3
99.4
101.2
102.8
13.8
21.4
23.0
21.4
0.14
0.22
0.23
0.21
Table 4.6-5 Simulated air mass that entered during injection and was produced during recovery, along with ratio of injected air that was recovered for each k h
/k v
case.
119

120
The recovery phase is marked by a mass flow spike followed by a period of flow decrease (Fig. 4.6-14), and anisotropy affects the details of this curve. The maximum flow value during the spike increases with k h
/k v
. Mass flow rate decreases more rapidly when k h
/k v
is less, so total air recovered during early times is greater when k h
/k v
is greater. However, at later recovery period times mass flow rate decreases faster for larger values of k h
/k v
. Flow values become similar for all four cases after approximately
80 min of air recovery.
In the isotropic case the total air mass recovered from the well was 0.14 of the air injected (Table 4.6-5). Larger ratios of air mass were recovered from the wells in the anisotropic cases, for which the recovery values were similar (0.21-0.23) (Table 4.6-5).
4.6.6
Mass Flow Transients Modeling
Mass flow effects observed in field test data from SP and ND wells are reproduced closely by the calibrated SP and HF models. However, some mass flow features observed in the field test data from HF wells differ from calibrated model results.
For example, mass flow into HF wells in the field tends to spike and then decrease to pseudo-steady state after the initial injection pressure is applied (Phase 1) (Fig. 4.5-2).
This flow history can be observed in calibrated model results following subsequent pressure increases (Phase 2) (Fig. 4.5-3), but not following initial injection. Another transient feature observed in HF and SP well mass flow histories is oscillatory flow, which is not reproduced in field-calibrated simulations. However, idealized models were created that reproduced the transient mass flow features observed in field test results.

4.6.6.1
Phase 1 Features
121
Simulations were conducted to reproduce Phase 1 flow histories observed during
HF and SP well field tests. Formation permeability was decreased in field calibrated HF and SP models, and air was injected at constant pressure for 2 hours. Injection pressures were chosen to produce similar flow rates to facilitate comparison. A set of simulations that produced flow histories similar to those observed in field data were created by decreasing formation permeability from the field calibrated value of 8.3
x 10
-13
m
2
to 1.5
x 10
-14
m
2
. Injection pressures were 66 kPa for the HF well and 100 kPa for the SP well.
Mass flow from the HF well simulation increases sharply then decreases steadily to a pseudo-steady state rate (Fig. 4.6-15). The mass flow from the SP well simulation increases sharply, decreases sharply, and then steadily increases. Flow rate
6
5
4
3
2
1
SP Well
HF Well
0
0 20 40 60
80 100 120
Figure 4.6-15 Results from simulations of injection at constant pressure representing mass flow features observed in field testing of two well types.

122 equilibrated after 2 hours in the HF well simulation, whereas it is increasing after 2 hours in the SP-2 simulation (Fig. 4.6-15), which is similar to what was observed in field data
(Fig. 4.5-2).
4.6.6.2
Oscillatory Flow
Attempts were made to simulate oscillating flow histories using grids that were representative of field scale. The approach was to produce a simulated flow geometry that approximated flow through a single vertical channel. This was done by moving the vertical no-flow boundary from a radius of 30 m to a radius of 4 m, producing a vertical to horizontal aspect ratio of 4.5. Air was injected at a variety of constant pressures with a variety of formation permeabilities, but the flow always changed steadily and oscillations were not produced.
Flow histories with oscillations were produced in simulations that involved injection into a well with a screen located approximately 640 m below the water table
(deep well simulations). A two-dimensional, radially symmetric r-z grid was utilized for the deep well simulations. The grid contained 53 rows representing 690 m depth and 31 columns representing a 150 m radius (aspect ratio = 4.6). The outer radius of the grid constituted a no-flow boundary. The well screen was represented by a 1-m-tall grid block. The injection pressure was held constant for 60 days.
Three versions of the deep well simulation were conducted. One simulated injection into a homogenous formation using parameters representative of saprolite
(deep1) (Table 4.6-1). Another version simulated injection into a formation with a 1-mthick horizontal high permeability layer at the elevation of the well screen (deep2).
Parameters used for the high permeability material were representative of sand (Table

123
4.6-1). The other version simulated injection into a formation with a horizontal high permeability layer, along with a vertical high permeability layer oriented parallel to the well bore but offset by 1 m (deep3). The vertical high permeability layer was included to cause preferential vertical flow near the well bore, an attempt to create conditions similar to flow in vertical channels. Injection pressures were adjusted so that mass flow data could be plotted on the same graph; 120 kPa for deep1, 50 kPa for deep2, and 50 kPa for deep3.
Mass flow increases sharply during the first 0.5 days of injection, and then decreases sharply for each of the three cases (Fig. 4.6-16). The period of mass flow decrease lasts from 6 to 10 days. Mass flow then increases again and begins to oscillate.
The oscillation period remains fairly constant for each simulation; however, the period differs from one simulation to another (Fig. 4.6-16). The period of mass flow oscillations from the deep3 simulation are the shortest (approximately 13 days), completing 4 cycles in 52 days. The period of mass flow oscillations from the deep2 simulation are slightly longer (approximately 15 days), completing more than 3 oscillations in 50 days. The longest period is observed in the deep1 mass flow data
(approximately 16 days); 2 cycles are completed in 32 days, however, flow reaches a pseudo-steady value after approximately 42 days of injection.
The amplitude of the oscillations decreases with time (Fig. 4.6-16). Mass flow data from the deep2 simulation produces the largest amplitudes, followed by mass flow data from the deep3 simulation. The smallest oscillation amplitudes are observed in the deep1 data.

