New England Interstate
Water Pollution Control
Commission
www.neiwpcc.org/lustline
116 John Street
Lowell, Massachusetts
01852-1124
Bulletin 68
June 2011
LUS.T.UNE
A Report On Federal & State Programs To Control Leaking Underground Storage Tanks
The GISST of GoN
by Jennifer Pruett and Suzan Arfrnan
•^ T"ew Mexico is developing an excit-
l\l ing new Geographic Information
A. V System (GIS) tool with applications
to its inspection, remediation, and state
fund programs. In the face of decreasing
resources and increased demands, the state's
Petroleum Storage Tank Bureau is hopeful
that this new tool will allow it to better and
more effectively carry out all aspects of its
mission. It's called GoNM, which stands
for GISST (Geographic Information System
Screening Tool) of New Mexico, and this
article explains how it is being developed
and implemented, as well as the goals for
using it in the future.
Big State, Big Challenges
As the nation's fifth-largest state, New
Mexico has a substantial geographic
area with UST facilities scattered over
wide-ranging inspector territories.
The Bureau's Prevention/Inspection
Program currently has 10 inspectors,
down from 13 several years ago, in
eight field offices around the state. The program regulates
approximately 4,800 tanks (3,500 USTs and 1,300 ASTs) at
1,830 facilities with 748 owners. Historically the program
easily met the Energy Policy Act's three-year UST inspec-
tion cycle, inspecting each facility annually. In recent years,
however, as staff has decreased and inspector respon-
sibilities have increased, the program is now on an 18- to
30- month inspection schedule.-
The impact of the federal Energy Policy Act on New
Mexico's program (and the programs of most states) can-
not be underestimated. Our inspections must now be much
• continued on page 2
Prioritize Inspections,
Target Remediation,
Reduce Claims to the
State Fund
(
221
231
Distilling the Essence of SOC
Compliance Assistance in Oneida Country
Testing Automatic Line-Leak Detectors
Annual Maintenance of ATG Systems
Using LIF to find LNAPL
USEPA's Plan for Vapor Intrusion Guidance
Restoring Santa Monica's Drinking Water
E15? The Sky Need Not Fall
Blofuels Happenings
FAQs: Getting the Most Out of the NWGLDE Website
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LUSTLine Bulletin 68 • June 2011
m The GISST of GoNM from page 1
more detailed, requiring review of
many additional requirements and
features—more testing and main-
tenance reporting, follow-up, and
paperwork. In addition, the Bureau
has added inspection priorities,
requiring that every active LUST site
be inspected annually (to ensure the
state Corrective Action Fund that it is
not spending money on remediation
at sites with significant compliance
violations). As the Bureau has devel-
oped more aggressive delinquent fee
and account-receivables programs,
inspectors are asked to spot-check
facilities for unreported transfers or
other fee-related issues.
The Bureau has adopted several
strategies for meeting the three-year
inspection requirement, including
using a "30-month" list, which is
a monthly accounting of all facili-
ties not inspected within the last 30
months. It is sent to all inspectors
to ensure they inspect those facili-
ties before the 36-month deadline.
Inspectors are encouraged to visit
problem facilities more often, to
L.U.S.T.Line
Ellen Frye, Editor
Ricki Pappo, Layout
Marcel Moreau, Technical Adviser
Patricia Ellis, PhD, Technical Adviser
Ronald Poltak, NEIWPCC Executive Director
Deb Steckley, USEPA Project Officer
LUSTLine is a product of the New England
Interstate Water Pollution Control Commis-
sion (NEIWPCC). It is produced through
cooperative agreements (US-83384301 and
US-83384401) 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 neces-
sarily 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 old-
est agency in the Northeast United States
concerned with coordination of the multi-
media environmental activities
of the states of Connecticut, Maine,
Massachusetts, New Hampshire,
New York, Rhode Island, and Vermont.
NEIWPCC
116 John Street
LoweU, MA 01852-1124
Telephone: (978) 323-7929
Fax: (978) 323-7919
lustline@neiwpcc.org
*® LUSTLine is printed on recycled paper.
push for compliance, and to delay
inspections of facilities that are usu-
ally in compliance with all Signifi-
cant Operational Compliance (SOC)
requirements. The problem facilities
should be inspected each year, if pos-
sible, while the better facilities can
wait for 30 months.
Then Came GoNM
Like many states, New Mexico has
been under a hiring freeze for nearly
two years—and we do not anticipate
being able to hire additional inspec-
tors for the foreseeable future. So it
is critical that the Bureau maintain
USEPA grants and federal funding by
maintaining our required inspection
frequency. With the state's delivery
prohibition rules soon to be adopted
and implemented, inspectors will
face additional enforcement respon-
sibilities. All of these factors require
the Bureau to do more with less.
The GoNM project is a key
strategy for maximizing available
resources. It is GIS-based, and rates
UST facilities on their potential to
leak. The tool can also be used to
facilitate remediation by providing
both location-specific data and a ref-
erence for determining which reme-
diation technologies have worked at
similar locations. The Bureau may
also use the tool to prioritize inspec-
tions, ensuring that facilities with the
highest risk of release are inspected
more often.
Developed with a grant from
USEPA Region 6, the project is based
on CRUST (Cumulative Risk for
Underground Storage Tanks) devel-
oped by Frank Harjo, Cherokee
Nation; the Inter-Tribal Environmen-
tal Council UST Program; and GISST
developed by EPA Region 6 (Dr. Ger-
ald Carney and Jeff Danielson).
GoNM Information Layers
The GoNM project includes GPS
coordinates for all tank-system fea-
tures. A first step in accomplishing
this is collecting GPS coordinates
for all aspects and equipment of our
operating gas stations—fill ports,
monitoring wells, vapor-recov-
ery locations, submerged turbine
pumps, automatic tank gauges, vent
lines, and other equipment particular
to a facility. While some GPS coordi-
nates are already in the New Mexico
database, most must be collected by
local inspectors or the project leader.
The Area of Analysis for each
facility is a quarter-mile buffer
around the facility. Within this area,
the program reviews physical, envi-
ronmental, and demographic data
and scores each factor based on the
risk of environmental damage from
a release. Each facility is scored on
approximately 70 criteria compiled
from the following three dataset lay-
• LUST Ranking Layer — addresses
the physical surroundings of the
facility, including factors such
as aquifer geology, road den-
sity, stream density, floodplain
proximity, rainfall, distance and
depth to water, air features, and
soil permeability. The data are
based on a USEPA dataset origi-
nally called Landscape, which
was modified for New Mexico
by adding layers with data for
remediation and cost prediction.
• Socioeconomic Layer — based
on United States Census data.
Criteria examined in this layer
include population density, per-
centage of economically stressed
households, percentage of chil-
dren, percentages of people over
55, age of housing, percentage
of residents without high school
degrees. These socioeconomic
and demographic data are very
important for addressing envi-
ronmental justice issues.
• Facility Criteria Layer — based
on the Bureau's OneStop tanks
database, includes all equipment
and technical features of each
UST facility, including number
of dispensers, tank composition,
piping construction, secondary
containment, overfill protection,
leak detection method, records
for both tanks and piping,
tank(s) age and capacity, type
of cathodic protection (if steel
tanks or piping), and history of
Notices of Violations.
Risk Scoring
The Bureau was able to merge data
for parameters already in its data-
base and incorporate it into the
GoNM project. A team of inspec-
tors then gave each of 35 to 40
parameters a risk score of 1 to 5
(5 = highest risk, or "worst" score;
1 = lowest risk of release, or "best"
score). Table 1 is an example of scor-
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June 2011 • LUSTLine Bulletin 68
Variable 1 Overfill Protection 1 Score
1-01
I-02
I -04
I-05
1-10
1-11
Product Level Sensor/Alarm
Automatic Tank Fill Shut-Off
<25 Gal at a time Trans Tank
None
Ball Float Valve
Flapper Valve
Product Level Sensor/Alarm, Automatic Tank Fill Shut-Off
Product Level Sensor/Alarm, Ball Float/Flapper Valve
Automatic Tank Fill Shut-Off, Ball Float Valve
Product Level Sensor/Alarm, Flapper Valve
2
2
5
5
2
2
1
1
1
1
TABLE 1. Overfill-prevention equipment and scores
FIGURE 1.
ing for overfill-prevention equip-
ment that can be found at a given
facility.
Each parameter within each
layer is assigned automatically a 1
to 5 score. Each layer also receives
a score. Then the scores for each of
the three layers are averaged to pro-
duce the cumulative-risk score for
each facility. The lower the score,
the less likely a facility is to have a
release and thus fewer inspections
are needed; these facilities could per-
haps slip to being inspected every
24-30 months, rather than annually.
Conversely, facilities with higher
scores and potential
risk can be inspected
on a more frequent
schedule (such as
annually) to perhaps
prevent a release and
risk to human health
and the environment.
In the future, the
Bureau may weigh
particular criteria or
layer scores as higher
risks than others. For
example, the Bureau
could assign higher
risk scores to facili-
ties where the depth
to water is quite shal-
low or located in
close proximity to
drinking water wells,
whereas facilities in
very rural areas with
great depth to water
and few human recep-
tors would be assigned
lower risk scores. The
Bureau could also
manipulate the scores
to increase weight on
the Socioeconomic Layer to empha-
size environmental justice concerns.
Close-up of a Facility Score
Figure 1 shows how an individual
facility is approached in the GoNM
project. On the bottom right, a state
map shows the location of the facil-
ity. Next to that is a smaller-scale
map indicating where the facility is
in the county and identifying major
roads. The aerial view of the facil-
ity indicates the major pieces of UST
equipment and provides scores for
the three layers and the averaged site
score.
Both inspectors and remediation
project managers use these maps and
data in site analyses, working with
contractors and facility operators,
and in public meetings. The GoNM
maps can be prepared to show all
the facilities in a particular commu-
nity, which is particularly useful for
city council or neighborhood meet-
ings. Similarly, maps can easily be
made so that state legislators can see
all current remediation sites in their
district.
Placing detailed information and
documentation of the equipment and
surrounding factors for each facility
in a database provides very helpful
information for inspectors in case of
staff turnover or re-assignment of
facilities. These peripheral benefits of
the project have been very helpful to
the Bureau.
Looking to the Future
The Bureau is in the process of inte-
grating all facilities in its database
into the GoNM project. Recently,
we expanded the criteria evaluated.
We must still verify or add data for
some of the parameters; not all facili-
ties have accurate data for all param-
eters. Quality control remains a
• continued on page 4
GoNM ANALYSIS SITE
Burger King Texaco
1050 RiD Giandt BoulsvanJ NW
Albuquerque EemaliJe County
New Mexico 87107
#1004
NcwMoueo
o
O
LUST Ha«>nj Soar* 1*2
Ctmtrupfi Crneta Settt 1 92
FKtt, C'ltffii* Scwe 2 90
Overall Facility Scorn; 2.41
* Wf*.
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LUSTLine Bulletin 68 • June 2011
m The GISST of GoNM from page 3
challenge when dealing with data for
approximately 1,511 VST facilities.
As more and more facilities are
accurately scored, the use of the
GoNM program increases. We can
look for trends. Which owners have
the most leaks? Does one piece of
equipment leak more than others?
Are some release-detection methods
more accurate than others? Similarly,
the program can be used to minimize
releases and allow the Bureau to be
proactive in preventing releases at
high-risk sites, rather than reactive
once a release occurs. The facility
scoring can provide a more rigor-
ous inspection schedule that targets
high-risk facilities in an objective
manner.
In times of shrinking budgets
and staff, the GoNM program can
also allow the Bureau to efficiently
utilize its resources, providing a
basis for more effective inspection
scheduling and identifying remedia-
tion technologies that are most effec-
tive at particular facilities or certain
physical surroundings.
As pressure mounts to examine
and address environmental justice
concerns, the GoNM program will
allow us to determine if fuel releases
and high-risk facilities prevail more
frequently in lower income commu-
nities or communities dealing with
environmental justice issues. GoNM
provides a good tool to document
compliance with environmental jus-
tice principles to ensure that all areas
and populations are treated equally
based on a risk calculation.
The possibilities for the GoNM
program are enormous, and we look
forward to continuing its develop-
ment. The Bureau thanks USEPA
Region 6 for its support and funding
for this program, and looks forward
to sharing our experiences with the
GoNM program with other federal
and state programs. •
Jennifer Pruett is a manager with
the NMED Petroleum Storage Tank
Bureau. She can be reached at 505-476-
4392 or Jennifer.Pruett@state.nm.us.
Suzan Arjman is a GIS analyst with
the NMED Information Technology
Applications Services Bureau. She is
the GoNM Project Leader. She can be
reached at 505-222-9527 or
Suzan.Arfman@state.nm.us.
Distilling the
Essence of SOC
by Leslie Harp
Kentucky is known for a lot of things—fast horses, cool Corvettes, smooth bour-
bon, Southern hospitality—but significant operational compliance (SOC) at
UST facilities is not listed among them. The good news is that after stream-
lining internal processes and implementing new strategies for compliance assistance,
Kentucky's SOC rates have increased, in some cases as much as 20 percent in a single
year.
SOC is essentially a snapshot in time to help determine whether an UST facility
is in compliance at the time of inspection. In 2003, SOC became the measure employed
by USEPA as a general assessment of UST facility significant operational compliance.
At that time Kentucky's SOC rates hovered around the 40 percent mark. The Com-
pliance Section of Kentucky's Underground Storage Tank Branch was tasked with
finding ways to effectively improve SOC rates. Three key factors were identified for
improvement: data integrity, consistency of inspections, and compliance assistance.
