&EPA
United States
Environmental Protection
Agency
Solid Waste and
Emergency Response
Washington, DC 20460
National Risk
Management Research
Laboratory
Cincinnati, OH 45268
EPA510-R-96-001
September 1996
How To Effectively Recover
Free Product At Leaking
Underground Storage Tank
Sites
A Guide For State Regulators
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How To Effectively Recover
Free Product At Leaking
Underground Storage
Tank Sites
A Guide For State Regulators
United States Environmental Protection Agency
Office of Underground Storage Tanks, OSWER
National Risk Management Research Laboratory,
ORD
September 1996
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Acknowledgments
This guidance manual is the result of a cooperative effort between the
Environmental Protection Agency's (EPA's) Office of Underground Storage Tanks
(OUST) and Office of Research and Development, National Risk Management Research
Laboratory (NRMRL). OUST would like to express its sincere gratitude to Evan Fan
(NRMRL) for his technical assistance and to Tony Tafuri (NRMRL) for his generous
contributions in forming this partnership. The principal authors of the document,
Charles R. Faust and Michael P. Montroy (both from GeoTrans, Inc.), deserve special
recognition for their technical expertise, responsiveness, and commitment to producing
this manual. This document underwent extensive peer review by a group of experts
drawn from EPA Headquarters, regional offices and laboratories, as well as state
regulatory agencies, universities, and private industry. Primary contributors to the
technical review process include George Mickelson (Wisconsin Department of Natural
Resources), Steve Acree (EPA Robert S. Kerr Environmental Research Laboratory),
Harley Hopkins (American Petroleum Institute), Duane Hampton (Western Michigan
University), Gary Robbins (University of Connecticut), Jack Hwang (EPA Region 3),
Delonda Alexander (Texas Natural Resources Conservation Commission), and Lisa
Lund, Dana Tulis and Debby Tremblay (all three from OUST). Other individuals who
provided valuable comments for improvement of the manual include Jane Cramer (New
Mexico Environment Department), Sandy Stavnes (EPA Region 8), Katrina Varner
(EPA Environmental Monitoring and Systems Laboratory), James Atchley (Arkansas
Department of Pollution Control and Environment), and Dwayne Conrad (Texaco
Research and Development). Special thanks are also due to OUST's outreach team
members Lela Hagan-Bijou and Kate Becker.
Hal White, P.G.
OUST, OSWER
September 1996
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CONTENTS
I INTRODUCTION I - 1
Background I" 1
Puipose 1-2
Scope And Limitations 1-3
How To Use This Manual 1-3
II THE CORRECTIVE ACTION PROCESS II - 1
Hydrocarbon Releases To The Subsurface II - 1
Risk-Based Corrective Action II - 4
Steps In Reviewing Free Product Recovery Plans II - 6
Step 1. Review Data Adequacy II - 6
Step 2. Evaluate Remedial Objectives Of The Site II - 8
Step 3. Evaluate Need For Active Free Product Recovery ... II - 9
Step 4. Evaluate Design Of Free Product Recovery System 11-10
Step 5. Evaluate Operation, Maintenance, And Monitoring
Approach II -11
Primary References II - 11
III BEHAVIOR OF HYDROCARBONS IN THE SUBSURFACE ... Ill -1
Classification And Composition Of Hydrocarbons Ill - 1
Gasolines Ill - 3
Middle Distillates HI - 3
Heavy Fuel Oils IH - 4
Phase Distribution In The Subsurface Ill - 4
Properties Of Geologic Media .111-8
Porosity HI - 9
Permeability Ill - 10
Properties Of Fluids Ill - 14
Density Ill -14
Viscosity Ill - 15
Interfacial Tension Ill - 18
Properties Of Fluids And Geologic Media Ill - 19
Capillary Pressure Ill -19
Relative Permeability Ill - 21
Wettability Ill - 24
Saturation Ill - 25
Residual Saturation Ill - 26
Groundwater Flow Conditions Ill - 27
Depth To Water Table Ill - 27
Groundwater Elevation (Hydraulic Head) Ill - 28
Relevance To Free Product Recovery Ill - 29
in
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CONTENTS
(continued)
Page
Primary References Ill - 31
IV METHODS FOR EVALUATING RECOVERABILITY OF FREE
PRODUCT IV -1
Areal And Vertical Extent Of Free Product IV - 2
Strategy For Delineation Of Free Product IV - 4
Excavations And Test Pits IV - 10
Soil Borings IV -12
Monitor Wells IV - 13
Volume Estimation IV -17
Volume Estimates Based On Release History IV - 18
Volume Estimates Based On Soil Samples IV - 20
Volume Estimates Based On Product Thickness In Wells . IV - 23
Volume Estimates Based On Extrapolation Of Free Product
Recovery Data IV - 27
Estimation Of Recovery Rates IV - 28
Bail Down Test And Pumping Tests IV - 28
Multiphase Flow Analysis IV - 30
Calculations Of Initial Free Product To Total Fluid
Recovery Ratio IV - 33
Use Of Computer Models IV - 33
Recoverability Of Free Product IV - 35
Primary References IV - 36
V HYDROCARBON RECOVERY SYSTEMS/EQUIPMENT V-l
Free Product Removal/Skimming Systems V-4
Applicability V-4
General Design Considerations V-4
Equipment Description V-5
Mechanical Skimming Systems V-5
Passive Skimming Systems V-8
System Startup V -10
Operations And Maintenance V - 10
Termination Criteria/Monitoring V-ll
Free Product Recovery With Water Table Depression V-ll
Applicability V-ll
General Design Considerations V -13
Recovery Well/Drain Network Design V-13
Basic Analysis V-13
Modeling Analysis V -16
IV
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CONTENTS
(continued)
Discharge Of Treated Groundwater V - 18
Equipment V - 18
Single-Pump Recovery Systems. V - 20
Two-Pump Recovery Systems V - 20
System Startup V - 23
Operation And Maintenance V - 23
Termination Criteria/Monitoring V - 24
Vapor Extraction/Groundwater Extraction V - 24
Applicability V - 25
General Design Considerations V - 25
Equipment V - 27
System Setup V - 27
Operation And Maintenance V - 29
Termination Criteria/Monitoring V - 29
Dual-Phase Recovery V - 30
Applicability V - 32
Equipment V - 32
System Setup V - 32
Operation And Maintenance V - 34
Termination Criteria/Monitoring V - 35
Primary References V - 38
APPENDIX Appendix -1
CHECKLIST: FREE PRODUCT RECOVERY PLAN Checklist - 1
REFERENCES References-1
GLOSSARY OF TERMS Glossary -1
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EXHIBITS
Number Title page
II-1 ASTM Risk-Based Corrective Action (RBCA) Process Flowchart II - 5
II-2 Major Steps in Reviewing Free Product Recovery Plans II - 7
III-l Gas Chromatogram Showing Approximate Ranges For Individual
Hydrocarbon Products Ill - 2
III-2 Vertical Distribution Of Hydrocarbon Phases Ill - 5
III-3 Progression Of A Typical Petroleum Product Release From An
Underground Storage Tank Ill - 6
III-4 Phase Distribution At A 30,000-Gallon Gasoline Spill Site In An Aquifer
Of Medium Sand HI. 8
III-5 Functional Characteristics Of Geologic Media Properties Ill - 9
III-6 Porosity Of Various Geologic Materials Ill - 11
III-7 Range Of Values Of Hydraulic Conductivity And Permeability Ill - 13
III-8 Functional Characteristics Of Fluid Properties Ill - 15
III-9 Density And Dynamic Viscosity Of Selected Fluids Ill - 16
III-l0 Correction To Compute Hydraulic Head In Wells Containing Free
Product Ill - 17
III-l 1 Functional Characteristics Of Properties Dependent On Both The Fluid
And The Geologic Media Ill - 20
III-12 Ratio Of Apparent To True Free Product Thickness Measured In A Monitor
Well For Various Soil Types Ill - 22
III-13 Hypothetical Relative Permeability Curves For Water And A Liquid
Hydrocarbon In A Porous Medium Ill - 23
III-14 Functional Characteristics Of Groundwater Conditions Ill - 28
III-15 Most Important Factors Influencing Free Product Recovery Ill - 30
IV-1 Features Of Methods For Delineating Extent Of Free Product IV - 5
IV-2 Sample Locations Of Wells/Well Points For Determining Groundwater
Flow Direction IV - 7
IV-3 Placement Of Observation Points For Delineation Of Free Product Plume IV - 9
IV-4 Delineation Of Free Hydrocarbon Plume Extent Using Soil Borings Or
Probes And Monitoring Wells IV - 11
IV-5 Monitoring Well Installations And Their Ability To Detect Free Product IV - 14
IV-6 Methods For Measuring Accumulations Of Free Liquid Hydrocarbons In
A Well IV-16
IV-7 Methods For Volume Estimation IV - 19
IV-8 Measured Hydrocarbon Saturation Profiles At Three Boreholes Showing
Variability Due To Vertical Heterogeneity IV - 21
IV-9 Calculation Procedure To Convert TPH Data From Soil Samples To
Hydrocarbon Saturations IV - 22
IV-10 Effects Of Falling Or Rising Water Table On Hydrocarbon Thicknesses
Measured In Wells IV - 24
IV-11 Comparison Of Seven Alternative Methods For Correlation Of Product
Thickness Measured In A Monitor Well To Actual Thickness In
The Soil IV - 26
IV-12 Sample Calculations For Estimating Initial Free Product Recovery
Rates IV - 29
VI
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EXHIBITS
(continued)
Number Title Page
IV-13 Computational Procedure For Determining Ratio Of Free Product Recovery
To Total Fluid Recovered From A Single Recovery Well IV - 31
V-l General Approaches To Free Product Recovery V-2
V-2 Comparison Of General Features Of Free Product Recovery Systems .... V - 3
V-3 Interceptor Trench With Skimming Equipment V-6
V-4 Applicability of Skimming Systems V - 7
V-5 Pneumatic Skimmer In A Single Well V - 9
V-6 Pumping Recovery System Capture Zone V - 12
V-7 Procedure To Determine Number Of Wells And Total Pumping Rate
Using Water Table Depression V-15
V-8 Sample Capture Zone Analysis V - 17
V-9 Applicability Of Water Table Depression Equipment V-19
V-10 Single-Pump System For Free Product Recovery And Water Table
Depression V - 21
V-11 Two-Pump System For Free Product Recovery And Water Table
Depression V - 22
V-l 2 Applicability Of Vapor Extraction/Groundwater Extraction Equipment. . V - 26
V-l3 Vapor Extraction/Groundwater Extraction (VE/GE) Recovery System . . V - 28
V-14 Dual-Phase Extraction Recovery Systems V-31
V-15 Applicability Of Dual-Phase Recovery Equipment V - 33
V-l 6 Summary of Advantages and Limitations of Free Product Recovery
Systems V - 36
A-l Variables Appearing In Volume Estimation Equations Appendix-1
A-2 Relationship Of Variables And Characteristics Of Free Product In
The Vicinity Of A Monitor Well Appendix-2
A-3 Parameters And Experimental Data Used In Calculating Free
Product Thickness Based On Measurements Of Free Product In
Monitor Wells Appendix-3
vn
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CHAPTER I
INTRODUCTION
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CHAPTER I
INTRODUCTION
Background
Over 315,000 releases from leaking underground storage tanks
(USTs) were reported by state and local environmental agencies as of
March 19961. EPA's Office of Underground Storage Tanks (OUST)
anticipates that at least 100,000 additional releases will be confirmed in
the next few years as tank owners and operators comply with the
December 22,1998, deadline for upgrading, replacing, or closing
substandard USTs. Each release represents a potential threat to human
health and the environment; appropriate remedial steps must be taken to
assess the risk and minimize the impact. The Federal regulations (40 CFR
280.64) state that at UST sites where investigations indicate the presence
of free product, owners and operators must remove free product to the
maximum extent practicable as determined by the implementing agency.
Typically, the implementing agency is represented by the state
environmental agency or local fire prevention office. Where the threat is
imminent (e.g., seepage of free product into basements or parking garages)
an appropriate reponse would be immediate emergency action to prevent
explosion or fire. Even where the consequences of the release are not
immediately hazardous (e.g., contamination of groundwater resources)
expeditious recovery of free product will contribute to minimizing the
costs and time required for effective corrective action.
The decision-making process for determining the most appropriate
corrective action is intended to develop a remedy to mitigate risks.
Typically, the remedial approach is described in a corrective action plan
(CAP) or other report along with target clean-up levels to be achieved in
an appropriate period of time. The corrective action specified in the CAP
may include a combination of alternative techniques (e.g., bioremediation,
soil vapor extraction [SVE]), traditional remedial methods (e.g., free
product recovery, excavation, pump-and-treat), institutional controls (e.g.,
deed restrictions), and natural attenuation. At most sites where significant
volumes of petroleum have reached the water table, free product recovery
is the first step of the remedial approach. Because free product recovery
may be initiated prior to implementing long-term corrective action using
alternative or traditional technologies, this critical step may not be
included in a CAP. The written strategy for recovering free product may
'EPA O.U.S.T. Semi-Annual, FY96 UST Activity Report
I- 1
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be presented in a variety of different formats; this guide will refer to such a
document as a free product recovery plan.
Releases of petroleum products may occur above ground (e.g.,
spills, leaks from exposed piping) or below ground (e.g., leaks from tanks
or piping). Recovery of product above the ground is relatively routine,
and effective methods for cleaning up these releases from the ground
surface, surface water bodies, or sewers and other underground conduits
are well established. Recovery of product from below the ground is
usually much more difficult, more costly, and less effective. Released
product first soaks into the soil, and only if the volume of release is large
enough will free product accumulate at the water table. The soil will
retain a significant portion of the product, but as this portion is immobile,
it does not contribute to that portion termed "free product".
This manual addresses recovery of free product below the ground
surface. A few standard technologies are typically used to recover free
product under these conditions. These methods include the following:
Simultaneous withdrawal of vapor (air and vapor phase
hydrocarbons) and fluids (groundwater and free product).
Collection of free product using skimming equipment in wells,
trenches, or excavations.
Pumping of free product by depressing the water table to enhance
migration of free product to a well or drain.
The design of any of the above remedial systems requires an
understanding of the site hydrogeological conditions and characteristics,
the types, extent, and distribution of free product in the subsurface, and the
engineering aspects of the equipment and installations.
Purpose
The purpose of this manual is to provide youstate and local
regulatorswith guidance that will help you review strategies for recovery
of free product from beneath the ground surface. The manual does not
advocate the use of one technology over another; rather it focuses on
appropriate technology use, taking into consideration site-specific
conditions.
The manual is designed to enable you to answer the following
three basic questions when reviewing a free product recovery plan.
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Is recovery of the free product necessary?
Has an appropriate method been proposed for recovering the free
product?
Does the free product recovery plan provide a technically sound
approach to remediating the site?
Scope And Limitations
This manual is intended to provide technical guidance to state and
local regulators who oversee cleanups and evaluate free product recovery
plans at petroleum release sites. It does not represent the issuance of
formal policy or in any way affect the interpretation of the regulations.
The text focuses on scientific and engineering-related
considerations for evaluating various technologies for the recovery of free
product from the subsurface. It does not provide instruction on the design
and construction of remedial systems and should not be used for designing
free product recovery plans. In addition, this manual should not be used to
provide guidance on regulatory issues, such as securing permits and
establishing cleanup standards, health and safety issues, state-specific
requirements, or cleanup costs.
This document is not intended to be used as the sole reference for
review of free product recovery plans. Rather, it is intended to be used
along with published general references (e.g., EPA, 1995; Newell et al,
1995; API, 1989,1996; and ASTM, 1995), guidance from technical
experts, information from training courses, and current journals.
The material presented is based on available technical data and
information and the knowledge and experience of the authors and peer
reviewers.
How to Use This Manual
EPA's OUST encourages you to use this manual at your desk as
you review free product recovery plans. We have designed the manual so
that you can tailor it to meet your state's or your own needs. The three-
ring binder allows you to insert additional material (e.g., state-specific
guidance on permitting and technology relevant to free product recovery)
and remove certain tools (e.g., flow charts, checklists) for photocopying.
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The wide margins in this manual were provided to enable you to add your
own notes to the text.
The manual contains the following four chapters that address the
major considerations necessary for reviewing plans for recovering free
product.
Chapter II The Corrective Action Process is an overview of free
product recovery actions. This chapter contains
information that is used in determining the complete
remedial action or interim action, the remedial objectives,
and the technology evaluation process.
Chapter III Behavior of Hydrocarbons in the Subsurface is an overview
of important properties of hydrocarbons and geologic
media that must be considered when designing a free
product recovery system.
Chapter IV Methods for Evaluating Recoverability of Subsurface
Hydrocarbons. This chapter contains discussions of the
methods used both to characterize the extent of free product
at a site as well as to estimate the volume of free product at
the water table and the rates at which it can be recovered.
Chapter V Hydrocarbon Recovery Systems/Equipment. This chapter
contains descriptions of alternative recovery technologies
and it addresses applicability, system design, and
monitoring requirements.
As appropriate, the discussion in each chapter has illustrations,
comparative tables, example calculations, flow charts, and a list of
selected key references. An appendix, a glossary of relevant terms, and a
comprehensive list of references appear at the end of the manual.
At the back of the manual, a step-by-step checklist is provided to
facilitate your review of a proposed free product recovery system. This
checklist can help you determine whether or not the free product recovery
plan contains the necessary supporting information to approve the free
product recovery system. The checklist is also designed to verify that an
appropriate technology and design have been selected for free product
recovery.
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CHAPTER II
THE CORRECTIVE ACTION PROCESS
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CHAPTER II
THE CORRECTIVE ACTION PROCESS
Releases from underground storage tanks and piping caused by
leaks, spills, or overfills may result in a subsurface accumulation of a
separate phase liquid ("free product" or "free phase") that will flow into
wells or excavations. Other terms that are sometimes used to refer to free
product include; phase separated hydrocarbons (PSH), liquid hydrocarbons
(LHC), liquid phase hydrocarbons (LPH), and nonaqueous phase liquids
(NAPL). These alternative terms also refer to separate phase liquids in the
subsurface that are not present in an amount sufficient for them to flow
readily into wells or excavations. In this situation, the petroleum
hydrocarbons represent a separate residual phase, but not a "free product"
phase.
Confirmation of a release from an underground storage tank (UST)
and/or its associated piping initiates the corrective action process. At sites
where free product is present in the subsurface, free product recovery will
be part of most corrective actions, although it may precede development of
a formal corrective action plan (CAP). Before addressing the corrective
action process, a brief overview of hydrocarbon releases to the subsurface
is presented.
Hydrocarbon Releases To The Subsurface
The release of hydrocarbons from an UST can occur under a wide
range of operational conditions and environmental settings. The extent of
any threat to human health and the environment will depend on these
release-specific conditions. Factors that significantly determine the level
of risk include the following:
Type of petroleum hydrocarbon(s) and the contaminants of
concern.
Volume and age of the release.
Contaminant migration pathways (e.g., utility trenches, sewers,
drinking water supplies) to reach receptors.
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Proximity of receptors to the site of the release. Receptors include
human and animal populations, as well as environmental receptors
(e.g., ground-water resources, surface waters, buildings, residences).
Receptor exposure pathways (e.g., ingestion of water or soil,
inhalation of vapors).
The hydrocarbons associated with UST releases are usually fuels, oils, or
lubricants and almost all are less dense than water, therefore they float on
top of the water table. Liquid phase hydrocarbons (residual and free) that
are less dense than water are also referred to by the acronym LNAPL (light
nonaqueous phase liquids). A nonaqueous phase liquid that is more dense
than water is called DNAPL (dense nonaqueous phase liquid). DNAPLs
sink throughout the saturated zone to accumulate at the bottom of the
aquifer where their movement is dictated by gravity and the topography of
the subsurface geologic layers. Solvents such as trichloroethylene and
other chlorinated hydrocarbons are DNAPLs. Some of the non-
hydrocarbon fuel additives (e.g., MTBE, ethanol) are extremely soluble
and dissolve into, and can be transported over long distances by, flowing
groundwater.
The volume and the age of the release are the factors that largely
control the potential extent of contamination in the subsurface. Small
volumes of hydrocarbons or releases detected soon after release tend to be
located near the source and can be remediated by direct removal. Large
volumes or older releases may lead to more extensive subsurface
contamination. The extent of contamination is also controlled by the
potential pathways of migration. For example, free product or dissolved
hydrocarbons may move rapidly through coarse-grained subsurface
materials or in utility beddings. If the contamination extends to points
where groundwater is used or discharged to surface water, then the risk of
potential exposure is present. The hydrocarbon vapors can pose an
explosive risk or health risk where high vapor concentrations migrate to
residences, buildings, or accessible subsurface utilities.
Hydrocarbons released to the subsurface partition into one or more
of four phases:
Vapor - Gaseous state; occurs primarily in the
unsaturated zone.
Residual - Adsorbed to soil particles and trapped within soil
pores; occurs above or below the water table.
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Aqueous - Dissolved in groundwater and soil moisture.
Liquid - Free product; held up by buoyancy at the water
table and capillary fringe, or perched above low
permeability lenses in the unsaturated zone.
If a sufficient volume of petroleum hydrocarbons is released into the
subsurface, then all four phases are generally present. As each of these
phases behaves differently, remediation will typically require a
combination of corrective action technologies. Recovery of free product is
an especially important aspect of site remediation because improper
recovery techniques can cause reduced effectiveness and transfer
significant portions of the contaminant mass into other phases.
Vapor phase hydrocarbons are found mixed with air and water
vapor in the unsaturated zone. This phase tends to be the most mobile
phase and can present an immediate threat from explosion or asphyxiation
when the vapors migrate into confined spaces such as basements and
sewers. Because of the mobility of hydrocarbon vapors, this phase can be
effectively remediated using vacuum-air flow technologies. At any given
time, the amount of vapor phase hydrocarbons at a site is typically a very
small percentage of the total mass present.
Residual phase hydrocarbons typically do not extend great lateral
distances from the source of the release, and they tend to be relatively non-
mobile. Residual hydrocarbons can persist in the environment, and
leaching of the more soluble components can continue to provide a source
of groundwater contaminants for a long period of time. As a result of
fluctuations in water table elevations, residual phase hydrocarbons can
occur either above or below the water table. This effect, known as
"smearing", can result in the immobilization of significant quantities of
previously mobile free product. Above the water table, this phase often
can be effectively remediated in situ by promoting volatilization and
stimulation of natural biological processes. Residual hydrocarbons can
occupy more than 50 percent of the total pore space in subgranular
sediments. Generally, greater amounts of residual phase hydrocarbons are
retained below the water table than above the water table.
Aqueous or dissolved phase hydrocarbons are found in soil
moisture above the capillary fringe, in groundwater in the capillary fringe,
and below the water table. Despite the relative insolubility of many
constituents of hydrocarbon fuels, some constituents (e.g., MTBE) are
extremely soluble and can migrate dissolved in groundwater a significant
distance from a site. Although dissolved hydrocarbons typically account
for a very small percentage of the total mass of hydrocarbons released,
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they represent the largest volume of contamination and are spread over the
largest area. They also represent the most probable pathway for human
and environmental exposure.
Liquid phase hydrocarbons (free product or free phase) are
characterized by having sufficient volume to saturate the geologic media
such that the liquid hydrocarbons accumulate on the water table and
readily flow into wells or excavations. Because it is the sufficiency of
volume and not physical or chemical differences that differentiate between
the liquid phase and residual phase, these two phases are often referred to
as a single phase (e.g., LNAPL). Both free phase and residual phase
hydrocarbons can contribute to the contaminant mass in the vapor (gas)
phase through evaporation and the aqueous phase through dissolution.
Sorption onto soil particles contributes the residual phase. The liquid
phase hydrocarbons may also constitute a threat to health and safety.
Risk-Based Corrective Action
Confirmation of a release from an UST initiates the corrective
action process. The objective of the corrective action process is to assess
site conditions and to implement a cost-effective response to protect
human health and the environment. Traditional approaches have applied
uniform procedures and standards to sites where the subsurface
contamination varies greatly in terms of complexity, physical and
chemical characteristics, and potential risk. Alternatively, and often more
cost effectively, the procedures and remedial objectives can be developed
based on a site-specific analysis of risk.
U.S. EPA encourages the use of risk-based decision-making in
UST corrective action programs (EPA, 1995; OSWER Directive 9610.17).
The American Society for Testing and Materials (ASTM) has issued a
"Standard Guide for Risk-Based Corrective Action Applied at Petroleum
Release Sites" (ASTM, 1995). The ASTM risk-based corrective action
(RBCA; pronounced "Rebecca") process provides a framework for a
consistent decision-making process for the assessment and response to a
petroleum release. States generally modify this approach so it is tailored
to their individual state needs. The RBCA process uses a tiered approach
where corrective action activities are tailored to site-specific conditions
and risks. Fundamental to the proper application of this approach is an
adequate site assessment. The entire procedure is comprised often steps
(Exhibit II-l). Free product recovery is typically conducted during steps 2
and 9. Consequently, state and local regulators may need to review free
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Exhibit 11-1
ASTM Risk-Based Corrective Action (RBCA)
Process Flowchart
STEP 10
Initial Silt Assessment
Conduct site invasiigaiion and complete Tier 1 Summary
Report to organza available site information regarding principal
chemical (s) ol concern, axlenl of affected environmental
media, and potential migration pathways and receptors
Sit* Clauillcatlon and Initial Reepont* Action
Classify site per specified scenarios [Table 1} and implement
appropriate initial response action.
Redassify site as appropriate following initial response actions.
interim remedial action, or additional data collection.
Titr 1 Evaluation
Identify reaton&ble potential sources, transport pathways.
and exposure pathways (us* flowchart given in Figure 2).
Sated appropriate Tier 1 rrsk-basad sunning tevils (HBSLs)
Irom Tier 1 'Look-Up Table', or other relevant criteria (taste.
odor thresholds, etc.). Compare these values with sit*
oondiliont.
Tier it Evaluation
CoBeeJ additional sfte dala as noeded
Conduct Tier 3 atsestmenl per spocitMd prooedures.
