Buried fuel tanks had been

leaking for years—probably for as long as they

had been buried. Finally, in

1983, the CBS program 60

Minutes aired a story

called “Check the Water,”

which brought national

attention to the effects of

leaking underground

storage tanks. In 1984,

Congress passed a new

law, requiring the U.S. EPA

to develop a regulatory program to prevent, detect, and

clean up releases from UST systems to protect human health and

the environment. On September

23, 1988, U.S. EPA issued comprehensive regulations (Federal

Register, 1988) affecting owners

and operators of UST systems

throughout the United States. 

The regulations went into effect on

December 22, 1998, and tank owners were

given ten years to meet some of the equipment compliance deadlines. The regulations incorporate three

broad strategies: 

• Identify and then correct faulty or leaking tanks 

• Reduce the incidence of future releases by mandating minimum operating and performance

standards

• Minimize hazards from releases by mandating a

standard release investigation, response, and corrective action procedure

L.U.S.T.LINE

New England Interstate Boott Mills South

Water Pollution Control 100 Foot of John Street

Commission Lowell, Massachusetts

01852-1124

Bulletin 48

November

2004

A Report On Federal & State Programs To Control Leaking Underground Storage Tanks

Strong Actions and Creative Solutions

OUST UPdate

Age-Dating Releases at LUST Sites: Part 1—Lead Fingerprints

Collecting Reliable Soil-Gas Data—Vapor Intrusion FAQs

Vapor Release Assessment Techniques—Vermont

Thoughts on Small-Time Vapor Releases

Spill Buckets: Mistaken Expections?

Remote-Earth Testing of Galvanic Cathodic Protection 

Shell U.S./Motiva to Phase Out MtBE in Gasoline

Enhanced UST Compliance in New Jersey

FAQs from the NWGLDE

Inside

5

6

7

12

18

23

26

28

34

35

36 ■ continued on page 2

www.neiwpcc.org/lustline.htm

20 Years of LUST Busting

The Changes, the Joys, the Frustrations...the Future?

by Patricia Ellis

Wow!!

20 Years of

LUST Busting

MTBE, TPH, RBCA........

Time flies when you’re having FUN!!!
2

LUSTLine Bulletin 48 • November 2004

nation was shallow, you could

overexcavate and dispose of contaminated soils—”dig and dump,” or

“muck and truck.” If groundwater

was impacted, you could recover free

product (normally by hand-bailing

or mechanical skimming, or one- or

two-pump groundwater pumping. 

But pump-and–treat was the

main way to clean up contaminant

plumes. Pump-and-treat seemed like

a “forever” type of corrective action,

because you could pump, and pump,

and pump, and the site still wouldn’t

clean up, because the petroleum contaminants sorbed to the soils and

only slowly released to the groundwater. Whether or not you could

manage to close a LUST project with

pump-and-treat was highly dependent on the cleanup goals for the site.

If you had to meet an MCL, you

could be pumping forever. 

Shortly after I joined the program, we began to see more and

more ex-situ bioremediation of excavated soils. It seemed to be considerably cheaper than paying for

disposal, but you needed sufficient

space and time for the bugs to do the

cleanup. In Delaware, we maintained

a “Dirty Dirt List” to keep track of

the soil piles. Keeping the covers on

the piles intact was a nuisance, and

letting the contractors and responsible parties know that a big mound of

dirt next to the former tank pit was

not really a bioremediation cell and

probably wouldn’t remediate very

well that way, was a nuisance. 

With a little guidance, however,

ex-situ bioremediation was a reasonably inexpensive, effective technology. Of my biopiles, I had only one

stolen, and one attempted escapee

was chased for a day, apprehended,

and returned to where it was supposed to be. 

In-situ bioremediation of soils

and groundwater came into vogue at

about the same time. Unfortunately,

in our experience, not everyone was

good at designing and operating an

in-situ bioremediation project, so

some of these projects were not very

successful.

Pump-and-treat with soil-vapor

extraction (SVE). SVE. Air sparging,

Air sparging with SVE. Biosparging.

All were introduced into our toolbox

to give us a few additional weapons

for cleanups, and they are still commonly used. Various configurations

of dual-phase/multiphase extraction

have proven effective in tighter soils

where some of the technologies that

rely on the soil’s ability to move

fluids are ineffective, removing a

combination of petroleum vapors,

free-phase product, adsorbed product, and dissolved phase. 

The U.S. EPA Office of Solid

Waste and Environmental Remediation (OSWER) Directive on Monitored Natural Attenuation was

issued in 1999, providing guidance

on how to evaluate and monitor natural attenuation sites. It differed from

some of the other guidance being

issued at the time in that bioremediation was stressed—other processes,

such as dispersion, diffusion, and

dilution, or chemical or mechanical

destruction were not included. A 

lot of sites were eliminated from consideration of this remediation option

when, due to its resistance to biodegradation, large amounts of MtBE

were found at the release site. 

Various oxidation technologies

are among the newer tools in our

toolbox. They have the advantage of

being relatively quick technologies,

although not necessarily cheap, and

they work reasonably well for the

fuel oxygenates. They can help us

meet the goals of faster cleanups. 

What Chemicals Are We

Looking At?

Life was simple in the early days—

most states looked at benzene,

toluene, ethylbenzene, and xylene

(BTEX), or even just BTX, and total

petroleum hydrocarbons (TPH).

Later, TPH was split into gasolinerange organics (GRO), diesel-range

organics (DRO), and sometimes even

high-range organics (HRO). Exceed

the action levels and you’re in the

cleanup program. 

With the advent of risk-based

corrective action (RBCA) programs in

the early 1990s, you needed some

sort of toxicology data to be able to

generate safe levels in soils and

groundwater. One approach was to

use groups of chemicals and choose a

surrogate to represent the toxicology

of the group (e.g., the method used

by the TPH Criteria Working Group,

1997). Another method was to establish a list of chemicals of concern for

each petroleum product and use

available toxicology data for each

L.U.S.T.Line

Ellen Frye, Editor

Ricki Pappo, Layout

Marcel Moreau, Technical Advisor

Patricia Ellis, Ph.D., Technical Advisor

Ronald Poltak, NEIWPCC Executive Director

Lynn DePont, EPA Project Officer

LUSTLine is a product of the New England

Interstate Water Pollution Control Commission (NEIWPCC). It is produced through a

cooperative agreement (#T-830380-01)

between NEIWPCC and the U.S.

Environmental Protection Agency.

LUSTLine is issued as a communication

service for the Subtitle I RCRA 

Hazardous & Solid Waste Amendments 

rule promulgation process. 

LUSTLine is produced to promote 

information exchange on UST/LUST issues.

The opinions and information stated herein

are those of the authors and do not necessarily reflect the opinions of NEIWPCC.

This publication may be copied. 

Please give credit to NEIWPCC. 

NEIWPCC was established by an Act of

Congress in 1947 and remains the oldest

agency in the Northeast United States

concerned with coordination of the multimedia environmental activities 

of the states of Connecticut, Maine,

Massachusetts, New Hampshire, 

New York, Rhode Island, and Vermont.

NEIWPCC

Boott Mills South, 100 Foot of John Street

Lowell, MA 01852-1124

Telephone: (978) 323-7929

Fax: (978) 323-7919

lustline@neiwpcc.org

LUSTLine is printed on Recycled Paper 

■ 20 Years from page 1

The third area is meant to streamline

and standardize the ways in which operators respond to suspected and confirmed

releases from USTs. The two subparts of

this section deal with release reporting,

investigation and confirmation, and

release response and corrective action. 

Because of the large regulated universe of USTs at the beginning of the

program (over two million tanks), EPA

designed the program to be implemented

by the states. Armed with the new federal

regulations, the states were tasked to

develop programs to manage the UST

universe. 

While I’ve only been with the UST

program for 15 years, in honor of this

anniversary, I would like to take this

occasion to reflect on the life and times of

the LUST side of the tanks program,

starting with the advances in cleanup

technologies.

20 Years of Technology

Improvements

Early LUST cleanups consisted primarily of three methods. If contami-
chemical to generate acceptable concentrations. Some states kept the list

short, and other states added long

lists of analytes for required testing. 

Around the time that the Santa

Monica, California, wells were

impacted with MtBE, tank programs

began to realize that they needed to

add another analyte to the list. A few

states were already looking for MtBE

at that point, but they were few and

far between. In January 2000, 60

Minutes put the tank program in the

spotlight again with a double-length

segment devoted to MtBE. At least

we had warning that the segment

was going to air, because most states

had to scramble to create fact sheets

about the additive, field questions

from the local print and news media,

and respond to questions from residents questioning whether they had

MtBE in their drinking water. 

Two days after the 60 Minutes

presentation, the EPA Office of

Underground Storage Tanks (OUST)

strongly urged the states to immediately begin monitoring and reporting

MtBE and other fuel oxygenates at all

LUST sites (U.S. EPA, 2000). Based on

the New England Interstate Water

Pollution Control Commission’s survey on state experiences with MtBE

being conducted at approximately

that time (NEIWPCC, 2000), 42 states

were looking for MtBE in groundwater, and 29 were looking for MtBE in

soil samples. Only four or five states

were looking for any of the other oxygenates “most of the time.” 

In another survey, based on

responses from 27 states, over 91,000

LUST sites were closed prior to MtBE

sampling/analytical requirements

(Sakata and Martinson, 2001).

And what about the other oxygentate in gasoline?

“Many within the petroleum

industry have suggested that it

was overemphasis on benzene in

the 1980s and early 1990s that

caused them to neglect MtBE. It

appears that we may not have

learned from this oversight, and the

pattern maybe repeating itself.

Where there is now an emphasis on

MtBE, in many places they are not

looking for or evaluating the potential impact from the other fuel oxygenates.”

GRAY AND BROWN, 2000

development and application of the

RBCA process, which involves evaluating all aspects of a site and determining how much of a release can

safely be left in the ground, rather

than remediating the site to a onesize-fits-all predetermined cleanup

number. The program was developed in part to help us target our

cleanup dollars to where environmental risk is highest. 

For some states, where cleanup

numbers were low or fixed for every

site, this marked a significant change

in the way of doing business. For

others, where a more site-specific

approach to setting cleanup goals

was already being used, this represented less of a change. 

I will admit, however, that the

concept still gives many of us major

heartburn when we see the cleanup

numbers generated using the process. As we watch our soils and

groundwater being left with “safe”

levels of chemicals, particularly when

you consider the small number of

chemicals that we are actually looking for out of the huge number of

chemicals in the products that are

released, we can’t help but wonder...

(Ellis, 2003). 

Quicker, Better

Investigations

Another major change I’ve observed

during my tenure with the LUST program is the development of many

tools that allow us to do quicker, better investigations. When I started

with the program 15 years ago, monitoring wells were the norm. If there

was a release, the consultant sent in a

workplan to install a few monitoring

wells (usually no more wells than the

absolute minimum needed to determine groundwater flow). 

After a few weeks of waiting to

get a driller and permits, the consultant would go out to the site and

install three wells. After developing

the wells and waiting a few weeks for

the well to stabilize, groundwater

samples would be collected. Then,

after waiting a few more weeks for

lab analyses, the consultant would

write a report and send it in to the

state. 

Oops—with three wells, maybe

you’ve got an upgradient well, and

the other two are kind of cross3

November 2004 • LUSTLine Bulletin 48

■ continued on page 4

How Much Is Acceptable?

Now that more states are looking for

the fuel oxygenates, one of the problems in dealing with them becomes

“How much is acceptable?” There are

no established maximum contaminant levels (MCLs), and little toxicological data are available for any of

the fuel oxygenates, so deciding how

to deal with them under a RBCA program can be a problem. Some states

are waiting for EPA to establish an

MCL, and others have tired of waiting and have established their own

standards. 

Now that several reformulated

gas (RFG) states have banned MtBE

(including California, New York, and

Connecticut) with the oxygenate

mandate still in place, ethanol is

becoming an emerging chemical of

concern, with related issues of fate

and transport, remediation technologies, analytical methods, and UST

system compatibility. 

As we look ahead to future

changes in the composition of gasoline and other petroleum products,

we must also look to the past, at various components of leaded gasoline,

ethylene dibromide (EDB or 1,2-

Dibromoethane), 1,2-Dichloroethane

(EDC), and tetra-ethyl lead, which

were not examined. 

The RBCA Process

One of the greatest changes I’ve seen

happen to the LUST program is the

Now that more states are looking for

the fuel oxygenates, one of the

problems in dealing with them

becomes “How much is acceptable?”

There are no established maximum

contaminant levels (MCLs), and little

toxicological data are available for

any of the fuel oxygenates, so

deciding how to deal with them under

a RBCA program can be a problem.

Some states are waiting for EPA to

establish an MCL, and others have

tired of waiting and have established

their own standards.
gradient/downgradient. That’s not

enough. So the consultant writes

another workplan, proposes more

wells, waits for approval, goes back

to the field, puts in more wells, waits

for the analytical. Good, we have a

downgradient well this time, but we

sure aren’t at the end of the plume.

Repeat the cycle. 

With the advent of direct-push

technologies, the consultant could

propose a dozen holes, and get the

samples collected in a day. The second round might then consist of

monitoring well installations, this

time in locations where they needed

to be, where good data could be collected. Sometimes direct-push sampling was accompanied by a mobile

lab that allowed decisions to be made

in the field. 

When the “diving plume” phenomenon became more common

knowledge (see Weaver and Wilson,

2000), direct-push technologies could

be used for three-dimensional plume

characterization. Guidance documents were produced describing the

benefits and process of expedited site

assessments (U.S. EPA, 1997), involving direct-push sampling methods

and a host of other technologies that

could assist in more rapid and complete site characterization—smarter,

better, faster, and often, even cheaper

site assessments.

The 1998 Deadline...No More

Leaking Tanks?

As the 1998 deadline for UST owners

to close, upgrade, or replace their

tanks approached, our workload

increased drastically. Lots of people

sputtered that the #!!%&##@ government was making them remove a

perfectly good tank that wasn’t leaking, but it was no surprise to us that a

considerable number of those tanks

had, in fact, been leaking—whether

or not inventory and tank testing had

ever given an indication of a release.

The closer to the deadline these tanks

were removed, or in many cases,

after the deadline, the higher the

chances were that the state was

requiring MtBE analysis at the time

of removal. Not only were a lot of

tanks coming out of the ground, but

they were triggering investigations

for a chemical for which many states

had not previously been looking and

often had no experience in remediating.

We assumed that 1998-compliant

tank systems wouldn’t leak. They

were state-of-the-art and had all the

bells and whistles. You’d know it

right away if any product dared to

escape. We figured we’d get our

backlog cleaned up, whittle down the

last of the oldie-but-moldy sites, and

work ourselves right out of a job.

Bzzzzz! Wrong answer. Tank systems still leak somehow. We often

just don’t know how! Or the sophisticated leak-detection systems are just

too much for some people—Darn

things always buzzing, beeping, and

alarming. Must not be working right!

Turn them off!

Somewhere along the line, it

occurred to us that tanks often

weren’t the source of the problem.

The lines, with all their joints and

elbows could be a problem, sumps

(or lack of sumps) could be a problem, and under the dispensers was a

good place to look for, and find, contamination. 

Then there are the miracle

releases. If a tank system isn’t tight,

all of the chemicals should be escaping—not just the MtBE. Alas, the concept of vapor releases has emerged.

And vapors don’t just escape and

waft off into the atmosphere, they

can dissolve in soil moisture...and

end up in the groundwater...and

show up in monitoring wells...and

nearby potable wells...and sometimes

the not-so-nearby potable wells. 

New Initiatives on the 

LUST Side 

In October 2002, OUST rolled out its

USTfields initiative to promote the

cleanup of the approximately 200,000

abandoned tanks at brownfields with

a series of pilot grants. The 2002

Brownfields law authorizes EPA to

give grant money to states and communities so they can inventory,

assess, and clean up petroleum-contaminated brownfields. (See http://

www.epa.gov/swerust1/priorits.htm.)

This money complements the OUST

USTfields initiative.

Another of the 2002 initiatives

was a re-evaluation of UST system

design. While this is a complianceside initiative, it will have impacts on

the LUST side of the program down

the road, identifying additional LUST

sites as upgrades are made and,

hopefully, decreasing the occurrence

of future releases. 

In the future, as the number of

releases declines, the backlog of old

cleanups can be reduced. I, for one,

hope that we don’t pinch pennies

when it comes to upgrading the

requirements for new tank installations. If increasing spending a few

hundred here and a thousand there

on a new system will prevent a

release that can cost from tens of

thousands to millions to clean up, it’s

worth the price. 

“Accelerated Cleanup” was

another of the initiatives rolled out in

October 2002. This initiative was

designed to address the backlog of

139,000 tank releases that still hadn’t

reached closure. It was designed to

identify the holdups in the process.

Are the investigations not getting

underway? No RP? Recalcitrant RP?

No money? Once an investigation is

complete, is cleanup not getting

started? Are the technologies applied

at a site not successful, and if not,

why not? Maybe the results of this

initiative will allow us to work

smarter.

Here are the figures from March

2004 (http://www.epa.gov/swerust1/cat/

ca_04_12.pdf):

■ 443,568 releases confirmed

■ 408,834 cleanups initiated (92%)

■ 311,125 cleanups completed

(70%)

■ 132,443 cleanups not yet completed (31%, with 50% of these

4

LUSTLine Bulletin 48 • November 2004

■ 20 Years from page 3

In the future, as the number of

releases declines, the backlog of old

cleanups can be reduced. I, for one,

hope that we don’t pinch pennies

when it comes to upgrading the

requirements for new tank

installations. If increasing spending

a few hundred here and a thousand

there on a new system will prevent a

release that can cost from tens of

thousands to millions to clean up,

it’s worth the price.
involving groundwater contamination)

■ Completed cleanups reported for

2003 met EPA’s annual national

cleanup goal of approximately

18,000 and reversed a three-year

downward trend in the number

of cleanups completed. 

Wow! Five hundred twentythree of those confirmed releases are

mine—0.1 percent! Four hundred

forty-one of the cleanups completed

are mine—0.1 percent. Eighty-two of

the cleanups not completed are

mine—0.06 percent. No wonder I’m

tired! I don’t think the answer lies in

setting numerical quotas, though.

Subliminal message—send money,

lighten project load, stop leaks! 

Setting numerical quotas for each

state ignores many of the differences

between state programs. Some states

are required by law to remediate to

MCLs—no MCL, no closure. In some

states, all cleanups are paid for by the

state cleanup fund, so you have less

of a fight to get the cleanup initiated.

In some states, each project officer

may have as many as 300 LUST projects to handle, and it makes a considerable difference how those projects

are funded, contracted, and so on, as

to how that workload might compare

with that of a LUST project officer in

another state. 

Try this calculation: take the

number of days in the year, subtract

weekends, holidays, vacation, and a

few sick days and divide that by the

average number of projects that an

average project officer might have.

That’s how many days per year that

you can average for each project (if

you don’t go to any training and

don’t attend and meetings and don’t

spend time on planning or program

development). If you’ve got a few big

LUST projects that suck up a bunch

of your time, reduce the amount of

time accordingly that you can devote

to any of the lower-priority projects. 

