bulletin 57 commission 01852-1124 2007 l.u.s.t...new england interstate 116 john street water...

New England Interstate 116 John StreetWater Pollution Control Lowell, MassachusettsCommission 01852-1124

Bulletin 57November2007

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

www.neiwpcc.org/lustline.htm

L.U.S.T.LINE

P etroleum products—gasoline, diesel fuel, heating oil—are composed of hundreds of chemicals, some of whichare present in crude oil and some not. Fuels contain

various classes of compounds. The bulk of the fuel is com-posed of petroleum hydrocarbon constituents that areeither present in crude oil or in very similar compoundsproduced by refining (e.g., iso-octanes). The refineriesblend these compounds into a finished product accordingto complex requirements derived from regulation, crude-oiltype, component abundance, and operating characteristics.Additives are used for a wide variety of purposes. Some,for example, are detergents required by the Clean Air ActAmendments (CAAA) of 1990. Because fuel additives areproprietary, we know little about their properties and envi-ronmental behavior.

At the beginning of the underground storage tank pro-gram our approach to site assessment at a fuel-release sitewas to look for benzene, toluene, ethylbenzene, andxylenes (BTEX). This was a logical approach for three keyreasons: benzene is a carcinogen; many gasoline com-pounds have a very low effective water solubility; andhighly volatile compounds are quickly lost to the atmos-phere. However, this approach began to change whenmethyl tert-butyl ether (MtBE) usage and releases becamecommon in reformulated gasoline after the passage of theCAAA.

Most of us now know that MtBE was used earlier as anoctane booster to replace leaded additives. Although somewarnings about MtBE were raised, most people in theLUST program were unaware of the impending problemsthis chemical would cause. And MtBE isn’t the only fueladditive whose use has resulted in unpleasant surprises:ethers such as tert-amyl methyl ether (TAME), di-isopropylether (DIPE), and to a lesser degree ethyl tert-butyl ether(ETBE), and alcohols such as tertiary-butyl alcohol (TBA),

ethanol, and methanol can also be found in various petro-leum products.

As we’ve learned from New England Interstate WaterPollution Control Commission surveys of state LUST pro-gram experiences, many states don’t analyze for thesecompounds. (See LUSTLine #56, “The Results ofNEIWPCC’s 2006 Survey of Tank Programs…”) Becausethe ethers are used to boost octane, they have been used inconventional gasoline. Some states that may have thoughtthey didn’t have these chemicals because they were notrequired have been surprised.

And we’re on the verge of another surprise—the leadscavengers. These compounds, which were used until the

TBA, Go Away!

What About 1,2-DCA?

Musings on the UST Challenges of the Future

The Gospel According to Phil

Egads, Not a Test!

California Field Study on ATG and LLD Systems

Update on Bad Gas in West Virginia

STI Online Recertification for Cathodic-Protection Testers

Inside2

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What is in these gasoline free-product samples—BTEX?MtBE? TBA? 1,2 DCA? TAME? DIPE? EDB? ETBE?…

It’s Always Something!That Element of Surprise in Analyzing for Gasoline Compounds

■ continued on page 2

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LUSTLine Bulletin 57 • November 2007

MtBE—Leaving a Legacy?It’s been a little over a year sinceMtBE disappeared from Delaware’sgasoline (April-May 2006). Many ofmy newer LUST sites started show-ing significant decreases in MtBEconcentrations fairly quickly after itsdisappearance, and some are justnow starting to show declining

trends in MtBE in the groundwater.We’ll get rid of it eventually. But I’mstill faced with another problem—high levels of recalcitrant tert-butylalcohol (TBA). As a matter of fact,some sites have shown massiveincreases in TBA concentrations ingroundwater samples as the MtBEhas declined.

L.U.S.T.LineEllen Frye, Editor

Ricki Pappo, LayoutMarcel Moreau, Technical Adviser

Patricia Ellis, Ph.D., Technical AdviserRonald Poltak, NEIWPCC Executive Director

Lynn DePont, EPA Project Officer

LUSTLine is a product of the New EnglandInterstate Water Pollution Control Commis-sion (NEIWPCC). It is produced through a

cooperative agreement (#T-830380-01)between NEIWPCC and the U.S.

Environmental Protection Agency.LUSTLine is issued as a communication

service for the Subtitle I RCRA Hazardous & Solid Waste Amendments

rule promulgation process. LUSTLine is produced to promote

information exchange on UST/LUST issues.The opinions and information stated hereinare 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 ofCongress in 1947 and remains the oldest

agency in the Northeast United Statesconcerned with coordination of the multi-

media environmental activities of the states of Connecticut, Maine,Massachusetts, New Hampshire,

New York, Rhode Island, and Vermont.

NEIWPCC116 John Street

Lowell, MA 01852-1124Telephone: (978) 323-7929

Fax: (978) [email protected]

LUSTLine is printed on Recycled Paper

late 1970s to prevent lead precipita-tion on engine components, have per-sisted in groundwater to this day.

So, it has become apparent thatour traditional approach to site char-acterization does not serve us well foranticipating problems and prevent-ing exposure to chemicals in gaso-line, including BTEX. (See articles onmonitoring wells, LUSTLine #42, anddiving plumes, LUSTLine #36.)

Just as we’ve taken some stridesto improve our site-characterizationapproach by embracing new tech-nologies (e.g., direct push sampling)and employing “unconventional”techniques (e.g., installing nestedmonitoring wells to look for divingplumes), we can also improve ourability to prevent pollution fromLUST sites by evaluating productcomposition in more detail than wehave previously. This suggestion cantake many forms. Some state pro-grams, such as in Maine, are activelymonitoring the composition of petro-

TBA, Go Away!by Patricia Ellis

Most LUSTLine readers probably know that I’ve been crusading againstMtBE (or rooting for an MtBE ban) for more than ten years. USEPA’s BlueRibbon Panel on MtBE recommended that MtBE in gasoline be phased out

or its use substantially curtailed. Though it didn’t happen, through the years more andmore states climbed on the “Ban MtBE” bandwagon, either because they saw impactsto the groundwaters of their states, or because it was a way to increase ethanol usage.Delaware proposed banning MtBE during several legislative sessions, but to my disap-pointment, each time they failed to bring the issue up for vote. The Energy Policy Act of2005, while not banning MtBE, accomplished much the same result by not grantingprotection from lawsuits claiming that MtBE was a defective product. Between notbeing protected from lawsuits and the requirement for increased use of renewable fuels,

refiners and blenders dropped MtBE like ahot potato. To me, it wasn’t quite as satis-fying a way of getting MtBE out of thegasoline, but at least the end result hasbeen nearly the same.

leum product that comes into theirstates. This provides a statewide per-spective on fuel composition.

Nationally, research into fuelcomposition, as being undertaken byUSEPA ORD, is revealing previouslyunknown aspects of fuel composi-tion, even for conventional gasolineand traditional chemicals such asBTEX. At the site level, judgment isneeded for the use of all advancedtechnologies, including product char-acterization. A few judiciously cho-

sen product analyses may provide uswith the information we need to bet-ter protect public or private drinkingwater sources.

The following two articles, fromMinnesota and Delaware, providegood examples of the kinds of sur-prises that can pop up when a stateLUST program ventures beyond thecomfort of conventional thinking andheads out on the road to enlighten-ment.

■ Analyzing for Gasoline Compounds from page 1

November 2007 • LUSTLine Bulletin 57

ter. The MtBE continues to decline,but the TBA is definitely not showingsigns of going away.

I’ve got a number of other siteswhere all other chemicals of concernare below our cleanup levels, buthundreds of thousands of parts perbillion TBA remain in the groundwa-ter. Delaware’s Risk-Based Correc-tive Action (RBCA) program sets itscleanup goals based on distances to apoint of compliance, rather than justwhether there are any specific recep-tors within reach. One point of com-pliance is the property boundary.This was done specifically to mini-mize impacts to other properties.

