Aggressive removal of dense non-aqueous liquid (DNAPL) phase tetrachloroethylene (PCE) and trichloroethylene (TCE) under an active manufacturing

Welding the black steel casing for the horizontal ERH system and horizontal SVE

facility is the objective of an electrical resistance heating (ERH) system that was installed using horizontal drilling.  Placement of electrical resistance heating electrodes within horizontal carbon steel pipe overcame concerns about traditional, vertically installed electrodes at the site:

1. Drilling inside of the active facility would generate dust and cause vibration that would interfere with the precision machining and manufacturing work performed in the building,
2. The labyrinthine distribution of multiple milling machines of many different shapes and sizes would interfere with vertical drilling work to install the ERH electrodes under the building,
3. Interruption of the non-stop, 24-hour-a-day production schedule was unacceptable to the owners of the operation, who were not responsible for the plume beneath the building because it emanated from a neighboring former drycleaning facility, and
4. A grid of vertical ERH electrodes would severely limit placement options for a horizontal soil vapor extraction (SVE) system that was required in order to prevent vapors generated by the ERH system from entering the indoor air of the manufacturing facility.

Horizontal drilling was used to allow the 24-hour production schedule to continue and to avoid the labyrinthine of milling machines in this active facility.

The Horizontal Solution to ERH Electrode Placement

Electrical resistance heating electrodes are distributed in the subsurface to create a network of triangular electrode groupings in cross section.  The purpose of such a configuration is to optimize the distribution of heat across the target zone, from top to bottom.  One set of electrodes is placed at a shallow horizon within the target zone, and another set is placed at a deep horizon.  Shallow and deep electrodes are staggered, so that they don’t overlie each other.

Vertically the target zone reaches from 2 to 15 feet below ground surface (bgs), but horizontally it spans a 17,000 square foot area of the building.  Electrodes are placed at only two different elevations, but multiple electrodes are placed along a given horizontal traverse.  Installing electrodes within horizontal casings is therefore much more efficient than installing them in vertical casings.  The flexibility of shifting electrodes within a horizontal casing that extends 200 feet across the building is an additional benefit of using horizontal drilling to install the electrodes.  This flexibility will allow the electrical resistance heating to be optimized in the course of its operation, as some portions of the target zone remediate more quickly than others.

Hybrid ERH and horizontal SVE Wells

The shallow ERH pipes served double duty as horizontal soil vapor extraction (SVE) wells.  Alternating sections of the pipe were slotted for SVE, or solid for ERH.  This configuration avoided the logistical problem of threading SVE wells into the network of ERH electrodes.

Horizontal Electrode Pipe Installation

Heavy, rigid black steel casing with 6-inch diameter was used for installing the ERH system. Directional Technologies employed both blind and entry-exit installation methods for the horizontal ERH system.  Each black steel casing was welded onto the casing string as it advanced into the wellbore.  See the illustration at the top of this article.  The shallow wells were only 3 feet below the building slab, so the drilling method was adapted to minimize communication through cracks in the foundation.  A grout seal was emplaced around the pipe where it crossed below the building foundation in order to prevent short-circuiting of the horizontal SVE system.  Installation of the deep wells 14 feet bgs in weathered sandstone and gravel formation was challenging because of the weight and limited flexibility of the black steel casing.  In completing the ERH casing under the manufacturing facility, Directional Technologies Inc.  brought to bear its 20 years of experience directionally drilling in every form of soil, sediment or igneous and metamorphic rock.

Round-the-clock site operations using sensitive milling equipment continued unabated by the directional drilling work in yet another example of Directional Technologies’ tradition of partnering with consultants and site owners/operators to ensure successful and unobtrusive remedial system operation.

Contact Directional Technologies, Inc.
Horizontal Directional Drilling Services
Kathy Sequino
ksequino@directionaltech.com
203-294-9200

Let’s make our point up front: 1) bentonite-based drilling fluid is NOT bad for horizontal well projects; 2) it does not damage the formation; 3) it is a naturally occurring clay material that is mined; and 4) it does flush easily/adequately during horizontal well development. Most remediation professionals have designed and/or installed vertical wells at one time or another during their careers. After advancing the boring, setting the screen/riser and sand pack, the vertical driller usually pours dry bentonite chips or pellets into the annular space between the vertical well and formation. The vertical driller then adds water to hydrate the bentonite, creating a very effective seal as the bentonite swells (or “yields”).

Why are we discussing a topic that is common knowledge/practice to most remediation professionals? Because some people who claim to be experts at installing horizontal wells assert that bentonite-based drilling fluids damage the formation and cannot be adequately flushed from the annular space during development. These are false assertions that distort what actually happens when bentonite-based drilling fluid is used. These false assertions feed off of most remediation professional’s real-world experience when dry bentonite is intentionally hydrated in situ to create a seal in a vertical monitoring well. In other words, an attempt is being made to make you think that because straight bentonite hydrated in situ makes a great seal, it does the same thing when used in a drilling fluid when installing a horizontal well.

The argument turns on the fact that: 1)bentonite-based drilling fluid is hydrated ex situ and yields prior to commencing directional drilling; and 2) bentonite is a component of the directional drilling mud system, not the sole component.

Horizontal Well mud pit

A “seal” is never formed by bentonite in a horizontal well and in addition Directional Technologies, Inc. uses a proprietary process to develop the horizontal wells based on years of field experience in the oil field, the utility industry and the environmental industry. This development process results in fully functional horizontal wells.

The same horizontal remediation well professionals that criticize bentonite-based drilling mud also advocate the use of “bio-polymer” drilling muds. These are manmade products based on gaur gums and vegetable products that biodegrade after use to various types of sugars that purportedly “jump start” the bioremediation process by supplying nutrients to naturally occurring bacteria. The problem with this is that the sugars tend to enhance undesirable bacteria that can create slime that damages the formation.

Directional Technologies, Inc. develops and formulates-specific drilling fluid programs for each horizontal remediation well we install. We do not use a one-dimensional, “one-size-fits-all” drilling program. There is both a science and an art to creating the optimal drilling fluid program for each horizontal well installation. It is imperative that the selected directional drilling fluid(s) build the bore path to: 1) prevent formation damage; 2) enable safe cost efficient directional drilling/horizontal well installation; and 3) prevent bio-fouling.

Stay tuned for additional technical communications regarding the horizontal well installation process or contact us at 1-877-788-4HRW or drilling@directionaltech.com to further discuss your possible horizontal remediation system.