Compare Her 2 site-specific larpat tevall (SSTLs) with Xite
Tier 3 Evaluatio
Colled additional t«* dau **
Conduct Ttar 3 asMSsmant per specified prooeduf»».
Compere Tier 3 tite-specific larget levels {SSTLs) with site
conditions.
Idently eo*f*ttectiM means ot achitvtng linal corrective
action goate. indudkig cambinaiions of remediation, natural
attenuation, and institutional controls. Implement the
preferred llematnre.
r^^^^ required? ^^
^Tves
Compliance Monitoring
Condud morrloring program as needed to confirm that
corrective adion goata.are satitlied
^| No Further Action J
Source: Reprinted, with permission, from the Annual Book of ASTM
Standards, copyright American Society of testing materials, 100
Barr Harbor Drive, West Conshohoken, PA, 19428.
II-5
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product recovery systems not only as specified in the Corrective Action
Plan (CAP) but also in interim actions that may involve free product
recovery. States that are adapting the ASTM standard or developing state-
specific risk-based procedures need to determine how to review free
product recovery plans so that the steps (of the plan) are well integrated
into the rest of their program. For more information, please refer to the
ASTM standard E 1739-95.
Steps In Reviewing Free Product Recovery Plans
Following are the steps that the state regulator should take when
reviewing free product plans (see Exhibit II-2):
Determine if site data are sufficient to evaluate the need for free
product recovery and/or recovery design.
Determine if proposed free product approach is consistent with
comprehensive CAP and if remedial action objectives are clear.
Determine if active free product recovery is necessary.
Evaluate design of the free product recovery system.
Evaluate operations and monitoring plan.
A checklist based on these steps is presented at the end of the manual.
Step 1. Review Data Adequacy
The site information and data that are contained in the free product
recovery plan or CAP must provide an adequate basis for making
decisions regarding the corrective action. Information required for a CAP
is generally more extensive than that required for a free product recovery
plan. The need to implement a free product recovery system is typically
determined on the basis of site data that indicate that free product is
present and recoverable. For a CAP, the need and type of corrective action
are based on an evaluation of risks to human health and the environment.
The CAP must also consider hydrocarbons present in the vapor phase or
dissolved in the liquid phase.
The technical data necessary to evaluate a free product recovery
plan include:
II-6
-------
Exhibit 11-2
Major Steps in Reviewing Free Product Recovery Plans
c
Corrective Action Plan
Received by State
STEP 1.
Review Adequacy of Site Data.
Yes
STEP 2.
Evaluate Remedial Objectives of the Site.
Incorporate free product recovery comments
into overall review comments on CAP
Notify consultant/owner/
operator of deficiencies
approach consistent?
Are remedial action
objectives clear?
STEP 3.
Evaluate Need for Active Free
Product Recovery
Is free
product recovery
necessary?
STEP 4.
Evaluate Design of Free Product
Recovery System
STEP 5.
Evaluate Operation, Maintenance,
And Monitoring Approach
Note deficiencies
Complete review of other
aspects of CAP
Complete review of other
aspects of CAP
II-7
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Description of site.
Description of current and past operations relevant to USTs and
piping.
Information on past releases or spills.
Summary of current and completed corrective actions and
investigations.
Description of regional and site hydrogeological conditions.
Discussion of hydrocarbon phase distribution in the subsurface.
Listing of the physical and chemical properties of liquid
hydrocarbon phase.
Estimates of free product extent (maps and cross sections), free
product volumes, and recoverability.
The significance of this information and methods for obtaining it are
discussed in Chapters IV and V.
Step 2. Evaluate Remedial Objectives Of The Site
A free product recovery system is often a small part of a
comprehensive remedy that also addresses contamination dissolved in
groundwater and/or vapors in the unsaturated zone. The remedies
proposed for each medium must be compatible. For example, the
pumping and treating of contaminated groundwater may result in large
drawdowns of the water table. If large drawdowns occur in the vicinity of
the free product, then the free product may be drawn to a lower depth
where it may become immobilized (i.e., the "smearing" effect) and
contaminate previously clean aquifer materials. An example of
compatible remedies is the combination of a soil vapor extraction system
and free product recovery in moderately permeable soils. Operation of the
soil vapor extraction system may actually enhance the effectiveness of a
free product recovery system by helping to maintain a higher saturated
thickness in the aquifer than would occur with free product recovery only.
Remedial objectives should be clear, achievable, and measurable.
A remedial objective of removing all free product may be clear but not
necessarily achievable. Many free product recovery systems have the
capability to reduce the free product thickness to 0.01 foot or less,
however, they may not be cost effective to implement at a site with
II-8
-------
accumulations on the order of 0.1 foot or less. Minimal amounts of free
product will exist no matter how effective the free product recovery
system. Therefore, the remedial objective should also include success
measures such as maximum thickness of free product in wells (e.g., less
than 0.01 foot or reduction to no more than a sheen) or minimum recovery
rates (e.g., 2 gallons per month).
Step 3. Evaluate Need For Active Free Product Recovery
Active free product recovery may not be necessary (or feasible)
unless free product is present in sufficient volumes which can be
recovered effectively. The necessity for free product recovery should be
determined based on an analysis of the feasibility of collecting significant
amounts of free product. Feasibility depends not only on site conditions,
but also on the chosen technology. For example, although free product is
difficult to collect in fine-grained materials, the use of vacuum-enhanced
recovery may increase the volume of free product that can be collected.
Factors which would suggest a need for free product recovery
include:
Estimates of free product at water table that are moderate to high
(greater than 200 gallons).
Permeable aquifer (e.g., sands and gravels) or hydraulic
conductivity greater than 10"3cm/sec.
Thick accumulations of free product in wells (greater than 1.0
foot).
Nearby surface water or groundwater use (/'. e., close proximity to
receptors).
Free product recovery is generally infeasible or otherwise
unnecessary at sites where the following factors apply:
Low volumes of free product (less than 50 gallons) at the water
table.
Distant (greater than 2,500 feet from free product plume) surface
water discharge points and no nearby groundwater use.
Very low permeability media (e.g., silty clay and clay).
II-9
-------
« Thin accumulations of free product in wells (less than 0.1 foot).
Inclusion in the CAP of other remedial alternatives such as soil
vapor extraction or pump-and-treat.
The need (or lack of need) for a free product recovery system may not be
clear at all sites (e.g., those with free product volume or free product
thickness that fall between the above guidelines). However, as a general
rule, where two or more favorable factors (with respect to free product
recovery) apply to a given site, the need for free product recovery is
indicated; conversely, where three or more unfavorable factors apply, free
product recovery is generally not indicated.
Step 4. Evaluate Design Of Free Product Recovery
System
It is also necessary to verify that the design of the free product
recovery system is likely to be effective. The major design considerations
include:
Use of wells or trenches.
Number and location of wells and or trenches.
Fluid production rates, vacuum pressures, fluid elevations to be
maintained in wells or trenches.
Design of wells or trenches in terms of construction specifications
and depth.
Pumping, skimming, or vacuum equipment.
Pipelines and manifolds.
Instrumentation.
Storage, separation, and treatment facilities (not covered in this
guidance).
The rationale for the selection of the recovery approach (skimming, water
level depression and collection, or dual phase extraction) should be
checked for consistency with remedial objectives. For example,
depressing the water table is used when one of the remedial objectives for
free product recovery is to contain the free product plume.
II-10
-------
The free product recovery plan may include the results of a capture
analysis or computer modeling analysis to support the design of the
network of wells or trenches and associated pumping rates, fluid
elevations and/or vacuum pressures. Simple checks for small systems are
suggested in Chapter IV. For complex sites with large volumes of free
product, or where sophisticated models have been used in the free product
recovery plan, the reviewer should probably seek guidance from an
environmental professional with experience in computer modeling.
Step 5. Evaluate Operation, Maintenance, And
Monitoring Approach
The free product recovery «plan should include an Operation and
Maintenance (O&M) plan that describes equipment operation and
maintenance and monitoring activities at the site.
Monitoring parameters typically include:
Fluid production rates at wells or drains (both free product and
groundwater).
Oil thickness in wells.
Groundwater elevations in wells.
For dual phase recovery systems, vacuum pressures and air flow extraction
rates at wells or on the manifold need to be monitored. The O&M plan
should specify monitoring points and frequency for each monitoring
parameter. The O&M plan should also describe monitoring activities to
be continued once the free product recovery system has achieved its
remedial objective(s) and associated criteria. The details of an O&M plan
depend on site conditions and the free product recovery technology
selected (see Chapter V for further discussion).
Primary References
ASTM, 1995. Standard Guide fo? Risk-Based Corrective Action Applied
at Petroleum Release Sites, E 1739-95, Annual Book of ASTM
Standards, Philadelphia, Pennsylvania.
EPA, 1995. OSWER Directive 9610.17: ^e of Risk-Based Decision-
Making in UST Corrective Actionprograms, Office of
Underground Storage Tanks. ; 1 1
11-11
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-------
-------
-------
CHAPTER
BEHAVIOR OF HYDROCARBONS
IN THE SUBSURFACE
-------
-------
CHAPTER III
BEHAVIOR OF HYDROCARBONS IN THE
SUBSURFACE
The purpose of this chapter is to supplement your knowledge of
hydrocarbon behavior in the subsurface. This basic information lays the
foundation for the principles and concepts used in the design of effective
and efficient free product recovery systems.
The fate-and-transport of liquid petroleum products in the
subsurface is determined primarily by the properties of the liquid and the
characteristics of the geologic media into which the product has been
released. Important liquid properties include density, viscosity and
interfacial tension. Soil properties that influence the movement of
petroleum hydrocarbons include porosity and permeability. Other
additional properties, which are functions of both the liquid and the media,
include capillary pressure, relative permeability, wettability, saturation,
and residual saturation. Site-specific physical conditions (e.g., depth to
groundwater, volume of the release, direction of groundwater flow) also
contribute to the migration and dispersion of released petroleum products.
This chapter contains discussions of each of these factors. To put the
following discussion in the context of the types of petroleum hydrocarbons
commonly found at UST sites, we begin with a brief description of the
classification and composition of hydrocarbons.
Classification And Composition Of Hydrocarbons
Petroleum hydrocarbons are derived from crude oil, which is
refined into various petroleum products by several processes. Like the
parent crude oil, refined petroleum products are also mixtures of as many
as several hundred compounds. The bulk products may be classified on
the basis of composition and physical properties. Products typically stored
in USTs include the following main groups:
Gasolines
Middle Distillates
Heavy Fuel Oils
Exhibit III-l presents a gas chromatogram of a hydrocarbon sample with
the approximate ranges in which the various constituents fall. Compounds
outside the normal ranges depicted are commonly found as contaminants
III-l
-------
Exhibit 111-1
Gas Chromatogram Showing Approximate Ranges
For Individual Hydrocarbon Products
TOLUENE,
BENZENE
\
ORTHOXYLENE
r
C11
C12
CQ
^
k
UUU
GASOLINE
DIESEL
KEROSENE
LUBRICATING OIL
__
Source: Adapted from Senn and Johnson, 1985.
Ill-2
-------
in other products. For example, diesel fuel may contain minor amounts of
benzene and other light hydrocarbons.
Gasolines
Gasolines are mixtures of petroleum hydrocarbons and other non-
hydrocarbon chemical additives, such as alcohols (e.g., ethanol) and ethers
(e.g., methyl tertiary-butyl ether, or MTBE). Gasolines are more mobile
than either the middle distillates or the fuel oils. The higher mobility of
gasoline is primarily due to the fact that its components tend to have lower
molecular weights; hydrocarbon compounds usually found in gasoline
have between 4 and 10 carbon atoms per molecule. The lower molecular
weight results in lower viscosity, higher volatility, and moderate water
solubility. Fresh gasolines contain high percentages of aromatic
hydrocarbons (i.e., those with a 6-carbon benzene ring), which are among
the most soluble and toxic hydrocarbon compounds. The most frequently
encountered aromatic compounds are benzene, toluene, ethylbenzene, and
xylene (BTEX). Because of their relatively high volatility, solubility, and
biodegradability, BTEX compounds are usually among the first to be
depleted from free product plumes. At sites of older gasoline releases, the
free product plume may contain relatively little BTEX, being instead
enriched in heavier, less soluble, and less readily biodegradable
components. As a consequence, the product will be more viscous, slightly
more dense, less volatile, and less mobile than fresh product. The non-
hydrocarbon additives (e.g., ethanol, MTBE) are readily soluble and
preferentially dissolve into groundwater, which diminishes their
concentration in the free product, but results in formation of longer
dissolved plumes. MTBE also moves away from the source faster than
free product and because it is relatively non-degradable, it is difficult to
remediate. Discussion of methods to remediate dissolved plumes are
beyond the scope of this manual.
Middle Distillates
Middle distillates (e.g., diesel fuel, kerosene, jet fuel, lighter fuel
oils) may contain 500 individual compounds, but these tend to be more
dense, much less volatile, less water soluble, and less mobile than the
compounds found in gasolines. The major individual components
included in this category of hydrocarbons contain between 9 and 20
carbon atoms each. Lighter aromatics, such as BTEX, are generally found
only as trace impurities in middle distillates, and if initially present, they
are generally not present in plumes at older release sites, because they
have biodegraded, evaporated, and dissolved into groundwater.
Ill-3
-------
Heavy Fuel Oils
Heavy fuel oils and lubricants are similar in both composition and
characteristics to the middle distillates. These types of fuels are relatively
viscous and insoluble in groundwater and are, therefore, fairly immobile
in the subsurface. Most of the compounds found in heavy fuel oils have
more than 14 carbon atoms; some have as many as 30. Like the older
releases of middle distillates and gasolines, the lighter end components are
present only in trace amounts as they are more readily biodegraded and
dispersed.
Phase Distribution In The Subsurface
The petroleum hydrocarbon constituents that comprise free product
may partition into four phases in the subsurfacevapor (in soil gas),
residual (adsorbed onto soil particles including organic matter), aqueous
(dissolved in water), and free or separate (liquid hydrocarbons). Exhibit
III-2 illustrates the distribution of the hydrocarbon phases in the
subsurface from a leaking UST. The partitioning between phases is
determined by dissolution, volatilization, and sorption.
When released into the subsurface environment, liquid
hydrocarbons tend to move downward under the influence of gravity and
capillary forces. The effect of gravity is more pronounced on liquids with
higher density. The effect of capillary forces is similar to water being
drawn into a dry sponge. As the source continues to release petroleum
liquids, the underlying soil becomes more saturated and the leading edge
of the liquid migrates deeper leaving a residual level of immobile
hydrocarbons in the soiLbehind and above the advancing front. If the
volume of petroleum hydrocarbons released into the subsurface is small
relative to the retention capacity of the soil, then the hydrocarbons will
tend to sorb onto soil particles and essentially the entire mass will be
immobilized. For petroleum hydrocarbons to accumulate as free product
on the water table, the volume of the release must be sufficient to
overcome the retention capacity of the soil between the point of release
and the water table. Without sufficient accumulation of free product at
the water table, there is no need for a free product recovery system.
However, in either case, there may be a need for appropriate remedial
action to mitigate the residual (sorbed) phase so that it does not continue to
act as a lingering source of soluble groundwater contaminants or volatile,
and potentially explosive, vapor contaminants. Exhibit III-3 illustrates
the progression of a petroleum product release from a leaking UST.
Frame A shows the hydrocarbon mass before it reaches the capillary
fringe. If the release were to be stopped at this point, there would
III-4
-------
Exhibit 111-2
Vertical Distribution Of Hydrocarbon Phases
FLUIDS SATURATION
GENERALIZED
CROSS-SECTION
Unsaturated Zone With
Residual Hydrocarbons
and Hydrocarbon Vapor
'' '-.' "...Capillary Fringe-\ *..- J ..
. t ' * ; " " I". V *. * - .
Annual Low
Water Table
' »./'.".: V" "' "'" '' '' '
.." _ " J "" ; " i^
'* '-'1*' -"---^-'
Capillary Zone With
Free Liquid Hydrocarbons
-'1* i a -"
Lower Limit of
Smear Zone
-i--y
'
LEGEND
Free Hydrocarbons j
-x- Effective Water Table
&3 Sand Grain
ts^ Water
^H Liquid Hydrocarbons
I I Air/Vapor
Water Table Fluctuation Zone
With Residual Hydrocarbons
Saturated Zone With
Dissolved Hydrocarbons
Source: Modified from Lundy and Gogel, 1988.
Ill-5
-------
Exhibit 111-3
Progression Of A Typical Petroleum Product Release
From An Underground Storage Tank
Unsaturated Zone
[capillary Zone
Saturated Zone
»
CUST
-NAPL
Water Table
Confining Layer
Beginning of Release
t
Unsaturated Zone
TcapillaryZone
Saturated Zone
B
Release Continues
Unsaturated Zone
Capillary Zone
Saturated Zone
Source of Release is Eliminated
Source: EPA, 1990
III-6
-------
probably be no accumulation of free product. In Frame B, the release has
continued and the volume of the release is sufficient for free product to
begin accumulating on, and displacing, the capillary fringe. The free
product is beginning to displace the capillary fringe and some of the
soluble constituents are dissolving into the groundwater. The source of
release has been stopped in Frame C. Residual hydrocarbons remain in
the soil beneath the UST. The free product plume has spread laterally, and
a plume of dissolved contaminants is migrating downgradient.
Portions of the hydrocarbon mass from both the residual and free
phases will volatilize (evaporate) and solubilize (dissolve) to become
components of the soil vapor and groundwater, respectively.
Volatilization and solubilization of the lighter fractions tend to make the
remaining hydrocarbon mass more dense and even less mobile.
Hydrocarbons that are in the vapor phase are much more mobile and can
migrate relatively great distances along preferential flow paths such as
fractures, joints, sand layers, and utility line conduits. Accumulation of
vapors in enclosed structures (e.g., basements, sewers) potentially can
cause fires or explosions. The more soluble components of the
hydrocarbon mass will dissolve into groundwater, both above and below
the water table. The dissolved hydrocarbons move with the flowing
groundwater and can contaminate drinking water supplies. Also, if
groundwater is recovered as a result of pumping or skimming, it may
require treatment or disposal if the concentration of dissolved
hydrocarbons is higher than the applicable groundwater or drinking water
standard. Vapors may be released from the groundwater or be drawn
directly from the subsurface if vacuum-enhanced free product recovery
systems are employed. These vapors may require treatment to mitigate
fire or explosion potential and to comply with air quality criteria.
Exhibit III-4 presents estimates of phase distribution from a
gasoline release into the subsurface consisting of medium sand. Most of
the amount spilled (64 percent) remains in the free phase; however, the
volume contaminated by residual phase and dissolved phase hydrocarbons
represents nearly 99 percent of the total contaminated volume. Perhaps
the most important point to note is that a very small quantity of petroleum
hydrocarbons (1 to 5 percent of the original release volume) can
contaminate a significant amount of groundwater (79 percent of the total
contaminated volume). Hence, recovery of as much free product as
possible is important, but only a portion (up to 50 percent) of the free
phase hydrocarbon is actually recoverable with the balance remaining in
the residual phase acting as a continuous source of groundwater
contamination. Where a water supply is threatened by a release, recovery
of free product may be only the first step. An adequate remedial action
may require aggressive remediation of the residual phase as well.
Ill-7
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Exhibit 111-4
Phase Distribution At A 30,000-Gallon Gasoline Spill
Site In An Aquifer Of Medium Sand
Phase
Free Phase
Residual Phase
Dissolved (Water)
Contaminant
Volume (gal)
18,500
10,000
333
% of Total
64
35
1
Contaminated
Volume (yd3)
7,100
250,000
960,000
% of Total
1
20
79
SourcerModified from Wilson and Brown, 1989.
Properties Of Geologic Media
The extent and rate of petroleum hydrocarbon migration depends
in part on the properties of the subsurface medium in which it is released.
The subsurface medium may be naturally occurring geologic materials
(e.g., sedimentary, metamorphic, or igneous rock or sediments) or artificial
fill that has been imported to the site by human activity. In order to design
effective and efficient free product recovery systems, you need to
characterize both the type and the distribution of geologic media (or fill
material) so that you can determine the likely migration routes and travel
tunes.
In the context of fluid flow in the subsurface, geologic media can
be classified on the basis of the dominant characteristics of pore space,
fractures, or channels through which fluids move. In porous media, fluids
move through the interconnected voids between solid grains of soil.
Fractured media are those in which fluids migrate readily through fractures
rather than the adjacent soil or rock matrix. Fracturing is usually
associated with consolidated materials, but it can also occur in
unconsolidated clays due to desiccation. Karst media are those in which
fluids flow through solution features and channels (e.g., caves associated
with carbonate rocks such as limestone).
Porosity and permeability are the two most important media-
specific properties of a natural geologic material. Porosity characterizes
the ability of media to store fluids, and permeability characterizes the
ability of the media to transport fluids. Exhibit III-5 summarizes the
III-8
-------
( ; EXHIBIT 111-5
"-y - ....
Functional Characteristics
Of Geologic Media Properties
Property Significance
Porosity Porosity is required for calculation of the amount of free product
and immobile (residual) product. The relevant parameter for
determining recoverable free product is the "drainable" or
"effective" porosity, which is always less than total porosity.
Permeability . Permeability controls the rates of groundwater flow and free
product migration. It is also used to calculate pumping rates
required for hydraulic control.
Anisotropy Anisotropy is a condition of the geologic media in which
measurement of a property (e.g., hydraulic conductivity)
depends upon the direction of measurement. Anisotropy can
cause groundwater flow to not be in the same direction as the
hydraulic gradient.
Heterogeneity Heterogeneous media often provides preferential pathways for
fluid migrationthese pathways are difficult to locate and to
characterize.
significance of geologic properties and their relevance to free product
recovery.
Porosity
i Porosity, or more specifically effective ("drainable") porosity, is an
I important factor to be considered in the evaluation of a free product
! recovery system. Calculation of the amount of free and immobile product
| in the subsurface requires a value or estimate of effective porosity.
! - .
i Porosity defines the storage capacity of a subsurface media. All
! rocks and unconsolidated media contain pore spaces. The percentage of
j the total volume of an unconsolidated material or rock that consists of
' pores is called porosity. Porosity is classified as either primary or
' secondary. Primary porosity, which is created when sediments are
I deposited (or crystalline rocks are formed), depends on the shape, sorting,
: and packing of grains. Primary porosity is greatest when grains are nearly
if ^\ equal in size (i.e., are well graded or sorted) and nonspherical in shape.
% J Unconsolidated sediments that contain a wide range of grain sizes (i.e., are
III-9
III -11
-------
The intrinsic permeability of the geologic media is independent of the , ;
nature of the fluid flowing through the media. Intrinsic permeability is -"'
related to hydraulic conductivity, which is a measure of the ability of the
geologic medium to transmit water, but the terms are not interchangeable.
Hydraulic conductivity is a function of properties of both the media and
the fluid. Although confusing, hydraulic conductivity is often referred to
as simply "permeability". Geologic media with high hydraulic
conductivities are highly permeable and can easily transmit non-viscous
fluids, especially water and many types of petroleum products. Various
geologic media tend to have hydraulic conductivity values within
predictable ranges (Exhibit III-7).
A geologic medium is described as "isotropic" if the measured
permeability is the same in all directions. Flow through an isotropic
medium is parallel to the hydraulic gradient. This condition might exist in
a uniform, well-graded sand. The permeability of a geologic medium is
often observed to vary depending upon the direction in which it is
measured. Known as "anisotropy", this condition can cause the flow of
groundwater and free product to occur in a direction that is not necessarily
the same as the principle direction of the hydraulic gradient. Because of
anisotropy, a cone-of-depression formed around a pumping well may be x
asymmetrical (e.g., elliptical) rather than circular. Sediments that are {
comprised of a high proportion of flat, plate-like particles (e.g., silt, clay) _---
which can pack tightly together and foliated metamorphic rocks (e.g.,
schist) often exhibit anisotropy. Anisotropy may occur in three
dimensions. For example, in flat-lying sedimentary units, horizontal
permeability is usually much greater than vertical permeability.
The nature of geologic processes results in the nonuniform deposition
and formation of rocks and sediments. Geologic media often are
characterized by the degree of uniformity in grain size and properties such
as permeability. Geologic media with uniform properties over a large area
are referred to as being homogeneous. By contrast, geologic media that
vary in grain size from place to place are called heterogeneous. In nature,
heterogeneity is much more common than homogeneity. Soil properties
(e.g., permeability, texture, composition) can be dramatically different
over short distances. These changes strongly influence the direction and
rate of the flow of groundwater, free product, and vapor through the
subsurface. For example, free product may migrate farther and faster than
it would in homogeneous media because hydrocarbons tend to move
through the most permeable pathways and bypass extremely low
permeability zones. Fine-grained fractured media are heterogeneous in the ^^^
extreme. Migration distances in fractured media can be large because of i )
the very small storage capacity of the fractures. ' -"
III - 12
-------
Exhibit 111-7
Range Of Values Of Hydraulic Conductivity And Permeability
SI
u CQ
c
a o
Rocks
A
?
I
O
Unconsolidated
Deposits
ll
Q OT
i
*o w J!e '
£00 ]
"Go. ^
^ (0
0
-1Q-3
-10"4
-1Q-5
-10"6
-io-7
-10"8
-io-9
-10-10
-io-11
-io-12
-10-13
-io-14
-io-15
-10-16
-102
-10
-1
-10'1
-1C-2
-ID'3
-io-4
-10'5
-10-6
-io-7
-10-8
-10-9
_10-10
-10-11.
-10s
-104
-103
-102
-10
-1
-io-1
-io-2
-io-3
-io-4
-10-5
-10"6
-10'7
-106
-105
-104
-103
-102
-10
-1
-10'1
-ID"2
-I 0-3
-io-4
-10-5
-io-6
-m-7
LEGEND
k Permeability
K Hydraulic Conductivity
Source: Modified from Freeze & Cherry, 1979
III- 13
-------
Properties Of Fluids
The physical properties of fluids that are most significant to free
product recovery and migration are density and viscosity. Density
determines the tendency of free product to accumulate above the water
table or to sink to the bottom of the aquifer. Common petroleum
hydrocarbons tend to accumulate above the water table because of their
low density. Viscosity is a factor controlling the mobility and
recoverability of liquid hydrocarbons. Petroleum hydrocarbons with low
viscosity are more mobile and are more easily recovered than those with
high viscosity. A third fluid property is interfacial tension, which is
important because it determines how easily a geologic media will be
wetted with a fluid and also controls (with pore size) the height of the
capillary rise in a porous media. All three properties are inversely related
to temperature. Exhibit III-8 summarizes the significance of fluid
properties and their relevance to free product recovery.