We can also justify closing a siteif a stable or shrinking plume can bedemonstrated, but on many of thesesites, the TBA really isn’t showingsigns of decreasing. Our TBA stan-dard is an action level, not a cleanupnumber, but I really want to havesome sort of a warm fuzzy feelingbefore I’ll close a site, and a millionparts per billion doesn’t make me feelwarm or fuzzy.

We’re now armed with a newguidance document from the Ameri-

Some of the sites show the classichigh levels of MtBE followed by adecrease in MtBE concentrations anda corresponding increase in TBA con-centrations, indicating biodegrada-tion of the MtBE to TBA. But what Idon’t often see is a subsequent dropin TBA levels as the MtBE supply isexhausted and TBA-degrading bacte-ria have kicked into high gear. TBAseems to increase and stay high, orincrease and continue increasing.Come on bugs, you can do it. It’salcohol and doesn’t smell or tastenearly as bad as MtBE!

A few years ago, John Wilson,from USEPA’s Ada, Oklahoma lab,performed some isotope analyses ofgroundwater samples from one ofmy sites. The results showed thatapproximately 95 percent of theMtBE had degraded under anaerobic,methanogenic conditions. Unfortu-nately, I now have a site with TBAlevels as high as 1,650,000 ppb TBA.We’ve blasted the site on severaloccasions with massive amounts ofan oxygen-releasing compound, andmanaged to get respectable levels ofoxygen dissolved in the groundwa-

can Petroleum Institute (API) forevaluating the natural attenuation ofMtBE (Technical Protocol for Evaluat-ing the Natural Attenuation of MtBE,API Publication 4761, May 2007,http://www.api.org/ehs/groundwater/oxygenates/upload/4761new.pdf). How-ever, when I apply these protocols toTBA, the data indicate that the TBA isnot naturally attenuating to any sig-nificant extent.

[See also LUSTLine #34, February2000, “Tertiary Butyl Alcohol (TBA):MtBE May Not Be the Only GasolineOxygenate You Should be WorryingAbout” by Steve Linder.]

Developing ActionLevels/Cleanup StandardsWhich brings us to the question—How do we come up with action lev-els/cleanup levels for a chemical ifthese levels are normally generatedby starting with some sort of health-based information? The 2006NEIWPCC Survey of State Experienceswith Petroleum and Hazardous Sub-stance Releases at LUST Sites, HeatingOil Sites, and Out of Service Tanks had

State GW Action GW Cleanup Soil Action Soil Cleanup Primary Drinking Secondary Drinking State (or other) Level Level Level Level Water Std. Water Std. Advisory

CA 12 ppb

CT 100 ppb

DE 140 ppb 0.05 ppm

FL 1400 ppb 5.7 ppm

KS 43 ppb 43 ppb

MA 1000 ppb 100 ppm

MI 3900 ppb 78 ppm 3900 ppb

MO 286 ppb 0.563 ppm

NC Detection limit for all categories – Violation if exceeded

NH 40 ppb

NJ 100 ppb 4.10 ppm

NY 50 ppb

SC 1400 ppb 1400 ppb

VT 1 ppb

WY 2200 ppb 2200 ppb

TABLE 1A summary of the result of state responses to a question on state standards for

TBA in the 2006 NEIWPCC Survey of State Experiences with Petroleum and Hazardous Substance Releases at LUST Sites, Heating Oil Sites, and Out of Service Tanks


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a question dealing with TBA soil andgroundwater action levels, cleanuplevels, and drinking water standards.A number of states said that theirTBA numbers were site specific,while many more states evidently arenot yet dealing with TBA. Judgingfrom the range of values in Table 1,which summarizes the numbers fromthe states that provided them, we’veall chosen different methods to comeup with our numbers. (See LUSTLine#56 for more information about thesurvey.)

I developed the Delaware num-bers a few years ago (which are stillin draft form), using the only health-based information that I could find atthe time, which happened to be theCalifornia number. California had adrinking water advisory level of 12ppb, considering TBA as a probablecarcinogen. According to the 2005survey that Mike Martinson of DeltaEnvironmental has on USEPA’s web-site, the California number is now anenforceable Provisional Action Goalhttp://www.epa.gov/swerust1/mtbe/oxytable.pdf.

I used that value to back-calculatea reference dose, and then ran thatnumber through our RBCA softwareto arrive at soil and groundwateraction levels. More recent evaluationsof the health risks associated withTBA say that the mechanisms onwhich the California number is basedare specific to rats and that the samemechanism doesn’t operate inhumans. Other studies find that thekidney tumors induced in rats in thatstudy could be used for human riskassessment. The study in question(Cirvello et al, 1995) included suchphrases as “some evidence of carcino-genicity” in male rats based on…, but“no evidence of carcinogenicity” infemale rats; and “equivocal evidenceof carcinogenicity” based on…; and“some evidence of carcinogenicity” infemale rats based on…” So who’s tosay that I’ll behave as a rat whenexposed to TBA?

There are two major recent com-pilations of TBA health studies ofwhich I am aware. The first is a com-pilation prepared by ENVIRON andpublished by the American Petro-leum Institute (Hazard Narrative forTertiary-Butyl Alcohol (TBA). API

Publication Number 4743, October2005, http://www.api.org/ehs/ ground-water/upload/4743final.pdf). In thatstudy, analysis of various studiesresulted in a reference dose (RfD) of220 micrograms/kg/day. Assumingan average body weight of 70 kg andan average daily water consumptionof 2 liters, the average drinking waterconcentration for TBA associatedwith the RfD would be approxi-mately 8 mg/L. From Table 1, youcan see that no state has action levels,cleanup levels, or drinking waternumbers as high as those that wouldbe generated from the ReferenceDose in the API report. I have nottried to contact any of these states tosee how their numbers werederived—I tried that once with MtBEand it was a futile effort.

The second compilation, pre-pared by the Production High Vol-ume Chemicals Branch of EPA’sOffice of Pollution Prevention andToxics (Screening-Level Hazard Charac-terization of High Production VolumeChemicals - t-Butyl Alcohol), was re-leased in August 2007 and can beaccessed at http://iaspub.epa.gov/oppthpv/hpv_hc_characterization.get_report (TBA is listed as 2-Propanol,2-methyl-).

Among the conclusions of thestudy are the following statements:(1)TBA is not readily biodegradable inthe environment; (2) two carcinogenic-ity studies provide some evidence forcarcinogenicity of t-butyl alcohol, and(3) the potential health hazard of t-butyl alcohol is moderate based on theresults of the repeated-dose and repro-ductive / developmental toxicology. Idon’t want it in my drinking water. Doyou want it in yours?

We’re still waiting for a moredefinitive health number fromUSEPA for MtBE. According to theUSEPA document Regulatory Deter-minations Support Document forSelected Contaminants from the SecondDrinking Water Candidate List (EPAReport 815-D-06-007, Chapter 14:

MtBE, http://www.epa.gov/safewater/ccl/pdfs/reg_determine2/report_ccl2-reg2_supportdocument_ch14_mtbe.pdf),the health-risk assessment for MtBEwas scheduled for completion inApril 2007. The IRIS-tracking reportstates that the MtBE assessment wasstarted in 1998, and the final editedversion is now scheduled for comple-tion in 2009. I guess I shouldn’t holdmy breath until it’s done.

USEPA is doing a literaturereview on the health effects of TBA.But in the meantime, I believe that weneed to err on the conservative sideto be protective of human health.TBA doesn’t have that early warningstink that MtBE has, so we can’texpect people to stop drinking itbecause they taste or smell it in theirwater. Five years from now we don’twant to be kicking ourselves becausewe closed a few hundred (or thou-sand) sites with significant TBAimpacts that we didn’t think couldcause a problem.