Poster for Post Closure Analysis in Power Point

Michael Sequino (msequino@directionaltech.com) (Directional Technologies, Inc., Wallingford, Connecticut, USA), George Losonsky, Ph.D., P.G. (glosonsky@cox.net) (Losonsky & Associates, Inc., Baton Rouge, Louisiana, USA), James R. Oppenheim (jroppenheim@sunocoinc.com) (Sunoco, Inc. Lester, PA, USA) and Kevin W. Martin, CHMM (km@acquaterra-tech.com) (Aquaterra Technologies, Inc., West Chester, PA USA)

Introduction

A major oil storage facility (MOSF) in New York was successfully remediated in the late 1990’s using a horizontal well air sparge system. The site is closed and no remedial efforts have been required since 2003. The subject property is known as Griffith Terminal, (“site”) located on the south side of Route 352 in Big Flats, Chemung County, NY. Elevated concentrations of dissolved phase hydrocarbons were detected in site groundwater monitoring wells in 1995. Non-aqueous phase liquids (NAPL) were subsequently discovered in the vicinity of a six-inch diameter petroleum product pipeline that passed under Route 352. Product inventory records indicated that approximately 50,000 gallons of product were released between 1994 and 1995, including mixed oils, gasoline, No.2 fuel oil and kerosene. The plume related to the product release encompassed approximately 15 acres. Sensitive receptors include residences with private wells, the Chemung River, and a quarry with a pond. The objectives were to prevent exposure to sensitive receptors, control the plume by preventing migration beyond the existing plume boundaries, and remediate the plume using a logical, phased implementation of the remediation program.

Geographic Setting

Site Location and Description – The subject property is known as Griffith Terminal (“site”) encompassing approximately 20 acres, located on the south side of Route 352 between the intersections of South Corning Road and Route 17 in Big Flats, Chemung County, NY. The site’s elevation is approximately 900 feet above mean sea level. The surrounding area has low topographic relief, with a shallow slope southeast toward the Chemung River, which flows adjacent to the site along the south and southeastern property boundaries. Surrounding land use includes residential properties, light commercial properties and an industrial property (Figure 1).

Description of Facility

The site is a major oil storage facility (MOSF), containing several slab-on-grade buildings, a product loading rack and six aboveground bulk petroleum storage tanks (AST) located in the approximate center of the site. The site also contains two 30,000-gallon bulk propane ASTs located in the southern portion of the site on what used to be known as the Stueben property. Approximately 15% of the property is covered by impermeable surfaces while the remainder is covered with gravel or turf (Figure 1).

Site Hydrogeology

The Corning Elmira Primary Aquifers consisting of highly permeable gravel deposits exist beneath the site. A constant rate 24-hour pumping test performed at a constant rate of 14 gallons per minute revealed calculated hydraulic parameters including transmissivity of 13,000 gallons per day per foot, storativity of 0.02 and hydraulic conductivity of 210 gallons per day per square foot, which is equal to 28.1 feet per day.

Groundwater depth varies between 9 and 17 feet across the site. Historical groundwater monitoring well data indicate that the site water table is subject to seasonal fluctuations of approximately four feet. Groundwater flow is predominantly southeast toward the Chemung River (Figure 2).

The site bedrock consists of the West Falls Group comprised of Devonian shale and siltstone. Overburden soils consist of approximately 65 feet unconsolidated glacial and fluvial deposits. Logs for groundwater monitoring, recovery, soil vapor extraction and sparge wells installed post-release indicate that silt and fine-grained sands are present at the surface, grading to well-rounded gravel and sand at 10-15 feet below ground surface (bgs). The sand and gravel layer is approximately 15-feet thick and is underlain by coarse to medium sand. A confining layer of silt and gravel is present at approximately 45 feet bgs and a second confining layer of glacial till overlies the bedrock (see Figure 3).

The recharge and product yield obtained from monitoring wells is highly variable due to the presence of zones of highly transmissive stringers or buried erosional channels which may or may not intersect the boring depending on location. It is impossible to predict the location of such zones when advancing vertical borings.

Site History

Elevated concentrations of dissolved phase hydrocarbons were detected in site groundwater monitoring wells in May 1995. This discovery triggered an investigation and non-aqueous phase liquids (NAPL) were subsequently discovered in the vicinity of a six-inch diameter product delivery pipeline that crossed under Route 352 during July 1995 (see Figure 1). The product delivery pipeline reportedly exhibited corrosion when inspected. A NAPL sample was collected and analyzed and found to be less than one year old. The greatest NAPL thickness of 2.3 feet was detected in monitoring well MW-21 in 1995. It was estimated that at least 50,000 gallons of petroleum products were released to the subsurface between 1994 and 1995. Product lost during this period included mixed oils, gasoline, No. 2 fuel oil and kerosene. An eight-inch diameter pipeline was subsequently installed to replace the six-inch pipeline.

Remedial Actions

A series of remedial actions have been implemented, including excavation, soil vapor extraction, air sparging, oil skimming and total fluids extraction using vertical wells, air sparging with horizontal wells, and wellhead treatment of water supply wells. Only the wellhead treatment is ongoing.
A combination of floating skimmers, an automatic product-only pump, an auto-skimmer, hand bailing and vacuum enhanced pumping were employed to recover NAPL from July 1995 to August 1995. Sixty tons of soil were excavated in 1996. A total phase extraction system was also installed, connected to monitoring wells MW-10, 15, 16, 17, 33 and 42 and operated from 1999 and 2000 during low water table conditions (late summer through early fall). Approximately 19,000 gallons of SPH was recovered using these combined technologies.

Conceptual Site Model

The primary means of groundwater and contaminant mobility is through buried channels of transmissive sand and gravel. Boring logs show sand and gravel lenses interbedded with less permeable silty and clayey soils. A poorly cemented bed of gravel, sand and silt occurs at 10 to 15 feet bgs and appears to act as a barrier to vertical movement of soil vapor.
The groundwater gradient is eastward toward the quarry. Groundwater fluctuates about 4 feet, creating a substantial smear zone. Free product has collected in the smear zone. This makes the subsurface amenable to air sparging and soil vapor extraction. In addition the site has a dissolved groundwater plume.

Vapor phase contamination is present throughout the area defined as underlain by free product. Lateral migration of soil vapor contamination is limited. Soil vapor contamination does not appear to extend beyond the dissolved contaminant plume.