5

November 2004 • LUSTLine Bulletin 48

■ continued on page 17

A MESSAGE FROM CLIFF ROTHENSTEIN

Director, U.S. EPA Office of Underground Storage Tanks

As We Begin Our Third Decade, Strong Action

and Creative Solutions Are Essential

This is a special year for those of us working in the

underground storage tank program. In November

we will celebrate the 20th anniversary of the program—and we have a lot to celebrate. Just this past year,

we surpassed 300,000 cleanups, we continue to cut the

number of new leaks—from a high of almost 67,000

releases in 1990 to about 10,000 last year—and we are

beginning to make some real progress cleaning up abandoned petroleum brownfields sites. As former U.S. Senator David Durenberger said about our program, “With

the right balance between technology, industry, federal,

state, private, and public forces, you can get a lot done.”

We have struck the right balance, and we have gotten a

lot done. 

But as we celebrate 20 years of accomplishments, our

work is not finished. We still have over 130,000 petroleum leaks not yet cleaned u,p and only six in ten gas stations are in full operational compliance. Far too often we

hear stories about leak detection alarms that are turned

off or equipment that is installed wrong, and we now

have evidence about new or upgraded leaking tanks and

pipes that should not be leaking. To make matters worse,

we are facing these challenges at a time of tight budgets,

highly stressed state cleanup funds, and growing concerns from citizens demanding faster cleanups.

These challenges call for strong action and creative

solutions. Here’s what I suggest: 

■ Prevent releases in the first place. With cleanup budgets so tight, release prevention is critical. By integrating compliance and prevention into the design

and execution of our cleanup funds we can create

incentives for tank owners to prevent releases. By

better educating tank operators and better training

inspectors we can improve compliance. The good

news is that we are close to launching a new Webbased training course for EPA and state inspectors.

Once this is up and running, inspectors can take

the training 24/7 at their

own desks. As for tank

operators, we just finished writing an easyto-use regulatory checklist patterned after EPA’s

successful Environmental Results Program. 

■ Improve program integration. Fortunately, we just initiated a new partnership to share data with our colleagues in the drinking water program. Through this

partnership we have learned that some states rank

USTs as one of the top threats to their designated

source water areas. This simple but important datasharing partnership will help us make the best use of

our resources and increase public health protection.

■ Develop new tools and technologies to streamline

cleanups. This can be done through the use of multisite agreements, pump-and-treat optimization, and

systematic project planning and real-time measurement—commonly known as “Triad.” We also need

better methods to detect vapor releases from tanks

and cost-effective ways to make sure tanks are both

liquid and vapor tight.

This November, when we pause to celebrate our program’s 20th anniversary, we should take pride in the

tremendous progress that we have made. By working

together, we have successfully cleaned up more than

two-thirds of all known leaks and prevented thousands

of new leaks. As we begin the third decade of our program, we face even tougher challenges. But as before, by

continuing to work together we will meet whatever the

future brings. ■
LUSTLine Bulletin 48 • November 2004

New Model Environmental

Results Program Workbook

for USTs Unveiled

The U.S. EPA Office of Underground

Storage Tanks (OUST) has developed

a Model Underground Storage Tank

Environmental Results Program

Workbooks to help state UST programs and state funds improve

owner and operator compliance with

UST regulations. States may need to

modify the model workbook to

reflect their own state laws. States

may then request or require tank

owners and operators to follow the

final, state-specific environmental

results program (ERP) workbook,

which can help owners remain in or

achieve compliance with UST

requirements. 

ERP is an innovative program

that can improve the environmental

performance of a large number of

small sources within a state’s regulatory system. Some states have successfully used ERP to improve

environmental performance in other

small business sectors, such as auto

repair, dry cleaning, printing, and

photo processing. ERP consists of

three related components—inspection and performance measurements,

self-certification, and compliance

assistance—which work together to

produce an integrated system that

holds facility owners accountable for

their environmental UST regulations.

The primary audience for the

workbook is UST owners and operators who either volunteer or are

required to use the workbook to

determine whether or not their facilities comply with UST requirements.

The 164-page workbook contains

general information about ERP,

instructions on how to use the workbook, regulatory requirements, best

management practices, and compliance checklists for USTs and draft

forms and worksheets in the appendices. The workbook is available only

on the OUST Web site at

www.epa.gov/oust/pubs/erp.htm (EPA510-R-04-003, June 2004). For more

information, contact Paul Miller

(703) 603-7165.

EPA Report on Technologies

to Remediate MtBE and

Other Fuel Oxygenates 

Over the past several years U.S. EPA

has been documenting experience

with technologies to remediate fuel

oxygenates and has recently published Technologies for Treating MtBE

and Other Fuel Oxygenates. The report

is an overview of the treatment technologies used to remediate groundwater, soil, and drinking water

contaminated with MtBE and other

fuel oxygenates. It summarizes available cost and performance information for eight treatment technologies,

provides examples of where they

have been used, and contains additional sources of information. . The

technologies range from exsitu drinking water treatment methods to in

situ techniques. 

The report was prepared by the

Office of Superfund Remediation and

Technology Innovation (OSRTI) and

is available online at http://www.cluin.org/s.focus/c/pub/i/1073/. Much of

the data in the report was derived

from the MtBE Treatment Profiles

database (http://clu-in.org/products

/mtbe), which provides project managers with examples of the use of

technologies at specific sites. OUST

and OSRTI are sending reference

copies to regional and state LUST

programs. EPA is not recommending

the use of any specific product or service mentioned in the document. For

more information, contact Linda

Fiedler (703) 603-7194. 

New Report on UST

Dispenser Releases in 

South Carolina

U.S. EPA has produced a new report,

Frequency and Extent of Dispenser

Releases at Underground Storage Tank

Facilities in South Carolina, which

describes the results of information

collected and analyzed from UST closure and assessment reports at sites

in South Carolina. The report

describes the background, purpose,

methodology used, quality assurance

and quality control procedures

applied, results of the study, and conclusions. It includes supporting information in the appendices. EPA developed this report as part of its ongoing

evaluation of UST systems and to

contribute to the UST community’s

understanding of dispenser releases. 

“This study reaffirms the threat

posed by releases from dispensers,”

says OUST Director Cliff Rothenstein. “Nearly half of all facilities

reviewed as part of this study had

contamination under one or more

dispensers, and nearly one quarter

had contamination exceeding South

Carolina’s risk-based screening levels. With 256,000 facilities nationwide—only half of which have

containment under their dispensers—the national implications

are significant.”

Rothenstein adds that while

increased use of dispenser containment should help reduce the future

risk posed by dispenser releases, vigilance on the part of inspectors, owners and operators, and service

personnel is critical to minimize or at

least contain future dispenser leaks.

Copies of the report (EPA-510-R04-004, September 2004) are available

through OUST’s Web site at

www.epa.gov/pubs or by calling

NSCEP, OUST’s publications warehouse at (800) 490-9198.

New Guide on Evaluating

Alternative Cleanup

Technologies at UST Sites

U.S. EPA has updated its manual,

How to Evaluate Alternative Cleanup

Technologies for Underground Storage

Tank Sites: A Guide for Corrective

Action Plan Reviewers, for federal and

state UST professionals. The one

revised and two new chapters in the

manual discuss monitored natural

attenuation (Chapter 9), enhanced

aerobic bioremediation (Chapter 12),

and chemical oxidation (Chapter 13)

at UST corrective action sites. The

original manual was released in 1994

and then revised in May 1995.

A limited number of copies of the

manual at no cost (EPA-510-R-04-002,

May 2004) are available by calling

NSCEP at (800) 490-9198. Copies can

be downloaded at OUST’s Web site

at www.epa.gov/pubs. ■

OUST UPDATE

6
LUSTing for an Answer

Given that the era of leaded gasoline

in the U.S. has passed, analyses of

samples for lead at LUST sites are

performed less frequently. However,

lead (Pb) and its four naturally occurring isotopes are persistent in the

environment, as none are degraded

by biogeochemical processes (Faure,

1986). As a result, lead isotope ratios

(e.g., 206Pb/207Pb, 208Pb/206Pb) can

provide valuable insights, serving as

“fingerprints” of historic gasoline

releases at LUST sites and offering

answers to questions such as:

• What year did the gasoline

release occur? 

• How many releases occurred and

did they commingle?

• What is the source (or sources) of

the leaded or unleaded release?

• How should the liability for site

remediation and cost recovery be

apportioned among potentially

responsible parties (PRPs)?

The ability to age-date a gasoline

release is not trivial; many have tried.

My contribution to this forensic effort

has been to develop a model based

on calibrated temporal variations or

changes in the lead isotope ratios of

leaded gasoline. Called the ALAS

Model (Anthropogenic Lead ArchaeoStratigraphy; Hurst et al., 2001;

Hurst, 2002a, 2002b), since about

1993 it has been applied at about 100

LUST sites in the U.S. as a tool to

assist regulatory agencies and PRPs

(along with their representatives)

answer the questions posed above. 

In this first of a two-part series in

LUSTLine, I will review lead isotopes,

the details of the ALAS Model, and

the age resolution possible. Given

that many readers may be treading

on unfamiliar turf, Part 1 provides

the technical foundation needed. In

Part 2, I will present representative

applications of the ALAS Model at

LUST sites via case studies that

involved cost recovery and site remediation. In addition, the case studies

will demonstrate how lead isotopes

are used to: (a) differentiate natural

from LUST-derived lead; and (b)

model the relative contributions from

commingled releases.

Used properly, with good

sampling strategy and sampling protocols (i.e., a sound scientific

approach), lead isotope ratios provide a viable means of: (a) estimating

the year leaded gasoline was released

into the environment (Kaplan, 2003;

Schmidt, personal communication);

and (b) fingerprinting sources of

leaded/unleaded gasoline releases as

well as their dissolved-phase constituents (e.g., BTEX, MtBE). 

CSI Lead FAQs—What Clues

Does Lead Leave Behind? 

As stated above, the persistence of

lead in the environment is well established, and hence, despite the fact

that gasoline is no longer leaded, the

lead from past gasoline releases

remains adsorbed onto soil minerals

as a record of that release long after

the gasoline organic constituents

have degraded. 

From the perspective of anyone

charged with the decision to close a

site and/or assess liability, lead is

gone from gasoline; however, from

my perspective, lead from past

releases is retained at LUST sites—in

soils, free product, and groundwater;

hence, it is important. Despite the

clues left by lead, as with any CSI

forensic investigation, representative

samples should be collected for analysis prior to site remediation following

appropriate sampling protocols. Let’s

examine some issues/questions that

arise regarding sampling/analysis

and their resolution. 

■ Soil/groundwater lead concentrations

do not exceed the regulatory threshold

value, hence they are attributable solely

to the natural background. 

Many believe that if lead concentrations in a soil/groundwater are low,

no anthropogenic lead is present.

This cannot be resolved using concentration analyses alone, but by

incorporating lead isotopes it is possible to fingerprint both natural and

anthropogenic lead, even at low concentrations (e.g., tens of ppb), well

below those of regulatory-mandated

threshold values—this will be discussed in Part 2 in more detail. 

■ Should I add a preservative to

samples, and what about the potential

for removing lead from particulates in

groundwater when samples are

acidified? 

It is imperative that groundwater

samples never be acidified because of

7

November 2004 • LUSTLine Bulletin 48

Age-Dating Releases at LUST Sites: Part 1.

Lead [Isotopic] Fingerprints

by Richard W. Hurst

“The significant problems we face cannot be solved at the same level of thinking we were at when we created them.”

Albert Einstein

Sometimes we plan our research. Sometimes a course of research comes knocking at our door. My story

begins circa 1989, when I began to receive calls, predominantly from attorneys, concerning my knowledge

and/or ability to age-date releases of gasoline into the environment. I was recognized as a forensic geochemist, performing environmental isotope and geochemical research as a professor of geology/geochemistry at

California State University, Los Angeles, and as a consultant for the petroleum industry and environmental

firms.

Little did I know that those calls would lead me into a project that would envelop a substantial chunk of my

research efforts over the next 15 years. The contribution has been well worth the time, both professionally and personally, having taken me full cycle from age-dating the oldest rocks in the world during my doctoral days to dating the youngest events, those associated with 20th-century releases of refined petroleum hydrocarbons.

■ continued on page 8
the potential to extract lead from suspended/colloidal particulates whose

lead concentrations and isotope

ratios reflect the characteristics of the

aquifer material, not the contaminant! This will lead to artificially high

dissolved lead concentrations that

will be attributed, incorrectly, to a

gasoline release (Hurst, 2000; Landmeyer et al., 2003). 

Because any preservative may

contain lead, no sample matrix

should be preserved other than by

chilling to preserve organics—lead

does not degrade, hence it need not

be preserved. Ask yourself, would

we have a global lead pollution problem if lead degraded?

■ How is anthropogenic lead removed

from soil without extracting background

lead from the soil matrix (minerals)? 

Sequential chemical extraction protocols have been developed to strip the

anthropogenic lead component adsorbed on the surface of soil minerals

without removing lead bonded in

soil minerals (Hurst, 2000). This

approach is very effective when it

comes to deciphering the number of

releases at LUST sites. At this time, I

have collaborated with and trained

researchers at MIT who perform the

required extractions per my instructions following my evaluation of sitespecific conditions and client needs.

■ Can commingling of petroleum

hydrocarbon plumes homogenize lead

isotope ratios, compromising their

utility? 

On the contrary, commingling of

plumes can be identified and modeled using lead isotope/concentration data from sequential chemical

extractions in order to assess the relative contributions from each release. 

ALAS Model: Historic U.S.

Gasoline Lead Isotopic

Temporal Variations

Ng and Patterson (1982) must be

credited with identifying the rapid,

temporal increases in 206Pb/207Pb

ratios of the anthropogenic lead component of sediment in southern California and attributing the change to

our increased reliance on Mississippi

Valley Type (MVT) lead to produce

alkyllead additives. 

Briefly, MVT lead ores have very

high, or radiogenic, 206Pb/207Pb ratios

(~1.3) relative to other ores whose

ratios range from about 1.0 to 1.2.

Furthermore, Ng and Patterson proposed, correctly, that the similarities

between the 206Pb/207Pb ratios of the

anthropogenic lead component in

sediments and those of contemporaneous gasoline-derived aerosols from

1965 to 1975 indicated gasoline combustion, a major source of anthropogenic lead both locally and

globally. 

Their work, however, focused on

global lead pollution, not the development of a chronometer to age-date

gasoline releases. Realizing the need

for improved accuracy in estimating

the age of gasoline releases, my

approach was to use the NgPatterson data as the prototype calibration curve and build upon it. The

next leg of this journey was to: 

• evaluate whether the temporal

increases observed in gasoline

lead isotopic ratios could be calibrated

• determine the age resolution of

the hypothetical technique 

• assess its geographic applicability 

I started to acquire samples to

calibrate what would eventually

become the ALAS Model (e.g.,

archived leaded gasoline, free-product-impacted soils from documented

releases). In short, this was a tedious

task, but as a result of 10 to 12 years

of work, the current ALAS Model calibration includes more than 125 free

product/soil lead isotope analyses of

documented gasoline releases

throughout the U.S. (i.e., California,

Illinois, Florida, New Jersey, Arizona,

Massachusetts, Ohio, Washington,

Texas, New York, Oregon, and Pennsylvania). The ALAS Model is shown

in Figure 1. (At the scale of the figure,

only about 35 of the 125 individual

data points can be resolved.) 

As I am my own toughest critic, I

decided to further refine and evaluate the model. How? The ALAS

Model remains the only gasoline agedating model for which historic data

are available to, so to speak, model

the model. First, using annual U.S.

Bureau of Mines lead production figures (1920–1992), I calculated the contribution of lead from each state and

foreign source relative to total U.S.

lead production. Second, I integrated

the results with published ore lead

isotopic ratios for each source to

calculate annual average 206Pb/207Pb

ratios of U.S. industrial lead (Hurst,

2002b). These calculations and data

acquisition required about 10 months.

What was the result? The correlation between the calculated ratios

with those of ALAS Model calibration samples is statistically significant

(R2 = 0.95; Figure 1), indicating that

the ALAS Model could, in fact, be

modeled. It also suggested that major

manufacturers of tetra-ethyl lead

(TEL) (e.g., Ethyl and DuPont) purchased lead from the average U.S.

lead market. 

This result provided an answer

to a valid question posed by detractors of the ALAS Model that alkylleads, may, on occasion, be

manufactured entirely from a shipment of, let’s say, Australian lead that

has a very different lead isotopic signature. Furthermore, historical data

acquired by Robert (1984) indicate

that Ethyl and DuPont collaborated

on TEL and other alkyllead production, hence they purchased lead from

the same U.S. lead market. 

Additional support came in the

form of correlations between the

ALAS Model and independent analyses of atmospheric aerosol lead isotope ratios (Figure 2), which are: (a)

very significant when leaded gasoline combustion was a major source

of lead in the atmosphere between

1962 and 1985 (R2 = 0.87); and (b)

poor, after 1985, as alkyllead concentrations in gasoline decreased from

1.1 to 0.1 gm/gal (R2 = 0.003). 

The significant correlation

between the ALAS Model and

aerosol lead isotope ratios was one of

the first lines of evidence that the

model had potential applicability

throughout the U.S., rather than just

California, where it was initially

developed. But why should lead isotope ratios of the ALAS Model and

aerosols from gasoline combustion

be in such accord throughout the

U.S.? 

In 1933, the Ethyl Corporation

capitalized on its virtual monopoly of

TEL production and began marketing TEL throughout the U.S. (Robert,

1984). Despite the fact that there were

numerous petroleum companies,

8

LUSTLine Bulletin 48 • November 2004

■ Isotopic Fingerprints from page 7
there was only one Ethyl Corporation

from which gasoline refiners could

purchase TEL, and Ethyl bought lead

from the average U.S. lead market,

which focused on MVT lead sources. 

Economically, Ethyl realized that

it made no sense to mine lead and

either store it for long periods of time

or transport it great distances. As

realized by medieval alchemists, lead

cannot be transformed into gold—in

its heyday, about 1950 to 2000, lead

commanded a maximum price of

about 50 cents per pound. For this

reason, Ethyl Corporation sited the

majority of its TEL production facilities (Louisiana, South Carolina,

Texas) proximal to sources of MVT

ore (Robert, 1984). 

Lastly, as observed in Figure 1,

there are two ways lead isotope ratios

are represented: as the “raw’

206Pb/207Pb ratio and as a “delta”

notation, ∆206Pb, relative to a lead isotopic reference standard (i.e., like

light-stable isotope ratios of carbon

are reported). I will not discuss the

details of reporting lead isotope

results in the delta notation; suffice it

to say it is used in litigation where

small differences between isotopic

ratios often confuse nontechnical folks

who more clearly understand comparisons of numbers like +5.2 or – 3.7. 

Why Does the ALAS Curve

Look Like It Does?

Let’s look deeper into the control

imparted by the use of radiogenic

MVT ores on the ALAS Model before

versus after 1960. We will also get

some sense of how rapidly lead went

from the mine to the TEL market. 

Prior to 1960, the 206Pb/207Pb

ratios of gasoline lead fluctuated but

remained low, about 1.15 to 1.175;

observed fluctuations are dependent

on sources of lead, and MVT lead

contributed about 30 to 50 percent

(average 42 percent) to annual

domestic U.S. lead production prior

to 1960. During the war years (World

War II, Korean War), 1937 to 1954,

lead was used, in part, for

military/defense purposes. 

In 1940, the proportion of less

radiogenic foreign and domestic ore

increased (25 to 50 percent of U.S.

total lead production) while MVT

sources declined (U.S. Bureau of

Mines Yearbooks, 1939-1941). The

result was immediate—an anomalously low 206Pb/207Pb ratio in

1940 (~ 1.155) relative to other years.