0.5
0.4
124
0.3
0.2
Homogenous (deep1)
Horizontal Frac. (deep2)
Hor. and Vert. Frac. (deep3)
0.1
0 10 20 30
40
Figure 4.6-16 Mass flow verses time from deep well simulations.
50 60
The gas-bearing zone increases in the sand layer out to a radius of approximately
20 m during the first day of injection in the deep2 simulation (Fig. 4.6-17). The volume of increasing gas saturation reaches a radius of approximately 16 m within the formation at the elevation of the well screen. However, after 7.5 days of injection the radius of the gas-bearing zone decreases to approximately 10 m (Fig. 4.6-17). After 10 days of injection the ground water table is reached, however, a region of relatively low gas saturation (approximately 0.04) remains about half way up the well casing (Fig. 4.6-17).
The mass flow from the deep2 simulation begins to increase after approximately
10 days of injection (Fig. 4.6-16). This event coincides with the region of relatively low gas saturation beginning to move vertically upward. The region moves vertically upward

125 approximately 130 m between 10 and 17.5 days after injection begins (Fig. 4.6-17). The region begins to move horizontally away from the well casing at this time, creating a continuous vertical column of relatively high gas saturation along the well casing. The point at which mass flow begins to decrease coincides with the development of this high gas saturation region along the well casing. The maximum mass flow value for the initial oscillation is reached after 19.5 days of injection. However, gas saturations along the well bore continue to increase after this time. After 22.5 days of injection there is a continuous region along the well bore with gas saturations > 0.05.
A region of relatively low gas saturation begins to move into this continuous region after approximately 22.5 days of injection (Fig. 4.6-17), coinciding with the period over which mass flow begins to increase (Fig. 4.6-16). The region moves horizontally towards the well casing in a manner similar to the way the region of relatively low gas saturation moved away from the well bore beginning at 17.5 days of injection. However, the region moving toward the well bore at 22.5 days of injection is at a lower elevation than the region the moved horizontally away from the well casing at 17.5 days of injection (Fig. 4.6-17). The region of relatively low gas saturation reaches the well casing at approximately 26.5 days of injection, and then begins to move vertically upward and the cycle is repeated (Fig. 4.6-16). The distance between the points where the region of relatively low gas saturation moves away from the casing and toward the casing decreases as the oscillations continue, and the system moves toward steady state.
It appears that the oscillations in flow are related to transient patterns of gas saturation. Flow decreases as the gas saturation overlying the well increases and flow increases as saturation overlying the well decreases.

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Figure 4.6-17 Plots of gas saturations from deep well simulation with hydraulic fracture.
126

127
5 DISCUSSION
Mass flow histories from constant injection pressure field tests and modeling suggest that there can be at least five stages during the transient development of air sparging (Fig. 5.1-1). Mass flow histories can vary depending on which stage of transients that the system is in when data are collected. Therefore, a fundamental understanding of mass flow transients is required to properly interpret field test and modeling data.
5.1
Mass Flow Transients
Air flow into a sparging well under ideal conditions may go through five stages of transients before steady state is reached. The first two stages (StageW1 and StageW2) represent flow that occurs prior to air entering the formation (Fig. 5.1-1). Mass flow histories from the other three stages (Stage1, Stage2, and Stage3) represent flow that occurs after air has entered the formation (Fig. 5.1-1). Some of the transient stages may be absent, or may occur rapidly in flow histories from some wells. Oscillatory flow tends to occur during Stage2 or Stage3.
5.1.1
StageW1
StageW1 begins when injection into the well is initiated. The characteristic history observed during StageW1 involves a sharp increase in mass flow followed by a sharp decrease (Fig. 5.1-1). This spike in flow represents the air mass required to increase the pressure within the well casing from atmospheric pressure to the injection

128 pressure. Therefore, the overall duration and maximum mass flow during StageW1 are dependent on injection pressure, casing volume, and restrictions between the air source and well bore.
5.1.2
StageW2
StageW2 follows StageW1 and involves a steady decrease in mass flow (Fig. 5.1-
1). StageW2 represents flow during the period when water within the well casing is displaced through the well screen. Mass flow decreases to zero during StageW2 when injection pressure is less than hydrostatic pressure plus air-entry pressure. However, mass flow continues through this stage when injection pressure is greater than hydrostatic pressure plus air-entry pressure. The duration of StageW2 depends on injection pressure, screen length and diameter, and formation permeability. The data used for early sparge slug tests are collected from StageW2 flow histories.
Stage 2 absent
Steady State
Range of flow variation
StageW2
Stage3 Stage1 Stage2
StageW1
Time
Figure 5.1-1 Idealized flow history showing the five transient phases.