Remedial Objectives

The plume related to the product release initially encompassed approximately 15 acres (see Figure 2). The most significant sensitive receptor is the Chemung River, adjacent to and hydraulically downgradient of the site.
Private commercial and residential wells have documented petroleum impact, including toluene, MTBE, and ethylbenzene, and are operating with point of entry treatment systems.
The site remediation objectives were to: 1) prevent impacts beyond known plume boundaries; and 2) aggressively remediate the plume in a step-wise phased approach.
• Limit the migration of product and dissolved plume to the potential receptors including potable drinking water wells in the vicinity, the quarry to the east, and the Chemung River.
• Remove free product
• Remediate soil and groundwater to established site-specific cleanup levels required by NYSDEC

Remediation Strategy

The horizontal wells were installed as part of a large field-scale program to address the groundwater plume by removing source area contaminant mass, decreasing the area of the plume that exceeds regulatory standards, promoting natural attenuation. Plume stability is the expected result of attainment of these remediation goals. Engineering analysis revealed that a total of 129 vertical wells coupled with 23 blowers would be required to remediate the entire affected area via bio-sparge technology. Analysis further revealed that only 12 horizontal bio-sparge wells coupled with 6 blowers would be required to remediate the same area. As a gross approximation the time and cost of a remedial project such as this is inversely proportional to the amount of well screen that can be placed in contact with contaminated media. For this project, the vertical well system would provide only 272 feet of well screen versus 2,650 feet of well screen for the horizontal well system. On a generalized basis it can be stated that horizontal well installation costs are greater than vertical wells; however, when assessing total life cycle costs, horizontal well systems are substantively less expensive than their vertical counterparts. In summary, the horizontal bio-sparge well option was selected on the basis of (1) large plume area, (2) expected rapid remediation versus vertical well configuration and (3) life cycle cost.

Pilot testing included conventional pump-and-treat, total fluids extraction, vacuum enhanced pump and treat, product only recovery, and soil vapor extraction. Soil vapor extraction pilot testing indicated up to 60 feet of radial influence at 10 inches of mercury, which is half the vacuum required for total fluids recovery.

Air sparge pilot testing of vertical wells indicated that dissolved oxygen (D.O.) increased significantly above ambient levels up to 44 feet away from the sparge wells. Pressure influence was detected up to 72 feet away.

Interim product recovery was achieved with direct pumping of pure product, and dual diaphragm pump recovery. Pilot testing for product recovery included conventional pump-and-treat, total fluids extraction, soil vapor extraction, and air sparging.

Horizontal Air Sparge Well System

Two networks of horizontal bio-sparge wells were installed during site remediation; the first in 1996 and the second in 1997. A perimeter network of six horizontal bio-sparge wells designed to protect the Chemung River and an adjoining quarry was installed in 1996. A second goal of installing the perimeter horizontal bio-sparge wells was to determine the constructability and effectiveness of the horizontal remediation well technology in advance of designing and installing the “Core” plume area horizontal bio-sparge well network of 13 horizontal wells in 1997. The six-well perimeter system included horizontal wells HSW-2, HSW-3, HSR-1, HSR-2, HSQ-1 and HSQ-2 (Figure 4). The core area horizontal bio-sparge wells installed in 1997 included HSW-1, HSF-1, HSF-2, HSF-3, HST-2 and HST-3. The system operated from 1996 to 2003.

Performance Evaluation

NAPL decreased from a thickness of 2.3’ in 1995 to essentially a sheen by 2003. Measured by volume, bio-sparging eliminated at least 30,000 gallons of NAPL. Soil samples collected in the release area circa 1996 uniformly and significantly exceeded regulatory criteria. Soil samples collected from the same approximate locations in the release area circa 2005 were either “non-detect” or below actionable clean-up criteria.

The estimated volume of spilled free product was 50,000 gallons. The original remediation design expected 37, 500 gallons to be recoverable. Vertical recovery wells extracted over 18,000 gallons by 1995, using various product recovery methods and by soil vapor extraction. Product recovery methods included direct product recovery, floating skimmers, and hand bailing.

The area with separate-phase hydrocarbons before the installation of the horizontal well system covered an area of 7 acres, shown in Figure 5 with a dashed outline. Product thicknesses ranged from a sheen to 0.9 feet. After the horizontal well air sparge system was shut off, no separate-phase hydrocarbons remained.

The dissolved hydrocarbon plume experienced a dramatic size reduction from 1995 to 2003 (see Figure 6). Analysis of changes in concentrations of constituents of concern over time was used to assess the effectiveness of the remediation system, and to evaluate plume stability. The slope of the natural log as a function of time describes attenuation characteristics. Decreasing concentration trends occurring both in the source area and in the downgradient plume would suggest that active remediation and natural attenuation is occurring. Increasing trends in both source and downgradient areas would indicate that the rate of contaminant loading into the
aquifer exceeded the rate of natural attenuation. Plume stability is typically indicated by unchanging concentrations.

Groundwater contaminant concentration trend analysis demonstrated steady improvement from 2000-2005. The trend analysis reveals decreasing trends in most wells at the site, suggesting that active remediation and natural attenuation has reduced the source mass and decreased the footprint area of the dissolved plume (Figure 7). In one exception, concentrations of ethylbenzene and xylene are increasing, however, this trend does not account for high concentrations that would be in a well that was excluded from the sampling and analysis because it contains separate-phase hydrocarbons.

Conclusions

Conventional wisdom says that bio-sparging is ineffective for remediating NAPL because it is not feasible to introduce sufficient quantities of oxygen across the source mass to sustain bacteria populations that use the hydrocarbons as a nutrient source. This project proves that conventional wisdom is not always reliable. At this site, bio-sparging with horizontal wells eliminated at least 30,000 gallons of NAPL at this site. NAPL bio-sparging can be successfully implemented when applied using properly designed and installed horizontal remediation wells. A horizontal well system provide significantly greater source mass contact area and oxygen quantity compared to an equivalent system of vertical wells. Horizontal remediation well systems can be very effective and less expensive at remediating large expanse plumes than vertical well systems. In addition, this project demonstrates that horizontal sparge wells can be used as very effective barriers to plume migration.

Old Version:
Battelle Remediation of Chlorinated and Recalcitrant Compounds May 2010

George Losonsky, Ph.D., P.G. (Losonsky & Associates, Inc., Baton Rouge, Louisiana)
Michael J. Sequino (Directional Technologies, Inc., North Haven, Connecticut)

ABSTRACT:

Environmental injection wells are used to deliver a variety of fluids into
porous media for the purpose of in situ soil and groundwater remediation. Injection wells
are used to deliver nutrients for enhanced bioremediation; various amendments for bioaugmentation; and potassium or sodium permanganate, or mixtures of ozone and peroxide for chemical oxidation. Remediation agents are injected in both liquid and gas states, and they have a wide range of physical properties, such as temperature, density and viscosity. Long screens are often specified in order to deliver efficiently into large soil or aquifer volumes. The screens may be vertical, horizontal, or inclined, depending on hydrogeology and plume geometry. Some screens have variable inclinations, such as horizontal screens that continue into the riser section. Complete and efficient sweep of the targeted volume of porous material is ensured if long screens are engineered to provide
uniform injection of the fluid.