Density
Density, which refers to the mass per unit volume of a substance, is
often presented as specific gravity (the ratio of a substance's density to
that of some standard substance, usually water). The densities of
petroleum hydrocarbons typically found in USTs are less than 1.0 and
typically range from 0.75 g/ml to as high as 0.99 g/ml. Density varies as a
function of several parameters, most notably temperature, however, in
most subsurface environments the temperature (and hence the density)
remains relatively constant. The density of water is about 1.0 g/ml at
normal groundwater temperatures. Densities of some common petroleum
hydrocarbons are presented in Exhibit III-9. For a more detailed list of
hydrocarbons and their properties, see Eastcott et al. (1988).
Petroleum hydrocarbons that are less dense than water will float;
these are also referred to as light non-aqueous phase liquids, or LNAPLs.
It is important to know the density of free product at a release site because
water levels measured in monitor wells that also contain free product must
be corrected to account for the different densities of water and the product
and the thickness of the product layer. The correction procedure is
demonstrated in Exhibit 111-10. Density is also a required parameter for
some volume estimation methods, which are discussed in Chapter IV and
in the Appendix.
Ill - 14
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EXHIBIT 111-8
Functional Characteristics
Of Fluid Properties
Property
Viscosity
Interfacial Tension
Significance
Density Density .values are used to determine whether free product
will float on top of water or sink through it. Products that float
are called LNAPLs (light non-aqueous phase liquids). Most
fuel hydrocarbons are LNAPLs. Water levels measured in
monitor wells containing free product must be corrected to
account for the density and thickness of the product layer
(see Exhibit 111-10).
Viscosity is a measure of how resistant a fluid is to
f|ow_vjscous fluids resist flow. Higher viscosity fluids are
more resistive to flow than lower viscosity fluids. For
example, gasoline, which is less viscous than diesel fuel,
flows faster than diesel fuel. Diesel fuel, which is less viscous
than fuel oil #2, flows faster than the fuel oil.
Interfacial tension is responsible for the capillary rise
exhibited by fluids in fine-grained media. Interfacial tension is
inversely related to the size of the pores. Fine-grained media
retain more free product (residual saturation) than coarse-
grained media. ^^______^^______^^____..^^_____,
Viscosity
Viscosity, which describes a fluid's resistance to flow, is caused by
the internal friction developed between molecules within the fluid. For
most practical applications, viscosity can be considered to be a qualitative
description in that the higher a fluid's viscosity, the more resistive it is to
flow. Fluids with a low viscosity are often-referred to as "thin", while
higher viscosity fluids are described as "thick". Thinner fluids move more
rapidly through the subsurface than thicker fluids. This means that a
thinner petroleum product (i.e., gasoline) is generally more easily
recovered from the subsurface and leaves a lower residual saturation than a
thicker petroleum product (e.g., fuel oil). Viscosity is inversely
proportional to temperature: As the temperature of the fluid increases, the
viscosity decreases. The efficiency of free product recovery may be
reduced at sites in northern areas if temperatures in the shallow subsurface
decrease significantly during the winter months. The viscosity of free
product in the subsurface environment typically changes over time,
becoming thicker as the thinner, more volatile components evaporate and
dissolve from the liquid hydrocarbon mass.
Ill-15
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Exhibit 111-9
Density And Dynamic Viscosity Of Selected Fluids
Fluid
Water
Automotive gasoline
Automotive diesel fuel
Kerosene
No. 5 jet fuel
No. 2 fuel oil
No. 4 fuel oil
No. 5 fuel oil
No. 6 fuel oil or Bunker C
Norman Wells crude
Avalon crude
Alberta crude
Transmountain Blend crude
Bow River Blend crude
Drudhoe Bay crude
Atkinson crude
.aRosa crude
Density, p
(g/ml)
0.998
0.729
0.827
0.839
0.844
0.866
0.904
0.923
0.974
0.832
0.839
0.840
0.855
0.893
0.905
0.911
0.914
Dynamic (Absolute)
Viscosity, fj
(centipoise, cP)
1.14
0.62
2.70
2.30
47.20
215.00
5.05
11.40
6.43
10.50
33.70
68.40
57.30
Notes: all measurements at 15°C.
g/ml = grams per milliliter
C = Celsius
Source: API, 1996. A Guide to the Assessment and Remediation to
Underground Petroleum Releases, 3rd edition. API Publication
1628, Washington, DC. Reprinted Courtesy of the American
Petroleum Institute.
Ill-16
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Exhibit 111-10
Correction To Compute Hydraulic Head In Wells
Containing Free Product
Equation: To obtain a corrected hydraulic head value
when free product (liquid hydrocarbon) is
present in a well:
where:
HO
Po
Pw
hydraulic head corrected (ft)
measured elevation of hydrocarbon-water
interface (ft)
thickness of hydrocarbon layer (ft)
hydrocarbon density (g/ml)
water density (g/ml); usually assumed = 1.0
Example:
Solution:
The distance from the well head to the hydrocarbon-air
interface is 15.00 feet. The hydrocarbon-water interface is
measured at 19.75 feet. The elevation of the top of the well
head is 100.00 feet above sea level. The density of the
hydrocarbon is 0.73.
What is the hydraulic head in this well?
The elevation of the air/hydrocarbon interface is 85 feet above
sea level (100.00 feet-15.00 feet). The elevation of the
hydrocarbon-water interface is 80.25 feet above sea level.
The hydrocarbon thickness is 4.75 feet (19.75 feet - 15.00
feet). Substituting the appropriate values into the equation:
h = 80.25ft + 4.75ft x °-739/ml
0 1.0g/ml
= 83.72 feet
Note that the hydraulic head elevation (83.72 feet) is significantly different
from the measured hydrocarbon-water interface (80.25) and from the
measured air-hydrocarbon interface (85.00 feet). Groundwater elevations
based on uncorrected measurements are incorrect and flow directions
should not be determined using these values. Because the flow
directions are incorrect, a recovery system designed based on them
would likely be inefficient or even ineffective.
III- 17
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Three different terms are commonly used to describe viscosity:
absolute, dynamic, and kinematic. Absolute and dynamic are synonymous
terms and are typically reported in units of centipoise (cP). Kinematic
viscosity, which is equal to dynamic (or absolute) viscosity divided by
density, is typically reported in units of centistokes (cSt). Because
viscosity is relative, the term selected for use when comparing viscosities
for various petroleum hydrocarbons, does not matter as long as it is the
same for all the products being compared. If a flow equation is being
solved, be sure to use a term that expressed in units which are consistent
with the equation. Absolute (or dynamic) viscosities of common
petroleum hydrocarbons are presented in Exhibit III-9.
Interfacial Tension
The characteristics of free hydrocarbon movement are largely
determined by interfacial tension that exists at the interface between
immiscible fluids (e.g., hydrocarbon, air, and water). Interfacial tension
causes a liquid to rise in a capillary tube (or porous medium) and form a
meniscus. The height of the capillary rise is inversely proportional to the
radius of the tube (or pore spaces), which explains why the capillary rise is
greater in fine-grained porous media than in coarse-grained material. In
general, higher surface tensions result in higher capillary pressure, which
may produce higher residual saturation (Mercer and Cohen, 1990). The
interfacial tension between a liquid and its own vapor is called surface
tension.
Interfacial tension is the primary factor controlling wettability.
The greater the interfacial tension, the greater the stability of the interface
between the two fluids. The interfacial tension for completely miscible
liquids is 0 dyne cm'1. Water (at 25 °C) has a surface tension of 72 dyne
cm"1. Values of interfacial tension for petroleum hydrocarbon-water
systems fall between these two extremes (Mercer and Cohen, 1990).
Interfacial tension decreases with increasing temperature and may be
affected by pH, surface-active agents (surfactants), and gas in solution
(Schowalter, 1979). Some of the theoretical methods for estimating free
product volume in the subsurface and some multiphase flow models
require values of interfacial tension as input. Obtaining accurate values is
difficult for a couple of reasons. First, measurement of interfacial tension
in the field is generally not practical. Second, although values for some
petroleum hydrocarbons may be obtained from the literature, these values
tend to be for pure compounds under ideal conditions and may not be
representative of free product plumes in the subsurface environment.
Ill- 18
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Properties Of Fluids And Geologic Media
The movement of free product in the subsurface also depends upon
several factors which are functions of properties of both the fluid and the
geologic media. These factors are capillary pressure, relative
permeability, wettability, saturation, and residual saturation. Although all
of these factors are interrelated, the most important are capillary pressure
and relative permeability. Exhibit III-l 1 summarizes the most significant
properties of both the fluid and the geologic media and illustrates how
these properties relate to free product recovery.
Capillary Pressure
Capillary pressure is the difference in pressure observed between
two phases (e.g., hydrocarbon liquid and water) that occupy the same pore
space. As the result of interfacial tension, the boundary between two
immiscible phases is a curved surface, or interface. Capillary pressure is
the change in pressure across this curved interface. In the vadose zone
capillary pressure is negative (i.e., less than atmospheric) and is referred to
as suction or tension. Capillary pressures are larger in fine-grained media
(e.g., silt, clay) than in coarse-grained media (e.g., gravel). The capillary
fringe above the water table is a familiar consequence of capillary
pressure. Because capillary pressure resistance is inversely proportional to
pore size, the height of the capillary fringe is greater in finer grained
media.
The distribution and accumulation of free product in the subsurface
is influenced by capillary pressure. Soil water content and the size and
orientation of pore spaces affect the penetration of free product in the
vadose zone. Penetration of free product into the subsurface is enhanced
by dry soil conditions and facilitated by inclined, relatively permeable
pathways such as those provided by secondary permeability features (e.g.,
fractures, root holes, and bedding plane laminations). Upon reaching the
capillary fringe, resistance to downward movement will be increased and
hydrocarbons will spread laterally and accumulate above the saturated
media. This accumulation is sometimes referred to as a "lens" or
"pancake". As long as there is a sufficient supply of hydrocarbons from
above, the lens thickness and downward pressure will continue to increase.
Eventually, the petroleum product (the nonwetting fluid) will begin to
displace water (the wetting fluid) and enter the largest pores. The pressure
required for this to occur is referred to as the "threshold entry pressure"
(Schwille, 1988; Gary et al, 1991).
III -19
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EXHIBIT 111-11
Functional Characteristics Of
Properties Dependent On Both The Fluid
And The Geologic Media
Property
Capillary Pressure
Relative Permeability
Wettability
Saturation
Residual Saturation
Significance
Capillary forces restrict the movement of free product-
movement tends to occur through pathways where capillary
pressures are low, as in coarser-grained media. Capillary
pressure is inversely related to saturation. It is not practical
(or necessary) to measure capillary pressure in the field.
Relative permeability is a function of saturation and also
controls the mobility of liquids in a porous medium. Relative
permeability and saturation are directly proportional. In
media with two liquids present, the permeability of the media
is reduced for each liquid due to the presence of the other
liquid.
Most geologic materials are preferentially wet by water as
opposed to free product (or air)-this means that water, rather
than free product will be more mobile.
Saturation controls the mobility of liquids (water and free
product) through a porous medium--for a liquid to be mobile,
the liquid phase must be continuous and the media must be
at least partially saturated. Saturation levels are also used to
determine the volumes of free and residual product.
Liquids drain from a porous medium until a certain minimum
saturation level is reached (for free product this is "residual
saturation") and flow ceases.
Similarly, in the saturated zone, hydrocarbons will tend to spread
laterally over fine-grained capillary barriers and move through fractures
and coarser media wherever possible. The thickness or height of a
hydrocarbon column required to develop sufficient hydrocarbon pressure
head to exceed capillary force resistance is known as the critical
hydrocarbon thickness (or height). Because capillary forces can restrict
the migration of free product into water-saturated media, fine-grained
layers can act as capillary barriers. That is, before free product can
penetrate a water-saturated porous medium, the hydrocarbon pressure head
must exceed the resistance of the capillary forces (Schwille, 1988). In
heterogeneous media, free product tends to move through pathways where
capillary effects are weak, such as lenses of sand and gravel or large
fractures.
Ill-20 '
-------
Although capillary pressure is not measured in the field (it can be
measured in the laboratory or estimated from grain size data [Mishra et al.,
1989]), the effects of capillary pressure should be considered in the
analysis of field data. A commonly measured field parameter is the
thickness of product in a well, however, this thickness is usually much
greater than the true thickness of free product in the aquifer. This
exaggeration is most pronounced in media with strong capillary effects
(e.g., fine grained silts and clays) and least pronounced in media with
weak capillary effects (e.g., sands and gravels). Exhibit 111-12 illustrates
this effect, however, the exhibit is not intended to be used to estimate the
amount of free product at a particular site. This effect obviously is of
great practical significance in the design of a free product recovery system.
For example, thick oil accumulations in monitor wells may be caused by
either significant amounts of free product or small amounts of free product
in fine grained media. A conventional recovery system (e.g., skimmer)
may be appropriate in coarser-grained media with thick accumulations of
free product. In the case of thinner accumulations in finer-grained media,
a vacuum-enhanced recovery system, rather than a conventional recovery
system, may be required.
Relative Permeability
The effectiveness of a recovery system to collect free product
depends upon the mobility of the free product through the geologic media.
Mobility is strongly controlled by the relative permeability of the
petroleum hydrocarbons and water, which in turn is dependent upon
saturation. Relative permeability is the ratio of the effective permeability
of a fluid at a specified saturation to the intrinsic permeability of the
medium at 100-percent saturation (Mercer and Cohen, 1990). The relative,
permeability of a particular geologic media that is completely saturated
with a particular fluid is equal to the intrinsic permeability. When more
than one fluid (i.e., air, water, petroleum hydrocarbon) exists in a porous
medium, the fluids compete for pore space thereby reducing the relative
permeability of the media and the mobility of the fluid. This reduction can
be quantified by multiplying the intrinsic permeability of the geologic
media by the relative permeability. As with saturation, the mobility of
each fluid phase present varies from zero (0 percent saturation) to one (100
percent saturation).
An example of relative permeability curves for a water-
hydrocarbon system is shown in Exhibit 111-13. The curves representing
water saturation and hydrocarbon saturation are contrary to one another
and divide the figure into three flow zones. Zone I, where hydrocarbon
saturations are relatively high, is dominated by hydrocarbon flow. Water
III - 21
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Exhibit 111-12
Ratio Of Apparent To True Free Product Thickness
Measured In A Monitor Well For Various Soil Types
10
Q
I
ui
h-
P
6
4
I
<
UL
o
O 2-
o'
Source: EPA, 1990
III - 22
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Exhibit 111-13
Hypothetical Relative Permeability Curves
For Water And A Liquid Hydrocarbon In A Porous Medium
Kr = Relative Permeability
1.00
1.00
0.01
100%
>wr
100%
Hydrocarbon Saturation
Sr
ZONE
EXPLANATION
Liquid hydrocarbon occurs as a potentially mobile, continuous phase and
saturation is high. Water is restricted to small pores. The relative permeability
of water is very low or zero. Such conditions may be observed within large
mobile product accumulations.
Both liquid hydrocarbon and water occur as continuous phases, but generally
they do not necessarily share the same pore.spaces. However, the relative
permeability of each fluid is greatly reduced by the saturation of the other fluid.
Such conditions may be representative of zones of smaller mobile product
accumulations at the water table.
Liquid hydrocarbon is discontinuous and trapped as residual in isolated pores.
Flow is almost exclusively the movement of water, not LNAPL. Examples of
such conditions may be found within zones of residual LNAPL retained
below the water table.
Source: Newell et. al., 1995
III - 23
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saturations are relatively high in Zone III, and water flow is dominant.
Mixed flow characterizes Zone II. Refer to the exhibit explanation for
more details.
Because of the difficulties associated with laboratory and field
measurement of relative permeability, alternative theoretical approaches
can be utilized to estimate this function from the more easily measured
capillary pressure data (Mualem, 1976; Lenhard and Parker, 1987;
Luckner et al, 1989; and Busby et al, 1995). Relative permeability
relationships can be estimated from grain size data for unconsolidated
materials (Mishra et al., 1989).
Wettability
Wettability, which depends on interfacial tension, refers to the
preferential spreading of one fluid over solid surfaces in a two-fluid
system (Mercer and Cohen, 1990). Because of the dependence on
interfacial tension, the size of the pore spaces in a geologic medium
strongly influences which fluid is the wetting fluid and which fluid is the
nonwetting fluid. The dominant adhesive force between the wetting fluid
and media solid surfaces causes porous media to draw in the wetting fluid
(typically water) and repel the nonwetting fluid (typically hydrocarbon or
air) (Bear, 1972). Liquids (hydrocarbon or water), rather than air,
preferentially wet solid surfaces in the vadose zone. In the saturated zone,
water will generally be the wetting fluid and displace LNAPL (Newell, et
al., 1995). Whereas the wetting fluid (usually water in a hydrocarbon-
water system) tends to coat solid surfaces and occupy smaller openings in
porous media, the nonwetting fluid tends to be constricted to the largest
openings (i.e., fractures and relatively large pore spaces). When a
formerly saturated porous media drains, a thin film of adsorbed wetting
fluid will always remain on the solid.
The factors affecting wettability relations in immiscible fluid
systems include mineralogy of the geologic media, the chemistry of the
groundwater and the petroleum hydrocarbon, the presence of organic
matter or surfactants, and the saturation history of the media. Sometimes,
such factors can lead to the preferential wetting of only a portion of the
total surface area; this is called fractional wettability. With the exception
of soil containing a high percentage of organic matter (e.g., coal, humus,
peat), most geologic media are strongly water-wet if not contaminated by
NAPL (Mercer and Cohen, 1990). This means that free product will be
less mobile and generally leave a higher residual saturation in the soil,
than will water.
Ill - 24
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Anderson (1986a, 1986b, 1986c, 1987a, 1987b, and 1987c)
prepared an extensive literature review on wettability, its measurement,
and its effects on relative permeability, capillary pressure, residual
hydrocarbon saturation, and enhanced hydrocarbon recovery.
Saturation
The level of saturation possible in a subsurface media has several
implications for recovering free product. First, it controls the mobility of
fluids; second, it defines the volumetric distribution of petroleum
hydrocarbons (discussed in Chapter IV); and third, it is a function of other
properties (e.g., capillary pressure, relative permeability). The mobility of
a particular phase is reduced with decreasing saturation until flow ceases
to occur. Saturation of a porous medium may be defined as the relative
fraction of total pore space containing a particular fluid (Newell et al.,
1995). The saturation level for each of the fluids ranges between zero (the
fluid is not present in the porespace and saturation is 0 percent) and one
(the fluid completely occupies the porespace and saturation is 100
percent). Of course, a given pore space can only be filled to a maximum
of 100 percent, and the proportions of each phase saturation must sum to 1
(or 100 percent saturation).
The mobility of a liquid through a porous medium is a function of
the saturation of the porous medium with respect to that liquid. In order
for it to flow through a porous medium, a liquid must be continuous
through the area where flow occurs. As liquid drains from the media, the
liquid phase becomes discontinuous. The point at which the saturation
level for a continuous liquid phase other than water (i.e., petroleum
hydrocarbon) becomes discontinuous (and hence immobile) is known as
the residual saturation (Newell, et. al., 1995). The corresponding
saturation level for water is called the irreducible water saturation. At
these low saturations, capillary pressures are very high.
The wetting and draining cycles of a porous media differ from one
another as the result of differences in saturation, wettability, and capillary
pressure. During drainage, the larger pores drain the wetting fluid (i.e.,
water) quickly while the smaller pores drain slowly, if at all. During
wetting, the smaller pores fill first, and the larger pores fill last. The
consequence of this phenomenon is that the vadose zone will retain less
residual petroleum hydrocarbon than the saturated zone.
Ill - 25
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Residual Saturation
Residual saturation refers to the saturation level at which a
continuous mass of petroleum hydrocarbons (NAPL) becomes
discontinuous and immobilized by capillary forces (Newell, et al., 1995).
Residual saturation is important to free product recovery, because it
represents the amount of petroleum that cannot be recovered by pumping
or gravity drainage. Following a release of petroleum hydrocarbons into
the subsurface, the hydrocarbon mass seeps downward into the unsaturated
zone. If the volume of the release is enough to sufficiently saturate the
soil, the leading edge of the hydrocarbon mass continues to move deeper
into the subsurface. Behind and above the leading edge, a significant
portion of the hydrocarbon mass is retained in pore spaces by capillary
forces. The amount of hydrocarbon that is retained against the force of
gravity is referred to as the residual saturation. The corresponding term
for water is irreducible water saturation.
Generally, the finer-grained the soil, the higher the residual
saturation. Residual saturation for the wetting fluid is conceptually
different from that for the nonwetting fluid. When the wetting fluid (i.e.,
water) drains from a porous media, even at the level of the irreducible
water saturation, there is a thin, continuous layer of water occupying the
smallest pores and coating the grains of the media. As the nonwetting
fluid (i.e., petroleum hydrocarbon or NAPL) drains from a porous media,
the pores drain incompletely because of the residual water that remains in
the smallest pores. The result is that discontinuous blobs of immobile
petroleum hydrocarbon remain in the soil at the level of the residual
saturation. More viscous fluids tend to have higher residual saturations
than less viscous fluids. Fluids that are more dense for a given viscosity
drain to a greater degree under the influence of gravity than do less dense
fluids. Fluids that have high interfacial tension also tend exhibit higher
capillary pressure, which may result in higher residual saturation.
Although field-scale values for residual saturation are difficult to either
measure or accurately estimate, in general, residual saturation levels tend
to be much higher in the saturated zone (0.15 to 0.50) than in the
unsaturated zone (0.10 to 0.20) (Mercer and Cohen, 1990).
Because residual hydrocarbons are both tightly bound and
discontinuous in pore spaces, they are essentially immobile and, therefore,
not amenable to collection by standard free product recovery methods.
However, the residual phase often represents a potential long-term source
for continued groundwater contamination. Although some portion of the
residual mass will be slowly diminished (i.e., will naturally attenuate)
over time as the result of dissolution, volatilization, and biodegradation,
III - 26
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more aggressive remedial action may be required to mitigate this source
within a reasonable amount of time.
Groundwater Flow Conditions
The subsurface can be divided into two zones based on water
content: The unsaturated zone and the saturated zone. The movement of
petroleum hydrocarbons in the subsurface is fundamentally different in the
unsaturated and saturated zones. The boundary between these two zones
is commonly accepted to be the water table, which is the surface where
water pressure equals atmospheric pressure. Below the water table, in the
saturated zone, all pore and void spaces are filled with water and water
pressure is greater than atmospheric pressure. Water pressures above the
water table, in the unsaturated zone, are less than atmospheric pressure,
and the water may be considered to be under tension or suction. Directly
above the water table is a relatively thin zonethe capillary fringethat
is saturated with water but the water pressure is less than atmospheric
pressure. The capillary fringe is thicker in fine-grained media and thinner
in coarse-grained media. Above the capillary fringe in the unsaturated
zone, voids and pore spaces are filled primarily with air and varying
amounts of water as either liquid or vapor.
Petroleum hydrocarbon migration is strongly affected by
essentially the same factors that govern groundwater flow. In general,
liquid hydrocarbons move in the same direction as groundwater but at a
reduced rate because of the higher viscosity of the hydrocarbons (except
for gasoline) and the lower relative permeability of the porous medium.
Important characteristics of the groundwater flow system that influence
free product are depth to water and hydraulic head variations across the
site. Direct measurements of depth to water and water table
elevations/head are necessary to design or evaluate most free product
recovery systems. Exhibit III-14 summarizes the characteristics of the
groundwater flow system that are most relevant to free product recovery.
Depth To Water Table
The depth to water table is an important factor that affects how the
free product migrates and how its recovery should be approached. Except
for very deep water tables, the depth to the water table can be determined
through relatively inexpensive borings or monitoring wells (or well
points). The depth to water table will indicate the potential for petroleum
hydrocarbons to reach the water table, where the free product can then be
collected in wells or trenches. All other factors being equal, a greater
III - 27
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I
EXHIBIT 111-14
Functional Characteristics Of
Groundwater Conditions
Property
Significance
Depth to Water Table
Mass of free product required to reach the water table
increases with depth; options to recover free product
become more limited (e.g., depth must be less than 20
feet for trenching); costs to recover free product
increase with depth.
Groundwater Elevation
Groundwater elevation (hydraulic head) determines
hydraulic gradient and direction of groundwaterflow
and free product migrationpresence of free product
requires that measured groundwater elevations be
corrected to account for the density and thickness of the
free product layer (see Exhibit 111-10).
depth to water table requires a greater volume of liquid petroleum
hydrocarbons to reach the water table.
The depth to water table, or the top of the free product layer in a
well or trench, is a critical consideration in the selection of a recovery
approach and equipment specification. For example, excavation depth is
constrained by equipment limitations, and excavation costs increase
substantially with depth in nearly all cases. Thus, recovery systems
utilizing drains or gravel-filled trenches are typically limited to sites with
water tables less than 20 feet deep and preferably closer to 10 feet deep.
Excavated material may be highly contaminated and require appropriate
handling and disposal. In most cases where the depth to the water table is
greater than 20 feet, wells must be installed.
Groundwater Elevation (Hydraulic Head)
Measurements of groundwater elevations in wells and piezometers
(a well open to a narrow interval) are the basic response data that
characterize the direction of groundwater flow. The basic principle of
groundwater hydrology is described by Darcy's Law, which relates flow
through porous media to the hydraulic gradient. Groundwater flows
downgradient; that is, from areas of higher head to areas of lower head.