Oh, Did I Say MtBE Is Gone?I am a member of Jim Weaver’s(USEPA ORD, Northeast RegionalLab, Athens, Georgia) gasoline sam-pling crew. He is studying theregional and seasonal differences ingasoline composition, RFG and non-RFG areas, and which oxygenates arebeing used in what areas. I recentlyreceived the results of the February2007 sampling and was amazed tostill see MtBE in several of theDelaware gasoline samples eight ornine months after we thought itwould be gone.

Both of the samples where MtBEwas detected were of 93 octane gaso-line, and MtBE was detected at 0.21and 0.44 percent, by volume. Neitherof the stations are very high-volume,and I suspect that the operators ofboth of these stations did not followour recommendations about havingtheir tanks cleaned prior to the switchto ethanol, but I was still surprisedthat after all these months, the MtBEwas still present. According to Jim,some of the samples collected inother areas also showed low levels ofMtBE, but it wasn’t common. I’ve justcompleted the August 2007 gasolinesampling. I’ll be curious to see ifwe’ve managed to dilute it out ofthose tanks by now.

For now, I’ll just sit back and seeif any of my new groundwater analy-

4


Five years from now we don’t want to

be kicking ourselves because we

closed a few hundred (or thousand)

sites with significant TBA impacts that

we didn’t think could cause a problem.

■ Analyzing for Gasoline Compounds – TBA from page 3

Our Long-Term ScavengerHuntRecent articles and presentations atthe National Tanks Conference byother states (particularly South Car-olina) have emphasized the need toexpand groundwater analysis toinclude the leaded-gasoline additivesEDB and 1,2-dichloroethane (1,2-DCA). In Minnesota we’ve been for-tunate to have some very forward-thinking people in our environmen-tal programs. Since the creation ofour LUST program in 1987, volatileorganic compound (VOC) analysisusing USEPA method 8260 has beenrequired for all first-round ground-water sampling. Our VOC-parameterlist was designated by our HealthDepartment lab and included theleaded-gasoline additives EDB and1,2-DCA (and with even moreimpressive foresight, MtBE in 1989).Although it’s likely our VOC sam-pling requirement was implementedto screen for nonpetroleum contami-nants (more than one chlorinatedplume was discovered this way),we’ve been keeping track of EDB and1,2-DCA for a long stretch.

As reported previously in LUST-Line, both EDB and 1,2-DCA werepart of the tetraethyl lead (TEL) addi-tive package designed to removeexcess lead from gasoline-engine

combustion chambers. Since 1942,these two compounds were added inmolar ratios with lead that resulted inalmost equal quantities, ranging from0.27 – 0.34 g/L, (Falta, June 2004). Aninteresting side note is that EDB isadded to aviation gasoline becausechlorine from 1,2-DCA in the exhaustwould be corrosive to aluminum air-frame parts. And since TEL was onlyadded to increase the octane ratingfor gasoline engines, it would neverhave been used in any turbine engine(jet) fuels, which comprise the vastmajority of aviation fuels used today.

Minnesota’s experience withthese two additives is that EDB is nota significant problem. An informalsurvey of Minnesota Pollution Con-trol Agency (MPCA) petroleum-remediation program staff found thatwhile we have numerous examplesof drinking water wells that are cont-aminated with 1,2-DCA, only two areknown to contain EDB (up to 1.4µg/L). In both cases, the 1,2-DCAconcentrations were much higherthan the EDB and also exceeded thestate drinking water standard of 4µg/L (the federal MCL is 5 µg/L). Inaddition, routine analysis of publicwater supply wells by the MinnesotaDepartment of Health, using method8260B, has never detected EDB; how-ever, 1,2-DCA has been detected in26 wells.

Looking Harder and Meanerfor EDBBecause of the extremely low drink-ing water standards for EDB (0.004µg/L state HRL and 0.05 µg/L fed-eral MCL), the elevated detectionlimits with method 8260B were a con-cern. We began to think that perhapsEDB was persistent below detectionlevels, which typically are in the 0.4-1.0 µg/L range. So when the USEPAOffice of Underground StorageTanks (OUST) in collaboration withthe USEPA Office of Research andDevelopment (ORD) got word outthat it was looking for leaded-gaso-line release sites to sample for low-level EDB using EPA method 8011through the Kerr EnvironmentalResearch Lab, we were more thanhappy to participate.

One site we submitted repre-sented a typical scenario seen in Min-nesota. In the beautiful north centralcity of Alexandria, a large petroleum-distribution terminal is situatedabove an aquifer consisting of pre-dominantly sand, occurring from 80-120 feet below grade. Separating thisdeep aquifer from a shallow surficialaquifer is a confining unit consistingof clay-rich till that is 30-40 feet thick.The deep aquifer is considered thesole source for the city and surround-

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by Mark Toso

As state regulators, working the day-to-day grind of site remediation, we often only see what’s happening in our own littleworlds. Because of this, we sometimes have information we’ve picked up along the way that could be beneficial to others butthat gets lost in the shuffle or filed away when the next big project comes along. This occurred to me one day while reading

through some past issues of LUSTLine. While a few articles made it pretty obvious that there was a heightened national concern overthe leaded gasoline additive ethylene dibromide (EDB), my first reaction was: “Never mind EDB, what about 1,2-DCA?” (See LUST-Line issues #47, “Lead Scavengers: A Leaded Gasoline Legacy?,” #50, “What South Carolina Is Learning about Ethylene Dibromideat LUST Sites,” and #51, “Leaded Gasoline? Hmm, What’s in Those USTs?”)

Never Mind EDB, What About 1,2-DCA?Minnesota’s Curious Little Piece of the Puzzle

ses for ethanol will manage to exceedthe TBA numbers I’ve seen.Ah….almost! I’ve got 1,300,000 ppbethanol in MW-2! At least I think thatthe ethanol will disappear soon, butit may have managed to remobilizefree product that we hadn’t seen inthe last few years, because the freeproduct in some of the wells seems tohave a weathered look about it. ■

Patricia Ellis, PhD., is a hydrologistwith the Delaware Department of Nat-

ural Resources and EnvironmentalControl, Tank Management Branch.She writes the LUSTLine column,

“WanderLUST,” and can be reached [email protected].

References:Cirvello, J.D., Radovsky, A., Heath, J.E., Farnell, D.R.,

and Lindamood, C. 3rd (1995) Toxicity and carcino-genicity of t-butyl alcohol in rats and mice follow-ing chronic exposure in drinking water. Toxicol. Ind.Health 11(2): 151-165.


ing area, and downgradient from theterminal it is contaminated with 1,2-DCA, but not EDB.

Since the terminal is located justinside the city limits, approximately300 deep-aquifer wells wereimpacted in new residential develop-ments outside the city. We have beentracking 1,2-DCA concentrations ofup to 8.0 µg/L in select offsite wellsin this area; several have exceededthe state standard of 4 µg/L (MCL is5 µg/L). These levels have remainedrelatively consistent over the last 12years. The front edge of the plumehas been migrating slowly to the cur-rent maximum extent of 3,200 feetdowngradient (ironically, the fewresidences that have shallow sand-point wells have no contamination).With the exception of the rare,extremely low-level detection of aBTEX compound, 1,2-DCA was theonly compound detected.

The highest 1,2-DCA concentra-tion seen in any onsite deep well was20 µg/L, again without anydetectable EDB. The last EDB detec-tion at the site was in a shallowaquifer well in June 1994 at 1.2 µg/L.There have been no detections of 1,2-DCA in a shallow-aquifer well sinceApril 1999. This could be the result ofvarious remediation systems thathave operated entirely in the shallow

aquifer since the early 1990s.A total of eight well samples

were submitted to the Kerr Environ-mental Research Lab for low-levelmethod 8011 EDB analyses. Of these,two were onsite-monitoring wells,and the remaining six were offsiteprivate wells. These wells were allselected based on historical detectionof 1,2-DCA. All samples were alsoanalyzed for VOCs using EPAmethod 8260B. As shown in Table 1,all but one well had a detection of1,2-DCA. However, the 8011 analysisdid not detect EDB in any of the wellsat a level of 0.010 µg/L.