Low 206Pb/207Pb ratios during the

Korean War years also reflect a drop

in domestic MVT ore production

and/or its use by the military. 

The post-1960 interval was initially marked by a decrease in ALAS

Model 206Pb/207Pb ratios to about

1.15, followed by the steady, rapid

increase to values of about 1.23 by

1990. The increased reliance on MVT

lead, whose proportion of total U.S.

lead increases systematically after

about 1965 to greater than 85 percent

by the 1980s, contributes to the dramatic increase in 206Pb/207Pb ratios

observed in the ALAS Model during

this time interval. 

The minimum in 1962 is linked

directly to a workers strike at the

largest MVT lead mine in Missouri.

What is so important here, as

observed in 1940, is the “from mine

to market” factor—in 1962, MVT ore

production ceased for months but

was replaced by less radiogenic lead

from Idaho (U.S. Bureau of Mines

Yearbook, 1962). 

As observed in 1940 and again in

1962, the ALAS Model 206Pb/207Pb

ratio decreases immediately (Figure

1). These observations indicate just

how rapidly lead went from the mine

9

November 2004 • LUSTLine Bulletin 48

■ continued on page 10

1.236

1.225

1.214

1.203

1.192

1.181

1.170

1.159

1.148

1.137

1915 1925 1935 1945 1955 1965 1975 1985 1995

40

30

20

10

 0

–10

–20

–30

–40

–50

Delta 206Pb206Pb/207Pb

ALAS (Calculated) ALAS (Calibration) ALAS (pre-1955 Calibration)

Year

FIGURE 1. ALAS Model calibration curve. 37 of ~125 calibration samples can be resolved at the

scale of the figure; the line depicts the ALAS Model as calculated from U.S. Bureau of Mines

annual lead production figures and known lead isotope ratios of lead ores mined globally.

1915 1925 1935 1945 1955 1965 1975 1985 1995

1.120

1.140

1.160

1.180

1.200

1.220

1.240

1.260

1.280

206Pb/207Pb

ALAS (Calculated) Patterson et al. Rosman Chow Sturges/Barrie GGC

Year

FIGURE 2. ALAS Model versus lead isotope ratios of atmospheric aerosols. Note the distinct

similarity between the 206Pb/207Pb ratios of the ALAS Model and aerosols prior to 1985, when

the dominant source of atmospheric lead was leaded gasoline combustion.
to TEL production and further support my contention that large quantities of lead from sources that were

not representative of the average U.S.

market did not occur because they

would have been recorded in the

ALAS Model.

How Precise and Accurate is

the ALAS Model?

When applied properly, by defining

a site-dependent sampling strategy,

integrating lead-organic geochemical

analyses of a statistically significant

suite of samples, and quantifying

commingling among multiple

releases, ALAS Model ages have

proven reliable and accurate—as

long as you do the science. 

The analytical uncertainty of the

model is a function of the steepness

(i.e., slope) of the ALAS Model calibration curve (Figure 1). Where the

ALAS Model uncertainty is greater,

between about 1965 and 1982, an analytical uncertainty of ± 1 year in the

model age of a release is attainable.

The model age uncertainty increases

to ± 2 years for releases that occurred

post-1982. For releases that occurred

prior to the early 1960s, where the

ALAS Model is much “flatter,” the

ALAS Model age resolution increases

to ten-year intervals. Furthermore, the

fluctuations observed in the ALAS

Model curve prior to about 1970 can

produce more than one unique ALAS

Model age. (See Figure 1.)

ALAS Model ages throughout

the U.S. have been quite accurate,

typically agreeing to within two

years (Figure 3) with the “suspected”

age of a release. The “suspected” age

of a release means my client provided a best estimate of the age of the

release, based on inventory/HazMat/fire department records. It is

important to recognize that ALAS

Model ages have always been determined independently with neither prior

knowledge of the “suspected” age or year

of a release at a particular site nor the

age(s) that would most benefit a client’s

exposure in litigation involving hydrocarbon contamination at a site. 

What Have We Learned 

So Far?

The ALAS Model is based on systematic increases observed in lead isotope ratios of gasolines caused by

shifts in sources of lead ores used by

the U.S. lead industry, including

manufacturers of alkylleads, to more

radiogenic Mississippi Valley Type

deposits. Acquisition of high-quality

samples of known age and highprecision lead isotopic analyses over

about 14 years has resulted in a calibration curve whose model age

uncertainties range from ± one to two

years for gasoline releases that

occurred between 1960 and 1990, a

major era in the history of leaded

gasoline usage. 

Numerous site-specific investigations involving free-product releases

throughout the U.S. exemplify the

utility and accuracy of the ALAS

Model as a tool in forensic investigations in which estimates of the age

and identification of sources of

leaded gasoline releases are an

important issue. Part 2 of this series

will provide the reader with selected

representative applications of the

model to site-specific investigations

in which hydrocarbon remediation,

cost recovery, and apportioning of

liability were the predominant

issue(s). ■

Richard W. Hurst, Ph.D., is the President of Hurst & Associates, Inc. and

has been a Professor of Geology/Geochemistry since 1978 at California

State University, Los Angeles. He can

be reached at (805) 492-7764 or Alasrwh@aol.com. Check out his Web site

at www.hurstforensics.com. 

10

LUSTLine Bulletin 48 • November 2004

■ Isotopic Fingerprints from page 9

1935 1945 1955 1965 1975 1985 1995

1935

1945

1955

1965

1975

1985

1995

Estimated Release Age: ALAS Model

CA CA FL IL IN MA MD MO NJ OR PA TX VA

Age of Release

FIGURE 3. ALAS model ages versus the age of gasoline releases throughout the U.S.

The excellent correlation between the model and suspected age of releases from actual site

remediation demonstrates the utility and accuracy of the ALAS Model. 

A Primer on Lead Isotopes 

There are four naturally occurring, stable isotopes of lead (Pb), three of which

are radiogenic (i.e., their abundances increase over time due to the radioactive

decay of uranium, U, or thorium, Th). The Pb isotopes produced (radioactive

parent with half-life, t1/2, in billions of years or Ga; Faure, 1986) are: 208Pb

(

232Th, t1/2 = 14.01 Ga); 207Pb (235U, t1/2 = 0.7038 Ga); and 206Pb (238U, t1/2 =

4.468 Ga). The fourth Pb isotope, 204Pb, is not radiogenic, having no radioactive

parent nuclide. By convention, either 204Pb or 206Pb is used as a reference isotope; analytical results are reported as Pb isotope ratios (e.g., 206Pb/204Pb,

206Pb/207Pb). Over earth history, Pb isotope ratios have increased by 30 to 100

percent or more (Stacey and Kramers, 1975). 
References

Doe, B.R., 1970, Lead Isotopes, Springer-Verlag, 137 pp. 

Faure, G.R., 1986, Principles of Isotope Geology, Wiley &

Sons, 589 pp.

Hurst, R.W., 2000, Applications of Anthropogenic

Lead ArchaeoStratigraphy (ALAS Model) to hydrocarbon remediation, Jounal: Environvironmental

Forensics, Vol. 1, pp. 11-23.

Hurst, R.W., D. Barron, M. Washington, and S.A.

Bowring, 2001, Lead Isotopes as Age Sensitive,

Genetic Markers in Hydrocarbons: 1. Co-Partitioning of Lead with MTBE into Water and Implications

for MTBE-Source Correlations, Environmental Geoscience, Vol. 8, pp. 242-250.

Hurst, R.W., 2002a, Lead Isotopes as Age Sensitive,

Genetic Markers in Hydrocarbons: 2. Kerogens,

Crude Oils, and Unleaded Gasoline, Environmental

Geoscience, Vol. 9, pp. 1-7.

Hurst, R.W., 2002b, Lead Isotopes as Age Sensitive,

Genetic Markers in Hydrocarbons: 3. Leaded Gasoline, 1923-1990, Environmental Geoscience, Vol. 9, pp.

43-50.

Hurst, R.W. and Schmidt, G.W., In press, Age Significance of nC17/Pr Ratios in Forensic Investigations

of Refined Product and Crude Oil Releases, Environmental Geoscience,

Kaplan, I.R., 2003, Age dating of organic environmental residues, Jounal: Environvironmental Forensics,

Vol. 4, pp. 95-141. 

Landmeyer, J.E., P.M. Bradley, and T.D.Bullen, 2003,

Stable lead isotopes reveal a natural source of high

lead concentrations to gasoline-contaminated

groundwater, Environmental Geology, Vol. 45, pp.

12-22.

Ng, A. and C.C. Patterson, 1982, Changes of lead and

barium with time in California off-shore basin sediments, Geochimica et Cosmochimica Acta, Vol. 46, pp.

2307-2321. 

Robert, J.C., 1984, Ethyl: A history of the corporation and

the people who made it, University of Virginia Press,

448 pp.

Rosman, K.J.R., W. Chisholm, C.F. Boutron, J.P.Candelone, and S.Hong, 1994, sotopic evidence to

account for changes in the concentration of Greenland snow between 1960 and 1988, Geochimica et

Cosmochimica Acta, Vol. 58, pp. 3265-3270.

Shirahata, H., R.W. Elias, and C.C. Patterson, 1980,

Chronological variations in concentrations and isotopic compositions of anthropogenic atmospheric

lead in sediments of a remote alpine pond, Geochimica et Cosmochimica Acta, Vol. 44, pp. 149-162.

Stacey, J.S. and J.D. Kramers, 1975, Approximation of

terrestrial lead isotope evolution by a two-stage

model, Earth and Planetary Science Letter, Vol. 26,

pp. 207-221.

Sturges, W.T. and L.A. Barrie, 1987, Lead 206/207

isotope ratios in the atmosphere of North America

as tracers of US and Canadian emissions, Nature,

Vol. 329, pp. 144- 146.

U.S. Bureau of Mines, 1920-1989, Mineral Yearbook.

11

November 2004 • LUSTLine Bulletin 48

Lead Isotopic Ratios in Ores 

The major source of Pb for gasoline additives, sulfide ore (e.g., galena, PbS),

contains ~865,000 ppm Pb but virtually no radioactive parent nuclides, U or Th.

Hence, once a galena forms, its lead isotope ratios are “frozen in time”—they

do not change. Ores used to produce alkylleads (TEL) include imported (i.e.,

Australia, Canada, Chile, Mexico) and domestic sources (i.e., ID, UT, CO, MO

region; U.S. Bureau of Mines Yearbooks, 1956-1989). 

The 206Pb/207Pb ratios of these ores are: ~1.0–1.1 (Australia, Canada, CO, ID);

~1.20 (Chile, Mexico, UT); and ~1.32 (MO; Doe, 1970). The significance of the

MO region ores, with regard to leaded gasoline, centers on the systematic,

increased reliance of the U.S. lead industry, including Ethyl Corporation, on

radiogenic MO region lead caused gasoline lead isotope ratios to increase systematically; calibration of this change would lead to the development of the

ALAS Model (Hurst, 2000, 2002a, 2002b).■

SNAPSHOTS FROM THE FIELD SNAPSHOTS FROM THE FIELD

On June 8, 2004,

at about 4:00 in

the afternoon,

lightning struck

an underground

storage tank in

Simpsonville,

South Carolina.

The resulting

spark ignited

vapors in the

tank, resulting in

a large explosion

and complete

destruction of the

tank. The tank

was a 10,000-gallon fiberglass tank that had previously

contained gasoline. It had been empty since August 2002

and met the standard for temporarily out-of-service. As the

tank was owned by a large public utility, an in-depth analysis of the event was conducted. The owner determined that

a -10,000 amp. (-10ka) lightning bolt struck the vent line. A

15’ x 30’ section of concrete and backfill was lifted approximately 10 feet into the air, accompanied

by a loud boom and heavy, black smoke.

One of the 18” x 18” steel access covers

was blown approximately 125 feet into

the air and landed 70 feet from the UST.

Lightning Strike Causes Underground Storage Tank Explosion

Photos by Dale W. Stoudemire

If you have any UST/LUST-related snapshots from the field that you would like to share with our readers, please send them to Ellen Frye c/o NEIWPCC.
■ What is the primary reason that soilgas sampling for vapor intrusion differs

from soil-gas sampling for typical site

assessment?

The difference is in how low a concentration you have to measure. For

site-assessment applications, we typically worry about contaminant concentrations above 1 μg/L. For

vapor-intrusion applications, we

measure down to levels as low as 1

μg/m3, fully 1,000 to 10,000 times

lower. This means that we need to be

much more careful in how we collect

and analyze samples. Field and analytical techniques that are suitable for

higher concentrations are often not

suitable for these ultra-low concentrations. Small contaminant blanks

from equipment, fingers, clothing,

the working surface (e.g., the tailgate

of your pick-up), even the ambient

air can be enough to fail acceptable

risk levels. 

■ Why do you say that vapor units are

the most common (and very significant)

error in vapor-intrusion assessments?

In the vapor-intrusion world, labs

and regulations employ a vast array

of units, including most commonly

ppmv, ppbv, μg/L, μg/m3, mg/m3,

and %. It’s enough to drive a geologist and risk assessor mad. Even 

the engineers are having trouble

(although they will never admit it). 

For water samples, a ppb is

equivalent to an μg/L. For vapor, a

ppbv is not equivalent to a μg/L.

Because the vast majority of us in this

field (e.g., regulators, consultants,

project managers) are used to dealing

with groundwater, it is very easy to

carry over this equivalency to vapor

samples. Undoubtedly, this is the

most common error that I see being

made by practitioners in the vaporintrusion field. And it’s huge! The

reason? For benzene, one μg/L is

equal to ~300 ppbv; for TCE, ~180

ppbv. So, we’re talking greater than

two orders of magnitude error if the

units are inadvertently thought to be

equivalent. 

This confusion about units

occurs most commonly in the following situations: 

• When vapor-risk models, such as

EPA’s Johnson-Ettinger model

spreadsheets, are used. If you

inadvertently flip the units, you’ll

start off two orders of magnitude

too high or too low. Compare the

magnitude of this error to the

sensitivity of some of the other

common J-E model parameters

from default values. Porosity: factor of 5; Qsoil: factor of 3; Ventilation rate: factor of 10. The point is

this error is much greater than all

of the others combined.

• Calculating soil-gas concentrations from groundwater data

using Henry’s constant. For benzene, the equilibrium soil-gas

concentration with 10 μg/L in

the groundwater is ~2 μg/L. If

you inadvertently write it as 2

ppbv, then you have erred by 300

times. 

• Comparing on-site results in

units of μg/L to off-site results

reported in ppbv. If the off-site

confirmation samples show hits

at 100 ppbv and the on-site data

were all below detection at a DL

(detection level) of 1 μg/L, don’t

panic. The results agree. 

■ What’s an easy way out of unitconversion madness? 

• Instruct your lab on what units

and detection levels you want

the data reported in. 

• Go to www.HandPmg.com for a

handy-dandy, easy-to-use unit

conversion spreadsheet.

■ What are “vapor clouds” and why

should we care about them?

Vapor clouds refer to situations

where there is subsurface contamination of the soil vapor with little or no

coincident soil or groundwater contamination, hence the term “cloud.”

They arise from leaking vapors, not

from contaminated soil or groundwater. Common sources for vapor

clouds are sites that contain surface

sources of chlorinated solvents (e.g.,

vapor degreasers, dry cleaners, clarifiers), where the dense chlorinated

vapors enter the vadose zone from

above, or where vapors are leaking

out of USTs.

12

LUSTLine Bulletin 48 • November 2004

How to Collect Reliable Soil-Gas Data for Risk-Based

Applications—Specifically Vapor Intrusion

Part 3 – Answers to Frequently 

Asked Questions

by Blayne Hartman

Since I wrote Parts 1 and 2 in July 2002 and October 2003 (LUSTLines #42 and #44), vapor intrusion has continued to be a

“box-office blockbuster” throughout the environmental remediation community. I have provided vapor-intrusion training to

no fewer than 12 states, several U.S. EPA regions, and the Department of Defense. Others, including U.S. EPA staff and the

American Petroleum Institute (API), are providing training at conferences and to interested parties. Groups such as EPA’s Office of

Solid Waste and Emergency Response and the Office of Underground Storage Tanks, ITRC, and API have formed vapor-intrusion

technical workgroups. Many states have written soil-gas policy/guidance, promulgated regulations (e.g., CT, LA), prepared draft

documents (i.e., NJ, MI), or are presently contemplating preparing guidance (i.e., WA, AZ). Everyday, I receive phone and e-mail

inquiries on a variety of topics, including soil-gas protocols, analytical methods, and sampling strategies. With all this interest, I figure it’s time for Part 3 in this series: Answers to Frequently Asked Questions. The following questions are accompanied by answers,

as I see them, that I hope will be helpful.
You should care about vapor

clouds for a number of reasons. First,

unlike groundwater, vapors can

move in all directions, regardless of

the groundwater gradient, and move

quickly—approximately 25 feet/year

by molecular diffusion alone. So, a

vapor cloud from a dry-cleaning

washer unit can move laterally

underneath adjoining businesses in a

strip mall within one year and represent an upward migration threat to

nearby residences within a few years. 

Vapors leaking from an UST can

move downward through the vadose

zone to the groundwater and represent a groundwater contamination

threat. (See “The Downward Migration of Vapors,” LUSTLine #29 and

“The Great Escape from the UST,”

LUSTLine #30 for discussions of this

pathway.)

When the J-E model underpredicts the measured risk, or indoor

air results don’t match with groundwater patterns, or when vertical profiles of the soil gas don’t show

increasing concentrations with depth,

vapor clouds should be suspected

and soil-gas data, not soil or groundwater data, must be collected to adequately assess the upward vapor risk

pathway.

Finally, as pointed out by a

reviewer of this article from the rainy

south, while vapor sources can exist

anywhere, vapor clouds are more

likely to exist in areas with deeper

groundwater and less rain. In areas

with shallow groundwater and abundant rain, any leaking vapors are

more likely to get scrubbed (partition) into the groundwater (similar to

a “Mister Coffee”). 

■ Is it true that an equation written to

allow passive soil-gas data to be

converted to concentration units is now

applicable for vapor-intrusion

assessment? 

Yes and no. It is true that an equation

has been written by a firm providing

passive soil-gas services. The analysis

of passive soil-gas samplers gives the

mass on the passive collector (e.g.,

micrograms [μg] or some other form

of relative units), not concentration.

Concentration is mass/volume. So, to

convert mass to concentration we

must know the volume of vapor that

comes into contact with the adsorbent during burial. There is no way to

know this and no accurate way to

measure this volume on a true passive sampler. Therefore passive 

soil-vapor data cannot be used 

for quantitative upward vapormigration assessment, despite what

you might be hearing. One could

pump a known volume of air

through a passive collector, similar to

the NIOSH methods or TO-17, but

this is far different than simply burying a collector into the ground and is

actually a form of active soil-gas surveys.

■ Why weren’t you more bullish on

flux chambers in your last article?

The primary purpose of the article

was to describe the two common

chamber methods (i.e., static and

dynamic), how to use them, and the

pros and cons of each. The article was

written in response to numerous

questions I was receiving from both

the consulting and regulatory communities about the technique. But 

the overriding problem with the

approach is whether chambers can be

located properly. In many structures,

the primary entry of soil gas into the

structure is through discontinuities in

the floor slab (e.g., cracks, holes,

sumps), and these locations might be

concealed by barriers such as floor

coverings, walls, and stairs. 

However, as I wrote in the article, I think flux chambers have their

place when the right conditions exist.