129
5.1.3
Stage1
Stage1 follows StageW2 and involves a period of increasing mass flow (Fig. 5.1-
1). This stage is interpreted to represent the growth of an air-filled region in the vicinity of the well screen. Air relative permeability increases due to increasing air saturation.
Field tests showed that Stage1 in SP wells was longer than in HF wells. This is likely due to differences in gas saturation pattern development during transience (Fig. 4.6-
8,9,10,11).
When air is injected into an HF well it initially displaces water from, and flows along, the fracture. Air then flows into the formation, preferentially entering around the well screen and possibly at the fracture tip (Fig. 4.6-11). When air is injected into conventional wells it initially displaces water from the sand pack, and then enters the formation to increase gas saturation around the well screen.
Mass flow increases due to changes in relative air permeability during early injection times are smaller in HF wells than in SP wells. Much of the affected volume that develops during early injection times in HF wells is several meters away from the well screen. Effects from relative air permeability increases in this region are less than from relative air permeability increases in a region adjacent to the well screen.
5.1.4
Stage2
Stage2 involves a period of decreasing flow rate (Fig. 5.1-1). The major difference between transient mass flow histories from HF and non-fractured well field test results is that mass flow decreases to pseudo-steady state during Phase 1 in HF wells and increases to steady state during Phase 1 in non-fractured wells (Fig. 4.5-1). This

130 difference suggests that Stage2 transient flow is represented in HF well data and absent in
SP and ND well data. Early injection mass flow increases in non-fractured wells are greater than in HF wells due to preferential near screen development. However, this does not explain why mass flow decreases in HF wells.
Flow into a well can be calculated using Darcy’s Law
Q
 k
 a a
A

P

L
(21) where Q is volumetric flow rate, k a
is permeability with respect to air, μ a
is dynamic viscosity of air, A is the area available to flow, and

P

L
is the pressure gradient. Mass flow decreases with time are probably due to decreases in head gradient as the air-filled region develops. This is inferred because effective permeability and cross sectional area available for flow either remain constant or increase with time. The gradient would decrease when either

P decreases or

L increases.
A scenario that could cause a more rapid gradient decrease in HF wells than in SP wells is presented in the case of an infinite radius fracture. The geometry of the air-filled region around a sparging well can be approximated by a sphere with radius L in the conventional well case (Fig 5.1-2a), and a cylinder with radius L and thickness b in the fractured well case (Fig 5.1-2b). Assuming these geometries, L can be calculated using
non-fractured wells - L



3 V
I
4



1
3
(22)
fractured wells - L



V
I b



1
2
(23)

a) b)
131
L
L b
Figure 5.1-2 Assumed geometry of gas-bearing zones at early sparge times for a) conventional wells and b) fractured wells. where V
I
is volume of air injected, b is fracture aperture, and

is porosity (assuming complete desaturation of affected volume). If air distribution assumes these geometries, and the fracture has infinite radius with a relatively thin aperture, then L will increase at a greater rate during early injection times in HF wells. For example, if 1 m
3
of air is injected, porosity is 0.3, and fracture aperture is 1 cm, L would be 0.9 m for a nonfractured well and 10 m for a fractured well. Assuming a horizontal flow geometry, the gradient driving flow will be

P

L
, where

P is the difference between injection pressure and hydrostatic pressure at the elevation of the well screen. The pressure gradient decreases when L increases, causing flow to decrease.
L may increase with time as described above during early injection into a finite radius fracture, however, it will not increase with time during later injection into a finite radius fracture. This scenario is reproduced by modeling sparging into a well intersecting

132 a 5.1 m fracture. Mass flow begins to decrease immediately following injection initiation
(Fig. 5.1-3).
The pressure front reaches the fracture tip within a short period of time after injection begins (Fig. 5.1-4). Pressure along the fracture continues to increase with time, causing a decrease in air pressure gradient at the well screen due to a decrease in

P .
The pressure along the entire fracture radius increases to nearly injection pressure within approximately 1 hour, at which point pressure within the fracture is essentially constant.
However, flow continues to decrease until approximately 11 hours of after injection initiation, which corresponds to the point at which air initially reaches the water table according to gas saturation plots. This suggests that decreases in mass flow during injection times greater than 1 hour are due to factors associated with the development of the gas bearing zone above the fracture prior to air reaching the water table.
Modeling results suggest that fracture to formation permeability ratio is an important factor controlling whether mass flow increases or decreases to pseudo-steady state during early injection. If the fracture to formation permeability ratio is large then air displaces water from the fracture to a larger radius before it enters the formation. This flow scenario would cause the head gradient to decrease at a higher rate, therefore, causing the flow to decrease with time.

2.5
2.0
1.5
1.0
0.5
-5 0 5 10 15 20 25 30 35 40 45
Figure 5.1-3 HF Well simulation results displaying Stage2 transient flow.
240
220
200
180
1 sec
10 sec
1 min
20 min
2 hour
11 hour
48 hour
160
0 5
10 15
Figure 5.1-4 Pressure distribution along row containing fracture from HF Well simulation.
133

134
5.1.5
Stage3
Stage3 involves a period when flow rate increases (Fig. 5.1-1). The evidence for
Stage3 flow comes mostly from modeling. Analyses of gas saturation patterns from simulations suggest that the beginning of Stage3 marks the point at which injected air initially reaches the water table (4.6-17). Injected air reaching the water table would establish a continuous flow path between the well screen and the atmosphere. dL remains constant during this stage, and mass flow increases as residual water saturation within the flow path decreases and k rg increases.
It is unclear whether Stage3 flow conditions occurred in field tests on any of the wells. HF well tests show Stage1 and 2, but flow rate decreased to an apparent steady state; the increasing characteristic of Stage3 was not observed. Because mass flow continuously increased during SP and ND well tests, it may have been impossible to identify the beginning of Stage3 flow. It may also be that Stage3 is obscured by the onset of oscillatory flow. Modeling results suggest that air may not reach the water table for many hours. Therefore, injection durations longer than those used for this research may be required to observe Stage3 in field tests.
5.1.6
Oscillatory Flow
Air flow rate into the formation during sparging is a function of injection pressure and relative air permeability. Injection pressures were constant during oscillatory flow periods observed in field test data collected for this research. Therefore, the flow behavior seems to be a result of cyclic changes in relative air permeability near the well.