And the Winner Is…1,2-DCAAs is typical of what we experience inMinnesota, the 1,2-DCA outlived allthe other VOCs at this site. While thedegradation of these two additives inleaded-gasoline releases is not wellunderstood, it’s clear that at least inMinnesota, EDB is attenuating at arapid rate and 1,2-DCA is not. In factour experience has been that of all theVOCs we analyze for at petroleum-release sites, 1,2-DCA is the longest-lived, most traveled compoundwe’ve seen. It may even rival MtBEfor risk to drinking water supplies(incidentally, MtBE was found in theonsite deep wells beginning in 2003).

Why Minnesota’s data seem tocontradict those of states such asSouth Carolina, where EDB is moreprevalent, is a puzzle. This is espe-

cially interesting when you considerthat we see the same results across awide variety of geologic settings (i.e.,glacial, carbonate, and igneousbedrock formations). Perhaps thereare some significant differences ingeochemistry (there is the obviousdifference in temperature) or someother factor. It’s known that EDB hadbeen used as an agricultural pesticidemore widely in South Carolina andthat there might even be more recentleaded-racing-gasoline releases thanMinnesota.

So far, there is nothing to suggestthat we need to make a change in ourinvestigation and cleanup policy.However, if you are concerned aboutEDB and not currently sampling for1,2-DCA, you might want to thinkabout reevaluating your strategy.And stay tuned for additional infor-mation as we plan to develop thisand several other case studies as partof the national evaluation of leaded-gasoline scavengers.

But That’s Not Quite the Endof Our StoryIt’s always something! We have alsobeen seeing occasional detections of1,2-dichloropropane (1,2-DCP), whichis usually found associated with 1,2-DCA. Often the levels are right at thedetection limits of method 8260B, butsome have been as high as 46.5 µg/L(MCL is 5 µg/L). While one of thelisted uses of 1,2-DCP is as a leadscavenger, a major manufacturer ofTEL additives claims its use wasextremely limited. There is the possi-bility that 1,2-DCP is produced as abyproduct during the manufacture of1,2-DCA. However, there was appar-ently an acute shortage of 1,2-DCAbetween 1957 and 1960, and 1,2-DCPwas used as a replacement. This mayhold promise for dating some oldreleases. We plan to investigate thisfurther as well. ■

Mark Toso is a hydrogeologist with theMinnesota Pollution Control Agency

in St. Paul. He can be reached [email protected] or

651-297-8669.

ReferencesFalta, R. W. and Bulsara, N. 2004. “Lead Scavengers:

A Leaded Gasoline Legacy?” LUSTLine, New Eng-land Interstate Water Pollution Control Commis-sion. Bulletin 47, pp. 6–10, 2004, http://www.neiwpcc.org/lustline.htm


Distance of wellWell ID from site (ft) Benzene 1,2-DCA MtBE EDB

HRL/HBV 5 4 70 0.004

Cemetery Shop 1215 ND 2.4 ND ND

313 Agnes 1125 ND ND ND ND

Jerry's Bar 900 ND 3.6 ND ND

708 Kinkead 1665 ND 2.5 ND ND

903 Van Dyke 2475 ND 2.1 ND ND

1007 Van Dyke 2790 ND 1.8 ND ND

MW-57D – ND 8.2 68 ND

MW-58D – ND 6.0 11 ND

TABLE 1 Benzene, 1,2-DCA, MtBE, and EDB in the Deep Aquifer

Alexandria Terminal, April 24, 2007

All results in µg/l = micrograms per literAnalysis by Method 8260B except EDB by method 8011ND = Not detectedHRL = Minnesota Department of Health, Health-Risk LimitHBV = Minnesota Department of Health, Health-Based Value

■ Analyzing for Gasoline Compounds – MN from page 5

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Will Secondary ContainmentEver Contain? As many avid LUSTline readersknow, there have been various stud-ies in California and New Hampshireconcerning vapor leaks and theextreme measures needed to reducethem. Will we need vapor-tight sec-ondary containment for everyone?Years ago we were asking the samequestion about run-of-the-mill, liq-uid-tight secondary containment.“Vapor-tight” secondary wasn’t evenin our lexicon back then! Here inMaine, we moved to secondary con-tainment in 1991, and now theEnergy Act will practically require itnationwide. A good thing, but willwe now need a new generation ofsecondary containment? One withmore expensive vapor-tight tanks,piping, containment sumps, anddouble-walled spill buckets to ensurethat our ever-vulnerable drinkingwater supplies are protected?

Oh well, we are only in the 21stcentury, a place that was always inthe future and where all problemswere supposed to be solved. And we

are only talking about storage of themost dangerous and toxic and flam-mable liquid that we routinely comein contact with throughout our dailylives. Why worry?

Who Owns These Tanks? In the old days—and for all practicalpurposes, we are talking about some30 years ago in Maine—the “sevensisters” major oil companies ownedmost of the service-station tanks.Now the majors have moved on totend their crops out in the Gulf,North Sea, and North Slope, leavingthe feeding stations to the large oiljobbers and mom ‘n pops. In Maine,it was basic market share, or lack ofit, that seemed to move the majorsout of our territory.

Also in Maine, as I would expectelsewhere in the country, we’ve gotthe very capable oil jobbers and mom‘n pops and then we’ve got those thatthe Operator Training requirementsof the Energy Act will hopefully helpto become capable. With this changeof tank ownership we are also chal-lenged with communicating withsome folks who are not fluent in the

language of the rules with which theymust comply. Being a nation of immi-grants, this is not a new challenge.But, considering the technical natureof these rules, all training and infor-mation will need to be clear and intu-itive.

Will We Recognize the RightProblem and Have the RightSolution? Are we going to be smart enough torecognize the next MtBE or the nextflex-pipe fuel-compatibility issuesand head them off before theybecome problems? Many of us arealready thinking about ethanol, espe-cially E85, and its fate and transportand equipment-compatibility issues.Good training for the folks in chargeof forecasting the future! Maybe, aswas pointed out at the last “statesonly” session during the 2007 TanksConference, USEPA should sponsorsome/more up-front research onthese issues. We did get the messagethat EPA will come up with someUST component/ethanol compatibil-ity guidance.

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Tanks Down EastTanks Down Eastby W. David McCaskill

David McCaskill is an Environmental Engineer with the Maine Department of Environmental Protection. “Tanks Down East” is a regular feature of LUSTLine. David can be reached at [email protected] always, we welcome your comments.

Musings on the UST Challenges of the FutureWhile hypnotized by the gentle wash of waves on a pocket beach, numbed by the cold Labrador Current as it swept across the Gulf ofMaine, I got to thinking (heaven help me!) about tanks...about where the whole business of tanks and groundwater salvation and reg-ulations was heading. And maybe with the various UST provisions of the Energy Act of 2005 the future may be smoother than thepast 20 years, once we get that initial beach sand out of our shoes. When I finally snapped to, I decided it was time to start writing andthrow out some questions that we might want to ponder concerning the possible and probable future challenges that we face in our lit-tle esoteric world of USTs and LUSTs. After all, if we don’t ask the questions, we won’t be able to answer them. If we don’t answerthem, we might find some of those waves washing right over us.



How Many Times Do WeClean Up a Site?First it was BTEX, then MtBE, andnow it’s TBA and EDB and 1, 2-DCA.What’s next? Back to the future withethanol-mobilized BTEX plumes?Know thy contaminant and thy risk!

What Happens When the RugIs Pulled Out from Under Us? It has happened in the past. So it willbe true in the future. Some tank andpipe companies will go out of busi-ness, leaving the owners with little orno technical support. And whatabout the miles of first-generation,recalled, flex pipe left in the groundlong after the manufacturer has goneout of business?