Data Integrity
In 2005, Kentucky implemented a
department-wide database called
Tools for Environmental Manage-
ment and Protection Organizations
(TEMPO). After implementing the
database, inspectors and compliance
reviewers noticed that it had incor-
rect information regarding UST-
facility equipment. In order to begin
any sort of compliance-assistance
process, we had to resolve these data
integrity issues.
We started by taking the inspec-
tors out of the field for approximately
three months to assist with database
"cleanup." Although we knew this
move could delay our UST inspection
cycle, it was decided that the benefits
would outweigh this setback.
At the end of the data review, the
inspectors learned a great deal about
data integrity and why that level of
integrity was difficult to maintain
without the active participation of
field inspectors. As an added benefit,
inspectors found a new appreciation
for the work of the technical compli-
ance staff that input and maintain
the data. After all was said and done,
Kentucky still met its statewide
three-year UST inspection deadline
through the cooperative efforts of the
regional offices.
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June 2011 • LUSTLine Bulletin 68
Consistency of Inspections
In order to improve the consistency
of facility inspections, we ramped
up our inspector training. Thor-
ough training in inspection methods
ensured that field inspectors were
equipped to evaluate system com-
ponents. By updating our standard
operating procedures, we offer new
inspectors the ability to perform
inspections with the same consis-
tency as veteran inspectors, all the
while ensuring that our violations are
being issued using consistent criteria
across the state. Consistent inspec-
tions and data entry have allowed
for effective reporting to better iden-
tify problem areas within the SOC
criteria.
Compliance Assistance
After addressing the first two areas
for improvement, it was time to
implement the third and most com-
plex part of our plan: compliance
assistance. In Kentucky, three groups
are involved in achieving and record-
ing compliance: the owner/operator,
the inspector, and the technical com-
pliance reviewer. Each group had a
unique set of issues that needed to be
addressed under the plan.
• Owner/operator
One of the issues we faced was
the fact that a significant num-
ber of UST owners and operators
were overwhelmed by the array
of technical compliance require-
ments and often lost track of
what was required. The key to
improving compliance centered
on the education of owners and
operators as to the site-specific
requirements they must meet.
Rather than present them with
broad information on all of the
various types of UST systems,
we wanted to focus our efforts
on the site-specific UST system
requirements for their UST facil-
ity. This effort was designed as a
precursor to the technical-com-
pliance inspection, so the owner
and operator would know what
was expected and be prepared
when the inspector showed up.
• Inspector
During inspector training, we
noted that inspectors spent a
large amount of time chasing
down paper violations rather
than finding and stopping
leaks. New standards of prac-
tice were developed that placed
an emphasis on the technical
inspection aspects of their role.
• Technical compliance reviewer
Back in the office, our technical
reviewers were not only going
over paperwork associated with
the initial field inspection, mak-
ing corrections to the database,
and making an SOC determi-
nation, they were also field-
ing phone calls from owners/
operators and contractors with
questions regarding site-specific
testing dates and requirements.
It Comes Down to
Communication
After analyzing these three factors,
we realized that we needed to estab-
lish a clear, focused, and efficient
communication process. So we dra-
matically streamlined that process
for all three groups of people by
providing owners/operators with
notifications regarding when testing
is due. These programmatic changes
required restructuring our review
process to include an outreach com-
ponent that would not only help
owners remain in compliance, but
also decrease the amount of time
inspectors were required to spend on
each site.
We now provide owners/opera-
tors with an annual reminder letter
that lists which tests are required and
the dates those tests are (or were)
due. We also take this opportunity
to request information for any data
gaps in our files (e.g., tank and pip-
ing materials, types of leak detection
used). This, in turn, has increased
the number of calls from owners/
operators and opened the door to
increased communication between
the regulators and the regulated
community.
By sending out the reminder
letters, our inspectors often already
have their paperwork without hav-
ing to request it, thus reducing the
amount of time they spend chasing
down various items. The reminder
letters go out. The owners/operators
have any tests done that are due for
their system and submit them to us
via mail, fax, or email. The compli-
ance reviewers receive the test infor-
mation and put the dates the tests
were performed and the results into
TEMPO. When the UST Inspectors
go into the database to prepare for
an inspection, they can easily deter-
mine whether the testing is current
or whether they need to request that
information.
To ease the burden of reporting,
we designated a new email address
that is specifically used for receiv-
ing the electronic submission of test-
ing results. Electronic submittal has
proven to increase the ease of sub-
mittal as well as provide a timely
response to deficiencies noted within
the reports. This simple step has also
significantly increased communica-
tion among staff, contractors, and
owners/ operators.
The Kentucky UST Branch is
also beginning its third year of pub-
lishing the UST Quarterly, a newslet-
ter that offers timely information to
the regulated community on a wide
array of information, including tech-
nical compliance. This, in conjunc-
tion with enhanced information on
the branch webpage, offers owners
and operators additional assistance
in maintaining compliance.
Hey, Not Bad!
The results of implementing all three
components of our plan to increase
SOC have been very positive! In only
one year, SOC rates have increased
by nearly 20 percent in some areas;
Kentucky's overall SOC rate has
increased by 13 percent. Several
owners and operators have called to
compliment the new process and say
how helpful the changes have been.
By demonstrating to the regu-
lated community that we are try-
ing to be more a helping hand than
a hammer, we hope to see improved
two-way communication and a
decrease in violations. While we
are busy implementing many more
requirements in accordance with the
Energy Policy Act of 2005, our regu-
lated community seems to see that
our helping hand has arrived at a
perfect time. In turn, these changes
are making our new inspection
requirements easier to achieve. •
Leslie Harp is Energy Act Coordinator
with the Kentucky UST Branch. She
can be reached at leslie.harp@ky.gov.
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LUSTLine Bulletin 68 • June 2011
Compliance Assistance Is a
Priority in Oneida Country
by Victoria Flowers
The Oneida Tribe of Indians of
Wisconsin Compliance Assis-
tance Program continues to
contribute to the development of
tribal capacity to track, record, and
report on federally regulated under-
ground storage tanks (USTs) within
the Oneida Reservation. As a result,
100 percent of facilities on the Oneida
Reservation have been inspected by
Region 5 USEPA and are in signifi-
cant operational compliance (SOC).
The Tribe's Compliance Assistance
Inspector, Shawn Suri has received
federal UST inspector credentials, as
well as State of Wisconsin credentials
as an installation inspector and UST
inspector.
The Oneida Tribe of Indians of
Wisconsin is a member of the Six
Nations or Haudenosaunee (People
of the Longhouse), indigenous to
New York State, who started to come
to Wisconsin in 1822. On February 3,
1838, the 65,400-acre Oneida Indian
Reservation (the Reservation) was
established pursuant to the Oneida
Treaty of 1838 and is located in
northeastern Wisconsin. The primary
land use is agriculture, followed
by residential and forest. There
are 233 miles of rivers, creeks, and
streams, 78 lakes and ponds covering
approximately 112 acres, and about
1,450 acres of wetlands. The land
is "home" to 16,622 enrolled Tribal
members; 4,225 of those members
live on the Oneida Reservation; 2,854
members live in adjacent Brown and
Outagamie Counties and have access
to Tribal services and amenities
of the Reservation. The remaining
members live outside the northeast-
ern Wisconsin area.
Five municipalities and two
counties are present within the Res-
ervation boundaries. The federal
government retains primacy for
environmental regulation within
the Reservation. However, feder-
ally delegated programs (to the
state), nontribal ownership of land,
and local zoning authorities create
a complex mix of tribal, local, state,
and federal authorities. In response
to this challenge, Oneida's Compli-
ance Assistance Program (OCAP)
has developed working relationships
with nontribal business partners
and the State of Wisconsin's Under-
ground Storage Tank Inspectors that
establish the OCAP as a resource for
ensuring compliance with 40CFR280.
OCAP has provided resources
to stations and other federally reg-
ONEIDA
NATION f( <'
presenting of
colors by the
Oneida Vet-
erans group
and a wel
come by the
Oneida Nation
Dancers. Dur-
ing the meeting,
OCAP and State
of Wisconsin rep-
resentatives gave
a presentation on how the OCAP and
state UST programs have identified
common goals for ensuring improve-
ment of SOC rates. They also dis-
cussed how the OCAP has increased
its capacity by taking
advantage of state training
and receiving state creden-
tials that demonstrate the
proficiency of the tribal
compliance inspector.
Annual Tribal Meeting attendees at compliance
assistance field trip.
ulated facilities to assist them in
achieving SOC at their facilities.
The resources include a Compliance
Assistance Handbook (see page 24), bi-
monthly newsletters to federally reg-
ulated facilities, and petroleum spill
kits. The materials and the capacity
developed under this program are
available to other Wisconsin tribes if
requested. So far, one Wisconsin tribe
has requested assistance for a tank
system installation. Additionally,
Shawn Suri has been asked by the
states of Wisconsin and Maine and
off-reservation nontribal facilities to
use the OCAP materials for their pro-
grams and/or stations.
On May 3-5, 2011 the Annual
Tribal/USEPA National UST meet-
ing was hosted by Oneida and
attended by representatives from 32
tribal nations, USEPA regional and
headquarters staff, NEIWPCC, and
the State of Wisconsin. The meet-
ing featured an opening thanksgiv-
ing prayer and welcome address by
Oneida Councilman Tehassi Hill,
The capstone of the meeting
was the field visit to a tribal retail
facility to conduct a practice com-
pliance assistance visit. During this
visit the group heard from Oneida
Retail about the proactive measures
they institute as a part of good busi-
ness practices to improve the bot-
tom line. Practices they highlighted
included making sure location man-
agers (Class B operators) had a good
understanding of their tank systems
and that Oneida Retail management
(Class A operators) communicated
best practices and the effect on the
"bottom line" to Class B operators. •
Victoria Flowers is Environmental Spe-
cialist with the Environmental, Health
and Safety Division of the Oneida Tribe
of Indians ofWisconsin. She can be
reached at vflowers@oneidanation.org.
-------
June 2011 • LUSTLine Bulletin 68
The Frontline in the Leak Detection Battle
Testing Automatic Line-Leak Detectors
by Kevin Henderson
After more than 20 years of battling leaks from underground storage tank (UST) systems, it is apparent that, with some
notable victories here and there, the battle lingers on. Despite the myriad regulations that require all kinds of monitoring,
maintenance, and testing, leaks continue to vex our efforts. Therefore, our ability to quickly and effectively detect leaks is of
mission-critical importance. The frontline of defense and probably the most important weapon we have in our struggle to quickly
detect leaks in pressurized piping systems is the automatic line-leak detector (ALLD). Therefore, it is manifest that our attention be
directed at ensuring that these soldiers serve as an effective fighting force. How do we accomplish this? 1) Ensure that these devices
are tested so that they perform as intended and 2) train personnel to evaluate whether or not the testing has been conducted properly.
This attentiveness is fundamental to our battle plan. Even though line-leak detectors have been around for more than 50 years, the
operation, maintenance, and testing of these devices is still poorly understood.
Mission Briefing — The Need to
Answer the Eternal Questions
ALLDs are relatively simple mechan-
ical (and in more recent years elec-
tronic) pressure-sensing devices that
test piping systems for relatively
large ("catastrophic") leaks. When
functioning correctly, leak detectors
are capable of detecting catastrophic
leaks equal to or greater than 3 gal-
lons per hour (gph) at a line pres-
sure of 10 pounds per square inch
(psi). As this article will focus on
the testing of mechanical ALLDs,
a brief summary of how they work
is needed, as well as an articulation
of the ALLD eternal questions. (For
a more detailed discussion see "Of
Blabbermouths and Tattletales - The
Life and Times of Automatic Line
Leak Detectors" in LUSTLine #29.)
In normal operation, if the
line pressure falls to near zero the
mechanical leak detector will "trip"
or close, enabling a test of the pip-
ing to be conducted the next time
the pump is activated. When the
pump is turned on, the leak detector
moves into the leak-sensing position,
and a metered volume of product is
allowed to enter the line at a certain
pressure. If the leak detector is not
able to pressurize the line above the
metering pressure, it will remain in
the leak search position.
If the leak detector remains in
this search position and is unable to
fully open, this is an indication that
a leak equal to or greater than 3 gph
at 10 psi may exist. Under this condi-
tion, someone attempting to dispense
product will face the familiar "slow
flow" that we have all experienced
at the corner gas station. The annual
"functionality" test of a leak detector
is simply confirming that the device
stays in the leak search position while
a simulated leak equivalent to 3 gph
at 10 psi is intentionally introduced in
the piping system.
So I ask: With our extensive
training requirements, why is it that
most people still do not really under-
stand how leak detectors work? Why,
with all our certification require-
ments, do we still have many people
testing these devices in a manner
that is simply wrong? In some cases,
this "testing" is so grossly wrong
that it possibly does more harm than
good. Why is the correct procedure
for testing leak detectors so poorly
understood? Why does the test pro-
cedure vary so much, depending on
who is conducting the test? Why do
we allow testing practices of dubi-
ous validity to go virtually unchal-
lenged? Why don't we do something
about it? Why? Why? Why? How
about some answers?
Basic Training —
The UST Rules and Regulations
According to the federal rule (40
CFR 280.44(a)) ALLDs must be able
to detect leaks of 3 gph at 10 psi
line pressure within one hour with
at least a 95 percent probability of
detection and no more than 5 percent
probability of false alarm. The rule
also requires that leak detectors be
tested annually in accordance with
the manufacturer's requirements.
Since it is left up to the manu-
facturer, there is no consistency in
determining how the testing must be
conducted. Somehow, we have even
wound up with third-party manu-
facturers of testing equipment, who
have their own protocols for how
the testing is done. This has led to a
mishmash of convoluted test proce-
dures from various manufacturers
and third parties.