Examples of “right conditions”

include slabs in good condition 

with limited pipes/utilities poking

through, larger slabs (i.e., larger than

a typical residence), and undeveloped lots in warmer climates or

where estimates of a future stack

effect due to the building can be

made. 

If you elect to use flux chambers,

be sure that enough chamber measurements are collected to get a representative value over the footprint

of the building (analogous to placing

enough borings on a typical site) and

that they are located near edges

where the slab meets the footing,

over any zones with more cracks, and

over the center of the contamination,

if known. 

Assuming uniform subsurface

contamination, five chambers might

be appropriate (one on each side of

the structure and one in the center). If

the contamination is not directly

below, then fewer chambers on the

side of the contamination might be

appropriate. In all cases, chambers

should be deployed for long enough

periods to enable temporal variations

to be assessed, similar to indoor air

measurements (8 to 24 hours depending on the conditions; 24 hours if

large temperature differences exist

between day and night).

■ Why do you recommend small

purge-and-sample volumes for soil-gas

samples?

Multiple reasons. I too often see soilgas data from large Summa canisters

(3L to 6L) with tracer/leak compound detections. (By tracer/leak

compound, I am referring to a

compound such as butane or

isopropanol, deliberately applied

during sample collection, that acts as

a tracer of leaks from the surface or

leaks in the sampling system.) Also,

successive duplicate samples (i.e.,

one collected after the other) show

larger variations than duplicates

collected with smaller volumes.

Remember, the larger the volume collected, the greater the uncertainty as

to the source of the sample. (See Figure 1.) That’s a plain fact. 

So, if you are sampling near the

surface, large extraction volumes will

increase the potential that atmospheric air might be drawn down the

outside of the probe body. If you are

sampling under a slab, large extraction volumes will increase the potential that samples might be from a

deeper depth or outside the slab. In

addition, large purge-and-sample

volumes can create vacuum conditions that cause contaminant partitioning from the soil into the soil gas. 

All of these issues increase the

potential that the collected soil-gas

sample is not representative of in-situ

soil vapor at the target depth. Finally,

the larger the volume required, the

larger and more complex the sample

collection system required (e.g., vacuum pumps, larger sample containers). 

■ What about when air labs tell me I

need to collect 6L volumes to reach my

required DL?

You shouldn’t need to. Soil-gas DLs

for VOCs of 0.2 to 0.5 ppbv (~ 1

μg/m3 for most compounds) can be

reached with only 300 cc of sample

(as reported to me by a nationwide

air lab) using method TO-15, and

13

November 2004 • LUSTLine Bulletin 48

■ continued on page 14
with volumes as small as 50 cc using

methods 8260 SIM or 8021. Yes,

larger canisters are useful in case

repeated runs are required. But, for

the TO-methods, one to three liters

should be more than sufficient to

enable re-runs, if necessary. For

methods 8260 or 8021, 500 cc should

be more than sufficient.

■ Is it true that the toxic organic (TO)

methods are the only appropriate

method for analyzing soil-gas samples? 

No, but you may be hearing this from

some of the labs that specialize in

these analyses. The argument is that

EPA methods such as 8260 and 8021

are soil and water methods that use

liquid standards and hence are not

appropriate for air samples. Further,

according to the argument, soil-gas

samples are air samples and, thus,

should be analyzed by air methods

that use gaseous standards. The key

difference in the methods is not the

type of standard but how the

standard and sample are introduced

into the analytical instrument. TOmethods use air concentrators. Methods 8260 and 8021 use direct injection

or purge-and-trap injection systems. 

For the majority of compounds of

concern at vapor-intrusion sites (e.g.,

BTEX, chlorinated solvents), there is

no significant difference caused by

the injection methods. For some compounds (typically the more polar

ones such as ketones and alcohols),

methods 8021 and 8260 can give different values from the TO-methods

by up to a factor of two to three if the

purge-and-trap injection method

with liquid standards is used. In the

cases where this might be an issue,

either use the TO-methods or ask the

laboratory to use vapor standards for

8260 or 8021. 

The decision on what analytical

method to use should be based primarily on the required detection

level, project scope, and cost—in this

order. See Table 1 to help you decide.

For example, if the compounds of

concern at a site are only TCE, PCE,

TCA, and DCE, then the GC-ECD is

more than likely to reach the DLs

required and it costs one-third what a

TO-15 SIM would cost. And yes, the

data will be legally defensible if the

lab follows the method QA/QC.

■ Why do you promote on-site analysis

so heavily?

Mostly because on-site analysis

allows you to use your brains in realtime. This is especially powerful for

vapor-intrusion assessments because

additional locations can be added,

either spatially or vertically, based on

the real-time data. It also allows mistakes (e.g., leaked gas breakthroughs,

inconsistent numbers, hardware

blanks) to be recognized on-site and

verification or replicate samples to be

collected as needed. Laboratorygrade instruments, including mass

spectrometers, can be transported

into the field, and they fulfill necessary analytical protocols. 

■ Isn’t your opinion biased, since you

provide on-site services?

Yes, but not for this reason. The real

reason for any bias is the power that

real-time data and decision making

bring to assessing this risk pathway—and I’m not the only one who

feels this way. A growing number of

federal and state regulatory agencies

and consultants are hopping on this

bandwagon. In fact, EPA has a realtime, instantaneous analyzer called

the Trace Atmospheric Gas Analyzer

(TAGA) that staff actively promote

and use on vapor-intrusion sites.

Also, EPA is a strong supporter and

promoter of the Triad approach 

that includes on-site analyses

(http://www.clu-in.org/triad/#usin).

14

LUSTLine Bulletin 48 • November 2004

METHOD DETECTION LEVEL (μG/M3) PRICE* COMMENTS

8021 for MTBE/BTEX 10 to 20 $ 75 False positives if high TPH

8260 100 $ 100 Complete VOC list & naphthalene

8260 SIM 5 to 10 $ 150 Subset of 5-10 compounds#

TO14 or 15 1 to 5 $ 250 Complete VOC list, no naph.

TO15-SIM 0.01 to 0.05 $ 325 Subset of 5-10 compounds#

GC-ECD 0.5 to 5 $ 90 Chlorinated compounds only

* Listed price are estimated and will vary around the country.

# You select the subset from the full VOC list.

Summary of Analytical Methods for VOCs in Soil-Gas Samples TABLE 1

FIGURE 1. A basketball or a baseball? The 6L Summa canister has a volume about the size of a

basketball, whereas the mini-can has an approximate volume of a baseball. 

■ Vapor Intrusion from page 13
(See “LUST Innovations, TRIAD, and

Computer Imaging Move LUST Site

Investigation into the 21st Century,“

LUSTLine #45.)

■ Why are you so worried about the

hardware required by the TO-methods

for soil-gas samples?

For a number of reasons, primarily:

• There are many connections and

fittings, all with dead-volume

and possibilities of leaks. (See

Figure 2.)

• More hardware means more can

break, have blanks, or not work

properly.

• Few field technicians or fieldsampling companies have the

experience of testing and using

the hardware properly or fixing

or repairing it if problems are

recognized.

• Often, the connecting fitting/

tubing or flow chokes are reused

between samples without being

cleaned. Very recently, a lab provided me 30 canisters for a program with only two flow chokes

(one to use plus a spare). What’s

wrong with this picture? If

you’re reusing flow chokes

between samples, how do you

know that they are not contaminated from the previous sample?

At a minimum, a cleaning kit and

instructions on how to clean the

flow choke between samples

should have been included.

Throw into this mix the bulkiness

of the hardware (ever tried to put sixteen 6L canisters in your car?), and

hopefully you can understand my

concern.

■ I keep getting tracer/leak gas

detections in my samples, and the

regulators are not accepting the data.

What am I doing wrong?

The problem probably stems from any

one or all of the following scenarios: 

• Collecting too large a volume of

soil-gas sample (>1 liter) too

close to the surface

• Not adequately sealing at the

surface of the ground where the

probe rod enters

• Leakage at the coupling inside

the probe rod, if the post-run tubing method is being used

• Using a permeable tubing to collect soil-gas samples

• Loose fittings on your sampling

system train 

■ What tubing do you recommend?

Rigid-wall, nylon tubing, 1/8” or

1/4” outer diameter. Believe it or not,

Teflon, while inert, has a relatively

high sorption for many compounds.

The 1/8” nylon tubing is easier to

work with than the 1/4” tubing if

soil-gas sampling is your only need.

If permeability testing is desired, the

1/4” tubing is better. Stainless-steel

tubing is fine for shallow sampling

but is logistically more difficult to

install as the sampling depth

increases (>5’). Flexible tubing (e.g.,

rubber, plastic), such as the type

available on rolls at the hardware

stores, or tygon tubing should be

avoided at all costs (too permeable).

■ What is an “alpha factor,” and how

do I use it when trying to scope a vaporintrusion project? 

An alpha factor is a unitless empirical

attenuation factor relating the indoor

air concentration to either a subsurface soil-gas concentration (αsg) or to

a groundwater concentration (αgw) as

follows:

(αsg) = Cindoor/Csoil gas

(αgw) = Cindoor/(Cwater * H)

H is the compound’s unitless

Henry’s law constant.

U.S. EPA and most oversight

agencies have tabulated acceptable

levels for compounds in breathing air

for various risk levels (Cindoor). So, if

you know the alpha factor that the

oversight agency allows for soil gas

or groundwater, you can calculate

the required “fail level” and hence,

detection level for the compound in

either the soil gas or groundwater.

Let’s try one to see how it works:

From Table 2 of the EPA draft vaporintrusion guidance, the allowable air

concentration for benzene at a 1 in a

million risk level is 0.31 μg/m3. For

soil-gas samples collected at 5 feet

below the structure, the default alpha

factor from Figure 3a of the guidance

for sandy soils is 0.002. What is the

15

November 2004 • LUSTLine Bulletin 48

■ continued on page 16

FIGURE 2. Comparison of a sampling train provided by a lab to fill canisters for off-site analysis

vs. a syringe used for on-site analysis. The larger dead-volume and numerous connections of the

sampling train increase the chances of equipment blanks and leaks.
soil-gas “fail level” and what analytical

method(s) could be used?

Rearranging the first equation

above: 

Csoil gas = Cindoor/(αsg) =

0.31/.002 = 155 μg/m3 

From Table 1 in this article, we

see that all the methods can

reach this detection level.

But, for sub-slab sampling, the

EPA draft vapor-intrusion guidance uses a default alpha factor of

0.1. Now what is the soil-gas “fail

level” and what methods suffice? 

Answers:

Soil-gas “fail level” = 3.1 ug/m3

Analytical methods = 8260 SIM,

TO14, or TO15

■ What is the EPA vapor-intrusion

“dead zone”?

Well, to be honest, it’s my own term

to describe the lack of direction in

EPA’s draft vapor-intrusion guidance on what sampling to do

between 5 feet and the sub-slab (in

review of this article an EPA representative called it the “No Predictive

Modeling Zone”). This amounts to a

4 1/2 ’ gap in the vadose zone where

there is no instruction. And yet, this

is an important zone. 

A number of key processes influencing the soil-gas concentrations are

active in this zone, including bioattenuation, surface reaeration, barometric pumping, and infiltration of

surface precipitation. Vertical profiles

of soil gas adjacent to or under structures can be very informative and

demonstrate that attenuation of the

contaminant is occurring. Agencies

should allow and encourage these

data. The San Diego County Department of Environmental Health

(DEH) is currently writing regulatory

guidance and protocols for the “dead

zone.”

■ What is your opinion on sub-slab vs.

near-slab sampling?

The default approach right now by

some agencies is to collect sub-slab

soil-gas samples and apply an alpha

factor of 0.1 to 0.01. But sub-slab sampling has its share of problems. 

Operationally, sub-slab sampling

is easy to do. But for the responsible

party (RP), sub-slab sampling can

definitely be a “Prozac moment.”

First, sub-slab sampling is much

more intrusive than outside sampling

and, more likely than not, will

require access agreements and attorneys, especially if you are an RP with

deep pockets. Second, the proper

alpha factor to apply is not known, so

the significance of detected values is

not clear, and you may over exaggerate the risk. Third, sub-slab data

alone give you no information on

what is going on below in the vadose

zone towards the source.

For these reasons, I typically recommend that clients refrain from

sub-slab sampling at the start.

Instead, I prefer to collect soil-gas

data around the structure for an

underlying source (e.g., groundwater

contamination), or on the side of the

structure towards the source for a lateral source (e.g., adjoining groundwater or soil contamination or a

vapor cloud), in an attempt to

demonstrate there is no potential

risk. If oxygen levels are high,

groundwater levels are not within

two feet of the structure (e.g., basement, slab, crawlspace), and areas for

air penetration exist around the slab

(e.g., lawns and gardens), then

chances are high that reaeration is

occurring under the slab, and nearslab data will be representative of

sub-slab, especially for residences

with small slabs. 

Remember also that contaminants in the vapor phase, like balls

and groundwater, cannot run uphill

and accumulate under a slab at

higher concentrations than the source

concentration. In other words, the

very highest the sub-slab soil-gas

concentration can be is the same as

the soil-gas concentration at the

source. So, assuming a groundwater

source, if you measure the soil-gas

concentration just above the groundwater, the sub-slab concentration can

be no higher, even with preferential

pathways. If the risk calculation

passes using this measured value,

you need not collect sub-slab samples. 

Likewise, if you measure the soil

gas midway between the source and

structure, the soil-gas concentration

will be approximately one-half the

source concentration assuming a

homogeneous vadose zone with no

advection. So if measured values all

around the structure at the middepth agree, and the risk calculation

passes by more than a factor of two,

sub-slab sampling is likely not necessary unless you have reason to suspect a preferential conduit. 

If you must go sub-slab, try to

stay in garages (if technically sound)

to do so. And remember, collect

enough samples to get a representative value under the slab. EPA recommends three sub-slab samples per

domestic residence to characterize

spatial variability, although I personally think one per side and one in the

middle is better (total of five).

■ What’s this I’m hearing about using

radon gas as a natural tracer?

As mentioned previously, the difficulty with sub-slab soil-gas data is

that the alpha factor is not really

known and regulatory default values

tend to be conservative, so use of

them may overestimate the risk.

Measurement of naturally occurring

radon inside the structure and subslab can allow a site-specific alpha

factor to be calculated that may be

considerably less than the value

allowed by the regulatory agency.

That same alpha factor can then be

used to estimate the indoor air concentration of the contaminant of concern, assuming that all vapors are

entering the building at equal rates. 

Keep in mind that like all the

other tools being used for vaporintrusion assessment, radon has its

limitations too. First, and perhaps

foremost, you must have radon in

high enough concentrations to be

useful. Then there’s a host of other

questions: Are there any inside

sources of radon (e.g., cement block,

granite stone, and shower water)?

How will the values vary with barometric pressure fluctuations? From

season to season? And remember,

indoor and sub-slab samples create

access headaches. Nevertheless, if

you are already collecting sub-slab

samples, concurrent collection of

radon data may prove useful, and it

does not cost a great deal (<$100 per

sample). 

■ Are hydrocarbons really

bioattenuating in the shallow vadose

zone, or is it propaganda by the oil

companies in an attempt to minimize

their vapor-intrusion problems?

A vast number of studies have been

performed that clearly demonstrate

16

LUSTLine Bulletin 48 • November 2004

■ Vapor Intrusion from page 15
the bioattenuation of hydrocarbon

vapors in aerobic soils. Many, but not

all of these studies, were performed

by the oil industry (go to www.API.

org to read published studies). In general, the studies show that when oxygen levels are 10 percent or greater

and at least two feet of vadose zone

exists between the contaminant

source and the overlying structure,

the hydrocarbons aren’t likely to

pose an unacceptable risk. (A published study by the New Jersey

Department of Environmental Protection suggested oxygen levels as

low as 6 percent are sufficient).

While there is a current effort to

try and quantify the bioattenuation

process and add a quantitative term

to the existing models, it is more

likely to expect that the bioattenuation rate will be extremely site dependent. The more accepted alternative

is to document that this process is

occurring by collecting vertical profiles of the soil gas for the hydrocarbons, oxygen, and carbon dioxide. 

If shown to occur, some agencies

are conservatively allowing a factor

of 10 to 100 reduction in the alpha

factor. EPA-OUST currently has a

technical workgroup consisting of

EPA and state regulators studying

this issue with the intention of

preparing guidelines or recommendations on assessing vapor intrusion

at hydrocarbons sites.

To document that bioattenuation

is occurring, I recommended that

data be collected at a minimum of

three locations vertically in the upper

vadose zone to ensure that vertical

variations are characterized adequately. If repeated data are desired,

install vapor-monitoring wells

(implants) for easy resampling. 

■ What are the best current

documents, including regulatory, on

soil-gas collection for vapor intrusion?

• The most comprehensive regulatory document for the collection

of soil-gas samples was written

by California EPA (Department

of Toxic Substance Control) in

conjunction with the Regional

Water Quality Control Board in

January 2003.

http://www.dtsc.ca. gov/PolicyAndProcedures/SiteCleanup/SMBR_A

DV_activesoilgasinvst.pdf

• The San Diego County DEH Site

Assessment Manual has soil-gas

collection guidelines for a variety

of soil-gas applications, including upward vapor risk. These

guidelines are not step-by-step

protocols, but they present general issues that need to be considered and fulfilled. 

http://www.sdcounty.ca.gov/deh/

lwq/sam/vapor_risk_assessment_

2000.html

• The API has written a soil-gas

sampling document and has a

number of papers on bioattenuation, J-E model, and other related

topics. 

http://www.api.org/bulletins

• EPA-ORD (Dr. Dominic DiGuilio) recently released a sub-slab

soil-gas sampling standard operating procedure (SOP) that is

available on the following Web

site: (http://iavi.rti.org/resources.

cfm?pageID=document).

• SOPs for vapor monitoring

well/implants installation, subslab soil-gas sampling, deeper

soil-gas sampling, and fluxchamber sampling are available

on my Web site, as well as links

to most of the above documents

and Parts 1 and 2 of this series of

LUSTLine articles.

www. HandPmg.com

I wish to thank my reviewers on

this article for their constructive comments, including Henry Schuver,

Rafael Cody, Rod Thompson, Craig

Dukes, Tom Scott, Larry Frobe, Todd

McAlary, Gina Plantz, Victor

Kremesec, John Menatti, Roger

Brewer, and Louise Adams. ■

Blayne Hartman, Ph.D., is a partner of

H&P Mobile Geochemistry (formerly

HP Labs), a firm offering on-site sampling and analysis. He has lectured on

soil vapor methods, data interpretation,

and vapor intrusion to over 20 state

agencies, to all of the U.S. EPA regions,

and the DOD. Blayne has authored

chapters in four textbooks on soil vapor

methods and analysis. He has contributed more than ten articles to

LUSTLine since 1997, and this is his

fifth article on vapor intrusion-related

issues. Blayne can be contacted at

bhartman@ HandPmg.com or check

out his Web site at

www.HandPmg.com.

What Does The Future Hold?

I dream of leak-free tank systems, the

end of operator error, gasoline in the

tanks and cars and not in the environment (or better yet, vehicles propelled

by something better for the environment), and........ ZZZZZZZ. Actually,

I’m too tired to dream. But for now,

we’re hanging in there, and we’ve got

the program with the most “interesting” acronym. Go LUSTBusters! ■

Patricia Ellis is a hydrologist with the

Delaware Department of Natural

Resources and Environmental Control

(DNREC), Tank Management Branch.

She has a regular column in LUSTLine

called “WanderLUST.” Pat can be

reached at Patricia.Ellis@state.de.us.