And what about warranties? InMaine, we require tanks to beremoved at the end of their warranty.This is usually 20 years for cathodi-cally protected (CP) steel tanksinstalled before October 1985 and 30years for most other tanks—be theyCP steel, fiberglass-reinforced plastic(FRP), or jacketed steel. Now theSteel Tank Institute has limited itswarranties to 10 years. Now what?Who’s next? What’s next?

In Maine, we have documentedabout a dozen (and more on the hori-zon) cases where a double-walled CPor jacketed-steel tank’s primary shellhas been breached due to internalcorrosion. The good news is that thesecondary containment worked andnothing got into the environment.But the bad news is that the owneronly got 15 years of life out of thetank, rather than the warranted 30years.

I recall the sagely prognostica-tion of one of my colleagues 20 yearsago when he said, “Now that we areprotected against external corrosionwe’ll start seeing internal corrosion.”If double-walled tanks are leakingfrom internal corrosion at 15 years,might not the single-walled tanks beleaking as well? We have now insti-tuted a policy to take water samplesat the tap of convenience stores withsingle-walled CP tanks locatedwithin 300 feet of a private well.Maybe we’ll catch some horse-out-of-the-barn leaks before they run too far.

What about Those ErrantDelivery Drivers?Many states have trained UST tankinstallers and inspectors and, thanksto the Energy Act requirements, willhopefully be training operators, butwhat about delivery drivers? Theseare the folks who are responsible forsafely filling tanks and preventingspills and overfills. To my knowl-edge, there are currently neitherrequirements for that sort of trainingnor any regulatory hook to hold themaccountable.

Talk about being out of the loop!Who’s going to train these folks? Ourspill-response records rank overfillsas the leading source of releases fromall tanks—above or below ground.We recently sponsored an overfillmodule as part of a half-day industryhazmat training session for heatingoil and transport truck drivers, whichwas organized by the Maine OilDealers Association. This federallyrequired hazmat training deals withplacarding and emergency responseand is also a good way to get much-needed UST and AST overfill train-ing to the drivers, since they aregathered together and in trainingmode already. The feedback on thetraining was positive, and we plan tocontinue this collaboration with theMaine Oil Dealers Association.

As part of the Energy Act deliv-ery-prohibition requirements there isa regulatory hook that makes deliv-ery drivers liable for filling out-of-compliance (“red tag”) tanks. Thisseems to be a good start toward get-ting them involved in the UST regu-latory chain, but in order to actuallyprevent overfills in the future theyneed to be trained, as well.

Will We Ever Get SpillBuckets Right?Spill buckets—they are not justfuture problems; they are ongoingproblems in the here and now!Florida’s Leak Autopsy Study showsthat spill buckets in that state have arelatively short working lifespan. Ishudder to think what the lifespan ofthe spill bucket is here in Maine, withsand and salt continuously washinginto them during the winter months,not to mention snow plows playinghockey with their puck-shaped lids.

Coupled with malfunctioningand misused overfill devices, releases

at this human/UST system interfacewill no doubt persist. Will double-walled 15 gallon spill buckets solvethe problem? In Maine, we have arequirement that all new and replace-ment spill buckets have a capacity of15 gallons to hopefully capture thecontents of the delivery hose whendelivery “mistakes” are made. (See“Small Spills Count ….The SpillDrill,” LUSTline #49). I guess now weneed to contemplate the prospect ofdouble-walled spill buckets. We per-severe……

Out Over the HorizonWoven throughout the future of theUST program are the provisions ofthe Energy Act—and any subsequentprovisions. We will likely see bothpositive and perhaps not so positiveeffects. I believe that since many ofthe provisions in the Act werealready on our wish list, the futureproblems may be more predictable inour regulatory minds. As far as theunforeseen problems are concerned,maybe we, as states, territories, andtribes, should come together with ourbrain trust of knowledge and peerout to the horizon with an eye topreparing for any gathering storms,rather than blithely wait for futureproblems to wash up and over us. ■

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■ Tanks Down East from page 7

Snapshots from the Field

Midwest “Biowillie”Dispenser

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One of my best and mostrespected mentors during themid 1980s, when I was a reg-

ulator at the Maine Department ofEnvironmental Protection, was a ser-vice station owner named Phil. Thiswas back in the days when a gas sta-tion was a place you went to get yourcar fixed and to buy gasoline, but notto buy beer and groceries. Phil wasactive in his industry and was a fre-quent spokesperson for the state’sgasoline retailers, so we often foundourselves on opposite sides of tankregulatory issues. But because of adeep respect for one another, thesedifferences often led to great debatesand discussions rather than great ani-mosity.

As I began to investigate themore or less newly recognized tankproblem in the state, Phil was one ofthe first people I visited to learn moreabout the tank owner’s perspectiveon tank issues. I remember he tookme into a cramped office that wasjust barely big enough for a desk andtalked to me about the challenges ofrunning a service station. He told meabout some of the tricks attendantsused to steal money from him or hiscustomers, how to keep customerscoming back (“Always tell them thetruth”), and, very importantly for me,how to keep fuel-inventory records.Phil had a shelf full of binders withmany years worth of carefullydetailed fuel-inventory records. Hekept inventory not because anybodysaid he had to but because he thoughtanybody who didn’t was foolish.And Phil was definitely no fool.

I recall one day, over a drink, heleaned across the table, and I sawfrom the look in his eye that he hadsomething important to say. “Do youknow who you are when you walkinto a gas station?,” he asked. I was abit stumped; I wasn’t sure what hewas driving at. “Well,” I beganslowly, “I guess I am a representativeof the state.”

“No,” he said. “That may be theway you see yourself, but to the per-son on the other side of the counter ordesk, you are GOD.” I must havelooked somewhat puzzled, becausePhil went on to explain. “When youwalk in to a gas station, the owner orattendant believes that you have thepower to do anything you want to his

9


Marcel Moreau is a nationally recognized petroleum storage specialist

whose column, Tank-nically Speaking, is a regular feature of LUSTLine. As

always, we welcome your comments andquestions. If there are technical issues

that you would like to have Marceldiscuss, let him know at

[email protected]– nically SpeakingTank – nically Speaking

by Marcel Moreau

The Gospel According to Phil: “Be Sure You Know What You Are Talking About!”


business, and that whatever you sayis the law. So you’d better know whatyou’re talking about.”

There have always been, andthere always will be, business ownerswho have little respect for regulatorsor regulations. But there is also a sig-nificant percentage of tank ownerswho generally strive to do the rightthing. It is this latter group that tendsto hear the regulator’s word asgospel. These are also the people whocomplain to me about situationswhere regulators have given themvarious erroneous or illogical inter-pretations of regulatory require-ments. When I ask them why theydon’t point these things out to theregulators, there is typically a shrugof the shoulders, a look of resigna-tion, and silence. In the silence I hearPhil’s answer: “What can we do …?”

Consider some of the complaintsconcerning regulators I have heard oflate.

The Mistaken Swing JointA regulator inspected a new tankinstallation and refused to approve itbecause of a couple of elbows con-nected by a short length of pipe. Tra-ditionally, this combination offittings was known as a swing joint,and it was used to provide flexibilityfor galvanized steel piping. Swingjoints are generally not acceptable asa means of providing flexibility, butin this particular case, the fittingswere installed not to provide flexibil-ity (the piping was flex pipe) but tofacilitate the alignment of the pumpoutlet with the flexible piping. Thuswhile the fittings used were those ofa traditional swing joint, the functionof the fittings was completely differ-ent—and completely acceptable.

In this case, the inability of theregulator to differentiate between thetwo uses of the fittings (providingflexibility versus aligning the piping)caused much gnashing of teeth onthe part of the installer.

The Redundant Ball FloatThere are a number of tank installa-tions where both ball-float valves anddrop-tube shutoff overfill devices areinstalled. To be clear, this is a practiceI would discourage, but that is a topicfor a different article. Because they

treat both of these devices as overfill-prevention devices, there are regula-tors who require that the ball float beset at 90 percent of tank capacity andthe shutoff device at 95 percent.When only one of these devices isinstalled in a tank this is reasonable,because this is one version of whatthe tank rules require when thesedevices are installed for overfill pre-vention.