135
The transient cycle that causes oscillatory flow appears to involve periodic resaturation, or a process that otherwise makes gas-bearing volumes temporarily unavailable for air flow. Relative permeability increases as the air-filled region around the well screen grows during early transient development. Air preferentially enters the larger pore spaces forming flow channels (Fig. 5.1-5). Buoyancy forces begin to dominate as the volume of the channel increases until a critical volume is reached and the channel begins to rise as a bubble. The volume that was occupied by the channel is displaced by water that flows vertically downward (Fig. 5.1-5). Eventually the channel may completely detach from the gas-bearing volume around the well screen, making it temporarily unavailable to air flow. An influx of water would produce a significant drop in air relative permeability within the vicinity of the well screen, thus causing a drop in mass flow rate (Fig. 5.1-3). Flow would then increase as the invading water is again displaced and flow channels are re-opened.
This process dampens with time until the system reaches equilibrium. The system reaching equilibrium flow likely represents the development of permanent vertical flow channels, or the total volume reaching a size that is large enough to not be significantly affected by the detachment of individual channels. Increasing the injection pressure may cause the collapse of vertical flow channels, or require an enlargement of the de-saturated zone, both of which may require a re-equilibration of the system.
This conceptual model of flow in the vicinity of the well screen is similar to what is observed in deep well simulation results that produced oscillating flow (Fig. 4.6-16).
The gas saturation plots show that the affected volume develops, the upper portion detaches,

a) b) c)
136 a)
Gas-bearing region grows around well screen during initial injection. k b)
Flow channels develop, channels move up and water moves down. k c)
Water invades region around well-screen. One or more channels detach. k
Figure 5.1-5 Conceptual model describing process that creates oscillatory flow in mass flow histories.

137 and water invades the gas-bearing region (Fig. 4.6-17). The simulated flow occurs over a much larger scale than flow in the conceptual model, which may account for the longer period of simulated cycles.
5.2
Well Performance
The ultimate measures of sparging well performance are the rate at which contaminants are removed and the total mass of contaminants removed. Greater injection rates at particular pressures typically indicate better well performance; this aspect is characterized by Well Capacity Tests as described here. Radius of influence and gas distribution patterns are also important considerations and have been investigated using a variety of formation and well geometry conditions. Increasing permeability of the formation around the well screen will increase well performance.
5.2.1
Well Capacity Tests
Well Capacity is the relationship between pseudo-steady flow and injection pressure, and this function can be characterized by two parameters, W c
and n . W c
is the mass flow rate into a sparging well when injection pressure is twice hydrostatic pressure, whereas n is a measure of the curvature of mass flow as a function of pressure. The relationship in equation (9) is linear when n =1, but it has positive curvature when n >1.
When n =1 the slope of the line from equation (9) is
W c
P h
when mass flow is plotted as a function of injection pressure (dashed line in Fig. 5.2-1). When n >1 mass flow values for injection pressures greater than twice hydrostatic pressure increase at a rate that is greater than when n =1 (Fig. 5.2-1). However, mass flow values for injection pressures

138 less than twice hydrostatic pressure are greater when n =1 than when n >1 (Fig. 5.2-1).
W c
can be used alone to characterize well performance when injection pressures are approximately equal to twice hydrostatic. However, the n value must also be considered when injection pressures are significantly different from twice-hydrostatic pressure.
W c
values from ND wells are much smaller than values from HF wells, suggesting that the creation of a hydraulic fracture can increase well performance. W c values from SP and HF wells are similar (Table 4.3-1). W c
tends to increase with test duration for all completion methods, however, it increases at a greater rate for SP wells than it does for HF wells (Table 4.3-1). These results suggest that HF wells perform
5
4 n = 1, W c
= 1.0 scms n = 2, W c
= 1.0 scms
3
2
Injection pressure twice hydrostatic pressure
1
0
60 80 100 120 140 160 180 200
Figure 5.2-1 Mass flow as a function of injection pressure when n =1 and n =2.

139 better at short injection times or when total injected volumes are small, and SP wells perform better at longer injection times or when total injected volumes are large.
However, the limited time over which tests were conducted (max. 2 hours) may make conclusions about well performance at steady state uncertain. Mass flow histories from
HF Wells typically enter Stage2 transient flow after a relatively short time, whereas histories from SP Wells steadily increase to a pseudo-steady state flow rate, and Stage2
(Fig. 5.1-1) seems to be absent. Modeling results suggest that HF Well transient flow may enter Stage3 if sparging is continued for a longer period than the field tests. For example, mass flow at constant injection pressure begins to increase after 11 hours of injection for the simulation results shown in Fig. 5.1-3. With this in mind it is reasonable to assume that W c
values for HF Wells would increase at longer sparging times.
The n values obtained from fitting (9) to field data allow reasonable fits over the range of pressures applied for particular tests. The fitted function may overestimate flow values for pressures larger than those used during testing. The n and W c
estimates for the
ND Wells were most likely affected by the large increases in effective air-entry pressure
(Table 4.2-1), which would cause n estimates to be high and W c
estimates to be low.
These effects occur because air-entry pressure is not included in (14). Air-entry pressure was omitted because it only seems to be important for ND wells. n values from the 120-minute Well Capacity Tests conducted for this research are approximately 2.0, regardless of well completion method. However, n values from the 1minute and 10-minute tests are greater than 2 for ND and SP Wells, and less than 2 for
HF Wells. This discrepancy in n values may be because flow rate in SP Wells gradually