The hydraulic gradient is the change in head per unit distance at a given
point and given direction. In an unconfined aquifer, the hydraulic gradient
III - 28
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is defined by the slope and direction of dip of the water table. A common
observation at many UST sites is a groundwater mound created by the
influence of the tank excavation. These excavations are typically filled
with pea gravel which has a much higher permeability than the native soils
at the site. As a result, tank excavations tend to accumulate and hold
water, usually at a higher hydraulic head than the local water table. This
can cause the formation of a localized groundwater mound that can
influence the hydraulic gradient at the site, possibly inducing free product
to migrate outward hi all directions from the source of the release.
Because petroleum hydrocarbons have a density different from that
of water, neither the measured elevation of free product nor the measured
elevation of water in a well containing free product represents hydraulic
head. Measured fluid elevations in monitoring wells must be corrected to
determine groundwater flow directions and rates. The equation for this
correction and an example calculation are presented in Exhibit III-10.
Relevance To Free Product Recovery
This chapter has presented many factors that influence the
occurrence and movement of free product in the subsurface. This section
presents a discussion limited to those factors that are most relevant to the
recovery of the principal types of petroleum products typically stored in
USTs (i.e., gasolines, middle distillates, and heavy fuel oils). A summary
of these factors is provided in Exhibit 111-15.
The majority of petroleum hydrocarbons stored in USTs are lighter
than water, which means that they float. Free product generally moves in
the same direction as the flow of groundwater. This movement is strongly
influenced by soil heterogeneity and anisotropy, and the design and
operation of an effective free product recovery system is dependent upon
accurate characterization of the hydrogeologic conditions at the site. It is
extremely important to realize that the elevations of liquid surfaces in a
monitoring well containing both groundwater and free product is not
representative of hydraulic head at that location. The measurement must
first be corrected to account for the thickness of the free product and its
density. Other critical factors to consider are the total volume of the
release and the depth to groundwater. If the volume of release is so small
that there is no accumulation at the water table, then recovery of free
product is not practical.
Gasolines are significantly less viscous than water. They can move
more rapidly through geologic media than water and subsurface
accumulations can be relatively easily recovered. Many of the principal
III - 29
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Exhibit 111-15
Most Important Factors Influencing
Free Product Recovery
Factor
Significance
Soil Heterogeneity
and Anisotropy
Controls direction of free product migration and the
flow of groundwater
Product Viscosity
Affects mobility, ease of recoverability, and level of
residual saturation
Soil Permeability
Controls rate of free product migration and the flow
of groundwater
Depth to Water Table
Coupled with volume of release, determines which
remedial technologies may be effective at the site
Volume of Release
Coupled with depth to water table, determines
whether free product recovery is practical or
necessary
components of gasoline are volatile and somewhat soluble. Because of
their high mobility and vapor generation potential, recovery measures
should be initiated as soon as possible after a gasoline release has been
discovered. The lighter components also tend to be more soluble and
groundwater supplies can easily be contaminated. Residual soil saturation
is lower than for the heavier and thicker petroleum products. Older
gasoline plumes will be enriched in the heavier, less volatile fractions;
they may behave more like a fresh middle distillate plume. As a result of
the absence of the volatile fractions, vacuum technologies will be less
effective in recovering petroleum hydrocarbons due to volatilization
(evaporation), but vacuum-enhancement may be effective in recovering a
greater proportion of the plume than would be possible without the
enhancement.
Middle distillates and heavy fuel oils are significantly more
viscous than water. Their movement through the subsurface is typically
slow. Although not as volatile as gasoline, vapors emanating from middle
distillate plumes can create situations in which fire, explosion, or toxicity
threatens human health and safety. Because of the higher viscosity and
lower volatility, residual soil saturation is higher for plumes comprised of
middle distillates and heavy fuel oils than for gasoline plumes.
Recovery of free product to the maximum extent practicable is
merely the first step in a typical remedial action. Regardless of what type
III - 30
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of petroleum product was released and the characteristics of the subsurface
materials, a significant portion of the total release volume will not be
recoverable by any existing remedial technology. Appropriate treatment
of the residual hydrocarbon mass may require application of a combination
of alternative remedial technologies.
Primary References
API, 1996. A Guide to the Assessment and Remediation of Underground
Petroleum Releases, Third Edition, API Publication 1628,
Washington, D.C.
EPA, 1990. Assessing UST Corrective Action Technologies: Early
Screening of Cleanup Technologies for the Saturated Zone,
EPA/600/2-90/027, Risk Reduction Engineering Laboratory,
Cincinnati, OH.
Mercer, J.W., and R.M. Cohen, 1990. A review of immiscible fluids in
the subsurface: Properties, models, characterization, and
remediation, Journal of Contaminant Hydrology, 6:107-163.
Newell, C.J., S.D. Acree, R.R. Ross, and S.G. Ruling, 1995. Light Non-
aqueous Phase Liquids, EPA-540-5-95-500, USEPA/ORD Robert
S. Kerr Environmental Research Laboratory, Ada, OK.
Ill-31
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CHAPTER IV
METHODS FOR EVALUATING
RECOVERABILITY
OF FREE PRODUCT
-------
-------
CHAPTER IV
METHODS FOR EVALUATING RECOVERABILITY
OF FREE PRODUCT
The primary objectives of a free product recovery system are to
recover as much free product as possible, as quickly as possible, and with
as little expense as possible. In order to design an effective and efficient
free product recovery system, you need to answer several questions:
"What is the areal and vertical extent of the free product?", "How much
free product has accumulated?", "How much of the total volume is
recoverable?", and "How quickly can the free product be recovered?".
The answers to each of these questions relate to the recoverability of free
product from the subsurface.
Intuitively, the most effective locations for free product recovery
devices are those places where the accumulations are the greatest. Early
tasks, therefore, include locating those areas where free product
accumulations are the greatest and delineating the areal extent of the free
product plume (or pools). Knowledge of the areal extent is also necessary
to assess whether or not hydraulic containment is required. This
information can be obtained from excavations and test pits, soil borings,
and monitoring wells or well points.
The volume of free product present at a site should be estimated in
order to help evaluate progress during the recovery phase. One of the
ways to establish this estimate is to determine the hydrocarbon
concentrations in soil and hydrocarbon thickness in wells. Methods used
to estimate free product volumes are based on theoretical models,
simplified correlations between hydrocarbon thickness in wells, and
specific oil volumes. The reliability of volume estimates is typically low,
with accuracy within an order of magnitude. Because of the uncertainty,
we suggest that more than one method should be used for volume
estimation.
The recoverability of free product from the subsurface environment
is dependent upon several factors: The physical and chemical properties of
the separate phase petroleum hydrocarbons, the transport properties of the
geologic media, and the capabilities of engineered recovery systems. The
physical and chemical properties of the petroleum hydrocarbons determine
how the free product will primarily exist in the subsurface; whether as a
vapor, a liquid, or dissolved in groundwater. These properties also affect
how fast the free product will move and where in relation to the water
IV-1
-------
table it will accumulate. Properties of the geologic media influence the
rate and direction in which the free product will move. Engineered
systems are designed for use within discrete operating ranges, and no one
recovery system will be optimally suited for all hydrocarbon release sites.
It is also important to realize that only a portion of the total volume of the
release will be recoverable. Even under ideal conditions a significant
proportion of the free product will remain in the subsurface as immobile
residue.
Finally, the rate at which free product can be collected in wells or
trenches will influence decisions on the types and number of wells, the
type of collection equipment used, and the sizing of the treatment system
and/or separators. Recovery rates can be estimated from the results of
specialized pumping tests, the projection of initial recovery rates, and the
use of theoretical models. As recovery progresses product thicknesses and
saturation levels decrease, which affects recovery rates. Other factors,
such as fluctuating water table elevations, can also affect recovery rates.
As a result, the uncertainty associated with estimates of long-term
recovery rates is high.
The relevant properties of petroleum hydrocarbons and geologic
media that govern the behavior of free product in the subsurface have been
discussed in detail in Chapter III. Engineered free product recovery
systems are described in Chapter V. The remainder of this chapter
presents methods for: delineating the areal and vertical extent of free
product, estimating the volume of free product at a release site, and
estimating free product recovery rates. Theoretical models used to
estimate hydrocarbon volumes and recoverability are discussed only
briefly.
Areal And Vertical Extent Of Free Product
The areal and vertical extent of free product must be delineated
before a free product recovery system can be designed. First, the areal
extent is defined by determining the free product thicknesses at available
observation points. Second, using these data an isopach (thickness
contour) map is developed. Locations where free product thicknesses are
greatest are usually the best locations for installation of free product
recovery equipment. There are several common methods used to identify
locations and thicknesses of free product in the subsurface. Used either
alone or in combination with one another, these methods include:
Observation/measurement of free product in excavations or test
pits.
IV-2
-------
Observation/measurement or analysis of hydrocarbons in soil
samples collected from borings.
In situ measurements using a variety of geophysical and direct
push techniques.
Measurement of hydrocarbon thicknesses in wells.
Observations of hydrocarbon seepage in springs or surface water
bodies.
At a given site, not all the above methods may be applicable or cost
effective, and they each have limitations. Excavations may provide
information about free product thickness through measurement of either
the thickness of floating product or the thickness of hydrocarbon-saturated
soil. In either case, such measurements may not be indicative of the true
free product thickness in the soil. For example, the water level in the
excavation may not be representative of the ambient water table elevation.
Measurements of the thickness of saturated soil should be conducted
immediately after the excavation has been dug so that the soil does not
have time to drain. Excavations are also generally limited to depths of 20
feet or less.
The process of collecting soil samples results in some degree of
disturbance of the sample. For instance, the degree of compaction (which
may affect saturation) can change especially if the samples are collected
with a split-spoon sampler. The sample collection location relative to the
water table and capillary fringe can also affect the degree of saturation and
subsequent determination of free product thickness. Various in situ
methods may be employed to overcome the problems associated with
disturbed samples. However, some of the in situ methods are geophysical
techniques that collect indirect data; that is the response of subsurface
materials to an induced stress (e.g., friction) or energy (e.g., electricity,
radiation) is measured and the resulting signal is correlated with a
particular soil type or characteristic. Their applicability depends to a large
degree upon site-specific conditions. The resolution of surface techniques
generally diminishes with increasing depth. Borehole techniques require
pre-existing wells or boreholes. Direct push techniques enable continuous
subsurface data to be collected as well as provide the opportunity to collect
samples of both soil and groundwater. The "Soil Borings" section of this
chapter provides a limited discussion of direct push methods; a detailed
discussion is beyond the scope of this manual. For additional information,
please refer to OUST's soon-to-be published manual on Expedited Site
IV-3
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Assessment Methods and Equipment for Underground Storage Tank Sites,
which is anticipated to be available in the late fall of 1996.
Although the thickness of a layer of free product in a monitor well
can be measured with high accuracy and precision, the measured thickness
is usually larger (sometimes by a factor of as much as 4) than the thickness
that exists in the surrounding soil. The reasons behind the limitations of
monitor wells in providing accurate information on the thickness of free
product in the soil are discussed in greater detail later in this chapter.
In most instances where free product appears in a spring or surface
water body, its presence is indicated only as a mulit-colored sheen. Rarely
is it possible to measure either the thickness of the free product or the rate
of flow. However, its presence may provide insight into migration
pathways, which can aide in the design of the free product recovery
system.
In developing an approach to free product delineation,
consideration of each method should lead to the optimal strategy in terms
of cost, time, and impact to/existing operations at the site. Exhibit IV-1
provides a summary of the features of each of the above methods.
Strategy For Delineation Of Free Product
The strategy for delineating the extent of free product should
involve the following steps:
« Estimate duration and volume of release.
» Evaluate potential to reach water table.
» Select methods for identifying locations of free product (e.g.,
excavation, soil borings, in situ techniques, seepage observations,
wells).
» Evaluate probable direction of groundwater flow and free product
migration.
»
Collect samples, make observations, and install wells/well points,
moving outward until areal extent is delineated.
Estimation of the duration and volume of a release is initially based on
review of inventory and other records in addition to interviews with site
IV-4
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Exhibit IV-1
Features Of Methods For Delineating Extent
Of Free Product
Method of
Data
:ree Product
Thickness in
Excavations
Soil Samples
Chemical
Analysis (lab
or field
methods)
Direct
Observation
In Situ
Measurement
Surface
Geophysical
Borehole
Geophysical &
Direct Push
Free Product
Thickness in
Wells
Seepage in
springs and
surface waters
Data Analysis
direct
measurement/
observation
indirect
measurement
direct
measurement
indirect
measurement
direct or
indirect
measurement
(depends on
method)
direct
measurement
direct
measurement/o
bservation
Data Quality &
Reproducibility
highly variable.
but generally low
generally high
quality, good
reproducibility
highly variable
highly variable.
depends on
method and
conditions
generally high.
depends on
method and
conditions
high, very
reproducible
low
Correlation to
Actual Free
Product Thickness
poor-fair, qualitative
(present or absent,
much or little)
good, quantitative
variable, depends on
soil type
variable
good, quantitative
poor, qualitative
(requires
extrapolation)
poor, qualitative
(present or absent.
much or little)
Maximum
Practical
Depth
shallow,
less than 20
feet
limited only
by sample
collection
method
limited only
by sample
collection
method
up to 100
feet
limited only
by the
depth of the
boring
limited only
by depth of
well
not
applicable
Minimum
Free Product
Thickness
sheen
1 % of
saturation of
sample;
depends on soil
type
0.01 feet
min. detectable
thickness
increases with
depth
typically less
than 1 foot
0.01 feet
sheen
personnel. This information may not be credible or available for many
sites.
Initial remedial activities often provide direct observations of the
depth to water and the presence (or absence) of free product at the water
table. Knowledge of the depth to water table is useful in selecting the
method of defining the locations of free product. For example, in areas
with very shallow water tables (less than 8 feet), test pits excavated by
IV-5
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backhoe may be the most cost effective approach to determining the extent
of free product. If the geologic materials are coarse-grained sands or
gravels, the test pits may also be used as temporary free product recovery
trenches.
Indirect techniques to identify probable areas of free product may
also be useful in focusing the free product investigation. However, these
methods (e.g., soil gas surveys, surface geophysical surveys) can be
expensive, and the results can be difficult to equate with free product
presence. One technique that holds some promise is soil gas monitoring
for H2S, which is associated with anaerobic conditions that may occur with
the degradation of free or residual product in the soil (Robbins et al.,
1995).
The location of sampling or observation points should be focused
in areas in the direction (i.e., downgradient) that groundwater and free
product are flowing. This direction may be inferred from the topography
and location of surface water bodies (e.g., streams, ponds). In shallow
water table aquifers unaffected by pumping, the water table tends to be a
subdued reflection of the topography (i.e., groundwater flows from
topographically high areas to topographically low areas). This general
principle is useful in locating wells to define the direction of groundwater
flow. Either traditional wells or well points may be used as locations to
measure groundwater elevations. Well points, which are generally less
expensive than traditional monitoring wells, can be installed with direct-
push equipment during the initial site assessment phase. A minimum of
three observation points (well points and/or wells) is required to define the
groundwater flow direction. In addition, it is generally recommended that
an additional observation point be installed upgradient of the suspected
release area. These points must not all be located in the same line. If three
points are used, they should be situated in an array that is approximately
an equilateral triangle. If four (or more) points are used, they should be
arranged in an approximately rectangular array as indicated in Exhibit IV-
2. In all cases, whether monitoring wells or well points are installed, the
well head or top of casing should be surveyed to establish the elevation.
With the groundwater flow direction reliably established,
additional sampling points, observation points, or wells/well points can be
sited. Well installation and sampling activities generally proceed outward
and downgradient from the source area. The areal extent of the plume is
adequately delineated when the plume is encircled by a number of
observation points (and/or wells/well points) that do not indicate the
presence of free product (i.e., no free product is present in the well). The
precision of the areal definition of the free product plume depends upon
the number of observation points and distances separating the observation
IV-6
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Exhibit IV-2
Sample Locations Of Wells/Well Points For
Determining Groundwater Flow Direction
Service
Station
Tanks
(a) Good spread, sensitive to any flow direction
(b) Poor spread, not sensitive to gradient or flow in SE-NW direction
LEGEND
Monitor Well or
Well Point
N
IV-7
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points both inside and outside the boundary of the plume. Although the
precise number of observation points must be determined on a site-by-site
basis, a sufficient number of observation points should be installed to
ensure that no part of the plume is migrating in an unexpected direction. It
is also important to realize how soil permeability and retention capacity
affect the thickness and extent of the free product plume. For a given
volume of free product released into a permeable soil (e.g., sand, gravel),
the plume will tend to be flat and relatively broad in extent. The same
volume of free product if released into less permeable soil (e.g, silt, very
fine sand), will form a thicker plume (especially near the point of release)
and the spread will not be as broad. The decrease in plume thickness near
the plume boundary is more rapid in tight formations than in permeable.
formations. The consequence of this is that in tight formations the
distance separating inside and outside wells should be less than in
permeable formations or the extent of the free product plume is likely to
be overestimated.
By its nature, plume delineation is largely a trial-and-error process;
the location of each additional observation point is selected based on
results of the preceding ones. Because it is not practicable to install an
infinite number of observation points, there needs to be a logical and
systematic method which can improve plume delineation. First, we will
make the assumption that the plume boundary is located half-way between
two suitably positionedone inside the plume and one outside the
plumeobservation points. For regular-shaped plumes (e.g., circular or
elliptical) the accuracy of the delineated plume area will be about ± 40
percent of the actual area. Second, we will introduce a few guidelines for
suitably positioning observation points.
The well locations depicted in Exhibit IV-3 are intended to
illustrate key points of the following discussion; they are not intended to
be interpreted as examples of "ideal" well placement. In general,
observation points that are situated within the plume boundaries can be
considered to be either interior (e.g., MW-2) or perimeter (e.g., MW-1).
For perimeter observation points, the distance between observation points
located inside and outside of the free product plume should be less than
40 percent of the distance from the inside observation point to the plume
origin. For example, the dashed circle around MW-1 has a radius of 16
feet, which is 40 percent of the distance (40 feet) from MW-1 to the plume
origin. Well MW-8 is located within this radius and the mid-point
between the two wells (marked as point "v") is relatively close to the
actual plume boundary. Error in the estimated boundary increases with
distance beyond this radius. For example, well MW-6 is considerably
outside the 16 foot radius and the midpoint (point "u") significantly
overestimates the plume boundary. For interior observation points, these
IV-8
-------
Exhibit IV-3
Placement Of Observation Points For
Delineation Of Free Product Plume
PLUME ORIGIN
BOUNDARY OF
FREE PRODUCT
PLUME
0 10 20 30 FT
IV-9
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conditions are reversed. Well MW-2 is an internal observation point,
which lies 70 feet j&om the plume origin. The dashed circle around MW-2
has a radius of 28 feet (40 percent of 70 feet). Note that wells either on
this radius (MW-4) or inside (MW-7), result in an underestimation of the
plume boundary (points "x" and "z", respectively). The midpoint (point
"y") between wells MW-1 and MW-3 (just slightly outside the 28 foot
radius) is reasonably close to the actual plume boundary. If the
observation point is too far outside the radius, then the extent of the plume
will be overestimated. For both interior and perimeter wells, interpolation
accuracy is unproved if a straight line between the two observation points
intersects the plume boundary at a right angle. Significant deviation from
90° results in increasing error in estimation of the plume boundary. As
may be expected, there are exceptions to these guidelines. For instance,
the midpoint (point "w") between MW-2 and MW-6 is reasonably close to
the actual plume boundary despite the fact that a line drawn between the
two wells intersects the boundary at an angle significantly different from
90°. In spite of the uncertainty in this process, a line beginning at the
plume origin drawn so that it connects points v-w-x-y-z and returning to
the origin is a reasonable approximation of the actual plume boundary.
The approximation could be improved by adding additional observation
points to fill in the gaps: Near point "w", between MW-3 and MW-4, and
between MW-1 and MW-4. Exhibit IV-4 shows alternative observation
point spacing for free product plumes of various sizes and shapes. In
reviewing a free product recovery plan, the adequacy of the delineation of
the free product plume is one of the first technical factors to be checked.
If the extent of the plume is not defined in all directions from the source
area (plume origin), then more site characterization is required. This
deficiency frequently occurs when the free product plume is not defined
beyond the site property boundary.
Excavations And Test Pits
Excavation of tanks or pipelines is commonly performed soon after
a hydrocarbon release has been confirmed or suspected. These
excavations provide for direct observation of the areal and vertical
distribution of hydrocarbons. Such observations, if noted and located on a
sketch map, can be used to partially identify the extent of free product.
However, where the water table is below the maximum depth of the
excavation equipment, the extent of lateral spreading at the water table
won't be defined.
For those sites where the water table is very shallow (i.e., less than
8 feet), excavation of test pits can be a quick and cost effective approach to
delineating the extent of free product. Direct observations of the geologic
media and potential preferential permeable pathways or barriers can also
IV -10
-------
Exhibit IV-4
Delineation Of Free Hydrocarbon Plume Extent
Using Soil Borings Or Probes And Monitoring Wells
(a) Small plume, well defined in all directions,
distance between soil borings about 20 feet
(c) Large plume, defined in all directions, with
borings spread at reasonable locations
Tanks
Free Hydrocarbon
(b) Small plume, not delineated in NW direction
(d) Large plume, not delineated offsite-
unacceptable
LEGEND
« Monitor Well or Well Point
Soil Boring
N
IV-11
-------
be obtained from test pits. The practicality of using of test pits diminishes
with depth. Entry into test pits greater than 4 feet requires shoring, a
trench box, or sloping of the sides of the excavation to protect workers
from cave-in. Such measures although necessary, can be expensive and
time consuming to construct or install. In some cases observations can be
made from the surface without actually entering the excavation, but visual
inspection of deep test pits from the surface is more difficult and less
reliable than in shallow test pits. Also, excavated materials, if
contaminated, will have to be handled appropriately (e.g.,
treatment/disposal) which can add to the expense of the investigation.
Soil Borings
The three-dimensional distribution of liquid hydrocarbons can best
be determined through a systematic program of soil sampling and free
product thickness measurements. These observations may be collected
through the use of traditional soil boring and sampling equipment or
direct push (DP) technologies. Traditional soil boring techniques include
augers (both drill rig-operated hollow-stem and solid stem as well as hand
augers) and other rotary drilling methods. Core samples collected by
auger rigs are typically obtained using split-spoons and shelby tubes.
Direct push technologies, which are also known as "direct drive" and
"soil probe" technologies, also include cone penetrometer (CPT) and
relatively simple, mechanically assisted push samplers (e.g., impact
hammers, hydraulic presses).
DP systems drive, push, and/or vibrate small-diameter steel rods
into the ground. These rods may be fitted with specialized tools to collect
subsurface samples and data either continuously or over discrete intervals.
A wide variety of sampling tools is available for collecting samples of
solids (soil), liquids (free product and groundwater) and gas (soil vapor).
CPT cones are specially designed to collect continuous lithologic data as
the tools are pushed at a constant rate into the subsurface. The presence of
free product can be detected using laser induced fluorescence (LIF)
technology or other in situ analytical screening methods.
DP technologies are generally suitable to depths of up to 100 feet under
ideal conditions (i.e., unconsolidated soils free of coarse gravels and cobbles),
but at most sites the depth range is between 20 and 60 feet. Deeper penetration
typically requires rotary (air or mud) drilling methods. Manual techniques are
generally only practical to depths between 0 and 15 feet. None of the DP
technologies is applicable for sites overlying bedrock, large cobbles or
boulders, or cemented sedimentary rock. Under such circumstances, even
augers may not be suitable, in which case rotary drilling/coring techniques
may be required.
IV-12
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Direct push techniques offer the following advantages relative to
standard soil boring methods:
Ability to collect samples rapidly and obtain a large number of
samples.
Capability to collect samples of soil, liquid, and gas.
Little or no generation of soil cuttings.
Deployment vehicles are more mobile and require less overhead
clearance than drill rigs.
Lower cost per sample in most settings.
At sites where the use of DP technologies is appropriate,
characterization of the subsurface can be more comprehensive than is
typically achieved using traditional methods. Where free product recovery
(or other remedial alternatives) is required, a more efficient and cost-
effective system can be designed for sites that are better characterized.
The additional expense of a site characterization conducted using DP
technologies can be recovered (possibly many times over) .in savings
achieved during the remediation phase. However, because the size of the
DP borehole is small, installation of free product recovery wells usually
must be accomplished with traditional drilling rigs.
Monitor Wells
Properly installed and constructed monitor wells can be used both
to delineate the extent of free product and monitor temporal changes in
free product accumulations. However, it is also important to realize that
monitor wells are subject to significant limitations in their ability to
provide accurate measurements of the thickness of free product in the
surrounding soil. Free product can accumulate in a well only if the well is
open (i.e., screened) across the zone of free product (Exhibit IV-5a). A
well screened above the water table will generally be dry (Exhibit IV-5b).
A well screened below the zone of free product will collect water but no
free product (Exhibit IV-5c). Within a well with a properly positioned
screen, the thickness of free product typically fluctuates in response to
changes in water table elevation. With each rise (or fall) in water table
elevation, the measured thickness of free product also changes, resulting in
a different calculation of "actual" thickness in the soil (Durnford, et al.,
1991). Where a free product recovery plan relies on wells for free product
delineation, the reviewer should check the construction diagram of each
well and verify that the open (screened) interval of each well straddles the
IV- 13
-------
Exhibit IV-5
Monitoring Well Installations And Their
Ability To Detect Free Product
Hydrocarbon
water contact
(a) Properly Installed well for monitoring
free product accumulation
Free hydrocarbon
er
Hydrocarbon
water contact
(b) Well Is dry
(c) Well contains only water
Source: API, 1996. A Guide to the Assessment and Remediation to Underground
Petroleum Releases, 3rd edition. API Publication 1628, Washington, DC.
Reprinted Courtesy of the American Petroleum Institute.
IV- 14
-------
water table. Where wells are initially installed with short screens (i.e., 5
feet or less), changes in the water table elevation may result in a dry well
(declining water table) or in a well that is screened below the zone of free
product (rising water table). Even in properly constructed wells, the
absence of free product may not necessarily indicate that petroleum
hydrocarbons (including free product and residual and trapped fractions)
are not present in the soil. Similarly to the observation that water may
take days or weeks to enter some monitor wells constructed in clayey soil,
free product may not initially appear in monitor wells. Such a condition
indicates that the relative permeability with respect to free product is very
low, hence the mobility of the free product is also low. This may also
result in a lower calculated volume of free product.