To further obfuscate things,
although the rule dictates that the
leak detector must be capable of
detecting a 3-gph leak at a line
pressure of 10 psi, many years ago
USEPA issued an interpretation that
the annual test does not have to actu-
ally determine whether or not the
leak detector is capable of seeing
such a leak. The test that is required
is referred to as a "functionality"
check. The size of the leak that must
be simulated during the test is not
specified. As long as the leak detec-
tor "sees" the leak (irrespective of
how large that leak may be) it is
declared to be functioning.
This is akin to having a military
specification for an automatic rifle
that says it must have an accuracy of
plus or minus one inch at 100 yards
when new, but once the gun has been
taken out of the box, it doesn't matter
whether you can hit the broad side of
a barn. As long as it still shoots, it is
considered to be "functioning" prop-
erly. Is this a good idea? Would you
consider the analogous scenario we
have with ALLDs to be a good idea?
While some manufacturers have
rejected this and require that the leak
detector be able to see a leak equiva-
lent to 3 gph at 10 psi, there are oth-
ers that are still fine with hitting the
broad side of a barn.
Theatre of War —
Historical Background
Where did the regulatory standard
of 3 gph at 10 psi come from? In the
• continued on page 8
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LUSTLine Bulletin 68 • June 2011
• Testing ALLDs from page 7
mid-1980s, when the federal rules
were being developed, the industry
standard mechanical line-leak detec-
tor operated (looked for a leak) at a
metering pressure of 10 psi. After
some debate, it was decided that the
devices available at the time were
capable of detecting leaks of 3 gph.
Since the devices of the day metered
at a pressure of 10 psi, the leak detec-
tion threshold of 3 gph was related to
10 psi. Today, it is not uncommon for
leak detectors to operate at metering
pressures other than 10 psi.
Logic would seem to dictate
that all leak detectors should be able
to detect leaks of 3 gph regardless
of the pressure at which they oper-
ate. However, this is not the case.
The actual leak rate is allowed to
vary with the metering pressure. As
illustrated in Table 1, if a leak detec-
tor meters at greater than 10 psi, the
leak rate that occurs is correspond-
ingly higher. Out of this confusion,
the leak detector is said to be able to
detect a leak that is equivalent to 3
gph at 10 psi.
Surely it is time we demanded
more of our ALLDs. Surely after all
these years, we should be able to
agree that a leak detector must be
Pressure Leak Rate Leak Rate
(pounds/ (milliliters/ (gallons/
inch2) minute) hour)
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
189
198
207
216
224
232
239
247
254
261
268
274
281
287
293
299
305
311
317
3.0
3.1
3.3
3.4
3.5
3.7
3.8
3.9
4.0
4.1
4.2
4.3
4.5
4.6
4.7
4.7
4.8
4.9
5.0
TABLE 1. Variation of leak rate with pres-
sure change through an orifice calibrated to
allow 3 gph @ 10 psi.
8
able to detect a leak that is equiva-
lent to 3 gph at 10 psi, no matter how
long it has been in service. Surely we
should be able to agree on how the
testing of these devices is to be con-
ducted. Surely we should expect that
the people conducting these tests
know what they are doing. Surely we
should expect the people that review
these test records (i.e., regulators)
are scrutinizing them to ensure the
test has been done properly. Perhaps
a formal battle plan would be more
emphatic.
ALLD BATTLE PLAN
1. Develop standardized test
procedure.
2. Develop standardized test form.
3. Educate regulators and
contractors.
4. Critically evaluate test results.
5. Demand testing be done
correctly.
6. Deploy ALLDs that can quickly
find leaks as they are intended.
Tour of Duty — Leak Speak
Just like everything else, there is spe-
cialized jargon associated with leak
detector testing. In order for us to
begin to understand the issues and
strategize an effective battle plan for
standardizing a test protocol and
documenting the test data, we must
first have a firm comprehension of
leak speak:
• Full pump pressure (a.k.a.
operating pressure or pump
pressure). The maximum line
pressure that the submersible
pump is capable of producing,
measured while the pump is
operating but not dispensing.
Typically, the pump pressure is
between 22 and 40 psi, although
this can vary depending on the
type of pump and the opera-
tional conditions. We need to
know what the pump pressure
is so that when the test is con-
ducted, we are able to recognize
whether or not the leak detector
has fully opened.
• Holding pressure (a.k.a. check-
valve seating pressure, seating
pressure, functional-element
seating pressure, or static line
pressure). The pressure at which
the line will decay immediately
after the pump motor is turned
off. The holding pressure is
determined by the type of check
valve and/or functional element
(a check valve that incorporates
a pressure-relief mechanism)
that is installed in the submers-
ible pump. The holding pressure
must be determined in order
to confirm that the check valve
and/or functional element are
working correctly. In addition,
in systems that are designed to
allow the line pressure to decay
to some predetermined pressure
(i.e., the holding pressure is less
than the full pump pressure),
this data can be used to confirm
that the pump motor is properly
cycling on/off during normal
conditions. Note that if the hold-
ing pressure is the same as the
full pump pressure, the person
conducting the leak detector test
must manually confirm that the
pump motor properly cycles on/
off.
Resiliency (a.k.a. bleedback).
A measure of the elasticity of
the pipe determined by mea-
suring the volume of fluid that
returns when the line pressure is
allowed to decay from the hold-
ing pressure to zero. If it is a very
rigid pipe, the bleedback will be
low (on the order to 50-100 mL).
If the piping is flexible and rela-
tively long, the bleedback will
be much greater (on the order
of 300-500 mL). If the amount of
bleedback is greater than what
would be expected given the
length and material of construc-
tion of the piping, this generally
means that there is an air pocket
trapped in the line.
Metering Pressure (a.k.a. leak-
sensing pressure). The pres-
sure at which the leak detector
operates while searching for a
leak. The metering pressure is
typically 10-15 psi, although it
can vary considerably depend-
ing on the model of leak detec-
tor. We need to determine what
the metering pressure is in order
to know that the leak detec-
tor is in the leak-sensing posi-
tion. In addition, it is important
to understand that the meter-
ing pressure determines what
the actual leak rate is when the
-------
June 2011 • LUSTLine Bulletin 68
leak detector test is conducted.
This is because the leak orifice
is calibrated to allow a flow rate
of 3 gph at 10 psi. If the meter-
ing pressure is greater than 10
psi, the actual flow rate (leak
rate) that is allowed during the
test will be greater than 3 gph.
Conversely, if the metering pres-
sure happens to be less than 10
psi, the actual leak rate will be
less than 3 gph. To determine the
leak rate that corresponds to a
given pressure, refer to Table 1.
• Opening time (a.k.a. step-
through time). The length of
time it takes for the leak detec-
tor to conduct a test of the piping
if there is no leak under normal
operating conditions. Generally,
it is considered to be the length
of time it takes once metering
pressure is achieved until full
pump pressure is obtained. It
is sometimes described as the
length of time it takes from ini-
tially turning the pump on until
full pressure is achieved. Typi-
cally, the opening time is 2-4
seconds, but can be substantially
longer if the piping has high
elasticity or trapped air pockets.
Of special significance is the pos-
sibility that a long opening time
may be an indication that a small
leak (one less than 3 gph at 10
psi) is present in the line.
• Leak-test pressure. The actual
line pressure observed when
the leak detector test is being
conducted with the leak detec-
tor in the leak-search position.
The leak-test pressure should be
approximately the same as the
metering pressure. It is impor-
tant to document the pressure
observed while the leak detector
test is being conducted as confir-
mation that the leak detector is
in the leak-search position. If it
is significantly different, it nor-
mally means the leak detector
is not in the proper leak-search
position and the test is invalid.
• Leak-test volume. The actual
volume of product that passes
through the simulated leak ori-
fice during the timed interval of
the test and normally measured
in milliliters. The leak-test vol-
ume should be equal to the leak
rate expressed in milliliters per
minute, indicated for the cor-
responding leak-test pressure
in Table 1. If the volume is sig-
nificantly different, this indicates
that the leak-test-apparatus ori-
fice is not properly calibrated.
• Test leak rate. The actual leak
rate that occurs during the leak
detector test. It is important to
note that this will vary, depend-
ing on the metering pressure
of the leak detector. For exam-
ple, if a leak detector meters at
exactly 10 psi, the leak rate that
will occur with a properly cali-
brated orifice would be exactly
3 gph. If the metering pressure is
15 psi, the leak rate through this
same calibrated orifice would be
3.7 gph. The metering pressure
determines the leak rate that the
leak detector "looks at" when
the test is conducted.
If the testing and/or
documentation are sloppy, then it
is usually hecause the regulator
accepts this as adequate. As
regulators, we must scrutinize
these testing records to ensure the
test was done properly.
Leak-search position (a.k.a.
tripped, closed position, or
relaxed position). When the line
pressure drops to some prede-
termined pressure (generally 1-5
psi, depending on the model of
mechanical leak detector), the
leak detector closes (or trips)
and moves into a position that
enables the device to conduct
a test of the piping when the
pump is activated and the line
is repressurized. It is important
that the test be conducted with
the leak detector installed in the
pumping system and under nor-
mal operating conditions. This
is because we must ensure that
there is not excessive static head
pressure in the piping system.
If there is too much static head
pressure, the leak detector will
not trip and will never conduct
a test. The commonly accepted
rule of thumb is that in a gaso-
line system, an elevation change
of 38 inches between the height
of the leak detector and the high-
est dispenser will produce a
static head pressure of one psi.
Since we know that some leak
detectors will not trip unless the
line pressure decays to a certain
pressure, the test must confirm
that the leak detector will trip
under normal static operating
conditions.
The Salient Front —
Adjusting the Orifice
When a leak detector is tested, a
leak is created in the piping sys-
tem through an orifice. The orifice
is sized to allow a leak of 3 gph at a
line pressure of 10 psi. Proper siz-
ing of the leak orifice is of para-
mount importance when testing leak
detectors. The leak orifice must be
adjusted or calibrated each time the
test is conducted. The most common
method is to adjust the line pres-
sure to be equal to 10 psi and then
adjust the size of the orifice until the
desired leak rate of 3 gph (189 millili-
ters per minute) is achieved.
Why must the orifice that is used
to simulate the leak be adjusted each
time the test is conducted? This is
not any more complicated than the
basic principle that, since different
fluids have different viscosities, they
will have different flow (leak) rates
through a given size orifice at a given
pressure. Viscosity is a measure of
the thickness of a fluid or its resis-
tance to flow.
To put it in an everyday exam-
ple, think about the flow rate of
honey versus water. It is not hard
to see that the flow rate of honey
through a small opening (orifice) will
be very different than the flow rate
of water through this same opening.
Although not nearly as pronounced,
the same principle applies to prod-
uct flow rates in a typical UST piping
system. The flow rate of diesel fuel,
for example, will be different than
the flow rate of gasoline if they are
pumped through the same orifice at
the same pressure.
Differing fuel viscosities is the
reason there are different leak detec-
tors for gasoline and diesel fuel.
Have you ever wondered why it
is said to be acceptable (from an
operational perspective) to install
• continued on page 10
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LUSTLine Bulletin 68 • June 2011
• Testing ALLDsfrcm page 9
a gasoline leak detector in a diesel
system, but not vice versa? Since
the viscosity of diesel fuel is greater
than the viscosity of gasoline, the
size of the metering orifice in a die-
sel leak detector must be larger than
the metering orifice in a gasoline leak
detector in order to achieve the same
flow at the same pressure.
Thus, if you install a diesel leak
detector in a gasoline system, you are
actually allowing more than 3 gph to
be metered into the piping when the
leak detector is conducting a test. If
you are allowing more than 3 gph to
be metered into the piping, the leak
you are able to see is correspondingly
greater than 3 gph. It is okay to install
a gasoline leak detector in a diesel
system since the smaller metering
orifice of the gasoline leak detector
actually allows less than 3gph to be
metered into the piping, and the leak
that can be seen by the leak detector is
less than the required 3 gph.
Temperature also affects viscos-
ity and is another reason why the
leak orifice must be adjusted in order
to conduct an accurate test. Diesel
fuel that is at 50 degrees will have a
substantially different flow rate from
that same diesel fuel at 90 degrees.
Biofuels complicate things even
further. Ethanol-blended fuels have
a lower viscosity than 100 percent
gasoline. Biodiesel has a consider-
ably higher viscosity than 100 per-
cent diesel. Finally, since all fuels in
the market are fungible, even if you
are testing the same grade of product
(e.g., E10 gasoline) at the same tem-
perature but at two different facili-
ties, it is entirely possible that the fuel
viscosity will vary enough between
the two facilities to cause a mea-
surable difference in the flow rate
through an identically sized orifice.
Night Vision Goggles —
Types of Testing Equipment
Because different fuels under differ-
ent conditions have different flow
characteristics, testing equipment
using fixed orifices that cannot be
adjusted to compensate for these
different flow characteristics, in my
opinion, should not be allowed.
In addition to fixed-orifice testing
devices, some kinds of testing equip-
ment make use of flow meters. Flow
meters allow the operator to deter-
10
mine the flow rate through the leak
orifice without having to measure
the volume of fluid over a time inter-
val. This makes the process of cali-
brating the leak orifice much easier
and quicker. However, because flow
meters are calibrated with a specific
product that has specific flow charac-
teristics, if you change the fuel, you
are potentially changing the flow.
If, for example, you attempt to
measure the flow of E85 gasoline
with a flow meter that was calibrated
utilizing standardized diesel fuel,
that flow meter will likely not accu-
rately measure the flow rate because
the flow characteristics are markedly
different between these two fuels.
Thus, devices with flow meters have
limitations similar to those of fixed
orifice devices—the inability to com-
pensate for the differing flow charac-
teristics of differing fuels.
From this discussion, it should
be apparent that the leak orifice must
be adjusted and the flow rate mea-
sured manually (volume measured
over a timed interval) each time a
test is conducted. If this is not done,
it is not possible to say with certainty
that the leak orifice has been prop-
erly calibrated to the regulatory stan-
dard of 3 gph at 10 psi.