References

Ellis, Patricia, 2003. A Hot Dog by Any Other Name

Could Be Your Drinking Water. LUSTLine Bulletin

44, July 2003, pgs. 1-6. 

Federal Regulations, 1988, 40 CFR 280 – Underground Storage Tanks – Final Rule as of 9/13/88

http://www.epa.gov/swerust1/fedlaws/cfr.htm#

40cfr280.

Gray A. and A. Brown, 2000, Fate, Transport And

Remediation Of Tertiary Butyl Alcohol (TBA In

Groundwater (Abstract) In Ground Water: Prevention, Detection, & Remediation Conference and Exposition. Special Focus: Natural Attenuation and Gasoline

Oxygenates, November 14, 2000, Anaheim, California; P278

NEIWPCC (New England Interstate Water Pollution

Control Commission), 2000, Survey of State Experiences with MTBE Contamination at LUST Sites, June

2000.

Sakata, Rachel, and Mike Martinson, 2001, Update on

State MTBE Regulatory Standards & Guidelines:

Drinking Water & LUST Cleanup. Presented at 13th

Annual UST/LUST National Conference, March 20,

2001.

TPH Criteria Working Group, 1997, Total Petroleum

Hydrocarbon Criteria Working Group Series, Vol. 4:

Development of Fraction Specific Reference Doses (RfDs)

and Reference Concentrations (RfCs) for Total Petroleum

Hydrocarbons (TPH). Amherst Scientific Publishers,

Amherst, Massachusetts, 137 pp. 

U.S. EPA, 2000, Memorandum from Sammy Ng,

OUST to Regional UST Program Managers and

State UST/LUST Program Managers: Monitoring

and Reporting of MTBE and Other Oxygenates at

UST Release Sites, January 18, 2000. 

U.S. EPA, 1999, Use of Monitored Natural Attenuation at

Superfund, RCRA Corrective Action, and Underground

Storage Tank Sites, Directive Number 9200.4-17P.

http://www.epa.gov/swerust1/directiv/d9200417.pd.f

U.S. EPA, 1997. Expedited Site Assessment Tools For

Underground Storage Tank Sites: A Guide for Regulators, (EPA 510-B-97-001), March 1997.

http://www.epa.gov/swerust1/pubs/sam.htm.

U.S. EPA, 1995, Use Of Risk-Based Decision-Making in

UST Corrective Action Programs, OSWER Directive

9610.17 March 1, 1995. http://www.epa.gov/swerust1/

directiv/od961017.htm

Weaver, James W., and John T. Wilson, 2000, Diving

Plumes and Vertical Migration at Petroleum

Hydrocarbon release Sites. LUSTLine Bulletin 36,

November 2000, pps.12-15. 

17

November 2004 • LUSTLine Bulletin 48

■ 20 Years from page 5
by Andrew Shively

S

ince February 2002, the Vermont

Department of Conservation’s

(DEC’s) UST program has discovered situations that represent

acute or chronic releases of vaporphase petroleum from UST systems.

Since our initial investigations, we

have grown increasingly concerned

that underground petroleum vapor

releases (UPVRs) have the potential

to significantly impact human health

and the environment. Our experience

seems to support findings in New

Hampshire and California. (see

LUSTLine #46 and #47); however, the

topic is still in its infancy, and more

knowledge is needed to nurture a

greater understanding of the potential impacts, investigative tools, and

remedial solutions in UPVR scenarios. 

The LUSTLine #47 article titled

“Tracking Troubling Vapor Releases

in New Hampshire” discusses the

relationship of UST system pressurization and vapor releases. The

research conducted by the New

Hampshire Department of Environmental Services (NHDES) provides a

shot of adrenaline to our body of

knowledge on the topic. The study

documents the chronic and dynamic

force of very low pressure within

UST ullage systems, presents a remedial technology that can be used to

control the ullage system pressure,

and demonstrates the reduction of

volatile organic compound (VOC)

impact to groundwater. I would like

to help reinforce our information

base by providing a framework of

specific elements and techniques that

should be considered when determining if UPVRs are a suspected

source of petroleum contamination at

a facility.

In the beginning, it was hard to

imagine how a little gas vapor from

the in-tank monitor (ITM) probe riser

could cause groundwater contamination. In fact, as late as 1998, few people in the business paid any attention

to a little gas vapor under an USTsystem manhole. How many times

did a seasoned UST inspector open

an uncontained vent-riser manway

and note moderate gasoline vapors?

Plenty I’d say. Almost routinely. But

the vapor concentrations were also

routinely and quickly dissipated after

the manway was allowed to remain

open, and with no apparent liquid

source, the potential threat of impact

was dismissed. That was the paradigm we operated under until early

2002, when an incident occurred that

expanded our awareness to include

vapors as a possible source of petroleum compound impact to human

health and the environment.

An Explosive Episode in

Paradigm Progress

In late February 2002, I was notified

that intermittent but significant gasoline vapors were inundating the

indoor air space of a retail gasoline

facility in northern Vermont. The

UST owner contacted the DEC

because he had recently discovered

that the back room of his facility had

been filling with gasoline vapors during evening deliveries. He had not

been informed of this fact until the

night staff started complaining to the

manager.

The manager learned that over a

period of a several months, every

time gasoline was delivered, the

uninsulated back room would reek of

gasoline vapors. The night staff had

temporarily solved the problem by

venting the back room—a good idea,

since that was where they took cigarette breaks during the cold (and I

mean cold) winter nights. Since the

vapors diminished after delivery and

venting, little was said about the condition.

Upon my arrival, several initial

steps had been taken to reduce the

indoor air impact and diagnose the

cause. An air-purifying unit had been

installed in the back room to reduce

overall VOC concentrations inside

the building. A soil-vapor extraction

(SVE) vent leg and high-vacuum

motor with carbon treatment had

been installed adjacent to the building in the area where the electrical

conduits from the tanks entered the

back room—Area of Concern #1

(AOC #1)—and an initial UST system

evaluation had been conducted by

the consultant. 

The initial evaluation revealed

the following:

• An in-tank monitor (ITM) probe

communication wire had been

installed such that gasoline

vapors could easily escape and

accumulate in the subgrade manway of the probe riser.

• The electrical conduit junction

box for the ITM communication

wire and the UST interstitial sensor wire were not sealed, allowing

vapors to migrate preferentially

toward the building.

• The routine UST compliance

inspection did not reveal any liquid release sources from the

gasoline USTs.

• The UST and Air Pollution Control (APC) regulatory requirements were in compliance.

• No gasoline spills had been

reported in the area of the facility, and no visual indications of

small unreported spills were

observed. 

Based on the observed status of

the UST features and lack of an

observable or reported spill, a liquid

release was concluded to be unlikely.

The owner agreed to and arranged

for a helium test to determine if any

additional or less obvious vaporrelease sources existed. The only significant helium source identified was

the previously mentioned ITM proberiser communication wire fitting. The

18

LUSTLine Bulletin 48 • November 2004

Vermont Vapor Stories

The Evolution of Vapor-Release 

Assessment Techniques
LUST Sites Calling

Clearly, the scenario described above

represents a potential human health

impact—200 to 300 ppm VOC in

indoor air is nothing to dismiss. The

1996 Threshold Limit Values (TLVs)

for gasoline, as published by the

American Conference of Governmental Industrial Hygenists (ACGIH),

identify gasoline as a carcinogen and

adopt a time-weighted average

(TWA) exposure value of 300 ppm

with a short-term exposure limit

(STEL), or ceiling, of 500 ppm for airborne contaminants. At the time of

the incident, the indoor air contaminant levels were taken very seriously,

but the connection of a petroleum

vapor release to a groundwater

impact seemed less certain—at least

until our next reported incident. 

In October 2003, the DEC Sites

Management Section (SMS) was

notified of extremely high MtBE concentrations in groundwater downgradient of an active UST system at a

location in Colchester, Vermont. The

MtBE concentrations were the highest recorded in the four years of

quarterly groundwater monitoring

conducted at the site (See Table 1).

The site was monitored for a

baseline of contamination concentraNovember 2004 • LUSTLine Bulletin 48

FIGURE 1. ITM and interstice risers with electrical junction box, post repairs. Note UST

system backfill.

19

riser was contained in a 24” shallow

manway with the UST system backfill exposed. (See Figure 1.) 

As part of the emergency

response, the SVE system was operated to reduce VOC impact to indoor

air space. VOC influent concentrations measured during active SVE

system operation declined from 200

to 300 parts per million (ppm), as

measured by a photoionization

detector (PID) at start-up, to 30 to 40

ppm within a few hours of operation.

The SVE remained in operation until

the helium test could be conducted

and was shut down during testing. 

Following testing and repairs to

the ITM communication wire assembly and the junction box, a postrepair SVE start-up test measured no

detectable influent VOCs by PID.

Additional monitoring of the SVE

system operation over the following

week found no detectable influent

VOC concentrations, and the emergency remedial equipment was dismantled and removed from the

facility. 

Groundwater monitoring conducted on the site indicted that no

discernible additional impact of

groundwater had occurred in the area

of the SVE system, but a new previously unknown plume of methyl-tert

butyl ether (MtBE) in groundwater

was identified in another isolated

area of the site (AOC #2). The common thread connecting AOCs #1 and

#2 to the vapor release source location

was electrical conduits for the ITM

and interstice sensors for a diesel UST

installed in a separate excavation

from the gasoline USTs. 

The certainty of concluding that

the new MtBE plume in groundwater

was from the vapor release at the

gasoline UST appears logical but not

conclusive. What is certain, however,

is that an underground petroleum

vapor release can occur from an UST

system, and it can cause significant

human health impacts that require

emergency corrective action. Furthermore, the force driving the emission

of vapors appears related to delivery

pressures.

Date MW-2 MW-3 MW-4 SS-2

5/18/1999 1 1 1,210 64

9/13/1999 420 260 900 160

12/21/1999 250 100 1,800 16

3/7/2000 160 100 2,100 12

5/31/2000 300 370 1,200 11

9/22/2000 213 1 264 66

3/29/2001 200 1,000 1,260

6/18/2001 400 1,000 642

9/17/2001 364 1,000 756 10

12/28/2001 84 500

3/8/2002 1,200 240 2,300 28

6/3/2002 1,610 672 233 21

3/31/2003 192 1,080 1,520 10

9/11/2003 53,000 47,000 641 1,740

11/28/2003 33,000 64,000 4,400 130

3/18/2004 1,060 414 58

7/2/2004 191 198 5,720 29

MTBE Concentrations (ppb) in Groundwater, Colchester TABLE 1

■ continued on page 20
tions prior to a corrective action feasibility investigation (CAFI), and a

pilot study of remedial options was

scheduled for the fall of 2003. The

groundwater analytical results took a

drastic turn upward during the summer of 2003. Most unsettling was the

fact that only MtBE seemed to be

increasing, both significantly and

suddenly. MtBE-contaminated groundwater was also infiltrating a storm

sewer along the downgradient

boundary of the site and discharging

to a surface water feature (SS-2). (See

Table 1.) Was this the lead edge of an

upgradient plume? Was the source

within the tank cavity? Was it a spill?

Was it a UPVR impacting groundwater?

An inspection conducted at the

facility during the summer of 2002

prior to the request for a CAFI had

not found any signs of a liquid

release or spill, let alone significant

compliance deficiencies. APC records

indicated the facility was in compliance with testing and inspection

requirements. The operator maintained adequate documentation and

operational release detection. The

peak MtBE concentrations in groundwater suggested the source centered

in the tank cavity. A PD test was suggested to determine if a potential

vapor-phase release existed and, if

so, to pinpoint the release location.

The owner agreed to and arranged

for a PD test with oversight by DEC,

a contractor, and a consultant. The

test was conducted in late October

2003. 

Prior to the PD test, a routine

inspection was conducted to establish

a baseline of possible liquid release

sources. The inspection resulted in

the same conclusion drawn in 2002—

no signs of a liquid release,

unreported spills, or compliance deficiencies. During the test, several pressure-decay release sources were

identified, including a misthreaded

vent-riser cap and a compressed cap

gasket. Other decay sources included

loose fill risers at both gasoline USTs

located on site. All of these potential

vapor-release sources were repaired

at the time of the test and the PD test

ultimately passed. 

Groundwater analytical results

following testing and repair showed

a marked decline in MtBE concentrations, beginning with the monitoring

location immediately downgradient

(MW-2). Over time, it appeared that

the MtBE plume migrated, as

expected, along the groundwater

gradient (MW-2 to MW-3) and was

diluted with uncontaminated

groundwater, thereby reducing overall groundwater concentrations

(MW-3 to MW-4). Groundwater discharged from infiltration into the

storm sewer (SS-2) also declined substantially following the October testing and repairs. 

The SMS site manager considered the findings of the inspection

and the reduction of groundwater

concentrations over time to be indicative of a new release and requested

additional investigation under a second $10,000 release deductible. Currently, corrective action has been

postponed for the site pending ongoing monitoring with declining VOC

concentrations in groundwater (see

Table 1) and declining discharge concentrations to surface water.

An Evolving Issue

The vapor-release issue and the second deductible came as a shock to the

regulated entity, and, based on the

findings of inspections, testing, and

monitoring, a new “something” had

clearly occurred. That “something”

was clearly a contaminant from a

petroleum storage system. Significantly, the results of testing and

repairs appeared coincidental to the

decline of MtBE concentrations in

groundwater. I began to consider

ways to bridge that gap between

vapor-phase VOC emission concentrations and groundwater analytical

concentrations. 

The PID is an accepted portable

device for direct-read measurement

of VOC concentrations. We felt that

collecting atmospheric and belowgrade, vapor-phase VOC concentrations would provide us with a useful

set of data to determine the relative

significance of detected vapor-phase

VOC emissions from tank-top features and to help pinpoint the source

of the emissions in an effort to make

immediate repairs. The process

would be to screen for atmospheric

VOC concentrations before opening

features, immediately upon accessing

features, and during the incremental

increase of UST ullage system pressure using pressure decay test

methodology. (See Figure 2.) 

The most obvious isolated subsurface areas of UST systems are the

below-grade features contained in

manways and sumps. Ancillary riser

manways are generally uncontained

(open bottom) and installed within

the system backfill underlying the

concrete pad. These types of features

include vent-extractor risers, Stage I

vapor-recovery poppets, in-tankmonitor risers, and unused risers.

Vapor emission sources could exist at

any uncontained feature connected to

the UST ullage system, including

Stage II and vent piping. For tank-top

features, a competent concrete pad

with tight manway covers acts as a

cap, forcing emitting vapors to accumulate in the below-grade atmosphere of the capped manway. (See

Figure 3.) 

LUSTLine Bulletin 48 • November 2004

■ Vermont Stories from page 19

20

FIGURE 2. VOC measurement by PID at suspected vapor release source.
Below-grade access features

allow for the accumulation and measurement of VOC emissions from

tank-top features. The VOC emission

data will assist in determining if a

vapor release is occurring, the relative concentration of the vapor

release, and the specific source point

of emission. Other elements that

impact the certainty of a vaporsource release determination include: 

• Observed or documented information of UST system configuration 

• Surface protection equipment

features (i.e., contained or uncontained)

• Backfill material (i.e., compacted

sand or peastone) 

• Subsurface migration pathways

(i.e., electrical conduits and backfill pathways) 

• Groundwater data (i.e., depth to

groundwater and VOC concentrations)

• Testing results (i.e., pressure

decay or helium) 

• Repairs (e.g., tighten seals,

replaced gaskets, additional pipe

dope)

In June 2004 an exercise was conducted at another LUST site with

active gasoline USTs to determine if a

vapor release was occurring. The

SMS site manager had been concerned that MtBE concentrations had

been rising downgradient of the

active UST systems. The site manager

suspected the source could be from a

vapor release because only MtBE was

increasing—to the highest level ever

recorded on-site. A pressure decay

(PD) test was scheduled for mid June

2004. As part of the PD test, a vaporrelease screening was conducted

with a PID before test set up, during

pressurization of the common UST

ullage system, and after repairs to

source features. 

Before the PD test setup, the

atmosphere above each UST feature

was screened with a PID to determine if fugitive VOC emissions were

escaping the sealed manways or if

ambient background VOC concentrations existed that could skew the values measured upon access to each

feature. No VOCs were measured by

PID during the atmospheric-assessment phase of the exercise. During

test setup, all potential vapor emission sources in subgrade UST-feature

manways were screened with a PID

as the manway covers were removed.

The VOC concentrations measured represent VOC values that

exist under chronic, standard operational system pressures. Based on the

data presented in the LUSTLine #47

article, standard operational pressures of a Stage II-compliant UST systems remain greater than 0.0 inch

water column (wc) and less than 1.0

inch wc. More importantly, this simple screening exercise is repeatable

and does not require an induced

increase of ullage system pressure.

From the setup screening exercise, three suspected VOC emission

source locations were determined to

exist—the ITM riser for the midgrade gasoline UST, the ITM riser for

the premium-grade gasoline UST,

and the vent riser for the premiumgrade gasoline UST. (See Figure 3.)

Specific emission sources were pinpointed at each of these features, and

the ongoing static VOC emission

value was measured. The PD test

began with the gradual increase of

ullage system pressures to 5.0 inches

wc positive pressure. (See Table 2.)

The VOC emission value exercise

was then repeated at all potential

emission sources. One additional

emission source was identified at a

system pressure of 5.0 inches wc.

Based on the calculated rate of decay,

the initial PD test was aborted at 5.0

inches wc, and repairs were made 

to the identified features with

measurable VOC emissions. Repairs

included: 

• Tightening fittings of communication wires of electronic release

detection equipment 

• Removing and rethreading of

riser features (riser bar caps) with

additional (or any) pipe dope

• Replacing cap gaskets

November 2004 • LUSTLine Bulletin 48

FIGURE 3. Riser manway with 235 ppm measured at static ullage system pressure.

Note condition of caps and backfill material at the base of the manway.

Initial Mid ITM Mid vent Prem ITM Prem vent

Static 79.5 ND 168 235

5.0” wc 146 83 <200 <300

Post repair

Static ND ND ND ND

5.0” wc ND ND >1.0 >1.0

10.0” wc ND ND >1.0 >1.0

21

■ continued on page 22

Pressure-Decay Test VOC Emission Concentrations (in ppm) Table 2
One major advantage of conducting this type of pressure-decayassisted vapor-release assessment is

that the VOC emission points can be

itemized, the emission value can be

measured, repairs can be made on the

spot before proceeding, and a VOC

emission reduction can be measured,

real time. (See Table 2.) As a result of

the above exercise, MtBE concentrations in groundwater immediately

downgradient of the active UST system have begun to decline. (See Table

3.) Additional groundwater sampling

is pending. 

If MtBE concentrations in

groundwater downgradient of the

active UST system continue to

decline as a result of the pressuredecay-assisted vapor-release assessment, the conclusion that a vapor

release was occurring and that the

source of the VOC emission was

repaired, will lead us to a determination that a vapor-phase underground

petroleum release had occurred.

The Evolution Continues....

The assessments presented include

three examples of what I consider

UPVRs. These are but three. Additional UPVR investigations are currently underway at ongoing

groundwater monitoring sites and

post-active remediation sites. The

degree of certainty in determining

that UPVRs exist varies considerably.

The determination requires time-sensitive information from often different regulatory jurisdictions. LUST

site monitoring data, spill data, APC

data, and UST compliance data must

all come together to provide a reasonable certainty that a release has

occurred. These data must also lead

to a high degree of certainty that the

22

LUSTLine Bulletin 48 • November 2004

■ Vapor Stories from page 21 release can only be attributed to

underground petroleum vapor-phase

emissions from petroleum UST features. 