140 increases with time, whereas flow quickly decreases to a pseudo-steady value in HF wells. Pseudo-steady flow rate increased when injection pressure was increased in each of the wells. The new pseudo-steady value in HF wells is increased based on injection pressure, whereas SP Wells may also benefit from additional development of the gasbearing region adjacent to the well screen.
Increasing the total volume of sand used to create the fractures in HF wells increases both W c
and n . These results suggest that the performance of a hydraulically fractured air sparging well is strongly influenced by the volume of sand in the fracture.
Although data that could be analyzed were limited, the well that seems to perform the best is Well HF-4-725. The W c
value from the 1-minute test is more than twice that from any other well. Furthermore, the maximum mass flow at the initial injection pressure during the 120-minute-high test on Well HF-4-725 is 0.17 scms, the highest mass flow rate observed during this research.
Results from Well Capacity Tests on HF and SP wells at the Simpson Station field site suggest that the completion methods perform similarly when the small fractures are considered. However, the permeability of the saprolite at the Simpson Station field site is moderate. The greatest performance advantage of SP wells over HF wells is a longer screen. The SP wells at the Simpson station field site contain screens that are approximately 150 times longer than the HF well screens. Fracture sand to formation permeability ratio is the most important factor determining which completion method will perform best under these conditions. For example, if the fracture sand and formation material permeabilities are equal (k s
/k f
=1), then the length of the screen is the only

difference between the two well types. If this is the case, then the well with the longer screen performs better.
141
Modeling results suggest that the benefits of a sand-filled fracture increase as permeability of the formation diminishes (Fig. 4.6-3). Where the permeability of the formation is low, air flow away from the well screen preferentially occurs through the fracture (Fig. 4.6-11). The geometry of the fracture allows flow from high permeability material into the lower permeability material to take place over an interfacial area that is larger than that of the SP well.
Well Capacity modeling results suggest that the performance of wells intersecting sand-filled fractures increases as fracture radius and/or aperture increases (Fig. 4.6-
4,5,6,7). Well performance increases as fracture radius becomes larger in Fit-k and Lowk simulations. However, increasing fracture radius beyond approximately 2 m produces negligible changes in Fit-k simulations. Well performance increases over the entire range of fracture radii in Low-k simulations. The higher permeability ratio allows a greater portion of the fracture to be utilized by flow, and thus increases the area over which air enters the formation.
Well performance increases as fracture aperture becomes larger in Fit-k and Lowk simulations. However, well performance increases more consistently at larger fracture apertures in Fit-k simulations than it does in Low-k simulations. Increasing the aperture of a sand-filled fracture increases the transmissivity of the fracture. An increase in fracture transmissivity may allow for a greater portion of the fracture radius to be utilized in the Fit-k case.

142
The effect of air flowing through a sand filled fracture can be characterized using
Injection/Recovery Tests. The ratios of air mass returned are similar for most of the wells (Table 4.4-1), however, the flow from the HF wells differs from that from the SP and ND wells. Mass flow values are large during early times in the return period of HF wells, and then diminish quickly and are small after 2 hours. This most likely results from the presence of the hydraulic fracture, which serves as a high permeability conduit for the air to reach the well screen quickly.
5.2.2
Gas Distribution
According to modeling results, the development of gas-bearing regions differs according to well completion method and formation permeability. It has also been shown that the presence of a sand filled fracture has an effect on the radius of influence of a sparging well. These aspects are important in that they determine the interface surface area to air volume ratio and the total volume affected by sparging.
Results from HF Well simulations suggest that gas saturations begin to increase within the fracture before they increase within the formation (Fig. 4.6-7 and 4.6-9). Gas tends to flow to a greater radius within the fracture when formation permeability is low
(Fig. 4.6-9). Air also tends to preferentially enter the formation in the region around the tip of the fracture when formation permeability is lower.
The radius of the fracture that contains gas prior to air entry into the formation is an important control on the radius of influence of a well intersecting a hydraulic fracture.
When gas enters the formation before reaching the fracture tip then the remaining portion of the fracture is not utilized. If air preferentially enters the formation in the region

143 around the fracture tip, then the gas-bearing zone will extend horizontally beyond the tip of the fracture.
The radius of influence from k f
/k s
=18 simulations increases up to a fracture radius of approximately 1.0 m (Fig. 4.6-11). Radius of influence increases for fracture radii greater than 1.0 m are negligible. This suggests that 1.0 m of the fracture is utilized before air begins to enter the formation under k f
/k s
=18 conditions. Therefore, any fracture radius increase beyond 1.0 m has minimal effect. The radius of influence from k f
/k s
=10000 simulations continues to increase for all simulated fracture radii (Fig. 4.6-11).
This means that the maximum fracture radius that could be utilized under k f
/k s
=10000 conditions is greater than the maximum simulated fracture radius (5.05 m).
Injection/Recovery Test results may be indicative of radius of influence.
Modeling has shown that anisotropy, where the horizontal permeability is much larger than the vertical permeability, increases the mass of air produced during Injection
/Recovery Tests. This condition causes the horizontal dimension of the gas-bearing zone to increase. Presumably, increasing the horizontal spread of air will increase the radius of influence. Therefore, volume of recovered air may be an indirect measure of the radius of influence.
The gas saturation pattern observed in Low-k HF Well simulations may be beneficial to air sparging performance, because it increases the volume of water exposed to air in the sparged region (Fig. 4.6-11). The gas-bearing zone associated with SP Wells is spherical about the well screen initially, and then grows vertically up the casing (Fig.
4.6-8). Water will be displaced away from the well when the gas-bearing zone develops in this manner.