Final Assault —
Conducting the Test
Once the size of the leak orifice is
determined, the test is conducted
without any regulation of line pres-
sure by the test apparatus. The actual
pressure that is applied to the orifice
during the test is dependent upon the
metering pressure of the leak detec-
tor. Thus, if a leak detector meters at
exactly 10 psi, the resultant leak rate
will be exactly 3 gph. However, if for
example, the leak detector operates
at 15 psi, the resultant leak rate will
be 3.7 gph. Thus, the leak detector
test does not necessarily confirm that
the leak detector is capable of seeing
a 3-gph leak. Instead, we say that the
leak detector is capable of seeing a
leak that is equivalent to 3 gph at 10
psi. What we are really saying is that
the leak detector is capable of see-
ing a hole (breech of integrity) in the
piping that would allow a leak of 3
gph to occur if the line pressure was
10 psi.
A detailed, step-by-step pro-
cedure for testing leak detectors is
beyond the scope of this discussion;
however, Table 2 provides a sim-
plified version. A detailed testing
procedure for both mechanical and
electronic leak detectors and a com-
prehensive form may be accessed at
the Mississippi Department of Envi-
ronmental Quality website (www.
deq.state.ms.us/MDEQ.nsf/page/UST_
Publications ?OpenDocument).
1
2
3
4
Determine operating parameters
a
b
c
d
e
f
g
Confirm pump cycles on/off
Determine full pump pressure
Determine holding pressure
Confirm leak detector trips
Determine metering pressure
Determine opening time
Determine resiliency
Calibrate orifice to simulate a leak
equivalent to 3 gph @ 10 psi
Conduct test
a
b
c
Cause leak detector to trip by bleeding
line pressure to zero
Turn pump on allowing simulated leak
of 3 gph @ 10 psi to occur
Monitor line pressure with pump run-
ning and simulated leak occurring
Determine test result
a
b
Pass - Line pressure does not rise
above metering pressure during the test
Fail - Line pressure increases to full
pump pressure during the test
TABLE 2. Simplified mechanical line-leak-
detector test.
In addition, the Petroleum
Equipment Institute (PEI) is devel-
oping a recommended practice that
should, among other things, provide
a comprehensive line-leak-detector
test procedure and standardized
forms for recording test data. The
PEI recommended practice will
finally provide an industry stan-
dard by which leak detector testing
should be conducted. It is expected
to be published in early 2012.
Debriefing —
New Marching Orders
In today's economic climate, we
must get the biggest bang for our
testing dollars. Even after more than
20 years of regulating UST systems,
it is still painfully obvious that much
of the leak detector testing that we
spend good money on is not accom-
plishing what it could. Another cru-
-------
June 2011 • LUSTLine Bulletin 68
cial component of the equation is
that regulators are accustomed to
simply looking at someone's test-
ing records, checking the date, and
ensuring the test result was "pass."
But if we are to move forward, we
must get past this frame of mind.
In my experience, the quality of
UST system testing and the docu-
mentation of such testing are directly
related to what the authority hav-
ing jurisdiction (i.e., the regulator)
accepts. If the testing and/or docu-
mentation are sloppy, then it is usu-
ally because the regulator accepts
this as adequate. As regulators, we
must scrutinize these testing records
to ensure the test was done properly.
If you don't think it's your job as
a regulator to make sure leak detec-
tors are tested properly, consider the
recent Deepwater Horizon oil spill
in the Gulf of Mexico. Okay, that
event was certainly not comparable
in scope or size to our leak scenarios,
but look at what happened in the
wake of that disaster. While many
fingers were pointed, laying poten-
tial blame at many different parties,
one of those fingers was pointed
directly at the federal Minerals Man-
agement Service (MMS) charged
with regulating offshore drilling
operations.
Much of the post-blowout inves-
tigation centered on the possibility
that certain "functionality" testing
of various pieces of equipment on
the rig (notably the blowout pre-
venter) was not conducted properly.
In the investigation that followed,
the regulators at MMS were faulted
for possibly not providing adequate
government oversight relative to,
among other things, the required
"functionality" testing of the blow-
out preventer.
Going back to UST systems, as
we know all too well from experi-
ence, leaks from pressurized pip-
ing systems that go undetected for
extended periods can have serious
consequences. In the struggle to
quickly detect leaks from UST sys-
tems, we have our own mini version
of blowout preventers—automatic
line leak detectors. Still don't think
it's your job? Think again. •
Kevin Henderson is UST Manager for
the Mississippi Department of Envi-
ronmental Quality. He can be reached
atKevin_Henderson@decj.state.ms.us.
Observations on Annual
Maintenance of ATG Systems
by Chris Prokop
The Code of Federal Regulations (CFR) provides the governing statement
regarding the maintenance of release detection equipment for UST systems at
40 CFR § 280.40(a)(2). This section states that release detection equipment
must be "installed, calibrated, operated and maintained in accordance with the manu-
facturer's instructions." Over the years, this statement has led to some ambiguity for
federal, state, and local regulatory entities regarding what constitutes proper main-
tenance of release detection equipment. For example, some state and local regulatory
entities require annual maintenance of automatic tank gauge (ATG) systems, whereas
other regulatory entities do not require this maintenance. This article focuses on the
maintenance of ATG systems.
Industry Standards for
Maintaining ATG Systems
During my eight years of conducting
UST inspections, the majority of the
ATG systems that I have observed
were manufactured by Veeder-Root,
or an affiliated company (e.g., Gil-
barco). While many other ATG brands
are in use nationally (e.g., Incon,
OPW, EBW, Petro Vend, Ronan), I will
focus my discussion on Veeder-Root
due to their market share and good
maintenance documentation.
Section 31 of Veeder-Root's Opera-
tor's Manual (Manual No. 576013-610,
Revision Y) contains a Periodic Main-
tenance Checklist, which addresses
recommended frequencies of main-
tenance, as well as the maintenance
procedures, for the ATG console,
magnetostrictive probes, line-leak
detectors, magnetostrictive sump sen-
sors, and other sensors.
Page 9 of Veeder-Root's Oper-
ability Testing Guide (Manual No.
577013-814, Revision E) discusses
Veeder-Root's recommended pro-
cedures for "Verifying Operability
of UST Leak Detection Equipment."
Both the Operator's Manual and the
Operability Testing Guide state that
conducting regular maintenance of
Veeder-Root's leak detection equip-
ment associated with ATGs may
extend the life of that equipment but
is not required for proper operation
(see www. veeder.com/page/Monitoring-
Consoles).
Veeder-Root's rationale for this
statement is that the components of
the leak detection equipment con-
nected to ATGs are self-diagnosing
(i.e., alarms will be indicated on
the ATG console if malfunctions
occur). The takeaway message is
that Veeder-Root (and probably most
other ATG manufacturers) recom-
mends annual maintenance of their
ATG systems, but they do not require
it. However, most states and local
regulatory entities within Region 9
require some form of annual ATG
maintenance, as well as some type of
standard maintenance checklist.
However...
When I first began conducting UST
inspections several years ago, I rarely
saw documentation demonstrat-
ing maintenance of ATG systems.
When I did see such documentation,
it was often presented in an irregu-
lar format, or it only addressed very
basic operations of the ATG sys-
tems (e.g., ATG power on, audible
alarm operational). As I learned
more through experience and train-
ing, I began requesting that proper
annual maintenance of ATG systems
be conducted and documented. As
a consequence, I began to see bet-
ter written examples of annual ATG
maintenance that included detailed
checklists, supported by some or all
of the following ATG printouts docu-
menting:
• Fuel/water alarms simulated by
manipulating containment sump
sensors (e.g., turning the sensors
upside down or placing them in
water)
• Alarms for probe out, high
water, low product, and overfill
simulated by removing the in-
tank probes and manipulating
the floats,
• continued on page 12
11
-------
LUSTLine Bulletin 68 • June 2011
m Annual Maintenance of ATGs
from page 11
• VST annular space alarms simu-
lated by removing the sensors
from annular spaces (where pos-
sible) and immersing the sensors
in fuel/water.
During my UST inspections, I
also review and print the alarm his-
tories for all sensors in order to inde-
pendently verify that the ATG was
"calibrated" on the date shown on
the ATG system checklist. The man-
ner in which annual maintenance of
ATG systems is conducted depends
on the role the ATG plays in leak
detection. By this I mean that differ-
ent components of the ATG system
need to be evaluated depending on
whether:
• UST leak detection is conducted
by volumetric leak testing or
annular space monitoring
• Piping leak detection is con-
ducted by containment sump
sensors (for double-walled pip-
ing) or annual tightness tests
• Another leak detection method
is being used, such as Statistical
Inventory Reconciliation (SIR)
using inventory data from the
ATG.
In addition to printing leak-test
and sensor-alarm histories from
ATGs, I request that maintenance
technicians evaluate the appropri-
ateness of the "setup" parameters
for the ATG. At one site, the mainte-
nance technician indicated to me that
the overfill alarm on the ATG had
been set too low, and he adjusted it.
I also request that maintenance
technicians compare the fuel vol-
umes from the in-tank probes to the
fuel volumes from stick readings.
Visual inspections of all containment
sumps are another important com-
ponent of the annual maintenance
of ATG systems because they allow
electrical wiring to be checked for
any evidence of deterioration.
California's Form for
Documenting UST/ATG System
Annual Maintenance
The State of California requires that
owners and operators of UST sys-
tems conduct annual maintenance
of those systems, and that this
maintenance be documented on its
"Monitoring System Certification"
form (see www.Tvaterboards.ca.gov/
water_issues/programs/ust/forms/index.
shtml). This form contains a thorough
UST facility equipment section, good
checklists for "Testing/Servicing,"
"In-Tank Gauging/SIR Equipment,"
and "Line-Leak Detectors." It also
includes a page for diagramming
the UST facility and an UST techni-
cian "Certification" section for attest-
ing that all work was conducted in
accordance with the manufacturers'
specifications. Although under the
jurisdiction of USEPA, many tribal
UST facilities in the state are requir-
ing that their service technicians con-
duct California-equivalent annual
UST system maintenance, which is
documented by this Monitoring Sys-
tem Certification form and support-
ing records.
And So...
Although ATG manufacturers rec-
ommend but do not require annual
maintenance of their ATGs, I strongly
believe that annual maintenance
is an important means for ensur-
ing the integrity of these systems. In
addition, owners and operators of
UST facilities should document this
annual maintenance with detailed
checklists supported by printouts
from the ATG and related records. •
Chris Prokop is an UST Inspector and
Corrective Action Project Manager at
USEPA Region 9. He can be reached at
Prokop.Chris@EPA. GOV.
Drinking
Water"
Help UST Owners and Operators Protect
Their Drinking Water
Drinking water and gasoline
should never mix. That's why
it is especially important that
gasoline facility owners and opera-
tors make sure that any onsite well
is protected. The New England Inter-
state Water Pollution Control Com-
mission's (NEIWPCC) publication,
Protecting the Drinking Water You
Provide: A Guide for Owners and
Operators of Gas Stations, is a great
resource to help tank owners and
operators with onsite wells under-
stand their responsibilities in meet-
ing drinking water regulations and
protecting the health of those who
drink the water or otherwise come into contact with it.
This colorful booklet can be distributed electronically or as printed
copies (instructions for printing are located on the NEIWPCC website).
Also, for those who want to train others through a presentation, NEI-
WPCC provides PowerPoint slides that highlight the major themes of
the guide. The guide and PowerPoint presentation can be found at www.
neiwpcc. org/tncguide.asp.
USEPA Seeks $233,000 in
Penalties for UST Violations in
New York
USEPA has issued a complaint to the owners
and operators of several upstate New York
gasoline stations for violating federal regu-
lations governing 17 USTs. The complaint, which
seeks $233,000 in penalties, was issued to one
individual and three companies that owned or oper-
ated gasoline stations in four towns. The complaint
alleged that the various owners and/or operators
failed to:
• Test cathodic protection systems in three USTs
• Perform automatic line-leak detector tests in 16
USTs
• Provide adequate overfill-prevention equipment
in three USTs
• Conduct annual leak tests—or monthly monitor-
ing—for five pressurized underground lines
• Properly cap off and permanently close one UST
• Report, investigate, and confirm a suspected
release at one facility
• Keep adequate records of release detection mon-
itoring.
12
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June 2011 • LUSTLine Bulletin 68
Where's the LNAPL?
How about Using LIP to Find It?
by Paul Stock
The Minnesota Pollution Control Agency (MFC A) Petroleum Remediation Program (PRP) routinely uses data from laser-
induced fluorescence (LIF) probes to target petroleum light non-aqueous phase liquids (LNAPLs) when remediation is neces-
sary. Given our experience in using LIF, PRP staff had gained a great deal of insight on LNAPL behavior and found themselves
nodding their heads in agreement during the Interstate Technology Regulatory Council's (ITRC) internet-based training on LNAPL
behavior when it first became available in March 2009.
A couple of months ago, several PRP technical staff were invited to attend a dry run of the ITRC's LNAPL Classroom Training
in order to provide the ITRC's LNAPL Team with feedback. The LNAPL Team has developed a set of excellent classroom training
modules that lay out the latest understanding of LNAPL behavior using a multiple lines of evidence approach—LNAPL science, if
you will. This science is consistent with and provides a much deeper understanding of what PRP staff have observed about LNAPL
behavior using LIF. The LNAPL Classroom Training also includes a process for selecting the appropriate remedial technology to
address specific LNAPL concerns using an LNAPL science-based site conceptual model (SCM). You may have guessed by now that
one of the first things one needs know is: where's the LNAPL?