Monitor wells may be installed by any of several methods. (See
Driscol, 1986, and Aller et al, 1989, for detailed descriptions of modern
well drilling methods.) For unconsolidated media, hollow-stem augers are
used most commonly. The well casing and screen are inserted through the
opening in the auger. Depending on the stability of the well bore, the sand
pack, sealing, and grout can be placed as the augers are retracted or after
the augers have been removed. After the monitor well has been
constructed, it should be developed by surging or pumping until water is
free of turbidity. The development of new wells in very fine grained
materials may not be practical because of its slow recharge rate. For a
well with a slow recharge rate, development involves dewatering the well
and allowing it to recover for one or more cycles. The development of the
monitor well will tend to pull in free product and overcome capillary
barriers as a result of the smearing of fine-grained material on the well
bore. Without adequate development, free product may accumulate very
slowly in the monitor wells (over a period of months). In these cases,
initial estimates of the extent of free product may be understated. Product
may also enter slowly, or not at all, if the wrong sized sand (filter) pack
has been installed. The sand (filter) pack must be four to six times coarser
than the aquifer material (Hampton and Heuvelhorst, 1990). The rate of
product entry and recovery in wells can be improved by using
hydrophobic filter packs (Hampton, 1993).
The presence of free product at a well is indicated by the
accumulation of a measurable thickness of hydrocarbons in it. Three
following methods (see Exhibit IV-6) are commonly used to measure free
product thickness in a well:
Steel tape and paste
Interface probe, and
Bailer.
IV- 15
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Exhibit IV-6
Methods For Measuring Accumulations Of
Free Liquid Hydrocarbons In A Well
a. Steel tape with water and
hydrocarbon-finding pastes
b. Interface probe
c. Bailer
Source: API, 1996. A Guide to the Assessment and Remediation to Underground
Petroleum Releases, 3rd edition. API Publication 1628, Washington, DC.
Reprinted Courtesy of the American Petroleum Institute.
IV- 16
-------
The pastes used with the steel tape are sensitive to hydrocarbons and
water. Commercially available interface probes sense the presence of both
oil and water. The first two methods are accurate to within about 0.01 foot
and are convenient for determining the elevation of the air/free product
and oil/water interfaces. Whenever possible measurements should be taken
using either steel tape and paste or an interface probe. A bailer is a
transparent cylinder with a check valve at its base. The bailer method can
significantly under- or over-estimate the thickness of free product in the
well and should not be used for determining the elevations of air/free
product and free product/water interfaces. Disposable bailers, which are
commonly dedicated to monitoring wells containing free product, typically
collect an unrealistically small product thickness because of the small size
of the intake holes. The use of bailers should be limited to verification of
the presence of free product in a well or collection of a sample of it.
Bailers can be used to remove liquids from monitoring wells during bail-
down tests that are designed to determine the rate of free product recovery
into wells.
Volume Estimation
Knowledge of the volume of hydrocarbons in the subsurface is
useful for evaluating the performance of a free product recovery system in
terms of both total volume recovered and time required for recovery. In
some instances the original release volume may be unknown but can be
estimated by calculating the volume of free product present in the
subsurface. Several methods can be used to estimate hydrocarbon
volumes. These include:
Compilation of historical information on release events and from
inventory records.
Soil sampling and analysis for total petroleum hydrocarbons.
Correlation of the thickness of free product measured in
monitoring wells to total volume of free product.
Evaluation and projection (extrapolation) of free product recovery
data.
The first two approaches yield estimates of total hydrocarbonsresidual
and freepresent in the subsurface. The last two methodsproduct
thickness measured in monitor wells and recovery dataprovide estimates
of the volume of free product. None of these four methods are entirely
precise in most settings because of limited and uncertain data. Even where
IV-17
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substantial data are available and several estimation methods used, volume
estimates with an uncertainty of minus 50 percent to plus 100 percent are
the best that can be expected. Exhibit IV-7 presents a brief summary of
the salient points of each of these four methods.
The relative mass present as free and residual liquid hydrocarbons
is large compared to the mass of dissolved or vapor phase hydrocarbons in
most subsurface settings. Residual hydrocarbons may represent as much
as 50 to 80 percent of the total volume that was originally released.
Recoverable free product typically represents 20 to 50 percent of the total.
The ratio of free product to residual liquid hydrocarbons tends to decrease
with time as plume migration and other processes occur that trap free
hydrocarbons (e.g., rising or falling water table). The relative permeability
(and mobility) of the free product decreases as more of the free product is
recovered and the level of liquid hydrocarbon saturation decreases. When
the saturation approaches the residual saturation of the geologic medium,
free product will stop flowing readily into monitor/recovery wells. At this
point, the recovery well or recovery system should be switched to operate
intermittently or possibly turned off altogether. Small quantities of liquid
hydrocarbons may continue to slowly drain into wells, but the rates of
drainage are usually not sufficient to justify continuous operation of the
recovery system.
Volume Estimates Based On Release History
Historical records of release events and hydrocarbon inventories
can be used to estimate the total amount of hydrocarbons lost. When
accurate inventory or release data are available, the amount lost is likely to
be greater than the amount in the subsurface as a result of volatilization
and biodegradation. The reliability of historical data ranges widely, but
generally, the older the information, the less reliable it is. Furthermore,
historical data generally cannot be used to characterize phase distribution
in the subsurface.
Even though volume estimates based on release and inventory data
may have limited reliability, these estimates are useful in at least two
important ways. First, the volume estimate based on historical data can be
compared with volume estimates obtained with other approaches to
provide a check on the other methods. Second, historical information on
when releases began can provide a basis for initial estimates of the extent
of free product migration that can be used to assist in locating sampling
points and wells for site characterization.
IV- 18
-------
Exhibit IV-7
Methods For Volume Estimation
Method
Approach & Results
Advantages
Disadvantages
Release History
Review inventory records to determine
volume(s) and date(s) of release(s).
Relatively simple and statistically accurate
if accurate historical data are available.
Data rarely accurate given numerous
potential error sources (e.g.,
measurement technique, volume
changes due to temperature)
TPH Concentration in
Soil Samples2
Convert TPH concentrations in soil
samples to saturations and integrate
these values over the area of
contamination.
Data are relatively easy to collect; several
methods are available for data integration.
Calculations required are relatively
complicated; requires a lot of data to
reduce uncertainty associated with
calculated volume; results may differ
among various methods for data
integration; TPH analysis may not be
representative of actual petroleum
hydrocarbon saturations.
Product Thickness in
Wells
Measure the thickness of the
accumulated layer of free product in all
monitoring wells.
Free product thickness measurements in
monitor wells are routinely collected on a
regular basis; the thickness of the free
product layer in the monitor well can be
measured quite accurately; several
methods are available for data analysis.
Product thickness in wells usually
exaggerates the thickness in the
aquifer-this effect is more
pronounced in finer-grained geologic
materials; none of the methods that
correlate product thicknesses
measured in wells to actual product
thickness in the soil are reliable either
in the field or in the laboratory.
Extrapolation of
Recovery Data
Sum the cumulative product recovery
volume and an estimate of the residual
volume.
Recovery data are routinely collected.
Works best during later stages of
recovery; many factors can bias
recovery (e.g., smearing); requires
two types of data. _
2 The U.S. Air Force is currently working on an alternative method of using TPH values based on examination of TPH fractions.
EPA will release information on this process after peer review has been completed.
-------
Volume Estimates Based On Soil Samples
Estimation of the volume of free product in the subsurface based
on soil sample data first requires the collection of soil samples and their
subsequent analysis for hydrocarbon content. Hydrocarbon content in soil
samples can be measured by a variety of standard laboratory methods.
These methods include solvent extraction, solvent extraction with
distillation, and centrifuging (Cohen and Mercer, 1993; Cohen etal,
1992). The total petroleum hydrocarbons (TPH) analysis commonly used
in site assessments is based on solvent extraction. For sites where
sufficient TPH data are available, volumes of hydrocarbons in the
unsaturated and saturated zones can be estimated. One limitation of TPH
data is that it does not distinguish between individual petroleum
hydrocarbons or between petroleum hydrocarbons and other non-
petroleum organic matter that may be present in the soil sample.
The estimation of hydrocarbon volumes based on soil sample data
is subject to significant uncertainty because of the sparseness of the data
and the often extreme variability in hydrocarbon concentration within the
soil. Exhibit IV-8 shows how variable hydrocarbon saturation can be
within the same boring and between three different borings at a typical
site. The detail shown in Exhibit IV-8 is much greater than that obtained
during most site characterization investigations, but even with this amount
of detail at one or more boring, there is still tremendous uncertainty about
concentrations in the soil between the borings.
The procedure for estimating liquid hydrocarbon volumes from
TPH data involves two calculation steps: (Step 1) TPH results are
converted to saturation values at each point, and (Step 2) the volume of
liquid hydrocarbons is determined by integrating point saturation data over
the volume of subsurface where hydrocarbons are present. The conversion
calculation (Step 1) is straightforward and is illustrated in Exhibit IV-9.
Integration of the total hydrocarbon volume (Step 2) can be accomplished
using standard interpolation and integration techniques. As a simple
example, TPH (saturation) results are plotted at their collection locations
on a site map. Contours of equal saturation are drawn on the map. The
area and volume represented by each contour level is then calculated.
Integration is merely the summation of the individual volumes. There are
a number of more sophisticated techniques, including computer software,
but discussion of these is beyond the scope of this manual. It is also
important to recognize that interpolation and integration methods yield
only approximations of what is actually present in the field and different
methods using the same data set can result in volume estimates that range
from minus 30 percent to plus 50 percent. In general, as the number of
data points increases the error associated with the method decreases.
IV-20
-------
Exhibit IV-8
Measured Hydrocarbon Saturation Profiles At Three Boreholes
Showing Variability Due To Vertical Heterogeneity
A)
BOREHOLE 11
0.00
0.05 0.10 0.15 0.20 0.25
Hydrocarbon Saturation
B)
2501
200-
150-
100
50-
o-
BOREHOLE 12
.Qil/WaterJntecface
.£? -50"! T 1 1 ' 1 ' ' ' ' '
IE 0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50
Hydrocarbon Saturation
C)
60-
40-
20-
o-
-20-
-40-
-60-
-80-
-100-
-120-
0.00
BOREHOLE 13
0.05 0.10 0.15
Hydrocarbon Saturation
0.20
0.25
Source: From Huntley, et. al., 1992
IV-21
-------
Exhibit IV-9
Calculation Procedure To Convert
TPH Data From Soil Samples To Hydrocarbon Saturations
TPH analysis results for soil samples may be converted to
hydrocarbon saturation by the following equation:
So = TPHx-
(i-*)pgr*io-
mg
where:
mg/kg
TPH =
Pgr =
Po =
total hydrocarbon saturation (dimensionless)
total petroleum hydrocarbon concentration in
grain density (typically 2.65 g/cm3)
porosity (dimensionless)
density of the hydrocarbon, liquid (g/cm3).
This equation applies to both the unsaturated and saturated
zones.
The amount of free hydrocarbon present can be calculated if
residual hydrocarbon saturation is known or estimated.
Usually residual saturations are not known or measured, but
literature values (e.g., Mercer and Cohen, 1990) can be used
as estimates. The free hydrocarbon saturation is given by:
Sof =
- S
where:
Sof = free hydrocarbon saturation
Sr = residual hydrocarbon saturation.
IV-22
-------
Volume Estimates Based On Product Thickness In Wells
The limitations of monitor wells in providing representative
measurements of free product thickness in the adjacent soil are well
documented. Fluctuations in the water table can result in large differences
in measured hydrocarbon thickness even though the in situ volumes are
not significantly changed. Increases in hydrocarbon thickness are
commonly observed with declining water tables. API (1989) attributes the
thickness increase to drainage from the unsaturated zone. As the water
table falls, hydrocarbons previously trapped as a residual phase can
become remobilized and enter into wells. Kemblowski and Chiang (1990)
relate the changes to preferential fluid flow through the well (Exhibit IV-
10).
Many investigators have tried to develop methods to explain how
small amounts of mobile hydrocarbons can lead to exaggerated
thicknesses of hydrocarbons measured in wells. Hampton and Miller
(1988) and Ballestero et al., (1994) provide comprehensive reviews of the
methods used to estimate the thickness of free product in the adjacent soil
from measurement in monitor wells. A comparison of the predictability of
these alternative methods indicates an order of magnitude accuracy of the
predicted versus the measured free product thickness among the methods.
These investigations can be grouped into two primary approaches: (1)
Derivation of empirically-based correlationstypically based on fluid
density differences, grainsize of the geologic media, or height of the water
capillary fringe, and (2) development of models based on idealized
capillary pressure-saturation curves. In spite of the intense attention that
has been focused on developing a correlation between free product
thickness measured in wells and volume of free product in the soil, none
of the available methods has been particularly reliable when tested either
in the field (Durnford et al, 1991; Huntley et al., 1992; and Ballestero et
al., 1994) or even in the laboratory (Hampton and Miller, 1988).
Durnford etal.,(l99l) summarize the limitations of the methods
developed to relate the free product thickness measured in monitor wells
to the volume of free product in the soil as follows:
Free product thicknesses observed in monitoring wells
change over time as the water table fluctuates. Each
different measured thickness of free product results in a
different calculation of free product in the aquifer, even if
the actual volume of free product (including residual and
trapped) hasn't changed.
IV-23
-------
Exhibit IV-10
Effects Of Falling Or Rising Water Table
On Hydrocarbon Thicknesses Measured In Wells
Monitoring Well
(a) Hydrocarbon thickness increase for falling water table
Monitoring Well
(b) Hydrocarbon thickness decrease for rising water table
Source: Kemblowski and Chiang, 1990
IV-24
-------
None of the estimation methods accounts for residual and
trapped petroleum hydrocarbonsa portion of these
fractions can be returned to the free product fraction as the
water table moves up or down.
Methods that are based on measurement of soil and fluid
properties require measurements (e.g., curves of capillary
pressure vs water saturation) that are difficult to obtain in
the field, and laboratory-derived measurements may not
accurately represent field conditions.
None of the methods account for spatial variability
(heterogeneity) of aquifer parameters. The movement of
free product is strongly dependent upon aquifer
heterogeneities, which are rarely represented adequately by
"average" properties.
Despite the drawbacks with these volume estimation methods, they
are frequently used in practice. To illustrate how some of these methods
are used, we present a comparison of seven methods reported in Ballestero
et aL, (1994). The seven different approaches can be grouped into the
following four categories:
Correlation based on the density of the liquid hydrocarbon
(de Pastrovich et aL, 1979);
Correlation based on properties of the geologic medium
(Hall, et aL, 1984);
Correlation based on the height of the water capillary fringe
(Blake and Hall, 1984; Ballestero etal, 1994; and Schiegg,
1985); and
Models based on idealized capillary pressure relationships
for homogeneous porous media (Farr et al., 1990; and
Lenhard and Parker, 1990).
Exhibit IV-11 summarizes the results of calculations for each of the
different methods listed above using data from laboratory experiments
reported by Abdul et aL, (1989), with additional parameter values acquired
(where necessary) from the individual papers. A more complete
presentation (including the equations, variable descriptions, input data and
discussion of the salient features) is included in the Appendix. It is
IV - 25
-------
Exhibit IV-11
Comparison Of Seven Alternative Methods For
Correlation Of Product Thickness Measured In A Monitor
Well To Actual Thickness In The Soil
Calculated Results (Hydrocarbon Thickness in Soil)
Measured
hydrocarbon
thickness in
the soil (cm)
.
1
3
7
13
de
Pastrovic
h etal.
(1979)
1.1
12
13
13.9
16
Hall etal.
(1988)
-6.5
50.5
55.5
60.5
71.5
Blake and
Hall
(1984)
-16
1.1
4.4
9.7
13.4
Ballestero
etal.
(1994)
-16
1.1
4.4
9.7
13.4
Schiegg
(1985)
-28
29
34
39
50
Farr et
al.
(1990)
2.3
24.3
26.2
28.1
32.4
Lenhard
and
Parker
(1990)
7.1
74.3
80.2
86.1
99.1 ]
Note: All values in centimeters except those for Farr et al. (1990)
which are volume in crrvVcm2.
This comparison is based on a study published by Ballestero et
al. (1994) using data published in Abdul etal. (1989). Additional
data required for the methods of Lenhard and Parker (1990) and
Farr et al. (1990) were obtained from their respective papers.
Note that the results presented above are only applicable for the
data specified in this example. The use of different data may
alter the relative performance of the methods. Refer to the
Appendix for a more complete presentation of the individual
equations used in this comparison.
IV-26
-------
important to realize that the relative performance of these methods is
dependent upon the specific experimental conditions. Given another set of
data obtained from a different experiment using different soil (with
different grainsize, porosity, and residual saturation) and different liquid
hydrocarbon, the relative performance may be radically different. To
reiterate from the opening paragraph in this section, none of the available
methods has been particularly reliable when tested in either the field or the
laboratory. For any given site, it is probably not likely that the method
that will ultimately yield the closest match to conditions in the field can be
chosen a priori. However this is not to say that there is no point in using
these methods to estimate free product volumes. On the contrary, free
product thickness data collected from monitor wells is typically plentiful,
easily collected, and is usually accurate. In many instances these data may
be all that are available. What is most important is to not rely too heavily
on one method over another. The best approach is to use more than one
method so that a probable range of volumes can be calculated.
Volume Estimates Based On Extrapolation Of Free
Product Recovery Data
The difference between the volume of free product released and the
volume recovered equals the volume remaining in the subsurface. Often
the volume of the release is not known, but in theory it can be determined
if the volume of free product that has been (or is anticipated to be)
recovered and the volume remaining (or is anticipated to remain) in the
subsurface is known. Knowledge of any of these three volumes is
associated with a degree of uncertainty, and it is usually not possible to
quantify the error associated with estimates of these volumes. Many
factors contribute to this uncertainty. Some of the components of the
types of petroleum hydrocarbons typically stored in USTs are volatile
and/or soluble, and are therefore not likely to be measured as residual
hydrocarbons. Biodegradation may further decrease the amount of
hydrocarbons present in the subsurface. As was discussed previously,
hydrocarbon saturations in soil borings are highly variable in both the
vertical and horizontal directions. Samples with anomalously high or low
saturations can bias estimates of total residual hydrocarbons remaining in
the subsurface. Also, it is important to recognize that the rate of free
product recovery typically exhibits a logarithmic decrease with time. The
rate of decrease can be quite variable even on the same site due to
heterogeneities in the soil which influence residual saturation and relative
permeability. The estimate of product remaining in the subsurface as
either free or residual changes constantly with time as recovery progresses.
Despite these limitations, this method may offer the best (or only) means
IV - 27
-------
for estimating volumes at a particular site. Although this method works
best late in the recovery phase (after the cumulative recovery curve levels
off), it can be used at any time with the understanding that volume
estimates based on early recovery data will be associated with a higher
degree of uncertainty. Methods to estimate free product recovery rates are
presented in the following sections.
Estimation Of Recovery Rates
An important design consideration for free product recovery is the
rate at which liquid hydrocarbons can be collected by pumping or
skimming techniques. The rate of recovery will depend on the design of
the recovery system, the type(s) and distribution of free product in the
subsurface, and the hydrogeological conditions. Expected recovery rates
are used to size the free product storage tanks and oil/water separators,
and, to a lesser degree, to select and size recovery equipment and
treatment equipment. Not only is it important to estimate the initial
recovery rates but also to predict how the recovery rates will change with
time after recovery starts. Estimates of recovery rates can be obtained
from field tests (e.g., bail down tests, pumping tests) or from multiphase
flow analysis. Usually, recovery rates of free product decline after startup
because wells and trenches are located in areas where the volumes of free
product are highest. In some settings where wells or trenches pull free
product from some distance, recovery rates may increase for a significant
duration before declining.
Bail Down Test And Pumping Tests
A bail down test involves removing the free product from a well by
bailing and measuring the thickness of and depth to free product in the
well as it recovers. These tests have been used to estimate free product
thickness by some investigators (Hughes etal, 1988; Wagner etal., 1989;
and Gruszczenski, 1987) with limited success. These tests can easily
provide estimates of initial recovery rates for a skimming type operation
(see Exhibit IV-12, Method 1). In order for the results of a bail down test
to be applicable, the free product recharge rate should be slow relative to
the rate of groundwater recharge. Where free product recharges the well
in less than a few minutes, it is difficult to accurately monitor recovery
rates (Hampton, 1993).
IV-28
-------
Exhibit IV-12
Sample Calculations For Estimating
Initial Free Product Recovery Rates
Method 1. Bail down testing (Applicable to skimming- Field Data
1.
2.
3.
4.
5.
iypc icuuvciy ayaieuiaj.
Inside Diameter of Well Screen = 4 inches
Radius = 2 inches
= 0.1 66 foot
Maximum thickness from table. = 1.15 feet
-
80% x maximum thickness
recovery.
(0.8x1.15) = 0.92 foot
Time corresponding to 80% of
recovery interpolated from table.
3 hours 24 min = 204 min
Compute gallons per foot of oil
Recovery
Free Product
Time Thickness (ft)
2 min
4 min
10 min
30 min
1 hour
2 hours
4 hours
8 hours
24 hours
48 hours
thickness in well screen.
n x (well radius in ft)2 x (conversion factor in gal/ft3) = gal/ft
n x (0.166)2 ft2 x 7.48 gal/ft3 = 0.65 gal/ft
Compute average recovery rate to 80% recovery.
0.65 gal/ft x 0.92 ft/204 min = 0.003 gal/min .= 4.2 gal/day
Method 2. Constant rate pump test (Applicable to free
1.
2.
Time Since
0.01
0.03
0.12
0.30
0.51
0.85
0.95
0.98
1.15
1.10
Field Data
Cumulative
product recovery with water level depression). Pumping Hydrocarbons
Started
Pumping Rate = 10 gal/min
Compute average hydrocarbon recovery rate from 10 min
table for 24 hours. 20 min
40 min
52.1 gal/24 hours = 2. 17 gal/hour 1 hour
= 0.0361 gal/min 2 hours
_ , 4 hours
ComPute 8 hours
Hydrocarbon Recovery Ratio = Hydrocarbon Recovery Rate 24 hours
Total Pumping Rate
0.0361 gal/min = QQQ^ = ^^
10 gal/min
Collected
0.0 gal
0.3 gal
0.8 gal
2.5 gal
5.8 gal
14.6 gal
23.8 gal
52.1 gal
IV-29
-------
For systems where free product will be collected by active
pumping of groundwater and product, a pumping test can be used to
estimate initial free product recovery rates (see Exhibit IV-12, Method 2).
Pumping tests (or aquifer tests) are usually performed to determine
groundwater flow properties such as hydraulic conductivity and
transmissivity. Estimates of free product recovery rates can be obtained
by collecting additional data in conjunction with a standard (groundwater)
pumping test or by conducting a specialized pumping test or pilot test.
A standard pumping test involves pumping groundwater at a
constant rate and monitoring changes in groundwater elevations in the
pumping and nearby wells during the test. If free product is present in the
vicinity of the well, the pumped fluid will contain both free product and
groundwater. The ratio of free product recovered to total fluid recovered
can be determined at different times during the test by collecting samples
of pumped fluid. These samples may show considerable variability, so as
many samples as practicable should be collected during the test. Where
the ratios of recovered product to total fluid are more than a few percent,
simple volume measurements of the separated liquids may be used to
determine the recovery ratio (see Exhibit IV-13). Usually the recovery
ratio of free product to total fluid is less than a few percent, in which case
the ratio may be determined by a standard TPH or oil and grease analytical
method.
Estimates of free product recovery rates can also be obtained from
pilot tests or records of free product pumping that may have been
performed as an interim or emergency removal action. Information from
pilot tests or prior free product recovery systems provide the best estimates
of expected free product recovery rates because the duration and rates of
pumping are usually much greater than those of bail down or pump tests.
Multiphase Flow Analysis
The theory of multiphase flow in porous media has been widely
used in petroleum reservoir engineering for over 50 years. During the past
decade, these same theories have been applied to analysis for
environmental applications. Because, multiphase flow theory results in
complex non-linear partial differential equations, few simple solutions to
practical problems are available. One such solution is presented in the
preceding section (see Exhibit IV-13). Commonly, the governing
equations are solved by a variety of sophisticated numerical techniques
using computer models.
IV-30
-------
Exhibit IV-13
Computational Procedure For Determining
Ratio Of Free Product Recovery
To Total Fluid Recovered From A Single Recovery Well
Basic Equations:
Separator
Treatment
Hydrocarbon I
and Water
I Hydrocarbon
and Water
Mobility of Water =
Transmissivity of Water T =
Mobility of Free Product =
Fransmissivity of Free Product T =
where:
k is the intrinsic permeability (L2)
kra is the relative permeability of water {dimensionless)
k,^ is the relative permeability of free product (dimensionless)
"k~ro is the average,relative permeability of free product layer
(dimensionless)
pw is the density of water (ML3)
p0 is the density of free product (ML3)
g is the gravitational constant (LT2)
£/w is the viscosity of water (ML"1T1)
H0 is the viscosity of free product (ML1T1)
b0 is the thickness of free product layer (L)
bw is the thickness of aquifer below free product layer (L)
Assumed: Water transmissivity of free product layer is negligible
IV-31
-------
Exhibit IV-13 (continued)
Computational Procedure For Determining
Ratio Of Free Product Recovery
To Total Fluid Recovered From A Single Recovery Well
General Equation:
Ratio
Free Product Recovery Rate)
Total Fluid Recovery Rate
bokro
where:
Q is volumetric flowrate of free product (o) or groundwater (w)
Assumed: Same hydraulic gradients exist in free product layer and groundwater
EXAMPLE:
A 2-foot-thick hydrocarbon layer has an average hydrocarbon saturation of 0.5, a
viscosity of 4 centipoise, a density of 0.9 g/cm3. The average relative permeability for a
free product saturation of 0.5 is assumed to be 0.25. The pumping well is screened across
the hydrocarbon layer to the base of the aquifer which has a saturated thickness of 20 feet
including the hydrocarbon layer.