The timeliness of information

from these four data sources has a big

impact on the degree of certainty.

Sometimes routine replacement of

caps or general maintenance events

can eliminate vapor sources. These

events could be UST-compliance

related or APC-compliance related.

Collecting the UST and APC compliance data and establishing a chronology of events enables a comparison

of MtBE concentrations in groundwater over time. 

The groundwater monitoring

results maintained as part of ongoing, pre- or post-remedial LUST sites

may indicate erratic MtBE spikes,

while the traditional benzene,

toluene, ethylbenzene and xylenes

(BTEX) concentrations decline. Sometimes these continued MtBE fluctuations drive remedial decisions long

after BTEX standards have been

meet. Conducting a pressure-decayassisted vapor-release assessment

allows us to detect VOC emissions

values to pinpoint source locations,

SNAPSHOTS FROM THE FIELD SNAPSHOTS FROM THE FIELD

Florida UST and AST facilities lost a lot

of canopies and dispensers to wind

damage. This UST was at a marina and

exposed by tidal surge. Marinas in general were hit hard, particularly docks

with dispensers and piping.

Ivan Takes on Tanks in Florida

Photo by Joe Thayer

Date MW-10

12/28/2001 950

3/25/2002 890

6/17/2003 510

11/18/2003 5200

7/9/2004 980

MtBE concentrations in 

groundwater immediately 

downgradient of an active UST system. 

(Note the period of concentration reduction

following pressure-decay-assisted vaporphase assessment and source repair.)

TABLE 3

If you have any UST/LUST-related snapshots from the field that you would like to share with our readers, please send them to Ellen Frye c/o NEIWPCC.

▲ These ASTs floated out of

their concrete dike area.

Photos by Charles Harp.
From recent articles and conference presentations there would

appear to be—at least in several

states—a heightened interest in the

potential effects of subsurface

releases of gasoline vapors from UST

systems. The last couple of issues of

LUSTLine have included several

interesting articles that address the

general topic of “small gasoline

releases,” which might be simply

defined as UST system releases that

are below the stated minimum

release-detection rates identified in

the federal regulations (i.e., 0.1 - 0.2

gph). 

It can be considered a testament

to the success of the state and federal

UST programs that while we used to

focus on releases of hundreds or

thousands of gallons of gasoline, the

debate has now moved to examining

the effects of comparatively tiny

releases. While it will always be our

goal to minimize the frequency and

amount of all UST releases, it will be

very important at this time for all of

us to better understand the prevalence and significance of these kinds

of small releases. We need to put

them in the context of our overall

goals for UST management. We need

to determine if existing regulations

provide a sufficient framework for

adequately addressing concerns with

this potential groundwater pathway,

or if new approaches might be

required.

Can We Put Vapor Releases

Into Perspective?

LUSTLine #46 provided a summary

of the California “Field-Based

Research” study, the first study to

suggest that small vapor releases

might be occurring in UST systems,

especially those with vacuum-assist

Stage 2 vapor recovery. That article

also summarized a sophisticated and

sensitive release-detection technology that can be used to identify certain types of releases that are much

smaller than 0.2 gph. 

LUSTLine #47 had a discussion of

some detailed, site-specific field evaluations of vapor releases being conducted by the New Hampshire

Department of Environmental Services (NH DEP). NHDES is also in

the process of amending its UST regulations, including emphasizing the

reduction potential problems from

vapor releases. Presentations on this

topic have been made at recent

national conferences. 

These articles appear to reflect a

perception that is gaining increasing

acceptance—that while we have been

successful in greatly reducing the likelihood of liquid releases from USTs

(and very importantly, greatly reducing the mass of the release), vapor

releases into the tank pit might also

contribute to groundwater impacts in

some situations. Clearly, there are a

number of case studies that would

suggest this mechanism is real. 

November 2004 • LUSTLine Bulletin 48

Honey, We Shrunk the Leaks 

Thoughts on Those Small-Time Vapor Releases

by Bruce Bauman

23

■ continued on page 24

prioritize repairs, and confirm

source-elimination results. The results of this effort provide a point in

time in the chronology of LUST-site

data, APC data, and UST data. If

known VOC emissions are eliminated and a substantial reduction of

MtBE concentrations in groundwater

results, the certainty of concluding a

UPVR existed has increased validity. 

The current analysis of UPVR

assessment results and recommended repairs indicate a correlation

with groundwater MtBE concentration reductions. Ongoing maintenance of tank-top features can result

in a reduction of chronic VOC emissions at tank-top features and a

reduction of MtBE concentrations in

groundwater. But as I stated in the

opening paragraphs, the topic is still

in its infancy, and more knowledge is

needed to nurture a greater understanding of the potential impacts,

investigative tools, and remedial

solutions in UPVR scenarios. 

I hope the framework of specific

elements and techniques presented

reinforces our information base when

determining if UPVRs are a suspected source of petroleum contamination at a facility. Each small step

taken to further understand the topic

will promote greater certainty that

UPVRs are a threat to human health

and the environment and lead to a

greater degree of pollution prevention and resource conservation. ■

Andrew Shively is an UST Inspector

with the Vermont Dept of Environmental Conservation. He can be reached at

andy.shively@anr.state.vt.us.

What is not clear, however, is

how prevalent vapor release problems might be. For example: What

percentage of existing USTs might

have vapor releases? What is the

nature of those releases (e.g., the

mass of vapor expelled, the composition of the vapor, reformulated gasolines versus conventional gasolines)?

What are the potential groundwater

quality impacts of those types of

releases under different environmental conditions (e.g., type of backfill

and native soils, depth to groundwater)? 

While there are interesting observations regarding vapor releases in a

handful of sites in a few states, I’m

not certain that we are currently able

to routinely differentiate groundwater impacts that are caused only by

vapors (versus impacts that may be

caused by a combination of other

known potential “small release”

sources that may occur from various

parts of the UST system) from operation and maintenance practices, or

even consumer-related releases. 

Will the Real Source Please...

I think most LUST investigators

would agree that it is frequently very

difficult to determine the specific
source or sources of gasoline that

have triggered the need for corrective

action at a site. As all the “causes of

leaks” studies show, there are multiple potential sources from various

components of UST systems. Those

studies also indicate that sometimes,

small releases of gasoline (e.g.,

weeps, drips, overfills) may occur at

dispensers, in sumps, or other locations. It’s also known that there can

be routine, small (or less frequently,

relatively large) surface releases from

consumers filling their vehicles or gas

cans. 

Individually and collectively,

those small releases may elude the

capability of the release detection

technologies routinely employed to

meet regulatory requirements. We

need to keep in mind that all of these

other potential sources cannot be

ignored in any holistic assessment of

how small releases might impact

groundwater quality. But, as our

time/space continuum does not

allow a discussion of the broad topic

of all the types of small releases here,

we’ll mainly focus on vapor releases. 

While some of the current vapor

studies may be able to make some

initial estimates regarding the concentrations of vapors that might be

released from various parts of an

UST system, it is more difficult to get

a handle on the mass of vapor discharged from the tank and how those

discharges might vary over time. It is

even more difficult to estimate how

much of that vapor (and which vapor

components) might actually get

transferred to the water table. 

Wanted Soon: More Data

It can be expected that biodegradation would play a very significant

role in potential attenuation of

vapors during vadose zone transport

or at the water table. For example, a

2002 lab study documented the cometabolic biodegradation of MtBE

and pentane vapors—pentane is

found in high concentrations in gasoline vapors (Dupasquier et al., 2002). 

In one of the most informative

research articles published on this

topic of small releases, Swiss

researchers (Pasteris et al, 2002)

found that while gasoline vapors

(specifically, MtBE) from a small

NAPL release in a lysimeter would

migrate to a shallow water table (< 2

m from their emplaced source), less

than 1 percent of the mass of the

MtBE ended up in the water. This

was sufficient to cause a high concentration of MtBE at the water table

(over 3 ppm) but represented a very

small mass. Most MtBE was

volatilized, and some was biodegraded. No petroleum hydrocarbon

compounds were detected in

groundwater in that study, primarily

because of biodegradation. 

A follow-up study (Dakhel et al.,

2003), using different hydrological

conditions and a gasoline with both

MtBE and ethanol, showed much

more MtBE transport to the water

table, perhaps because of reduced

biodegradation owing to the presence of ethanol and reduced volatile

losses. While these two studies are

very helpful in identifying key

processes regarding small releases,

they have their limitations, and further lab and fieldwork will be

required to fill out our knowledge

base. 

To better understand the potential water quality effects of vapor

releases, it would be very useful if we

had good data from a number of UST

sites that would indicate how much

of the vapor that may escape actually

ends up at the water table, versus

how much is volatilized to the atmosphere or biodegraded. Clearly, that

will be affected by a number of sitespecific properties, such as the “size,”

intensity, and duration of the vapor

releases, the type of backfill and

native soils, the type of paving over

the UST, the depth to groundwater,

and possibly factors like the presence

or absence of previous releases at that

site. 

Given our limited knowledge of

the nature of groundwater quality

impacts from vapor releases, proper

care should be exercised in

estimating how vapors may have

contributed to groundwater contamination at any existing UST facility.

For example, in a recent incident in

Maryland, a number of private drinking water wells around a UST facility

were found to have MtBE. (See

related article on page 34.) Because

the tanks at that facility tested tight,

and because an extensive evaluation

of possible sources indicated there

may have been some sources of

vapor losses, there have been some

presumptions that vapor problems

are the primary source. 

From my limited understanding

of that specific site, at this point in

time I’m a little skeptical that vapor

releases have been the only source of

the groundwater problems. I would

not discount that they may have contributed to some fraction of the overall groundwater impacts, but it is far

from clear that they are the sole

source of contamination.

The Work at Hand

Concerns about vapor and other

small releases have prompted the

Maryland Department of Environment to begin accelerated development of new UST regulations.

Hopefully those regulations will not

be rushed. We need to take the time

to allow our current, limited understanding of small releases to be

expanded sufficiently to ensure that

cost-effective, flexible approaches to

this complex problem can be crafted. 

We should also learn a good bit

more about the characteristics of the

soluble plumes that can be created

from small releases and how they

may differ from plumes created by

large NAPL releases. Modeling

research by the American Petroleum

Institute and others suggests that the

contaminant mass flux (see LUSTLine

#46, “Flux Redux,” or Einarson and

Mackay, 2002)) associated with

plumes from small releases will be

much less likely to impact offsite

drinking water wells than plumes

from larger releases (even though

both may have similar concentrations

of dissolved components in the

source area). 

As the authors of the various

LUSTLine articles on this topic have

indicated, there is still a lot of work to

24

LUSTLine Bulletin 48 • November 2004

■ Small-Time Vapor Releases

from page 23

While it will always be our goal to

minimize the frequency and amount

of all UST releases, it will be very

important at this time for all of us to

better understand the prevalence

and significance of these kinds of

small releases.
an UST system that could be considered highly unlikely to result

in any significant or long-lasting

degradation of groundwater

quality? 

• What do we know about the

characteristics of plumes caused

by small releases that might

influence the kind of corrective

action required? 

• What routine UST maintenance

and groundwater monitoring

practices would be the most

helpful in preventing problems

or minimizing problems, should

they arise, and might such

approaches provide an equivalent level of environmental protection as new release detection/

prevention technologies?

What Is “Vapor-Tight”?

In his remarks at a recent technical

conference, U.S. EPA Office of

Underground Storage Tank Director

Cliff Rothenstein stated that regarding vapor releases, “We need to get to

the bottom of this. We need to find

out the source of the problem and...

make sure systems are both liquidand vapor-tight.” This is an

admirable performance goal for UST

systems, but the key issue will be to

determine an acceptable definition of

“vapor tight.” 

A closely related question was

addressed in LUSTLine #47 (“The

Limits of Leak Detection”), where

author Marcel Moreau noted the ability of certain technologies to detect

“phenomenally” small releases. He

wondered if there was a practical

environmental benefit, asking “Can

leak detection be carried too far?”

That is a question that must also be

asked about vapor releases. Is there

some threshold level of vapor release

that might be regarded as unlikely to

cause groundwater problems? 

It will take some concerted effort

by all parties, probably over the next

year or two, to get a sufficiently comprehensive understanding about the

nature and potential impacts of small

releases/vapor releases. Then we

must development management

options that will provide efficient

and cost-effective approaches that are

commensurate with the level of

health and environmental protection

we wish to achieve. I would expect

that like other aspects of the UST program, individual states will tailor

their response to the nature of the

problem as it is characterized in their

state. We’ve made a very good start

toward figuring out this problem,

and I’m confident that it won’t be too

long before we will have come up

with a handful of good solutions. ■

Bruce Bauman, is Soil/Groundwater

Research Program Coordinator in the

Regulatory and Scientific Affairs

Department of the American Petroleum

Institute. He can be contacted at bauman@api.org. He gratefully acknowledges the helpful comments of a number

of reviewers of this article.

References 

Dakhel, N.; G. Pasteris, D. Werner, and P. Hohener,

2003, Small-volume releases of gasoline in the

vadose zone: impact of the additives MTBE and

ethanol on groundwater quality, Environmental &

Science Technology, 37(10); 2127-2133. 

Dupasquier, D., S. Revah, and R. Uria. 2002, Biofiltration of methyl tert-butyl ether vapors by cometabolism with pentane: modeling and experimental

approach, Environmental & Science Technology, 36

(2); 247-253. 

Einarson, M.D., and D.M. Mackay, 2001, Estimating

future impacts of groundwater contamination on

water supply wells, Environmental & Science Technology, 35 (3), pp. 66 A-73 A

Pasteris, G., D. Werner, K. Kaufmann, and P.

Hohener, 2002, Vapor phase transport and

biodegradation of volatile fuel compounds in the

unsaturated zone: a large scale lysimeter experiment, Environmental & Science Technology, 36 (1), 

30-39.

25

November 2004 • LUSTLine Bulletin 48

be done before we can truly obtain a

sufficient understanding of what’s

going on and when environmental

problems might arise from vapor or

other small releases. To recap, we all

probably agree that vapors can and

do escape from UST systems and

that, in some cases, those vapors can

impact groundwater quality near the

tank field. There also is likely consensus that vapors of the more soluble

and less biodegradable gasoline constituents would present a greater

likelihood of contributing to elevated

concentrations in groundwater. 

We have learned a good bit in the

last few years, and that knowledge

clearly indicates that this issue is

worthy of more investigation. But

before effective solutions can be

developed and implemented, we

have a lot of questions to answer,

including: 

• Can we reliably detect very small

releases? 

• How many existing UST sites

have similar problems with

vapor releases? 

• What are “typical” vapor-release

rates for the existing population

of UST systems? 

• Is there a de minimis rate of subsurface release of gasoline from

Information from API on Small Vapor Releases 

The American Petroleum Institute and its Soil/Groundwater Technical Task

Force have been actively investigating various topics associated with small

releases for several years, and they have ongoing projects that will also help

us better understand and manage this issue. Visit www.api.org/groundwater

to obtain more information or download some of the following reports: 

■ Simulation of Transport of Methyl Tert-Butyl Ether (MTBE) to Groundwater from Small-Volume Releases of Gasoline in the Vadose Zone,

Bulletin No. 10, http://api-ep.api.org/filelibrary/bulletin10.pdf, June 2000

■ Evaluation of Small-Volume Releases of Ethanol-Blended Gasoline at UST

Sites, Bulletin No. 19, http://api-ec.api.org//filelibrary/19_Bull.pdf,

October 2003

■ Evaluation of Potential Vapor Transport to Indoor Air Associated With

Small-Volume Releases of Oxygenated Gasoline in the Vadose Zone,

Bulletin No. 21, December 2004

■ Maximum Potential Impacts of Tertiary Butyl Alcohol (TBA) on Groundwater From Small-Volume Releases of Ethanol-Blended Gasoline in the

Vadose Zone, Bulletin No. 22, December 2004

■ Maximum Potential Impacts of Tertiary Butyl Alcohol (TBA) on Groundwater From Small-Volume Releases of MTBE-Blended Gasoline in the

Vadose Zone (in progress)
tion on any leaking spill buckets that

were encountered, it became a simple

matter of counting the number of

tanks with leaking spill buckets and

dividing by the total number of tanks

with spill buckets to get a percentage. 

What I Found

Of the 910 tanks in the sample, 76, or

8.4 percent, had leaking spill buckets.

Assuming this population was representative for the state, I applied the

8.4 percent to the entire population of

tanks in the state and arrived at the

conclusion that an estimated 1,032

spill buckets are currently leaking

statewide. This means that there are

1,032 potential releases that will have

to be reported and investigated.

Some of these investigations will

undoubtedly result in the discovery

of contamination requiring remediation. Since it appears likely that this

problem will worsen over time as the

buckets age and continue to degrade,

I anticipate we will discover more of

these leaks in the future. 

What I Learned

Once I identified the problem, I

searched for possible causes. The

answer was surprising—spill buckets

26

LUSTLine Bulletin 48 • November 2004

Spill Buckets: Mistaken Expectations?

by Dale W. Stoudemire

“Spill prevention equipment that will prevent the release of product to the environment when the transfer hose is detached from the

fill pipe (e.g., a spill catchment basin).” This is the extent of federal guidance for spill prevention equipment that most of us who regulate underground storage tanks were given—many state statutes also reflect this guidance. The concept of a spill catchment basin or

bucket is simple, and several designs on the market fit the concept

exactly, so you might think this was the only guidance we needed.

Well, surprise, it has become increasingly apparent that we had the

mistaken expectation that these buckets would continue to function

with little cost or maintenance for the life of the tank system. 

Hints of a Problem

In South Carolina, our first hints of a

problem showed up as we investigated a possible subsequent release at

a site already undergoing cleanup.

Monitoring reports showed unexplained increases in contaminant levels, but tank and piping tightness

tests indicated that the systems were

tight. In the absence of compelling

evidence, we initially attributed these

increases to errors in the baseline contaminant estimations. 

After several quarters of problems, we began to look for other possible sources for the contamination.

In one instance, we found that a seal

in a spill bucket had moved out of

position, allowing product to leak out

every time fuel was leaked from the

hose into the spill bucket. This displaced gasket was our first discovery

of what threatens to become a large

and costly situation.

As our inspectors began to see

more spill buckets that had various

problems, beginning in mid-2003 our

program began to focus on spillbucket integrity during routine

inspections. If the condition of a

bucket appeared suspicious, the

inspector would pour a small amount

of water into the bucket and observe

the level for several minutes. If the

water level dropped, we assumed the

water was leaking from the bucket

into the environment. If the leak was

later found to be the result of a leaking

drain that fed back into the tank, the

bucket was not counted as leaking. 

Questions have been asked about

this protocol. This “test” was not

designed as part of a controlled study.

The inspectors were not attempting to

measure the performance of the population of spill buckets. Rather, they

were deciding whether a situation

encountered at an inspection needed

further investigation. 

The question

of disposal of the

test water has also

been raised. We do

not pour water into

every bucket that

we inspect. The

inspector only tests

a bucket if he or

she is reasonably

certain that it has a

problem. Disposal

of the water has

not been an issue,

because almost

every bucket tested

with water turned out to be leaking,

and the water drained out through

the existing hole. Considering that

the holes in the buckets have already

been releasing pure petroleum, the

small amount of water is not considered a significant problem. 