The PRP has found that LIF data can reliably answer the question: where's the LNAPL? Moreover, LIF data can also help lead
to answers for many other important questions about site-specific LNAPL behavior and its remediation. After more than a decade
using LIF, we have concluded that its strategic application results in cost-effective use of limited resources. The word must be getting
out. More frequently over the past couple of years, we have been contacted by regulators, consultants, contractors, and even some
responsible parties from other states inquiring about the PRP's use of LIF. Recently, a regulator from another state invited PRP staff
to train their staff on how to interpret LIF data. The following discussion has been designed to address some of these questions.
NOTE: I should explain that, as we became more aware of what LIF was telling us about the behavior of petroleum products released
in the subsurface, we began to abandon the term "free product" in favor of LNAPL. We believe that LNAPL is more scientifically
accurate and descriptive, and less prone to past and existing misconceptions about free product. However, I will occasionally use the
term "free product" in the following discussion when historically appropriate.
What Is LIF?
Folks working the oil patch have
long used ultraviolet light to induce
fluorescence when examining drill
cuttings for the presence of petro-
leum hydrocarbons. That basic prin-
ciple can be applied to the down-hole
environment. As a probing tool is
advanced to depth, ultraviolet light
is directed through a transparent
window on to the immediately adja-
cent soil and whatever fluid occupies
the soil pores. A sensor detects and
records any florescent light returning
through the window.
Essentially, the more petroleum
present in the pores adjacent to the
window, the stronger the recorded
fluorescent response. Because differ-
ent chemical compounds predictably
fluoresce at varying wavelengths and
decay times, even more information
can be gleaned from further analyses
of the light returning to the sensor. In
addition, filters can be used to elimi-
nate or reduce unwanted responses.
I am aware of two companies
that design and produce commer-
cially available field sensors using
ultraviolet light to induce fluores-
cence of aromatic hydrocarbons for
detecting petroleum LNAPLs in
the subsurface: Vertek, a division
of Applied Research Associates,
Inc., out of Randolph, Vermont; and
Dakota Technologies, Inc. (DTI), out
of Fargo, North Dakota. Information
on Vertek's and DTI's respective sen-
sors can be found at www.vertekcpt.
com and www.dakotatechnologies.com.
These sensors are designed to
detect lighter and heavier petroleum-
based fuels, oils (including crude
and lubricants), and/or creosote and
tar. The main output is in the form
of a graph, typically called a log, of
fluorescent response versus depth
for each probing location. When a
laser is used to generate the ultravio-
let light, the technology is generically
referred to as laser-induced fluo-
rescence, or LIF for short. Figure 1
shows a sample LIF log.
The Ins and Outs of LIF
It is important to note that induced
fluorescence data must be integrated
with all available standard site data,
including site history, present land
use, geology, and soil and ground-
water contamination, to develop
an SCM using multiple lines of evi-
dence. Moreover, considering typi-
cal geological heterogeneity and
consequential LNAPL behavior, the
benefits of viewing side-by-side LIF
and geology data can hardly be over-
stated.
The induced fluorescent tools are
typically deployed with Cone Pen-
etrometer Testing (CPT) or Electri-
cal Conductivity (EC) sensors. These
sensors allow collection of side-by-
side, high resolution, geologic data.
CPT and EC often provide a more
objective and complete data set than
obtained from typically limited geo-
logic descriptions of physical soil
samples collected during routine site
investigations.
LIF detects polycyclic aromatic
hydrocarbon (PAH) molecules (e.g.,
naphthalene, perylene, anthracene)
that fluoresce efficiently when pres-
ent in an aliphatic solution like
typical petroleum LNAPLs com-
posed of gasoline, diesel, heating oil,
kerosene, jet fuel, and so on. We have
also used LIF to delineate heavier
• continued on page 14
13
-------
LUSTLine Bulletin 68 • June 2011
O
CJ
O
0 75 150 225
Fluorescence (%RE)
Groundwater21 ft
FIGURE 1. LIF log and associated wave-
form showing gasoline LNAPL extending
from approximately 20 to over 23 feet below
ground surface. The water table is located
about 20.5 feet below ground surface. The
LNAPL signature suggests straightforward
vertical LNAPL distribution in homogenous
sandy soil under a classic vertical equilib-
rium scenario.
I Using L\Ffrom page 13
petroleum products such as no. 6
fuel oil, motor oil, and hydraulic oil.
Monoaromatic compounds do
not fluoresce efficiently, so LIF will
not reliably detect LNAPLs com-
posed of, for example, pure benzene
or xylene. In addition, LIF does not
detect individual contaminant mol-
ecules occurring in the other three
physical phases of subsurface petro-
leum contamination commonly asso-
ciated with an LNAPL—the aqueous,
vapor, and adsorbed phases. In other
words, LIF does not detect PAHs,
BTEX, or other petroleum-related
molecules dissolved in water, dis-
solved in soil gas, or adsorbed to soil
solids because they do not fluoresce
efficiently.
Although not responding to
PAHs, we have also used LIF to suc-
cessfully investigate a release of 100
percent soy biodiesel—that's when
14
we found out that even banana skins
will fluoresce. There are some other
nonpetroleum compounds that fluo-
resce when stimulated by ultraviolet
light (e.g., mineral calcite and many
natural organic molecules, such as
those found in peat and other carbo-
naceous sediments).
To discriminate between inter-
fering fluorescence and fluorescence
caused by LNAPL, LIF can display
waveforms (Figure 1) from selected
depths (e.g., call-outs) which, along
with a multiple lines of evidence
approach, are useful for eliminat-
ing these false positives. Moreover,
the waveforms vary systematically
among different petroleum products;
thus they can be used forensically to
differentiate situations such as side-
by-side or overlapping gasoline and
diesel LNAPL bodies. However, dif-
ferential weathering and other phe-
nomena can also result in differing
waveforms from borings completed
across a single LNAPL body. For this
reason, forensic use of LIF should be
done very cautiously with corrobo-
ration by multiple lines of evidence
and logical consistency.
LIF has given us pause when
considering a definition for the
sometimes-confounding term "soil
contamination." Conceptually, we
have found it more straightforward
and useful to determine in which of
the four physical phases a detected
organic contaminant molecule exists
in the subsurface, rather than classi-
fying it generically as soil contamina-
tion.
Because many organic contami-
nation detection methods, such as
headspace screening and laboratory
analysis, are nonspecific with regard
to contaminant phase, we have
found that misconceptions about
soil contamination can lead to confu-
sion when developing an SCM and
designing corrective action. LIF's
ability to detect only the LNAPL is
perhaps the single most important
concept to understand when using
LIF data.
A Real Free-Product
Eye-Opener!
Although some fundamental prin-
ciples of LNAPL science, such as
vertical equilibration and multiphase
flow, were already understood, it
is fair to say that, back in the 1980s
and 1990s, free product behavior was
somewhat of a mystery to many reg-
ulators, including the PRP. It is also
fair to say that some misconceptions
persist to this day. The PRP began
experimenting with LIF in 1998 and,
by 2000, began to recognize its use-
fulness for understanding LNAPL
behavior and mapping its actual dis-
tribution in the subsurface. This sim-
ple mapping approach caused us to
abandon long-held preconceptions
about free product that were simply
not supported by an objective evalu-
ation of the new evidence supplied
by LIF.
With tongue in cheek, a col-
league from a southern clime once
asked me if we have ever found
any frozen LNAPL in Minnesota
using LIF. No we have not, but one
of the first things we learned from
LIF is that LNAPL is ubiquitous. Its
presence should be suspected at all
petroleum release sites, even if direct
evidence of LNAPL, such as measur-
-------
June 2011 • LUSTLine Bulletin 68
able thicknesses in monitoring wells,
is not present.
Perhaps the most profound
misconception held by many of us
was that petroleum releases orga-
nized themselves into a layer of free
product floating on top of the water
table in the formation. Admittedly,
this concept seemed self-evident
in light of how free-product floats
on top of the water in monitoring
wells. Indeed, monitoring wells were
designed to straddle the water table
with this misconception in mind.
LIF evidence made it immedi-
ately obvious that LNAPL does not
float on the top of the water table.
In fact, it was clear that the majority
mass of LNAPL was almost always
situated in the pores below the water
table. We realized this had profound
implications for development of suc-
cessful remediation strategies. By
2003, the PRP started requiring LIF
data at many high-risk leak sites
where aggressive remediation was
necessary.
LIF data allowed us to confi-
dently target remediation efforts on
the LNAPL with almost surgical pre-
cision. At the same time, we groaned
upon realizing that earlier soil exca-
vations had often stopped at the
water table while soil-vapor extrac-
tion would not have significantly
affected submerged LNAPL. On
the other hand, we realized why air
sparging had, perhaps inadvertently
to a degree, resulted in some notable
successes.
Until we learned that LNAPL
does not float on the water table, we
assumed that free product would
simply follow the water table gra-
dient as it migrated away from the
release point. LIF data showed us
that this is rarely the case; rather,
migrating LNAPL follows the path
of least resistance above and below
the water table. Upon encountering
the water table, the LNAPL contin-
ues to penetrate downward some
distance and then spreads laterally
in all directions within the saturated
zone, including opposite the hydrau-
lic gradient. That is not to say that
the LNAPL continues to expand for-
ever.
Strategic Regrouping
Under the misconception that free
product was floating on the water
table and migrating down gradi-
ent, almost like water flowing down
a hill, we had conceptualized that
there was nothing much stopping
it from continuing to migrate, albeit
slowly in most cases. There was
no way we wanted to close sites if
there was any chance of free product
migration, while the risks posed by
free-product migration seemed ever
present.
However, after mapping LNAPL
bodies with LIF data, and integrat-
ing standard investigation and long-
term monitoring data, the LNAPL
bodies from legacy releases appeared
remarkably stable under prevail-
ing, natural, hydraulic conditions.
Obviously, there were, albeit poorly
understood by us at the time, natu-
ral forces counteracting the forces
behind LNAPL migration.
LIF allowed us to strategically
locate monitoring and remedial wells
inside and outside an LNAPL body.
At first we were surprised when no
LNAPL showed up in some wells
purposefully screened across the
LNAPL body. We also noticed how
rarely actively migrating LNAPL
was observed in the sentinel wells
purposefully located just outside an
LNAPL body from a legacy release.
It became apparent that, after a rela-
tively short-duration, active-migra-
tion period immediately following
a release, an LNAPL body becomes
stable. However, the LNAPL within
the stable LNAPL body manifested
itself in one of two basic fractions
within the subsurface: mobile and
immobile.
Clearly, the mobile fraction was
locally mobile but, more importantly,
not necessarily migrating en mass
from the locales where it was found.
We also noticed that mapping an
LNAPL body often provided clues as
to where the mobile fraction could be
found within the LNAPL body foot-
print. On the other hand, we real-
ized that both mobile and immobile
LNAPL act collectively as a source
of the chemicals of concern (COC)
for the more extensive aqueous and
vapor phases.
LIF quickly taught us that the
migration and, ultimately, the distri-
bution of LNAPL in the subsurface is
often complex, with abrupt changes
occurring over short lateral (and ver-
tical) distances, due in large part to
geologic heterogeneity. Infrequently,
heterogeneity manifested itself with
LNAPL-less borings inside the foot-
print of an LNAPL body.
We have found that geologic
heterogeneity must be accounted
for not only when completing a LIF
investigation and corrective action
design, but also when evaluating
standard site investigation data, such
as laboratory analysis of discrete soil
samples. In other words, samples
collected using standard methods
may not be as representative as often
assumed, especially if not evaluat-
ing the standard data with an SCM
accounting for the four phases of
subsurface petroleum contamina-
tion.
LNAPL Loves Sand and
Hates Clay
A somewhat crude rule of thumb
developed from our LIF experience
is that LNAPL loves sand and hates
clay. However, that's only part of the
story, especially when it comes to
clay. Pore size, structure, and geom-
etry, rather than grain size per se,
seemed to control LNAPL migra-
tion and distribution. LIF showed us
that LNAPL readily occupies a clay's
secondary porosity features, such as
cracks and fractures (i.e., relatively
large pores), while not being pres-
ent within the primary porosity (i.e.,
very small pores).
I personally confirmed what
the LIF data was telling us when I
observed this behavior in fractured
clay till while attending an excava-
tion of an LNAPL body. Moreover,
the LNAPL can penetrate far into the
saturated zone along these fractures.
A better description of LNAPL's
seemingly curious behavior in fine-
grained soil is presented in a paper
by Mark Adamski and others in the
Winter 2005 edition of the National
Ground Water Association's publi-
cation Ground Water Monitoring and
Remediation. This subject is also cov-
ered in the LTRC LNAPL Classroom
Training, including a couple of very
clever but straightforward demon-
strations that you can even try at
home.
Keeping in mind that LNAPL
does not like clay, LIF data showed
us that LNAPL can be found under
several general geologic scenarios
when coarser-grained lithologies are
present. When homogenous, sandy
geologic conditions are present, the
• continued on page 16
15
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LUSTLine Bulletin 68 • June 2011
I Using L\ffrom page 15
LNAPL will usually be found floating
in the water like an ice cube in a glass
of water (not on the water like a solid
sheet of ice on a Minnesota lake in the
depth of winter; see Figure 1). Unfor-
tunately, this ideal, simple scenario
appears to be rare in Minnesota.
Things get much more compli-
cated when both finer- and coarser-
grained soils are present in discrete
layers. In the unsaturated zone,
LNAPL can be found perched on top
of a clay layer, and the attitude of
the clay's upper surface can control
LNAPL accumulation and migration
direction. Within the saturated zone,
LNAPL can be found in discrete lay-
ers reflective of inter-layered finer-
and coarser-grained soils, including
finer- versus coarser-grained sand
layers.