QQ To 2ftxO.25xO.9g/ml/4cp
2ftxO.25xO.9g/ml/4cp + 18ftx1 g/ml/1cp
= °-1125
0.1125+18
- 0.0062
For a total fluid production rate (Q0 + QJ of 2 gallons per minute, determining
free product recovery rate, Q0
Q0 = Ratio x (Q0 + QJ = 0.0062 x 2 gpm = 0.0124
gpm
IV-32
-------
Calculations Of Initial Free Product To Total Fluid
Recovery Ratio. A straightforward calculation based on the relative
mobility of free product and water can be used to determine the ratio of
free product to total fluid production under pumping conditions in a single
well. This procedure is described and illustrated in Exhibit IV-13, which
shows that for thin hydrocarbon layers and moderately high viscosities, the
recovery of free product will be a small portion of the total fluid
production in the well.
Use Of Computer Models. In theory, computer models based
on multiphase flow concepts can be used to predict free product recovery
rates. Selection of a model for a particular site must be made carefully
because all models are not appropriate for all sites. Factors to be
considered include; complexity of site geology, availability of input data,
and special features of the site (e.g., pumping wells, fluctuating water
table). Some of the numerous multiphase flow models that have been
developed include:
Simplified models simulating downward migration of liquid
hydrocarbons through the unsaturated zone, radial transport of a
hydrocarbon lens in the watertable, and radial migration of
hydrocarbons to a recovery well (El-Kadi, 1992; El-Kadi, 1994;
Weaver et al., 1994; and Charbeneau and Chiang, 1995).
Complex numerical models (finite-difference and finite-element)
of immiscible multiphase flow in porous media in cross-section or
three-dimensional (Faust et al, 1989; Kaluarachchi and Parker,
1989; Katyal et al, 1991).
Complex numerical models of areal hydrocarbon migration in
unconfined aquifers simplified from 3-D to 2-D (Kaluarachchi et
al, 1990).
Despite the seemingly wide variety of models that are available, in
practice the usability of models for reliable prediction of free product
recovery rates is limited for a variety of reasons. Many of the models
require data that are not measurable in the field (e.g., relative permeability-
capillary pressure relations). Mishra et al. (1989) present one solution to
this problem; they developed a model to estimate relative permeability-
capillary pressure relations from grain-size curves, which can be
developed relatively easily from soil samples. The problem is that each
soil sample would yield a different grain-size curve, and hence, different
relative permeability-capillary pressure curves. As even subtle
IV-33
-------
heterogeneities can radically influence the movement of free product in the
subsurface, no single curve is likely to be adequate to characterize the
entire site. Collection of a sufficiently large number of samples may be
prohibitive. Assumptions such as vertical equilibrium and vertical
uniformity, which are usually required by the simpler two-dimensional
models, are not generally applicable.
More often than not model simulations are very accurate only over
the period for which field data are available. Models are calibrated given a
set of field data (e.g., water table elevations, volume of product recovered)
collected over a specified period of time. Model parameters are then
adjusted so that the simulated results as closely as possible match the field
data. As more field data are collected, model parameters are adjusted so
that the simulation results once again closely match the field data. This
process is typically repeated every time additional data are available.
Often the final set of model parameters is quite dissimilar from the initial
set. If the initial parameters are used over the entire simulation period,
then the match is usually best during the early stages and worsens as the
simulation progresses. Conversely, if the final parameters are used to
simulate the behavior measured in the field, the match is typically poor
during the initial stages, but improves as simulation time progresses up to
the point in time that the latest data are available. It is reasonable to
expect that the simulation results would begin to worsen as the simulation
continued to progress into the future.
Appropriate use of models generally requires that they be used by
persons experienced in the use of models. As the complexity of the site
and the selected model both increase, so must the sophisitication of both
the modeler and the computer. Adequately trained modelers command
relatively high hourly billing rates. A single simulation using a complex,
multi-phase model may take 24 hours or more to run even on today's
fastest desk top computers. Often clients are billed for computer time as
part of the overall cost for computer modeling. Between the labor rates
and the computer usage rates, several simulations of even a small site can
result in a large invoice.
Because of limited reliability and expense of use, multiphase
computer models are seldom used to estimate recovery rates for a free
product recovery plan. For sites with large spills or large volumes of free
product in the subsurface, the expense and effort associated with these
models may be warranted if it can help significantly reduce the cost of
recovery or improve the effectiveness of free product recovery. Where
models have been used to design free product recovery systems, the
IV-34
-------
analysis is likely to contain significant uncertainty that should be explicitly
addressed in the model description.
Recoverability Of Free Product
Chapter IV has presented several methods for evaluating the
volume and recoverability of free product. This section presents a
discussion limited to those factors that are most relevant to the recovery of
the principal types of petroleum products typically stored in USTs (i.e.,
gasolines, middle distillates, and heavy fuel oils).
It has been established that the thickness of free product measured
in wells usually exceeds the thickness that is present in the surrounding
soil. Volume estimates based strictly on measured thickness in wells are
erroneous and are often significantly greater than the volume of product
that was released. Many methods have been developed to correlate the
measured thickness to volume in the soil, but none of the available
methods is reliable at all sites. Different methods applied to the same site
may yield radically different volume estimates. It is, therefore, important
not to rely on the estimate of any single method. Comparison of several
estimates may provide a reasonable range for the estimated volume. This
range may span an order of magnitude.
The steps involved in estimating the volume of free product in the
subsurface include measurements of thicknesses in wells, borings, and
excavations; determination of the direction(s) of groundwater flow and
free product migration; and estimation of the retention capacity of the soil.
Once the probable extent and realistic thicknesses of the free product
plume (or pool) have been determined, a variety of techniques are
available to calculate the total volume of the release. Under the most
favorable conditions, only a fraction of the total release will be
recoverable. Recoverable volumes typically range from 20 to 50 percent
of the total release. Factors that influence the recoverable percentage
include water table fluctuations (which can create a "smear zone"), depth
to water table, and soil properties (e.g., heterogeneity, pore size, layering).
The initial rates of product recovery are best estimated from bail
down tests and pumping tests. Knowledge of the expected recovery rates
are important in sizing components of the treatment process. Often the
recovery of product declines significantly from initial rates, especially for
wells located where free product volume is highest. Various computer
models can, in theory, be used to predict future rates of free product
recovery. However, these models are expensive to use and have limited
reliability.
IV-35
-------
Primary References
Abdul, A.S., S.F. Kia, and T.L. Gibson, 1989. Limitations of monitoring
wells for the detection and quantification of petroleum products in
soils and aquifers, Ground Water Monitoring Review, 9(2):90-99.
API, 1996. A Guide to the Assessment and Remediation of Underground
Petroleum Releases, Third Edition, API Publication 1628,
Washington, D.C.
Ballestero, T.P., F.R. Fiedler and N.E. Kinner, 1994. An investigation of
the relationship between actual and apparent gasoline thickness in
a uniform sand aquifer, Ground Water, 32(5):708-718.
Blake, S.B. and R.A. Hall, 1984. Monitoring petroleum spills with wells:
some problems and solutions, Proceedings, Fourth National
Symposium on Aquifer Restoration and Groundwater Monitoring,
National Water Well Association, Columbus, OH, pp. 305-310.
de Pastrovich, T.L., Y. Baradat, R. Barthel, A. Chiarelli, and D.R. Fussell,
1979. Protection of ground water from oil pollution, CONG A WE,
The Hague, Netherlands.
Durnford, D., J. Brookman, J. Billica, and J. Milligan, 1991. LNAPL
distribution in a cohesionless soil: a field investigation and
cryogenic sampler, Ground Water Monitoring Review, 11 (3V115-
122.
EPA, 1993. Subsurface Characterization and Monitoring Techniques,
Volume 1, Solids and Groundwater, EPA/625/R-93/003a.
Farr, A..M., R.J. Houghtalen, and D.B. McWhorter, 1990. Volume
estimation of light nonaquous phase liquids in porous media,
Ground Water, 28(l):48-56.
Hall, R.A., S.B. Blake, and S.C. Champlin, Jr., 1984. Determination of
hydrocarbon thickness in sediments using borehole data,
Proceedings, Fourth National Symposium on Aquifer Restoration
and Groundwater Monitoring, National Water Well Association,
Columbus, OH, pp.3 00-3 04.
IV-36
-------
Hampton, D.R. and P.D.G. Miller, 1988. Laboratory investigation of the
relationship between actual and apparent product thickness in
sands, Proceedings Conference on Petroleum Hydrocarbons and
Organic Chemicals in Ground Water - Prevention, Detection, and
Restoration, National Ground Water Association, Dublin, OH, pp.
157-181.
Kemblowski, M.W. and C.Y. Chiang, 1990. Hydrocarbon thickness
fluctuations in monitoring wells, Ground Water, 28(2):244-252.
Lenhard, RJ. and J.C. Parker, 1990. Estimation of free hydrocarbon
volume from fluid levels in monitoring wells, Ground Water,
28(l):57-67.
Schiegg, H.O., 1985. Considerations on water, oil, and air in porous
media, Water Science and Technology, 17:467-476.
IV-37
-------
-------
-------
-------
CHAPTER V
HYDROCARBON RECOVERY
SYSTEMS/EQUIPMENT
-------
-------
CHAPTER V
HYDROCARBON RECOVERY
SYSTEMS/EQUIPMENT
The selection of a hydrocarbon recovery system and its associated
equipment is based on specific remedial objectives, design constraints, and
site conditions. Hydrocarbon recovery systems are chosen to satisfy
remedial objectives involving the control of petroleum hydrocarbon
migration, maximum free product recovery, and simultaneous free product
and vapor phase collection. Design constraints governing the selection of
recovery systems may be site specific, such as limited access to wells.
Other constraints may involve conflicts between free product recovery and
other aspects of the corrective action; for example, a pump-and-treat
remedy may adversely affect free product recovery by smearing the zone
of free product.
The general site conditions affecting product recovery are the
volume of the free product, its type and areal extent, and the depth at
which it is located. Hydrogeologic conditions such as permeability and
groundwater flow also influence the selection and design process of
recovery systems.
Four general techniques or approaches are used to recover free
product:
Free product removal/skimming systems.
Free product recovery with water table depression.
Vapor extraction/groundwater extraction.
Dual phase (liquid and vapor) recovery.
A description and applicability for each of these techniques is summarized
in Exhibit V-l. Further detailed discussion on the applicability of these
methods is provided later in this chapter. Exhibit V-2 provides a
comparison of the general features of these techniques.
Each of these methods involves the installation of recovery
equipment (e.g., skimmers, pumps, filters, or absorbent materials) in wells,
trenches, or excavations. Other aspects of free product recovery systems
consist of phase separation, storage, and treatment processes. In addition,
V-l
-------
Exhibit V-1
General Approaches To Free Product Recovery
Free Product
Recovery Approach
Description
Applicability
Skimming Systems
Free Product Recovery
With Water Table
Depression
Vapor Extraction/
Groundwater
Extraction
Dual-Phase Recovery
Free product is recovered
from a well or trench without
recovering groundwater.
Free product is recovered
from a well or trench along
with groundwater.
Groundwater is pumped to
create cone of depression in
water table to expand area of
influence.
Vacuum is applied to well(s)
above water table to recover
vapor phase and residual
hydrocarbons and to help
maintain high water table.
Free product and/or
groundwater is recovered
from wells by pumps.
Both liquids and vapors are
recovered from same well.
Groundwater production is
minimized, and water table is
stabilized.
Small volumes of free product are
removed because of limited area
of influence in open trenches or
excavations. Often used during
emergency or short-term remedial
actions.
Requires moderately permeable
to permeable subsurface
materials (silts, sands, and
gravels). Can be used in settings
with deep water tables. Often
used in long term (>1 year)
remedial actions. Produced
groundwater can be expensive to
treat.
Low to moderately permeable
materials (silts, silty sands). Often
used to enhance recovery of
hydrocarbons.
Generally low permeability
materials (clay, clayey silts, silts,
silty/clayey sands). Requires
surface seal (either naturally
occurring clay or man-made) to
prevent short-circuiting of
vacuum.
V-2
-------
EXHIBIT V-2
Comparison Of General Features
Of Free Product Recovery Systems
System
Skimming
Water Table
Depression
Vapor
Extraction/
Groundwater
Extraction
(VE/GE)
Dual-Phase
Recovery
Provide
Hydraulic
Control
No
Yes
Yes
Yes
Install in
Excavations
Yes
Yes
No
No
Require
Specialized
Wells
Depends on
diameter of
skimmer
No
Yes
Yes
Provide
Fluid
Separation
Yes
Yes dual-
pump systems
No single
pump systems
No
No
Produce
Ground
water
No
Yes
Yes
Yes
Product
Recovery Rate
Low
Low-high
depends on volume of
recoverable free
product and formation
characteristics
Low-high
depends on volume of
recoverable free
product and formation
characteristics
Low-high
depends on volume of
recoverable free
product and formation
characteristics
Capital
Costs
Low -med
Low-high
depends on
number of
pumps and
complexity of
system
Med-high
High
Operation and
Maintenance
Costs
Low
Low-high
depends on number
of pumps and
complexity of system
Med-high
High
<
u>
-------
groundwater pumped in conjunction with free product recovery must be
discharged. Collection and treatment equipment must also be monitored
and maintained during operation.
This chapter describes each of the four recovery approaches with
respect to its applicability, general design considerations, required
equipment, system operation and maintenance, and the monitoring and
termination of recovery activities.
Free Product Removal/Skimming Systems
The goal satisfied by skimming systems is the collection of free
product with little or no recovery of water. In general this approach
involves using skimming devices to remove product floating on the water
table in excavations, gravel-filled trenches, and wells. This type of system
is commonly used in interim remedial actions.
Applicability
Free product removal using skimming equipment is applicable in
settings where long-term hydraulic control of the dissolved hydrocarbon
plume is not required. In most settings skimmer operations will not
control the liquid hydrocarbon plume. The most common use of these
systems is inclusion in an interim action where free product has entered
open excavations. In general, skimming systems are applicable to settings
in which the amount of free product is small and exists in permeable
conduits such as utility bedding or buried underground open structures.
The hydraulic conductivity should be greater than 10"4 cm/s to ensure a
sufficient influx of free product to the skimmer. Skimmers may also be
used in conjunction with other free product removal programs such as in
monitoring and extraction wells for water table depression methods.
General Design Considerations
When hydraulic control of the contaminated region is not
necessary, then skimmers are typically located hi permeable conduits
where significant free product is present. Skimmers are available for
installation in wells from 2 inches in diameter up to several feet in
diameter. Skimmer equipment may also be used in excavations and
V-4
-------
trenches which may be open for very short term or emergency operations.
For long-term operations, skimmers are placed in wells and in gravel-filled
trenches with sumps. Recovery may be enhanced by use of hydrophobic
gravel packs in wells. Field studies by Hampton et al. (1992) have shown
that gravel packs constructed from hydrophobic materials allow for free
product to enter wells and sumps more rapidly. Recovery rates for long-
term operations are generally very low, with the exception of skimmers
that are used in open excavations where rates of a few gallons per minute
are feasible.
If hydraulic control of the contaminated region is deemed
necessary, then skimmers should be located in trenches along the full
width of the plume at its downgradient edge. The trench should be
excavated several feet below the seasonally low water table to allow for
fluctuations over time. For longer term operations, the trench should be
filled with gravel or sand, as shown in Exhibit V-3. An impermeable
partial vertical liner at the downgradient side of the trench will also
prevent migration of the product contaminant plume. A sump should be
located at areas where free product is present and at low water table
elevations.
Equipment Description
The selection of skimming equipment will be based primarily on
the size of the recovery installation (well, trench, excavation) and expected
rate of recovery of free product. Two types of skimming equipment are
available. Mechanical skimming equipment actively extracts free product
from recovery initiation, whereas passive skimming equipment
accumulates free product over time. Exhibit V-4 summarizes the
applicability, advantages, and disadvantages of the common types of
skimming systems.
Mechanical Skimming Systems. Mechanical skimming
systems rely on pumps (either surface mounted or within the well) or other
motors to actively extract free product from the subsurface. The more
common forms of mechanical skimming systems are:
Floating (large)
Floating (small)
Pneumatic Pump
Belt Skimmer
V-5
-------
Exhibit V-3
Interceptor Trench With Skimming Equipment
PLAN VIEW
Free Liquid Hydrocarbon
Hydrocarbon Source
Surface Seal
(Optional)
Recovery Well or Sump
Sand or Gravel
GrourtdwaterFlow
Hydrocarbon/
Water Separator
Surface Seal ' ' ' '
Liner (Optional)
Sand or Gravel
Screen, or Slotted Pjge
Source: Modified from API, 1989
Source: API, 1996. A Guide to the Assessment and Remediation to Underground
Petroleum Releases, 3rd edition. API Publication 1628, Washington, DC.
Reprinted Courtesy of the American Petroleum Institute.
V-6
-------
Exhibit V-4
Applicability of Skimming Systems
Mechanical
Skimmers
Floating
Large
Saucer
Small Float
Pneumatic
Pump
Belt Skimmer
Passive Skimmers
Bailer/Filter
Canister
Passive
Absorbent
Recommended
Minimum
Well
Diameter
j- ,-. |
\ 1
i \t <
36"
4"
4"
2"
:
2"
2"
Relative
Capital
Costs
IV
, '
M-H
M-H
M
includes
comp-
ressor
M
, SV
L
L
Relative
Operating
Costs
V t- '
* i
M
M
M
M
? ' f
I
L
Relative
Maintenance
Costs
$
-if °v
M
M
M
L
% t 4
L
L
Potential
For
Product
Removal
)
^
M
M
M
L
» " «
L
L
Product
Recovery Rate
* _ i *z
'
L-H
[depends on
volume of
recoverable free
product and
formation
characteristics)
L-M
L-M
L
-------
Large floating skimmers can remove product at a fairly high rate
(up to 5 gpm). Each skimmer has a large hydrophobic screen that allows
only product into the pump body. These skimmers are generally limited to
shallow applications (less than 20 feet) and may require a well or sump
that has a 24-inch-diameter or greater. Small float systems require 4-inch
or larger wells for operation. They are limited to depths of 30 feet or less.
This type of skimmer typically uses a floating screen inlet to capture the
product and is contained in a pump device or bailer. A variation on
floating skimmers employs a floating (or depth-controlled) intake
equipped with conductivity sensors that activate surface mounted pumps
when liquid hydrocarbons have accumulated to a sufficient thickness. Belt
skimmers use a continuous loop of hydrocarbon absorbent material that
slowly cycles down into and out of the well, soaking up product as it
moves through the water surface. These skimmers are simple mechanical
systems that can operate in 4-inch or larger wells, but they are perhaps best
suited for skimming sumps. Pneumatic skimming systems may have a top
intake that allows skimming of fluids from the liquid hydrocarbon/water
interface (as in Exhibit V-5), or they may have a density-sensitive float
valve that permits the passing of water before the valve seats.
Passive Skimming Systems. Passive skimming systems do
not actively pump free product; instead they slowly accumulate it over
time. There are two basic forms of passive skimmers:
« Filter canisters .
» Absorbent bailers
Filter canisters are lowered into 2-inch or greater diameter wells so that
they contact the layer of free product floating on top of the water surface.
The filter is constructed of a hydrophobic material which allows only free
product to enter. Gravity causes the liquid hydrocarbons to trickle through
the filter and then flow into the bottom of the canister where the product is
stored. Canisters can store between 0.5 and 2 gallons of free product. The
product can be removed automatically by a suction pump or manually by
pulling up and emptying the canister (EPA, 1992). Absorbent bailers are
simple skimming devices which are suspended in the well across the
surface of the free product layer. Attached material absorbs product from
the water surface and must be periodically removed and disposed.
V-8
-------
Exhibit V-5
Pneumatic Skimmer In A Single Well
Hydrocarbon/
Water Separator
Air Supply
Air Supply
and Exhaust Line
Hydrocarbon/water Contact
Source: API, 1996. A Guide to the Assessment and Remediation to
Underground Petroleum Releases, 3rd edition. API Publication
1628, Washington, DC. Reprinted Courtesy of the American
Petroleum Institute.
V-9
-------
System Startup
The startup operations for skimmer systems, not including
treatment systems, are relatively straightforward and of short duration (a
few days). The following activities are applicable, in general:
« Set the skimmer equipment at proper levels in each well or sump.
« Inspect all mechanical and electrical components of skimmers and
collection system, and oil/water separator.
« Monitor the recovery rate of fluids.
Sample the fluids collected and inspect them for water content
and/or emulsification. Modify skimmer settings as necessary to
minimize water production.
After the startup activities have been completed, a brief startup summary
report should be prepared.
Operations And Maintenance
After the startup activities have been completed, normal operations
and maintenance (O & M) activities begin. These activities include:
Measure the thickness of free product and water and product
elevations in monitor and skimmer wells or sumps.
Record the amount of product collected at all recovery points.
Inspect all electrical and mechanical components of skimming and
collection systems and oil/water separator.
Maintain and repair all equipment as necessary, or as
recommended by equipment vendor.
Typically, these activities are performed every two weeks. Most states
require reporting at least quarterly.
V-10
-------
Termination Criteria/Monitoring
The free product skimming system should be operated until it is no
longer recovering significant amounts of hydrocarbons (e.g., less than 2
gallons per month). After the system operations have been suspended, the
free product thickness levels should be monitored on a monthly or
quarterly basis to ensure that significant accumulations of product do not
return to the wells. A threshold level of hydrocarbon thickness (e.g., 0.1
foot) may be used as an action level to restart the recovery system. The
termination criteria should also specify the period during which thickness
should be monitored (e.g., 2 years of quarterly monitoring) with no
exceedance of threshold hydrocarbon thickness.
Free Product Recovery With Water Table
Depression
This method of recovery creates a depression of the water table so
that any free product is directed toward pumping wells within the plume
area. Both free product and groundwater are produced during recovery
operations. The design of these systems is constrained by the need to
minimize drawdown of the water table. Minimizing drawdown will
reduce both the volume of coproduced water as well as the smearing of
free product along the drawdown surface. Exhibit V-6 shows a pumping
recovery system capture zone.
Applicability
Product recovery systems utilizing water table depression are most
applicable when hydraulic control of the hydrocarbon plume is necessary.
These systems can operate in a wide range of permeability values and
geologic media. However, because of the costs associated with the
separation and treatment of dissolved hydrocarbons, these systems are
better suited for formations of moderate to high permeability (greater than
10'4 cm/s). Typically, free product recovery with water table depression is
used in long-term operations of greater than one year.
V- 11
-------
Exhibit V-6
Pumping Recovery System Capture Zone
NJ
PLAN VIEW
Flow Divide
Induced by
Pumping Well
CROSS-SECTION A-A1
Pumping Well RoWiDivide |
Bedrock
Source:
Modified from API, 1996. A Guide'to the Assessment and Remediation to Underground Petroleum
Releases, 3r edition. API Publication 1628, Washington, DC. Reprinted Courtesy of the American
Petroleum institute.
-------
General Design Considerations
The major design components of a free product recovery system
using water table depression consist of:
Number, location, and depth of wells and drains
Pumping rates or fluid control levels
» Disposition of treated groundwater (discharge)
Pump selection
The primary constraints on the design include the need to minimize
pumping rates and drawdowns but still provide hydraulic control of at
least the free product plume. At some sites, discharge of treated
groundwater to surface water may not be possible because of state or local
regulations. At these sites, the design needs to address the impact of
subsequent recharge to the aquifer.
Recovery Well/Drain Network Design
" The success of a free product recovery system using groundwater
depression depends upon selecting the number and location of wells and
setting pumping rates or fluid control levels in a manner such that the
system pumps as little groundwater as necessary while collecting as much
free product as possible as quickly as possible. Design of a recovery
system can be based on the results of a simplistic basic analysis or a more
sophisticated modeling analysis.
Basic Analysis. The basic analysis requires knowledge of the
most fundamental groundwater principles and equations. Typically such
an analysis can be conducted using nothing more sophisticated than a
hand-held calculator. This approach to the design of a system for free
product recovery with water table depression is applicable to simple
hydrogeologic settings with small free product plumes. Probably the most
significant limitation of this method is that, because it considers only
groundwater flow rates, it does not provide an estimate of the time that
will be required to recover free product present at a site. The basic
approach involves four steps:
1. Determine the amount of groundwater flowing through the plume
area.
V-13
-------
2.
Set the total pumping rate of recovery system, usually 50 percent
or 100 percent greater than the groundwater flow through the
plume.
3. Determine the number of wells from which to extract groundwater,
but minimize drawdown in areas of free product.
4. Locate wells to maximize recovery of free product.
Determining the amount of groundwater flowing through the free product
plume requires site-specific information: Dimensions of the plume,
hydraulic gradient, aquifer saturated thickness, and hydraulic conductivity.
An estimate of the groundwater flow rate through the plume is calculated
using Darcy's Law.
To account for uncertainty in the site data and to provide a margin
safety should the actual groundwater flow rate be higher than the estimate,
the total pumping rate is typically set at 50 percent to 100 percent higher
man the estimated groundwater flow rate.
Once the total pumping rate is determined, the next consideration
is the minimization of drawdown. Large drawdowns in the free product
plume are undesirable because they can result in free product being drawn
to lower elevations in the aquifer where it may become immobilized and
not subject to recovery (smearing). Simple equations for steady-state flow
can be used to estimate flow to a well (or drain) for a desired drawdown.
These calculations will determine the number of wells or size of drains.
After the required number of wells has been determined, their
locations must be determined. For hydraulic control, the wells are best
placed near the downgradient end of the free product plume. Other
considerations in locating the wells include the amount of free product at
the proposed location and accessibility. If the optimal well locations are in
areas having small amounts of recoverable free product, then it may
instead be advantageous to place additional wells in the areas where free
product can be recovered at higher rates. Terrain and land use may limit
accessibility to optimal locations. Proximity to fragile environments (e.g.,
wetlands) or underground utilities may preclude siting of a recovery
well(s) in the optimal location.