During this same time period, we

also began to find buckets with

severe problems that had developed

since the last annual inspection. We

began to see more displaced gaskets

and large cracks or splits in the buckets, usually in the flexible bellows. In

response to these findings, I decided

to examine the data for trends.

The Study

Even though the data were collected

for routine inspections and not as a

part of a controlled test, examining it

provided useful information. Our

database tracks the inspections and

any violations that we encounter. We

conduct about 4,000 inspections

annually, so a direct examination of

each inspection was not practical. I

looked at the results of 12 months of

inspections in a selected region—a

total of 910 tanks at 337 locations. 

Since the records for each of

these inspections contained informaA spill bucket with a large horizontal split in the plastic bellows. The

brown spot below the tip of the screwdriver is the soil beneath 

the bucket.
are not designed to last for the life of

the tank system. Many spill buckets

are made from high-density polyethelene (HDPE) or have HDPE components. As we have learned from

experience with flexible piping,

HDPE can degrade from long-term

contact with petroleum. 

According to a representative for

a major manufacturer, many spill

buckets installed for the 1998

upgrade requirement are approaching the end of their useful lives. In

defense of the manufacturers, I must

say that I was never told the spill

buckets were designed to last; I only

assumed it. The representatives I

spoke with have been very forthcoming about the performance of their

products. The mistake was not in the

claims for the performance of the

buckets. Rather, it was in my

assumptions about them. Unfortunately, I suspect that many tank owners and regulators share my

assumptions.

What to Do

There are several things that tank

owners can do to lengthen the life of

their spill buckets:

• Check spill buckets after every

delivery to ensure that spilled

fuel is removed immediately. As

many of us have seen, spill buckets are not always thoroughly

cleaned after catching small

petroleum spills. In addition, the

buckets often contain sand, dirt,

or debris. According to the manufacturers, this material, if left in

the bucket, will significantly

shorten the life of the bucket.

Water and debris of any kind

should be removed from the

bucket weekly. 

• Replace cracked or broken

spill-bucket lids immediately. 

• Check clamps and seals regularly, and tighten, adjust, or

replace as needed. Although I

have not yet discovered the exact

cause for it, exposure to fuel

seems to cause the seal on some

models to become displaced.

Regular inspection and maintenance should detect this problem

early and help prevent any possible releases. 

• Be prepared to replace spill

buckets periodically, and budget accordingly. If buckets

installed in 1998 are nearing the

end of their useful lives, then a

six-year replacement cycle might

be a workable planning guide. I

learned that, in South Carolina,

the cost of replacing a spill

bucket is around $1,500. On a

four-tank installation, the owner

will need to plan on budgeting

about $6,000 for replacement. On

a six-year replacement cycle, at

an average cost of $1,000 per

year, spill-bucket maintenance

could cost more than some owners spend annually on release

detection. 

All of these suggestions are for

the short term. A long-term solution

is for tank owners to insist on spillbucket designs that correct these

problems. They should use their buying power to encourage manufacturers to select more durable plastics or

corrosion-resistant metals that will

last for a more reasonable period of

time. Current designs could also be

modified so an easy and less expensive replacement cycle could be

implemented. 

Pay Attention

Many tank owners and regulators

have assumed that spill buckets are

relatively maintenance free and will

last for the life of the tank system. It

turns out that this assumption was

wrong. Spill buckets appear to have a

much shorter life span than some

other tank-system components, so

regular maintenance is required to

extend bucket life, and owners

should plan for regular replacement.

As regulators, we must emphasize

the condition and functionality of the

spill bucket, not just verify that one

has been installed. ■

Dale Stoudemire is an Environmental/Health Manager with the South

Carolina Department of Health and

Environmental Control’s Underground

Storage Tank Program. He oversees six

field inspectors and is a main point of

contact for the program. He can be

reached at stoudedw@dhec.sc.gov.

27

November 2004 • LUSTLine Bulletin 48

A spill bucket with a

vertical split. The

screwdriver is touching the soil beneath

the bucket.

A completely deteriorated spill bucket.

More than half of the

bottom is missing.

The lid was in place,

so it is not clear how

the leaves got into

the bucket.
systems, this discussion will be limited to the testing of sti-P3 tanks. To

help the reader better understand the

seemingly mystical science of cathodic

protection, I’ll also discuss factors that

influence CP testing.

Reference Cell Placement

While it is important to realize that

many factors must be considered

when testing the structure-to-soil

potential of a cathodically protected

tank, reference cell placement is of

critical importance. The basic idea is

that the reference cell must be placed

where it can “see” the tank. The concept is analogous to a flashlight

beam—if the reference cell is placed

directly over the tank, the portion of

the tank that lies within the imagined

flashlight beam is the area of the average potential (voltage) measurement. 

The commonly accepted best

practice is to place the reference cell

in the soil directly over the centerline

of the tank being tested and as far

away from any anodes as is practical

(Moreau, 1999). Measurement of the

cathodic protection with the reference cell placed directly above the

tank is referred to as the “close,” or

more commonly, “local” potential.

While it is desirable to provide

dedicated access ports or test stations, practical considerations usually

dictate that the reference cell is

placed wherever soil access is available above the tank. This means that

the reference cell is usually placed

within the submersible-pump manway or some other existing opening

through the pavement. 

It is critically important that the

reference cell be placed in the soil

and never on top of the concrete or

asphalt when measuring the tank

potential (NACE, 2001). If there is no

access to the soil, holes must be

drilled through the pavement in

order to conduct a valid test. Testing

with the reference cell placed on the

pavement will usually introduce significant errors.

Unfortunately, the commonly

accepted best practice is not always

followed by CP testers, and the reference cell is more typically placed

practically anywhere that will yield

the desired result (a “pass” or a

“fail,” depending on the objectives of

the person conducting the test).

Given this “anything goes” scenario,

reference cell placement has ranged

from the soil over the tank to the

flower bed across the parking lot to

the drainage ditch behind the store

building and everywhere in between.

28

LUSTLine Bulletin 48 • November 2004

Should Remote-Earth Testing of Galvanic

Cathodic Protection Systems Be Required?

by Kevin Henderson

Testing of underground storage

tank UST cathodic protection

(CP) systems has historically

been one of the more problematic

aspects of UST regulation. Industry

standards provide a great deal of latitude with respect to exactly how CP

testing is to be conducted. In addition, very little is prescribed relating

to adequate documentation of such

testing. Therefore, it can be difficult

for regulators to evaluate whether or

not testing and the resultant documentation is sufficient to indicate

compliance with UST rules and regulations. More importantly, the adequacy of the CP system to effectively

mitigate the potential for a corrosion

failure of the UST system may be in

question. 

In an effort to improve this situation, the Mississippi Department of

Environmental Quality (MDEQ)

developed a guidance document

titled “Guidelines for the Evaluation

of Underground Storage Tank

Cathodic Protection Systems”

(MDEQ, 2002). This guidance document is intended to foster a more uniform approach for not only how CP

testing is conducted but also what

criteria are necessary in order to

“pass” the test. In addition, specific

forms must be completed that provide documentation on exactly how

the test was conducted so it can be

reproduced and a means for effectively evaluating the methodology/

results of the test.

One requirement of the MDEQ

policy that is relatively unfamiliar to

many practitioners is the testing of

galvanic CP systems with the reference cell placed far away from the

tanks being tested. Measuring CP

with the reference cell placed some

distance away from the tanks is commonly referred to as “remote” or

“remote-earth” potential. In this article, I’ll discuss remote-earth testing—

what it is, its significance, and why

you should consider incorporating

this practice when evaluating galvanic

CP systems. Although remote-earth

testing is applicable to all galvanic CP
Local Reference Cell

Placement

When obtaining the local potential,

only a relatively small portion of the

top of the tank is measured. Therefore, it has become common practice

to place the reference cell at three

points along the top of the tank (each

end and the middle) in an effort to

measure as much of the tank as possible (Moreau, 1999). Because local

measurements look at specific areas

of the tank, an area that is not receiving adequate cathodic protection

may be identified. However, since

only the top portion of the tank is

measured, local potentials tell you

nothing about the degree of cathodic

protection along the bottom half of

the tank. 

Portions of the tank other than

the top may be evaluated by conducting potential profiling, which

involves the drilling of holes in close

proximity to the tank so that the reference cell may be placed at various

depths, allowing measurement of the

potential from ground level to below

the bottom of the tank (NACE, 2002).

Unfortunately, it is not usually practical to perform potential profiling

since drilling is required and few

tank facilities have such an arrangement of test holes installed.

Permanent reference cells buried

at the time the tank is installed may

allow you to measure the tank potential at locations other than the top of

the tank. However, in order to interpret the test results properly, it is critical that the exact depth and

orientation of the permanent reference cell relative to the tank is carefully documented. Although a

number of sti-P3 tanks were installed

with permanent reference cells (PP4

test stations), the exact burial location

of the reference cell was often not

adequately documented. 

If the location of the reference cell

is not known with a high degree of

certainty, such potential measurements are of little value, since the cell

could have been buried in close proximity to one of the tank anodes. If the

reference cell is in close proximity to

an anode, the structure-to-soil potential measurement is likely to be

higher (more negative) than it really

should be because the measurement

will be influenced by the voltage gradient of the active anode, (See the

“raised-earth” discussion below.)

Although only the top of the tank

is usually tested, conventional wisdom is that it is reasonable to assume

that the top portion of the tank would

be the most difficult to protect with

sti-P3 tanks since this area is farthest

away from the anodes. While this is a

logical assumption, it may be prudent to keep in mind that most corrosion failures seem to occur along the

bottom of the tank. One of the reasons that the factory-installed anodes

are attached near the bottom of sti-P3

tanks is to help protect the more susceptible tank bottom.

Determining “True” Local

Potential

Factors that complicate our ability to

obtain accurate (“true”) local potentials must be considered when evaluating the significance of such

measurements. Local potentials may

be subject to interference or “shielding” from various sources at a typical

tank facility (Peabody, 2001). Shielding prevents or otherwise interferes

with the current reaching the reference cell as it normally would if there

were no interference. In the absence

of other readily apparent explanations, shielding is commonly cited as

the reason for substandard CP readings when the reference cell is placed

locally (STI, 2001a). 

Given that there may be numerous “foreign” metallic structures present (e.g. the submersible pump

head, metallic product piping, electrical conduits, tank risers), it seems

reasonable that these structures could

interfere with obtaining local potentials. However, there are differing

opinions regarding the validity of the

concept of reference-cell shielding

caused by electrically isolated tank

appurtenances. Accordingly, caution

should be exercised whenever shielding is cited as the cause of substandard cathodic protection readings.

Further testing or evaluation may be

necessary by a person qualified as a

“corrosion expert” to better determine the “true” cathodic protection

status of the tank.

In addition to shielding, local

potentials may also be influenced by

the effect of “raised earth,” a term

used to describe the voltage gradient

that is present in the soil near an

active anode (NACE, 2001). If there

are active anodes in proximity to the

reference cell, the potential measured

on the protected structure will

appear to be higher (more negative)

than it actually is. The potential will

appear erroneously high (more negative), since the measurement includes

the voltage drop induced by the voltage gradient of the active anode.

Because of the raised-earth effect it is

possible for the tank to appear well

protected when it may, in fact, not be

protected at all. 

While not typically a significant

concern on well-coated tanks that

have only factory-attached zinc

anodes, raised earth can have a substantial effect on those tanks that

have had magnesium anodes retrofitted or buried nearby. It is not uncommon to have magnesium anodes

buried within the submersibleturbine manway in an effort to protect metallic piping. In these cases,

the reference cell must not be placed

within the submersible turbine manway. 

If the structure-to-soil potential

of the tank is measured at the submersible-pump manway, the observed potential will be higher (more

negative) than it really is since it will

include the voltage drop caused by

the current output of the magnesium

anode. Depending on the soil resistivity and the amount of current produced by the anodes, it may not be

possible to place the reference cell

locally such that the observed potential is not influenced by the voltage

gradient of an active anode.

Other metallic structures commonly found in the tank environment described above that can have

an influence on the observed potential include the galvanized skirts present on most manways. Although the

29

November 2004 • LUSTLine Bulletin 48

■ continued on page 30

While it is important to realize that

many factors must be considered

when testing the structure-to-soil

potential of a cathodically protected

tank, reference cell placement is of

critical importance. The basic idea

is that the reference cell must be

placed where it can “see” the tank.
voltage drop produced by these

skirts is not as

pronounced as

with magnesium

anodes, the zinc

coating of the galvanized skirt may

also cause the

observed tank

potential to be

higher (more negative) than it actually is. The

magnitude of the

error that will be

caused by this

voltage drop depends largely on the

proximity of the reference cell to the

skirt and the condition of the galvanized metal. Figure 1 is a field example of a series of measurements made

within the submersible-turbinepump manway of a sti-P3 tank. The

tank in this example has substandard

CP that continuity testing indicates is

caused by a short between the tank

and the fill riser.

The manway in this example is

filled nearly to grade with sand backfill, a common practice when containment sumps are not present. The

manway is a typical 2’ x 2’ steel manway with a 10 inch galvanized steel

skirt. A potential measurement of

–730 mV was observed with the reference cell placed at grade level in the

soil within the manway. Grade level

in this example placed the tip of the

reference cell approximately 35“from

the top of the tank and 6 “ up inside

the metallic skirt (measurement point

P-1). The soil was then excavated

approximately 7” placing the tip of

the reference cell 1” below the bottom

of the manway skirt and a potential

of –658 mV was obtained (P-2). 

If the “true” potential of this tank

is –658 mV (the remote potential of

this tank was –656 mV), the galvanized skirt of the manway has apparently caused the tank potential to be

72 mV higher (more negative) than it

actually is.

As can also be seen from the data

in Figure 1, soil resistivity may also

influence the observed potential. If

you assume the “true” potential of

the tank as it would normally be

measured is –658 mV, it can be seen

that the voltage difference between

measurement points P-2 and P-7 is

103 mV. It is likely that this difference

is caused by the voltage drop present

in the soil column between the tank

and the reference cell. Although the

amount of error caused by this voltage drop is normally disregarded

because the –850 mV criterion is considered to compensate for this error

(Peabody, 2001), it is something to

keep in mind when evaluating test

data.

Another problem sometimes presented by soil resistivity characteristics can be seen in cases where a layer

of very high-resistivity soil is present

above the tank. Consider the case

where a tank is buried in sand backfill, but the top of the excavation is

filled to grade with pea gravel. In this

situation, it would be very difficult to

measure adequate CP with the reference cell placed on

top of the backfill,

as it typically

would be when

obtaining the local

potential. The tank

would appear to be

completely unprotected when it

could actually be

very well protected

along the most susceptible (bottom)

portion of the tank.

Contact resistance between the

reference cell and

the tank backfill,

material is another factor that sometimes makes it difficult to obtain

accurate local potentials. Although

contact resistance is normally compensated for by the use of voltmeters

with very high (10 megohm or

greater) input resistance, it can be

troublesome when the backfill material is very dry or is of crushed

stone/pea gravel composition. Water

is usually added to the soil at the

point of contact with the reference

cell in an effort to minimize contact

resistance. Additionally, petroleumcontaminated or frozen soils can

cause a high contact r esistance and

should be avoided whenever testing

CP (Moreau, 1996).

Local Variability

A rather large degree of variability is

seemingly inherent in local potentials

even when there are no apparent reasons for it. It is not uncommon to

30

LUSTLine Bulletin 48 • November 2004

Measurement Distance Observed 

Point Above Tank Potential

P - 1 35 inches –730 mV

P - 2 28 inches –658 mV

P - 3 24 inches –608 mV

P - 4 18 inches –600 mV

P - 5 12 inches –594 mV

P - 6 6 inches –580 mV

P - 7 1 inch –565 mV

Remote Earth = –656 mV

Potential Measurements Above the Tank Figure 1

Local Variability Figure 2

■ RemoteEarth Testing

from page 29
observe a substantial variation in the

potential just by moving the reference cell around a few inches this

way or that. Figure 2 depicts the test

data obtained by a MDEQ inspector

and illustrates very clearly the variability that can be seen when

attempting to measure the local

potential. The variation within the 2‘

x 2’ manway near the center of the

tank (where the automatic tank

gauge probe is installed) shows a

variation of 159 mV in the potential,

depending on where the reference

cell is placed within the manway. The

same variability can be seen within

the manway of the submersible-turbine pump, although here it is only

42 mV. All of these measurements

were made with the tip of the reference cell placed below the bottom of

the manway skirts in order to remove

any influence they may have.

Are these differences in the tank

potential real, or is this just an artifact

of measurement difficulties inherent

in the environment above the tank?

Are the readings being shielded by

metallic tank appurtenances in the

congested above-tank environment?

Is there an anode buried somewhere

within or near the manways that is

affecting the readings? Should the

test for this tank be declared a “fail”

since the potential at test point “E” is

–819 mV? Given that the reasons for

this variability are not well understood, can the remote-earth potential

help us decide what the most logical

answers to these questions should

be?

Remote Earth

Another way to measure the structure-to-soil potential is to place the

reference cell some distance away (or

remote) from the tank. By doing this,

the factors discussed above that can

make obtaining local potentials problematic may be mitigated. The structure-to-soil potential that is measured

at remote earth can be thought of as

representing the average potential of

the entire tank shell. Remote earth is

achieved when the structure-to-soil

potential of a buried metallic structure remains constant, irrespective of

how far away or in what direction the

reference cell is placed. 

It is generally accepted that the

reference cell must be at least 25–30

feet away from a sti-P3 tank in order

to achieve a remote-earth condition

(STI, 2000). Under normal conditions,

this distance is sufficient to place the

reference cell outside the area of

influence generated by the voltage

gradient of an active anode. Since a

volume of soil has a finite resistance

(STI, 2000), the potential will remain

essentially the same no matter how

far away or in what direction the reference cell is placed once remote

earth has been achieved.

Placing the reference cell

remotely accomplishes several

things, including: 

• Minimizing the raised-earth

effect voltage gradients of active

anodes may impart on the

observed potential. 

• Minimizing the “shielding”

effect tank-top appurtenances

may have on the observed potential.

• Mitigating the error imparted by

high-contact resistance between

the reference cell and the tank

backfill materials.

• Providing the average potential

over the entire tank, the only

practical way to “see” the bottom

of the tank.

• All things being equal, making

the test results generally more

reproducible than those obtained

with the reference cell placed

locally. This is because it is usually not known exactly where the

reference cell was placed to

obtain the local potential and, as

long as remote earth has been

established, it does not matter

where the reference cell is placed

to obtain the remote potential.

Determining “True” Remote

Earth

An important aspect of remote placement is the need to establish that a

“true” remote-earth condition has

been achieved. In the simplest scenario, remote earth is established by

placing the reference cell in the soil a

certain distance away from the protected structure and measuring the

potential. The reference cell is then

moved out away from the protected

structure an additional ten feet, and

the potential is again measured. This

process is repeated until there is no

appreciable difference between two

potential measurements. When there

is no difference between the two

potentials, it can be assumed that

remote earth has been achieved.

Factors that can complicate the

establishment of true remote earth

must also be considered when

attempting to measure the remote

potential. For example:

• The reference cell should not be

placed in proximity to any other

cathodically protected structures,

such as natural gas pipelines. 

• Chain-link fencing, commonly

found at UST facilities, is galvanized, and the reference cell must

not be placed near it since the

raised earth produced by the zinc

in the galvanized coating can

influence the observed potential. 

• Since any buried metallic structures (e.g., water lines, electrical

conduits, other utilities) can

influence the remote potential,

the reference cell must also not

be placed over these structures

(Peabody, 2001). 