Mechanical requirements for achieving uniform fluid injection center around three
design elements: pipe flow, orifice flow, and porous media flow, which are used to define
the three stages of the injection process: generation of positive pressure by the treatment
system at the ground surface; establishment of a pressure gradient through the conveyance
pipe and well screen; flow through the pipe; flow through the screen slots; and flow
into the formation. The flow process depends on physical specifications of the pipe and
screen, and on formation properties. Pipe and screen specifications include pipe material
and roughness factor; inner and outer pipe diameter; pipe inlet and outlet elevations;
length of conveyance pipe, well riser, and screen; screen slot dimensions and orifice coefficient; and open area distribution along the screen. Formation characteristics include
pneumatic or hydraulic conductivity of the formation; and hydraulic head elevation and
gradients. Sensitivity analyses provide an understanding of the relative influence of these
parameters, and guidance in focusing the design effort.

Design of an injection system accommodates boundary conditions set by the treatment
system capacity, well material properties, drilling conditions, and anticipated response
of the aquifer or soil zone to the injection process. Monitoring of wellbore and
aquifer conditions during well drilling and development provides data about subsurface
conditions that can be used to adjust and optimize the operation parameters for the injection
system. A series of examples illustrates typical and end-member cases of injection of
liquids and gases with different fluid properties, into wells made of commonly used pipe
materials, and into various geologic media.

INTRODUCTION

Efficient delivery or extraction wells are the lifeblood of effective in situ remediation
systems. A successful screen design achieves the necessary balance of screen dimensions
and operational parameters, and is appropriately tuned to material properties of the various
media involved, to achieve uniform delivery or extraction of sufficient volumes of
fluid or gas to effectively remediate the target zone. Fluids and gases used in such systems
include:

• Air
• Water
• Bioamendment solutions
• Chemical oxidant solutions
• Soil gas
• Groundwater and non-aqueous fluids

This paper examines the effect of key design parameters on the efficiency of well
screens. Although a well screen of any length should be engineered to be effective, the
design parameters discussed in this paper are especially relevant to long screens. The
need for proper screen design applies equally to vertical wells, horizontal wells, and inclined
wells.

DESIGN PARAMETERS

The size of the zone of influence of a fluid injection or soil vapor well is directly
proportional to the flow rate. For a fluid injection well, the zone of influence is proportional
to the rate of delivery of fluid into the soil formation. For a soil vapor extraction
well, the zone of influence is proportional to the extraction rate of air out of the formation.
As the flow rate increases, so does the hydraulic head gradient from an injection
well into the formation, or the negative pressure gradient between a soil vapor extraction
well and the formation. The efficiency of the fluid delivery or vapor extraction system
depends on the balance of pressures and flow rates applied at the surface, and resistance
to flow along the entire flow path, which is influenced by a series of material characteristics
encountered by the fluid or vapor, including:

• Roughness coefficient of the pipe
• Slot apertures
• Hydraulic radius of slots or orifices
• Depths of screen slots (pipe wall thickness)
• Distribution of slots along the screen (percent open area of screen)
• Hydraulic or pneumatic conductivity of the formation
• Skin factor of the well

The skin factor of the well is a measure of formation damage that develops adjacent
to the well screen, which reduces the well’s effectiveness in delivering or extracting fluid
or gas. By contrast, operation of a well can cause beneficial changes in formation adjacent
to the well screen. This process is causes the formation of a natural filter pack. This
self-development of a well depends on several key formation parameters:

• Sphericity of the grains comprising the formation
• Average diameter of the grains
• Grain size distribution, or grain sorting

During the operation of a fluid injection well or a soil vapor extraction well, the pressure
gradient within the formation depends on a series of physical parameters, many of which are
interrelated. These parameters include the material characteristics listed above, and:

• Viscosity of the injected fluid or extracted gas
• Pressure gradient along the well screen
• Flow rate of air through the well screen
• Reynolds number
• Diameter of the well
• Length of the well screen
• Length of the riser pipe
• Length and diameter of conveyance piping
• Depth of the well

The delivery of fluid into the formation or extraction of vapor out of the formation
sets up a pressure gradient from the well to the edge of the well’s zone of influence. This
pressure gradient drives fluid or vapor transfer between the well and the formation. The
steeper the pressure gradient, the faster groundwater or soil vapor will be replaced within
the pore spaces of the treatment zone. Pore fluid around an injection well becomes enriched
with the constituents of the injected fluid. Soil gas around a soil vapor extraction
well is removed from the formation by flowing into the extraction well. Various degrees
of mixing occur in both the fluid injection and soil vapor extraction processes. Treatment
of the target zone is expedited when the fluid or vapor phase is driven to move quickly
through the well’s zone of influence. Pressure gradients around the well directly impact
the rate of treatment of the target zone.

PRESSURE GRADIENT AND INJECTION RATE

Four plots of the pressure gradient as a function of the unit injection rate along the
well screen illustrate the effect of injection rate on the pressure gradient that drives the
rate of treatment of a target zone. Two plots are shown in Figure 1, representing different
open area values.

The pressure gradient is normalized with respect to the gradient. The plots show a direct
proportional increase of pressure gradient with increasing injection rate. A three-fold increase
in injection rate produces a three-fold increase in pressure gradient. The effect of screen open
area is to increase the rate at which pressure increases with increasing flow rate.
Figure 1 represents flow at low Reynolds Number values. Flow under these conditions
is considered to be laminar. Liquid injection can be designed to maintain laminar
flow through the well screen, preventing encrustation of the well. By contrast, soil vapor
extraction wells commonly develop turbulent flow conditions. The two plots in Figure 2
represent the increase in pressure gradient in response to increasing flow rates under flow
conditions with relatively high Reynolds Number values. The plots show a non-linear
increase of the normalized pressure gradient with increasing flow rate. Under these flow
conditions, the pressure gradient increases by several orders of magnitude while the flow
rate increases by integer amounts. The two plots in Figure 2 represent screen open areas
that differ by a factor of two, and illustrate the increased sensitivity of flow rate to the
pressure gradient with decreasing open area of the well screen.

SCREEN OPEN AREA AND FLOW DISTRIBUTION

Besides showing the effect of injection rate on the pressure gradient that drives the
rate of treatment, the plots above also illustrate the sensitivity of fluid injection well effectiveness to the open area along the well screen. The following example illustrates how
the efficiency of a liquid injection well is influenced by small changes in the percent open
area along the well screen. Figure 3 shows the pressure distribution and cumulative flow
rate along a properly designed, 230-foot long well screen. The left hand side of Figure 3
shows an even pressure distribution along the screen, while the right hand side shows that
the cumulative injection rate reaches 100 percent at the end of the well screen.
Small changes in open area can be detrimental to the effectiveness of the well. Figure 4 shows the impact along the well screen of a ten percent increase in open area over the optimal amount. The cumulative injection rate reaches 100 percent about 20 feet before the end of the well screen. This means that 20 percent of the screen is ineffective.