144
5.2.3
Hydraulic Performance
Slug tests provided hydraulic conductivity estimates for the formation material near the well bore, which may be indicative of well performance. According to presparge slug test data from SP Wells the formation hydraulic conductivity is between 6.0
x 10
-4
cm/s and 8.0
x 10
-4
cm/s. The hydraulic conductivity estimates obtained by testing
ND Wells were consistently lower than for SP Wells. The differences in these values are most likely due to well skin. The screened portions of ND Wells are porous polyethylene sleeves in direct contact with the formation material. The SP Wells were installed with a sand pack, which puts distance between the screen and skin-affected formation. Pumping tests were not conducted at the field site; therefore, direct measurements of well skin were not made. However, it has been shown that skin effects are diminished by reducing flux (Bradner, 2002). In ND Wells water flows through a small surface area, causing flux to be higher and skin effects to be greater. With this in mind I assume that formation hydraulic conductivity estimates from slug tests on SP Wells are more representative of in situ conditions than results from ND Wells.
The hydraulic conductivity estimates obtained for the HF Wells were 2 to 10 times greater than estimates for the ND and SP wells, suggesting that fractures may have important effects on well performance during water flow. The data also show that the effective hydraulic conductivity increases with the mass of sand in the fracture.
Hydraulic conductivity estimates from Wells HF-1-90 and HF-2-90 averaged 20 x 10
-4 cm/s, Well HF-3-180 was 23 x 10
-4
cm/s, and Well HF-4-725 was 81 x 10
-4
cm/s.

145
5.3
Changes During Sparging
Analyses of pre- and post-sparge slug test data suggest that sparging changes hydraulic conductivity determined during slug tests, and the changes depend on well completion technique. Hydraulic conductivity estimates from the ND and SP Wells decreased after sparging, and the differences were largest for the ND Wells. Possible explanations for these differences are residual air in the formation, consolidation of formation material near the well screen, and filter cake accumulation on the well screen and/or filter pack.
It is likely that pore spaces within the formation surrounding the well screen contain some residual air after sparging has taken place. This would decrease the water saturation in the region and thus decrease the relative permeability with respect to water.
A residual air saturation of 0.05 would decrease the permeability with respect to water by approximately 30%, based on relative permeability parameters estimated during model calibration. The effects of residual air saturation would likely decrease with time after sparging because air would dissolve into the aqueous phase.
The ground water recovered from wells at the site was highly turbid, with small mica flakes as the major sediment component. As water flows back into the well casings after sparging, these fine-grained particles may form a filter cake by clogging pores within the filter pack or openings on the well screen. The sediment load that is carried by water flowing towards the well screen is a function of flow velocity. For a given volume of fluid, greater flux and/or longer duration would be required if flow occurred through a smaller area. The surface area of the interface between the well screen and formation is ~
244 cm
2
for ND Wells, as opposed to a ~11700 cm
2
interface between the sand pack and

formation in the SP wells. Moreover, the screened portion of the ND Wells is porous polyethylene (small pores), which may promote the formation of filter cake as water flows back into the well.
146
Another process that could reduce effective hydraulic conductivity is the consolidation of the formation material near the well screen. Consolidation could occur because of the rapid increase in effective stress produced when the injection pressure is decreased to zero when sparging is terminated. Evidence of this type of process was observed the first time a sparge test was performed on a fractured well, before well inserts had been installed. Formation material entered the bottom of the open casing and flowed 1.5 m up into the bottom of the casing as the well recovered from air injection.
Porous polyethylene screens prevent the flow of formation material into the well, but consolidation of the formation material could occur.
The hydraulic conductivity estimates from HF wells increased or were unaffected by sparging. HF Wells may benefit from initial sparging due to the forced evacuation of residual fracturing fluid from the fracture. The biodegradation rate of gel within the fracture or formation material would also be greater due to increasing the oxygen content of the ground water during sparging. Presence of residual gel within the fracture prior to air injection would cause the effective hydraulic conductivity to be underestimated by initial slug tests. The fractured wells may be the least likely to be affected by consolidation or filter cake development. For a fracture created with 90 kg of sand, and a
1 cm aperture, the interfacial area between the fracture sand and formation would be
~170,000 cm 2 , or 15 times that of the conventional well.

147
Formation changes around the well screen that cause the effective hydraulic conductivity to decrease may also affect Entry Pressure Test results. Air-entry pressure estimates from ND Wells increase as the total number of tests conducted increases.
Consolidation and formation of a filter cake would individually or in combination effectively decrease the maximum pore size adjacent to the well bore. Air-entry pressure will increase when the pore size decreases.
5.4
Characterization of Multiphase flow parameters
Some multiphase flow parameters, such as formation permeability and effective entry pressure, can be directly estimated using the field sparging tests described here.
Others, such as permeability anisotropy, can be indirectly inferred using field tests.
Modeling of air sparging requires multiple parameters, not all of which can be measured in the field or reasonably estimated. Therefore, a model calibration process is required to obtain values for the remaining parameters.
5.4.1
Field Tests
The method used to analyze the initial portions of Injection/Recovery Test curves to estimate hydraulic conductivity gives results that are consistent with conventional methods. Results from tests on SP Wells probably provide the best estimates of formation hydraulic conductivity. This is because well skin effects are less for HF and
SP Wells than they are for ND Wells, and the Bouwer and Rice method can represent the sand pack geometry more closely than the fracture geometry.