Most surprisingly, under appro-
priate geologic conditions, an
LNAPL layer can be found along the
top of a hydraulically confined sand
unit (an aquifer!), several to a dozen
or so feet below the water table pres-
ent in the overlying, confining clay
unit. It shouldn't be a surprise that
LIF data has shown that more than
one of the above-described LNAPL
distribution scenarios are present at a
single geologically complex site.
Watch Out for Those
LNAPL Arms
Now I don't mean to say that
hydraulic gradients have nothing
to do with LNAPL migration. Map-
ping of LNAPL bodies with LIF data
has shown us that even apparently
minor, induced (i.e., not natural)
hydraulic gradients can have a sig-
nificant effect on LNAPL migration,
even when the induced gradients are
applied some time after the initial
migration period when an LNAPL
body has stabilized under prevailing
natural conditions.
Most LNAPL bodies will be more
or less circular, or roughly oblong,
and centered under the release
source in map view. However, some
will have lobes and some of these
lobes may take the form of relatively
narrow and sometimes surprisingly
long arms. Only because of a dense
LIF grid pattern (discussed below),
and probably some luck, have we
been able to identify some of these
LNAPL arms.
16
If there is an LNAPL arm, I know
where I am going to go looking for
actively migrating LNAPL. But, my
main point is that we have observed
LNAPL arms that apparently devel-
oped due to human-induced hydrau-
lic gradients caused by pumping
water wells screened within the
hydro-stratigraphic unit where
the LNAPL occurs. LIF data have
shown us LNAPL arms reaching
out from an LNAPL body toward:
a) a relatively deep, high produc-
tion municipal well located several
hundred feet away; b) a relatively
shallow, low-production domestic
well located less than 200 feet away,
or c) a perennially pumping but low-
volume basement sump less than 100
feet away. (The sump pump example
was a big surprise, especially since it
was located up gradient.) Moreover,
when very strong induced vertical
gradients are present, the LNAPL
arms have been observed "diving"
deeper as they migrate laterally.
Added Value of LIF Logs
LIF data led us to another unantici-
pated but very important benefit. We
found the LIF logs to be very use-
ful when negotiating cleanup plans
with responsible parties. It must
be the visual thing. The LIF logs
allowed the responsible parties to
"see" the LNAPL at their sites and
better understand the nature of the
problem. This clearer understand-
ing often led these important stake-
holders to take more ownership
of the problem and its resolution.
Moreover, it often elicited addi-
tional important site history infor-
mation that, in turn, yielded a more
informed SCM. Indeed, some par-
ties wanted to use LIF on their other
problem sites as quickly as possible
due to LIF's problem resolution
capabilities.
LIF Investigation Strategy
It should be understood that the
PRP's requirements for LIF investi-
gation and data analysis are typically
designed to yield a well-defined
remediation target while also devel-
oping an updated, evidence-based
SCM including the role of LNAPL.
Thus, a LIF investigation is typically
completed after a standard site inves-
tigation; so there is often standard
data to guide LIF planning. Nonethe-
less, we require prior submission of
a site-specific LIF investigation work
plan for our review before approving
LIF investigations.
If available, we often recom-
mend that LNAPL samples be col-
lected from monitoring wells before
conducting a LIF investigation. This
can be done well before mobilizing
the LIF equipment to the site. The
samples can be held to the probe
window to see how the LNAPL
responds to LIF. One can also obtain
LNAPL waveforms from the samples
to confirm how well the LNAPL
from the wells matches the LNAPL
in the formation.
For targeting purposes, and sub-
surface heterogeneity being the rule
rather than the exception when faced
with Minnesota's complex glacial
terrane, the PRP generally requires
that borings be completed across a
grid with 25 to 35 feet node spacing.
However, it is important to slightly
adjust, or add, some nodes within the
grid so as to be directly adjacent to
known or suspected LNAPL occur-
rences such as at standard borings
or monitoring wells with evidence
of LNAPL, as well as potential or
known release locations (e.g., tanks,
dispensers, product lines, spills).
LNAPL is laterally delineated by
LIF borings completed at grid nodes
in all directions around a confirmed
detection until the LNAPL body is
completely circumscribed by LIF
pushes with no evidence of LNAPL.
To be sure, some delineation node
locations may need to be adjusted
slightly to accommodate small foot-
print obstructions.
Large footprint obstructions
such as buildings or other major
infrastructure should be accommo-
dated with delineation probes com-
pleted on all sides. This is due to the
often unexpected, complex nature
of LNAPL migration in the subsur-
face that could render convenient
assumptions about limited LNAPL
distribution unwise. The require-
ment for complete lateral delineation
during a single LIF equipment mobi-
lization event belies our advice to
obtain site access permission before-
hand for all properties where LIF
data may be needed.
Vertically, we generally require
that all LIF probes be advanced to
depths at least 10 feet below the
deepest detectable LNAPL at a given
site (one of the reasons to start prob-
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June 2011 • LUSTLine Bulletin 68
ing in the source area) or below the
water table. But it is often wise to
go deeper, depending on site geol-
ogy or other evidence suggesting
that deeper LNAPL may be present.
Regardless, we generally require at
least one boring to 20 feet below a
site's deepest detectable LNAPL or
the water table to confirm that there
is no deep LNAPL. We have some-
times been surprised. The surface
elevation of all LIF borings must be
surveyed relative to the same on-site
datum used for groundwater eleva-
tions and other site features.
It is important to note that LIF
data is displayed in real time as the
probes are advanced, and entire logs
can be generated on-site immediately
after completing a boring. With an
ever-evolving SCM in mind, this capa-
bility allows a seasoned investigator
to rapidly adapt and make informed
decisions in the field as to how deep
to advance the probe or where to go to
conduct the next boring.
LIF Data Analysis Strategy
The evaluation of any LNAPL body
via LIF log interpretation usually
begins with the logs from the release
location, if known; otherwise, from
where the obvious shallowest and/
or thickest LNAPL is observed, as
these often provide clues about the
release location. After the release area
logs are interpreted, we move on to
interpret the logs in order of distance
from and in all directions around the
release point. In other words, we fol-
low LNAPL migration pathways
away from the release point. This will
usually result in immediate insights
as to LNAPL migration behavior over
time, including why the LNAPL is
distributed as it is now and where it
may migrate in the future.
If side-by-side geology data from
CPT or EC are available, those are
also interpreted when evaluating
respective LIF data; otherwise, geol-
ogy from nearby standard borings is
used cautiously. In addition, LNAPL
thicknesses and corrected water level
elevations—including fluctuation his-
tory—from nearby monitoring wells
are noted. "Snapshot" boring water
levels are considered less useful than
long-term monitoring well data but
can be useful for identifying perched
conditions in the unsaturated zone.
Each LIF log is first evaluated
for the presence of LNAPL using a
"machine-language" approach—is
LNAPL present or not? False posi-
tives, if any, are also identified and
discounted. If LNAPL is present, the
top and bottom depths of the LNAPL
interval are noted, as well as the
maximum fluorescence response and
its depth within the LNAPL interval.
With hydrogeology of the
LNAPL interval in mind, we also
note the shape, or signature, of the
fluorescent response as it varies ver-
tically across the LNAPL interval. We
have found that this signature is evi-
dence of varying pore structure and
geometry (i.e., geology) and/or rela-
tive LNAPL pore saturations within
a homogeneous geologic unit.
Under homogenous hydrogeo-
logic conditions, the LIF signature
can reflect a pore saturation profile
reflective of the vertical equilib-
rium model for LNAPL behavior
under multiphase flow conditions in
porous media (Figure 1). More often
than not, complex geology results
in complex LNAPL distribution,
and the LNAPL may be present in
relatively thick and/or thin, discrete
sand layers.
When clay geology is predomi-
nant, keep in mind that intermittent,
very thin, solitary LNAPL signatures
may indicate the LNAPL is in sec-
ondary porosity features, especially
if they don't correlate between adja-
cent borings. As one interprets each
LIF log, adjacent LIF logs are kept in
view and progressively correlated
with each other, often illuminating
an overall pattern of LNAPL body
geometry and behavior across the
site as it relates to release and migra-
tion history, and geology and hydro-
geology.
LNAPL Structural Mapping
Once the LIF logs are systemati-
cally interpreted, LNAPL elevations
are calculated and all the LIF data
interpretations and calculations are
tabulated. The data are then used
to map the structure of the LNAPL
body from two perspectives: map
(plan) view and cross section. Usu-
ally, at least four types of LNAPL
body structure maps are constructed
by contouring four LIF data sets: 1)
maximum fluorescence response; 2)
elevation of the top of the LNAPL
body; 3) elevation of the bottom of
the LNAPL body; and 4) LNAPL
body thickness (i.e., isopach).
Sometimes a depth, rather than
elevation, datum is used to map
the structure of the LNAPL body
when more appropriate for the pro-
posed remediation strategy (e.g., an
LNAPL body excavation). At this
point, I should admit to being a for-
mer coal geologist; thus I like to treat
the LNAPL body as a coal seam or an
ore body, if you will. I also happen
to be partial to LNAPL body exca-
vations since I can be confident in
the quick risk reduction that occurs
when one removes nearly 100 per-
cent of the LNAPL mass.
The maximum fluorescence
response map is completed first.
Preparation of the maximum fluo-
rescence-response map is initiated
by first mapping the horizontal
extent of LNAPL. This is easy to do
if the LNAPL has been delineated
using the grid approach; simply
draw a line weaving along half-
way between LNAPL-present and
LNAPL-not present data points. All
of the LNAPL structure maps are
then constructed by contouring the
data inside this common LNAPL
body footprint.
Cross-sections are constructed
showing the LNAPL body as it
relates to site geology, hydrogeology
(e.g., fluctuating water levels), and
the other dependent contamination
phases. The cross sections should also
show other relevant site features such
as buildings, basements, buried util-
ity lines, water wells, and other pref-
erential migration pathways, barriers,
obstructions, and receptors. The ver-
tical and horizontal variation of fluo-
rescence response within the LNAPL
body can be contoured on cross sec-
tional views to illuminate patterns
of internal LNAPL body structure,
providing additional insights about
LNAPL migration and behavior.
The various LNAPL structure
maps and cross-sections are used
to accurately target the LNAPL
body with the remediation strategy
in mind. For example, the LNAPL
structure maps can be used to stra-
tegically plan an LNAPL body
excavation so as to remove only
LNAPL-impacted soil for expensive
treatment while using the segregated
overburden as backfill (remember, I
am a formal coal miner).
The LNAPL body isopach map
allows for accurate estimation of
• continued on page 18
17
-------
LUSTLine Bulletin 68 • June 2011
I Using LIF from page 17
the in-place volume of the LNAPL-
impacted soil to be selectively
removed. Alternatively, if a multi-
phase extraction system will be used
under a dewater and aerate remedia-
tion strategy, the elevation of the bot-
tom of the LNAPL body map can be
superimposed with flow maps con-
structed with pilot-test or full-scale
system hydraulic data for evaluat-
ing the degree and extent of LNAPL
body dewatering around and
between extraction wells. The struc-
ture maps and cross sections can also
be used to explain the remediation
strategy (e.g., by superimposing var-
ious proposed remedial structures,
such as extraction or injection wells,
on them).
If geology is a key factor in
controlling LNAPL behavior and
employment of a given remediation
strategy, structural geology elements,
such as the elevation of a clay/sand
contact are also contoured. Facies
changes, as well as sand bodies or
buried sand channels embedded
within finer-grained soil, should also
be mapped, if relevant.
As an example of geologic map-
ping's usefulness when combined
with LIF data, we have seen evi-
dence of perched LNAPL stranded
in syncline- or basin-like geologic
structures. We have also seen evi-
dence of perched LNAPL migrat-
ing "down dip" and cascading off
the edge of the confining unit like a
slow motion subsurface waterfall.
We have observed the migration of
submerged LNAPL, apparently con-
trolled by anticline- or dome-like
geologic structures at the top of a
hydraulically confined sand unit.
From a remediation strategy per-
spective, geologic mapping allows
one to be aware of the limitations
imposed, but also the opportunities
presented, by site-specific geologic
structures. Of considerable impor-
tance, we have found that integrating
LNAPL distribution with geology
results in the need to consider more
than one remediation strategy to
address different areas of a com-
plexly distributed LNAPL body.
We also like to point out that
one can sometimes take advantage
of LNAPL's propensity to distribute
the bulk of its mass in more highly
permeable layers. Understanding
18
the location of the LNAPL relative to
geologic structure is particularly use-
ful for designing remediation wells
to precisely focus remediation efforts
and/or avoid short-circuiting.
Proximal, standard soil, ground-
water, and soil-gas analytical data
are also reviewed and evaluated to
see what they are telling us about
LNAPL chemistry, the COCs in
particular, and the evolution and
behavior of the aqueous and soil-gas
plumes originating from the LNAPL.
For example, soil-gas data can some-
times appear confounding, with the
need to sort out false positives.
Soil and groundwater samples
collected from within the LNAPL
body often contain entrained LNAPL.
Even if they don't, the samples are
likely representative of the COCs
present in the LNAPL. So, if no ben-
zene is detected (and the benzene
detection limit is not elevated) in soil
and groundwater samples directly
associated with a given LNAPL body,
it would be logically consistent to use
that line of evidence for questioning
any positive detection of benzene in a
soil-gas sample when evaluating the
vapor-intrusion pathway.
Moving Forward
In August 2010 we implemented a
new policy for managing LNAPL
risks, including a risk-based defini-
tion of free-product recovery to the
maximum extent practicable when
only LNAPL migration risks are
present. The development of this
new policy is the direct result of inte-
grating what we learned from LIF
and the LTRC.