When both devices are installed,however, locating the ball float at 90percent and the shutoff device at 95percent is a problem, because theball-float valve will operate first,since it is set at a lower level in thetank. Once the ball float closes andreduces the fuel flow into the tank,the shutoff device is essentially dis-abled. This is because the flow rate ofthe fuel down the drop tube isreduced to less than what is requiredto close the shutoff valve.

Not only is the shutoff valve ren-dered useless, the hapless deliverydriver who fills the tank past thepoint where the ball float closes willbe in for a rude surprise. Because thedriver likely observed that a shutoffvalve was installed, he would reason-ably assume that the shutoff devicewas the overfill device on the tank.While a shutoff device allows a dri-ver to drain the delivery hose verysoon after the shutoff device oper-ates, a ball float requires a substantialdelay to relieve the pressure in thetank. If the driver mistakenlyassumes that he is dealing with ashutoff valve rather than a ball float,and does not wait before he discon-nects the hose, he will likely get abath in fuel as the backpressure in thetank forces product out of the hose.(For more information on the opera-tion of ball floats, see LUSTline #21,December 1994, “What Every TankOwner Should Know About OverfillPrevention.”)

It is for these reasons that PEIRP100-05, Recommended Practices forInstallation of Underground LiquidStorage Systems warns against theinstallation of ball-float valves lowerthan the activation point of a drop-tube shutoff valve (Section 7.3.3). Anincomplete understanding of theoperation and function of equipmentby regulators can create hazardoussituations. While the tank managerwho told me this story opted not toinstall the ball float at all as a result of

this requirement, other, less informedowners may have to pay the price ofa delivery spill because of misguidedregulatory policy or interpretation.Needless to say, the regulator’s credi-bility with the regulated communityalso suffers.

To Lift a 42-Inch ManholeCoverThere is at least one state that wantsto include as part of its operatortraining information the recommen-dation that operators visually inspectsubmersible pumps on a weeklybasis. There are many hazards associ-ated with inspecting submersiblepumps. For starters, there is a sub-stantial traffic hazard because thetank pad is frequently located in atraffic area, the lids are often difficultto remove and heavier than manystore personnel can safely handle—and there could be flammable vaporspresent. Frequent removal of the lidswill also encourage the omission ofseals and gaskets that help to keepprecipitation out of secondary-con-tainment sumps. Is inspection of sub-mersible pumps an appropriate taskfor store clerks and facility man-agers?

The PEI UST Inspection andMaintenance Committee discussedthe issue of submersible pumpinspection in producing PEI RP900,Recommended Practices for the Inspec-tion and Maintenance of UST Systems.(See “Field Notes” on page 13.) TheCommittee decided that large man-way inspection was too hazardous tobe conducted by store personnel. Thedocument recommends that suchbelow-grade components be in-spected annually by qualified per-sonnel (e.g., service technicians), notstore personnel.

I agree with the RP900 Commit-tee that routine visual inspection ofsubmersible pumps by store person-nel is a practice to be avoided ratherthan encouraged. Regulators whopromote such a practice ignore basicsafety and common-sense considera-tions. From its inception, the goal ofthe tank program has been to protecthuman health and the environment.Let us not forget that human healthcomes first. The “safe” way to keep aneye on submersible pumps is to installthem in liquid-tight sumps with con-tinuously monitored sensors.

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■ Tank-nically Speakingfrom page 9

Electronic versus Mechanical LLDAnother state is proposing that allline-leak detectors (LLDs) shut downthe submersible pump when a 3 gal-lon per hour leak is detected. Thischange would essentially force aswitch from mechanical to electronicline-leak detectors. Now generallyspeaking, I think this is probably agood way to go. Electronic line-leakdetectors offer the ability to periodi-cally test for smaller leaks as well as 3gallon per hour leaks, and have diag-nostic features that can facilitate trou-bleshooting. There are somesituations, however, where mechani-cal LLDs may have an edge over elec-tronic ones. This is because electronicLLDs generally take a longer time todetect 3 gallon per hour leaks thanmechanical ones.

Many electronic LLDs incorpo-rate a multiple-test feature to helpreduce false alarms due to tempera-ture effects in the piping. Rememberthat volume changes due to tempera-ture are a significant cause of falsealarms in mechanical LLDs. (See “OfBlabbermouths & Tattletales, The Lifeand Times of Line Leak Detectors,”LUSTline #29, June 1998).

Because volume changes due totemperature diminish over time,repeating a test cycle is a good way todistinguish temperature effects fromreal leaks. If the measured volume orpressure loss diminishes over time, itis likely due to temperature. If themeasured volume or pressure loss isconsistent over time, it is likely due toa leak. So, although not declaring aleak until several tests have been runis a good way to evaluate whethertemperature effects are influencingthe results of a test, it takes time torun these multiple tests.

The test cycle of electronic LLDsis generally interrupted if a customeractivates the pump to dispense fuel.This means that a period of severalminutes of uninterrupted quiet timesufficient for several tests to be run isgenerally required for a leak to bedeclared. One brand of electronicLLD requires upwards of 10 minutesof uninterrupted quiet time todeclare a leak. At very high-volumefacilities, this amount of quiet time isgoing to be infrequent at best, if it ispresent at all.

While very active facilities poseproblems for both mechanical and

electronic LLDs because the pumpsare “on” most of the time, there is noquestion that most electronic LLDsrequire a longer time to find 3 gallonper hour leaks (minutes) thanmechanical LLDs do (seconds). (See“The Trouble with Truck Stops,”LUSTline #56.) Thus for very activefacilities, mechanical LLDs may be abetter choice in terms of timely detec-tion of large leaks than electronicLLDs. While this seems counterintu-itive at first, I believe that this is a fac-tor that should be considered beforedeciding whether electronic ormechanical LLDs are a better bet forleak detection.

There is a solution here in theform of hybrid LLDs that essentiallyuse a mechanical LLD to activate aswitch that will cut off power to thepump, but these types of LLDs arenot as widely known as the standardelectronic LLDs. The point is thattoday’s leak-detection technologiesand gas station operating characteris-tics must be carefully evaluated todetermine the “best” method of leakdetection for a particular facility.

“Be Sure You Know WhatYou’re Talking About.”For better or for worse, a regulator’swords may be taken as gospel bytank owners who are doing their bestto obey the rules and are unwilling togainsay a voice endowed with regu-latory authority. Whether or not theirproclamations are regarded as provi-dential, in my view, regulators havean obligation to be sure that the posi-tions they take with regard to regula-tory requirements are sound.

I expect there are many moreexamples of regulatory misinforma-tion and shortsightedness that couldbe cited. These are just examples thatI have recently come across. There ismuch attention being focused thesedays on the proper training of USToperators. Let us not presume thatUST operators are the only ones inneed of training. To be credible andeffective, regulators must be knowl-edgeable and exercise a reasonabledegree of common sense.

As the Energy Act’s three-yearinspection requirements are imple-mented and regulator/tank operatorencounters become more frequent,keep in mind the simple but pithygospel according to Phil. ■


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Snapshots from the Field

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Florida “Sinkhole”Dispenser

Arizona “Old Timey” Dispensers

If you have any UST/LUST-related snapshots from the field that you would like to share with our readers, please send them to Ellen Frye at [email protected]

12


SPEAKING OF TRUCK STOPS…Marcel Moreau’s cover article, “The Trouble with Truck Stops…,” in our last issue (LUSTLine #56) was followed up withnews of a recent release at a truck stop in Missouri and a note from Kevin Henderson (Mississippi Department of Environ-mental Quality UST program) with examples of truck-stop releases in that state.

MissouriThe appearance of fuel in astormwater retention pond inJune 2007 was the first indica-tion of a release at this high-vol-ume truck stop, located on aninterstate highway. Investigationinto the cause of the leak andwhy the leak-detection equip-ment failed to detect it, is stillunderway. Cleanup costs will besignificant; more than $300,000was spent for the initial response, which included excavation of impacted soil and installation of a recovery trench.