An example of the basic analysis used to determine the number of
wells and the total pumping rate is presented in Exhibit V-7. In this
example, the Theim Equation is used to compute drawdowns at the
V-14
-------
Exhibit V-7
Procedure To Determine Number Of Wells
And Total Pumping Rate Using Water Table Depression
Setting: Free product plume is 100 feet wide in an aquifer 25
feet thick with a hydraulic conductivity of 5 feet per
day and a hydraulic gradient of 0.006 feet per foot.
Step 1: Determine groundwater flow through the plume
using Darcy's Law.
Q =WB.K
^ AL
where:
W = width of the plume
B = saturated thickness of the aquifer
K = average hydraulic conductivity
Ah/AL = hydraulic gradient (the difference in
groundwater elevation between two
points in the direction of flow, divided by
the distance between those two points)
Qgw = 100 ft x 25 ft x 5 ft/day x 0.006 ft/ft
= 75ft3/day = 0.39 gallons per minute
Step 2: Set the design total pumping rate at Qgw + 100% Qgw=
150ft3/day.
Step 3: Determine the maximum pumping rate for single well
without interference using Theim Equation.
S (2irBK)
_ _ max v
In (W/r )
where:
the radius of influence is assumed to be the width of the plume (W)
rw = the well radius
S a = maximum allowable drawdown to minimize
smearing (assume 1 ft)
Q = 1 ft (2 x 3.14 x 25ft x 5ft/day) = 123ft3/day
max In (100 ft/0.166 ft)
For a desired maximum drawdown next to the well, the maximum pumping
rate is about 123 ft3/day, which is less than the total pumping rate of 150
ft3/day. Two pumping wells should be used at this site.
V- 15
-------
pumping well. This equation does not consider the combined drawdown
of several wells: The water levels within the overlapping cones-of-
depression would be lower as a result of well interference. If several wells
are determined to be necessary, the number determined using the Theim
Equation should be considered as the minimum; however, because of well
interference and increased drawdown, the pumping rates will need to be
reduced somewhat to minimize smearing.
Modeling Analysis. The most reasons cited for not using
models to aid in the design of free product recovery systems are
complexity of use and cost. However, for large free product plumes and
serious contamination problems, the cost of the modeling study may more
than pay for itself if the result is a more efficient and cost-effective
remedial design than would have otherwise been possible. Because of
their speed and flexibility, many models can be used to quickly examine
different remedial designs without the time and expense associated with
extensive field testing. For example, different well locations can be tested,
wells can be added or eliminated, and pumping rates and schedules can be
adjusted to achieve an optimal design. Three types of models are
available:
Analytical models of capture analysis based on groundwater flow.
Numerical (finite-difference or finite-element) models for
groundwater flow and capture analysis.
Numerical models of multiphase flow.
Analytical groundwater models of capture analysis provide for
detailed evaluation of a recovery system design without the expense and
complexity of the numerical modeling approach. Analytical methods such
as those developed by Strack (1994) may be applied for capture analysis
and optimal well and drain placement at smaller sites. The objective is to
create a capture zone that completely encompasses the free product plume.
An example of such an application is illustrated in Exhibit V-8.
Numerical groundwater flow models may also be used to perform a
capture analysis for a recovery system. The USGS model MODFLOW
(McDonald and Harbaugh, 1984) is one such model that is frequently
applied. A numerical groundwater flow model can simulate three-
dimensional flow conditions and heterogeneous conditions that cannot be
simulated by the analytical models.
V-16
-------
Exhibit V-8
Sample Capture Zone Analysis
M \ \
\ \ v \ Recovery
^ \ \ Well
N-
AQUIFER PARAMETERS
Hydraulic Conductivity 5ft/d
Thickness 25ft
Porosity 0.25
Uniform Flow 0.1 ft3/d/ft2 (Wast-southwest)
Rainfall 1 ft/yr
RECOVERY WELL DATA
Diameter 4 inches
Pumping Rate 1 gpm
Drawdown (at well) 2.47ft
LEGEND
Groundwater Elevation
Contour (ft)
Capture zone completely encompasses free
product plume using a single well with minimal
drawdown.
200'
SCALE IN FEET
Source: CZAEM, Strack (1994)
-------
Multiphase flow models are capable of simulating the flow of free
product as well as groundwater. Ideally, they can predict free product
recovery rates and show how the free product plume will evolve over time.
The complex models are rarely used in the design of free product recovery
systems because they are expensive to run, and they require specialized
modeling expertise and data that are generally not available or easily
collected at UST sites. However, at sites with large spills or large volumes
of free product in the subsurface, multiphase flow models may be useful
design tools.
Discharge Of Treated Groundwater
Free product recovery using groundwater depression can generate
large quantities of co-produced groundwater. Discharge of water is a
necessary element of the free product recovery design. Two options for
the disposal of recovered groundwater include:
» Surface water or POTW discharge
» Recharge to water-bearing geologic formation
Because of the cost of treating contaminated groundwater, discharging it
to a publicly owned treatment works (POTW) is preferred (provided the
state regulations allow for it and the facility will accept discharges and has
the hydraulic capacity). Some pretreatment, such as phase separation, may
be required before discharging to the sanitary sewer. Surface water
discharges usually require a National Pollutant Discharge Elimination
System (NPDES) permit and, thus, have greater treatment demands and
costs. Recharge to the aquifer must be considered carefully, as it may
directly affect contaminant capture. If water is recharged within the free ,
product plume, it may negate the hydraulic containment provided by
pumping. Water recharged to the aquifer outside of the free product
plume may alter the migration of the dissolved product plume.
Reinjection or recharge may be evaluated using the same methods used for
capture analysis.
Equipment
A variety of pumps in one or two configurations will provide water
table depression. The types of pumps include diaphragm, centrifugal,
submersible, pneumatic, and vacuum. All pumps should be rated for
operation in a hydrocarbon environment. The applicability and advantages
of the various pump configurations are summarized in Exhibit V-9. There
are two common configurations of pumps:
V-18
-------
Exhibit V-9
Applicability Of Water Table Depression Equipment
Diaphragm Pump
Centrifugal Pump
Submersible Pump
Pneumatic
Top Filling
Product Only .
GWP and PP (separate
product and level
sensors)
GWP (steady
' operation) with PP
(with product sensor)
GWP (steady
operation) with PP
(floating, skimming
type)
Recommended
Minimum
Well
Diameter
> u
j.
2"
2"
4"
4"
4"
. " *
4"
6"
6"
Recommended
Minimum
Value for K
(cm/s)
>10-4
> 5X 10'3
> 10'2
> TO'3
> 10'4
: 1 i
>10'2
>10'2
> 10'3
Relative
Capital
Costs
~
L
L
M
M
M
H
H
H
Relative
Operating
Costs
L
L
M
M
M
.. ',
H
H
H
Relative
Maintenance
Costs
L
L-
L
M
M
~"l/'&
H
M
M
Potential
For Product
Removal
1 x ,
L
L
L
M
M
s i f\ '
H
H
H
Product
Recovery
Rate
, \
L-M
L-M
L-M
L-M
L-M
"A
L-H
L-H
L-H
Advantages
.ow cost; low
maintenance
surface mounted
pumps; easy to
maintain low flows
.ow cost and
maintenance
*!o depth
imitation; ease of
installation;
removes product
and water; creates
capture zone
Operates over wide
range of flow rates;
will pump from
deep, low
permeability
aquifers
Can be set to skim
product with little
smearing
Can create large
cone-of-depression
to expedite
recovery
Can create large
cone-of-depression
to expedite
recovery; can skim
product
Disadvantages
3umps water and
product; requires 0/W
ieparator; limited to
shallow (less than 20
t.) applications
.evel sensor and 0/W
separator required
Flow usually greater
than 5 gpm; requires
0/W separator and
water treatment;
emulsification of
product in water
Requires air
compressor system
and water treatment;
recovered fluids are
emulsified
i % ' -'
Proper adjustment can
be time-consuming
Somewhat larger
recovery well required;
may require 0/W
separation
Somewhat larger
recovery well required
VO
K - Hydraulic Conductivity; L - Low; M - Moderate; H - High; GWP - Groundwater Purnp; PP - Product Pump; OA«.' - Oil/Water
-------
Single-pump systems or total fluids systems which simultaneously
collect both free product and groundwater in each installation.
Two-pump or dual-pump systems consist of one pump which
recovers only free product while another pump extracts
groundwater and provides the desired level of drawdown.
Single-Pump Recovery Systems. Single-pump systems
produce both water and hydrocarbons. Depending on the depth to water,
the pump may be surface mounted and operated by a suction lift, or it may
be submersible. Single-pump systems are most applicable in settings
where the soil has low to moderate permeability. The systems are simple
to install and consist of a drop tube, the suction lift or submersible pump, a
liquid level sensor, and an above ground phase separation unit. A single
pneumatic, submersible pump system is shown in Exhibit V-10.
Single pumps may operate well below 5 gpm (as low as 0.1 gpm)
to as high as 20 gpm. The pumps usually operate on an intermittent cycle
actuated by a liquid level sensor. All pump types have a tendency to
emulsify liquid hydrocarbons in water thus increasing the dissolved
concentration in the produced groundwater. As a result, above ground
separation and perhaps other levels of treatment are necessary components
of these systems. .
Two-Pump Recovery Systems. The objectives of two-pump
recovery systems are to optimize the cone-of-depression to achieve
maximum product recovery while minimizing smearing and prevent
mixing of free product with water which would then require separation.
Three basic configurations of two-pump systems are summarized in
Exhibit V-9. All of these systems employ one pump that produces
groundwater to create the cone-of-depression and a second pump to collect
free product. Groundwater pumping rates can be adjusted to some degree
to control the depth of drawdown. This is accomplished by either
intermittantly operating the groundwater depression pump, or regulating
its pumping rate. Free product recovery is controlled by either a floating
skimmer or a hydrocarbon detection probe which activates the pump when
there is a sufficient accumulation of free product. By carefully balancing
the pumping rates for groundwater and free product, emulsification of oil
can be minimized or eliminated, which negates the need for oil/water
separation. A dual-pump system that employs a hydrocarbon detection
probe is depicted in Exhibit V-l 1.
V-20
-------
Exhibit V-10
Single-Pump System For Free Product Recovery
And Water Table Depression
(Pneumatic or Electric)
Pump Control Switch
Hydrocarbon/
Water Separator
Free Hydrocarbon Layer
Liquid Level Sensor
Well Screen
Filter Pack
Source: API, 1996. A Guide to the Assessment and Remediation to
Underground Petroleum Releases, 3rd edition. API Publication
1628, Washington, DC. Reprinted Courtesy of the American
Petroleum Institute.
V-21
-------
Exhibit V-11
Two-Pump System For Free Product Recovery
And Water Table Depression
Water Discharge
^Hydrocarbon Storage
Water Pump
Controls
Hydrocarbon
Pump Controls
Hydrocarbon Detection
Probe
Water Pump
Filter Pack
Source: API, 1996. A Guide to the Assessment and Remediation to
Underground Petroleum Releases, 3rd edition. API Publication
1628, Washington, DC. Reprinted Courtesy of the American
Petroleum Institute.
V-22
-------
System Startup
Initial start-up of pumping systems involves the following steps:
Optimize hydraulic control of plume and fluid levels in the system
wells.
Calibrate the characteristic drawdown of each well. A flowrate
versus drawdown plot will assist in evaluating the effect on other
wells.
Determine the operational rate of the pump; select a rate that will
minimize drawdown and provide control of plume movement.
Determine a flow rate for each pump that stabilizes the fluid levels
and maintains sufficient liquid hydrocarbon/water separation.
Adjust pump rates to meet fluid level and plume containment
goals. Set sumps at elevations appropriate for expected
drawdowns.
The initial setup, operation, and maintenance are more difficult and time-
consuming for two-pump systems. Permits for well installation,
discharge, reinjection, and treatment system operation should be secured
prior to start-up and full operation of a pumping system.
Operation And Maintenance
Normal O&M activities begin after startup and include:
Measure groundwater elevations and product thicknesses in
monitoring wells within the plume.
Calculate amount of free product and water recovered at each well
in the pumping network and sample emulsified fluids for total
petroleum hydrocarbons (TPH).
Determine the volume of water that separates from the recovered
product (or the water to oil ratio).
V-23
-------
Measure influent and effluent concentrations of dissolved
hydrocarbons to and from the treatment system, respectively.
Inspect all electrical and mechanical components of the recovery
and treatment system.
Perform maintenance and repair of equipment and wells when
necessary.
Usually these activities are performed once every 2 weeks. Most states
require reporting on a quarterly basis.
Termination Criteria/Monitoring
A free product pumping system using groundwater depression
should be operated until it no longer produces significant volumes of
hydrocarbons. Termination usually requires a total system product
recovery at some specified rate (e.g., less than 2 gallons per month or less
than 0.02 percent ratio of hydrocarbon recovered to water pumped). In
addition, product thicknesses less than a specified thickness at all wells in
the monitoring and pumping network is a basis to terminate system
operations. After the system is shut down, thicknesses should be
monitored on a monthly or quarterly basis to ensure that wells do not
contain hydrocarbons in significant amounts. Termination criteria should
also consist of a specified period (e.g., 2 years of quarterly monitoring)
during which no exceedance of the threshold hydrocarbon thickness (e.g.,
0.1 foot) should occur. The threshold thickness should serve as an action
level to restart the system if it is exceeded.
Vapor Extraclion/Groundwater Extraction
Vapor extraction/groundwater extraction (VE/GE or "veggie")
systems combine conventional water table depression techniques with soil
vapor extraction. The systems are designed to expose the smear zone in
the capillary fringe by groundwater pumping while simultaneously
volatilizing the residual petroleum hydrocarbons in the smear/vadose zone
with SVE. VE/GE systems are used after other free product recovery
methods have removed as much mobile product as feasible. Then, and
only then, is the water table drawn down to expose the smear zone. VE/GE
systems have the following favorable characteristics:
V-24
-------
Recovery of a larger fraction of total hydrocarbons (i.e., free
product and vapor) over shorter time periods.
Increased air flow and groundwater extraction rates.
Recovery of some residual phase hydrocarbons.
These benefits are derived from the fact that volatilization (and
biodegradation) is the primary removal mechanism as opposed to the
draining and dissolution that results from conventional pumping systems
(Peargin, 1995). SVE is ineffective on nonvolatile hydrocarbons, but the
increased flow of oxygen may aid in the stimulation of biodegradation.
Applicability
VE/GE systems may be screened on the basis of aquifer hydraulic
conductivity, but they are generally most applicable to:
Fine-grained soil types.
Aquifers with moderate to low permeabilities (10'3 to 10"5 cm/s).
Aquifers with thicker capillary zones (up to several feet).
Settings in which conventional pumping approaches are too costly
or ineffective.
The applicability of VE/GE systems is summarized in Exhibit V-12.
General Design Considerations
Recovery wells in VE/GE systems require additional design
considerations such as:
Air-tight well caps with an additional connection for air extraction
piping.
Well screens extending further into the unsaturated zone for air
extraction.
V-25
-------
Exhibit V-12
Applicability Of Vapor Extraction/Groundwater Extraction Equipment1
<
ON
Pneumatic or
Electric
Submersible Pump
Augmented with
Vacuum on Well
Recommended
Minimum
Well
Diameter
Recommended
Minimum
Value for K
(cm/s)
< 10"3
Relative
Capital
Costs
H
=^=^=
^ ^MM^^MIM.^_
Relative
Operating
Costs
H
^==^
Relative
Maintenance
Costs
M
=======.
Potential
For Product
Removal
^ ^ ^
VH
Advantages
Effective on low permeability
aquifers; extracts product
from thick capillary fringes;
recovers or remediates some
residual phase hydrocarbon
^^^^^^^ZZ^^^TS^^S^SSE^^S
Disadvantages
Large capital investment;
requires vacuum pump or
blower; longer initial
setup times; usually
requires vapor phase and
water treatment
1 See also Exhibit V-10, Single-Pump Systems
K - Hydraulic Conductivity; L-Low; M - Moderate; H - High; VH-Very High
-------
Solid, impermeable annular seals to prevent air short-
circuiting from the ground surface to the well screen.
VE/GE well locations may be determined by the same methods used for
conventional pumping wells, provided hydraulic containment of the free
product plume is desired.
Equipment
The equipment used in VE/GE systems is essentially the same as
that involved in conventional pumping and SVE. Exhibit V-13 depicts a
VE/GE system in a monitor well. Primary equipment includes:
Surface mounted vacuum pumps or regenerative blowers for
air/vapor extraction.
Pneumatic or electric submersible pumps for groundwater
extraction.
Air extraction piping.
Contingent vapor treatment equipment (e.g., air/water separator,
GAG).
Other equipment such as instrumentation for measuring vacuum
pressure and airflow rate.
System Setup
The initial setup of a VE/GE system involves the following
procedures:
After readily recovered free product is removed by
pumping with minimum smearing, increase pumping rate to
draw water table down and expose smear zone.
, Adjust vacuum and pumping rates in the field such that the
recovery of free product is maximized while the recovery
of total fluids requiring treatment is minimized.
V-27
-------
ExhibitV-13
Vapor Extraction/Groundwater Extraction (VE/GE)
Recovery System
Hydrocarbon/
Water Separator
Suction Line
Air Discharge
Pump 7 Off-Gas
Treatment
Grout Seal
Bentonite Seal
Filter Pack
Well Screen
Submersible
Hydrocarbon
Pump(Electric
or Pneumatic)
Separate Vacuum and Liquids Pump (VE/GE)
Source: API, 1996. A Guide to the Assessment and Remediation
of Underground Petroleum Releases, 3rd edition. API
Publications 1628, Washington, DC. Reprinted Courtesy
of the American Petroleum Institute.
V-28
-------
Optimize the product recovery while maintaining static
fluid levels to avoid unnecessary additional drawdown.
Determine the optimal placement of fluids pump in each well.
Setup times for VE/GE systems are significantly longer than conventional
pumping approaches. Adjustment of vacuum pressures and airflow rates
will also be necessary during periods of falling background water tables.
Operation And Maintenance
Normal O&M activities of VE/GE systems are equivalent to those
of conventional pumping systems. In addition, the following activities are
usually performed once every 2 weeks. Most states require quarterly
reporting.
Monitor the vacuum applied to each recovery well.
Monitor the vacuum readings at sealed monitoring wells in the
vadosezone.
Record the airflow rates, vacuum, and temperature readings at the
vacuum pump and air/water separator (if present).
Lubricate and maintain the vacuum pump and check all seals and
connections for leaks.
Determine the total volumes of recovered phases and calculate
fraction of product recovered from extracted groundwater.
Termination Criteria/Monitoring
A VE/GE may be operated until significant volumes of petroleum
hydrocarbons are no longer recovered. Termination criteria are a total free
product recovery of less than 2 gallons per month and a free product
thickness of less than 0.01 foot at all recovery and monitoring wells.
Product thicknesses in wells should be monitored on a monthly or
quarterly basis. The free product recovery plan should specify an
acceptable time frame (e.g., 2 years of quarterly monitoring) in which no
exceedance of the threshold thickness value (e.g. 0.1 foot) should occur.
V-29
-------
The system should be restarted if the threshold thickness value is exceeded
within the specified time frame.
Dual-Phase Recovery
The approach of dual-phase recovery is to extract free product,
vapor, and groundwater by vacuum enhanced pumping techniques. In
contrast to VE/GE systems, dual-phase systems have a single well point
that accomplishes dewatering while also facilitating vapor-based
unsaturated zone cleanup (Baker and Bierschenk, 1995). This approach
has several benefits relative to other free product recovery methods:
A cone of depression is not formed at the air/oil interface or the
air/water interface.
Smearing of the free product zone is minimized.
Aquifer transmissivity near the well is maintained because
of the vacuum enhancement even when the water level is
drawn down.
Vapor-phase hydrocarbons and mobile free product are collected
simultaneously.
There are two main conceptual approaches to dual-phase recovery,
although they differ only in the vertical positioning of the pump intake
(Exhibit V-14).
Recovery of free product and water by a single vacuum/liquids
pump.
Extraction of free product, air, and water with a single pump and a
vacuum extraction point set at the air/product interface. This
technology is commonly referred to as "bioslurping" (Kittel et al
1994).
Dual-phase recovery systems may be designed to obtain hydraulic
control of the free product plume, depending on the amount of
groundwater removed and/or the number and placement of well points.
V-30
-------
Exhibit V-14
Dual-Phase Extraction Recovery Systems
Compression
Screws
Metal Plates
6" Header
Diaphragm or Liquid
Ring Pump
Suction Line
O* Casing Vacuum Gauge
Hydrocarbon/ pvc Casing
Water Separator
(A) Single Vacuum/Liquids Pump
Source: API, 1996. A Guide to the Assessment and
Remediation of Underground Petroleum
Releases, 3rd edition. API Publications 1628,
Washington, DC. Reprinted Courtesy of the
American Petroleum Institute.
1" Suction Tube
Free Phase Product
Water Table
(B) Bloslurplng
Source: Kittei, et ai., 1394
-------
Applicability
As shown in Exhibit V-15, dual-phase recovery systems are most
applicable to:
« Medium to low permeable media (<, 10"3 cm/s) or thin (less
than 0.5 foot) saturated thicknesses.
* Water table depths of 5 to 20 feet (deeper for some designs).
Settings in which conventional pumping approaches or
trenches are inappropriate or ineffective (API, 1989).
Free product plumes located under paved or sealed surfaces.
Equipment
The equipment used in dual-phase recovery systems includes:
Surface-mounted vacuum pumps for air, water, and product
extraction.
Vapor and liquid treatment equipment (e.g., phase
separators, granular activated carbon [GAC])
Other equipment such as manifolds, suction lines, and drop tubes.
Gauges and other instrumentation for measuring vacuum pressures
and airflow rates.
System Setup
The initial setup of a dual-phase recovery system involves the
following procedures:
Place wells sufficiently close to achieve measurable pressure drops
(e.g., 0.1 psi) at one-half the distance between adjacent wells.
V-32
-------
Exhibit V-15
Applicability Of Dual-Phase Recovery Equipment
Single Vacuum
Pump
Bioslurping
Recommended
Minimum
Well
Diameter
2"
2"
Recommended
Minimum
Value for K
(cm/s)
>10'5
> 10'5
Relative
Capital
Costs
M
H
Relative
Operating
Costs
H
H
Relative
Maintenance
Costs
M
M
Potential
For Product
Removal
VH
VH
Advantages
Effective for medium to
low permeability soils;
potentially large radius
of influence; increases
water and product flow
by 3 to 10 times while
minimizing drawdown;
no reduction of
transmissivity at the
well; extracts product
(liquid and vapor) from
capillary fringe;
significantly reduces
remediation time
Disadvantages
Large capital
investment; requires
high vacuum pump or
blower; generally
limited to applications
of less than 20ft.;
requires phase
separation and
treatment; longer initial
startup and adjustment
periods
K - Hydraulic Conductivity; L - Low; M - Moderate; H - High; VH - Very High
-------
Set well screen intervals at a minimum of 5 feet above and 2 feet
below the water table.
Place vacuum extraction points at an elevation just above the
air/product interface.
Adjust vacuum and pumping rates in the field such that the
recovery of free product is maximized while minimizing the total
fluid requiring treatment.
Optimize and control the vacuum applied to each well point.
Seal recovery and monitoring well systems.
Setup times are significantly longer than other recovery alternatives.
Adjustments may be necessary to maintain product/water suction for
periods when background water tables are falling.
Operation And Maintenance
Normal O&M activities of dual-phase recovery systems include
the following activities:
Visually inspect clear tubes for the production of water and
product.
Monitor the total system vacuum.
Frequently monitor the vacuum applied at each well point.
Adjust the gate valves on lines at well heads (balance system).
Operate the vacuum pump properly.
Take vacuum and temperature readings at the vacuum pump and
air/water separator.
Record airflow rates.
Lubricate vacuum pump.
V-34
-------
Check all seals and connections (for leaks).
Monitor vacuum readings at sealed monitoring wells in the vadose
zone.
Determine the total volumes of product, water, and air produced as
well as the fraction of product recovered from extracted air.
Termination Criteria/Monitoring
Operation of a dual-phase recovery system is complete when it
ceases to produce significant volumes of hydrocarbons. Termination
criteria may include total free product recovery rates (e.g., less than 2
gallons per month or ratio of hydrocarbons recovered to groundwater
pumped of 0.1 percent) and free product thickness in monitoring or
extraction wells (e.g., less than 0.01 foot). Thicknesses should be
monitored on a monthly or quarterly basis to ensure that wells do not
contain hydrocarbons. A time period should be specified in which no
exceedance of a threshold hydrocarbon thickness (0.1 foot) should occur
(e.g., 2 years of quarterly monitoring). The threshold thickness may also
serve as an action level to restart the system if it is exceeded.
A summary of the advantages and limitations of free product
recovery systems is provided in Exhibit V-16.
V-35
-------
Exhibit V-l 6
Summary of Advantages and Limitations
of Free Product Recovery Systems
SKIMMING
Floating/Floating Inlet
Direct Pumping of
roduct Layer
Absorbent
Advantages
Removes product to a sheen
Minimizes water recovery
Requires minimal adjustment
since unit moves with
fluctuating water table
Capable of recovery of up to 5
gpm
Advantages
High recovery rates (>5gpm)
are possible
Advantages
No water produced
Skims product to a thin layer
(0.01 ft)
Low cost and simple
operation and maintenance
Limitations
Membranes and screens are
prone to clogging and failure
and require cleaning
Large-diameter units perform
better than small-diameter
versions
Limited radius of influence
Limitations
Removal of product to a sheen
requires pumping of some
water
Requires a minimum product
thickness of 1 - 4 inches
(-0.08 - 0.30 ft)
Frequent adjustment of pump
intake required
Limitations
Low recovery rates and limited
influence
Frequent media replacement/
change-out required
Requires manual adjustment
WATER TABLE DEPRESSION
Advantages
Capture zone is created which
enables hydraulic control of
groundwater and product
Product recovery rates are
enhanced by water table
depression, especially in high
permeability formations
Recovered groundwater can
be oxygenated and reinjected
for bioremediation
Limitations
Recovered fluids usually
require treatment
Lower permeability
formations can require
numerous well points
Product can be "smeared"
across area of depression
resulting in greater formation '
storage ;
Higher permeability formations
may require high pumping
rates
Well network design requires
capture zone analysis
V-36
-------
Exhibit V-16
Summary of Advantages and Limitations
of Free Product Recovery Systems
(continued)
VE/GE
Advantages
Increases free product
recovery rates in low
permeability settings
Recovers product from thick
capillary fringes
Decreased residual phase
formation or "smearing"
May be used to recover or
remediate residual phase
hydrocarbons
Limitations
Initial startup times are longer
than other, conventional
methods
Phase separation is required
Water and vapor treatment is
typically required
Higher capital costs
DUAL PHASE RECOVERY
Advantages Limitations
Effective for lower permeability Usually requires vapor and
formations
High vacuum increases
groundwater and product
recovery
Minimizes drawdown and
"smearing" of product
Expedites site cleanup by
recovering all hydrocarbon
phases
groundwater treatment
Phase separation is required
Longer initial startup time
Higher capital costs
V-37
-------
Primary References
API, 1996. A Guide to the Assessment and Remediation of Underground
Petroleum Releases, Third Edition, API Publication 1628,
Washington, D.C.