The PRP is in the business of
reducing risks posed by LNAPL in
the formation pores, not cleaning up
individual wells, so we no longer use
an in-well minimum free-product
thickness criterion for determin-
ing the need for and completion of
LNAPL recovery efforts. We believe
our approach is consistent with the
requirements listed in 40 CFR 280.64,
including to "use abatement of free-
product migration as a minimum
objective." The policy is outlined
in MPCA Guidance Document 2-02
"LNAPL Management Strategy"
which can be downloaded from
www.pca.state.mn.us/bkzij810.
More recently, we implemented
new policies for oversight of correc-
tive action, in particular, the design
and implementation of aggres-
sive remediation systems target-
ing LNAPL. The development of
new corrective action policies was
substantially informed by what we
learned about remediation using
LIF to target LNAPL bodies. In most
cases, the entire LNAPL body must
be targeted when risks are posed
by COCs that originate from the
LNAPL. This includes the immobile,
sometimes called residual, fraction of
the LNAPL that cannot migrate but
is still a potent, long-term, source of
COCs. These new policies are out-
lined in MPCA Guidance Document
7-01, Corrective Action Design and
Implementation, which also contains
LIF guidance in Appendix B. That
document can also be downloaded
horn www.pca.state.mn.us/bkzij810.
I am very excited about ITRC's
plan to take their LNAPL Classroom
Training on the road. The training is
designed for regulators, consultants,
and others LNAPL remediation
stakeholders.
Although a finalized schedule
has not been publicized, I have been
told the first two-day course will be
offered during fall 2011. A total of
up to twelve training events across
the country are envisioned, so most
everyone should have an opportu-
nity to attend a relatively nearby
offering. In the meantime, the LTRC's
internet-based training is still being
conducted and past sessions can be
downloaded for review at your con-
venience. For more information on
the internet-based training schedule
or downloads, check the LTRC's web-
site, www.itrcweb.org. The classroom
training schedule will be posted
there when it becomes available. Two
ITRC LNAPL-related publications
can also be downloaded, as well as
other useful documents and links to
other relevant websites.
In conclusion, I hope Minneso-
ta's story will give you some reasons
to consider induced fluorescence
methods the next time you find
yourself trying to answer the ques-
tion: where's the LNAPL? •
Paul Stock is a hydrologist with the
Minnesota Pollution Control Agency,
Petroleum Remediation Program.
Paul can be reached at
paul.stock@state.mn.us.
-------
June 2011 • LUSTLine Bulletin 68
USEPA's Plan for Petroleum Vapor-
Intrusion Guidance
The USEPA has prepared the following petroleum vapor-intrusion (PVI) communications paper, which briefly articulates differ-
ences in vapor intrusion potential between petroleum and chlorinated hydrocarbons and discusses USEPA's plans to develop com-
munications and technical products to support the guidance now scheduled for completion by the end of '2012. As part of this effort,
the USEPA Office of Underground Storage Tanks (OUST) has also prepared a draft paper entitled "How does the vapor-intrusion
pathway differ for petroleum and chlorinated hydrocarbons?," which describes in detail how petroleum and chlorinated hydrocar-
bons behave differently in the subsurface and how these differences can influence whether there is a potential for vapor intrusion to
occur. OUST is inviting comments on this paper, which can be found at www.epa.govI oust. OUST is currently developing a dedi-
cated Petroleum Vapor-Intrusion Compendium website, which will be online this summer. For more information, contact Hal White
(white. hal@epa. gov).
Why is USEPA developing petroleum
vapor intrusion guidance?
Petroleum hydrocarbon vapors from
leaking underground storage tanks
can migrate into inhabited build-
ings and threaten public health and
safety. To address this threat, OUST is
developing petroleum PVI guidance
to assist regulators, consultants, and
other practitioners in their investiga-
tion and assessment of petroleum-
contaminated sites where PVI may
occur. The guidance applies to and
will focus on the most common feder-
ally regulated (RCRA Subtitle I) UST
sites, which are typically gas stations.
The guidance will contain informa-
tion and practices that will also be
useful at other sites (for example, fuel
terminals and airport hydrant sys-
tems) where petroleum contamina-
tion and PVI are potential concerns.
USEPA's Office of Solid Waste and
Emergency Response (OSWER) is
developing vapor intrusion guidance
that applies to hazardous substances
other than petroleum (e.g., chlori-
nated hydrocarbons) that have been
released into the environment from
any source, including USTs.
What is vapor intrusion?
Vapor intrusion occurs when toxic
chemicals volatilize from source
materials, contaminated soils, or
groundwater plumes, and migrate
into inhabited buildings. Vapor
intrusion is a potential concern
because of both immediate threats
to safety (e.g., explosive concentra-
tions of petroleum vapors or meth-
ane) and possible adverse health
effects from inhalation exposure to
toxic chemicals. The toxic impacts of
VI are usually associated with two
COMMUNICATIONS PAPER
classes of chemicals that cause soil
and groundwater contamination
across the country: petroleum hydro-
carbons (PHCs), such as gasoline,
diesel, and jet fuel; and chlorinated
hydrocarbons (CHCs), such as dry
cleaning and degreasing solvents.
Vapor intrusion associated with
PHCs is referred to as PVI, and vapor
intrusion associated with CHCs
is referred to as chlorinated vapor
intrusion (CVI).
How do petroleum hydrocarbons
and chlorinated hydrocarbons differ
with respect to the vapor intrusion
pathway?
The most significant difference
between these two potential sources
of contamination is that petroleum
hydrocarbons are typically con-
sumed by microorganisms (biode-
graded) in groundwater as well as
in unsaturated soil zones. When
sufficient oxygen is present, this
biodegradation can limit the poten-
tial for PVI. In contrast, chlorinated
solvent compounds, if they biode-
grade, tend to degrade more slowly
and in anaerobic environments. As a
result, there are generally more sites
in which CVI has been an issue rela-
tive to sites with PVI. OUST is devel-
oping an information paper to more
expansively describe how petro-
leum and chlorinated hydrocarbons
behave differently in the subsurface
and how these differences can influ-
ence whether there is a potential for
vapor intrusion to occur.
How does this guidance relate to
USEPA's existing draft vapor intru-
sion guidance?
In November 2002, OSWER issued
Draft Guidance for Evaluating the
Intrusion to Indoor Air Pathway
from Groundwater and Soils (Draft VI
Guidance). This guidance was devel-
oped primarily to address vapor
intrusion from solvents and other
CHCs, and it specifically states that
the Draft VI Guidance is "not recom-
mended for use at Subtitle I Under-
ground Storage Tank (UST) sites at
this time." OSWER is currently revis-
ing the Draft VI Guidance and plans
to have it completed by the end of
2012.
Concurrently, OUST is devel-
oping additional guidance specifi-
cally to address PVI at Subtitle I UST
sites. The PVI guidance will discuss
important differences between petro-
leum and chlorinated hydrocarbon
contaminants that require a differ-
ent approach to investigating and
assessing sites where PVI may occur.
The PVI guidance will complement
the overall OSWER vapor intrusion
guidance and will not replace or
duplicate that guidance effort. Miti-
gation approaches, where needed,
will be addressed in the overall
OSWER vapor intrusion guidance.
What does the USEPA PVI guidance
aim to provide?
The PVI guidance will provide a
framework for investigating Subtitle
I UST sites to determine whether PVI
is not a concern, is a potential con-
cern, or is an actual concern where the
exposure pathway is complete. The
PVI guidance will address the follow-
ing issues and also provide links to
additional sources of information:
• What PVI is and how it is different
from CVI
• What criteria are used to assess
the potential for PVI
• continued on page 20
19
-------
LUSTLine Bulletin 68 • June 2011
m PVI Guidance from page 19
• How to develop a conceptual site
model (CSM) that includes the
potential for PVI
• How to conduct a field investigation
to assess the potential for PVI
• How to appropriately use a model
to support a data-based PVI
assessment
• How and when to engage the
potentially impacted community.
What additional components and
products is USEPA developing as
part of the PVI guidance?
USEPA is developing an informa-
tion paper that more expansively
describes how PHCs and CHCs
behave differently in the subsurface
and how these differences can influ-
ence whether and how vapor intru-
sion occurs.
USEPA is also in the process of
assembling a database of petroleum
release sites where the PVI pathway
has been evaluated. USEPA plans to
use the dataset to provide evidence
for biodegradation and for model
testing.
Additionally, USEPA's modeling
studies are assessing the uncertainty
associated with PVI model usage
to demonstrate the capabilities and
limitations of currently available
models. The results of these studies
will form the basis for appropriate
incorporation of model usage within
a PVI assessment.
How is USEPA engagi ng stakehold-
ers, communities, and the public
throughout the PVI guidance devel-
opment process?
OUST has engaged a work group of
stakeholders from states and tribes,
industry, and USEPA Regional
offices to obtain their individual
technical and practical input on PVI.
OUST has presented its proposed
plans for PVI guidance at several
conferences, workshops, and meet-
ings over the past year and will con-
tinue to involve the workgroup and
other stakeholders during the guid-
ance development process. One of
the major thrusts of these activities
will be to gather public perspectives
on appropriate and effective com-
munity outreach for PVI investiga-
tions. •
20
High-Tech Water Treatment
Plant Restoring Santa Monica's
Drinking Water Supply
On February 24, folks in
Santa Monica, California,
celebrated the dedication
of the city's Charnock water wells
and the state-of-the-art renovation
of the Santa Monica Water Treat-
ment Plant. This important mile-
stone marks the full restoration of
the city's local groundwater and
the reduction of the use of expen-
sive imported water from north-
ern California and the Colorado
River. It secures a sustainable sup-
ply of locally produced water for
future generations. Santa Monica,
which was one of the first victims of
methyl-tertiary butyl ether (MtBE)
pollution, is now setting the stan-
dard for MtBE cleanup.
The Charnock Well Field has
been used as a drinking-water
source since 1924. That supply was
threatened in 1996 when MtBE was
discovered in the city's ground-
water. The gasoline additive had
leaked into the well field from gas
stations in the area. (MtBE is no lon-
ger used in gasoline in the United
States, primarily because of liability
concerns.) The well fields, which in
1996 supplied 50 percent of Santa
Monica's drinking water, had been
shut down for the last 15 years due
to MtBE contamination.
With its wells back online, Santa
Monica can now produce about 70
percent of the water it needs on a
typical day. The rest is purchased
from the Metropolitan Water Dis-
trict, which gets its supplies from
Northern California and the Colo-
rado River. The city hopes to be 100
percent self-sufficient in supplying
its own water by 2020.
The Treatment System
The cleanup and filtration system
includes a granulated activated car-
bon system and then a three-stage
Reverse Osmosis (RO) membrane
system, which softens the water by
removing minerals (calcium and
magnesium). RO uses pressure to
force water through membranes
with pores so small the miner-
als can't pass through. The final
step, aeration and storage, uses the
existing air-stripping technology
in the five million gallon reservoir
to remove any remaining volatile
groundwater contaminants.
Pretreatment > Reverse
Osmosis Filtrations > Water
Quality Adjustments > Aeration
and Storage > Final Delivery
In 2006, Santa Monica reached an
agreement with all major oil com-
panies responsible for the MtBE
contamination, allowing the city to
restore the Charnock Well Field so
that it could once again be a viable
drinking water source.
The Santa Monica Water Treat-
ment Plant treats water from three
city groundwater well fields—
Charnock, Olympic and Arcadia—
providing eight and a half million
gallons of drinking water each day
to its 89,000 residents. With the plant
upgrade to state-of-the-art technol-
ogy the city is ensured of additional
water quality benefits and added
protection against potential pollu-
tion in the future. •
-------
June 2011 • LUSTLine Bulletin 68
E15? THE SKY NEED NOT FALL
by Robert Renkes
~j ~j~SEPA is moving full steam ahead with plans to allow the use ofethanol blends up to E15 in model year 2001 and newer
I I light-duty motor vehicles, which includes passenger cars, light-duty trucks, and medium-duty passenger vehicles, provided
\^sL conditions for mitigating misjueling and ensuring fuel quality are met. When petroleum marketers will actually start sell-
ing the new fuel is anyone's guess, since various state and local laws—plus supplier contracts, insurance agreements, liability
issues, bank covenants, equipment coste, local retailer competition, and decisions at the terminal level—will have to be considered
before a drop ofE15 is dispensed. But eventually it will be sold in almost every state of the nation, and before it is, we have to ask
ourselves if it can be done safely from afire safety standpoint and without damage to the environment.
What Do We Know?
We already know something about
the effect mid-level ethanol blends
have on dispensing equipment (see
LUSTLine #66, December 2010), and
have learned that things are not so
cut-and-dried on that front. The
National Renewable Energy Labo-
ratory's (NREL) study—carried out
by Underwriters Laboratories Inc.
(UL)—provides data on the impact
of introducing gasoline with an
additional amount of ethanol, such
as E15 and E20, into legacy (exist-
ing) dispensing equipment that was
not listed by UL for ethanol blends
greater than E10. (See report at: www.
nrel.gov/docs/fyllosti/49187.pdf.)
Although the UL report con-
cluded that there were "no noted
effects on metallic parts of equip-
ment," some other equipment dem-
onstrated "a reduced level of safety
or performance, or both, during
either long-term exposure or per-
formance tests." According to UL,
"leakages are largely attributed to
effects of exposure on the gasket,
seal, and hose material."
Influenced by its findings, UL
retracted its earlier (February 2009)
position on E15 dispensers which
stated that it supports authorities
having jurisdiction who decide to
permit legacy system dispensers,
listed to UL87, to be used with fuel
blends containing a maximum etha-
nol content of 15 percent. Now—
since December 2010—UL has
maintained that the use of greater
than E10 ethanol blends in these dis-
pensers certified under UL Standard
87 is "contra-indicated."