Pressure drop along a well screen may become excessive, as shown in Figure 5, if the
well specifications, such as well diameter, length, depth, and screen design do not match
the operational requirements, such as injection rate and injection pressure, and do not
take into consideration material properties of the well pipe and target formation. The red
plot on the left hand side of Figure 5 represents pressure drop, measured in feet of water.
The lower plot represents background pressure in the formation. Excessive pressure drop
can lead to a declining injection rate along the well screen, as shown on the right hand
side of Figure 6. The same engineering principles apply to the design of extraction well
screens. For example, an imbalance of vacuum and flow rate against the well specifications
and formation characteristics can lead to a large pressure drop and unacceptably
declining extraction rates along a soil vapor extraction well screen. Problems with high
pressure drop are more common under typical operating conditions for soil vapor extraction
wells than they are for fluid injection wells.
ZONED SCREENS
Problems associated with high pressure drop in an injection or extraction well can be
resolved by adjusting the well diameter or by progressively changing the open area along
the well screen. Typically, the open area is increased in 100-foot intervals toward the distal
end of a well screen, which is the point furthest away from the source or blower. This
is referred to as zoning the screen. Open area zones are designed so that the average injection
or extraction rate is constant among the zones, as illustrated in Figure 6 for a soil
vapor extraction well.

INCLINED SCREENS

Changes in screen elevation also affect flow distribution along a horizontal well. The
example in Figure 7 shows changes in fluid injection rate along the screen of a liquid injection
well with slots extending partially into the curved riser section of the well. The
screen represented on the left hand side of Figure 7 has a constant open area along the
entire screen, including the shallower portion of the screen on the left. The screen represented
on the right hand side of Figure 7 is zoned to adjust to the changing screen
elevation. As in the previous example of a soil vapor extraction well, the liquid injection
well can be designed to achieve even distribution of flow along the well by dividing the
screen into several zones with progressively changing open areas. The liquid injection
screen in the example below is divided into three sections, or open area zones.

PIPE DIAMETER

The sensitivity of pressure and air flow distribution is enhanced at high vacuum, high
air flow rate, and small well diameter. The latter is illustrated by the comparison of extraction
rates along two wells with different diameters, in Figure 8. The distribution of the
extraction rate along a 2-inch diameter screen is shown on the left hand side, and the extraction
rate along a 4-inch diameter screen is shown on the right hand side of Figure 8.
The flow rate is essentially constant in the 4-inch well, but decreases away from the
blower in the 2-inch well.

CONVEYANCE PIPING

Finally, the importance of taking into account the length or diameter of conveyance
piping between the blower or fluid source and the wellhead is illustrated by the Figure 9,
which shows the cumulative extraction rate for a soil vapor extraction well which was
designed without taking into account several hundred feet of conveyance piping. As a
result, the well produces only 70 percent of the air flow required by the design. The low
air flow rate will result in diminished performance of the remediation system. The design
must also account for changes in pipe diameter or pipe materials. Compared to the effect
of pipe diameter, the effect of pipe materials is small.
2″ SVE Well with 350′ Conveyance

CONCLUSION

Proper sizing and design of wells and well screens is essential to successful delivery
or extraction of agents used for in situ soil and groundwater remediation. The open area
of a wells screen determines its ability to distribute flow evenly along the entire length of
the screen. Screen zonation is one mechanism for equalizing flow, but equal flow can
also be achieved by adjusting well diameter or operational parameters, such as pressure
or total flow rate. Problems of variable well elevation can also be addressed with screen
zonation. Proper engineering of well screens must also account for conveyance lines.
Most important among the design considerations is that the design assumes operational
parameters that will cause sufficient volumes of fluid or gas to be delivered or extracted
for the system to effectively remediate the target soil zone, water-bearing unit, or aquifer.

Background

A Research and Development facility in central New Jersey released several thousand gallons of gasoline to the subsurface. Environmental investigations revealed that approximately 80% of the phase separated plume existed below the building. Uninterrupted operation and prevention of vapor intrusion in the facility were key factors that dictated an alternative approach to the remedial strategy. Hudson Environmental Services, Inc. of Matawan, New Jersey completed the remedial investigation, assessed remedial alternatives and proposed a remedy. Horizontal air sparge (AS) and horizontal soil vapor extraction (SVE) with vapor treatment utilizing catalytic oxidation was the recommended and selected remedy.

The Challenge Presented

Two technical approaches were available for the horizontal air sparge (AS) and horizontal soil vapor extraction (SVE) system orientation: install a series of multiple vertical wells (a number would be required inside the building) with an interconnecting subsurface piping network, or install three horizontal wells, which would pass beneath the building. Feasibility and financial analyses indicated that the horizontal well system would not disrupt business operations, be less expensive and more efficient than the traditional vertical well approach. Directional Technologies, Inc. was engaged to install the horizontal wells.

Directional Technologies at Work: Our Solution

Pilot testing and subsurface characterization provided data enabling Directional Technologies to design two horizontal air sparge wells and one horizontal soil vapor extraction well. The horizontal air sparge and horizontal soil vapor extraction wells were designed to operate at 250 cubic feet per minute (CFM). The system design included a catalytic oxidizer to destroy hydrocarbon vapors extracted from the horizontal soil vapor extraction well. The NJ Department of Environmental Protection (NJDEP) approved the remedial design following the first design submittal. Underground utilities, building footings and other subsurface structures were identified and surficially marked out prior to well installation. Directional Technologies designed the horizontal well trajectories to avoid these buried structures.
Directional Technologies used a Ditch Witch Directional Boring System to directionally drill the horizontal wells and has used this drill rig to successfully drill bores up to 12 inches in diameter and 700 feet long; while compact in size, it is extremely powerful. The directional drill rig’s compact size allows it to be used in relatively confined areas and the rubber tracks exert minimal ground pressure, minimizing risk of damage to pavement and turf. The power and two speed spindle rotation capability enabled the rig to successfully penetrate both hard and soft soil conditions encountered at the site (fine sands, silts and clays).