148
Air-entry pressures obtained during Entry Pressure Tests represent the effective values for each of the wells (Table 4.2-1). It was found that the air-entry pressure of the formation could not be measured if the screen does not contact the formation. Results of
Entry Pressure Tests on ND Wells, whose screens do contact the formation, probably overestimate the formation air-entry pressure because of well skin. Therefore, under real conditions the formation air-entry pressure is difficult to measure, however, the test does provide an air-entry pressure estimate that includes well skin effects. This property would have to be considered when characterizing wells installed in similar formation, and may provide an estimate of well skin permeability based on maximum pore size.
The percentage of air recovered from the wells was relatively insensitive to well completion method. This implies that the volume of air recovered was more dependant on formation properties than completion method. Modeling results show that simulations with anisotropic formations produced larger volumes of air than the isotropic case (Table
4.6-8). However, the air mass produced during recovery roughly stayed the same as k h
/k v
increased. Permeability anisotropy may be detectable using Injection/Recovery
Tests if the volume produced from a homogenous formation with the slug test measured permeability can be characterized.
5.4.2
Model Calibration
The model calibration method described here involved a multi-step process that minimalized the residuals between measured and predicted flow rates during a 1-minute
Well Capacity Test. This method produced parameter values that were within an acceptable range and reproduced field test results reasonably well.

149
This method, like all parameter estimation methods, will work more effectively when a greater number of parameters can be fixed at known values. Estimation of the remaining parameters requires a process where some parameters are fitted while others are held constant. The groups of parameters are then switched and the process repeated.
This approach is effective when conducting simulations that may be unstable when groups of parameters are assigned extreme values by the parameter estimation software.
Ideally, initial conditions are recalculated during each simulation in the calibration process. This step was overlooked during model calibration for this research, but was found to be important for estimating mass flow at long sparging times.
5.5
Artifacts of Grid Setup
All simulations were originally conducted using the small grid. The outer radius boundary condition for the small grid is no flow. The large grid outer boundary condition is constant head, and located at a larger radial distance. When simulated injection rates were small, or injection periods short, the boundary condition effects on flow rate were small (Fig. 5.6-1). For instance, model calibration results are not significantly affected by the no flow boundary condition because total injection time was only approximately 7 min. The simulated mass flows differed by 8% after 7 min of injection in the HF Well calibration simulation.
Initial conditions (pressure and saturation distributions) were calculated prior to model calibration using initial parameters that were chosen based on estimated sand and saprolite properties. These initial conditions were maintained throughout the model calibration process and much of the original modeling. Initial conditions for grid cells

150 below the water table were accurate for all simulations; however, the water saturation distributions in the vadose zone were out of equilibrium with the fitted parameters. The initial water saturation distribution in the vadose zone caused vertically upward flow at the water table-vadose zone interface due to capillary action during simulations. This action had little effect on flow at early sparging times, however, at longer sparging times it caused flow to be overestimated due to decreases in hydrostatic pressure.
The effects of boundary conditions and initial conditions were evaluated individually, and in combination, for each simulation type. Early sparging times were not significantly affected by either condition. The tendency for initial condition effects to increase flow at later sparging times was found to be greater than the tendency for boundary condition effects to decrease flow in almost every case (Fig. 5.6-2). Boundary condition effects were negligible in some cases.
All Well Capacity Test modeling consisted of approximately 7-minute-long injection periods, and flow rates were affected little (<10 %) by boundary and/or initial conditions. These effects were investigated for each simulation type by simulating selected cases using the large grid with appropriate initial conditions. Simulation types were redone if original versions were misleading. However, some inaccuracy in mass flow magnitudes was acceptable in most cases if general trends were unaffected.

151
1.4
1.2
1.0
0.8
0.6
0.4
Small Grid
Large Grid
0.2
0.0
180 200 220 240
Figure 5.6-1 Comparison of results from HF well calibration simulations with small and large grid. Overall injection time is approximately 7 min.
12
10
8
6
4
2
Small grid, old initial conditions
Small grid, new initial conditions
Large grid, new initial conditions
0
0 1 2 3
Figure 5.6-2 Results from Fit-k SP well simulation showing boundary condition and initial condition effects.

152
6 CONCLUSIONS
This research project was designed to characterize effects of hydraulic fractures on air sparging wells. Three new two-phase well tests were designed to quantify well performance and provide insight into formation properties. Discoveries were made during analysis of field test and modeling data that provided insights into the development of sparging transients.
6.1
Mass Flow Transients
Field test results suggest that histories of air mass flow at constant injection pressure can involve periods of increasing or decreasing flow rate. The recurrence and duration of these periods are functions of flow geometry and depth of the well screen below the water table. Lundegard and LaBrecque (1995) suggested that air sparging transients consist of two periods. I propose that the first period of transients described by
Lundegard and LaBrecque (1995) may, under ideal conditions, consist of three distinct transient stages (Stages1, 2, and 3 in Fig. 5.3-1). All three stages may not always be present in mass flow histories from wells that have reached steady state. Stages1 and 2 were observed in most HF well tests, however, Stage2 was not observed in ND and SP well test histories. Stage3 occurs in theoretical analyses, but field tests conducted for this work were terminated prior to the start of Stage3. Oscillatory flow may also obscure some stage transitions.
Oscillatory flow is probably due to the periodic partial re-saturation of flow channels that develop during air injection (Fig. 4.5-4). Flow through channels becomes

153 more stable with time, and the amplitude in flow oscillation decreases with time as a result. Simulations predicted oscillatory flow histories that resemble those observed in the field (Fig. 4.6-16). These simulations effectively represent flow through a single vertical channel, which periodically partially re-saturates at a point near the center of the channel (Fig. 4.6-17).
6.2
Well Capacity Tests
Well Capacity Tests as described in this research proved to be a viable method for characterizing sparge well performance. When using Q