Mississippi“Having read ‘The Trouble with Truck Stops’ in the last issue of LUSTLine, Iwas reminded of some incidents we have experienced with truck stops. Thephoto in Figure 1 depicts what happened when a customer drove off with thenozzle still in the fuel tank. As a result of the drive-off, the dispenser cabinetwas pulled from the mounting frame and the shear valve did not properlyfunction. The system continued pumping until it was manually shut down bya store clerk—but not before some 1,300 gallons of fuel were released.Obviously, the fact that the leak-detection system was unable to recognizethat this sudden and catastrophic release was occurring at this high-capacitypumping system leaves us with a lot to be desired.

Figure 2 depicts an incident that occurred in 2003 that also resulted in acatastrophic release, although this one occurred over a relatively longperiod of time. In this case, a relatively small leak in the undergroundpiping system went undetected until it was eventually visually detected.Fuel came up through the expansion joints in the truck-stop parking lotand then made its way to the drainage ditch shown in Figure 3. Uponsubsequent testing and excavation, it was revealed that the piping hadfailed near one of the dispenser-containment sumps.

Although the pipefailure shown in Fig-ure 3 appears to becatastrophic, it was

actually not as bad as it looks. Further investigation revealed that the paththe leak was taking through this multi-layered pipe was such that the pipewould only leak if the line pressure was above 7 psi. Because this was avery high-volume truck stop, the mechanical automatic line-leak detectorthat was installed in the system had virtually no chance of detecting theleak. The fact that the leak would stop at 7 psi and that the facility washigh volume meant that the line pressure would probably never decay tothe 1 psi or less needed for the mechanical leak detector to go into theleak-detection mode. Clearly, we deserve better than this.”

FIGURE 1

FIGURE 2

FIGURE 3

SPEAKING OF TRUCK STOPS…

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Field Notes ✍from Robert N. Renkes, Executive Vice President, Petroleum Equipment Institute (PEI)

Egads, Not a Test!

The Petroleum Equipment Institute (PEI) has pub-lished seven recommended practices to date,with two more slated to be completed within the

next year. The documents have been widely acceptedby the contractors for which they were written.Because the subject matter of most of the documentsinvolves either aboveground or underground storagetanks, LUSTLine readers and tank regulators also seemto find the documents useful.

If there is one knock on the recommended prac-tices, it is that there is no means to gauge how well theusers of the document understand what they read untilthey are out in the field—which for some contractors istoo late. PEI is attempting to fill that void by preparingtests for each of the recommended practices it pub-lishes. We began work on the project this summer andhope to have tests for all recommended practices com-pleted by March 2008.

The tests are being written and proofed by thetechnical committees responsible for each document.The questions are in a multiple-choice format. Deliveryand scoring will be available through the Internet. PEIwill have a bank of questions available, so no two testswill be the same. We estimate that most tests will

include around 70 questions and take 30 to 45 minutes tocomplete.

The contractors that we talk to about the tests aredelighted with the prospect of giving the test to jobapplicants who claim to have experience in tank installa-tion and/or inspection. Contractors also tell us that theywould use the tests for refresher training and before theypromote people from within their construction depart-ment.

We are not sure if tank regulators have a use forthese tests. We think that they might be used for licens-ing and certification purposes. On the other hand, theyhave probably developed their own tests by now. Train-ing and continuing education of inspectors is anotherpossible use for the tests.

Pricing of the tests has not been determined. Wewant to keep them affordable to our contractor membersand any regulatory agency that wants to use them. If youhave a use in mind and want to discuss how you and PEImight work together in product delivery and pricingschemes, please let me hear from you. As the sayinggoes, I’m from private industry and I’m here to help.Email: [email protected]. Phone: 918-494-9696 ■

Veeder-Root Issues Alert About Red Jacket FX Leak DetectorOn August 1, 2007, the Veeder-Root Company notified its customers that a small percentage of Red Jacket Leak Detec-tors manufactured from December 2006 through May 2007 might not seal when installed into a submersible turbinepump packer-manifold. The company notes that this condition, if present, will not compromise the leak-detection func-

tion of the units. To detect this condition, thepump must be running with the line pressur-ized. If an improper seal is present, it can befound by making a visual inspection to see ifseepage is occurring at the joint between theleak detector and the packer-manifold.

The equipment affected is unit FX1V Partnumbers 116-056-5 and 116-058-5, and unitFX2V Part numbers 116-057-5 and 116-059-5.The date code, printed on the name tag of theleak detector, indicates the manufacture date ofthe unit. Units manufactured during the affectedtime period will have a date code of X1206,0107, X0207, X0307, X0407, or X0507.

For more information, contact the Veeder-Root customer service department at (800) 873-3313. ■

Problem Area

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Update on the Bad Gas in West Virginia Story

The California State WaterResources Control Board(SWRCB) recently published a

project report entitled Field Evaluationof Automatic Tank Gauging Systems,Electronic Line Leak Detection Systems,and Mechanical Line Leak Detectors. Asthe title suggests, this projectinvolved testing the effectiveness ofATG and LLD systems in the field.Using funding from the USEPAOffice of Underground StorageTanks, the SWRCB contracted withKen Wilcox Associates to simulateleaks of 0.1 gph, 0.2 gph, and 3 gph at106 UST facilities throughout Califor-nia and assess how effective the ATGand LLD systems were at detectingthe simulated leaks. As many indi-viduals experienced with UST leakdetection might expect, the resultswere encouraging in some cases andsomewhat of a concern in others.

Summary of Findings forATGsThe overall probability of detectionof a leak of 0.20-gal/hr was estimated

as 86%, somewhat less than the 95%prescribed by the USEPA perfor-mance standards. The probability ofdetection was significantly associatedwith the product in the tank, thematerial or type of construction of thetank, and the size of the tank. Theprobability of detection was 95% fortanks of 8,000 gallons and less; 84%for tanks from 8,000 gallons to 25,000gallons; and only 63% for tanks of26,000 gallons up to 50,000 gallons.

Summary of Findings forMLLDsThe overall probability of detectionof a 3-gal/hr leak rate was estimatedas 63%, but 76% of the MLLDsdetected a leak rate of 5-gal/hr, and88% detected leak rates up to 10-gal/hr.

Summary of Findings for ELLDsThe estimated probability of detec-tion for ELLDs was 71% at the 3-gal/hr level and 76% at the 5-gal/hrlevel. A specific problem was identi-

fied when a Veeder-Root ELLD wasused with an F.E.Petro turbine, lead-ing to a failure of the ELLD to detectthe 3-gal/hr leak rate. A maintenancebulletin had been issued earlier per-taining to this issue, but evidently ithad not been implemented fully.With this corrected, the probability ofdetection of 3-gal/hr should increasesubstantially.

The overall probability of detec-tion was estimated to be 80% for the0.1-gal/hr leak rate. The overall prob-ability of detection at the 0.2-gal/hrleak rate was estimated to be 70%.Nearly all of the missed detectionswere traced to an improper installa-tion. Among the ELLDs that werecorrectly installed, the probability ofdetection was 96%.

If you are interested in knowingmore about how ATG and LLD sys-tems perform in the field, a completeproject report for this field study isavailable at http://www.waterboards.ca.gov/ust/leak_prevention/lld_atg_study/index.html

14


California Publishes a Field Study of ATG and LLD Systems

by Ellen Frye

Back in March 2003 (LUSTLine#43), I wrote a story called“Tanks Systems in a Jam—

Contaminated Gasoline from a Ken-tucky Refinery Spurs a Flurry ofTank Cleanups and Lingering Con-cern.” Since you may have forgottensome of the details of this case in theintervening years since that article, Iwill give you a short synopsis. From2000 to 2002, Marathon AshlandPetroleum’s Catlettsburg, Kentucky,refinery produced gasoline that con-tained rust, spent caustic, and mer-captan scavenger. This contaminatedgasoline was then distributed towholesalers and jobbers, who trans-ported and sold it to gasoline sta-tions throughout the State of WestVirginia under various brand names.The Catlettsburg refinery suppliesabout 85 percent of the gasoline sold

in West Virginia. In September 2002,Marathon undertook remedial effortsto remove the contaminants from theaffected USTs.