Directional Technologies advanced each pilot hole to the specified depth and horizontal termination point using a spade bit. Drill bit X-and-Y axis directional control and operational temperature was provided by a hand-held surface walk-over radio detection instrument. The instrument receives continuous radio signals from a battery-powered instrumentation module contained in a length of drill pipe located directly behind the drill bit. Regularly measuring drill bit temperature is important to ensure that drilling fluids are circulating through the drill bit, especially when drilling in rock.
Directional Technologies enlarged each pilot hole to a diameter of 6.5 inches using a spiral-cutting-configured back reamer drill bit designed to minimize formation displacement and compaction. Cement grout pumped through tremie pipes formed a seal in the annular space between the riser and formation. Directional Technologies developed the horizontal wells with water and a proprietary additive to flush out drilling fluid that may have entered the formation during the horizontal drilling process. Directional Technologies installed two identical horizontal air sparge wells configured as follows: 4 inch diameter, riser length: over 500 feet, screened interval: 260 feet, installed depth: 22 feet below ground surface, 7-9 feet into the water table. The single horizontal soil vapor extraction well was configured and installed as follows: 4 inch diameter, riser length: over 480 feet, screened interval: 240 feet, installed depth: 8 feet below ground surface (5-7 feet above the water table). The horizontal wells were constructed of SDR-11, a high density polyethylene (HDPE) product; Directional Technologies validated the choice of this choice product via detailed computer modeling. Modeling further dictated the need for multiple slot-zones in the horizontal soil vapor extraction well screen due to the multiple design goals of uniform air sparging and extraction and a flow rate of 250 CFM to the catalytic thermal oxidizer.

Results that Reward

The time required to achieve site remediation can be conservatively calculated from the quantity of oxygen delivered to the site by the remediation system. Directional Technologies designed/installed each horizontal air sparge well to deliver approximately 2 pounds per minute of oxygen to the subsurface, or a total of 4 pounds per minute. At this oxygen delivery rate Directional Technologies estimated that site cleanup would be accomplished in approximately one year. The horizontal air sparge and horizontal soil vapor extraction system operated from March 1999 to October 2000 and removed approximately 17,000 pounds of gasoline. The separate phase gasoline plume under the building was completely eliminated. This resulted in the NJDEP approving” no further action” for soils.

William M. Moran (The Shaw Group, Trenton, New Jersey) George Losonsky, Ph.D., P.E. (Losonsky & Associates, Baton Rouge, Louisiana)

ABSTRACT: Commercial re-development of environmentally impacted land can require aggressive remediation schedules. Effective delivery of in-situ remediation agents is a key factor in meeting deadlines. In situ chemical oxidation (ISCO) was used to remove drycleaning solvent from the subsurface beneath a large property in the Mid-Atlantic region of the United States. Directional drilling technology was used to install horizontalscreens beneath buildings, streets, and utilities. Ten parallel horizontal wells were installed to inject potassium permanganate (KMNO4) solution. Well screens were between 130 and 330 feet long. Some of the wells were installed in pairs, with screens placed in target zones at 30-foot and 40-foot depths. Aquifer tests were used to evaluate hydraulic conductivity and anisotropy. A three-dimensional, finite difference flow and transport model was used to design well screens and define operational ranges of the injection system, including flow rates and pressures. KMNO4 solution was injected in two phases. In total 140 tons of KMNO4 were mixed to create 1.75 million gallons of solution. The use of horizontal wells allowed Shaw to inject into 10 horizontal wells instead of what would have been 120 vertical wells, and minimized our footprint on the Site. The ability to inject at 10 points into 2300 feet of well screen allowed for a higher injection rate than would have been accomplished using vertical wells. This resulted in our highest injection rate of 1.03 million gallons of KMNO4 solution in a 26-day period. After 6 months the KMNO4 solution remains persistent in the formation and has reduced tetrachloroethene (PCE) concentrations from 12 mg/L to non-detectable levels.

INTRODUCTION
The Site had been a regional shopping center for 60 years, but most of the tenants had
vacated and what remained was the larger Main Parcel with abandoned buildings and a
smaller parcel with an active dry cleaning facility. Sixty years of operations of the dry
cleaning facility had resulted in soil and groundwater contamination at the Site, first
noted in 1994. In 2004, the Site was purchased from the former owners with the intent to
complete a major redevelopment of the Site for mixed commercial and residential use.

SITE SETTING
The Site is located on 35 acres in Maryland overlying the Aquia Formation, a water table aquifer with the depth to groundwater ranging from 15 to 25 feet below ground surface (bgs) at the Site. The dry cleaner is located on the Annex Parcel to the north and across a road from the Main Parcel. The underground utilities around the dry cleaner’s building, the road and its underground utilities near the source area, and utility corridors and building construction in the more downgradient area of the plume were limiting factors that made the use of a vertical injection well system impractical at this Site (Figure1).

FIGURE 1. Site setting.

CONCEPTUAL SITE MODEL
The majority of the dry cleaning solvent was released as a solution through a break in a pipe leading to the local POTW. This pipe break was located directly under the dry cleaning building. Concentrations of PCE in this discharge water were 2,000 mg/L. Concentrations of PCE in the discharge from the dry cleaning distillation unit were as high as 11,000 mg/L prior to mixing with other wastewaters from the facility. In 2004, when Shaw and Losonsky & Associates first became involved, the groundwater plume had migrated 1,600 feet from the source. The highest concentrations of PCE were found at depths of 25 to 45 feet bgs (Figure 2). There was no indication of the presence of a dense non-aqueous phase layer. Soils at the Site are primarily medium to fine sands and silty sands. The groundwater flow direction is to the south-southeast. Groundwater flow rates within this aquifer are 0.2 to 0.4 feet per day. Hydraulic conductivity generally decreased with depth. Soil oxidant demand (SOD) concentrations were determined to be 1.5 to 2.0 mg/L. There was little natural reductive dechlorination occurring even 1,600 feet from the source.

FIGURE 2. Cross-section of groundwater plume.

The placement of a sufficient number of vertical wells in the area of the plume was
impractical due to the presence of streets and underground utilities. The horizontal well
option was then explored.

HORIZONTAL WELL SCREEN DESIGN
The design of the screens for the horizontal wells was performed using modeling efforts to produce a screen pattern designed to achieve even distribution of the KMNO4 solution throughout the length of each horizontal well screen. Aquifer tests provided hydraulic conductivity and anisotropy data. A 3-D, finite difference flow and transport model of the injection wells was used to design the well screens and define operational ranges of the injection system, including flow rates and pressures. The groundwater modeling was performed using Waterloo Hydrogeologic’s Visual MODFLOW version 4.1.0.143. The model code is based on the finite difference method of solving partial differential equations describing groundwater flow. The design specifies the open area of the screen that allows uniform injection of fluid into the formation. This analysis consists of iterative calculations of pipe flow, orifice (slot) flow, and formation flow to generate the following parameters; pressure along the screen, flow through the screened pipe, and incremental and cumulative injection of fluid into the formation. The analysis requires definition of a series of pipe specifications and hydrogeologic parameters and was used to specify optimal operating conditions for each horizontal well. The model simulates the injection fluid moving down the well, through the well screen slots, and into and through the formation. The model provides the necessary open area along the length of the well screen to achieve uniformity of flow. The necessary open area requirements for the 10 wells ranged from 0.0357 to 0.0429 percent open area. Using a standard slot width of 0.02-inch, the required number of slots was calculated for each length of screen.