W c


P
I

P h
P h

 n
, well performance is quantified using two variables ( W c
, n ). Q equals W c
when injection pressure is 2 times hydrostatic. This allows W c
to be used alone to quantify well performance when baseline injection pressures are 2 times hydrostatic. n quantifies the non-linear relationship between Q and P
I
, and must be considered when injection pressure is variable. Plots of data collected during Well Capacity Tests conducted for this research range from roughly linear to positively curved (n >1).
Wells HF-1-90, HF-2-90, and HF-3-180 perform similarly to SP wells at the field site according to Well Capacity Test results. HF wells perform slightly better at low injection pressures and/or early injection times when W c
values are high and n values are low, whereas SP wells seem to perform slightly better at higher injection pressures and/or later injection times when W c
values are low and n values are high. The ND wells consistently under performed compared to the HF wells, suggesting that the creation of a hydraulic fracture can improve well performance.

154
The hydraulic fractures intersected by Wells HF 1,2, and 3 are relatively small, created with 90 to 180 kg of sand. However, Well HF-4 was created with 725 kg, which is more typical of fractures created for environmental purposes. The W c
value from 1minute tests on Well HF-4 (280 scms) is more than twice the greatest value from the other wells (130 scms) (Table 4.3-1). Oscillatory flow obscured interpretation of other tests on Well HF-4, however, mass flow rates up to 0.015 scms were observed during these tests. This flow rate is 3 times larger than any flow rate observed during testing on other wells. This suggests that increases in sand volume significantly increase the capacity of air sparging wells that intersect hydraulic fractures.
HF-1-90, HF-2-90, and HF-3-180 and SP wells perform similarly at the field site where formation permeability is moderate, approximately 8.3
x 10
-13
m
2
. However, modeling results show that HF wells will perform better than SP wells as formation permeability decreases (Fig. 4.6-3). Creating fractures with larger volumes of sand will increase fracture radius and aperture. Modeling results suggest that increasing either of these fracture characteristics can significantly increase the performance of a fractured well (Fig. 4.6-4 through Fig. 4.6-7). The beneficial effects of increasing fracture radius and/or aperture become greater as formation permeability decreases.
6.3
Gas Distribution
There are potentially beneficial effects, other than increasing flow rate, that are associated with an air sparging well that intersects a sand-filled fracture. Injected air initially displaces water from the fracture and then preferentially enters the formation at the tip of the fracture when the fracture to formation permeability ratio is sufficiently

155 large (Fig. 4.6-11). Sparging into conventional wells causes air to enter the formation near the sand pack (Fig. 4.6-8). This geometry will cause contaminated water to be displaced away from the well. However, contaminated water remains engulfed within the sparge region when air enters the formation at some horizontal distance from the well screen (Fig. 4.6-11).
The flow geometry associated with fractured wells increases radius of influence.
Modeling results suggest that the radius of influence of a sparging well increases as fracture radius increases, or as fracture to formation permeability ratio increases. A 5 m radius fracture with a permeability four orders of magnitude greater than formation permeability can increase the radius of influence by up to 6 times, according to modeling results (Fig. 4.6-13).
6.4
Injection/Recovery Tests
Results from Injection/Recovery Tests show that the mass of air produced during the recovery period is independent of well completion method. The mass of air produced from a well depends on injection rate, injection duration, and formation properties. In general, larger percentages of the injected air are produced during the recovery period when less air mass is injected. Modeling results show wells installed in anisotropic formations produce more air during the recovery period than wells installed in isotropic formations.
The manner in which flow decreases during the recovery period of
Injection/Recovery Tests differs depending on well completion method. In fractured wells mass flow rate is great initially and then decreases quickly, whereas mass flow

156 decrease is more uniform in non-fractured wells. This difference is probably due to differences in flow geometry during the recovery period. Sand-filled fractures probably act as low resistance conduits that allow air to flow from the formation to the well screen at a greater rate. Interpreting recovery histories may improve interpretation of fracture performance; however, more research is required to characterize how fracture and formation properties affect mass flow during recovery periods.
6.5
Entry Pressure Tests
Entry Pressure Tests conducted on ND wells apparently overestimate the actual formation air-entry pressure. The entry pressure obtained from field tests is approximately 30 kPa, which corresponds to the entry pressure of silt (Baker, 1997)
(Table 1.1-1). The actual entry pressure of the saprolite is probably closer to the value obtained during model calibration to field conditions (8 kPa), which corresponds to the entry pressure of a silty sand (Baker, 1997). The entry pressure determined using the ND well is probably overestimated because of skin and formation compaction around the well screen. As a result, it is an effective entry pressure that must be overcome to initiate air flow from the well into the formation.
6.6
Slug Tests
According to the results of slug tests performed on SP wells the hydraulic conductivity of the saprolite at the Simpson Station field site is approximately 7.0
x 10 -4 cm/s. Slug test results show that creating hydraulic fractures in the wells increases the effective hydraulic conductivities. Hydraulic conductivity estimates from slug tests on

157 wells intersecting relatively small fractures (HF-1,2,3) are 2 to 3 times greater, and estimates from Well HF-4-725 are approximately an order of magnitude greater than SP well estimates. Early-sparge slug tests proved to be a convenient method for estimating formation hydraulic conductivity. Early-sparge slug test estimates correlate well (r
2
=
0.85) with estimates from conventional slug test methods.