However, many tank ownersbelieved that Marathon’s UST-sys-tem cleanup project (Project Moun-taineer) was not effective and thattheir tanks are now damaged. In Sep-tember 2004, four gasoline retailersfrom West Virginia filed suit in theUnited States District Court for theSouthern District of West Virginia,Huntington Division (civil actionnumber 3:04-0966, Loudermilk Ser-vices, Inc., et al. v. Marathon Petro-leum Company LLC). The suit wasfiled on behalf of the four retailersand as representatives of all compa-nies and persons in West Virginiathat received the contaminated gaso-line from the defendants. The suitrequested the creation of a fund tomonitor, test, repair, and potentially

replace any USTs affected by the con-taminated gasoline.

The first step of the legal processhas now been accomplished—thecourt has certified a “class” for allowners and operators of under-ground storage tanks in West Virginiawho received contaminated gasolinefrom Marathon Petroleum Companyfrom February 1, 2000 through June30, 2004. The trial date has been set forSeptember 23, 2008. The courtappointed as class counsel RichardRowe of Goodwin & Goodwin, LLP,[email protected]; Robert T.Cunningham, Jr., Gregory B.Breedlove, Richard T. Dorman, andBryan Comer of Cunningham, Bounds,Crowder, Brown and Breedlove, LLC;and James M. Cawley, Jr. of James M.Cawley, Jr., PLLC, [email protected] can contact the attorneys listedabove for details of the case and acopy of the court order. ■

15


After serving for many years asExecutive Director of Min-nesota’s Petroleum Tank

Release Cleanup Fund, Jim Pearson isfamiliar to many in the tanks commu-nity. Now, he’s taking on a new chal-lenge: Pearson has been named theDirector of Drinking Water and Under-ground Storage Tanks Programs at theNew England Interstate Water Pollu-tion Control Commission. NEIWPCC,which publishes LUSTLine, is based inLowell, Massachusetts.

The job is new for Pearson and forNEIWPCC, which for the first time isplacing its drinking water and under-ground storage tanks programs underthe authority of one person. It’s not alight load. Pearson will plan and facili-

tate meetings of NEIWPCC’s variousworkgroups in these arenas, managemultiple projects including the cre-ation of guidance documents, andsupport state and federal staff on thedevelopment and implementation ofprograms and regulations. He’ll doeverything from coordinating re-gional comments on federal policyinitiatives to overseeing preparationsfor such events as the National TanksConference.

Pearson should be served well byhis vast experience in state govern-ment in Minnesota, where he estab-lished a reputation for successfullybuilding consensus around toughpolicy issues. His achievementsincluded designing and implement-ing a statewide abandoned USTremoval program that led to theremoval of over 100 tanks. Despite hissuccess in Minnesota, Pearson wasready for something new.

“This is a tremendous opportu-nity,” Pearson said. “I’m keeping onefoot in the tanks world, where I’veenjoyed working for years, and I’llhave the other in the drinking waterrealm, which is exciting on so manylevels. It’s also a great honor to be atNEIWPCC, which works to solveproblems collaboratively, the same asI always have.”

Pearson, who started work atNEIWPCC on Sept. 10, can be reachedat 978-323-7929 ext. 233 or via email [email protected]. ■

From MN to MA—Jim Pearson Joins NEIWPCC

Illinois “Mosaic” Dispenser

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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 01852-1124Phone: (978) 323-7929 ■ Fax: (978) 323-7919 ■[email protected] ■ www.neiwpcc.org

UL Not Quite Ready toList E85 Dispensers

Underwriters Laboratories (UL),Northbrook, Illinois, has determinedthat certain commercially available

gasket and seal materials perform accept-ably when exposed to concentratedethanol blends such as E85, while othermaterials experience significant deteriora-tion. In October, UL announced that it hasestablished certification requirements forE85 fuel-dispensing equipment and isnow accepting submittals for certificationinvestigations.

In October 2006 UL suspended autho-rization for manufacturers to use UL list-ing or recognition on components forfuel-dispensing devices that specificallyreference compatibility with alcohol-blended fuels containing greater than 15percent alcohol (i.e., ethanol, methanol,other alcohols). The suspension wasissued because studies on ethanol indi-cated that ethanol in high concentrationsmay significantly degrade equipment.

Some states have gone ahead and cer-tified. According to the U.S. Departmentof Energy's Alternative Fuels Data Center(http://www.eere.energy.gov/afdc/resources/technology_bulletin_0307.html), sev-eral states (i.e., CO, IL, IA, MI, MN, NY,OH, OR) and organizations have chosento grant variances/waivers or haveproduced a written stance on the E85Underwriter Laboratories Certification re-quirements. The website provides lettersfrom these state officials. ■

The NEW Version of the LUSTLineIndex—is ONLY available online. To download the LUSTLine Index, go towww.neiwpcc.org/lustline.htmand then click on LUSTLine Index

L.U.S.T.LINE INDEXAugust 1985/Bulletin #1 – November 2007/Bulletin #57

L.U.S.T.LINENew England Interstate WaterPollution Control Commission116 John StreetLowell, MA 01852-1124

Non-Profit Org.U.S. Postage

PAIDWilmington, MA

Permit No.200

STI/SPFA Offers OnlineRecertification for STI Cathodic-Protection Testers

The Steel Tank Institute/Steel Plate Fabricators Associ-ation (STI/SPFA) has announced that cathodic-pro-tection testers for USTs can gain recertification

through a new, online examination offered through STI.According to STI, the easy-to-follow, interactive exam isavailable to cathodic-protection testers currently certifiedby STI or NACE International. The exam is structured sothat answers must reflect the body of knowledge in STI'srecommended practice for cathodic-protection testing. Allwho wish to take the test must provide proof of activeengagement in the field of cathodic-protection monitoring.In addition, cathodic-protection testers whose STI certifica-tions have expired will be permitted to recertify under thisprogram until February 29, 2008.

Lorri Grainawi, director of technical services forSTI/SPFA, says that for several years STI has offered certi-fication programs that require cathodic-protection testersto travel to various locations to obtain and maintain certifi-cation. “The online exam decreases time and cost commit-ments substantially,” says Grainawi. “Testers can take therecertification exam from their offices or homes—even on aweekend, if they don't want to disrupt their work sched-ules.”

To register for the exam, which costs $395, visitwww.steeltank.com, where a library of downloadable reviewmaterials is available. After obtaining the materials, theregistrant has 59 days to take the recertification exam. Afterstarting the actual exam, the registrant will have 24 hoursin which to complete the effort. To date, most testers havefinished the exam within two to four hours.

Although the STI certification is generally acceptedthroughout the United States, some regulatory agenciesmay have additional requirements. STI recommends thatthose who wish to take the test check with regulators toensure that they are aware of all cathodic-protection moni-toring mandates in their service areas. ■

The 20th Annual National TanksConference & Expo will be held on March 17-19 in Atlanta, Georgia.It’s time to:

➟ Reserve booth space or poster session space!

➟ Register online for the conference and workshops!

Send any questions to: [email protected] conference provides learning and networkingopportunities for federal, state, and tribal UST/LUSTregulators. The focus is on building on our progress,setting priorities, and developing plans for reachingour common goal—to find new and better ways towork together to protect human health and the envi-ronment by preventing tank releases and quickly andefficiently cleanup releases that do occur.

Getting Readyfor the 2008National TanksConference

Getting Readyfor the 2008National TanksConference

Visit our new conference website

www.neiwpcc.org/tanksconference➟

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