HORIZONTAL WELL INSTALLATION
Directional drilling technology (Figure 3) was used to install the horizontal wells under utility corridors, buildings, and roads during the early stages of construction of commercial and residential buildings. The horizontal well screens were placed in the heaviest contaminated zones without having to deal with interferences from underground utilities and access issues associated with drilling in public roadways. Well screens were between 130 and 330 feet long (Figure 4). The wells were drilled as blind wells, without exit points. Wells nearest the source were screened at 30 feet bgs. Wells further downgradient were paired to be screened at target zones of 30 and 40 feet bgs (Figure 5).

FIGURE 3. Directional drill rig.

FIGURE 4. Example of longer horizontal well construction.

FIGURE 5. Plan view of horizontal wells.

FIRST INJECTION
In the first phase, 56,000 pounds of KMNO4 were mixed to create 340,000 gallons of 2-
percent KMNO4 solution injected into the 10 horizontal wells. The delivery rate per unit
length of screen was generally uniform. The longest well injected at more than 16 gallons per minute. An HDPE manifold transferred KMNO4 solution to the 10 well heads.

The KMNO4 injection model developed in the design phase of the project was recalibrated using data collected during and after the first injection. Hydraulic data confirmed the accuracy of anisotropy values previously derived from analyses of a vertical pumping test performed in support of the design of the injection system. The first injection indicated zones of delayed arrival of KMNO4 between certain wells. The three-dimensional model was used to simulate the first injection, and assess various alternatives for improved delivery of KMNO4. The difference between pulsed injection, as executed during the first injection phase, and a continuous, 30-day injection of equal volume of KMNO4 solution is illustrated by the injection simulation cross sections in Figure 6. The model simulation shows that the differences between the two injection schemes are minor and appear mainly at the down-gradient edge of the injected KMNO4. The base case simulation of three horizontal wells with variable spacing is shown in Figure 7, along with an alternative injection scenario using vertical and horizontal injection wells. The base case shows a zone of delayed arrival of KMNO4 between adjacent horizontal wells, on the left hand side of Figure 7. The alternative scenario simulation shown on right hand side of Figure 7 uses vertical wells to accelerate KMNO4 delivery. The alternative scenario also illustrates minor adjustments in the distribution of KMNO4 around the horizontal wells, resulting from the vertical well injection. Cross sections of these two scenarios are shown in Figure 8. Comparison of the base case with the alternative scenario shows that the vertical wells fill in the zone of delayed arrival to similar depths as the horizontal wells. Minor impact of a vertical well on the adjacent horizontal well is seen at the downgradient edge of the injected KMNO4. The simulations shown in Figure 9 illustrate the effect of using a combination of horizontal injection and extraction wells. One well on the right hand side of Figure 9 withdraws groundwater while the other two are injecting KMNO4. This allows KMNO4 to spread more quickly into the zone of delayed arrival than in the base case, shown on the left hand side of Figure 9. These simulations of alternative injection scenarios provided valuable information that was considered in planning the second injection phase. During the injection, KMNO4 concentrations were monitored at three depths as shown in Figures 10 and 11.

FIGURE 6. Injection simulation cross sections.

FIGURE 7. Injection simulation and alternative scenario.

FIGURE 8. Base case and alternative scenario cross sections.

FIGURE 9. Injection and extraction simulation.

SECOND INJECTION
In the second phase, 84 tons of KMNO4 were injected into the horizontal wells. Then 30 tons were injected into newly installed supplemental vertical wells. The use of an automated mixing system with two 18,000-gallon mixing tanks allowed the mixing and injection of up to three tons of KMNO4 or 55,000 gallons of KMNO4 solution per shift. The batch process entailed a fire hydrant to put approximately 1,650 pounds of KMNO4 into solution. This would create 10,000 gallons of solution stored in one of the 18,000- gallon mixing tanks. Because of the combined screen length of the 10 horizontal wells, the KMNO4 solution was be pumped from the mixing tank at 115 gallons per minute. At the same time a second 10,000 gallon batch could be prepared. During this second injection, our production rate was maximized so that we were able to inject 1.03 million gallons of KMNO4 solution in a 26-day period.

PERFORMANCE EVALUATION
Monitoring wells were installed to monitor the distribution of the KMNO4 solution as
wells as the PCE concentrations.

FIGURE 10. Visual depiction of injection of permanganate.

FIGURE 11. Injection of permanganate – 90 days later.

SUMMARY
The use of horizontal wells allowed Shaw to inject into 10 horizontal wells instead of 120 vertical wells. This minimized our footprint on the Site and helped to keep our ISCO project going during heavy Site redevelopment work by our client. The ability to inject at 10 points into 2200 feet of well screen allowed for a higher injection rate than would have been accomplished using vertical wells. This resulted in an injection rate of 1.03 million gallons of KMNO4 solution in a 26-day period, our most productive period. The use of horizontal wells resulted in a shorter injection time frame than would have occurred with vertical wells and minimized impacts to our client’s development work and schedule. Horizontal wells screens were determined to be more efficient at distributing KMNO4 into the zone where the highest contamination was present. After more than 6 months the KMNO4 solution remains persistent in the formation and has reduced PCE concentrations from 12 mg/L to non-detectable levels. Our client is completing their Site redevelopment and is scheduled to open this fall.

The man on the line had just found Directional Technologies Inc.’s business card ad in the back of Trenchless Technology and he was wondering if Sequino could answer a few questions. He wanted to know if it was technically feasible to drill into the subbasement of the World Trade Center (WTC) using directional drilling technology. He wanted to know if they could bore through concrete walls and tons of steel super structure on the chance that they might locate trapped survivors. He wanted to know if Sequino would help.

The president and owner of Directional Technologies hung up the phone. She conferred with her husband, Mike Sequino, and a few hours later he headed for New York City, 90 miles away.

It had only been two days since hi-jacked airliners full of innocent passengers, had decimated the two WTC towers, symbols of the financial prowess of the Unites States. While most of America, still shell shocked, huddled around televisions waiting for the next bits of news, New York City was busy assembling a elephantine rescue effort for the thousands of missing people.

Directional Technologies was enlisted to help, but the company wasn’t alone. Police, fire and medical personnel along with countless engineers, demolition experts and soldiers were already scouring streets and giving the city support. Amongst these operations, the N.Y. DOT was working on a plan to use a directional drill to burrow through WTC debris in order to insert television inspection cameras and look for victims.

"Directional Technologies, Inc. at World Trade Center ground zero on September 11th, 2001

Directional Technologies received support from oil field companies like Schlumberger Oilfield Services, Baker Oil Tools, Houston, Geological Boring, Tacoma, Wash., Frank’s Casing Crew and Rental Tools, Lafayette, La., and television inspect companies like Underground Video, Hillsdale, N.J., Downhole Video, Oklahoma City, Hit Well, Lexington Ky., and CUES, Orlando, FLA. Also helping, companies like UEMSI, Northbrook, Ill., donated television inspection cameras for the rescue effort. Sequino reached New York City that same Thursday night. The surrounding buildings around Ground Zero were still collapsing and crews were unable to get close enough to start the operation.