Baker, R.S., and J. Bierschenk, 1995. Vacuum-enhanced recovery of water
and NAPL: Concept and field test, Journal of Soil Contamination,
4(l):57-76.
EPA, 1992. Filter canisters: A new method for recovering free product,
EPA-510-8-92-002, Office of Solid Waste and Emergency
Response, Washington, D.C.
EPA, 1995. How to Evaluate Alternative Cleanup Technologies for
Underground Storage Tank Sites: A Guide for Corrective Action
Plan ReviewerspPA. 510-B-95-007, Office of Underground Storage
Tanks, Washinton, D.C.
Kittel, J.A., R.E. Hinchee, R. Hoeppel, and R. Miller, 1994. Bioslurping -
vacuum enhanced free product recovery coupled with bio venting: A
case study, Petroleum Hydrocarbons and Organic Chemicals in
Groundwater: Prevention, Detection, and Remediation, 1994
NGWA Conference Proceedings, Houston, TX.
Peargin, T., 1995. Vacuum-enhanced recovery: theory, Underground Tank
Technology Update, 9(4):2-7.
V-38
-------
-------
-------
APPENDIX
-------
-------
APPENDIX
Chapter IV presented various methods for estimating the volume of
free product in the subsurface. The results of seven methods were
compared for data representative of the same site conditions. Each of these
methods are described in greater detail in this Appendix. To facilitate
comparison, a uniform terminology has been adopted. Exhibit A-l lists the
variables that appear in the various equations. Exhibit A-2 is a diagram
showing the relationship of the variables and characteristics of free product
in the vicinity of a monitor well. Experimental data from Abdul et al.
(1989) and parameter values for the example calculations are presented in
Exhibit A-3.
Exhibit A-1
Variables Appearing in Volume Estimation Equations
3ao = air-oil scaling factor
pow = oil-water scaling factor
D = function of interfluid displacement pressures and hydrostatics
Ap = difference in density between water and hydrocarbon (pw - p0)
F = formation factor
g = acceleration of gravity
ha - distance from water table to bottom of mobile hydrocarbon
hcdr = average water capillary height under drainage conditions
Hf = thickness of mobile hydrocarbon in the adjacent formation
H0 = hydrocarbon thickness measured in the well
Pd°w = water-hydrocarbon displacement pressure
P/° = air-hydrocarbon displacement pressure
pw = density of water
P0 = density of the hydrocarbon liquid
V0 = volume of hydrocarbon in the adjacent formation per unit area
4> = soil porosity
oaw = surface tension of water (= 72 dynes/cm @ 20°C)
oao = surface tension of hydrocarbon
°ow = hydrocarbon-water interfacial tension (= oaw - oao)
Sr = residual saturation
x = distance from water table to interface between free product
and groundwater in the well-x is equal to the product of the
thickness of the hydrocarbon and the hydrocarbon density
(H, p.)
Appendix-1
-------
Exhibit A-2
Relationship Of Variables And Characteristics
Of Free Product In The Vicinity Of A Monitor Well
Mmpermeabli
Legend
H0 = apparent (wellbore) product thickness
H, = actual formation free product thickness
DTP = depth to wellbore product level from ground surface
H. = free product distance to groundwater table, within formation
X = interface distance below groundwater table, within well
Modified from Ballesteroef a/. (1994).
Appendix-2
-------
Exhibit A-3
Parameters and Experimental Data Used
In Calculating Free Product Thickness Based on
Measurements of Free Product in Monitor Wells
Parameters listed in the following table correspond to the variables
appearing in the seven equations described previously.
Parameter Values
p0 = 0.84 gm/cm3
pw = 1 .00 gm/cm3
F = 7.5 (med.sand)
hc,dr = 17
g = 980 cm/s2
aaw = 72 dynes/cm
oao = 32 dynes/cm
oow = 40 dynes/cm
Pao = 2.25
8= 1.80
(|> = 0.424
Sr = 0.091
Pdao = 5.21 cm H2O
Pdow = 6.51 cm H2O
D = 0.035
The data appearing in the following table are from Abdul et al.
(1989). Their experiment essentially involved introducing dyed diesel fuel
into an acrylic column containing well-graded sand and a minature monitor
well. The cylinder was initially filled with water from the bottom and then
allowed to drain until equilibrium was reached. Diesel fuel was then
allowed to infiltrate from the surface. The height of diesel fuel in the sand
and well was measured and recorded. The experiment was repeated 5
times.
Experimental Data
Trial
Number
1
2
3
4
5
H0
(cm)
6
63
68
73
84
ha
(cm)
17
9
6.5
2
0
x[H0-Po]
(cm)
5.04
52.92
57.12
61.32
70.56
Appendix-3
-------
Method of de Pastrovich (1979}
# (P -Pj
This method depends only upon the density (p0) of the liquid hydrocarbon
relative to the density of water. For a hydrocarbon liquid with a density of
0.8, and assuming that the density of water (pw) is equal to 1, the
hydrocarbon thickness in the formation (the actual thickness) is only one-
fourth the thickness measured in the well (the apparent thickness). Stated ''.
another way, the hydrocarbon thickness measured in the well is four times
greater than the actual thickness in the formation. The principal weakness
of this method is that it does not account for the effects of different soil
types. Exhibit III-12 illustrates that in general, the ratio of apparent to true
free product thickness increases as soil grain size decreases. Thus, this
method may be more accurate in finer grained soil (e.g., silt, clay) than in
coarser-grained soil (e.g., sand, loam)
Method of Hall, et al (1984)
=H - F
This method depends upon a "formation factor" (F), which is apparently
empirical, and not related to any other type of formation factor (e.g., those
found in petroleum literature) (Ballestero et al., 1994). For a fine sand, F is
equal to 12.5 cm; for a medium sand, F is equal to 7.5 cm; and for a coarse
sand, F is equal to 5 cm. The principal weakness of this method is in
selecting an appropriate value for F, especially when the soil is either not
one of the three types mentioned above or is layered. Hall et al. (1984) also
report that there must be a minimum thickness of hydrocarbon in the well
for this method to be valid. For a fine sand, the minimum thickness is equal
to 23 cm; for a medium sand, the minimum thickness is equal to 15 cm;
and for a coarse sand, the minimum thickness is equal to 8 cm.
Appendix-4
-------
Method of Blake and Hall (1984)
This method is relatively straightforward, depending only upon measured
lengths, however, the parameter ha is difficult to accurately measure
especially in the field. Ballestero et al. (1994) indicate that ha should equal
the height of the water capillary fringe when the thickness of hydrocarbon
in the formation is relatively small since no pore water is displaced. As the
thickness of free product builds up, the water capillary fringe becomes
depressed as pore water is displaced and the value of ha diminishes. When
the hydrocarbon lens reaches the water table, the value of ha becomes zero.
At this point, the thickness of hydrocarbon in the formation is equal to the
distance between the top of the free product layer and the true elevation of
the water table. Both of these measurements can be obtained using the
methodology illustrated in Exhibit III-10.
Method of Ballestero et al. (1994)
This method is essentially equivalent to the method of Blake and Hall
(1984) when an actual measurement of their parameter "x" is not available,
but the product density and thickness of product in the monitor well are
known. Recall that x is equal to the product of the thickness of the
hydrocarbon in the well and the hydrocarbon density (H0 p0). Rearranging
the above equation and substituting x for (H0 p0) yields the same equation.
The principal limitation of this method (as well as the method of Blake and
Hall) is that the parameter ha is difficult to measure in the field. When ha
has decreased to zero, the thickness of the free product layer in the soil is
equal to the distance between the top of the free product layer measured in
the well and the true (corrected) elevation of the water table. Both of these
measurements can be obtained using the methodology illustrated in Exhibit
III-10.
Appendix-5
-------
Method of Schiepg (19RS)
H =H -2(h
f o v c
This method essentially attempts to correct the exaggerated thickness of
free product in a well by subtracting a constant (2 h^ that depends on the
soil type. The finer the soil, the greater the constant. Typical values of
Tz^as reported by Bear (1972), are 2-5 cm for coarse sand, 12-35 cm for
medium sand, and 35-70 for fine sand. The principal weakness of this
method is that it relies on a parameter that is difficult to accurately
determine. Values for hCidr vary by a factor of 2 over the range from low to
high. Also, it is possible for this method to yield a negative value if there is
only a thin layer of free product in the well.
Method of Farr et al. (199m
P P
ao
D = " - d
pz
This method is dependent upon conditions of static equilibrium. Farr et al.
(1990) present several variations of this equation for different soil types and
different extent of liquid hydrocarbon in the unsaturated zone. The above
equation is based on equation #15 in their paper, which is valid for
unconsolidated sand with very uniform pore sizes. The principal limitation
of this method is in obtaining values for Pfw and P/°, neither of which is
easily measured in the field. Ballestero et al. (1994) present and discuss
this method, however there is a discrepancy in the formulation of the "D"
term, which is not possible to resolve based on the information provided.
Ballestero et al. (1994) also mistakenly assume that Hfand V0 are
equivalent. The relationship between Hfand V0 is discussed later in this
Appendix.
Appendix-6
-------
Method of Lenhard and Parker (1990}
P P
o ao o
fj. _
f p p - p (i -p )
n/t, * ft * rvtlt v ' *»'
ao o ow
a
"*
a
B = ""'
ow a
ow
This method is dependent upon conditions of static equilibrium; it assumes
a theoretical, vertical saturation profile based on generalized capillary
pressure relationships. Extensions of this method allow consideration of
residual oil trapped above and below the mobile zone by a fluctuating water
table. The principal limitations of this method are that it does not account
for dynamic conditions or small-scale heterogeneities, and few of the
parameters can be measured in the field. Parameters from published
literature for pure compounds may be substituted but it is uncertain how
applicable such values are to aged mixtures of petroleum hydrocarbons in
the subsurface.
Relationship Between K. and Hr
Although both the thickness of hydrocarbon in the soil (Hf) and
specific oil volume (F0) can be expressed in dimensions of length [L], they
are not equivalent terms. Vertical integration of the hydrocarbon content in
the soil yields the volume (T0) of hydrocarbon in the medium per unit area,
whereas Hfis merely the corrected thickness of the free product layer in the
geologic formation. V0 actually has dimensions of L3/L2 and is commonly
expressed hi terms of cubic feet per square foot. To determine Hf, V0 must
be divided by the effective porosity. In the unsaturated zone, effective
porosity is equal to the product of porosity [4>] times the quantity 'one
minus the residual saturation' (1-S,). The length dimension of the V0 term
Appendix-7
-------
is equivalent to the height that a specified volume of liquid hydrocarbon
would rise in an empty box measuring one unit of length on each side. The
length dimension of the Hfterm is equivalent to the height that the same
specified volume of liquid hydrocarbon would rise in the same box filled
with a porous media (e.g., sand) of porosity (J) and residual saturation Sr.
Obviously, the height of the rise in the box filled with a porous media
would be higher than in the empty box. To illustrate this point, consider an
empty box that measures one unit of length on each side. Take a specific
volume of liquid and pour it into the box. The depth of liquid in the box is
equivalent to the specific volume of the liquid. Now consider the same box
but this time it is filled with marbles that are packed so that the pore spaces
represent only 25 percent of the total volume. If the same volume of liquid
is poured into this box, the height of the liquid will be four times greater
than the height in the empty box.
Relevance To Free Product Recovery
Each of the above methods for determining volume of free product
has its strengths and weaknesses. In general, none of the methods is
particularly reliable under any given set of conditions either in the field or
in the laboratory. Although there have been some creative attempts to
compensate for the limitations of some of the methods, it is not usually
possible to predict the accuracy. For example, Huntley et al. (1992) apply
the methods of Farr et al. (1990) and Lenhard and Parker (1990) to a
stratified system, with each layer represented by its own specific capillary
pressure-saturation curves. The profiles generated by the layered model
match measured hydrocarbon saturations better than the use of a single
"average" layer. However, the study indicates that predicted saturations
can be erroneous if the system is not in equilibrium, and hence in violation
of the assumption of hydrostatic pressure distribution. These non-
equilibrium effects can be caused by rising or falling water table elevations.
Unfortunately, like anisotropy, non-equilibrium is most often the rule, and
isotropy and equilibrium are the exceptions. To estimate the volume of free
product in the subsurface, no one method should be relied on exclusively.
Select the methods that are most appropriate to the site conditions and !
determine a volume using each method. In this way a reasonable range of
values can be established.
Appendix-8
-------
-------
-------
CHECKLIST
-------
-------
CHECKLIST: FREE PRODUCT RECOVERY PLAN
This checklist can help you to evaluate the completeness of a plan
for free product recovery. As you go through the plan, answer the
following questions. If you answer several questions no, you probably
need additional information or clarification from the plan preparer. This
summary should be helpful in answering some of the questions.
1. Are The Data Necessary For Review Of The Free Product
Recovery Plan Adequate?
Yes No
Q Q
Does the plan contain release history and volume
estimates?
Q Q Is the area of the free product plume defined in all
directions?
Q Q Is the depth to water known?
Q Q Is the volume of free product estimated?
Q Q Are hydraulic conductivity and thickness of the aquifer
known or estimated?
Is hydraulic gradient known or presented as water table
contours?
Q Q
Are the hydrocarbon type, density, and viscosity known?
2. Is The Approach To Free Product Recovery Consistent With
Remedial Action Objectives And The Comprehensive CAP?
Yes No
Are the remedial objectives of the free product recovery
system clearly defined?
Checklist - 1
-------
Q Is an applicable approach (skimmer, recovery with
groundwater depression, or dual-phase recovery)
matched to remedial action objectives?
Q Is the free product recovery approach compatible with
the comprehensive CAP remedy?
3. Is Active Free Product Recovery Necessary?
Yes No
Q Q Is the volume of free product greater 50 gallons?
Q Q Is the maximum thickness of free product in monitoring
wells greater than 0.1 foot?
Q Q Is the hydraulic conductivity of the soil greater than 10'
5cm/s?
4. Have All The Free Product Recovery System Design Criteria Been
Evaluated?
Yes No
Q Q Are well/drain locations specified?
Q Q Are construction details for wells/drains specified?
Q Q Are pumping rates and drawdown levels estimated for
wells and drains (groundwater depression)?
Q Are the total rates of groundwater, free product, and
vapor production estimated?
Q
Q Is the discharge option for any pumped groundwater
specified?
Q Is pumping/skimming equipment specified and
appropriate?
Checklist - 2
-------
Q
Are the locations of pipelines, manifolds, and
separator/treatment system shown on map?
Are system startup procedures specified?
5. Is The Operation And Monitoring Plan Complete?
Yes No
Q Q Is monitoring of production rates of hydrocarbon and
groundwater proposed?
Q Q Are hydrocarbon thickness and groundwater elevations
to be monitored?
Q Q Are routine maintenance procedures described?
Q Q Is regular monitoring scheduled during active recovery?
Q Q Are termination criteria specified?
Q Q Is post-termination (of the recovery system) monitoring
specified?
Q Q Are criteria for restarting recovery specified for the post-
termination monitoring period?
Checklist - 3
-------
-------
-------
-------
REFERENCES
-------
-------
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References-9
-------
-------
-------
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GLOSSARY
-------
-------
GLOSSARY OF TERMS
Absolute Viscosity:
Air/Oil Table:
Anisotropy:
A measure of a fluid's resistance to tangential or
shear stress. Also referred to as dynamic viscosity;
see also viscosity. Units are usually given in
centipoise.
The surface between the vadose zone and the oil;
pressure of oil in the porous medium is equal to
atmospheric pressure.
The conditions under which one or more of the
hydraulic properties of an aquifer vary with
direction.
Aquifer:
Aquifer Test:
Biodegradation:
Bulk Density:
Capillary Forces:
A geologic formation, group of formations or part of
a formation that contains saturated permeable
material that yields sufficient, economical quantities
of groundwater.
A test to determine hydraulic properties of an
aquifer, involving the withdrawal or injection of
measured quantities of water from or to a well and
the measurement of resulting changes in hydraulic
head in the aquifer.
A subset of biotransformation, it is the biologically
mediated conversion of a compound to more simple
products.
The mass of a soil per unit bulk volume of soil; the
mass is measured after all water has been extracted
and the volume includes the volume of the soil itself
and the pore volume.
Interfacial forces between immiscible fluid phases,
resulting in pressure differences between the two
phases.
Glossary - 1
-------
Capillary Fringe:
Cone of Depression:
Darcy's Law:
DNAPL:
Drawdown:
The zone immediately above the water table within
which the water is drawn by capillary forces (fluid is
under tension). The capillary fringe is saturated and
it is considered to be part of the unsaturated zone.
A depression in the groundwater table (or
potentiometric surface) that has the shape of an
inverted cone and develops around a vertical
discharge well.
An empirically derived equation for the flow of
fluids through porous media. It is based on the
assumptions that flow is laminar and inertia can be
neglected, and it states that the specific discharge, q,
is directly proportional to the hydraulic conductivity,
K, and the hydraulic gradient, I.
Dense Non-Aqueous Phase Liquid. A liquid which
consists of a solution of organic compounds (e.g.,
chlorinated hydrocarbons) and which is denser than
water. DNAPLs sink through the water column until
they reach the bottom of the aquifer where they form
a separate layer. Unlike LNAPLs, DNAPLs flow
down the slope of the aquifer bottom which is
independent of the direction of hydraulic gradient.
A lowering of the water table of an unconfined
aquifer or the potentiometric surface of a confined
aquifer caused by pumping of groundwater from
wells. The vertical distance between the original
water level and the new water level.
Dual-Phase Extraction:
Effective Porosity:
The active withdrawal of both liquid and gas phases
from a well usually involving the use of a vacuum
pump.
The interconnected pore space through which fluids
can pass, expressed as a percent of bulk volume.
Part of the total porosity will be occupied by static
fluid being held to mineral surface by surface
tension, so effective porosity will be less than total
porosity.
Glossary - 2
-------
Extraction Well:
Free Product:
A discharge well used to remove groundwater or air.
Immiscible liquid phase hydrocarbon existing in the
subsurface with a positive pressure such that it can
flow into a well.
Groundwater:
Interfacial Tension:
Henry's Law:
Heterogeneity:
Homogeneity:
Hydraulic Conductivity:
Hydraulic Gradient:
The water contained in interconnected pores below
the water table in an unconfined aquifer or in a
confined aquifer.
The strength of the film separating two immiscible
fluids (e.g., oil and water) measured in dynes (force)
per centimeter or millidynes per centimeter.
The relationship between the partial pressure of a
compound and its equilibrium concentration in a
dilute aqueous solution through a constant of
proportionality known as the Henry's Law Constant.
Characteristic of a medium in which material
properties vary from point to point.
Characteristic of a medium in which material
properties are identical throughout. Although
heterogeneity, or non-uniformity, is the characteristic
of most aquifers, assumed homogeneity, with some
other additional assumptions, allows use of
analytical models as a valuable tool for approximate
analyses of groundwater movement.
A coefficient of proportionality describing the rate at
which water can move through a permeable medium.
Hydraulic conductivity is a function of both the
intrinsic permeability of the porous medium and the
kinematic viscosity of the water which flows through
it. Also referred to as the coefficient of permeability.
Slope of a water table or potentiometric surface.
More specifically, change in the hydraulic head per
unit of distance in the direction of the maximum rate
of decrease.
Glossary - 3
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Hydraulic Head:
Height above a datum plane (such as mean sea level)
of the column of water that can be supported by the
hydraulic pressure at a given point in a groundwater
system. Equal to the distance between the water
level in a well and the datum plane.
Hysteresis: Phenomenon in which properties such as capillary
pressure or relative permeability may differ
depending on whether a fluid-fluid interface is
advancing (imbibition) or receding (drainage).
Immiscible: The chemical property where two or more liquids or
phases do not readily dissolve in one another, such as
soil and water.
Intrinsic Permeability:
Pertaining to the relative ease with which a porous
medium can transmit a liquid under a hydraulic or
potential gradient. It is a property of the porous
medium and is independent of the nature of the
liquid or the potential field.
Isotropy: The condition in which the properties of interest
(generally hydraulic properties of the aquifer) are the
same in all directions.
Kinematic Viscosity:
The ratio of dynamic viscosity to mass density. It is
obtained by dividing dynamic viscosity by the fluid
density. Kinematic viscosity is typically reported in
units of centistokes (cSt).
LNAPL: Light Non-Aqueous Phase Liquid. A liquid
consisting of a solution of organic compounds (e.g.,
petroleum hydrocarbons) which is less dense than
water and forms a separate layer that floats on the
water's surface.
NAPL: Non-Aqueous Phase Liquid. See also DNAPL and
LNAPL.
Partitioning: Chemical equilibrium condition where a chemical's
concentration is apportioned between two different
phases according to the partition coefficient, which is
Glossary - 4
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Perched Aquifer:
Porosity:
Potentiometric Surface:
Pumping Test:
Radius of Influence:
Relative Permeability:
the ratio of a chemical's concentration in one phase
to its concentration in the other phase.
A special case of unconfined aquifer which occurs
wherever an impervious (or semipervious) layer of
limited areal extent is located between the regional
water table of an unconfined aquifer and the ground
surface.
Ratio of the total volume of voids to the total volume
of a porous medium. The percentage of the bulk
volume of a rock or soil that is occupied by
interstices, whether isolated or connected. Porosity
may be primary (formed during deposition or
cementation of the material) or secondary (formed
after deposition or cementation) such as fractures.
A surface that represents the level to which water
will rise in tightly cased wells. If the head varies
significantly with depth in the aquifer, then there
may be more than one potentiometric surface. The
water table is a particular potentiometric surface for
an unconfined aquifer.
A test that is conducted to determine aquifer or well
characteristics. A test made by pumping a well for a
period of time and observing the change in hydraulic
head in the aquifer. A pumping test may be used to
determine the capacity of the well and the hydraulic
characteristics of the aquifer. Also called aquifer
test.
The radial distance from the center of a wellbore to
the point where there is no lowering of the water
table or potentiometric surface (the edge of its cone
of depression). The radial distance from an
extraction well that has adequate air flow for
effective removal of contaminants when a vacuum is
applied to the extraction well.
The permeability of the rock to gas, NAPL, or water,
when any two or more are present, expressed as a
fraction of the single phase permeability of the rock.
Glossary - 5
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Residual Saturation:
Saturation:
Saturated Zone:
Solubility, Aqueous:
Sorption:
Transmissivity:
Unconfined:
Unsarurated Zone:
Vapor Pressure:
Saturation below which fluid drainage will not occur.
The ratio of the volume of a single fluid in the pores
to pore volume expressed as a percentage or a
fraction.
Portion of the subsurface environment in which all
voids are ideally filled with water under pressure
greater than atmospheric. The zone in which the
voids in the rock or soil are filled with water at a
pressure greater than atmospheric. The water table is
the top of the saturated zone in an unconfined
aquifer.
The maximum concentration of a chemical that will
dissolve in pure water at a reference temperature.
Processes that remove solutes from the fluid phase
and concentrate them on the solid phase of a
medium; used to encompass absorption and
adsorption.
Rate at which water of the prevailing kinematic
viscosity is transmitted through a unit width of the
aquifer under a unit hydraulic gradient.
Conditions in which the upper surface of the zone of
saturation forms a water table under atmospheric
pressure.
The zone between the land surface and the water
table. It includes the root zone intermediate zone,
and capillary fringe. The pore spaces contain water,
as well as air and other gases at less than
atmospheric pressure. Saturated bodies, such as
perched groundwater, may exist in the unsaturated
zone, and water pressure within these may be greater
than atmospheric. Also known as "vadose zone."
The partial pressure exerted by the vapor (gas) of a
liquid or solid substance under equilibrium
conditions. A relative measure of chemical
volatility, vapor pressure is used to calculate air-
Glossary - 6
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Viscosity:
Viscous Fingering:
water partition coefficients (i.e., Henry's Law
constants) and volatilization rate constants.
The internal friction within a fluid that causes it to
resist flow. Absolute viscosity is typically given in
centipoise; kinematic viscosity is the absolute
viscosity divided by the fluid density. Kinematic
viscosity is typically reported in units of centistokes
(cSt).
The formation of finger-shaped irregularities at the
leading edge of a displacing fluid in a porous
medium which moves out ahead of the main body of
a fluid.
Volatilization:
Water Table:
Well Point:
The transfer of a chemical from the liquid to the gas
phase. Solubility, molecular weight, vapor pressure
of the liquid, and the nature of the air-liquid interface
affect the rate of volatilization.
Upper surface of a zone of saturation, where that
surface is not formed by a confining unit; water
pressure hi the porous medium is equal to
atmospheric pressure. The surface between the
vadose zone and the groundwater; that surface of a
body of unconfined groundwater at which the
pressure is equal to that of the atmosphere.
A hollow vertical tube, rod, or pipe terminating in a
perforated pointed shoe and fitted with a fine-mesh
wire screen.
Wettability: The relative degree to which a fluid will spread on
(or coat) a solid surface in the presence of other
immiscible fluids.
Glossary - 7
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