• It is better if any buried metallic

structures are not between the

reference cell and the protected

structure, although this is generally not a significant factor.

Given that there is usually limited access to soil at locations that are

remote from the tank, and there are

other buried structures to contend

with, it is often necessary to move the

reference cell to several different

locations around the facility and at

varying distances away from the tank

before it can be comfortably established that remote earth has been

achieved. Only when the potential is

essentially the same at two or more

locations that are remote from the

tank can it be assumed that remote

earth has been achieved.

Remote vs. Local

Placing the reference cell remotely

measures the average potential of the

entire tank. Placing the reference cell

locally measures the average potential of a small area on the top of the

tank. Although local measurements

can give you information about a

specific area of the tank, it is sometimes problematic to be sure that the

local measurement is representative,

31

November 2004 • LUSTLine Bulletin 48

■ continued on page 32
and it may be difficult to reproduce

the test results. With remote measurements, it is normally easier to

mitigate environmental influences

and to reproduce the test results. The

ability of a person to reproduce the

results that someone else obtained

during a previous test is a very

important and desirable aspect of CP

testing.

Remote measurements do not tell

you anything about a specific area of

the tank, and it is possible to have an

area of the tank that is not protected

and still have a “passing” remote

potential. Similarly, local potentials

(measured at the top of the tank) do

not tell you anything about the lower

portion of the tank, and it is possible

to have an area of the tank that is not

protected and still have a “passing”

local potential.

Referring back to Figure 2, can

the remote-earth potential help us

decide which potential best represents the “true” local potential? Considering that the remote potential of

the tank in Figure 2 is 972 mV and all

of the local measurements (except

test point “E”) are well above –900

mV, it would seem reasonable to conclude that the –819 mV potential

observed at point “E” is not representative and should probably be disregarded. The remote potential can

sometimes help you decide what is

the most representative local potential in those cases where it is not

clearly evident.

MDEQ Testing Requirements

In the State of Mississippi, the reference cell must be placed both locally

and remotely when conducting a test

of a galvanic CP system. In order for

the test to “pass,” both the local and

the remote potential must be –850mV

or higher (more negative). The test

result is declared a “fail” if both the

local and the remote are lower (more

positive) than –850 mV. If one of the

potentials is –850 mV or higher but

the other is not, the test is considered

to be “inconclusive.” (See Table 1.)

With inconclusive results, the CP system must be modified/ repaired or

evaluated by a “corrosion expert,”

who may evaluate the data or conduct further testing in order to

declare either a pass or fail of the test.

When obtaining the local potential, the reference cell can be placed

anywhere along the centerline of the

tank but not directly over the ends.

Since the remote potential is also

required, it was decided that only

one local measurement of the potential directly over the tank would be

required. Ideally, if only one local

potential is measured, it should be

obtained from the center of the tank.

If the anodes located at both ends of

the tank are functioning, the center of

the tank should have the lowest

potential, since

this is the area of

the tank that

would be the farthest away from

the anodes. 

With only one

local measurement, it is possible

that the anodes

could be completely depleted

on one end of the

tank and this condition would not

be recognized.

While possible, it

seems reasonable that such a condition would usually be recognized

when the MDEQ testing guidelines

are followed, since the remote potential would likely be too low and the

test result would be inconclusive.

MDEQ Findings

From July 2002 through March 2004,

MDEQ inspectors measured the CP

on 1,037 sti-P3 tanks as part of

routine compliance inspections.

Structure-to-soil potential measurements were obtained both locally and

remotely on all of the tanks that were

included in the data set for this study.

The tanks measured ranged in size

from 500 to 20,000 gallons and were

installed from 1985 through 2002. No

attempt was made to identify tanks

that had been retrofitted with supplemental anodes at the time the testing

was conducted.

The results of the testing

revealed that 83 percent of the tanks

fully passed the evaluation. Of the

tanks that did not pass the evaluation, 12 percent failed and 5 percent

were inconclusive. (See Figure 3.)

This means that in only 5 percent of

the cases was there any discrepancy

between the local and the remote

potential with respect to the pass/fail

status of the tanks. Of the tanks that

were inconclusive, 53 percent passed

the remote but failed the local and 

47 percent failed the remote while

passing the local.

The MDEQ testing data indicate

that the remote potential is just as

likely to indicate a “fail” as it is a

“pass” when there is a discrepancy

between the local and the remote

potentials of sti-P3 tanks. In only 3

percent of the cases where there is a

discrepancy between the local and

the remote does the remote indicate

that the tank is protected when the

local does not.

In comparing the local to the

remote potential (without considering the pass/fail status), the local was

essentially the same as the remote for

15 percent of the tanks. (See Figure 4.)

The local was found to be higher

(more negative) than the remote 42

percent of the time. While there are a

number of factors that could cause

32

LUSTLine Bulletin 48 • November 2004

■ Remote-Earth Testing 

from page 31

LOCAL POTENTIAL REMOTE POTENTIAL TEST RESULT

–850 mV or higher –850 mV or higher Pass

lower than –850 mV lower than –850 mV Fail

–850 mV or higher lower than –850 mV Inconclusive

lower than –850 mV –850 mV or higher Inconclusive

“Making the Call” TABLE 1

MDEQ Test Results Figure 3
this difference, the voltage gradient

caused by active anodes in the soil

near the tank (raised earth) is one

possible explanation. The local potential was found to be lower (more positive) than the remote potential on the

remaining 43 percent of the tanks. In

the absence of other readily apparent

reasons, shielding of the reference

cell in the congested above-tank environment is the most logical explanation for this difference.

When a difference is measured

between the local and the remote

potentials, how much is it? In the

cases where the local was higher

(more negative) than the remote, the

average difference between the two

was 80 mV. In cases where the local

potential was lower (more positive)

than the remote potential, the average difference was 79 mV. The

remote is just as likely to be lower

(more positive) as it is higher (more

negative) than the local is when measuring sti-P3 tanks

and that difference is +/–80 mV.

At the End of

the Day

Although this discussion has been

limited to sti-P3

tanks, remoteearth testing is

equally applicable

to most galvanic

(sacrificial anode)

CP systems. Of

the 1,037 tanks

tested by MDEQ,

the average local potential was –964

mV and the average remote potential

was –962 mV. While it sometimes

seems that the only thing certain with

CP is that there are no certainties, the

data would suggest that the remote

potential is a valuable tool. Given the

inherent advantages of measuring

remote potentials (see Table 2), it

would seem prudent to incorporate

remote-earth testing when evaluating

galvanic CP systems. 

In addition to Mississippi, the

states of Georgia, Kentucky, North

Carolina, and South Carolina also

have policies that require testing of

galvanic CP systems remotely. There

are several other states that are in the

process of adopting similar CP testing requirements. The Steel Tank

Institute describes the use of remote

earth testing for sti-P3 tanks (STI,

2001a). NACE International also recognizes that remote-earth placement

of the reference cell can be an acceptable alternative and is useful when

determining the significance of voltage drops (NACE, 2001).

While the data would suggest

that the remote-earth potential by

itself on a well-coated tank could be

reliable, we will continue to require

that both the remote and the local

potentials be measured. We believe

that each has its own distinct advantages/disadvantages. The remote

measurement tells you the overall

condition of the tank while the local

helps to identify specific areas of the

tank that may not be protected. Both

measurement techniques should be

utilized in conjunction with each

other in order to evaluate galvanic

cathodic protection systems in the

best manner possible. ■

Kevin S. Henderson, P.G., is Compliance and Enforcement Manager for the

Underground Storage Tank Branch,

Mississippi Department of Environmental Quality. He can be reached at

Kevin_Henderson@deq.state.ms.us.

To Learn About CP Basics: Check

out LUSTLine #23, “Rust Thou

Art and to Rust Thou Shalt

Return,” and LUSTLine #25, “Is

This Tank Cathodically

Protected?”

References

MDEQ, 2002, Guidelines for the evaluation of underground storage tank cathodic protection systems,

Mississippi Department of Environmental Quality,

Jackson, MS.

Moreau, Marcel, 1995, Testing cathodic protection

systems, LUSTLine Bulletin #25.

Moreau, Marcel, 1999, Combating CP-test heartburn,

LUSTLine Bulletin #32.

NACE, 2001, TM0101-2001, Standard test method,

measurement techniques related to criteria for

cathodic protection on underground or submerged

metallic tank systems”, NACE International, Houston, TX.

NACE, 2002, RP0285-2002, Standard Recommended

Practice, Corrosion control of underground atorage

rank aystems by xathodic protection”, NACE International, Houston, TX.

Peabody, A.W., 2001, Peabody’s xontrol of pipeline

corrosion, NACE International, Houston, TX

STI, 2000, Consideration of extraneous voltage cComponents in tank-to-soil potentials obtained for

cathodic protection monitoring of sti-P3 Tanks”,

Steel Tank Institute, Lake Zurich, IL.

STI, 2001a, TankTalk Newsletter, Vol. 16, Number 2,

Ask the expert – CP tests for sti-P3 Ttanks, Steel

Tank Institute, Lake Zurich, IL.

STI, 2001b, Recommended practice for the addition of

supplemental anodes to sti-P3 USTs”, Steel Tank

Institute, Lake Zurich, IL.

33

November 2004 • LUSTLine Bulletin 48

LOCAL REMOTE EARTH

Ease of obtaining (soil access) X X

Reproducibility (between different testers) X

Variability (no change if reference cell moved) X

Shielding (from tank appurtenances) X

Shielding (from other metallic structures) X

Raised earth (voltage gradient of anodes) X

Contact resistance (between cell & soil) X

Measures specific area of tank X

Measures entire tank X

Overall cathodic protection status of tank X

Advantages of Local/Remote Reference Cell Placement TABLE 2

Local vs. Remote Figure 4
34

LUSTLine Bulletin 48 • November 2004

The Brownfields Beat

Oakland, California USTfields Pilot Wins Phoenix Award 

The winners of the 2004 Phoenix Awards were announced on July 22, and

the City of Oakland/Habitat for Humanity housing project was a Community Impact Award winner. This is one of only three such community

awards nationwide. In all, 14 brownfields projects were honored for meeting the environmental challenge of transforming abandoned brownfields

into productive new uses. In Oakland, an old petroleum-contaminated gas

station was cleaned up, and four new single-family homes housing 13 people were built on the site. The project was the recipient of a 2000 USTfields

Pilot grant. Phoenix Award winners were formally recognized at the

Brownfields Conference in September. 

New Federal ATF Building to Stand on Old LUST Site in DC

An old LUST site undergoing remediation in the northeast section of the

District of Columbia is slated to become the new national headquarters of

the federal Bureau of Alcohol, Tobacco, Firearms, and Explosives (ATF).

Five USTs were removed from the site in 1991, and the presence of petroleum hydrocarbons and other contaminants was discovered over much of

the area. A remediation system is in place, and the DC UST program is

working with the U.S. Government Services Agency to clean up and prepare the site for construction. The building planned for the site will house

approximately 1,100 ATF personnel and is expected to open in 2005. ■

Shell Oil U.S./Motiva to

Phase Out MtBE in

Gasoline

S

hell Oil Products U.S. and

Motiva Enterprises, LLC are

working toward substantially

reducing and ultimately phasing out

the use of MtBE in the gasoline the

companies manufacture and sell in

the United States. Shell Oil Products

U.S. no longer manufactures or

blends MtBE into gasoline produced

at its four West Coast refineries, and

Motiva has decided to cease blending MtBE into products it manufactures at two terminals in Louisiana.

Combined, these two terminals distribute more than 430 million gallons

of gasoline per year. Also, in

response to Connecticut and New

York MtBE bans, Motiva constructed

and operates an ethanol import and

blending facility at its terminal in

Sewaren, New Jersey. 

The companies are looking for

other markets where they might be

able to phase out the use of MtBE in

their gasoline, consistent with federal

fuel requirements, state legislation

and regulation, market conditions,

and the gasoline distribution system

in that part of the country. The companies are responding to legislators

and regulators who are asking that

they remove MtBE from gasoline. To

date, more than 20 states have or are

considering a ban of MtBE. The companies say a complete phaseout will

only occur if there is a change in current regulatory requirements. ■

MtBE Problems Set the Stage

for New UST Regs in Maryland

Long

sleeve

shirt

two wacky designs

created by LUSTLine cartoonist, Hank Aho

two colors... red and black

two versions... long and short sleeve

Long sleeve $17.00

Short sleeve $13.00

Sizes: M, L, X, XXL

TO ORDER: Send check or money order (drawn on U.S. banks only) to: 

NEIWPCC Boott Mills South, 100 Foot of John Street, 

Lowell, MA 01852-1124

Tel: (978) 323-7929 • Fax: (978) 323-7919

Have you checked your tank today?

Front of shirt

LUSTLine T-Shirts

Back of shirt

Short sleeve

shirt

The NEW LUSTLine

Index—the long and

action-packed story of

USTs and LUSTs—is

ONLY available online. 

To download the 

LUSTLine Index, go to

www.neiwpcc.org/lustline.htm, and then click

on LUSTLine Index.

L.U.S.T.LINE INDEX August 1985/Bulletin #1 – November 2004/Bulletin #48

Over the last several years, the

Maryland the Department of

the Environment (MDE) has

seen an increase of groundwater

cases that involve MtBE. Since 1998

MDE has found that close to 600 private wells have been impacted with

MtBE at 5 ppb or higher across the

state. Public well impact data show

similar locational trends. The largest

impacts appear to be across the top of

the state in areas with fractured-rock

geology. These areas include Harford, Cecil, Carroll, Baltimore, and

Frederick Counties. 

Early on, MDE technical staff felt

that a contributor to the MtBE problem at these stations was the enriched

MtBE vapors being released into the

storage tank backfill from systems

that utilize Stage II vacuum-assist

vapor recovery under continuous

pressure.

In response to these events, the

governor has ordered MDE to write

emergency technical regulations that

will require early detection and better

containment of MtBE in UST systems

in the state’s High Risk Groundwater

Use Areas. All UST construction, containment, and leak detections regulations, to date, have focused on liquid

releases, not vapor. The revised regulations are in the review process and

are expected to be promulgated in

January. Further details can be found

on MDE’s Web site at: www.mde.

state.md.us. We’ll provide up-to-date

details in the next issue of

LUSTLine.■
ASTM Microbiology Work Group Seeks Data on 

FRP Deterioration

I was delighted to read Mr. Roggelin's LUSTLine #47 article, “Pipes and

Sumps—As I See Them,” on the biodeterioration of non-metallic piping. The

phenomena that Mr. Roggelin discusses are not limited to piping. Unfortunately, most industry stakeholders with direct knowledge of failed fiber reinforced plastic (FRP) UST features are restrained from sharing that knowledge

in open forums like LUSTLine. Mr. Roggelin was able to write a pithy article

shedding much-needed light on this underdiscussed problem. My hat is off to

him for a job well done. 

I also encourage industry stakeholders with photos and other specific

data about FRP biodeterioration to share it, either in LUSTLine or at ASTM

Subcommittee D.02.14 Fuel Microbiology Working Group meetings. We can't

solve industry problems or develop best practices for problem prevention as

long as the affected folks pretend that denial is an effective prevention tool.

The next ASTM D.02 meeting will be on December 5–9, 2004, in Tampa,

Florida. Guests are always welcome at these meetings. People can get meeting

details at ASTM's Web site: www.ASTM.org. Once at the Web site, click on

“Meetings,” “List of ASTM Future Meetings”, and “Next 12 Months,” then

scroll down to “D02 Petroleum Products.” ■

Frederick J. Passman, Ph.D.

Chair, ASTM D.02.14 Fuel Microbiology Working Group

New Jersey Initiates an

Enhanced Statewide UST

Compliance Inspection

Program 

I

n August, New Jersey Department

of Environmental Protection

(NJDEP) Commissioner Bradley

Campbell announced the start of a

new, enhanced statewide UST compliance inspection program. NJDEP

is establishing a group of 18 state and

county inspectors to conduct compliance inspections at each UST facility

once every three years. In past years,

state UST inspections were conducted

on the basis of complaints or referrals.

“Millions of New Jersey residents get

their drinking water from aquifers

that are vulnerable to pollution from

leaking tanks. New Jersey was long

overdue for a more effective leakprevention program for underground

tanks, but this has changed with the

state making new funding available,”

said Campbell. In 2003, New Jersey

voters overwhelmingly approved a

public referendum to provide NJDEP

a stable funding source for its UST

inspection program. The complete

news release can be seen at

http://www.nj.gov/dep/newsrel/2004/04_0096.htm. ■

35

November 2004 • LUSTLine Bulletin 48

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From Our Readers
L.U.S.T.LINE

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200

Guess What? With this issue of LUSTLine we are

launching a new section called “FAQs from the

NWGLDE” by the National Work Group on Leak

Detection Evaluation, an independent work group

comprised of 10 members—eight representing various

states and two from the U.S. EPA. The Work Group plans

to publish the answers to frequent questions they receive

from regulators and people in the industry on leak

detection. If you have questions for the group, please

contact them at questions@nwglde.org . (Please note: the

views expressed in this column represent those of the

work group and do not necessarily represent those of any

implementing agency.)

FYI, the mission of the NWGLDE is to:

■ Review leak detection system third-party evaluations

to determine if each evaluation was performed in

accordance with an acceptable leak-detection test

method protocol and ensure that the leak-detection

system meets EPA and/or other applicable regulatory performance standards

■ Review only draft and final leak-detection test

method protocols submitted to the work group by a

peer review committee to ensure they meet equivalency standards stated in the U.S. EPA standard test

procedures

■ Make the results of such reviews available to interested parties

Can ELLDs Be Used as a Line-Tightness Test Method?

Q. Companies such as Veeder-Root and INCON are

marketing their electronic line leak detectors

(ELLDs) to the regulated community as LineTightness Test Methods, in addition to meeting

the line leak-detector criteria. Under the specs for

each ELLD, the 11th edition, 2004, List Of Leak

Detection Evaluations For Storage Tank Systems

shows that a 0.1gph test is possible, but does not

specify its equivalence to a line-tightness test.

However, the NWGLDE listing for Line-Tightness Test Methods does not list any ELLDs as

being acceptable as a Line-Tightness Test Method

(pg. 13, 11th edition of the List). So, my questions

are: (1) Are there any ELLDs that can do a linetightness test? (2) If so, where can I find that list?

A. You are right, ELLDs are not listed by the

NWGLDE under Line-Tightness Test Methods.

However, many, but not all, of them were thirdparty tested at the 0.1gph leak rate under the

same range of environmental and pipeline configuration conditions that are used to test systems

that conduct monthly monitoring and line-tightness tests. The performance of the ELLD during

third-party testing is documented on the

NWGLDE List data sheet for the equipment. 

If the ELLD has sufficient performance characteristics, it can be used to satisfy the monthly monitoring test or annual line-test requirements. The

leak rate of 0.1gph is an equivalent leak rate at a

lesser pressure, since the ELLD does not typically

test the piping at one and one-half times the operating pressure. (See USEPA Standard Test Procedures for Evaluating Leak Detection Methods:

Pipeline Leak Detection Systems, September

1990.) The decision to accept or deny use of this

method remains with the implementing agency. 

You can identify ELLDs that have an acceptable

third-party result at a 0.1gph leak rate by looking

at the method summary page for Automatic Electronic Line Leak Detectors at 

http://www.nwglde.org/methods/automatic_electronic_lld.html . ■

FAQs from the NWGLDE 

...All you ever wanted to know about leak detection, but were afraid to ask.