“It got so chaotic. The first night One Liberty Plaza was still unstable,” said Mike Sequino, “They thought the building was coming down. We didn’t even get to talk to anyone Thursday. The rescue team had to worry about building facades falling. They had to worry about buildings falling.”

Rescue efforts continued Friday and Saturday near Ground Zero, but without much success. The team spoke with fire chiefs as workers removed rubble; then crew was looking for a spot close enough to use the drill. By early Monday morning, around 2:30 early Monday morning, around 2:30 a.m. enough debris has been cleared where a target point was being considered, that target point was the remaining portion of the stairwell in Tower One. The Fire Department of New York Believed according to Sequino that a good portion of the people trying to escaper trying to exit from this location.

“They wanted to get into the stairwell and the only want to do that was to drill through the steel of the super structure. This would require different drilling bits,” explained Mike Sequino. “Digital pictures were sent from Ground Zero to Baker Oil Tools to determine the right drill bit and Ditch Witch quickly made an attachment piece to fit the drill string.” But the debris shifted again and the conditions were simply too unstable to drill though the rubble. Monday and Tuesday, the city re-evaluate its approach. Port Authority engineers and the crew discussed drilling into the mall under the WTC while in the nearby Customs Building, but the building was again too unstable; the noise and vibration might have caused it to collapse. Unfortunately, five days of hope and expectations led to disappointment and a long trip back home.

“We spend five days down there and our guys were burned out, “said Mike Sequino, “Everyone was ready to put anything we needed at our disposal. And that was the one thing that underscored everything. Everyone did everything humanly possible to find any survivors. Firemen, policemen, people from FEMA, everyone risked their lives mulling through the rubble looking for people.”

- Written by Keith Gribbins – TRENCHLESS TECHNOLOGY October 2001

Horizontal Wells allow Rapid Clean-up of R&D Facility Gasoline Release

Background A Research and Development facility in central New Jersey released several thousand gallons of gasoline to the subsurface. Environmental investigations revealed that approximately 80% of the phase separated plume existed below the building. Uninterrupted operation and prevention of vapor intrusion in the facility were key factors that dictated an alternative approach to the remedial strategy. Hudson Environmental Services, Inc. of Matawan, New Jersey completed the remedial investigation, assessed remedial alternatives and proposed a remedy. Horizontal air sparge (AS) and horizontal soil vapor extraction (SVE) with vapor treatment utilizing catalytic oxidation was the recommended and selected remedy.

The Challenge Presented Two technical approaches were available for the horizontal air sparge (AS) and horizontal soil vapor extraction (SVE) system orientation: install a series of multiple vertical wells (a number would be required inside the building) with an interconnecting subsurface piping network, or install three horizontal wells, which would pass beneath the building. Feasibility and financial analyses indicated that the horizontal well system would not disrupt business operations, be less expensive and more efficient than the traditional vertical well approach. Directional Technologies, Inc. was engaged to install the horizontal wells.

Directional Technologies at Work: Our Solution Pilot testing and subsurface characterization provided data enabling Directional Technologies to design two horizontal air sparge wells and one horizontal soil vapor extraction well. The horizontal air sparge and horizontal soil vapor extraction wells were designed to operate at 250 cubic feet per minute (CFM). The system design included a catalytic oxidizer to destroy hydrocarbon vapors extracted from the horizontal soil vapor extraction well.

The NJ Department of Environmental Protection (NJDEP) approved the remedial design following the first design submittal. Underground utilities, building footings and other subsurface structures were identified and surficially marked out prior to well installation. Directional Technologies designed the horizontal well trajectories to avoid these buried structures.

Directional Technologies used a Ditch Witch Directional Boring System to directionally drill the horizontal wells and has used this drill rig to successfully drill bores up to 12 inches in diameter and 700 feet long; while compact in size, it is extremely powerful. The directional drill rig’s compact size allows it to be used in relatively confined areas and the rubber tracks exert minimal ground pressure, minimizing risk of damage to pavement and turf. The power and two speed spindle rotation capability enabled the rig to successfully penetrate both hard and soft soil conditions encountered at the site (fine sands, silts and clays).

Directional Technologies advanced each pilot hole to the specified depth and horizontal termination point using a spade bit. Drill bit X-and-Y axis directional control and operational temperature was provided by a hand-held surface walk-over radio detection instrument. The instrument receives continuous radio signals from a battery-powered instrumentation module contained in a length of drill pipe located directly behind the drill bit. Regularly measuring drill bit temperature is important to ensure that drilling fluids are circulating through the drill bit, especially when drilling in rock. Directional Technologies enlarged each pilot hole to a diameter of 6.5 inches using a spiral-cutting-configured back reamer drill bit designed to minimize formation displacement and compaction. Cement grout pumped through tremie pipes formed a seal in the annular space between the riser and formation.

Directional Technologies developed the horizontal wells with water and a proprietary additive to flush out drilling fluid that may have entered the formation during the horizontal drilling process. Directional Technologies installed two identical horizontal air sparge wells configured as follows: 4 inch diameter, riser length: over 500 feet, screened interval: 260 feet, installed depth: 22 feet below ground surface, 7-9 feet into the water table. The single horizontal soil vapor extraction well was configured and installed as follows: 4 inch diameter, riser length: over 480 feet, screened interval: 240 feet, installed depth: 8 feet below ground surface (5-7 feet above the water table).

The horizontal wells were constructed of SDR-11, a high density polyethylene (HDPE) product; Directional Technologies validated the choice of this choice product via detailed computer modeling. Modeling further dictated the need for multiple slot-zones in the horizontal soil vapor extraction well screen due to the multiple design goals of uniform air sparging and extraction and a flow rate of 250 CFM to the catalytic thermal oxidizer.

Results that Reward The time required to achieve site remediation can be conservatively calculated from the quantity of oxygen delivered to the site by the remediation system. Directional Technologies designed/installed each horizontal air sparge well to deliver approximately 2 pounds per minute of oxygen to the subsurface, or a total of 4 pounds per minute. At this oxygen delivery rate Directional Technologies estimated that site cleanup would be accomplished in approximately one year. The horizontal air sparge and horizontal soil vapor extraction system operated from March 1999 to October 2000 and removed approximately 17,000 pounds of gasoline. The separate phase gasoline plume under the building was completely eliminated. This resulted in the NJDEP approving” no further action” for soils.

Contact Directional Technologies, Inc.
Horizontal Directional Drilling Services
Kathy Sequino
ksequino@directionaltech.com
203-294-9200