Dispenser manufacturers, how-
ever, don't see E15 as a problem
for their standard dispensers. Last
year, DresserWayne and Gilbarco
announced that warranties for their
standard fuel dispensers would apply
for ethanol blends up to E15. Both
manufacturers confirmed and reiter-
ated that their standard dispensers
can dispense E15 safely for the life of
the dispenser in the second quarter
2011 issue of the PEI Journal (see www.
peijournal.org). Generally speaking,
fire marshals have allowed nonlisted
dispensers for E85 in the past as long
as the owner is willing to commit
to an enhanced equipment inspec-
tion program. Since the equipment
is aboveground and accessible, this
seems to be a satisfactory compromise
between the dispenser owner and the
local authority having jurisdiction.
How Do We Deal with What We
Don't Know?
However muddled it is, that's what
the industry knows about dispensers
and hanging hardware in mid-eth-
anol blend service. But what about
the underground equipment? What
is the likely impact of using E15 in
legacy UST systems?
Although UL does not provide
a specific E15 rating for USTs, pip-
ing, and associated equipment, cer-
tification ratings that include E15 are
made public by UL and by the manu-
facturer of the product. Provided the
tank owner and regulator know the
date of manufacture and who made
the tank, piping, and associated
underground equipment, they can
determine if the equipment is certi-
fied or listed by an independent test-
ing laboratory for use with ethanol
blends.
It is widely recognized, however,
that many components of the UST
system may never have been tested
for compatibility with ethanol in the
first place and therefore are not listed
by UL for compatibility with any
ethanol blend. Other UST system
components that today are listed as
ethanol-compatible were not listed
as such at the time they were first
manufactured and installed. In other
words, identical equipment may be
deemed compatible in some contexts
and not listed as compatible in other
cases. In those cases, a statement
of compatibility from the manufac-
turer—much like that provided by
dispenser manufacturers—should
also suffice to demonstrate compat-
ibility.
From my perspective, if a manu-
facturer is willing to stick its neck out
and go on record to approve equip-
ment for use with E15, that manufac-
turer must have done the requisite
testing to be confident about its com-
patibility with E15.
What Do UST Regulators Do?
No tank owner in his or her right
mind is going to put E15 in a non-
compatible system. Today's tank
owners are too sophisticated and
environmentally savvy to do other-
wise. They know that if they store E15
in systems that are not certified either
by UL or the manufacturer as compat-
ible with that fuel, they could expose
themselves to myriad legal difficul-
ties, any of which could threaten the
future of their businesses. Absent cer-
tification, tanks owners—particularly
retail station owners—could be held
in violation of:
• OSHA regulations
• State UST insurance policies
• Local fire codes
• The terms of their mortgage and
other loan agreements, which
routinely include compliance-
with-law provisions
• State-based common law tort lia-
bilities.
• continued on page 22
21
-------
LUSTLine Bulletin 68 • June 2011
I E15 from page 21
And what if some "bad actor"
tank owners pop up and try to store
E15 in systems not listed, certified,
or approved for E15? That is where
the state comes in. In my opinion,
the UST regulator—provided he or
she has the power—simply doesn't
allow it. If the serial numbers and
model numbers for the UST system
components don't match up to serial
and model numbers provided by
UL and / or the manufacturers, tank
owners can't use E15 until the own-
ers replace the components with E15-
compatible equipment.
Congress passed the UST law
back in 1984 because tank systems
were failing and leaking product
into the ground. To a great extent,
we fixed that mess. Then we learned
from our experience with MtBE that
when the fuel composition changes
our storage and fueling equipment
infrastructure must be reevaluated to
make certain it is compatible. There
is no reason why systems should be
allowed to fail again, but that's a risk
regulators will be taking if they do
not establish adequate safeguards to
protect the environment against a few
tank owners who may try to market
E15 stored, monitored, and dispensed
in noncompliant equipment.
Bottom line, I don't think E15 will
impact the environment surrounding
UST systems any more than E10 has.
Like E10, E15 must be stored in com-
patible equipment. We know what is
compatible and what isn't. UST own-
ers and regulators—together with
UST providers and installers—have
every reason to do it right. And I have
confidence they will. •
Robert Renkes is Executive Vice
President of the Petroleum Equipment
Institute (PEI) and is author of the
LUSTLine column "Field Notes." He
can be reached at: rrenkes@pei.org.
BIOFUELS HAPPENINGS
Iowa Establishes Nation's First E15
Incentive for Fuel Retailers
Iowa recently enacted comprehensive renewable fuels
legislation that establishes the nation's first specific E15
incentive for the state's petroleum retailers to offer the
mid-level blend to motorists in the state. Among other
things, the new law:
• Provides retailers with a 3-cents-per gallon retailer
income tax credit for sales of E15.
• Extends a 16-cents-per-gallon E85 Promotion Credit
until December 31, 2017.
• Provides $3 million per year for biofuels infrastruc-
ture (e.g., blender, E85 and biodiesel dispensers).
• Provides retail stations with liability protection
from consumer lawsuits for misfueling, as long as
the retail station has provided the proper and legal
labeling.
• Encourages petroleum marketers to blend biodiesel
into on- and off-road diesel in a multiyear incen-
tive program. In 2012, retailers will earn 2 cents per
gallon for B2 blends and 4.5 cents per gallon for B5.
Retailers will earn 4.5 cents per gallon for selling B5
from 2013 through 2017, but the B2 blend credit will
disappear after 2012.
Fuel retailers in Iowa will be eligible to receive the
3-cents tax credit beginning July 1, or as soon as USEPA
clears the fuel for legal sale. USEPA is expected to give
final approval for E15 this summer for use in all 2001
and newer cars and light-duty trucks. •
USDA Announces Blender Pump Program
In April, United States Department of Agriculture
(USDA) Secretary Tom Vilsack announced a program to
increase production and use of higher ethanol blends by
adding 10,000 flex-fuel pumps across the country over
the next five years. Vilsack acknowledged that the cost
of a new flexible-fuel system (tank and dispenser sys-
tem) would run somewhere around $120,000, leaving
the impression that the USDA's grant and loan guaran-
tee program would go beyond the cost of the dispenser
itself. The funding would come through the USDA's
Rural Energy for America Program. According to
USDA, there are 8.5 million flexible-fuel vehicles in the
U.S., which make up 3.5 percent of the approximately
250 million vehicles on the road. The agency estimates
that 2,350 retail outlets are currently offering E85. •
E15 Still Only Legal for Flex-Fuel Vehicles
E15 blends cannot be sold for use in 2001 and newer
conventional-fueled vehicles until the conditions of the
E15 partial waivers granted for using E15 are fulfilled.
The fuel and fuel additive manufacturers must detail
how they will address misfueling of vehicles, engines,
and equipment not covered by the E15 partial waivers
and certain fuel quality requirements. Additionally, E15
must also be registered, which includes completion of
emissions speciation and health effects testing. USEPA
is also in the process of finishing a rulemaking that will
help facilitate compliance with the waiver conditions,
which include labeling requirements for pumps dis-
pensing E15. There may also be state and local govern-
ment requirements that must be addressed before E15
can be sold in some areas. Until all federal, state, and
local statutory and regulatory requirements are satis-
fied, E15 may be sold only for use in flexible-fueled
vehicles or engines.
To avoid significant civil penalties for improper
fuel blending, USEPA suggests that retail gasoline sta-
tions currently selling gasoline blended with more than
10 percent ethanol for use in flex-fueled vehicles take
appropriate steps to prevent misfueling. The agency
says the likelihood of violations can be reduced if the
retailer selling more than 10 percent ethanol affixes
warning labels to all pumps dispensing this product,
informing the public that the product may only be
used in flexible-fueled vehicles or engines. USEPA also
encourages fuel providers to "employ other strategies at
their facilities that are cost-efficient and effective in fur-
ther reducing the risk of misfueling." •
22
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June 2011 • LUSTLine Bulletin 68
FAQs from the NWGLDE
...All you ever wanted to know about leak detection, but were afraid to ask.
Getting the Most Out of the NWGLDE Website
In this LUSTLine FAQs from the National Work Group on Leak Detection Evaluations (NWGLDE), we look at the information that is
accessible from the NWGLDE website at www.nwglde.org. Note: The views expressed in this column represent those of the work
group and not necessarily those of any implementing agency.
. Other than a list of accepted leak detection equip-
ment, what other information is available from
the NWGLDE website?
A variety of leak detection information is available
on the NWGLDE website, covering a wide range of
topics.
Besides the listings of types of leak detection equip-
ment currently evaluated by the work group under
"Test Methods" on the left side of all the NWGLDE
web pages (the most used tab on the website), the
website includes an alphabetic listing, by vendor, of
leak detection equipment (e.g., Vendors: A-F). These
pages also include a helpful alphabetic "Outdated
Vendor" cross-reference, tracking outdated names
to current names.
The "Downloads" tab, also located in the left mar-
gin of every NWGLDE web page, provides links
to downloadable information, such as annual
additions of the NWGLDE list, minutes from all
NWGLDE meetings, and NWGLDE policy memos,
and links to utilities used on the NWGLDE website.
Past meeting minutes provide a good history of dis-
cussions and decisions made by the work group.
The next tab on the left side of the page, "Links,"
provides links to websites with leak detection infor-
mation such as evaluator, states and USEPA, ven-
dors, and other miscellaneous sites. Also included
is reference information that can be valuable for use
by UST inspectors.
The "Disclaimer" tab on the left side of the website
is frequently overlooked, but very important. All
the NWGLDE list disclaimers are included here. A
good discussion of the NWGLDE disclaimers can be
found in LUSTLine Bulletin #55 (June 2007), which
can be found on our website under the "Library"
tab with all the other LUSTLine articles written by
the work group.
The next tab on the left side of the page, "News and
Events," lists changes and/or additions to listings
since the last annual NWGLDE hard-copy list was
added under "Downloads." On the right margin of
this page there are also links to information regard-
ing future NWGLDE meetings and other events rel-
evant to the subject of UST leak detection.
On the bottom of the website pages, several other
pages can be accessed. Clicking on "Email" will
allow you to email questions to the work group
regarding the website, listings, or other pertinent
subject matter. Clicking on "Protocols" brings up a
list of all leak detection equipment evaluation proto-
cols currently available. "Checklists" contains ATG
and line-leak detector maintenance checklists. The
"Glossary" contains important definitions that help
clarify information on the NWGLDE list.
Very important information for leak detection
equipment manufacturers can be found under
"Listing Procedures and Requirements" on the
home page just above the NWGLDE Chairperson's
name. This provides a list of information that must
be provided to the work group when submitting a
protocol for review.
If you are looking for a specific item and are not
sure where to find it on the website, you can per-
form a search from the link in the top right margin
of all website pages.
If you have not visited the NWGLDE website, check
us out at www.nwglde.org. •
• About the NWGLDE
The NWGLDE is an independent work group comprising ten mem-
bers, including nine state and one USEPA member. This col-
umn provides answers to frequently asked questions (FAQs) the
NWGLDE receives from regulators and people in the industry on
leak detection. If you have questions for the group, contact them at
questions@nwglde.org.
L«U«S«T«LINE Subscription Form
Name
Mailing Address
Email Address
_ Company/Agency.
_l One-year subscription: $18.00
_l Federal, state, or local government: Exempt from fee. (For home delivery, include request on agency letterhead.)
Please enclose a check or money order (drawn on a U.S. bank) made payable to NEIWPCC.
Send to: New England Interstate Water Pollution Control Commission 116 John Street, Lowell, MA 01852-1124
Phone: (978) 323-7929 • Fax: (978) 323-7919 • lustline@neiwpcc.org • www.neiwpcc.org
23
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New England Interstate Water
Pollution Control Commission
116 John Street
Lowell, MA 01852-1124
August 1985/Bulletin #1 - June 2011/Bulletin #68
The LUSTLine Index is ONLY available online.
To download the LUSTLine Index, go to
www.neiwpcc.org/lustline/and then click on LUSTLine.
Oneida Tribe's New Compliance Assistance Flip Book
Has Great Recipes for UST Operators
UST Compliance Assistance
Handbook
--
The Oneida Tribe of Indians of
Wisconsin has published a
well-received UST Compliance
Assistance Handbook that provides
information for all levels of UST
operators (A, B & C). It offers textual
and visual information for operators
to ensure their facility is in com-
pliance. Its spiral-bound "recipe"
booklet format, with water-resistant
front and back covers, and the presentation of information in color-coded sec-
tions, makes it easy to use, and convenient to store and carry. It is intended for
distribution to employees of facility and allows for operators to fill in informa-
tion specific to their facility. It can be used as an instructional aid.
For more information about the handbook, contact Victoria Flowers at
vflowers@oneidanation.org. The entire handbook is posted on NEIWPCC's
website at www.neiwpcc.org/lustline/supplements.asp.
Our tank community
has lost a valued
member. On June 9,
2011, Richard Ostrom passed
away in his home in Idaho.
Before his retirement,
Dick was the state fund
manager for the Idaho
Petroleum Storage Tank 10
Fund. Dick was also a
valued member of the
ASTSWMO State Fund
Task since its inception |K)u!
in 1993. Dick hosted a
fantastic state fund administrators meeting in Boise,
Idaho in 2002.
CALL FOR ABSTRACTS
TRNHS CONFERENCE
(FXPO
Mardi 19-21, ±012
Abstracts are currently being accepted for the 23rd National Tanks Conference
& Expo (NTC), which will be held March 19-21, 2012 at the St. Louis Union
Marriott Hotel. We are inviting anyone interested in giving an oral presentation,
poster, or workshop to visit the NTC website at www.neiwpcc.org/tankscon-
ference/and submit an abstract or idea! The Call for Abstracts will be open
until August 26, 2011. The conference planning team is particularly interested
n presentations, posters, and workshops that focus on cross-programmatic
ssues addressing UST, LUST, and State Funds.
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